United States
Environmental Protection
Agency
Air and Radiation
(6202 J)
DRAFT
February 1996
r/EFft
A Guide for Methane
Mitigation Projects
Gas-to-Energy at Coal
Mines
Emissions Overview • Identify Opportunities • Preliminary Site Assessment 4-
Government Policies • Next Steps • List of Experts • Funding Sources
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A Guide for Methane Mitigation Projects
Gas-to-Energy at Coal Mines
DRAFT
Editors: Dina Kruger and Karl Schultz
U.S. Environmental Protection Agency
Office of Air and Radiation
February 1996
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ACKNOWLEDGMENTS
This report was prepared under Work Assignment 2-15 of U.S. Environmental Protection Agency Contract 68-04-
0088 by ICF Incorporated. The principal authors were Sonaii Shah and Mary DePasquale of ICF. The authors wish
to thank Dina Kruger and Karl Schultz of the U.S. Environmental Protection Agency for guidance and comment
during the preparation of this document. Mention of trade names or commercial products does not constitute
endorsement or recommendation for use.
This document is a working draft being used by Country Study Program participants to develop methane mitigation
projects. Users of this document and those implementing methane mitigation projects are encouraged to provide
feedback. Please direct comments to:
U.S. Environmental Protection Agency
Methane Branch
Mail Code 6202 J
401 M Street, S.W.
Washington D.C. 20460
Tel: 202/233-9768
Fax: 202/233-9569
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COMBED VETHAKE GUIDELINES "ab:e of
TABLE OF CONTENTS
1. INTRODUCTION . 1
2. OVERVIEW OF COAL NONE METHANE EMISSIONS AND EMISSIONS
REDUCTION OPPORTUNITIES
2.1 METHANE is A POTENT GREENHOUSE GAS 4
2.2 METHANE EMISSIONS FROM COALMINING 5
2.3 OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM COAL MINES 6
2.4 REFERENCES 9
3. IDENTIFY OPPORTUNITIES FOR REDUCING METHANE EMISSIONS ~.ll
4. PRELIMINARY SITE ASSESSMENTS 16
4.1 GENERAL SITE INFORMATION REQUIRED. 16
4.2 IDENTIFY POTENTIAL RECOVERY METHODS AND ESTIMATE GAS PRODUCTION 19
4.2.1 Gas Production Methods. 19
4.2.2 Criteria for Selecting a Gas Production Method 25
4.2.3 Estimate Recovery Potential 25
4.3 IDENTIFY POTENTIAL USES FOR RECOVERED METHANE 27
4.3.1 Options for Using Coal Mine Methane 27
4.3.2 Select Use Options for Further Analysis 30
4.4 ASSESS ECONOMIC FEASIBILITY 32
4.4.1 Costs Analysis 33
4.4.2 Benefits Analysis 36
4.4 REFERENCES 43
5. IDENTIFICATION AND ASSESSMENT OF KEY GOVERNMENT POLICIES 44
5.1 NATIONAL ENERGY PRICING, SUBSIDIES, AND TAXES 44
5.2 NATIONAL ENERGY SUPPLY PRIORITIES 45
5.3 ENVIRONMENTAL GOALS 45
5.4 FINANCING 46
5.5 TECHNOLOGY DEVELOPMENT ...: 47
5.6 CONCESSION PROCESS 47
5.7 REFERENCES , 48
6. NEXT STEPS : 49
6.1 FOCUS ON THE MOST PROMISING PROJECTS 49
6.2 AVAILABILITY OF TECHNOLOGY AND EXPERTISE 52
6.3 MOTIVATE DECISIONMAKERS 53
6.3.1 Outreach Activities 53
6.3.2 Demonstration Projects 55
6.3.3 Information Clearinghouses 55
6.4 REVIEW REGULATORY FRAMEWORK 56
6.4.1 Evaluate Existing Regulations : 58
6.4.2 Develop Feasible Options 59
6.4.3 Implement Options 59
6.5 OBTAIN PROJECT FUNDING 60
6.5.7 Review Types of Assistance Available 60
6.5.2 Identify Funding Requirements 61
6.5.3 Select Sources of Funding 62
6.6 REFERENCES .65
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of Corners COALBED V.ETHANE GUIDELINES
APPENDIX A: DIRECTORY OF SELECT COAL MINE METHANE RECOVERY
AND USE EXPERTS IN THE U.S . 1
APPENDIX B: DIRECTORY OF POSSIBLE FUNDING AGENCIES 1
International Bank of Reconstruction and Development (IBRD) 2
Global Environment Facility (GEF) 3
International Finance Corporation (IFC) 4
European Bank for Reconstruction and Development (EBRD) 5
Inter-American Development Bank (IDB) 6
Asian Development Bank (ADB) 7
African Development Bank (AfDB) 8
Trade Development Agency (TDA) 9
17.5. Agency for International Development (USAID) 10
Overseas Private Investment Corporation (OPIC).. : 11
Export-Import Bank (EXIMBANK)...... 12
£7.5. Initiative on Joint Implementation (USIJI) 13
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VETHANT GUIDELINES
.nirocuci.on
1. INTRODUCTION
THIS report provides guidance for developing programs to reduce
methane emissions from underground coal mines through coal mine
methane recovery and use. Methane trapped in the coal and
surrounding strata is released during mining. Because methane is a valuable
source of energy, recovering and utilizing coal mine methane is an
economically attractive option for reducing greenhouse gas emissions.
This document is directed towards program managers responsible for
developing greenhouse gas (GHG) mitigation programs in developing
countries and countries with economies in transition. By focusing on
identifying and evaluating opportunities to reduce emissions, this report
complements the guidance developed by the U.S. Country Studies Program
and materials available from related efforts of the U.S. Environmental
Protection Agency and others. Furthermore, as a guidance document for
reducing methane emissions from coal mines, this report assists countries in
fulfilling commitments under the United Nations Framework Convention on
Climate Change (UNFCCC) to implement greenhouse gas mitigation
programs.
The main goal of this report is to provide a step-by-step method for performing
a national assessment of the opportunities to reduce methane emissions from
coal mining. The report presents steps for identifying and evaluating gassy,
underground coal mines. Those characteristics that make gas recovery and
utilization technically and economically attractive are presented. Additionally,
this report discusses how national policies affect the viability of coal mine
methane recovery projects and identifies the steps which may be taken to
encourage the development of this resource.
The remainder of this report is organized into the following five chapters:
2. Overview of Coal Mine Methane Emissions and Emissions
Reduction Opportunities: This section provides a brief background
to the topic of methane emissions and emissions reductions from coal
mines.
3. Identify Opportunities to Reduce Methane Emissions: This
section describes a screening process by which the program
managers can identify whether underground coal mines in their
countries present attractive options for reducing emissions.
4. Perform Preliminary Site Assessments: This section presents the
process for conducting preliminary site assessments for individual
sites or representative facilities identified as being good candidates
for gas recovery projects in Section 3. Based on this information, the
Given the economic value of methane as
a fuel source and the potential availability
of international donor funding, coal mine
methane recovery and utilization presents
one of the most cost-effective options for
reducing methane emissions.
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;OAL GUIDELINES
program manager can begin to design an emissions reduction
strategy for this source of methane emissions.
5. Identify and Assess Key Government Policies: This section
identifies the key government policies that will promote or hinder coal
mine methane recovery projects. . Based on this information,
potential policy options will be assessed in the context of national
priorities.
6. Next Steps: This section discusses the steps that may be taken by
program managers to further the development of an emissions
reduction program for underground coal mines. Information on
international funding sources for coal mine methane recovery projects
is presented in this section.
Exhibit 1-1 summarizes how this document can be used to meet various
objectives. The first column lists several common objectives and the second
column lists the chapter to consult and key elements of that chapter
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COALBED VLTHAKC
;UIDEL!\"CS
Exhibit 1-1: How to use this Document
Objective
I WANT AN OVERVIEW OF METHANE AS A GREENHOUSE GAS
• What are the sources of methane emissions
and how does methane contribute to the
greenhouse effect?
2. Overview Of Methane Emissions And
Emissions Reduction Opportunities
2.1 Methane is a Potent Greenhouse Gas
22 Methane Emissions from Coal Mining
2.3 Opportunities to Reduce Methane Emissions
from Coal Mines
SHOULD I TRY TO REDUCE METHANE EMBSKWS FROM COAL
MINES?
• How do I assess whether we have coal mines
that would be conducive to methane
emissions reductions?
• What data can I collect to identify promising
opportunities to reduce methane emissions
from coal mines?
3. Identify Opportunities For Reducing Methane
Emissions
Identify Basins or Coal Regions with Gassy
Underground Mines
Determine the number of Large Mines
Obtain Methane Release Information
Determine Mine Lifetimes
Evaluate Energy Demand
I WANTTO ESTIMATE POTENTIAL EMISSIONS REDUCTIONS
• How do I estimate the emissions reduction
from individual methane projects?
• How do I estimate and compare costs and
revenues from individual methane recovery
projects?
• How do I develop a national assessment of
emissions reduction and energy production?
4. Preliminary Site Assessments
4.1 General Site Information Required
4.2 Identify Potential Recovery Methods and
Estimate Gas Production
4.3 Identify Potential Uses for Recovered
Methane
4.4 Assess Economic Feasibility
WHAT POLICIES AND REGULATIONS ARE MPORTANT?
• What policies affect the economic viability of
coal bed methane recovery projects?
• How can methane recovery projects help
meet other environmental goals?
• What policies affect the availability of
financing and technology?
POLICIES
5. Identify And Assess Key Government Policies
5.1 National Energy Pricing, Subsidies, and
Taxes
52 National Energy Supply Priorities
5.3 Environmental Goals
5.4 Financing
5.5 Technology Development
5.6 Concession Process
WHAT CAN I Do NEXT TO FACILITATE A PROJECT?
• What additional studies are needed?
• How do I remove the barriers that are slowing
down the process?
• Where can I get funding to undertake these
activities?
NEXT
6. Next Steps
6.1 Focus on the Most Promising Projects
62 Availability of Technology and Expertise
6.3 Motivate Decisionmakers
6.4 Review Regulatory Framework
6.5 Obtain Project Funding
WHERE CAN I GET ADVICE FROM EXPERTS?
Appendix A: Directory of Select Coal Bed Methane Recovery Experts in the
U.S.
WHAT ARE THE MAW FUNDING SOURCES APPLICABLE To
COALMINES?
Appendix B: Directory of Possible Funding Agencies
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Ove.T.ew
HALOED V.ETIIANE GUIDELINES
2. OVERVIEW OF COAL MINE METHANE EMISSIONS
AND EMISSIONS REDUCTION OPPORTUNITIES
'T'HIS chapter provides a brief background to the topic of methane
J. emissions and opportunities to reduce emissions from underground coal
mines. First, background information is provided about the atmospheric
importance of methane. Next, methane emissions from coal mines is
discussed. Finally, the opportunity to reduce methane emissions and the
benefits of reducing emissions are presented.
2.1 Methane is a Potent Greenhouse Gas
Because methane is a source of energy
as weff as a greenhouse gas, reducing
methane emissions coal mines is eco-
nomically beneficial.
Methane (CKU) is an important greenhouse gas and a major environmental
pollutant. Methane is also the primary component of natural gas and as such
can be a valuable energy source. Methane emissions reduction strategies
offer one of the most effective means of mitigating global warming in the near
term for the following reasons:
• Methane (Cft) is one of the principal greenhouse gases, second
only to carbon dioxide (COa) in its contribution to potential global
warming. In fact, methane is responsible for roughly 18 percent of the
total contribution in 1990 of all greenhouse gases to 'radiative
forcing,' the measure used to determine the extent to which the
atmosphere is trapping heat due to emissions of greenhouse gases.
On a kilogram for kilogram basis, methane is a more potent
greenhouse gas than C02 (about 24.5 times greater over a 100 year
time frame).
• Methane concentrations in the atmosphere have risen rapidly.
Atmospheric concentrations of methane have been increasing at
about 0.6 percent per year (Steele et al. 1992) and have more than
doubled over the last two centuries (IPCC 1990). In contrast, C02's
atmospheric concentration is increasing at about 0.4 percent per
year.
• Reductions in methane emissions will produce substantial
benefits in the short-run. Methane has a shorter atmospheric
lifetime than other greenhouse gases ~ methane lasts around 11
years in the atmosphere, whereas C02 lasts about 120 years (IPCC
1992). Due to methane's high potency and short atmospheric
lifetime, stabilization of methane emissions will have an immediate
impact on mitigating potential climate change.
• Because methane is a source of energy as well as a greenhouse
gas, many emissions control options have additional economic
benefits. In many cases, methane that would otherwise be emitted
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COALBED VETHANE
GUIDELINES
Ov6''v:e\v
to the atmosphere can be recovered and utilized or the quantity of
methane emitted can be significantly reduced through the use of cost-
effective management methods. Therefore, emissions reduction
strategies have the potential to be low cost, or even profitable. For
example, methane recovered from coal mines can be used as an
energy source.
• Well demonstrated technologies are commercially available for
reducing methane emissions. For all of the major sources of
anthropogenic methane emissions (except rice cultivation and
biomass burning), cost effective methane reduction technologies are
commercially available. While offering substantial emissions
reductions and economic benefits, these technologies have not been
implemented on a wide scale in the U.S. or globally because of
financial, informational, legal, institutional, and other barriers.
The unique characteristics of methane emissions demonstrate the significance
of promoting strategies to reduce the amount of methane discharged into the
atmosphere.
2.2 Methane Emissions from Coal Mining
Methane and coal are formed together during coalification, a process in which
vegetation is converted by biological and geological forces into coal. Methane
is stored within coal seams and surrounding rock strata and is released to the
atmosphere during mining or through natural erosion. Typically, significant
quantities of methane are trapped in the coal and surrounding strata of
underground mines, while little methane is associated with surface-mined
deposits.
In underground mines, methane is hazardous in the working areas because
methane is explosive in concentrations of five to fifteen percent in air.
Therefore, all underground coal mines use ventilation systems. These
systems pump large quantities of air through the mine to dilute the methane to
safe levels. In very gassy mines, however, additional degasification
techniques must be used along with ventilation systems. The methane
recovered from these systems is frequently vented into the atmosphere.1
There are two important factors that influence the amount of methane
generated in coal seams:
Underground coal nones account for 70 to
85 percent of methane emissions from the
coal fuel cyde.
1 Methane does not typically pose a hazard at surface mines, and ventilation systems
are not used. Methane released during the mining of surface deposits disperses in
the atmosphere and does not reach explosive concentrations.
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Overview
COALBED METHANE GUIDELINES
• Coal Rank. Coal is ranked by its carbon content; coals of a higher
rank have a higher carbon content and generally a higher methane
content.2
• Coal Depth. Pressure, which increases with depth, tends to keep
methane in coal seams and surrounding strata from migrating to the
surface. Thus, within a given coal rank, deep coal seams tend to
have a higher methane content than shallow ones.
In 1990, the coal fuel cycle (which includes coal mining, transportation, and
usage) emitted an estimated 24-40 teragrams (Tg) of methane.3 An additional
1.3 Tg of methane was recovered by coal mines and used as an energy
source. Underground coal mines were responsible for 70 to 85 percent of all
emissions, while surface mines and the transportation of coal were estimated
to contribute 10 to 20 percent. Coal combustion was estimated to contribute
the remaining 5 to 10 percent (USEPA1994).
There are many opportunities to expand
the recovery and use of methane fron
gassy underground coal mines. The
techonolgies are well known and have
been demonstrated worldwide.
2.3 Opportunities to Reduce Methane Emissions
from Coal Mines
Methane recovery and use is technically feasible at many large and gassy coal
mines, but may require a shift in the traditional perception that coal companies
and government authorities have of mine degasification. Techniques for
removing methane from mines have been developed primarily for safety
reasons. Thus, in many cases the recovered methane is released to the
atmosphere with little attention paid to the development of gas use projects. At
mines throughout the world, however, these same techniques have been
successfully adapted to recover methane, allowing the mines to both improve
mine safety and harness the methane for fuel. Many additional opportunities
exist to expand the use of these technologies and reduce worldwide emissions
of methane into the atmosphere.
There are a variety of reasons why coal mine methane projects are a good
way to reduce methane emissions. First, individual gassy coal mines can be
large emitters of methane. Therefore, developing a few key projects can result
in significant emission reductions. Current data indicate that there are a
significant number of large and gassy underground mines around the world
that are good candidates for such emissions reduction projects.
Second, the technologies for recovering methane in conjunction with coal
mining have been well demonstrated and are currently in use throughout the
In descending order, the ranks of coal are: Graphite, Anthracite, Bituminous,
Subbituminous, and Lignite.
One teragram is 106 metric tons, or 1012 grams.
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'OALBED VETIIAXE
GUIDELINES
Ove"\r'.e\v
world (see Exhibit 2-1). The methane recovered using these technologies can
be used in a variety of ways to meet local energy needs, including: on-site use
as gas; on-site use to generate electricity; or sale for off-site use to residential,
commercial, or industrial customers (see Exhibit 2-2).
Exhibit 2-1: Summary of
Underground Mining
Method
Vertical Wells
Gob Wells
Shorthole Horizontal
Boreholes
Longhote Horizontal
Borehole
Cross-measure
Boreholes
Methods for Recovering Methane from
Description
Drilled from the surface to the coal seam several years
in advance of mining.
Drilled from the surface to a few meters above the
coal seam just prior to mining.
Drilled from inside the mine to degasify the coal seam.
Drilled from inside the mine to degasify the coal seam.
Drilled from inside the mine to degasify surrounding
rock strata.
Exhibit 2-2: Summary of Methods for Utilizing Methane from
Underground Mines
Method
On-site
Off-site
Description
Recovered methane can be used on site directly as gas, or can be
used to generate electricity to meet on-site mine requirements. For
example, the methane can be used in the coal preparation plant or
for space heating or water heating. To produce electricity, the
methane can be used to power an engine-generator.
Coal mine owners and developers can sell recovered methane to
nearby industrial, commercial, and residential users. The quantity
and quality of methane produced and the local demand for the
energy will determine the distance that the gas must be transported
and how it will be used. In some cases the methane can be sold to
the local gas distribution network. Similarly, if more electricity is
produced than is required on site, the excess electricity can be sold
to the local power grid.
The benefits of recovering and using coal mine methane are summarized in
the following four main areas:
• Economic. There are several ways by which coal mine methane
recovery and use can lead to economic benefits. For example,
methane recovery through degasification systems can reduce
ventilation costs and improve mine productivity. Also, the mine can
realize cost savings by using the methane for on-site energy needs.
Alternatively, the methane can be sold to customers off site. If the
cost of recovering and using (or selling) the gas is less than the value
of the energy derived, the mine will earn a profit.
In addition to reducing methane
emissions, recovering coal mine
methane has other important benefits:
the gas can be used as an energy
source; ventilation requirements are
reduced; and local air quality is
enhanced.
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r\
uve.-v.ew
OALBED V.ETHANE GUIDELINES
Exhibit 2-3: The UN Framework Convention on Climate Change (UNFCCC)
The signature of the United Nations Framework Convention on Climate Change (UNFCCC) by around
150 countries in Rio de Janeiro in June 1992 indicated a widespread recognition that climate change is a
potentially major threat to the world's environment and economic development.
The Convention aims to stabilize greenhouse gas concentrations in the atmosphere at a level that
—3r - ic~ would prevent dangerous anthropogenic interference with the climate system. Such a level is to be achieved
within a time frame sufficient to allow ecosystems to adapt naturally to climate change. The Convention calls for Annex I countries
to take measures designed to limit emissions of carbon dioxide dioxide and other greenhouse gases, with the aim of returning to
1990 emissions levels by the year 2000.
To achieve this objective, the Convention sets out a series of principles and general commitments. The key principles
incorporated in the treaty are the precautionary principle, the common but differentiated responsibility of states (which assigns
industrialized states the lead in combating climate change), and the importance of sustainable development. The general
commitments, which apply to both developed and developing countries, are to adopt national programs for mitigating climate
change; to develop adaptation strategies; to promote the sustainable management and conservation of greenhouse gas "sinks'
(such as forests); to take climate change into account when setting relevant social, economic, and environmental policies; to
cooperate in technical, scientific, and educational matters; and to promote scientific research and the exchange of information.
• Energy. Coal mine methane can be used to meet the energy
requirements of the mine and nearby areas. The gas can also be
used as a residential, commercial, or industrial fuel. This increased
source of domestic energy can be especially important in nations
where demand is growing rapidly and domestic supplies are
constrained. The increased reliance on domestic energy resources
can also help reduce energy imports, thereby improving energy
security and the balance of payments.
• Environment As explained above, methane is a potent greenhouse
gas. By reducing emissions, coal mine methane projects fulfill a
country's commitment to the United Nations Framework Convention
on Climate Change (UNFCCC). The UNFCCC requires developed
countries (also known as Annex I countries) to adopt measures to
reduce greenhouse gas emissions, with the aim of reducing to 1990
emissions levels by the year 2000 (see Exhibit 2-3).
Furthermore, the recovery of methane increases the supply oftiatural
gas, which has several advantages over other fossil fuels. The
displacement of coal (and to a lesser degree oil) with gas will reduce
emissions of S02, NO,, and participates (USEPA1986). This will lead
to a cleaner local environment.
Safety. At gaseous concentrations of 5 to 15 percent, methane is
explosive. Thus the buildup of methane in underground mines poses
a serious safety hazard. Increased use of degasification systems
may improve safety by reducing methane levels in the mine.
Techniques for recovering methane before mining (through use of
vertical wells drilled from the surface, for example) can significantly
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COALBED VETMANE
GUIDELINES
Overview
reduce the amount of methane in the coal when mining occurs
(USEPA, 1993).
A variety of coal mine methane recovery activities are currently in place around
the world. There are examples of profitable projects involving gas sales and
on-site use. However, many more coal mines can implement economically
viable methane recovery and utilization projects. In some cases, national or
local policies hinder these projects from being undertaken. Relevant policies
should be evaluated to assess if they encourage or discourage methane
recovery and utilization projects. Important issues to analyze include energy
production and pricing, environmental policy, financing issues, and technology
transfer policies.
2.4 References
Crutzen, P.J. 1991. "Methane's Sinks and Sources" Nature Ho. 350. April
1991.
IPCC (Intergovernmental Panel on Climate Change). 1990. Climate Change:
The IPCC Scientific Assessment Report Prepared for
Intergovernmental Panel on Climate Change by Working Group 1.
IPCC (Intergovernmental Panel on Climate Change). 1992. Climate Change
1992. The Supplementary Report to the IPCC Scientific Assessment,
Published for the Intergovernmental Panel on Climate Change
(IPCC), World Meteorological Organization/United Nations
Environment Program. Cambridge University Press. Edited by J.T.
Houghton, G.J. Jenkins, and J.J. Ephraums.
Steele, L.P., E.J. Dlugokencky, P.M Lang, P.P Tans, R.C. Margin, and K.A.
Masarie. 1992. "Slowing down of the global accumulation of
atmospheric methane during the 1980s." Nature. Volume 358. July
23,1992.
USEPA (United States Environmental Protection Agency). 1986. Supplement
A to a Compilation of Air Pollutant Emission Factors; Volume I:
Stationary and Point Sources, U.S. Environmental Protection
Agency/Office of Air Quality Planning and Standards, Research
Triangle Park, N.C.
USEPA (U.S. Environmental Protection Agency). 1993. Options for Reducing
Methane Emissions Internationally, Volume I: Technical Options for
Reducing Methane Emissions, Report to the Congress, prepared by
the Office of Air and Radiation, EPA, Washington, D.C.
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0\e"\'e\\ COMBED VETHANC GUIDELINES
USEPA (U.S. Environmental Protection Agency). 1994. International
Anthropogenic Methane Emissions: Estimates for 1990, Report to the
Congress, prepared by the Office of Policy, Planning and Evaluation,
EPA, Washington, D.C.
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COALIO VCTHANC
GUIDELINES
icerui'v 0"jaor;«:iii.:es "or1 ^ec^cins ^TKS
3. IDENTIFY OPPORTUNITIES FOR REDUCING
METHANE EMISSIONS
nPfflS chapter presents a screening process for national program managers
A to determine if there are coal mines in their countries that are good
candidates for emissions reduction projects. This screening of project
opportunities requires five important pieces of information: (1) the location of
regions or basins that are known to have gassy mines; (2) the number of large
mines in those regions; (3) the amount of methane emitted from each mine;
(4) the expected lifetime of each large and gassy mine; and (5) potential uses
of the recovered methane. This information may be assembled for all mines in
the nation, or, in those nations with a large number of mines, for the largest
mines from each region or basin.
A step-by-step approach is presented to assess whether opportunities for the
implementation of gas recovery projects exist. Each step in the process is a
hurdle to be crossed. If a hurdle cannot be crossed, it is unlikely that
promising emissions reduction opportunities exist. For example, if the gassy
mines in the nation are likely to close in the near future, then there are no
emissions reduction opportunities and the analysis ceases. Assuming that
there are gassy mines, you may find that there can be no market for the
recovered gas. In this case, gas recovery projects cannot be profitable, and
emissions can only be reduced at a cost. The analysis would only proceed if
the program manager is willing to consider emissions reduction options that
cost money. In many countries, this step-by-step process is likely to identify
gassy coal mines with potential for energy recovery resulting in emission
reductions.
The initial screening steps are as follows:
1. Identify Basins or Coal Regions That Contain Gassy,
Underground Mines. The first step in the screening process
involves locating coal basins or regions that have gassy coal mines.
Typically, coal industry experts will be knowledgeable regarding the
gassiness of the underground coal mines in each mining region. In
the absence of specific gas content information, the presence of
degasification systems, the coal rank, or the coal depth can be used
as indicators of gassiness. If suitable coal basins or regions exist, the
analysis proceeds to the next step.
2. Determine the Number of Large, Underground Mines in Each
Coal Basin or Region Identified. For initial screening purposes,
coal mines producing more than 300,000 metric tons of coal annually
will be considered as potential candidates. Coal mines of this size
could generate enough methane to support a recovery project. It
should be noted, however, that this size criterion is not absolute.
Smaller coal mines potentially could support successful recovery and
use projects, given a high level of methane content in the seams.
The first step in the screening process is
to determine whether there are gassy
underground coal mines in your country.
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g imiss'ons
BALDED METHANE GUIDELINES
F" -isial screening purposes, mines
ft -it more than 10 cubic meters ot
rnt-.zne per metric ton of coal produced
are regarded as potential candidates. In
the absence of data on gassiness,
secondary indicators of gas emissions
rates can be used.
3. Obtain Information on Methane Released During Coal Mining.
For initial screening purposes, mines that emit more than 10 cubic
meters of methane per metric ton of coal produced are considered
sufficiently gassy to be regarded as potential candidates. Like the
criteria regarding coal production, this criterion is not absolute. In
addition, while annual production data may be readily available,
information on methane emissions may not be available without
directly contacting individual mine operators. If emissions data is
unavailable, other indications of gasiness may be used, including in-
situ methane content, records of outbursts or explosions, or use of
mine degasification systems.
4. Determine Projected Mine Lifetime. For a project to be
economically viable, the mine should remain open for at least five
years. Once again, this minimum lifetime is only an estimation. The
lifetime necessary for a project to be economically viable will be
specific to each mine. Because some nations are liberalizing and
privatizing their energy sectors, as well as enacting environmental
legislation that may affect coal consumption, many factors other than
the geology of the reserve must be considered in estimating the likely
life time of a coal mine. If this information is not readily available, the
remaining life span may be estimated by dividing the total remaining
reserves by the annual production. Examining the economic and
geological status of other mines in the basin or region may also
provide some clues.
5. Determine Use for the Recovered Methane: In nearly all cases, the
mine will be able to use the recovered methane on-site. Because the
candidate mines are relatively large, they have significant energy and
electricity needs for the mining equipment, for the coal preparation
process, and for water and space heating. In cases where the
amount of methane recovered exceeds on-site energy requirements it
is important to determine if there are other potential energy customers
in the surrounding area.
There are a variety of sources from which the above data may be obtained.
These include the following:
• Various Government Organizations. In many nations, the coal
mines are owned by the central or local governments and/or
government ministries that may be familiar with the mining industry
because they are involved in energy planning, policymaking, or
regulation. For this reason, government entities such as the Ministry
of Coal, Ministry of Industry, Ministry of the Environment, Mine Safety
Bureau, or Geologic Ministry or Institute may have readily available
sources of information.
For example, many countries have a ministry that collects coal
production and coal reserve data for each mine in the nation. Also,
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'OALBED VETIME GUIDELINES
one or more government agencies may • collect data regarding
methane emissions and mine life time. Alternatively, if specific data
are not readily available, industry experts may know if mines in a
particular basin or region are known to be gassy. The mine safety
agency staff might know that mine operators in a particular area were
experiencing problems due to high methane levels and planned to
expand their degasification systems. Similarly, central planning
ministry staff might be aware of likely shifts in coal production among
mines or mine shutdowns resulting from government actions such as
coal sector restructuring or additional environmental regulation.
• Coal Mine Operators. If all the information is not readily available in
a centralized location, it may be necessary to contact individual mine
operators. Data on methane emissions, in particular, may be difficult
to obtain from sources other than those at the mine. Mine operators
will almost certainly have this information because it is needed to
design and operate their mine ventilation system. The feasibility of
contacting individual mine operators however, will depend on the time
and resources available for conducting this screening step.
• Trade Associations, Energy Institutes, and Research
Organizations. These entities may have some of the necessary
data, and in fact, may have more data or may be more accessible
than the government ministries in some cases. Some of these
organizations may prepare energy studies, publish reports, and have
their own energy databases.
• Coalbed Methane Project Developers. Project developers who
recover and use coal mine methane or have done so in the past may
be a good source of information. They may be able to assist in
obtaining the preliminary information or may be willing to share their
experiences with those interested in promoting the implementation of
similar projects.
Using the information from the above five steps, the initial appraisal can be
performed. Exhibit 3-1 lists the questions addressed by each of the five steps.
If each of the questions listed in the exhibit can be answered "Yes," there are
likely to be good opportunities for reducing methane emissions through the
implementation of gas recovery and use projects.
Even if one or more questions cannot be answered "Yes," there may exist,
under certain circumstances, attractive opportunities for reducing emissions.
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.ceri:rv (boonjruies "o
-ciria lim'ssions
COALBED YCTHANE
GUIDELINES
Exhibit 3-1: Initial Appraisal Results Checklist
Are there any coal regions that have underground mines?
Do any of the underground mines in the identified region(s)
produce more than 300,000 metric tons annually?
Yes 3 No 3
4.
5.
Do any of the mines in the identified region that produce more than
300,000 metric tons annually: 1) emit more than 10 cubic meters of
methane per metric ton of coal produced; 2) employ degasification Yes -I No ID
methods; or, 3) exhibit other indications of high methane
emissions?
Do any of the mines that meet the above criteria have a life span
greater than another five years? Yes 3 No 3
Do the coal mines meeting the above criteria have significant
energy requirements; OR are there energy requirements in the Yes 3 No 3
surrounding area?
If the answer is YES to all of the above questions, there are promising options for gas
recovery. Proceed to Chapter 4, where the technical and economic feasibility of
gas recovery at each candidate site will be evaluated.
The following economic and social conditions would favor gas recovery from
coal mines:
• High Energy Cost If the cost of alternative fuels - such as oil, coal,
and conventional natural gas - is high in the area surrounding the
mine, smaller sites may be able to undertake a recovery and
utilization project profitably.
• Recovery Systems Already in Place. Some gassy mines already
may use degasification systems to recover methane for safety
reasons. In such cases, the cost of the project would include only the
cost incurred to employ the recovered methane. Smaller coal mines
would be potential candidates for methane recovery and.utilization
projects in such cases.
• Energy Shortage. Providing coal mine methane to areas* facing
energy shortages offers social and economic benefits that will not be
apparent in a simple financial assessment of the particular project.
The government may undertake a gas recovery project to provide
households with low cost and clean energy, thereby improving their
standard of living. Indirectly, such projects also may have economic
benefits. In such cases, the attractiveness of a gas recovery project
is better evaluated in terms of the social value of energy provided
rather than on a financial cost-revenue comparison.
Finally, it may be desirable to recover and combust methane recovered from
coal mines even if they do not meet the criteria listed above. In particular,
even if there is no opportunity to use the gas economically, methane
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"OALBED VCTHANE GUIDELINES ice-u/v Oaoonunii'.es "or- "rtecjcina limiss'.cns.
emissions can be reduced at relatively low cost by simply collecting and flaring
the gas. Such projects may be attractive to investors in developed countries
who are identifying low-cost options for reducing greenhouse gas emissions
through joint international action. There are a number of safety issues that
must be addressed, however, before flaring may be considered a viable
option. The U.S. Environmental Protection Agency is currently examining this
issue.
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:n:narv
Assessments
OALBED VETIIANC GUIDELINES
ASSESSMENT
This section presents a pre-feasibffity
site assessment aimed at evaluathg
the technical and economic feasbffity
of gas recovery. This is a preliminary
assessment, designed to allow
countries to get sufficient data to show
tfiaf there is merit in pursuing the
project further.
4. PRELIMINARY SITE ASSESSMENTS
'T'HIS section presents guidance for conducting preliminary assessments of
A the candidate sites identified in Section 3. These assessments will
provide a more comprehensive and concrete evaluation of the attractiveness
of each of the gas recovery opportunities. Using site specific information,
project development options that are most technically appropriate and cost
effective will be identified.
Some countries may not have the technical and labor resources needed to
conduct site assessments. Appendix A (at the end of this document) lists
experts that may be contacted to conduct project feasibility assessments and
develop gas recovery projects. Furthermore, Chapter 6 presents steps for
identifying and filling gaps in the availability of technology and expertise
required.
In most cases, the screening process in Section 3 will identify several
candidate sites worthy of this level of analysis. Under this circumstance, a
preliminary site assessment can be conducted for each site. In some cases,
however, so many sites may be considered candidates that it may not be
possible to conduct preliminary site assessments for each at this time. In this
case, it is recommended that several sites with significant emissions reduction
potential be selected for assessment. For example, the mine with the largest
estimated emissions in each coal region or basin could be selected.
Alternatively, sites could be selected to represent a range of mine
characteristics. Based on the results of the analysis of these sites, the need
for additional preliminary assessments at additional sites can be determined.
The preliminary site assessment examines the main factors influencing the
attractiveness of gas recovery projects. Section 4.1 describes the general site
information required. Section 4.2 presents the various recovery techniques
and Section 4.3 discusses the possible use options. Finally, Section 4.4
discusses the economic feasibility of these methods.
4.1 General Site Information Required
The preliminary site assessment begins by collecting general site information.
which will be used to examine the following: methods for recovering methane;
the quantity of gas likely to be produced; and the potential uses for the gas
recovered. For purposes of this preliminary assessment, the amount of gas
that can be produced will be estimated from information on the amount of
methane released by the mine during mining activities. The following
information should be obtained or estimated:
• Current and Future Coal Production. Obtain recent annual coal
production statistics from the mine (metric tons per year). Estimate
the number of years that the mine will continue to produce coal.
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'OALBED VETIIANE GUIDELINES
"Jre!:m:narv Siie Assessment
Identify whether the rate of coal production is expected to change
significantly in the near future.
Degasification System. Identify whether the mine has a
degasification system (in addition ot the ventilation system). Section
4.2 (below) describes various degasification systems that may be in
use.
Methane Emissions. Estimate current and expected future methane
emissions from this mining activity. Options for estimating this
quantity include:
1. Ventilation System Emissions: Methane emissions from the
ventilation system equal the methane concentration in the
ventilation air (typicaly less than one percent) times the volume
of ventialtion air (e.g., in cubic meters per day). The mine's
engineering staff generally knows or can estimate these
quantities.
2. Degasification System Emissions: If the mine has a
degasification system (in addition ot the ventilation system) the
methane emissions from this system must be estimated and
added to the emissions from the ventilation system.
Degasification system emissions are highly site-specific and
must be estimated from individual mine data obtained from the
mine's engineering staff. Identify the amount of methane emitted
(e.g., in cubic meters per day) and the'concentration of the
methane in the gas flow from the degasification system (e.g., in
percent).
3. In Situ Gas Content The methane emissions from the mine can
be approximated using the in situ gas content of the coal. At a
minimum the methane emissions will be equal to the gas content
per ton times the annual coal production in tons. In addition to
these emissions, methane is generally released from strata
surrounding the coal. The emissions from the surrounding strata
are highly site-specific, but may be equal in magnitude to the
emissions from the gas in the coal itself. The mine's engineering
staff can normally estimate the in situ gas content and emissions
from surrounding strata if emissions cannot be estimated from
ventilation and degasification system data.
Coal Characteristics. The permeability of the coal will influence the
types of gas production techniques that can be used. Obtain from the
mine's engineering staff whether the coal has high or low
ASSESSMENT
The mine's engineering staff generally
has sufficient information to estimate
current methane emissions from trie
mine. Current emissions will be used to
estimate potential gas production for the
preliminary assessment
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're::m:.ia.T Siie Assess.-nenis COALBED V.ETHANE GUIDELINES
permeability. Permeability of 1-2 millidarcies (md) is considered low,
3-10 md is medium, and permeability of over 10 md is high.4
• Terrain and Land Use. The local terrain and land use may impose
constraints on the types of gas production techniques that can be
used. Obtain a general description of the local terrain and land use
condition. In particular, assess whether wells can be drilled from the
land surface into the coal seam being mined and its surrounding
strata.
• On-slte Energy Requirements. Estimate current and expected
future on-site energy requirements. Current or potential on-site gas
use (e.g., for coal preparation or water and space heating) may be
estimated in terms of energy requirements (e.g., megaJoules (MJ) or
BTUs required per day). Estimate electricity usage in kiloWatt-hours
(kWh) per day. In addition to the quantity of on-site energy use,
estimate the cost of this energy.
• Potential Off-site Gas Use. If the mine is unable to use all the gas
produced, off-site gas use options must be examined. To conduct
this examination, a general survey of energy-using opportunities
around the site may be required. At a minimum, determine whether
there is a gas transmission/distribution system or an electric power
grid in close proximity to the mine. Also, identify any large energy
using facilities near the mine. A more detailed survey should be
conducted once it is clear that on-site energy requirements are less
than the amount of energy produced.
It is expected that not all the above information will be available from all the
relevant facilities. As much information should be obtained as possible within
the time and resources available so that a reasonable overview of the mine
and its energy situation can be obtained. If necessary, "general usage factors"
regarding energy requirements for the mine can be applied to provide a rough
approximation of the likely energy demand.
One way to obtain this information is to prepare a survey send it to the mine.
The mine's engineering staff should be able to provide the information
relatively easily. If possible, verify the information in follow up meetings with
the mine personnel. Once the information is obtained, the assessment moves
to the next step to identify potential gas production techniques.
Permeability is a measure of fluids to flow through the coal and surrounding strata.
Permeability is measured in dairies.
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COALBED VETHANE
GUIDELINES
3'ie Assessment
4.2 Identify Potential Recovery Methods and Estimate
Gas Production
The purpose of this step is to identify one or more potential gas recovery
techniques that can be used to produce gas at the mine site. The final
selection of the preferred technique requires a detailed gas production
assessment that is beyond the scope of the preliminary site assessment.
However, this step will provide a rough indication of the alternatives to be
considered so the potential economic performance of the project can be
examined.
Each of the major gas production techniques is described in the next section.
Following these descriptions, the criteria for selecting one or more method for
evaluation in the preliminary assessment are presented.
ASSESSMENT
43.1 Gas Production Methods
Methods for producing gas from active coal mines include vertical wells, short
horizontal boreholes, longhole horizontal boreholes, gob wells, and cross-
measure boreholes. Vertical wells and gob wells are drilled from the surface to
the coal seam, while the various types of boreholes are drilled from inside the
mine. Vertical wells, horizontal boreholes, and longhole horizontal boreholes
recover methane in advance of mining, and typically can produce nearly pure
methane gas. Gob wells and cross measure boreholes recover methane from
areas that have already been mined and consequently usually produce gas
that is contaminated with mine air, so that it is not pure methane.
This section describes each of the major degasification methods and provides
information for determining whether a method might be appropriate for a
particular mine.
Vertical Wells
Description: Similar in design to conventional oil and gas wells, vertical wells
are drilled from the surface into the coal seam several years in advance of
mining. In the U.S., they range from 300 to 600 meters in length, depending
on the depth of the mine. Well spacing depends on reservoir, geological, and
surface conditions. In the U.S., well spacing can range from one well per
8 hectares (20 acres) to one well per 65 hectares (160 acres).
.Vertical wells usually require hydraulic fracturing of the coal seam to activate
the flow of methane. These wells may produce large quantities of water and
small volumes of methane during the first several months of operation. As this
water is removed and the pressure in the coal seam is lowered, gas production
increases. This water produced by vertical wells is the same water that would
be removed when the coal is mined. Generally, this water must be treated and
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!"e.:.7i:na."V Siie Assessments COALI3ED V.ETHANE GUIDELINES
disposed in a manner that is similar to the treatment and disposal performed
for the water produced during mining. Since vertical wells are operated
several years in advance of mining, the equipment for water treatment would
need to be installed and operated sooner than would be necessary if the water
were handled during mining.
Vertical wells typically produce gas with a methane content greater than 95
percent because the methane that is recovered is not diluted with air from the
mine workings. The total amount of methane recovered using vertical pre-
drainage will depend on both the site specific geology and the number of years
the well is 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 possible for operations drilling vertical degasification wells at
least 10 years in advance of mining.
Although not widely used in the coal mining industry, vertical wells are used by
numerous stand-alone5 operations that produce methane from coal seams for
sale to natural gas pipelines. The use of this recovery method is growing in
the U.S. Exhibit 4-1 presents a schematic of a vertical degasification well.
Suitability/Technical Feasibility: Vertical wells (along with longhole horizontal
boreholes) are the preferred recovery technique when nearly pure methane
must be produced. Vertical wells are suitable for mines that have access to
advanced technology, can plan several years in advance of mining, have
medium or highly permeable coal seams, and have geological characteristics
that permit drilling from the surface. One advantage of vertical wells is that
they may be used in conjunction with virtually all coal mining methods. U.S.
coal mines employing this technique have successfully recovered large
amounts of high quality methane for sale through conventional gas pipelines.
Vertical wells cannot be used on low permeability coals (less than 3 md), when
surface access is restricted, or when degasification cannot be planned in
advance. In low permeability coal seams, vertical wells may not be effective
due to limited methane flow through the seam. Additionally, there is some
concern that in certain geologic conditions the hydraulic fracturing required to
stimulate production from a vertical well may cause damage to the roof rock,
which would hinder mining operations. However, U.S. mines employing this
technique have shown that hydraulic fracturing can be controlled and should
not adversely affect future mining. Finally, due to the need to fracture the coal
seam in advance of mining, vertical wells require a more advanced
technological expertise than do some of the other methods.
5 The term 'stand-alone' refers to coatbed methane operations that produce methane
from coal seams that are not being mined. In most cases, these operations recover
methane from deep and gassy coal seams that are not likely to be mined in the
foreseeable future.
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COALBED VETUANE GUIDELINES
"Jr'e^nf]'.na''v
Exhibit 4-1: Schematic of a Vertical Degasif ication Well
Vertical Well
Short Horizontal Boreholes
Description: Short horizontal boreholes are drilled from inside the mine (as
opposed to from the surface) and they drain methane from the unmined areas
of the coal seam or blocked out longwall panels shortly before mining. These
boreholes are typically 10 to 300 meters 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 have been used for short-term methane
control during mining.
Because methane drainage only occurs from the coal seam being mined (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
is captured (USEPA1990). However, this methane is typically 95 percent pure
methane. (USEPA 1993a). Exhibit 4-2 presents a schematic of a short
horizontal borehole.
Su/faM/fy/Tec/in/ca/ Feasibility: Horizontal boreholes recover nearly pure
methane and therefore can be used when high quality gas is desired. They
require access to advanced drilling technology and are most successful when
the coal is relatively permeable. As the recovery efficiency is quite low,
however, other recovery methods may be preferred for economic reasons.
Because they drain methane prior to mining, horizontal boreholes can be used
in conjunction with all mining methods. They are difficult to implement,
however, when coal seams are steeply inclined.
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;e
OALBED V.ETHANE GUIDELINES
Exhibit 4-2: Schematic of Short- and Longhole-Horizontal Boreholes
Mined Area
Unmined Area
Coal Seams
Short Horizontal
(ore-mining)
Long Horizontal •
(pre-mining)
Longhole Horizontal Boreholes
Description: Like horizontal boreholes, longhole horizontal boreholes are
drilled from inside the mine in advance of mining. They are greater than 300
meters in length and are drilled in unmined seams using directional drilling
techniques. Nearly pure methane is recovered and the recovery efficiency is
about 50 percent. Exhibit 4-2 presents a schematic of a longhole horizontal
borehole.
Suitability/Technical Feasibility: Longhole horizontal boreholes recover nearly
pure methane and therefore can be used when high quality gas is desired.
They are most suitable for mines that have access to advanced drilling
technology. They are particularly effective for gassy, low permeability coal
seams that require long diffusion periods. As they drain methane prior to
mining, longhole horizontal boreholes can be used in conjunction with all
mining methods.
Gob Wells
Description: The fractured zone caused by the collapse of the strata
surrounding the coal seam in longwall and room-and-pillar mining is known as
a "gob" area. Following collapse of this area, a significant amount of methane
is released. Gob wells are drilled from the surface to a point 2 to 15 meters
above the target seam just prior to mining. In the U.S., they range from 300 to
600 meters in length, depending on the depth of the mine. Although the
spacing of gob wells varies at each mine, generally two to six gob wells are
used per longwall panel. As mining advances under the well, the methane-
charged coal and strata around the well fractures. The methane emitted from
these fractured strata flows into the gob well and up to the surface. A vacuum
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COALBED METHANE GUIDELINES
e.:n.viaii\
Exhibit 4-3: Schematic of a Gob Well
is pulled on the well in most cases to prevent methane from entering mine
working areas. Exhibit 4-3 presents a schematic of a gob well.
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, reducing purity to between 30 and 80 percent. In some cases, it is
possible to maintain nearly pure methane production from gob wells through
careful monitoring and management. For example, the Jim Walter Resources
mines in Alabama have been able to maintain nearly pure methane production
from their gob wells.
Methane 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 their gob wells initially produce at
rates in excess of 56,000 cubic meters per day. Over time, production rates
typically decline until a relatively stable rate is achieved, typically in the range
of 2,800 cubic meters per day (USEPA 1990). Depending on the number and
spacing of the wells, gob wells can recover an estimated 30 to over 50 percent
of the methane that would otherwise be emitted from the coal mine (USEPA
1990).
Suitability/Technical Feasibility: Gob wells can be used to produce medium
quality gas, and if the initial quality is maintained, can produce high quality gas
as well. Such wells are suitable for all types of mining methods where gobs
are created, and for mines where wells may be drilled from the surface. Gob
wells can be effectively used in both low and high permeability seams as the
coal seam is fractured by the mining activity. This fracturing and breaking of
the seam and strata releases large amounts of methane, even in low
permeability areas. As with the vertical wells, it is necessary to consider the
surface conditions when assessing the technical feasibility of using gob wells.
If it is heavily populated or if the terrain from the surface to the target seam is
harsh, it may be difficult to drill a well. In addition, gob wells may be difficult to
place in mines where multiple seams have been mined. However, the
ASSESSMENT
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',e
COALBED VETI1ANE GUIDELINES
Exhibit 4-4: Schematic of a Cross Measure Borehole
Unmined Area
Mined Area
Coal Seams
Cross-Measure
technology required to drill a gob well is not as complex as that required to drill
a vertical well. This is because hydraulic fracturing of the coal seam in
advance of mining is not required for gob wells.
Cross-Measure Boreholes
Description: While horizontal boreholes recover methane from the target coal
seam, cross-measure boreholes degasify the overlying and underlying rock
strata. These boreholes are drilled from within the mine and generally produce
medium quality gas (similar to the gas produced by gob wells) depending on
site specific conditions. In the U.S., these boreholes typically range from 45 to
90 meters in length, are developed to depths ranging from 45 to 85 meters,
and are installed 60 to 90 meters apart. Cross-measure boreholes recover up
to 20 percent of methane that would otherwise be emitted. A schematic of a
cross measure borehole is presented in Exhibit 4-4.
Suitability/Technical Feasibility: Methane recovered from cross-measure
boreholes can be used when medium quality gas is sufficient. This method
requires only a low level of technology, and can be used effectively in both low
and high permeability seams. However, as recovery efficiency is quite low,
alternative production techniques may be preferred for economic reasons.
Exhibit 4-5 summarizes the characteristics of the gas production technologies.
As shown in the exhibit, vertical wells have the highest recovery efficiency (up
to 70 percent) and can typically recover nearly pure methane.
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COALBED VETIIANE
GUIDELINES
;ie s
4.2.2 Criteria for Selecting a Gas Production Method
For purposes of conducting the preliminary assessment, select one or two gas
production options for evaluation. As; mentioned above, when the project
moves beyond the preliminary assessment a detailed gas production
assessment will be conducted to select the preferred gas production method.
Therefore, this selection is strictly for preliminary evaluation purposes. The
following criteria are recommended.
• Existing Degasification System. If the mine already has a
degasification system that is optimized to promote efficient mine
production, then this existing system should be the primary candidate
for consideration.
• Coal Mining and Site Conditions. Select the option that is
consistent with existing coal production conditions. If the terrain and
land use activity permit it, vertical wells and gob wells would likely be
the two options most worthy of consideration. Both methods have
high recovery efficiencies. Additionally, both vertical and gob wells do
not require advanced in-mine drilling technology. Vertical wells
should not be considered, however, when the coal has low
permeability, or when degasification cannot take place in advance of
mining. Gob wells cannot be used if the mining technique does not
produce gob areas.
• Gas Quality Requirements. If nearly pure methane is required for
gas use, gob wells may be less preferred. In this case, vertical wells
and in-mine drilling options should be examined. If longhole drilling
can be conducted, its higher recovery rate may make it attractive.
The selection of the gas production method may need to be revisited when the
gas use options are examined. As discussed below, the perferred gas use
may impose constraints on gas quality and quantity.
4.2.3 Estimate Recovery Potential
Once the preferred gas production methods are selected, the amount of gas
that can be produced by each is estimated. If a mine has an existing
degasification system, gas quantity and quality are simply estimated based on
the current performance of the system. This information was collected as part
of the general site information (see above). If the mine's engineering staff
expects that enhanced production is possible as part of a recovery project,
increased rates of gas production can be considered.
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Exhibit 4-5: Summary of Methods for Recovering Methane from Underground Mining
Method/Description \ Methane Quality Recovery Applicability j Possible Utilization Options
j Efficiency8
Vertical Wells
Drilled from the surface to the coal
seam several years in advance of
mining.
Gob Wells
Drilled from the surface to a few
meters above the coal seam just
prior to mining.
Short Horizontal Boreholes
Drilled from inside the mine to
degasify the coal seam.
Recovers nearly pure up to 70%
methane.
!
May be used with all mine types where the terrain All use options; preferred method for use options
permits drilling from the surface; not suited for low- requiring nearly pure methane.
permeability seams.
Recovers medium
quality gas: methane
mixed with mine air.
Quality can vary over
time.
Recovers nearly pure
methane.
Longhole Horizontal
Drilled from inside the mine in Recovers nearly pure
advance of mining. methane.
Cross-measure Boreholes:
Drilled from inside the mine to Recovers medium
degasify surrounding rock strata. quality gas: methane
mixed with mine air.
Quality can vary over
time.
up to 50%
Can be used with all mining methods that create
gob areas; can be used in low and high permeability
seams; the terrain must allow for surface drilling.
,
up to 20%
up to 50%
Can be used with all mining methods; may not be
suited for low-permeability or steeply inclined
seams; best when used in conjunction with other
degasification techniques.
Can be used with all mining methods; effective in
low and high permeability seams.
Some mines may be able to recover nearly pure
methane from gob wells. In such cases, the use
options would be the same as for vertical wells.
When recovery of high quality methane is not
feasible, gas use would be limited to power
generation and other options that can use medium
quality gas.
Same as vertical wells, though recovery efficiency
is low, so may need to be used in conjunction with
another method.
Same as for vertical wells.
up to 20%
Sources: USEPA 1993a,b.
a Percent of methane recovered that would otherwise be emitted.
Can be used with all mining methods that create Gas use options are limited to power generation
gob areas; can be used in low and high permeability and other options that can use medium quality gas.
seams; best when used in conjunction with other May need to be used in conjunction with another
degasification methods. method as recovery efficiency is low.
: ,
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"OALBED YETIIANE GUIDELINES
S:ie Assessment
If there is no degasification system in place, the amount of methane that may
be recovered from a new system can be estimated by multiplying methane
emissions from the ventilation system by the recovery efficiency listed in
Exhibit 4-5. The emissions from the ventilation system were etimated as part
of the general site information. For example, if a mine emits 600 million cubic
meters of methane annually from its ventilation system, gob wells, which
recover up to fifty percent of the methane emitted, should be expected to
produce up to 300 million cubic meters of methane annually. Alternatively,
vertical wells would produce up to 420 million cubic meters' (70 percent of
emissions). Actual gas production will vary with site conditions and system
operation.
Exhibit 4-5 also lists the quality of the gas likely to be produced by each of the
methods. For example, the gob wells would likley produce medium quality
gas, whereas vertical wells can produce high quality gas (nearly pure
methane).
ASSESSMEMT
4.3 Identify Potential Uses for Recovered Methane
Methane recovered from coal mines can be used in a variety of applications.
In general, any equipment that can use natural gas as a fuel source can be
operated using coal mine methane. Additionally, coal mine methane can
substitue for oil and coal in many applications. The preferred methane use
option at each mine will depend on a variety of factors including the quantity
and quality of the methane recovered and local energy needs. First, the main
use options are described. Then, a process for selecting which options to
consider in the preliminary assessment is presented.
4.3.1 Options for Using Coal Mine Methane
The easiest and often least costly option for using coal mine methane is to use
the gas to fuel equipment at the mine. Both high quality and medium quality
gas (methane mixed with air) can be used in a variety of on-site applications,
including:
• Coal Preparation Plants. Coal preparation involves cleaning and
drying the coal. Coal mine methane can fuel the thermal dryers that
heat the air used to remove surface moisture from the coal. Although
coal is typically used to fuel the coal'drying process, the equipment
can be converted to use gas. The coal that would have been used to
fuel the thermal dryer can then be made available for sale.
• Mine Boilers. Recovered methane can be used in boilers for space
and water heating. For example, some mines may have bath houses
or dormitories that require hot water. Also, in some regions, it may be
necessary to heat the ventilation air in the winter before it is pumped
In the Rybnik coal region of the Upper
Silesian Basin in Poland, several mines
use recovered methane in their coal
drying plants as well as in their boiler
houses. CONSOL's Buchanan Mine in
Virginia (USA) has displaced the use o1
coal in its preparation plant thermal dryer
with coal mine methane.
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S'ie Assessment COALIJCD V.CTHANE GUIDELINES
into the mine. In the Donetsk Basin in Ukraine, a small amount of
coal mine methane is used in mine boilers.
• Cooking. Mines that have kitchens can use the recovered methane
for cooking purposes.
• Water Treatment Coal mine methane can be used to fuel the
process of treating water recovered during mining. A demonstration
project is underway at the Morcinek mine in Poland that involves
using the methane for this purpose. Once the water is treated, it will
be used for agricultural purposes.
The advantages of using coal mine methane in these uses on-site include:
(1) the gas does not need to be tranported over a long distance; (2) gas quality
need only be maintained at the level required for the on-site equipment; and
(3) purchase agreements or other sales arrangements do not need to be
negotiated. Additionally, experience indicates that only minimal conversion of
existing equipment is needed to convert from other fuels to coal mine
methane.
An alternative to using the gas on site in heating, drying, and related
applications is to use the gas to produce electricity. The electricity can be
used on site or, as discussed below, sold off site.
Gas turbines, internal combustion (1C) engines, and boiler/steam turbines can
each be adapted to generate electricity from coal mine methane. However,
the most likely choice of a prime mover for a coal mine methane project would
be a gas turbine. Boiler/steam turbines are generally not cost effective in the
size range typically encountered with coal mine methane projects (e.g., below
30 MW), and 1C engines are more sensitive to variations in fuel heating values
than are gas turbines. Furthermore, gas turbines are smaller and lighter than
1C engines and historically have had lower operation and maintenance costs.
A methane/air mixture with a heating value of at least 13,000 kJ/m3 is a
suitable fuel for each of the prime mover options. All of the gas production
methods discussed above, including gob wells, can produce gas of this quality,
which is the equivalent of about 35 percent methane in air.
Generating electricity is an attractive option because most coal mines have
significant electricity loads. Electricity is required to run nearly every piece of
equipment including mining machines, conveyor belts, desalination plants,
coal preparation plants, and ventilation fans. Ventilation systems in particular
require large amounts of electricity because they run 24 hours a day, every
day of the year. In the U.S., about 24 kWh of electricity are required per ton of
coal extracted from the mine and 6 kWh are required per ton of coal processed
in the coal preparation plant. Several small power generation projects are
operating at coal mines in China, the Czech Republic, Poland, Australia,
England, and Germany (Sturgill 1991).
The viability of producing electricity from coal mine methane may be limited,
however, 'if the amount and consistency of the gas produced varies
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COALBED VETIIAXE
JUIDL'LINCS
Assessments
considerably from day to day. For example, some gob wells are not
predictable with respect to length of production, methane concentration, and
rate of flow. Equipment to blend the air and methane may be needed to
ensure that variations in heat content remain within an acceptable range for
the prime mover. A supplemental gas source may be desired, and a reliable
back-up power source may be required to guard against potential gas
production or equipment problems.
In the event that electricity generating potential exceeds on-site needs, the
excess electricity can be sold to the local power grid. Because on-site
electricity requirements vary by time of day and day of week depending on
mining activity, the availability of excess electricity for sale may be intermittent.
Arrangements will be required with the local power authority to sell the
electricity into the system.
If on-site use and electricity generation are not feasible, the gas can be sold to
customers off site. The most attractive off-site sales option is to a gas
transmission or distribution system in close proximity to the mine. To be
viable, the coal mine methane must be processed to meet the specifications of
the pipeline receiving the gas. For most coal mine methane, the principal
contaminants are water and sand, which can be easily removed. After being
processed, compressors are used to pressurize the gas to the appropriate
pressure for injection into the pipeline.
In most regions, conventional gas pipelines carry high quality gas, which would
be the equivalent of nearly pure methane. Therefore, to sell gas to this type of
pipeline, the coal mine methane recovery system would need to be designed
and operated in a manner to produce this high quality gas. If lower quality gas
were produced it would need to be enriched. However, enrichment is often too
costly to be economically viable.
In some areas, medium quality gas is distributed through pipelines. These
pipelines are typically separate from the pipelines that distribute conventional
gas, depending on the local pipeline quality standards. Because coke oven
gas and methane recovered from coal mines can have similar heating values,
in some cases medium quality coal mine methane can be transported via
existing coke oven gas pipelines. If a medium quality gas pipeline is available,
the constraints on gas quality produced at the mine are reduced.
To be economical, the pipeline receiving the coal mine methane must be in
reasonably close proximity to the mine. Building and operating a pipeline
solely to carry the coal mine methane can be costly, and consequently the
transport distance should be minimized. If no suitable pipelines are in
proximity to the mine, alternative gas uses near the mine must be identified.
As described above, coal mine methane can be used to fuel nearly all types of
equipment that use natural gas. Additionally, the gas can be substituted for oil
or coal in many applications. Therefore, industrial, commercial, institutional, or
household energy requirements near the mine can be met using coal mine
ASSESSMENT
In the United States, Jim Walter
Resources is selling high quaSty
methane recovered from its mines in
Alabama to a local gas distribution
company. The gas is sold on the
same basis as conventional natural
gas, and in 1994, the company sold
approximately 3.8 billion cubic meters
of methane.
Mines in the Fushun coal mining
association m China are transporting
medium quality coal mine methane off
site. In 1993,113 million m3 of gas were
recovered, and about 75 percent of the
gas was supplied to 160 thousand
households for cooking and heating use.
Twenty percent of the methane was used
by the local chemical industry, and the
remaining five percent was used to
generate electricity.
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S.'ie Assessments
COALBED V.ETIIANE
GUIDELINES
If the opportunity to use gas on site is
stater to the level of estimated gas
production, direct on-site use will likely
be the preferred use option for
subsequent evaluation.
methane. The principal limitation to using the gas in these sectors is the cost
of transporting the gas to its point of use.
Coal mine methane can also be used as a feedstock in chemical production.
Methane is a feedstock in several important chemical processes, such as the
synthesis of ammonia, methanol, and acetic acid. Using high quality gas as a
chemical feedstock may be attractive for gassy mines in countries with
substantial domestic petrochemical markets. Alternatively, high quality
methane from several small mines could be collected at a central location in
order to meet the volume required by the chemical plant. Currently, in
Poland's Upper Silesian Basin, a small amount of coal mine methane is being
used as feedstock for a chemical plant.
Exhibit 4-6 summarizes the characteristics of these gas use options.
4.32 Select Use Options for Further Analysis
For purposes of conducting the preliminary assessment, each of the major gas
use options should be examined. When the project moves beyond the
preliminary assessment a detailed gas use assessment will be conducted to
select the preferred option.Jhe following options are recommended.
• On-site Use. Compare the on-site energy requirements (estimated
as part of the general site information) to the amount of gas
anticipated to be produced. If the opportunity to use gas on site is
similar to the level of estimated gas production, direct on-site use will
likely be the preferred use option for subsequent evaluation. If the
potential for direct on-site gas use is much less than the anticipated
gas production, an alternative use option should be identified.
It is recommended that the estimated gas production be compared to
on-site gas needs on an energy basis. The energy content of the gas
is estimated from its methane content. Pure methane has a heating
value of approximately 37 million Joules per cubic meter (MJ/m3) at
standard temperature and pressure. Gas that is 50 percent methane,
for example, will have a heating value of 50 percent that amount, or
about 18.5 MJ/m3.
• Electricity Generation. If on-site gas use is not feasible, or if the
amount of gas produced greatly exceeds on-site needs, electricity
production may be an attractive option. Compare the on-site
electricity requirements (estimated as part of the general site
information) to the amount of electricity that can be generated from
the gas anticipated to be produced. The amount of electricity that can
be generated from the methane may be estimated using the following
formula:
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COALBED VETIIANE
SIDELINES
'J:>e.!:ri::iariv S'ie Assessments
Electricity Generated (kWh) =
[Gas Recovered (ms) x Heating Value of the Gas (MJ/m»)] /
Generator Heat Rate (MJ/kWh)
The generator heat rate varies somewhat among generation
technologies, but can be assumed to be about 11.6 MJ/kWh, which is
appropriate for combustion turbines.
Using these values, an example calculation of potential electricity
production is as follows. Assume that 200,000 mVday of gas is
produced that is 50 percent methane. The heating value of the gas is
18.5 MJ/m3. The total electricity that can be produced is therefore:
200,000 m'/dayx 18.5 MJ/m'/ 11.6MJ/kWh = 318,965 kWh/day.
The generator capacity is this value divided by 24 hours, or about
13,300 kW, or 13.3 MW.
If on-srte requirements are much less than.potential electricity
production, then off-site electricity sales may be required to make
electricity production economically feasible. Such off-site sales may
be less attractive than off-site gas sales, discussed next. Also, a
combined gas use/electricity production approach can be examined in
which a portion of the gas is used directly or sold, and a portion is
used to produce electricity.
ff an off-site customer in dose proximity
to the mine can use the gas without
costtygas enrichment or processing, this
use option will be attractive.
Exhibit 4-6: Summ
Option
Direct use on-site
On-site electricity
generation
Sale into an Existing
Gas Distribution or
Transmission
System
Sale directly to an
industrial,
residential, or
commercial user
Chemical Feedstock
ary of Coal Mine M<
Min. Quality
Necessary
Medium
Medium
High
Medium
Medium
High
jthane Use Options
Applicability
Suitable for most mines, can be used
to fuel coal preparation plants, heat
space and water, and treat water
Most suitable for mines with large
electricity needs, especially those
which already produce their own
electricity.
Most suitable for mines using
premining degasification and located
near existing high quality gas
pipelines.
Most suitable for mines located near
medium quality pipelines.
Suitable for mines located near
industrial or commercial facilities, or
near residential areas.
Most suitable for very gassy mines
using degasification techniques that
recover nearly pure methane and are
located near chemical plants.
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ie Assessments
OALBED V.ETHANE GUIDELINES
If off-site sales appear to be required,
both electricity sales and gas sales
should be evaluated as part of the
preliminary assessment
• Off-site Gas Sales. Generally, off-site gas sales should be
considered when the above on-site use options are not attractive.
Some site-specific conditions, however, may make off-site gas sales
the most attractive gas use option. In particular, if an off-site
customer in close proximity to the mine can use the gas without costly
gas enrichment or processing, this option will be attractive. Off-site
gas sales can also be examined in combination with on-site use.
To assess the off-site gas sales option, a brief survey of potential gas
use in the area around the mine is warranted. Identify the location of
existing gas pipelines as well as potential industrial, commercial, or
residential customers. The distance to these potential gas customers
should be determined because distance is one of the key driving
factors of the cost of supplying gas to them.
The choice between off-site electricity sales and off-site gas sales will depend
on site-specific conditions. The advantage of off-site electricity sales is that
the gas quality need only be maintained at the level required for the on-site
electric power generator system. If only medium quality gas is produced, this
advantage can be important. The disadvantages are that an electric power
grid must be near by, and a power sales agreement must be negotiated. The
price at which the electricity can be sold will determine the economic feasibility
of this approach.
The advantage of off-site gas sales is that if a customer is near by, the cost of
producing and transporting the gas can be quite low. However, if the gas
customer needs high quality gas and only medium quality gas is produced by
the mine, the enrichment cost may make the project uneconomical. Given the
site-specific nature of the choice between these off-site sales options, it is
recommended that if off-site sales appear to be required, that both electricity
sales and gas sales be evaluated as part of the preliminary assessment. If
either or both of the options appears promising based on the preliminary
assessment results, they can both be evaluated in subsequent site-specific
studies.
4.4 Assess Economic Feasibility
The purpose of evaluating the economic feasibility of the project options is to
ensure that the project meets a target level of cost effectiveness. There may
be several goals of a gas recovery project: profitability; energy supply; or
emissions reductions (or a combination of the three). If only profitable projects
are to be considered, then revenues must exceed costs. If a net cost can be
incurred to reduce methane emissions and meet other environmental goals,
the threshold may be set in terms of cost per ton of emissions (e.g., $2/ton of
CO? equivalent emissions avoided). Alternatively, if the goal of the project is to
meet national or local energy demands, the threshold may be set in terms of
cost per unit of energy supplied (e.g., $0.07/kWh). Regardless of the
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COMBED VETHANE
GUIDELINES
"J"
8:rn.:ia'-y
Assessment
objective, the capital and operating costs of the project must be estimated and
balanced against the estimated revenues and other benefits.
Information from all parties potentially involved in the gas recovery project
should be considered at this stage of the assessment, including potential
energy users, the facility owner or operator, and equipment suppliers. If
energy production or prices are regulated, information from the appropriate
ministries should be obtained as well to help assess potential costs and
revenues. First, the cost analysis is presented, followed by the benefits
analysis, which includes a discussion of how to compare the costs and
benefits to assess economic feasibility.
It should be noted that labor and equipment costs can vary significantly among
countries and regions within countries. The dollar cost estimates presented in
this section represent U.S. prices. Potential additional transportation costs or
tariffs are not reflected. Additionally, operating and maintenance costs include
labor charges, which can vary significantly. Adjustments to local currencies
and cost conditions should be attempted whenever possible.
ASSESSMENT
4.4.1 Costs Analysis
Costs of recovering and using coal mine methane are highly dependent on the
amount of gas involved, the specific technologies used, and site-specific
factors. The cost estimates developed as part of this preliminary assessment
will be compared to revenue (or cost savings) estimates to make a rough
assessment of the economic viability of the project alternatives. If one or more
alternative project configurations looks promising, "more detailed cost
estimates will be conducted as part of subsequent more detailed studies.
Therefore, the cost estimates prepared here are solely for preliminary
assessment purposes.
As with all project evaluations, both capital costs and annual operating costs
will be considered. To estimate these costs, a listing of each piece of
equipment required must first be prepared. Exhibit 4-7 lists the major pieces of
equipment required for the project configurations that may be considered. As
shown in the exhibit, three main systems are required for all projects: the
degasification system; the gas collection and gathering system; and the gas
processing system. If the mine already has one or more of these systems, and
does not plan modifications for this project, then the costs for the existing
components may be excluded. For example, some mines will already have a
degasification system in place and operating.
The pieces of equipment required for on-site gas use, electricity production,
and off-site gas use are also listed. Gas enrichment equipment is listed for off-
site gas sales, but will only be required when the gas quality must be
enhanced.
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i-roa-v "Siie Assess-nenis COALBED VETIIANE GUIDELINES
In addition to the costs for these pieces of equipment, additional costs that
must be considered include:
• System Design. The costs of the system design and construction
management may be on the order of 15 percent of the total capital
cost for the project.
• Legal. Siting, permitting, and land use requirements must be met.
These costs, which can be substantial, include the costs of obtaining
necessary permits and licenses, and potentially installing pollution
control equipment.
• Financing. Financing costs include the cost for obtaining financing
as well as interest payments. These costs depend on the financing
method and project specific factors.
• Rights-of-Way. Costs of obtaining rights-of-way to run pipelines or
power lines must be considered and may be substantial.
Experience in the U.S. indicates that these additional non-equipment costs can
be substantial. However, due to their site-specific nature, general cost factors
cannot be provided to estimate each type of cost.
Given this approach, the equipment capital and operating costs are the
primary costs estimated in the preliminary assessment Exhibit 4-8 provides
cost coefficients for the main pieces of equipment required. It must be noted,
that costs will vary significantly among projects and among countries. The
costs presented here are based on U.S. experiences and technologies and are
presented in U.S. dollars.
To estimate project costs, perform the following:
1. Define the project configuration in terms of the gas production
system and gas use option.
2. Identify the pieces of equipment required for the project
configuration. Do not include equipment that the mine already
has in place (e.g., if the mine has an existing degasrfication
system).
3. Select a project lifetime, for example between 10 and 20 years.
The sensitivity of the costs and benefits to the project lifetime can
be examined.
4. Estimate the average annual amount of coal mined (in tons)
during the life of the project.
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OALBED VLTIIANT GUIDELINES
rjy-e.''n::ia"v S!ie Assessment
5. Estimate the average daily total gas production during the life of
the project (cubic meters per day).
6. If off-site gas sales are anticipated, estimate the distance to the
point of sale (in meters).
7. Using the cost coefficients in Exhibit 4-8, estimate the capital and
operating costs for the system components required.
8. Summarize the estimated costs to show one-time capital costs in
yearl, and recurring capital costs and operation and
maintenance costs in each year of the project. Add a percentage
of the one-time capital costs (e.g., 20 percent) to account for
system design and other costs.
For example, to estimate the costs for gob wells, the annual average coal
production (tons per year) is used to estimate the number of wells required per
year. The cost per well ($25,000 to $50,000) is multiplied by the number of
wells required per year to estimate the annually recurring cost of installing
these wells.
If vertical wells are planned instead of gob wells, the number of wells required
is estimated using the total planned coal production over the life of the project.
The cost per well is then used to estimate the total one-time capital costs for
these wells, which is incurred at the start of the project. Unlike the other gas
recovery wells which are drilled throughout the life of the project as the coal is
mined, all the vertical wells are typically drilled at the beginning of the project.
ASSESSMENT
Exhibit 4-7: Summary ol
System Component
Degasification System
(Required for all options)
Gas Collection and
Gathering System
(Required for all options)
Gas Processing System
(Required for all options)
On-site Gas Use System
Electric Power Generation
System
Off-site Gas Sales System
F Major Pieces of Equipmen
Purpose
Withdraw the gas from the
coal and and/or surrounding
strata.
Collect the gas from the
withdrawal wells to a central
point for use or sale.
Remove water and
impurities from the gas.
Convert on-site equipment
for direct gas use.
Produce electricity from the
recovered coal mine
methane.
Prepare and transport gas to
an off-site customer.
t Required
Equipment Required
• Withdrawal wells (vertical; gob; or in-mine)
• Water treatment and disposal equipment
(required only for vertical wells)
• Wellhead exhauster/blower
• Wellhead and satellite compressors to move the
gas to the central collection point
• Gathering line
• Wellhead separator
• Dehydrator
• Preparation plant conversion equipment
• Gas turbine
• Utility interconnect
• Gas enrichment equipment
• Sales compressor
• Sales meter and gas analyzer
• Transmission pipeline
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"e.'.-ninarv S'.e Assess.-nenis COALI3ED V.ETHANE GUIDELINES
The other cost components are estimated in a similar manner. Compressor
requirements, for example, are estimated based on the horsepower (HP)
required per million cubic meters of gas production per day and the cost per
HP. Gathering line costs are estimated based on distance estimates.
It should be emphasized that the cost ranges are representative of conditions
found in the U.S. For an initial evaluation, values in the middle of the ranges
presented may be used. However, if possible, site-specific conditions should
be considered in selecting values from the ranges. Particularly important site-
specific factors may include well depths, water treatment requirements (vertical
wells only), gathering line distances, gas enrichment requirements, and
equipment conversion costs.
4.42 Benefits Analysis
The goals of a gas recovery project may be several - profits from revenues or
cost savings, energy supply, and/or emissions reductions. The benefits of gas
recovery will be evaluated in terms of these project goals. The benefits
analyzed in this section include: revenues generated from the utilization of the
gas; energy supplied; and methane emissions avoided.
Revenues/Savings
The revenue from the project is estimated as the amount of energy (gas or
electricity) produced multiplied by its price. If the energy is used to offset on-
site energy costs (e.g., coal, natural gas, oil, electricity), the value of this offset
is counted as revenue to the facility. If the energy is sold, the revenue is the
quantity sold times the price. Tax credits or other government incentives may
supplement these revenues.
The value of the energy will vary according to local energy prices. These
prices may be negotiated with individual suppliers or customers, or may be set
by national or state policy. Important factors affecting energy prices include
the price of competing sources of energy, supply reliability, energy subsidies
and taxes, and the quantity purchased.
The revenue or savings resulting from each project must be estimated using
local information obtained from electricity/energy authorities. A brief
description of how these values may be estimated is as follows.
• On-Site Use. The savings associated with the use of coal mine
methane on-site are estimated using the cost of the fuel displaced, or
the value of the coal that otherwise would have been used. These
values should be estimated from on-site energy consumption records.
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Exhibit 4-8: Gas Recovery and Utilization Cost Factors
System Component/
Equipment Required
Number or Size of Units Needed
Cost Per Unit
Comments
Degaslfication System (Cost to drill, Install, and complete wells and boreholes)
Gob Wells
1 well for every 200,000 to 500,000 tons of coal mined
each year. This estimate was derived by assuming
that approximately 1 million tons would be mined per
longwall panel and that from 2 to 5 wells would be
drilled per panel. More accurate data can be
substituted if more detailed information is available
regarding longwall panel sizes and well spacing.
$25,000 to $50,000 per well. This estimate
assumes that drilling costs are roughly $90 to $140
per meter of well depth.
Cost for drilling gob wells is an annual capital cost
(incurred each year). The rate of advance of mining
dictates when gob wells are drilled.
Cost per well includes cost of hydraulic fracturing of coal
seam to stimulate gas production. Cost for drilling
vertical wells is a one-time capital cost. Total number of
wells required over project lifetime may be drilled during
first year so that individual wells can produce gas for as
long as possible before being mined through. However,
if up-front capital is limited, well drilling can be spread
out throughout the life of the project.
Pre-mining Vertical Wells
1 well for every 250,000 to 1,000,000 tons of coal
mined over the life of the project. This estimate was
developed assuming well spacing of from 20 to 80
acres.
$100,000 to $500,000 per well
Longhole Horizontal Boreholes
1 longhole borehole drilled each year per 1 million tons
of coal (approximately 1 borehole per longwall panel).
Typical length of longhole borehole may be 1200
meters.
$60,000 to $100,000 per 1 million tons of coal
(approximately 1 longwall panel). Estimate assumes
borehole length of approximately 1200 meters and
drilling cost of $50 to $80 per meter.
Drilling longhole horizontal boreholes is an annual
capital cost (incurred each year). Rate of drilling
longhole horizontal boreholes determined by rate of
advance of mining.
Shorthole Horizontal Boreholes
4,500 meters of borehole drilled each year per
1 million tons of coal (approximately 1 longwall panel).
Shorthole horizontal boreholes are drilled
perpendicular to the longwall panel. This estimate
assumes 30 boreholes are drilled into the longwall
panel and that each borehole is 150 meters long.
Given that a typical longwall panel is about 1800
meters long, boreholes would be spaced every 60
meters.
$30 to $50 per meter or $135,000 to $225,000 per 1
million tons of coal (approximately 1 longwall panel).
Drilling Shorthole horizontal boreholes is an annual
capital cost (incurred each year). Rate of drilling
Shorthole horizontal boreholes is determined by the rate
of advance of mining.
Capital Cost for Water Disposal
Costs for Vertical Pre-Mining
Degasification Wells
1 disposal system needed per project.
Range: $100,000 to $2,800,000. Capital costs vary
substantially depending on local environmental
conditions and disposal requirements. The low end
of the range of capital costs is for a simple aeration
system with discharge to surface water, which may
be used for relatively low volumes in some areas.
The higher end cost represents deep-well injection,
which may be required in some areas.
Cost for a water disposal system are a one-time capital
cost. Note that a coal seam is dewatered as part of the
normal mining process. Accordingly, the same water
produced from pre-mining degasification wells would
otherwise have been removed as part of the normal
mining process. Therefore, unless there is significant
recharging of the water table during the time between
well drilling and mining, costs for water disposal should
not be considered as an incremental cost associated
with a degasification project. However, costs would be
incurred at the time of well drilling, as opposed to at the
time of mining.
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Exhibit 4-8: Gas Re ory
System Component/
Equipment Required
Operating Cost for Water
Disposal for Vertical Pre-Mining
Degasification Wells
and Utilization Cost Factors
Number or Size of Units Needed
Water production might range from 17 to 70 barrels per
thousand cubic meters of gas produced. Water
production will be highly site specific. Water
production is significantly higher during the first years
of production.
Cost Per Unit
Annual operating costs for water disposal range from
$0.02/barrel to nearly $2/barrel. The lower operating
cost is typical for a simplified aeration system, while
the higher operating cost is typical for a system
requiring transport to an off-site disposal location.
Comments
Gas Collection and Gathering System Costs
Wellhead exhauster/blowers for
gob wells
Wellhead and satellite
compressors for all degasification
systems.
Gathering Lines from Satellite
Compressors to Central
Collection Point
Gathering Lines for Gob Well
System: Lines from the wells to
the Satellite Compressor
Gathering Lines for Pre-Mining
Vertical Well Degasification
System: Lines from the wells to
the Satellite Compressor
Gathering Lines for In-mine
Borehole Systems: Lines from
the wells to the Satellite
Compressor
1 blower per maximum number of gob wells drilled in a
year. Number of gob wells drilled annually estimated
above based on annual coal production.
14,000 to 25,000 HP per million cubic meters per day
of total gas production (maximum projected daily gas
production).
6,000 to 25,000 meters of gathering line, depending on
overall size of project and whether there is more than
one gob field.
Movable Lines from Gob Wells to Satellite
Compressors: 2,500 meters per 1 million tons of coal
mined annually (assuming a typical longwall panel
may contain 1 million tons of coal).
Lines from Wells to Satellite Compressors: 3,000
meters per well.
Underground Lines: 2,500 meters per 1 million tons of
coal mined (assuming a typical longwall panel may
contain 1 million tons of coal).
$20,000 per gob well.
S650/HP
Average: $26/meter. Ranges from $13/meter to
$46/meter, depending on whether line is buried,
material used (HPDE or steel), and size of line.
Most projects will require a combination of less
expensive and more expensive piping material.
Average: $26/meter. Ranges from $13/meter to
$46/meter, depending on whether line is buried,
material used (HPDE or steel), and size of line.
Most projects will require a combination of less
expensive and more expensive piping material.
Average: $26/meter. Ranges from $13/meter to
$46/meter, depending on whether line is buried,
material used (HPDE or steel), and size of line.
Most projects will require a combination of less
expensive and more expensive piping material.
$20/meter
If a mine already uses gob wells, the mine will already
have an exhauster/blower at the wellhead.
Horsepower includes total horsepower for wellhead
compressors and satellite compressors.
One-time capital cost. Highly dependent on site-
specific conditins.
Lines running from gob wells to satellite compressor can
be moved from year to year as some gob wells stop
producing and others come on-line. (A typical gob well
might produce gas for a few months to a few years,
though typically will produce gas for less than one year).
Since gathering lines can be moved, costs for
purchasing gathering lines is a one-time capital cost.
However, the cost for moving and installing gathering
lines is an annual cost. Roughly half of the costs shown
are for recurring (i.e., annual) installation costs.
Cost for purchasing and installing gathering lines is a
one-time capital cost. Lines running from vertical wells
to satellite compressors would not be moved on a
regular basis, since vertical wells will likely produce gas
for many years.
Underground lines can be moved from one borehole to
another. Cost for purchasing line would be a one-time
capital cost, while cost for moving and re-installing lines
would be an annual cost. Roughly half of the costs
shown are for recurring (i.e., annual) installation costs.
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Exhibit 4*8: Gas Recovery
System Component/
Equipment Required
and Utilization Cost Factors
Number or Size of Units Needed
Cost Per Unit
Comments
Gas Processing System
Wellhead Separators
Glycol Dehydrator Capital Cost
Dehydration Operating Cost
For surface wells: 1 separator for each well
(1 separator for maximum number of wells drilled per
year).
For in-mine boreholes: 1 separator is needed for every
four longwall panels drilled (every 4 million tons of coal
drilled each year). Since separators can be moved,
total number of separators needed would be based on
maximum number of longwall panels drilled each year.
1 Dehydrator per project.
$2,000 per separator
Initial capital cost: $30,000 to $50,000.
Annual operating cost: $3,000 per year
Wellhead separators are a one-time capital cost.
Because vertical wells produce simultaneously, one
separator is required for each well drilled. Because gob
wells and in-mine boreholes produce sequentially, one
separator is needed for the maximum number of wells
drilled in a single year. For long project lifetimes (more
than 15 years), separators may need to be replaced
once.
Dehydrator costs are a one-time capital cost. For long
project lifetimes (more than 15 years), the dehydrator
may need to be replaced once.
On-Site Gas Use System
Preparation plant conversion
equipment
$250,000 to $750,00
Initial capital cost (depends on site-specific equipment
requirements).
Electric Power Generation System
Gas Turbine Capital Cost
Gas Turbine Operating Cost
Utility Interconnection Cost
Installed capacity of the turbine in kiloWatts (kW)
Initial cost per project.
$1,100/kW installed capacity.
$0.01/kWh of electricity generated.
$300,000 to $500,000 per project.
Initial capital cost. Capacity estimated based on gas
production and engine-generator heat rate (see text).
Annual operating cost. Electricity generated estimated
based on gas production and engine-generator heat
rate (see text).
Initial capital cost.
Off-Site Gas Sales System
Gas enrichment equipment
capital cost.
Gas enrichment system operating
cost.
Sales compressor to bring the
gas to pipeline pressure
Sales meter and gas analyzer
Transmission Pipeline
One system per project.
3,500 MP per maximum expected production in million
cubic meters per day. Compressor HP needed will
vary based on pressure of sales pipeline and distance
to sales pipeline or pressure required by industrial end-
user and distance to end-user.
1 sales meter and gas analyzer per project
Length of transmission pipeline will vary substantially
depending on distance between mine and commercial
pipeline or industry end-user.
$1 to $3 million, depending on gas flow rates and
gas quality.
$3.50 per thousand cubic meters of gas enriched.
$650/HP
$20,000 per project.
$32/meter.
Initial capital cost. Enrichment will not be required for
gas produced from vertical pre-mining degasification
wells or horizontal boreholes. Gas produced from gob
wells or cross-measure boreholes, however, may
require enrichment. Enrichment equipment includes
cost for pressure swing adsorption system and a
catalytic deoxygination unit.
Initial capital cost.
Initial capital cost.
Initial capital cost.
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S:le Assessment COALBCD V.ETHANE GUIDELINES
• Electricity Sales. If electricity is to be distributed through the electric
power grid, the owner/operator of the grid (such as a national
electricity company) will typically purchase the electricity at the point
at which it enters the grid. There are a variety of methods by which
the electricity price may be determined. For example, the price could
be set at the average marginal cost of generating electricity
elsewhere in the system, or it could be set at the price given to
electricity producers using conventional fuels. It is recommended that
potential pricing arrangements be explored with the proper authorities
as part of this preliminary assessment. In some cases, the electric
power generation aspect of the project is best developed jointly witk
the electric power authority.
• Sale of Gas. The expected price of gas sold directly to customers
can be based on the price of alternative fuels, such as propane, oil,
natural gas or coal, on an energy basis (e.g., price per million Joules).
The relevant fuel price to use depends on which fuel the coal mine
methane will be replacing. The price of gas sold to a pipeline
company can be based on the price paid for other gas supplies on a
comparable energy basis. If the customer must convert his
equipment to use the coal mine methane, the gas may need to be
sold at a discount.
• Tax credits. Tax credits or other government programs can also
affect project revenues. Some government programs may offer tax
credits or subsidies for producing energy from non-conventional
sources, including coal mines. The applicability of these incentives
usually depends on the structure of the project and the coal mine
owner/operators' tax situation. Therefore, a complete understanding
of the tax laws and their application is critical to ensuring a project's
ability to take full advantage of the incentives.
\
Under some conditions royalties are paid to the resource owner. Royalties can
be viewed as compensation for gas rights or as a financial incentive for
allowing the project to be developed. Royalties are usually estimated as a
percentage of total revenue or energy produced. Any royalty payments should
be subtracted from the revenue estimate prior to comparing costs and
revenues from the project developer's perspective.
Cost/Benefit Analysis
Once the revenues are estimated, they must be compared to the costs
(estimated in the previous section). This comparison requires a time profile of
the project's costs and revenues. From the information above, the capital
costs, annual operating costs, and annual revenues can be estimated.
Possible increases or decreases in energy prices and gas production over the
life of the project should be taken account when estimating annual revenues
and savings. For purposes of evaluation, it can be assumed that the project
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'OALBED V.LTHAXC GUIDELINES
Assess Tierus
continues for 10 to 20 years, and the annual operating expenses are incurred
each year. Using the time profile of costs and revenues, three main
techniques can be used to determine the economic feasibility of the project:
• Payback Method. The payback method involves determining the
number of years it would take for a project to generate profits equal to
the initial capital outlay. The advantage of this method is that it is
simple. It may be particularly suitable where there is a great amount
of risk and uncertainty associated with a project and the emphasis is
on recovering capital expenditures as quickly as possible. Its main
drawbacks are that it does not consider the costs and benefits that
accrue at the end of the payback period and that it takes no account
of the time when costs are incurred or benefits received The payback
method is appropriate to use when making a rough preliminary
assessment of a project's economic feasibility.
• Discounted Cash Flow Method. The basic premise of the
discounted cash flow technique is that costs or benefits occurring in
the future are worth less that those occurring now. This means that
costs and benefits cannot simply be added up over the years of the
project. The costs and benefits in each year of the project are
adjusted by a discount factor so that costs or benefits occurring in
one year can be compared with the costs or benefits occurring in
another year. The discounted costs and benefits in each year can be
aggregated to give a net present value (see Exhibit 4-9) of future
cash flows of the project. The discount rate used will normally be
chosen on the basis of prevailing interest rates or on the basis of the
minimum desired rate of return for the project, jf the net present
value is positive, the appraisal shows that the project is capable of
yielding this minimum rate of return.
• Internal Rate of Return Method. The internal rate of return (see
Exhibit 4-10) is the discount rate at which the present value of the
project would be zero. This value shows the total rate of return
achieved by the project. This rate can be compared to return rates
from alternative investment opportunities.
Sensitivity analyses should be carried out to examine how changes in key
parameters such as electricity prices or gas production can affect the
economic viability of the project. These sensitivity analyses can carried out
before the financing arrangements for the project have been worked out and
are useful in providing an initial indication of the project's viability. Further
analysis can be conducted to examine the implications for viability of different
financing schemes.
ASSESSMENT
Exhibit 44: Net Present Value
The Net Present Value (NPV) is the
present value of a project's cash flows,
including all investment costs. If the
NPV is greater than 0, a project is
considered to be profitable at the
chosen discount rate. The net present
value can be expressed as follows:
n ACF
NPV= y '—-IO
where:
ACFt
r
10
n
annual cash flow in year't
discount rate
initial cash outlay
life of the project
Exhibit 4-10: Internal Rate of
Return
The Internal Rate of Return is calculated
as follows:
n
= I
ACF
— IO
where:
ACFt
10
n
IRR
= annual cash flow in year t
= initial cash outlay
= life of the project
= internal rate of return.
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COALBEDV.ETIIANE GUIDELINES
Energy Supplied
The cost effectiveness of a gas recovery project may be evaluated in terms of
the quantity of energy supplied. The cost of gas recovery would be compared
with alternative energy supply options to determine the most cost effective
option. The threshold level of cost effectiveness may be set in terms of energy
supplied per unit cost. For example, gas recovery projects that supply energy
at a cost of $0.07/kWh may be defined as being cost effective if the marginal
cost of alternative electricity supply options is $0.07/kWh.
In some cases, energy from the gas recovery project may be provided to
customers who otherwise would be using wood (e.g., for residential cooking).
In this case, the value of preventing over-harvesting of forest resources may
be the measure of cost effectiveness for the project. An alternative may be to
set a threshold level in terms of the number of households served by the
energy supplied. This would require data on average household energy
consumption. For example, a cost effective project may be one that costs less
than $3 per household served. Such evaluations are prudent particularly in
areas of energy scarcity.
Benefits of emission reduction are
difficult to evaluate in monetary terms as
they do not accrue directly to a project
developer. However, such benefits are
important to consider in the formulation
of national energy policy and tax and
subsidy regimes for emissions
mitigation or renewable energy projects.
Emissions Avoided
Recovery and utilization of methane from coal mines prevent the release of
methane and provide a clean energy source. Methane is a potent greenhouse
gas; over a 100 year period, a ton of methane emitted into the atmosphere has
the equivalent global warming impact of about 21 tons of carbon dioxide.
Combusting the coal mine methane prevents its emission into the atmosphere,
thereby reducing greenhouse gas emissions
Although the emphasis of this document is to identify projects that are
economically viable in their own right, gas recovery projects may be
implemented specifically to reduce methane emissions from the mine. The
economics of such a project will be evaluated in terms of the cost of emissions
avoided. For example, a threshold level of cost effectiveness may be set at
$50 per ton of methane emissions avoided. If the project costs less thgn $50
per ton of methane emissions avoided, the project is considered cost effective.
The emissions impact of a gas recovery projects is, simply, the amount of gas
recovered and combusted. The methane emissions avoided can be expressed
in terms of carbon dioxide emission avoided using a Global Warming Potential
of methane equal to 21.6 The following equation expresses the relationship.
The Global Warming Potential (GWP) is a measure of the relative warming impact of
a gas relative to the warming impact of carbon dioxide. One gram of methane has
21 times the impact of one gram of carbon dioxide over a 100 year period.
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COALBED VETIIANE GUIDELINES
le ssessment
COz Equivalent Emissions Avoided (tbns/yr)
Cm Emissions Avoided (tons/yr) x 21 tons COz Equivalent/ion Cfe
!y expressing the emissions reduction in terms of an equivalent amount of
arbon dioxide, the reductions from this project can be compared to alternative
methods of reducing greenhouse gas emissions. The extent to which the
recovered coal mine methane is substituted for more polluting fuels, emissions
of other pollutants will also be reduced.
4.4 References
ASSESSMENT
Sturgill, C. 1991. Power Generation: On-Site Use and Sale to Utilities.
Prepared for US EPA Office of Air and Radiation, EPA, Washington,
D.C.
USEPA (U.S. Environmental Protection Agency). 1990. Methane Emissions
from Coal Mining: Issues and Opportunities for Reduction, Office of
Air and Radiation, EPA, Washington, D.C.
USEPA (U.S. Environmental Protection Agency). 1993a. Anthropogenic
Methane Emissions in the United States, Report to the Congress,
prepared by the Global Change Division, Office of Air and Radiation,
EPA, Washington, D.C.
USEPA (U.S. Environmental Protection Agency). 1993b. International
Anthropogenic Methane Emissions: Estimates for 1990, Report to the
Congress, prepared by the Office of Policy, Planning and Evaluation,
EPA, Washington, D.C.
USEPA (U.S. Environmental Protection Agency). 1995. Economic
Assessment of the Potential for Profitable Use of Coal Mine Methane:
Case Studies of Three Hypothetical U.S. Mines, prepared by the
Office of Policy, Planning and Evaluation, EPA, Washington, D.C.
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5. IDENTIFICATION AND ASSESSMENT OF KEY
GOVERNMENT POLICIES
THE government can play an important role in developing domestic coal
mine methane resources. The policies that it formulates can promote or
hinder the recovery and use of this clean energy source. The purpose of this
section is to: 1) identify the key policies that will affect the development of coal
mine methane projects; and 2) assess whether these policies pose barriers
that must be overcome or are potential leverage points to promote project
development. Although there are various policies that can encourage coal
mine methane projects, it is not possible to recommend a general set of
policies for every circumstance. Rather, policies must be tailored individually
to suit each country.
5.1 National Energy Pricing, Subsidies, and Taxes
A primary barrier to coal mine methane recovery and use in both developing
and developed countries is often artificially low energy prices. Conditions
influencing electricity and natural gas prices, such as government energy
policies and subsidies, can have an important effect on the economic viability
of coal mine projects.
Energy subsidies can both help and harm coal mine methane recovery and
utilization projects. Artificially low energy prices can pose a barrier to coal
mine methane utilization. If the prices of natural gas, oil, and coal are less
than the cost of producing coal mine methane, it will be difficult to develop a
profitable coal mine methane project. Using market prices for natural
resources would allow coal mine methane to compete fairly. If even under
market prices coal mine methane is uncompetitive, however, the government
may offer tax credits or other financial incentives to encourage these projects
because of their environmental and safety benefits.
Energy taxes must also be assessed for their impact on gas recovery projects.
Energy taxes based on fossil carbon content would give recovered methane
an edge over coal and oil. Similarly, higher taxes on imported energy would
allow domestic coal mine methane to be more competitive. Depending on a
nation's energy goals, the tax structure may prefer one source of energy over
another.
For example, in the United States, several federal, state, and local incentives
are available for coal mine methane projects, such as the Internal Revenue
Service (IRS) Section 29 Tax Credit (see Exhibit 5-1).
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COALBED VLTHA.NE
GUIDELINES
0 oven men;. . o.:c:es
POLICIES
5.2 National Energy Supply Priorities
The nation's energy supply goals will help determine the emphasis placed
upon coal mine methane development There are two main national energy
concerns that may affect coal mine methane promotion: supply security and
increasing domestic demand.
Many nations are concerned about relying on foreign sources of energy. The
most notable example is reluctance of many nations to depend on oil and gas
from unstable regions. Because the price of natural resources has a great
impact on a nation's economy, and domestic sources of energy are considered
to be more stable, many nations share the common goal of increasing
domestic natural resources. Therefore, nations may choose to encourage coal
mine methane recovery and utilization to expand their domestic supply of
energy.
For nations where energy demand is growing rapidly and there are shortfalls in
supply, energy policy may include the development of coal mine methane to
help meet the nation's energy needs. For example, in many developing
nations, the shortage of energy has slowed down the process of electrification
of towns and villages. The use of coal mine methane as a fuel to generate
electricity could help to meet the goal of universal electrification. Furthermore,
the use of domestically produced energy will decrease the amount of foreign
exchange required to import energy. Many developing countries and those
with economies in transition face a shortage of foreign exchange. Coal
restructuring may force uneconomic or unsafe coal mines to close down, which
may cause some economic hardships. However, the benefits that coal mine
methane recovery produces, including jobs and safer, more profitable mines,
can offset the losses.
If coal mine methane recovery and utilization is consistent with a nation's
energy supply priorities, it may be easier to create policies to promote its
development. For example, a detailed resource assessment may be
undertaken or information on technologies, financing, and pertinent policies
can be made publicly available. If, however, a nation has ample quantities of
domestically produced energy, it may not involve itself in the issue simply for
the purpose of expanding energy supplies. Rather, in such cases,
environmental goals may be more important.
Exhibit 5-1: U.S. Internal Revenue
Service (IRS) Section 29 Tax Credit
This is a U.S. federal tax credit for
producing energy from non-conventional
sources, including coal mines. This tax
credit applies to wells drilled before 1992
and will expire on January 1,2003. When
the tax credit was established in 1979, the
value of the credit was set at $0.52 per
thousand cubic feet of gas. The value of
the credit changes annually, depending
on a number of factors, including the
domestic oil price and the inflation rate. In
1994, the credit equaled $0.90 per
thousand cubic feet of gas.
5.3 Environmental Goals
A nation's environmental goals will also play a large role in determining the
importance given to coal mine methane projects. Coal mine methane may be
encouraged when environmental issues are placed highly on the national
agenda. The two main issues concerning environmental policy and their
impact on coal mine methane can be divided into a global concern and a
local/national concern.
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As explained in Chapter 2, methane is a greenhouse gas, affecting the global
environment. If a nation has an active interest in reducing methane emissions,
it may promote the recovery of methane from coal mining.
Both national and local environmental policy may call for the use of cleaner
fuels to reduce local pollution and for the clean up of water discharged during
mining. Coal mine methane can be used to displace more polluting fuels, such
as coal or oil. Methane has several advantages over other fossil fuels.
Emissions of S02, NO,, and particulates can be reduced through the
displacement of coal (and to a lesser degree oil) with gas. Natural gas
combustion produces no 802 or paniculate emissions, and lower NO,
emissions.
Coal mine methane can also be used to treat mine water before it is
discharged into rivers or used for other purposes. The disposal of this water is
a significant local environmental problem in many countries. As described
above, a demonstration project is underway at the Morcinek mine in Poland
that involves using coal mine methane for this purpose.
5.4 Financing
In order to assess the impact of government investment polices on the
financing of coal mine methane projects, one must look at both the overall
investment regime and the financial regulations specifically concerning coal
mine methane. When studying the overall regime, it is necessary to look at the
corporate tax structure, import and export taxes and quotas, and laws
concerning foreign ownership. Low limits on foreign ownership and a high
corporate tax structure in comparison to other nations with potential coal mine
methane projects may pose barriers to foreign investors. In cases in which the
equipment must be imported from abroad, high import duties will place a
burden on both domestic and foreign investors.
The government also may have financial regulations dealing specifically with
coal mine methane. For example, low interest loans, tax credits, loans, grants,
and subsidies for coal mine methane projects will ease the financial burden on
the investor. As mentioned above, the use of such incentives will depend on
the overall energy and environment goals of the government.
For example, in the U.S., many state governments provide grants or low
interest loans to projects that improve the environment or increase the local
supply of clean fuels. As coal mine methane projects can do both, they may
be eligible to receive various types of state funding. Examples of such
programs include one by the Pennsylvania Energy Development Authority that
provides loans and grants for the development of new sources of energy, as
well as the Indiana Recycling and Energy Development Program, which
provides assistance for the development of new energy resources and
recycling programs.
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5.5 Technology Development
As some of the technologies associated with coal mine methane recovery and
utilization may not be available in many nations, the government's policy
towards the development of technology is important to assess. There are
various ways in which the government can encourage the development of
technologies specific to coal mine methane projects:
• Encourage foreign participation in coal mine methane projects.
This would allow foreign technology to be introduced without requiring
domestic capital. Foreign participation, however may bring forth
issues of ownership of the recovered methane. These arrangements
may thus require detailed contracts regarding use and rights of both
parties involved, discussed further in section 5.6 below.
* Lower import duties, taxes, and restrictions on required
technologies, thereby reducing the cost of a coal mine methane
project.
• Fund demonstration projects at domestic mines to allow the
industry to see and understand new technologies.
• Organize study tours and training trips abroad for key personnel
so that they may leam from the experiences of other nations.
• Finance research and development into recovery and use methods
to assist the local industry.
If technology is a strong barrier to the development of coal mine methane
projects, government policies that encourage the transfer of technology and
the development of local technology can help promote these projects. An
important part of technology transfer that must not be overlooked is the need
to ensure the safety of those using the equipment. Governments could involve
safety and certification agencies to examine and evaluate the technology; in
some cases a formal licensing or approval process could be established.
5.6 Concession Process
Through the granting of natural resource concessions, governments can
encourage project development. In granting a concession, a government
authorizes a developer to extract and sell a natural resource. Typically, the
grantee pays to obtain the concession, and often is required to pay a royalty
based on the amount of resource extracted.
There are two main issues that must be analyzed in this process. First, before
the concession process can begin, the issue of ownership of the coal mine
methane must be resolved. If natural resources are owned by the private
sector, coal mine methane resources can belong to the owner of the surface
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rights, the owner of the coal rights, or the owner of the oil and gas rights. If
natural resources are nationalized, it may be uncertain whether the national or
regional government has the authority to grant concessions. This uncertainty
can prevent projects from being developed. Furthermore, in nations in which
the natural resource sectors are being privatized, the laws concerning
ownership may be in flux.
The second matter concerns the clarity, efficiency, and stability of the actual
concession process. A long, complex concession process can act as a
deterrent to investment in coal mine methane resources. Common problems
faced by investors include delays in the decision making process, confusion
over who is in charge, sudden changes in regulations, and the reversal of
decisions. These problems are exacerbated in nations where all natural
resources were previously owned by the government and the concession
process is still being formulated. The following questions are useful in
determining whether the current concession process may be a potential barrier
to project development:
• Who should be contacted for questions concerning various steps of
the concession process? Is it clear exactly who is in charge of what
step and are those persons easily accessible?
• How long does the concession process take?
• Once a decision has been made, what is the likelihood of it being
overturned?
Clear laws concerning coal mine methane ownership and a clear, efficient, and
stable concession process will help to promote coal mine methane projects.
5.7 References
USEPA (U.S. Environmental Protection Agency). 1993. Anthropogenic
Methane Emissions in the United States, Report to the Congress,
prepared by the Global Change Division, Office of Air and Radiation,
EPA, Washington, D.C.
USEPA (U.S. Environmental Protection Agency). 1994. International
Anthropogenic Methane Emissions: Estimates for 1990, Report to the
Congress, prepared by the Office of Policy, Planning and Evaluation,
EPA, Washington, D.C.
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\ex. SI
6. NEXT STEPS
section outlines the next steps for evaluating and implementing coal
mine methane recovery and utilization projects in developing countries and
countries with economies in transition. The steps encompass a range of
initiatives that may be tailored to meet individual country objectives. These
initiatives are divided into the following five main areas:
• Focus on the Most Promising Projects. This section presents next
steps for focusing on the most promising coal mine methane projects
in your country.
• Availability of Technology and Expertise. This section identifies
approaches for assessing whether the technology and expertise
required for implementing projects are available.
• Decisionmaker Motivation. This section presents approaches for
motivating decisionmakers to undertake coal mine methane recovery
and utilization projects.
• Resolution of Regulatory Issues. This section lists regulatory
issues that should be examined to assess whether existing policies
hinder or further the goal of implementing coal mine methane
projects.
• Funding. This section identifies possible sources of funding for these
next step activities.
Exhibit 6-1 summarizes how this chapter can be used to meet various
objectives. The first column lists several common objectives and the second
column lists the chapter section to consult.
6.1 Focus on the Most Promising Projects
Although the site screening and preliminary assessments discussed above in
chapters 3 and 4 may show that a variety of promising projects exist, the
available data may be insufficient for identifying the most promising project
opportunities. In particular, if there are a large number of gassy mines,
detailed site-specific information on all the sites may not have been collected
in the screening step (chapter 3) because of the level of resources that are
required. This section provides guidance for collecting additional site-specific
information that will enable prefeasibility assessment activities to be focused
on the most promising opportunities. This initiative is only required when there
are a large number of potential sites that need to be evaluated.
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:OAL GUIDELINES
Exhibit 6-1: How to use this Chapter
Objective: i Section to Consult:
To focus on the most promising
coal mine methane projects.
To assemble the technology and
expertise needed to develop
coal mine methane recovery and
utilization projects.
To motivate derisionmakers to
invest in and implement coal
mine methane projects.
To identify and eliminate
regulatory barriers.
•
To obtain funding for program
development or project
implementation.
Section 6.1 - Focus on the Most Promising
Projects summarizes steps for collecting
additional data on candidate sites to better
focus efforts.
Section 6.2 - Availability of Technology and
Expertise presents steps for identifying and
filling gaps in the availability of technology and
expertise needed to develop projects.
Section 6.3 - Motivate Decisionmakers
presents options for assisting decision makers
and providing incentives.
Section 6.4 - Resolution of Regulatory
Issues discusses those policies and regulatory
structures that should be reviewed to identify
potential barriers.
Section 6.5 - Funding presents candidate
funding sources that can be consulted.
To collect this information, a specific program activity should be defined with
data collection as its objective. Such an initiative was conducted in the United
States to identify the most promising coal mine methane opportunities (see
Exhibit 6-2). Section 6.5 describes funding sources that may be contacted to
obtain funding for these types of activity. A sample five step program plan for
collecting the necessary data is as follows:
Step 1: Define Minimum Information
The first task is to define the minimum information that is required for each
coal mine. As discussed in Chapter 3, the three primary factors that makes a
site a promising opportunity for gas recovery and use are 1) coal production of
at least 0.3 million tons of coal annually, 2) methane emissions of at least nine
cubic meters per metric ton of coal produced, and 3) a remaining life span of
at least five years. Therefore, it is recommended that this information collection
effort focus on obtaining the best possible information on three factors:
• The number of tons of coal produced annually;
• Methane emissions per ton of coal mined; and
• Remaining mine lifespan.
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\exi Sieos
Exhibit 6-2: US EPA Coal Mine Profiles Project
The US EPA Coal Mine Profiles Project was developed to identify the most
promising coal mine methane project opportunities in the United States. This
information is being provided to coal mine owners and operators, electric utilities,
natural gas pipeline companies, state and local government officials, and potential
project developers. Based on publicly available data collected primarily from state
and federal reports and industry press, a minimum data set was developed for large
and gassy mines from which a profile is created. These profiles are then used to
identify those mines that may offer attractive energy development opportunities.
The profile for each coal mine has the following information:
Coal mine location and operating status;
Coal production;
Methane emissions;
Energy potential of the methane (including the amount of electricity that
may be generated from the recovered methane);
Existing methane recovery and use;
Distance from mine to a pipeline;
Nearby institutional or industrial .facilities; and
Contact information (i.e., coal mine owner/operator).
Based on this information, the gas recovery and use potential and associated
environmental and energy benefits from a potential project are estimated. These
profiles are currently available from the US EPA for over 80 mines in 10 states.
Additional information on energy needs surrounding the coal mine and
potential consumers in the area may also be collected if the information is
readily available. Since methane can be used at the mine itself, this
information is not on the list of the minimum information required.
Step 2: Define the Data Collection Method
The purpose of this second step is to define how the data will be collected.
Options may include working with local government officials who collect coal
production and methane emissions data or surveying individual coal mines to
collect or estimate this data. The techniques to be used to collect the data
should be selected based on the type of information most likely to be available
and the resources available for collecting the data. It may be appropriate to
test several different data collection methods before settling on the
recommended approach.
Step 3: Develop a Data Handling System
The purpose of this third step is to develop a system for handling the coal mine
data. A database program can be used to organize the data so the
subsequent data analysis and evaluation is facilitated. Data handling and
quality control procedures should be developed as part of this step, including
checking the accuracy of both the data collection and data entry activities.
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\exi s\eos COAL GUIDELINES
Step 4: Collect the Data
In this step the program personnel collect the data according to the method
defined in step 2. The data are entered into the data system developed in
step 3.
Step 5: Analysis and Recommendations
Based on the data collected, the gas recovery and use potential for candidate
coal mines is estimated (Chapter 4 presents equations for estimating gas
recovery). The most promising project opportunities will be those that produce
the most gas in areas that can use the energy. A list of the most attractive
projects can be created, along with the information available on each.
Once the most promising opportunities are identified, this information can be
disseminated to potential project developers to promote the projects (see
section 6.3).
6.2 Availability of Technology and Expertise
Specific technical expertise is required to plan and implement coal mine
methane recovery and utilization projects. Additionally, access to and
experience with specialized drilling and gas monitoring equipment are needed.
The absence of the necessary expertise and equipment can be a significant
barrier to the implementation of these projects. This issue may be particularly
important in developing countries and countries with economies in transition
because technical and labor resources may not be available to construct and
operate the projects.
Once it has been determined that promising opportunities exist, necessary
expertise and equipment should be located. Ideally, one or more local experts
with coal mine methane recovery and use expertise should be identified. For
example, a request for qualifications can be issued to identify local or regional
individuals and organizations with the necessary expertise.
In some cases a coal mine methane expert familiar with the latest technologies
may not exist in the nation. In this circumstance, a program can be organized
to train local personnel in the detailed aspects of coal mine methane recovery
and utilization. Training programs could include visits to existing projects in
other countries as well as inviting experts from other countries to give
seminars.
To augment local expertise, nations may wish to contact foreign companies
with the expertise necessary to complete the project. Foreign involvement
may take any of a variety of forms, including the build-operate-transfer (BOT)
financing model. The BOT is currently being used for various infrastructure
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:OAL GUIDELINES
Nexi S;eos
projects in developing countries and is applicable for coal mine methane
projects as well. Such arrangements with foreign companies allow technology
to be introduced without requiring the use of domestic capital. For countries
that have limited or no experience with coal mine methane recovery and
utilization, this may be an attractive short-term option. Appendix A lists
selected U.S. coal mine methane development experts available to provide
training or participate in project development.
6.3 Motivate Decisionmakers
Because coal mine methane recovery and utilization projects are relatively
new in many countries, steps to motivate decisionmakers may be necessary to
get promising projects built. Examples of decisionmakers include coal mine
owners, government officials in the energy and environment ministries, and
potential project developers. In addition to financial incentives, several
targeted initiatives have proven effective for both raising awareness regarding
the benefits of such projects, as well as creating the nucleus of interested
parties needed to create a viable project. Three main initiatives are
recommended to provide the information needed to motivate decisionmakers:
outreach activities, demonstration projects, and information clearinghouses.
6.3.1 Outreach Activities
Because the concept of recovering and utilizing methane from coal mines may
be unfamiliar, outreach activities may be required to educate and motivate the
community and its leaders on the technology and benefits of coal mine
methane projects. Outreach should be targeted to the following parties:
• Coal mine owners and operators, who may not recognize the
resource they have;
• Potential users of coal mine methane, who may not recognize the
opportunity to obtain low cost energy;
• Energy planners, who may not recognize how energy from coal mine
methane can contribute to meeting local energy needs; and
• Environmental and community groups, who may not be aware of
the environmental and safety benefits of coal mine methane projects.
Outreach activities to educate and motivate these parties must be defined in
terms of the message that is being delivered and the mechanism that is used
to deliver the message. The message must include the information needed to
educate and motivate each target group. The information must be presented
in a way that each target group can understand, and must be delivered in a
manner that ensures that each target group receives and assimilates the
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GUIDELINES
Exhibit 6-3: The US EPA Coalbed Methane Outreach Program
EPA's Coalbed Methane Outreach Program encourages the
use of coal mine methane as an energy resource. EPA enlists
the support of coal mine owners and operators, electric utilities,
state agencies, private financiers, and project developers to
reduce methane emissions from coal mines through the
development of profitable energy recovery projects.
The Coalbed Outreach Program promotes coal mine methane recovery and use
projects in the U.S. as well as in countries such as Russia, China, Poland, and
Ukraine. Projects undertaken by the Program in the U.S. include:
• Profiles of the gassiest mines in the nation (these profiles are discussed above);
• Guides to possible sources of funding for coal mine methane projects in West
Virginia and Pennsylvania, two state with several gassy mines;
• Study of the barriers facing coal mine methane projects and possible solutions to
these barriers; and
• Detailed technical and financial feasibility assessment for potential coal mine
methane project developers.
To promote coal mine methane projects abroad, EPA has helped establish
clearinghouses in Poland, Russia, and China. EPA has also written reports on the
coal mine methane potential of these nations and has profiled some of the gassiest
mines. At present EPA is working with the Chinese Coalbed Methane Clearinghouse
to develop a financial model to evaluate coal mine methane projects in China.
information. Because each target group is different, separate outreach
strategies may be needed for each.
For example, outreach to national planners and decisionmakers may employ
existing decisionmaking processes. Alternatively, outreach to local officials
responsible for the local coal industry may require seminars, training sessions,
or technical guidebooks to inform them of the coal mine methane recovery and
utilization opportunities. Options for reaching potential foreign partners may
include conducting studies through international funding agencies (discussed
below in section 6.5) or issuing requests for proposals for specific projects or
studies. Exhibit 6-3 summarizes the outreach program currently being used in
the United States to reach these various groups.
Exhibit 6-4: Demonstration Project in Russia
During its visit to Russia in 1995, the EPA identified a demonstration project at the
Kirov mine in the Kuzbass coal basin. This project would use methane recovered
from the degasification systems to fuel the three central boilers. At present, these
boilers run on coal. Currently, EPA is preparing a project opportunity report on this
project. This report will be distributed to potential lenders.
The successful implementation of this demonstration project will facilitate the
development of other coal mine methane projects in Russia.
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GUIDELINES
Ne'xi Sieos
6.3.2 Demonstration Projects
Sometimes information is not enough to promote the use of a new technology.
Users may want to see the technology in use. Demonstration projects are an
effective tool to test and promote the effectiveness of coal mine methane
recovery and use projects, especially in developing countries and countries
with economies in transition where such projects may be uncommon. By
providing analysis, technical support, and funding, the government can
facilitate projects to serve as examples for the industry as a whole.
In selecting projects to support and promote, several criteria should be
considered, including: choice of technology, time frame for the project, type of
government assistance required, and how projects will promote the
government's goals. In most cases, after a specific project is selected,
technical and financial analyses will be required to evaluate the effectiveness
of the technology, as well as its costs and benefits.
Upon completion of the demonstration project, the results of the project must
be summarized, including both positive and negative aspects and
recommendations for improvement. This information must be disseminated to
promote the technology. The demonstration site itself can then be used for
training and education purposes.
6.3.3 Information Clearinghouses
To provide owners, developers, regulators, and other stakeholders with
comprehensive information concerning all aspects of coal mine methane
recovery and utilization technology, finance, and economic development, a
central information clearinghouse could be established. Information
clearinghouses provide a central location for information where current
environmental, technical, financial, and business contact information is
available.
The clearinghouse can function at the national level of the country and can
involve professionals from leading research and development laboratories,
educational institutes, industries, and other organizations. The clearinghouse
can strengthen the existing infrastructure of national and regional bodies
involved in the training, information dissemination and implementation of the
programs in energy efficient technology. It can also facilitate training programs
and interactions with local and international experts.
The clearinghouse can also assist in developing the technical capabilities of
non-governmental organizations, consultants, industry associations, and any
other groups engaged in the promotion of energy efficiency activities. This can
be done by conducting regular training programs (both in the field and in the
classroom}, thereby exposing the participants to the latest tools and
techniques.
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\ex- S:eos v#AL C-UIDELINCS
At a minimum, the information clearinghouse should contain information in the
following areas:
• profiles of gassy mines;
• current technologies and new research;
• coal mine methane ownership laws;
• permitting requirement;
• applicable energy purchase rules (if any);
• international and domestic capital/funding sources; and
• government energy development policies.
An automated index of all materials could be made available electronically
through a bulletin board, or as a "fax-back" system. A collection of hardcopy
materials could also be assembled for use by anyone interested in coal mine
methane projects. US EPA has helped establish three clearinghouses abroad.
A description of these clearinghouses along with their contact information is
presented in Exhibit 6-5.
6.4 Review Regulatory Framework
Regulatory barriers are key obstacles facing potential coal mine methane
projects in many developing countries and countries with economies in
transition. In many of these nations, the regulatory frameworks do not address
issues related to coal mine methane recovery and use projects. This is not
unusual, given that such projects may be relatively new in these countries.
There are many types of regulatory barriers that a project may face. For
example, local, state, and national ownership and permitting legislation can
obstruct coal mine methane projects. Artificially low energy prices can pose a
barrier to coal mine methane utilization if the prices of alternative fuels are less
than the cost of coal mine methane. Furthermore, in most developing
countries
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Exhibit 6-5: Coalbed Methane Clearinghouses
The Polish Coalbed Methane Clearinghouse
The Polish Coalbed Methane Clearinghouse,
established in January, 1991, is part of the Polish
Foundation for Energy Efficiency (FEWE) and is
jointly sponsored by the FEWE and the US EPA.
The clearinghouse provides consulting services to
public- and private-sector clients (e.g., assisting
contractors with pre-feasibility studies on directional
drilling and gob gas recovery), hosts workshops,
and publishes journals, brochures, and newsletters
(e.g., the Silesian Coalbed Methane Newsletter).
Together, EPA and the Polish Clearinghouse
prepared a report entitled "Reducing Methane
Emissions from Coal Mines in Poland: A Handbook
for .Expanding Coalbed Methane Recovery and
Utilization in the Upper Silesian Basin." This report
profiles the top candidate mines in Poland, For
more information, contact:
Jan Surovka, Director
Polish Coalbed Methane Clearinghouse
ul. Powstancow41a
40-024 Katowice, Poland
48-3-10355114 (phone)
48-3-10355120 (fax)
Chinese Coalbed Methane Clearinghouse
The Chinese Coalbed Methane Clearinghouse was
established in August 1994 in Beijing. The
Clearinghouse is part of the Ministry of Coal
Industry's (MOCI) China Coal Information Institute
and is jointly funded by the MOCI and the US EPA.
Activities of the Clearinghouse include providing
consulting services, hosting seminars and
conferences, and publishing the journal China
Coalbed Methane in both English and Chinese. In
a joint report with EPA entitled "Reducing Methane
Emissions from Coal Mines in China: The Potential
for Coalbed Methane Development," the
Clearinghouse has profiled coal mining
administrations that have the top candidate mines
for coalbed methane projects. For further
information, contact:
Mr. Sun Mayouan, Director
China Coalbed Methane Clearinghouse
21 Hepingli Beijie
P.O. Box 1419
Beijing 100713, China
86-10-420-1328 (phone)
86-10-421-5187 (fax)
adb310@istic.sli.ac.cn (email)
Russian Coalbed Methane Clearinghouse
The Russian Coalbed Methane Clearinghouse
opened in 1995 in Kemerovo. It is located at the
Russian Institute of Coal and is affiliated with
Partners in Economic Reform (PIER) and the U.S.
EPA. Like the other Clearinghouses, the Russian
Clearinghouse is promoting the development of
coal mine methane projects by disseminating
information. It assisted the U.S. EPA in preparing a
report entitled The Potential for Coalbed Methane
Development" which includes profiles of the top
candidate mines. The Clearinghouse is also
working with EPA to develop a demonstration
project'at the Kirov mine (see box above). For
further information, contact:
Dr. Oleg Tailakov, Director
Russian Coalbed Methane Clearinghouse
Institute of Coal
Room 208
Rukavishnikova 21
Kemerovo 65061, Russia
root@tailak.kemerovo.su (E-mail)
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\exi Sieos COALBED VCTIIANC GUIDELINES
and countries with economies in transition, all major power and natural gas
producers and distributors are or have been State-owned. Privatization of the
energy industry is only recently occurring in many countries; therefore, the
concept of private, independent power producers or private gas producers may
be unfamiliar (Watts, 1995). These, and other barriers, are discussed in
Chapters.
The following is recommended to review the regulatory framework for coal
mine methane recovery and utilization: identify and evaluate existing
regulations; develop feasible options for removing barriers that will not
compromise other regulatory objectives;. and implement the necessary
changes.
6.4.1 Evaluate Existing Regulations
To evaluate the existing situation, the relevant laws, rules, regulations, and
policies must first be identified and summarized by conducting literature
reviews and contacting appropriate regulatory and legislative experts. In
addition, attention must be paid to institutional arrangements. The following
steps should be undertaken:
• Step 1: Identify Decisionmakers. The purpose of this step is to
identify the key decisionmakers involved in the approval of coal mine
methane projects. These decisionmakers may include local,
provincial, or national regulatory bodies that are involved in coal
production, land ownership, energy production, financing, and
equipment purchasing/importing.
• Step 2: Identify Decision Criteria. The purpose of this step is to
identify the decision criteria used by the key decisionmakers and the
underlying objectives they are trying to achieve. This information
would be obtained principally through contacts with the relevant
agencies and institutions in the country.
• Step 3: Identify Typical Project Development Path. The purpose
of this step is to describe the typical path that a project would take in
order to be developed. A concise listing of the major steps in getting
the project defined, approved, financed, and built should be
developed based on discussions with the relevant institutions
involved. This summary of the project development path could then
be used to promote the implementation of coal mine methane
projects.
The results of the above steps should be compiled in a concise summary
report highlighting the policies and current practices affecting gas recovery and
use the options available to the government to reduce the barriers to projects.
Any policies or requirements that significantly add to the cost of the project,
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Nexi Sieos
create uncertainty in the viability of the project, or delay its implementation
should be identified as major barriers requiring further analysis.
6.42 Develop Feasible Options
The purpose of this section is to develop available options for overcoming any
major barriers identified above. The options selected will be those that most
effectively promote the government's development objectives and are feasible
in terms of political acceptance, effectiveness, secondary impacts, costs, and
legality.
An Evaluation Team consisting of the decisionmakers and participants
involved in coal mine methane recovery and utilization can be established as a
working group to guide this process, This group would be charged with
ensuring that the recommended options incorporate the views of the
representative stakeholders in each area. At a minimum, the Evaluation Team
should include the following groups:
• Regulatory Community: municipal agencies, local government
regulators, ministries in charge of power, coal, natural gas, and the
environment, and others;
• Owner, Operator, and Developer Community: coal mine owners
and operators, recognized local, national, or international coal mine
methane project developers; and
• Financial Community: local, national, or international grant/loan
agencies and venture capitalists.
The assessment of available options will involve considerable debate on which
options can be implemented without compromising other pressing national
priorities. As such, proposed regulatory changes must be viewed in the context
of their impact on other national priorities.
6.4.3 Implement Options
Using the input and recommendations of the Evaluation Team, the options or
optimum mix of options can be implemented. The implementation strategy will
depend on the type of option to be implemented. Implementation strategy
options include, among others:
• legislative/regulatory actions (environmental, safety, ownership,
import restrictions);
• administrative and executive actions (committees, meetings,
conferences);
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OALBED VETIIANC GUIDELINES
• inter-governmental liaison actions (local, municipal, national, inter-
national); and
• outreach (training programs, demonstration projects, etc.)
The above options must be evaluated on an ongoing basis in terms of their
ability to promote promising projects. A structured program of data collection
for monitoring the progress of the objectives may be developed in this regard.
Once data has been collected, reviewed, and analyzed, an evaluation of the
impact of the option can be made and the established objectives can be
retained or modified as appropriate.
6.5 Obtain Project Funding
Each of the activities discussed above requires resources, as does the
implementation of individual projects. This section lists steps for obtaining
assistance from international funding agencies for these initiatives. The key
steps are to review the types of assistance available, identify funding
requirements, and select specific source(s) of funding. Once the appropriate
source of funding has been identified, a project proposal can then be prepared
in accordance with the specific criteria of the funding agency.
The first source of funding that
countries should consider is forming a
partnership with local and foreign
private sector project developers.
This method is often the quickest and
cheapest method of obtain funding.
However, such funding is only
available for projects that are dearly
profitable. For projects with a lower
economic rate of return, funding may
be available from international
agencies.
6.5.7 Review Types of Assistance Available
The main types of assistance offered by international funding agencies are
grants, loans, and other packages (including loan guarantees, venture capital
funds, and business consulting assistance). These types of assistance are
available to both governments and businesses. In some cases, the
government may reallocate the funds to eligible businesses. The funds
provided may cover costs to conduct feasibility assessments, implement
demonstration projects, or acquire equipment and technical expertise. The
main types of financial assistance are further described below:
4 Grants. These are direct monetary payments for specific projects
that do not need to be reimbursed. For example, grants may be used
to develop a demonstration project or to fund a training program to
enhance local expertise.
* Loans. These are made by the funding agencies directly to the
eligible parties and must be paid back in a specified period of time.
Typical recipients of such loans may be government agencies (for
direct use or reallocation to businesses); or businesses in
manufacturing, industrial export/import services, or technology
development.
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Nexi Sieos
Other. Loan guarantees, venture capital funds, and business
consulting services are some of the other types of assistance that are
offered by these institutions. These are described below:
• Loan Guarantees are commitments to repay the lender if the
borrower defaults. In these cases, a funding agency
guarantees its proportionate share of loss in accordance with
the percentage of the guarantee. Loan guarantees are
important to mitigate risk at projects that have a high degree
of uncertainty.
• Venture Capital Funds offer loans or equity to support the
start-up of new businesses or expansion of existing
businesses. Funding agencies may appropriate funds or
generate funds from private investors by selling shares in the
company.
• Business Consulting Services include technical, managerial,
and financial consulting and support services. Typical
sources of such assistance are governments, multilateral
and bilateral agencies, and business- and research-related
entities. Technical services may range from providing
technology transfer to providing engineering assistance to
offering use of research and development facilities.
Managerial consulting includes offering seminars,
workshops, and consultations on improving project
operations. Financial consulting may involve assistance in
creating packages to finance a project or group of projects.
6.52 Identify Funding Requirements
The type of funding required is driven primarily by two factors: the objectives
of the program, and the country's resource allocation. These are briefly
described below.
• Program Objectives. Government programs aimed at exploring the
opportunities for coal mine methane projects (e.g., by conducting
feasibility studies) would most likely seek grants or other
concessional funds. On the other hand, businesses and government
agencies pursuing profitable projects are eligible for loans, loan
guarantees, and venture capital funding.
• Resource Allocation. The extent of economic development and
resource endowments for a given country will determine its financial
requirements. Countries with a low GNP per capita will typically
require grants to undertake coal mine methane projects. Some
countries may face difficulty when securing loans, if they have
creditworthiness problems.
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\exi Sieos COMBED VLTIIANE GUIDELINES
Once the funding requirements have been assessed, the next step is to
identify the funding available.
6.5.3 Select Sources of Funding
There are a wealth of possible funding sources which provide assistance that
can be used for coal mine methane projects. These include multilateral
institutions, regional development banks, U.S. government agency programs,
country- and region-specific enterprise funds, and other institutions. Exhibit 6-
5 lists funding sources most applicable to coal mine methane recovery and
use projects, and summarizes the types of funding offered by each. Summary
profiles of the funding agencies are presented in Appendix B. The main
categories of funding sources are briefly described as follows:
• Private Sector. Funding may be available from private sector
associations or firms interested in coal mine methane recovery. Such
funding is most commonly available for projects with a high expected
rates of return and usually takes the form of a profit-sharing
partnership. This method is often the quickest and cheapest method
of obtaining project funding.
• World Bank Institutions. The World Bank institutions fund
environmental and energy infrastructure projects in developing
countries for which the procurement of technical assistance, civil
works, materials and equipment, are necessary. These agencies
provide grants and loans to government ministries and businesses,
which implement projects under local procurement and contracting
regulations. Examples of such institutions include the World Bank
itself (also known as the International Bank for Reconstruction and
Development), International Finance Corporation (IFC), and the
Global Environment Facility (GEF).
• Multilateral Development Banks. These are international lending
institutions owned by member countries that promote economic and
social development in developing member nations by providing Joans,
technical assistance, capital investment, and help with economic
development plans. Examples of such institutions include the Asian
Development Bank (ADB), the European Bank for Reconstruction and
Development (EBRD), and the Inter-American Development Bank
(IDB).
• U.S. Government Agency Programs. There are several U.S.
government agencies that promote development by funding feasibility
studies, training programs, and seminars in developing countries. In
most cases, these agencies/programs support projects that offer
export or investment potential for U.S. enterprises. Examples of such
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Nexi Sieos
agencies/programs include the Trade Development Agency (IDA)
and the Overseas Private Investment Corporation (OPIC).
• U.S. Initiative on Joint Implementation (USIJI): The USIJI is a
voluntary private program that provides recognition and select
technical assistance to U.S. companies implementing greenhouse
gas reduction projects in other .countries. While no funding is
available through the USIJI, projects that meet the USIJI criteria will
be likely to attract U.S. investors solely on the recognition of USIJI
acceptance.
For more information on the types of funding available and sources of funding
for coal mine methane recovery and use projects contact:
U.S. Environmental Protection Agency
Methane Branch
Mail Code 6202 J
401 M Street, S.W.
Washington D.C. 20460
Tel: 202/233-9768
Fax: 202/233-9569
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Exhibit 6-5: Summary Table of Promising So
Name of Agency
World Bank Agencies/Programs
International Bank of Reconstruction and
Development (IBRD)
Global Environment Facility
International Finance Corporation (IFC)
Multilateral Development Banks
European Bank For Reconstruction and
Development (EBRD)
Inter-American Development Bank (IDB)
Asian Development Bank (ADB)
Africa Development Bank' (AfDB)
U.S. Government Agency Programs
Trade Development Agency
United States Agency For International
Development (USAID)
Overseas Private Investment Corporation (OPIC)
Export-Import Bank (EXIMBANK) of the United
States
U.S. Initiative on Joint Implementation (USIJI)
ureas of Funding and Other Assistance
Type of Assistance Provided I Comments
Grants j Loans I diner*
/
/
7
'
'
J
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
/
The World Bank finance capital infrastructure projects through the International Bank for
Reconstruction and Development (IBRD) and its affiliates - IFC,' IDA, and MIGA.
GEF funds the difference between expected project revenues and project costs.
Therefore, GEF funding is ideal for conducting feasibility assessments.
IFC provides loans and other financial packages to private sector enterprises only. The
minimum support provided by IFC is $10 million.
EBRD provides loans, equity, and guarantees to Central and Eastern European countries
for developing into market-based economies.
IDB provides loans for development projects in Latin America and the Caribbean. Grants
are available for poorer member countries.
ADB provides loans for the economic and social advancement of member countries.
Concessional funds are available through special funds established by the ADB.
AfDB provides loans for the economic and social advancement of African countries.
Grants are available for the poorest countries through special funds.
TDA provides funding to projects in developing countries that offer export or investment
potential for U.S. enterprises. The average grant size ranges from $300,000 to $400,000.
USAID's Office of Environment, Energy, and Technology assists in developing market-
based solutions to environmental problems in developing countries.
OPIC provides funding by facilitating U.S. private investment in developing countries
through loans, loan guarantees, and special services.
EXIMBANK provides loans and guarantees to foreign buyers of U.S. goods and services.
The bank finances up to 85% of the U.S. export value.
Projects that meet the USIJI criteria are likely to attract U.S. investors seeking to obtain
recognition and other amenities available to U.S. participants in the USIJI program.
t This includes loan guarantees, venture capital funds, consulting services etc.
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COALDED VETHANE GUIDELINES
6.6 References
Watts; Robert A., (1995) Profitable Market Opportunities for Pollution
Prevention • International Market Opportunities, Presentation for US
EPA Atmospheric Pollution Prevention Division Forum, April 10,1995,
Washington D.C.
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OALDED VETHANE GUIDELINES Aooenclx A
APPENDIX A: DIRECTORY OF SELECT COAL MINE METHANE RECOVERY AND USE
EXPERTS IN THE U.S.
Listing of experts does not constitute endorsement or recommendation for use.
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PROJECT DEVELOPMENT
Name j Address
1 . Alternative Energy Development, j 8455 Colesville Road, Suite 1 225
lnc- | Silver Spring, MD 20910
2. Burns and Roe NIS Consortium i 1 400 K Street N.W., Suite 910
j Washington, DC 20005
3. Dominion Energy Advisors I 14389 Emerald Pool Drive
j Centreville, Virginia 22020
4. Energy Resources International, I 1015 18th Street NW
lnc- | Washington, DC 20036
•
;
5. HVS Consulting j 4898 Hartland Parkway
| Lexington, KY 40515
6. ICF Incorporated j 1 850 K St., NW, Suite 1 000
| Washington, DC 20006
7. ICMG / El. Lasseter & Associates j 3610 Watermelon Road
i Suite 104
! Northport, AL 34576
8. I. Havyrluk and Associates j P.O. Box 252
| Carnegie, PA 15106-0252
9. Murray & Associates j 200 Union Blvd.
| Suite 215
| Lakewood, CO 80228-1830
10. Resource Enterprises j 1 245 East Brickyard Rd.
| Suite 170
| Salt Lake City, UT 84106
1 1 . United Energy Development i Park West One, Suite 1 70
Consultants j Pittsburgh, PA 15275
Contact Person
Mathew S. Mendis, President
Tel: (301)608-3666
John Leonhardt
Tel: (202)898-1500
Charles M. Boyer
Engineering Consultant
Tel: (703) 803-6007
David W. South
Vice President
Tel: (202)785-8833
Hilmar von Schonfeldt
Tel.: (606) 272-71 12
Mary DePasquale, Project Manager
Tel.: (202) 862-1 124
Edward L. Lasseter
President
Tel: (205) 759-2046
Ihor Havryluk, President
Tel.: (412) 343-3285
Keith Murray
President
Jeffrey Schwoebel, Vice President
Tel. (801) 467-9981
;
Isaias Ortiz
Tel.: (41 2) 787-7880
Area(s) of Expertise
Project Development
Project Development
Project Development
Project Development
Project Development
Project Development; Gas Use
Gas Production, Project Development
Project Development
Project Development
Project Development, Gas Production and Resource Assessment
Project Development
1
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2.
3.
4.
5.
6.
7.
8.
9.
10.
PRODUCTION MO RESOURCE Assessm
Name
Amoco Production Company,
Natural Gas (International)
Bureau of Economic Geology
University of Texas
CD Exploration, Inc.
Conoco, Inc.
CONSOL, Inc.
Enron Exploration Company
GeoMet, Inc.
Gustavson Associates
Halliburton Energy Services
ICMG / El. Lasseter & Associates
j
avr
Address
550 West Lake Park Boulevard
Houston, TX 77079-2696
University Station
BoxX
Austin, TX 78713-8924
5485 Beltline Rd. STE 280
Dallas, Texas 75240
P.O. Box 2197
Houston, TX 77252
Route 1, Box 119
Morgantown, WV
1400 Smith Street
Houston, TX 77002
1 826 3rd. Ave., North
Suite 301
Bessemer, AL 35020
5757 Central Avenue
Suite D
Boulder, CO 80301
Halliburton Center
Suite 2300, 5151 San Ripe
Houston, TX 77056
3610 Watermelon Road
Suite 104
Northport, AL 34576
Contact Person
Bruce N. Erickson
Marketing Advisor
Tel: (71 3): 556 41 28
Andrew Scott
Research Associate
Tel: (512)471-1534
James W. Akers
Mining Engihneer
Tel: (214) 392-1880
John Oehler
Tel: (713)293-6292
Pramod Thakur
Tel.: (304) 983-3207
J.Bradley Williams
Director, Oil & Gas Ventures
Tel: (713) 853-4777
Bret Camp
Senior Vice President
Tel: (205) 425-3855
John B. Gustavson
President
Tel: (303)443-2209
Bruce D. Thomas
Regional Technical Manager
Tel: (71 3) -624-2000
Edward L Lasseter
President
Tel: (205) 759-2046
Area(s) of Expertise
Gas Production and Resource Assessments
Gas Production
Gas Production
•
Gas Production
Gas Production and Resource Assessment
Gas Production
Gas Production
•
Gas Production
Gas Production
Gas Production, Project Development
•
•
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GAS
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
PRODUCTION AND RESOURCE ASSESSM
Name
Jim Walters Resources, Inc.
LAHD Energy, Inc.
Lapp Resources, Inc.
North American Drillers
Pennsylvania State University
Pocahontas Gas Partnership
Raven Ridge Resources, Inc.
Resource Enterprises
The River Gas Corporation
Taurus Exploration
Union Texas Petroleum
ENT
Address
P.O. Box 133
Brookwood, AL 35444
P.O. Box 2185
Granbury, TX 76048
4900 Sportsman Drive
Anchorage, AK 99502-4169
Rt. 9 Box 106-C
Morgantown, WV 26505
Hosier Building
Pennsylvania State Univ.
University Park, PA 16802
P.O. Box 200
Mavisdale, Virginia 24627
584 25 Road
Grand Junction, CO 81505
1245 East Brickyard Rd, Suite 170
Salt Lake City, UT 84106
511 Energy Center Blvd.
Northport, AL 35476
2101 Sixth Avenue North
Birmingham, AL 35203-2784
1330 Post Oak Boulevard
P.O. Box 2*120
Houston, TX 77252-2120
Contact Person
Charles Dixon, Senior Vice President,
Engineering
Tel.: (205) 554-6106
David Elliot
Tel: (817)- 326-2562
David W. Lapp!
President Tel: (907) 248-7188
Bill Maloney
President Tel: (304) 291-0175
Jan Mutmansky
Tel: (81 4) 863-1632
Raja V. Ramani
Tel: (814) 863-1617
Randall Albert
Program Manager
Raymond Pilcher, President
Tel.: (970) 245-4088
Jeffrey Schwoebel, Vice President
Tel. (801) 467-9981
Joseph Stevenson
Vice President
Tel: (205) 759 31 88
Walter Ayers, JR.
Senior Exploration Geologist
Tel: (205) 326-2774
R..D LoPiccolo
Project Manager
Tel: (713) 968-2522
Area(s) of Expertise
Gas Production and Resource Assessment
Gas Production
Gas Production
Gas Production
Gas Production and Resource Assessment
Gas Production
Gas Production and Resource Assessment
Project Development, Gas Production and Resource Assessment
Gas Production
Gas Production
Gas Production
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GAS USE
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
Name i
Allison Gas Turbines !
i
AquaTech Services, Inc. j
i
Black Warrior Methane Corp.
;
i
i
•
Energy Systems Associates
Gas Separation Technologies
ICF Incorporated
International Fuel Cells
Michael Baker Engineering Group
Nitrotec Engineering
Northwest Fuel Development
Powerbridge
Address i
P.O. Box 420
Indianapolis, IN 46206
P.O. Box 946
Fair Oaks, CA
P.O. Box 140
Brookwood, AL 35444
300 Gateway Two
Pittsburh.PA 15222-1402
1667 Cole Blvd.
Suite 400
Golden, CO 80401-3313
1 850 K St., NW, Suite 1000
Washington, DC 20006
195 Governors Highway
P.O. Box 739
South Windsor, CT 06074
4301 Dutch Ridge Road
Beaver, Pennsylvania 15009
61 1-M Hammonds Ferry Road
Linthicum, MD
P.O. Box 35833
Canton, OH 44735
3710 Rawlins Street
Suite 1060
! Dallas, TX 75219
Contact Person | Area(s) of Expertise
R.F. Merrion, Director Gas Use
Tel: (317)230-411 j
John Tait, Principal j Gas Use
Tel: (91 6) 723-51 07 j
R.G. Sanders, President/ General
Manager
Tel.: (205) 554-6288 j
Roger Clicked
Tel: 412-392-2390
Gas Use
Gas Use
Jerry Comer Gas Use
Tel: (303)-232-0658
Mary DePasquale, Project Manager
Tel.: (202) 862-1 124
Fax:(202)862-1144
Murdp J. Smith
Tel: (203) 727-2269
Rebecca Rannich
Tel: (412)495-4042
Joseph D'Amico
! President
Tel: (301) 636-7200
Dale R. Jesse
V.P. Engineering
Tel: (909) 736-1 203
James R. Clemments
President
Tel: (21 4) 520-81 77
Project Development; Gas Use
Gas Use
Gas Use
Gas Use
Gas Use
Gas Use
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GAS USE
| Name 1 Address
12.
13.
14.
15.
Solar Turbines Inc.
.
Stord, Inc.
UOP
Viking Systems
818 Connecticut Ave., NW
Suite 600
Washington, DC 20006-2702
309 Regional Road South
Greensboro, NC 27409
13105 Northwest Freeway, Suite
600
Houston, TX 77040
20270 William Pitt Way
Pittsburgh, PA 15238
Contact Person
Peter A. Carroll
Vice President
Tel: (202) 293-4327
Jeff Johnson
Tel: (910) 668-7727
Ronald J. Buras
Account Representative
Tel: (713) -744-2881
Jack Saluja
President
Tel: (412) 826-3355
Area(s) of Expertise
Gas Use
Gas Use
Gas Use
Gas Use
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APPENDIX B: DIRECTORY OF POSSIBLE FUNDING
AGENCIES
Profiles of the following funding agencies are provided:
World Bank Agencies/Programs
International Bank of Reconstruction and Development (IBRD)
Global Environment Facility (GEF)
International Finance Corporation (IFC)
Multilateral Development Banks
European Bank For Reconstruction and Development (EBRD)
Inter-American Development Bank (IDB)
Asian Development Bank (ADB)
Africa Development Bank (AfDB)
U.S. Government Agency Programs
Trade Development Agency (IDA)
United States Agency For International Development (USAID)
Overseas Private Investment Corporation (OPIC)
Export-Import Bank (EXIMBANK)
U.S. Initiative on Joint Implementation
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Aooencix 3
VETIIANE GUIDELINES
The World Bank, through its affiliates
mm, IDA, IFC, and MIGA, provides
financial assistance to developing
countries for social and economic
development projects.
International Bank of Reconstruction and Development
(IBRD)
Overview: The World Bank, established in 1945, comprises the International
Bank for Reconstruction and Development (IBRD) and its affiliates: the
International Development Agency, the International Finance Corporation
(IFC), and the Multilateral Investment Guarantee Agency (MIGA). 155
member countries have subscribed capital to the Bank enabling it to finance its
lending operations primarily from its own borrowing in capital markets.
However, a substantial portion of the IBRD's resources also come from the
retained earnings and the flow of repayment.
The World Bank finances capital infrastructure, such as roads and railways,
telecommunications, and port and power facilities. However, the Bank's
development strategy emphasizes investments that can directly affect the well-
being of poor people in developing countries by making them more productive
and integrating them as active partners in the development process. The
Bank's efforts to reduce poverty include investments to improve education,
ensure environmental sustainability, expand economic opportunities,
strengthen population-planning, health and nutrition services, and develop the
private sector.
Criteria: The IBRD's charter requires that it: (1) lend for productive purposes
to stimulate economic growth in developing countries; (2) pay due regard to
the prospects of repayments; (3) make loans to governments or with
guarantees from the government; (4) not restrict procurement to purchases
from any particular member country; and (5) make lending decisions on
economic considerations alone.
The IDA provides assistance to poorer developing countries, i.e., those with an
annual per capita gross domestic product of $580 or less, expressed in 1989
U.S. dollars. Terms of the IDA loans are less stringent than those of "regular"
IBRD loans.
The IFC is legally and financially a separate entity. Its purpose is to promote
growth in the private sector of the less developed country economies, largely
by taking equity positions in projects (see profile).
The MIGA encourages equity investment and other direct investment trtrough
the mitigation of non-commercial investment barriers. MIGA must: (1) offer
investors guarantees against non-commercial risks; (2) advise developing
member countries on policies, programs, and procedures related to foreign
investment; and (3) sponsor a dialogue between the international business
community and host governments on investment issues.
Contact Information: For further information, contact
The World Bank
1818 H Street, N.W.
Washington D.C. 20433 USA
Tel: 202/477-1234
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HALOED VETHANE GUIDELINES
Airjeric'.x 3
Global Environment Facility (GEF)
Overview: The Global Environment Facility (GEF), an organization established
by the United Nations Development Program (UNDP), the United Nations
Environment Program (UNEP), and the World Bank, offers grants and
concessional funds to developing countries for projects that are beneficial to
the global environment. GEF funds are used to cover the difference between
the costs of a project undertaken with global environmental objectives in mind,
and the costs of an alternative project that the country would have
implemented in the absence of global environmental concerns. GEF
resources are available to projects that address the following four areas:
climate change, loss of biological diversity, pollution of international waters,
and depletion of the ozone layers. Listed below are several types of projects
that the GEF may fund.
• Technical assistance projects focused on human development,
capacity building, training, and information sharing;
• Feasibility studies for investment projects and complex technical
assistance projects;
• Small grants for community-based grassroots organizations and non-
governmental organizations in developing nations; and
• Grants to investment projects to fund the incremental costs of
achieving global environmental benefits.
Criteria: The GEF has established general criteria for all areas in which it may
fund projects, as well as criteria specific to each of the four areas. The general
points which are assessed include:
• Potential to benefit the global environment;
• Contribution to human welfare and sustainable development;
• Financability of project without GEF support;
• Scientific and technical basis of project;
• Plans for evaluation and dissemination of results;
• Host nation political, legal, economic, and administrative conditions
under which the project must be executed
• Development of human and institutional resources;
• Plans for post-GEF project continuation; and
• Involvement of local communities.
Contact Information: For further information, contact the GEF at:
GEF Administrator, Environment Department
World Bank
1818 H Street, N.W.
Washington, DC 20433
Tel: 202/473-1053
Fax: 202/477-0551
GEF will fund only those projects
which cannot pay for themselves, Le.,
whose project costs exceed project
revenues. Therefore, GEF funding is
ideal for conducting
assessments.
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Aooe.icix 3 COALDED VETHANE GUIDELINES
International Finance Corporation (IFC)
Overview: The International Finance Corporation (IFC) was established in
1956 to help strengthen the private sector in developing countries. IFC lends
directly to the private sector. IFC aids private sector development by providing
long-term loans, equity investments, guarantees and "stand-by financing", risk
management and "quasi-equity instruments", such as subordinated loans,
preferred stock, and income notes. IFC advisory services and technical
assistance help private business increase their chances of success. Other
relevant information on IFC is as follows:
• Source of funds: About 80% is borrowed in the international financial
markets through public bond issues private placements and 20% is
borrowed from IBRD;
• Lending. Each year, IFC approves about $4 billion in financing,
including syndications and underwriting for private-sector projects in
developing countries. The minimum amount of IFC support available
is $10 million; and
• Loan Conditions: Interest rate on IFC loans and financing are based
on market rates, which vary between countries and projects; maturity
on loans ranges from 3 to 13 years.
Criteria: Project proposals will be assessed on the basis of the following
IFC will provide loans and other information:
financial instruments (equity
imestments^uarant-ees^etc.)tothe 9 Project Description, brief description of the project and current status;
ornate sector only. The mnmum ' ,_._,.. L. . ._ .
support provided by IFC is $10 mason * Sponsorship and Management history and business of sponsors,
management arrangements, and technical arrangements;
• Markets and Sales: market orientation (export/domestic), production
volumes and sales objectives, potential users and distribution
channels, and relevant tariffs and protective measures;
• Technical Feasibility: equipment availability, labor and infrastructure
facilities, resource accessibility, and potential environmental issues;
• Financing Requirements: breakdown of project costs, proposed
financial plan, type of assistance sought, and expected profitability;
• Government Regulations: government controls, exchange controls,
tax regulations, export/import licences, and price controls applicable
to the project.
Contact Information: For further information, contact the IFC at:
International Finance Corporation
18501 (Eye) Street, N.W.
Washington, D.C. 20433
Tel.: 202/477-1234
Fax: 202/477-6391
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COALBED VETIIANC GUIDELINES
A'ooenc'.x
European Bank fot Reconstruction and Development
(EBRD)
Overview: The European Bank for Reconstruction and Development (EBRD)
is a multinational institution set up with the specific aim of assisting countries
of central and eastern Europe to develop into market-oriented economies. The
EBRD provides financial assistance to both the private and public sector. The
types of financial instruments offered include: loans; equity and quasi-equity
investments; and guarantees. Other information about EBRD financing:
• Minimum Loan Amount. The minimum lending requirement for the
Bank is ECU 5 million ($6.5 million, as of November 1995).
• Interest Rates: Interest rates are set at a margin over a market
benchmark (usually LIBOR - London Interbank Offered Rate). Loans
can be either variable rate or fixed rate;
• Loan Term. Maturities generally range,from 5 to 10 years, depending
on the individual operation requirements; and
• Currency. The EBRD lends in hard currencies - US dollar, the
Deutschmark, andtfie ECU.
Criteria: The first step in the approval process is the Concept Clearance
stage. Prospective borrowers approach the banking staff to advise on
procedure and potential structuring options. Based on information on the
scope of the project, financing requirements, and technical and
economic/commercial aspects, the Bank will determine whether the project fits
within its guidelines and strategies.
If the project is cleared, a Mandate Letter, defining the legal requirements for
entering to a relationship with the Bank, is signed and an Operation Leader is
assigned as the key Bank contact for the project. The next stage is the Initial
Reviewwhich requires detailed project information, including:
• detailed description of the enterprise, project, and key personnel;
• financial statements audited to international standards;
• financial projections about the viability of the project;
• regulations applicable to the project; and
• assessment of the environmental impact of the project.
Once the project has cleared Initial Review, it has to pass Final Review by the
Bank's Operation Committee. This evaluation process covers financial, legal,
economic, technical, and environmental issues.
Contact Information: For further information, contact:
EBRD, One Exchange Square
London EC2A2EH, United Kingdom
Tel: 44 71 338-6282
Fax:4471338-6102
EBRD provides bans, equity, and
guarantees to countries of central and
eastern Europe that are developing
into market-based economies.
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::x 3
"OALBED VLTIIANE GUIDELINES
IDB provides loans to governments
and private sector agencies for social
and economic development projects in
Latin America and the Caribbean.
Grants are available for poorer
member countries.
Inter-American Development Bank (IDB)
Overview: The Inter-American Development Bank (IDB) is a multilateral
development bank created to help accelerate the economic and social
development of its member countries in Latin America and the Caribbean. The
IDB provides the following types of assistance to its member countries: loans
and other financial instruments; concessional funds for needier countries
(through its Fund of Special Operations); and technical assistance to
strengthen regional development institutions and help identify and implement
investment projects. Other relevant information about the IDB is as follows:
• Extent of Financing. The IDB finances a certain percentage of project
costs, ranging from 50% for more economically developed countries
to 80% for poorer countries.
• Loan Conditions: Interest rates on IDB loans and financing are based
on market rates, which vary between countries and projects; maturity
on loans ranges from 15 to 25 years.
• Capital Resources: The IDB has a capitalization of over $100 billion
that can support a level of annual lending of over $7 billion.
Typical borrowers of IDB funds include governments, ministries, or an agency
or utility under a ministry. The borrower makes the key decisions on awarding
contracts for engineering, design, project management, works construction,
and purchase of capital goods. While governments and related agencies are
the primary recipients of IDB funds, private sector enterprises too are eligible
for some forms of assistance.
The IDB has an Environmental Division that monitors the environmental
component of the Bank's operations and develops loans and technical
assistance packages specifically directed towards protecting the environment.
Criteria: The following analyses are conducted to evaluate project proposals:
• Institutional: borrower's administrative and operational capability to
carry out the project;
• Technical technical equipment, labor, and infrastructure required;
• Socio-economic, social and economic costs and benefits, impacts on
trade, income distribution, production, and employment; and
• Environmental environmental impacts of the project.
Contact Information: For further information, contact:
Inter-American Development Bank
1300 New York Avenue, N.W.
Washington D.C. 20577 U.S.A
Tel: 202/623-1000
Fax: 202/623-3096
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COALBED VETHANE GUIDELINES
A'j'jenc'x 3
Asian Development Bank (ADB)
Overview: Established in 1966, the Asian Development Bank (ADB) is a
multilateral development bank whose primary objective is poverty alleviation
through sustainable economic growth in Asia The Bank has 35 developing
member countries, of which China, India, and Indonesia are the largest
recipients. ADB assistance is channeled into the following sectors: agriculture
and agro-industry; energy; industry and non-fuel minerals; financial services;
transport and telecommunications; social infrastructure (e.g., education,
health); and urban development.
Typical borrowers of ADB funds include governments, ministries, or an agency
or utility under a ministry. The borrower makes the key decisions on awarding
contracts for engineering, design, project management, works construction,
and purchase of capital goods. While governments and related agencies are
the primary recipients of ADB funds, private sector enterprises too are eligible
for some forms of assistance. For private sector support, a project must play a
catalytic role in the development of the country. For such projects, ADB
assistance is limited to 50% of project costs or up to $50 million, whichever is
less. The minimum loan is $5 million.
The financial resources of the Bank consist of ordinary capital resources
comprising subscribed capital from member countries, reserves and funds
raised through borrowings; and Special Funds, including the Asian
Development Fund, which is made up of contributions from member countries
and other accumulated income; and the ALGAS fund, which is designed to
support GHG mitigation activities in developing member countries.
Criteria: The projects or programs are analyzed in terms of:
• the borrower's capacity to finance and administer the project;
• its economic, technical, and environmental feasibility; and
• its social and economic benefits to the recipient country:
Contact Information: For further information, contact:
Asian Development Bank
Office of the Environment and Social Development
6 ADB Avenue, 1501 Mandaluyong City
0401 Metro-Manila, Philippines
Tel.: 632/813-2148
Fax: 632/741-7961
ADB provides loans for the economic
member countries. Grants are
available through special funds
established by the ADB (e.g., ADF,
ALGAS).
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COALBED V.ETHANE GUIDELINES
AIDB provides bans for the economic
and social advancement of African
countries. Grants are available for the
poorer countries through Vie Africa
Development Fund ami the Nigeria
Trust Fund.
African Development Bank (AfDB)
Overview: The African Development Bank (AfdB) is a multilateral development
bank whose primary objective is to finance economic and social development
in African countries. It achieves this objective through the provision of: loans
and other financial instruments; technical assistance and institutional support;
and mobilization of external resources for investment in Africa. Grants and
other concessional funds are allocated for the poorest countries through the
African Development Fund (ADF) and the Nigeria Trust Fund (NTF). The main
criteria for defining the poor countries is GNP per capita. The loan terms are
as follows:
Terms
Interest Rate
Service Charge
Repayment Period
AfDB
Variable'
1%
20 years
ADF
None
0.75%
50 years
NTF
4%
0.75%
25 years
t The interest rate is reviewed every 6 months. As of June 30, 1995, the rate was 7.42%
Typical borrowers of AfDB funds include governments, ministries, or an
agency or utility under a ministry. While governments and related agencies
are the primary recipients of AfDB funds, private sector enterprises too are
eligible for some forms of assistance. For private sector support, AfDB
assistance is limited to a third of project costs. The size of private sector loans
are generally in the $100,000 to $10 million range.
Criteria: The AfDB approves projects or program financing only on the basis of
appraisal reports prepared and submitted by the Bank's own staff, even where
a project have been previously appraised by other co-financing institutions.
The appraisal process accounts for the following:
• the borrower's administrative and operational capability to carry out
the project;
• technical equipment, labor, and infrastructure required and available;
and
• social and economic costs and benefits.
Contact Information: For further information, contact:
African Development Bank
01 BP1387 Abidjan 01
Cote d'lvoire, Africa
Tel: 225/2041 18
Fax: 225/204006
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OALBED VETHANE-GUIDELINES
Aovjenc:x
Trade Development Agency (TDA)
Overview: Established in 1980, the U.S. Trade Development Agency (TDA) is
a government organization that promotes U.S. exports by providing grants for
feasibility studies for large development projects in .developing and middle
income countries. The purpose of these grants is to provide U.S. firms with
the opportunity to undertake feasibility studies for large overseas projects,
thereby increasing the chance that they will be involved in project
implementation. TDA grants the funds on the condition that U.S. firms are
utilized to conduct the study. TDA is currently involved in: energy,
environment, mining and minerals development, health care, manufacturing,
telecommunications, transportation, water resources, agriculture, and aviation.
There are two types of studies which the TDA may fund: (1) feasibility studies
for projects in which U.S. companies intend to make equity investments, and
(2) feasibility studies for public sector projects. Before TDA funds a feasibility
study, experts are hired to develop reports regarding the feasibility study and
the project to be implemented at the conclusion of the study. If the TDA
decides to fund the feasibility study, it asks interested firms to submit
proposals. The host government decides which of the competing companies
will undertake the study.
The agency may provide up to one million dollars per study, although the
average grant amount ranges between $300,000 and $400,000. While up to
20 percent of the TDA funding may be used to pay subcontractors in the host
country, the remainder must be used for services sourced in the U.S.
Criteria: All feasibility study proposals must include the following information:
project description; U.S. export potential; information on host country partners;
evidence of the host nation's commitment to the project; justification for why
TDA funding is needed; a financial analysis of the project; an assessment of
foreign competition for project implementation; and the impact of the project on
U.S. labor. A few of the most important criteria include:
• The project must be a development priority for the host country.
• The export potential of the project must be significantly greater than
the cost of TDA assistance.
• The procurement process must be open to U.S. firms.
Contact Information: For further information, contact the TDA at:
Trade Development Agency
Room 309, SA-16
Washington, D.C. 20523-1602
Tel.: 703/875-4357
Fax: 703/875-4009
TIM will provide giants to conduct
feasibility studies in developing
countries on the condition ttaf U.S.
firms be hoed to conduct the study.
The average grant size ranges from
$300,000 to $400,000.
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AoDenclx 3
V.ETHANE GUIDELINES
USAID's Office of Energy.
Environment, and Technology
provides grants and tec/mica/
assistance to developing countries for
meeting their energy and
environmental needs.
U.S. Agency for International Development (USAID)
Overview: USAID's Office of Energy, Environment, and Technology assists
developing countries and emerging economies find market-oriented solutions
to their energy and environmental problems. The Office's programs address
three main issues: 1) high rates of energy demand and economic growth
accompanies with lack of energy, especially in rural areas; 2) financial
problems, including lack of investment capital; and 3) growing environmental
threats, especially global climate change, acid rain, and urban air pollution.
The Office focuses its efforts in the following areas:
• Energy Efficiency
• Renewable Energy Project Development
• Private Sector Energy Development
• Energy Technology Innovation
• Training/Technical Assistance
The Office has two main strategies for achieving its objectives:
• Tapping U.S. Know-how. The Office arranges cooperative
relationships between developing countries and U.S. energy and
environment industries, multilateral development banks, and non-
governmental organizations; and
• Promoting Private Sector Initiatives: The Office assists countries put
in place market-oriented policies and institutions to support private
environment and energy initiatives.
The types of assistance offered include: financing (loans, investment funds);
policy, legislative, and regulatory development assistance; reports and
workshops on market conditions and opportunities; and engineering and other
technical assistance.
Criteria: The criteria for USAID fund varies on a case-by-case basis.
However, the following points are generally considered in the project
evaluation process:
• Potential of the project to meet its goals
• Contribution to human welfare and sustainable development;
• Scientific and technical basis of project;
• Host nation political, legal, economic, and administrative conditions
Contact Information: For further information, contact:
U.S. AID: Office of Energy, Environment and Technology
Room 508, SA-18
Washington D.C. 20523-1810
Tel.: 703/528-4488
Fax: 703/528-2280
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"OALBED VETHANE GUIDELINES
AoDenclx 3
Overseas Private Investment Corporation (OPIC)
Overview: OPIC is a U.S. government agency that provides loans, loan
guarantees, and political insurance to American business ventures in the
developing world. These services are provided to those projects that are
economically and technically sound but are unable to receive sufficient
financing or insurance from the commercial sector. Projects supported by
OPIC must have a positive effect on the U.S. economy, be financially sound,
and provide significant benefits to the social and economic development of the
host nation. While OPIC does not require the foreign enterprises to be owned
entirely by U.S. interests, generally the U.S. investor is expected to own at
least 25 percent of the equity in the project. Neither financing nor insurance
will be available for investments in business that are majority owned by a
foreign government. Furthermore, only the portion of the investment made by
a U.S. investor may be insured by OPIC.
OPIC's finance division offers loans and loan guarantees. Loans are generally
granted to small U.S. businesses and range from $2 million to $10 million. For
larger projects, in the $10 million to $75 million range, loan guarantees are
provided. OPIC's insurance division offers coverage against the following
three risks: currency inconvertibility, expropriation, and political violence.
Other investor services provided by OPIC include investment missions and
outreach activities.
Criteria: Eligible projects must meet the following criteria:
• Positive effect on the U.S. economy: Projects must demonstrate
positive balance of payments and employment effects on the U.S.
economy;
• Development contribution: Projects must benefit the economic and
social development of the host nation;
• Performance requirements: OPIC will not become involved in any
project subject to performance requirements that will reduce the
potential for U.S. trade and employment benefits.
• Environmental impact: the project should not have an unreasonable
or major adverse impact on the host nation's environment; and
• Worker's rights: All projects supported by OPIC must meet
- internationally recognized standards with regards to worker's rights.
Contact Information: For further information, contact OPIC at:
Overseas Private Investment Corporation
1100 New York Avenue, N.W.
Washington, D.C. 20527
Tel.: 202/336-8799
Fax: 202/408-9859
Fax-ion-Demand System: 202/336-8700
OPIC will provide loans and loan
guarantees tor projects in developing
countries tfiaf US enterprises have a
stake in. The project must have a
positive effect on the US economy.
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COALBCD V.ETHANE GUIDELINES
EXIMBANK provides loans and
guarantees to foreign buyers of US
goods and services. The bank covers
up to 85% of the US export value.
Export-Import Bank (EXIMBANK)
Overview: The Export-Import Bank (EXIMBANK) of the United States is a U.S.
Government agency that facilitates the export financing of U.S. goods and
services to foreign buyers. EXIMBANK supports export sales by providing
direct loans to foreign buyers, guarantees to U.S. and foreign commercial
lenders for credit risk protection, export credit insurance, to U.S. exporters
against failure of foreign buyers to meet payment obligations, and pre-export
financing for small business through its Working Capital Guarantee Program.
Relevant information about EXIMBANK loans includes:
• Types of Loans: EXIMBANK provides both direct and intermediary
loans. Direct loans are provided to foreign buyers of U.S. exports;
intermediary loans fund parties that extend loans to foreign buyers;
• Interest Rates: EXIMBANK loans carry the lowest interest rate
permitted under the OECD Arrangement for the market and term. ,
this rate is the OECD Commercial Interest Reference Rate (CIRR),
which changes monthly. For relatively poor countries, lower interest
rates loans are available; and
• Extent of Assistance: Loan and guarantee programs cover up to 85%
of the U.S. export value.
Criteria: Transactions are evaluated in terms of the creditworthiness of the
buyer, the buyers country, and the exporters ability to perform. In general the
following information is assessed:
• Financial Data: Balance sheets and income statements for the past 3
years for the buyer and any guarantors);
• Credit Data: at least two credit references are checked;
• Technical Feasibility, technical characteristics of the project,
breakdown of costs, project scheduling, participant profiles,
environmental aspects, etc.; and
• Applicant and Exporter Data: Evidence of the applicants ability to
implement the requested loan or guarantee.
Contact Information: For further information, contact:
Export-Import Bank of the United States
Credit Information Section
811 Vermont Avenue, N.W.
Washington D.C. 20571
Tel: 202/377-6336
Fax: 202/566-7524
Fax -on-Demand system: 800/424-5201
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:OALBEU VETIIANE GUIDELINES
Aooenc'.x !3
U.S. Initiative on Joint Implementation (USIJI)
Overview: The U.S. announced its Initiative on Joint Implementation (USIJI)
in October 1993. This voluntary pilot program provides recognition and select
technical assistance to U.S. greenhouse gas reduction projects in other
countries. This program allows U.S. companies to reduce emissions at a
lower cost than would be incurred by projects undertaken at home. U.S.
government agencies involved in this program include the Environmental
Protection Agency, the Department of Energy, the Department of State, the
Agency for International Development, the Department of Commerce, and the
Department of Agriculture, among others.
The benefits of this program to U.S. participants include public recognition,
including use of the USUI logo and media events, and technical assistance.
This assistance may include help in obtaining host country acceptance of the
project, identifying or developing methodologies for establishing a greenhouse
gas emissions baseline, and guidance on how to monitor and verify emissions
reduced or sequestered. For foreign participants, the benefits may include
technology transfer, investments in technologies that benefit the global
environment as well as the local economy, employment opportunities and
training, and local environmental benefits.
Eligible program participants include U.S. citizens, U.S. companies, and any
U.S. federal, state, and local government entity. Foreign partners may include
private citizens and public entities of all nations that have ratified the United
Nations Framework Convention on Climate Change (UNFCCC).
Criteria: Projects accepted into the USIJI program must:
• obtain host country acceptance;
• prove that the specific measures to reduce or sequester greenhouse
gases are being undertaken as a result of USIJI or in its anticipation;
• provide sufficient and reliable data to establish a baseline of current
and future greenhouse gas emissions;
• provide for the tracking of emissions reduction or sequestration;
• allow for external verification of emissions reduction or sequestration;
• identify benefits or negative effects on the economic and social
development of the host country and on the local environment.
Contact Information: For further information, contact:
The USIJI Secretariat
600 Maryland Avenue, SW Suite 200 East
Washington, D.C. 20585
Tel.: 202/426-0072
Fax-on-Demand System: 202/260-8677
Projects that meet the USUI criteria
are likely to attract US investors
seeking the recognition and other
amenities available to participants in
the USUI program.
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