WHITE PAPER:
The Impacts of FERC Order 636 on
Coal Mine Gas Project Development
         March 27,1998


This draft report was prepared under Work Assignment 3-1 of the U.S. Environmental
Protection  Agency Contract  68-W5-0018 by Raven  Ridge  Resources,  Incorporated.
This report is a technical document meant to be used for information dissemination.

The views represented in this report do not necessarily reflect the views of the U.S.
Environmental Protection Agency. The mention of trade names or commercial products
does not constitute endorsement or recommendation for use.


The  U.S.  Environmental Protection Agency's Coalbed  Methane Outreach  Program (CMOP)
prepared this paper to help  coal companies and energy project developers understand the
increased  opportunities for coal mine  gas use resulting from Federal Energy  Regulatory
Commission (FERC) Order 636.  The paper presents approaches that both large and small
producers can use to optimize the sale  of coal mine gas.   It describes  the parties, and
combinations of  parties, that may be  involved in  bringing gas from the  producer  to the
consumer, and provides examples of the  various contracted transactions between parties.

Order 636 provides coal mine gas producers with expanded markets, expanded transportation
access, a greater role for gas storage, and the ability to accommodate fluctuations  in gas
quantity and quality. This report discusses each of these potential benefits in detail. The report
also describes the key factors that determine coal mine gas marketability, and opportunities for
expanding coal mine gas project development.

Order 636  has created a  gas market whose complexity is sometimes perplexing to those
outside the gas industry, yet at the same time has increased opportunities for the sale of coal
mine gas.  CMOP hopes that this paper provides a first step in helping coal mine gas producers
identify the gas marketing arrangement that will best meet their individual needs.


                        THE IMPACTS OF FERC ORDER 636 ON

This paper explores new opportunities for coal mine gas1 use resulting from the passage of the
Federal Energy Regulatory Commission's (FERC's) Order 636 in 1992. This regulation changed
the natural gas industry from a regulated industry to one that is market-based. The fundamental
change promulgated by Order 636 is that the gas market is now competitive, with the result that
market conditions change rapidly.

Prior to FERC Order 636, pipeline companies purchased natural gas that they transported. The
price at which pipelines sold gas to consumers generally included the bundling of transportation
costs and costs of other component services, such as marketing. In the post-Order 636 period,
interstate natural gas  pipelines must provide transportation services  unbundled from sales
services. This provision has had a profound impact on the buying and selling  of natural gas,
encouraging  the  development  and use of  market centers or hubs  where several pipeline
systems interconnect,  and where gas buyers and sellers  can make or take  gas deliveries.
Creation of these  hubs has allowed greater competition between gas suppliers,  distributors,
marketers, and buyers, thus  increasing purchasing and selling opportunities.  Along with the
diversity in available markets comes diversity in the types  of agreements that are  constructed
between these groups. An important benefit to producers is that, in cooperation with any one of
many marketing groups, they can now target a specific market, tailoring the contract to best suit
the mine's gas production characteristics.

Optimizing the Sale of Coal Mine Gas

The price that coal mine gas producers will receive for their gas depends on the gas quality and
reliability of production, the location of the gas relative  to competing supplies, transportation
constraints, and the extent to which the mine operator or producer can create value through the
addition of related services and bundling, such as storage.  Mines wishing to optimize their gas
sales should take one or more of the following approaches:

•   Assume the role of producer, or partner with a gas producer to develop and market  coal
    mine gas. Because coal  mine operators are not in the gas business, they  may find it
    advantageous to allow a natural gas producer to develop the methane for sale and take the
    risk. Gas producers may have expertise in areas such as transportation and marketing, and
    can assume these  responsibilities for the mine. The mine owner could receive a royalty for
    all  gas developed  and sold. The major  issues with  these types of arrangements  involve
    coordinating gas production with coal production and overall safety considerations.  The
    mine and  producer can address these issues by working together to design a  methane
    development program that optimizes mine productivity and safety.

•   Actively produce and market coal mine gas as a commodity. In cases where a mine  already
    has the infrastructure in place to sell  the gas, it may be more advantageous for the  mine to
    sell the gas directly to marketers or local distributing  companies  (LDCs)  rather  than simply
 The term "coal mine methane" refers to gas that is released from coal or surrounding rock strata during the process of coal mining.
In addition to methane, this gas may contain other hydrocarbon gases or constituents such as carbon dioxide, nitrogen, or oxygen.
Because some readers could construe "coal mine methane" to mean pure methane, this paper will instead use the term "coal mine

   accept a royalty payment. The  manpower required to market gas and ensure timely flow,
   deliverablity, and contract monitoring in the post-Order 636 environment has increased, but
   for some mines the rewards may support these additional staffing requirements.

•  Market gas consistent with production characteristics.  Coal mine methane degasification
   wells have  production characteristics that differ from conventional natural gas  wells. For
   example, because in-seam and gob wells are designed primarily to drain a mine of methane
   for safety reasons, the operator cannot halt gas flow simply because  demand for the gas
   has  diminished.   Methane production rates can also  vary within different areas of the coal
   seam that is undergoing mining. Thanks to the flexibility in contracts that is characteristic of
   the post-Order 636 environment,  mine operators may be in  a much better position to sell
   gas  production consistent with their operational requirements. In other words, variability in
   gas  production from coal mines due to the variability in mine operations need no longer
   hinder the marketability of the gas, because the mine and the marketer can  negotiate their
   contract with the understanding  that the amount and heating  value of the gas that the mine
   supplies will be variable.

•  Acquire pipeline capacity. This strategy is most suitable for larger producers and could be
   accomplished  by  acquiring  capacity  directly  from the pipeline  or indirectly  through the
   secondary  market. Having the ability  to deliver gas to a  major hub would provide greater
   opportunities for sales at current  market  prices. The ability to bundle  gas with capacity to
   deliver to larger markets will allow  producers to enjoy higher revenues.

•  Provide a variety of gas-related services. Some coal mines may have the opportunity to
   provide a "total Btu" type of service that  would provide coal  and gas,  and in some cases,
   electricity to the consumer. This will be most profitable to the operator in cases where coal
   mine gas production is well located relative to gas and electricity markets, in terms of both
   proximity  and  available  capacity.  High-deliverability  gas  storage,  a characteristic of
   abandoned  mine storage facilities, is another service  that  some mines could  offer (see
   section on Gas Storage  in Abandoned Mines under "Opportunities for Further Expanding
   Coal Mine  Gas   Project  Development"  below). This would  allow   rapid  injection  and
   withdrawal of gas, which commands a premium in the market. The proximity to market areas
   would allow users to receive higher seasonal gas prices. In addition,  the mine could take
   advantage of  the storage facility to  store its own gas. Providing additional services in
   conjunction with coal mine methane production can  also reduce the risks associated with
   fluctuating energy prices.

•  Bundle coal mine gas with environmental benefits. The biggest  environmental benefits of
   substituting or co-firing  coal with coal mine gas  are  a  reduction  in SO2,  NOX,  and
   greenhouse gas emissions. Today, only SO2 reductions have a set market value; however,
   in the future it  is projected that NOX and greenhouse gas emissions will  also have a tangible
   value and be traded as a commodity. Bundling coal  mine gas sales with these emissions
   reduction credits will add  value to most  coal  mine  gas  projects, enhancing  their
   marketability. The EPA has  recently prepared a report entitled Technical  and Economic
   Assessment of Coal Mine Methane in Coal-fired Utility and Industrial Boilers in Northern
   Appalachia  and Alabama. This report discusses the technical, economic and environmental
   advantages of co-firing coal mine methane in boilers.

It is clear that while  the opportunities  available to coal mine gas  producers are great, there are
risks associated with  developing those markets that could  bring the greatest return. For all of

these  strategies, producers should  employ creativity in contracting to achieve flexibility in
accommodating market  driven pricing.   Contracts can include special  terms and  delivery
assurances that best satisfy the needs of the mine.

Parties Involved in Bringing Gas From Producers to Consumers

A variety of opportunities can exist for sale, transportation, and delivery of gas produced from
coal mining properties.  Following is  a description of the parties that may be involved in  the
process of bringing gas from the producer to the consumer.

Producer: Responsible for exploring, drilling, and operating the gas wells. Is also often called
the Operator. The bulk of gas sale revenues goes to the producer, who bears the expense and
risk of drilling and marketing the production.

Marketer:  One of the aspects of Order  636 that provides opportunities for coal  mine gas
producers and  suppliers is that it allows for the aggregation of gas supplies from a variety of
sources. The marketer is the  middleman, or merchant,  who aggregates the gas.   Marketers
repackage the  gas with transportation and  pricing terms for resale to LDCs or  end-users.
Marketers may also provide services to producers  including financing,  hedging,  gathering,
processing and other related support services.

Pipeline Company: Provides  natural gas  transportation services under predetermined tariffs
(general operating  rules and  rates  kept  on  file at  FERC)  and  individual  transportation
agreements. The individual contract agreement to transport the gas will be between the shipper
and the pipeline. The shipper can be any of the parties described above.

Local  Distribution Company  (LDC): LDCs  are the primary retailers of natural  gas.  They
receive gas from the interstate pipelines  through their city gates, step down the pressure, and
deliver gas to customers on their distribution systems.

Consumer/End-user: The ultimate user  of natural gas, as contrasted to one who sells gas, or
purchases natural gas for resale, such  as a marketer or LDC.  Large gas consumers can
directly purchase coal mine gas from the producer. This would be appropriate for cases where a
facility with high gas demands (such as an institution, industrial or utility boiler, glass  factory, or
steel mill) is located near a gassy mine.

Gas Sales Contracts

Changes  in the  natural gas industry, augmented by  FERC Order 636, are creating new
opportunities for coal mine gas producers. The number  of mines with gas recovery and use
projects has increased from 10 in 1994 to at  least 17 in 1997. Detailed descriptions of these
projects, as well as profiles of the gassiest mines in the U.S., can be found in a 1997 EPA report
entitled Identifying Opportunities for  Methane Recovery at U.S.  Coal Mines: Draft Profiles of
Selected Gassy Underground Coal Mines. In 1996, U.S. mines recovered an estimated 49  bcf
of gas for use.  These projects range  in size and type, and exemplify most of the different types
of contract combinations discussed below and shown in Figure 1.

One of the key reasons that Order 636 has created new opportunities for coal mine gas sales is
that it allows flexibility in contracting.  It virtually guarantees that a producer can sell  its gas as
long as there is a market. The key to  profitability in this endeavor is the type of contract that the

various parties involved can negotiate. Following are several examples of the various contracted
transactions between parties. Figure 1 illustrates these relationships.

-   Producer/Marketer: A coal mine gas producer drains the gas in conjunction with mining and
    sells  the drained gas to  a marketer. The marketer is responsible for  all costs  and
    arrangements of getting the gas to the end-user.

-   Producer/LDC: A coal mine gas producer sells the drained gas directly to a LDC. The LDC is
    then  responsible for getting the gas to the end-user.

-   Producer/End-user: A  coal mine gas  producer identifies a particular customer for its gas,
    and enters into a direct contract with  the end-user, or consumer. In most cases, the end-
    user is then responsible for insuring that the gas is delivered, paying all transportation costs.

-   Marketer/LDC: This  is an arrangement whereby  the marketer purchases gas from one or
    more coal mine gas producers, and then  sells to the LDC. It is possible for two  or more
    mines to  act as one "marketing unit" to attain the economies of scale needed  to compete
    with large energy marketers. The marketing unit could then contract directly with LDCs.

-   Marketer/End-user: This arrangement is similar to  the Marketer/LDC arrangement, except
    that the marketer would sell gas directly to an end-user.   In the simplest case, such as the
    sale of gas to an independent power producer (IPP), the  gas  would  be transported directly
    from the producer to the end-user without accessing an LDC.  In the  case of gas sales to a
    typical consumer  (i.e., for residential or  commercial gas use), the  end-user would  be
    responsible for paying the tariffs associated with transportation and distribution (pipeline and
    LDC tariffs).
                       GATHERING SYSTEM
                       AND TRANSMISSION
                                                                  POWER PROJECT
                 Figure 1:  Types of Coal Mine Gas Sales Contracts

Current Opportunities for Coal Mine Gas Producers

There are four primary consequences  of Order 636 that are beneficial to the coal mine gas
industry:  1) expanded markets; 2) the ability to accommodate fluctuations in gas quantity and
quality; 3) expanded transportation access; and 4) a greater role for gas storage.  Following is a
discussion of each of these factors.

Expanded Markets. Producers now have numerous potential markets and opportunities to sell
gas. Most gassy coal mines are located near major gas consuming markets, and with the ability
to sell gas through marketers or directly to LDCs or end-users, coal mine gas producers can
now easily access these markets. The Southern Natural Gas Company's (SONAT's) activities in
the  Black  Warrior  Basin   of Alabama illustrate  how  this  company   is  involved   in
producer/marketer, marketer/LDC, and  marketer/end-user arrrangements and contracts. Figure
2 depicts SONAT's organization, which  comprises gas production, transmission, and marketing
companies.  SONAT Exploration, acting as a producer, drains methane from Drummond Coal's
Shoal  Creek Mine and  sells the gas to a market, in this case, SONAT Marketing. SONAT
Marketing, utilizing the intrastate pipeline system, transports the gas to a variety of markets, one
of which is an LDC.
    Gas Exploration And Production
     Natural Gas Transmission
     Energy Marketing
       Figure 2: SONAT's Gas Production, Transmission, and Marketing Companies

Another example of a producer/marketer arrangement is U.S.  Steel Mining's Pinnacle No. 50
Mine in West Virginia.  The Pinnacle No. 50 Mine sells its gas  to a marketing company, which
makes all transportation and final sales arrangements.  In contrast, a project that drains gas
from coal mines in  Illinois provides an example of a producer/end-user arrangement.  Pulse
Energy Systems has been draining methane from abandoned coal mines located in the eastern
margin of the Illinois Basin since 1979.  The gas is transported to an end-user that uses the gas
to generate electricity for sale to a public utility.

Accommodating Fluctuations   in  Gas  Quantity  and  Quality.  The  variable  production
characteristics of coal mine gas wells have traditionally presented difficulties for the natural gas
and pipeline industries. With conventional gas wells, gas flow may be curtailed at the discretion
of the operator. Coal  mines,  however, must continue to drain gas whenever the  mine  is
operating, with the exception of drainage wells drilled in advance of  mining. Conversely, gas
production from gob wells decreases during mining of relatively non-gassy areas, or  during a
longwall move.

In the  post-Order 636  environment, fluctuations in gas production and heating value are no
longer a  major obstacle to coal mine gas sales.  The mine can sell  its gas  to a marketer, who
has other sources of gas with  which to supply an end-user during times when the quantity or
quality of gas the  mine  produces may be low. The mine and  the  marketer negotiate their
contract with the understanding that the volume and heating value of the gas  that the mine
supplies will be variable.  Alternatively, the heating  value of the gas can be raised to pipeline
standards by  blending  it with higher heating  value gas (see section  on Blending  under
"Opportunities for Further Expanding Coal Mine Gas Project Development" below). For more
detailed information, the reader is directed to an EPA report entitled  Technical and Economic
Assessment of Potential to Upgrade Gob Gas to Pipeline Quality,  which evaluates the technical
feasibility and economics of blending.

Hedging is another opportunity available to coal mine gas producers with the passage  of Order
636. Hedging  helps guard against the problems associated with fluctuating production,  and
reduces exposure to risk  by shifting risk to those willing to accept  it  in  exchange for profit

opportunity. Hedging with gas futures contracts2 eliminates the risks to the producer associated
with fluctuating coal mine gas production, but at the same time limits the opportunity for future
profits should prices or production move favorably. Should coal mine gas production fall below a
negotiated contract amount, the operator would have the option of purchasing gas futures at a
price equal to or lower than the contract price. This insures delivery of the contract amount
without forcing the operator to pay any penalties or purchase gas on the spot market to fulfill the
contract, at a price that may be  greater than the contract price. The reader is directed to  A
Guide to Energy Hedging,  published by the  New  York Mercantile Exchange,  for  a more
thorough discussion of hedging  and futures.

Transportation Access. With  restructuring of the natural gas industry, an open access pipeline
network has evolved  that allows  more entities to become involved in gas supply purchasing.
Innovative developments in the  transportation sector have led to an increase in demand for new
services such as storage capacity and its  derivative services, such as balancing.

Balancing is defined as equalizing the volumes of gas withdrawn from a pipeline system with the
volumes  of gas injected into the  pipeline. A producer must notify the pipeline/marketer of the
amount of gas that they project  to produce on a daily, or more commonly, a monthly basis. This
is termed a nomination.  At the end of each period, the  actual amount produced is compared
with the nominated amount, and if the produced amount varies from the nominated amount, with
some pre-set tolerances  allowed,  then the nomination amount must be revised for the following
period. The operator can sell only the nominated amount at pre-arranged prices without paying
a penalty. This task may at first sound prohibitive from an administrative standpoint, but once
the mine better understands its  methane production characteristics, forecasting daily or monthly
production  should be  fairly straightforward. The  mine may  also elect to  change the way  it
produces gas, in order to make  balancing easier.

Transportation access is no longer a barrier to reaching secondary markets, however, the cost
of connecting to existing systems and/or increasing the capacity of this system will be a factor in
mine-specific situations.  A generally accepted rule-of-thumb value  for pipeline capital costs
ranges from $10,000 to $20,000 per  inch diameter of the pipe per mile installed, depending on
the complexity of the system.

Gas Storage. Gas storage has become  an  important commodity for the natural gas  industry
since the implementation of Order 636. Storage facilities store gas for use during periods of high
demand. The two most important features of a storage facility are capacity and deliverability.
Deliverability refers to the ease  with which gas can be removed  from the storage facility.
Before FERC 636, storage was limited mainly to:  1)  depleted petroleum reservoirs or  aquifers
with high capacity, yet low deliverability,  or 2) large surface facilities with higher deliverability,
but lower capacity. Such facilities were located near large market areas to meet peak demand.

The result  of unbundling gas storage and the gas markets from pipeline services is  that the
value of gas storage is driven only by the price of gas, and the relative value of storage in the
gas supply chain. Further, the creation of spot markets resulting from changes related to FERC
636 makes small, high deliverability storage facilities attractive. Storage facilities in salt mines,
which have high deliverability  due to their large amount of  void  space, are being  rapidly
developed.  However,  salt mines have low capacity.  Coal mines, like salt mines, could exhibit
high deliverability because of the large amount of void space.  Unlike salt mines, however, coal
 Futures contracts are firm commitments to take delivery of a specified quantity and quality of gas during a specific time in the
future at a pre-determined price.

mines also have additional capacity due to the adsorptive nature of the remaining coal.  The
EPA has prepared a report entitled Technical and Economic Assessment of Coalbed Methane
Storage in Abandoned Mine Workings, which at the time this document was printed, was in peer
review. This report discusses the advantages of using abandoned mines for gas storage as well
as the technical issues related to storing gas in  abandoned workings, and presents the results
of economic analyses conducted for a conceptual facility.

With the seasonal demand for gas, and the high costs  of pipeline capacity, gas storage is at a
premium. The potential use of nearby abandoned coal mines for storage is an additional option
for  mine operators that both increases the marketability for  coal  mine gas and provides a
valuable service to the gas market.

Key Factors Determining Coal Mine Gas Marketability

There are certain factors that determine the marketability of coal mine gas. They are:

•   The availability of an infrastructure that would allow immediate penetration into the existing
    market.  Often, there is an existing conventional oil and gas infrastructure in close proximity
    to  a coal  mining  district, meaning that the coal mine gas  producer would  not  have to
    transport drained  gas  long  distances  before tapping into  an existing  pipeline  system.
    Therefore, capital costs attributed to transportation could potentially be minimal.

•   The competitiveness of coal mine gas with conventional natural gas. For several reasons, it
    is possible that  coal mine gas production  would be sold at a reduced price.  The primary
    reason is that the heating value of coal mine gas may be  lower than conventional natural
    gas, since a percentage of the gas produced by the mine  will be gob gas.  Gob gas may
    contain significant percentages of air. Natural gas prices are based on heating  value, rather
    than volume. Coal mine gas may fail to meet pipeline specifications due to the presence of
    excessive  quantities of non-hydrocarbon gases (CO2, nitrogen, and oxygen)  and/or other
    contaminants. This may cause the marketer to discount the purchase price, as the marketer
    would  have to first enrich the coal mine gas, or blend the gas with conventional natural gas
    prior to injecting the gas into the pipeline system (this  process is discussed in greater detail
    later). The inconsistent delivery characteristics of coal mine gas is another factor that may
    require the mine to sell gas at a reduced price.

•   The possibility of  a local market that can  take  gas of almost any quality, as  long as it is
    combustible. In many cases, there are often industrial customers nearby that could  use gas
    of varying  quality, such as in an industrial coal-fired boiler. One or more boilers could  be
    converted to co-fire with coal mine gas. In cases where boilers are  already co-firing with
    natural gas, they could substitute coal mine gas for the natural gas.

Opportunities for Further Expanding Coal Mine Gas  Project Development

As described above, many different potential opportunities exist  for coal  mine gas projects. A
mine can simply sell the gas it drains to a marketer. Or, a group of mines can form a marketing
unit, selling  their  gas  to several  marketers  or  end-users,  maximizing  deliverability and
profitability. Similarly, a marketing group can purchase gas from several coal  mine gas  projects
and sell the gas to LDCs, other markets, and even to several end-users. Order 636 has created
many new opportunities for gas marketing, and allows  companies to be producers, marketers,
and LDCs at different  times, depending on the specific contractual arrangements or changes in
production or end user consumption.

Key issues that will determine coal mine gas project feasibility are:

       1)  whether the recovered gas can meet pipeline quality standards;
       2)  if unable to meet pipeline standards, whether upgrading is economical;
       3)  if the gas  ultimately meets pipeline standards,  whether the costs of production,
          processing,  compression,  transportation,   and   enrichment,  if  necessary,  are
          competitive with other gas sources; or
       4)  if  existing  pipelines would  be  willing  to  modify  gas  quality specifications to
          accommodate coal mine methane.

One factor unique to coal mine gas is that operators must determine which costs attributed to
gas drainage wells are viewed as sunken  costs associated with coal mining,  and which are
viewed as incremental costs charged against methane  production. This  in turn effects the
economic  constraints under which a gas supply contract may be negotiated.

There are  numerous coal mine gas sales or use options available to the mine, depending on the
quality and quantity of produced gas available as a result of mining operations. The options vary
depending on how involved  the mine  wants to be in the gas production operations. A brief
overview of the most likely options follows.

Enrichment of gob gas. If the  produced gas does not meet pipeline  quality standards, then
additional  enrichment costs must be considered. There are several different methods of  gas
enrichment, including pressure swing adsorption (PSA), cryogenics, selective adsorption,  and
spiking or blending. The problem is that gob gas can contain several gas contaminants,  and
most enrichment processes are designed to separate only one contaminant at a. time. Gob gas
enrichment has made great progress however, and a  full-scale gob  gas enrichment project is
now undergoing  startup in Pennsylvania. This project is integrated in  that it  removes several
contaminants (carbon dioxide, oxygen, and nitrogen) from the gas.

On-Site Use.  If enrichment costs are such that the  project becomes uneconomic, then a direct
market or  end-user must be identified for the lower quality gas. The most logical example would
be use of the gas on-site. An example of on-site use is Consol's Buchanan Mine, which uses a
small percentage of its recovered  methane in a thermal coal  dryer. Another option would be the
heating of  mine buildings and hot water.

Another opportunity for on-site use is  in power generation. Excess power generated on-site
could then be bundled with coal and/or gas and marketed as a "Btu" package (see "Bundling of
Gas and Power"  section below). There are several options available for power generation using
coal mine  gas, including 1C engines (which have been  commercially proven at  several mines)
and gas turbines. An added advantage of using coal  mine gas to fuel 1C engines and  gas
turbines is that the mine ventilation air can be used as combustion  air, increasing the overall
output  of the engines. This technology  has been  proven at the Appin Power Plant, New South
Wales, Australia. Fuel cells may represent a future  coal mine power generation option; the U.S.
Department of Energy is planning  a demonstration project using coal mine gas in fuel cells.

Formation of a Coal Mine Marketing Group. Although  FERC Order 636 does not specifically
affect on-site use projects, the post-Order 636  environment is ideal for undertaking this type of
project on  a larger scale. Several mines could join together and form a marketing unit, or a mine
gas producers association. The combined production from more than one mine would be more
easily marketable, without having  to sell the gas at a reduced price as discussed earlier, as the
combined  production from more than one mine would be less variable  in terms of quantity and

quality, enhancing its marketability. This marketing unit or association would then be able to
form  long-term alliances with either end-users or one or more marketing companies. One
advantage of this type of long-term alliance is that they could then market the gas to one or
more consumers, locking in a floor sales price for their gas that would be profitable to the mines.
Any gas produced in excess of that sold through long-term contracts could be sold by hedging
the gas on the spot market, maximizing additional  profits to the coal mine gas producer or
marketing group.

Another option is for mines to supply all of their low heating value gas to one or more end-users.
Potential end-users include independent power producers (see discussion under "Bundling"
below), or local industries that do not require pipeline quality gas (such as co-firing in a nearby
utility or industrial coal-fired boiler).  Members of a marketing group could also sell their low-
heating value gas to the member mine that has the greatest on-site fuel requirements.

A mine marketing group could also team with a smaller oil and gas producer. The producer
would have to develop the gas resource in conjunction with  mining operations; however, this
would enable the mines to focus on the business of mining and selling coal, while the producer
would be responsible  for the production  and sale  of the  gas. Advantages  of  this type  of
partnership are that the producer could already know the most profitable options for selling gas
in today's market, and  might already have  alliances with certain marketers or end-users.  The
recent partnership of Consol and MCN Energy Group exemplifies a variation on this type of
team.  MCN purchases coal mine gas production from several of Consol's  mines and transports
the gas via an existing integrated natural gas transportation/distribution system to the Midwest
market, where gas is sold for a premium.

Blending Of Lower Heating  Value Gas with High Heating Value Gas. Another option available to
a coal mine gas marketing  group is to identify  a marketer capable of taking the lower-heating
value coal mine gas and blending it with  high heating value gas, or with gas drained from pre-
mine  drainage boreholes. This scenario would work only if the ratio of the lower heating value
gas to the pipeline gas  is very small and the resultant product still meets pipeline specifications.
This would have a minimal effect on the gas  quality in the system, while enabling the lower-
quality gas to become saleable on the market. If the marketing unit were able to perform its own
blending, resulting in gas that meets pipeline standards, then it would receive market price for
the gas.

Bundling of Gas and Power. With the imminent implementation of FERC Order 888, which is the
catalyst for electric power restructuring, electricity and gas supply will compete head-to-head for
market  shares. Alternatively, the  development of companies structured to  supply  energy,
regardless  of its form,  could become the next  major revolutionary event  in the energy supply
market. Already, there are marketing groups that offer  "total  Btu packages", meaning that they
can offer services that would meet all of a consumer's energy needs, whether it be gas, heating
oil or  electricity, as well as  energy and environmental management services. One example of
this type of company is The Eastern Group, based out of Virginia, which specializes in providing
Total Energy Solutions™.  They have combined their  strengths  as a supplier of natural gas
(including coabed methane), electric power, and alternate fuels with knowledge-based energy
management services, such as risk management strategies and energy conservation programs.
Many pipeline and marketing companies are merging with  independent power producers  in
order to achieve larger market penetration.

Marketing of Greenhouse Gas Offset Credits. If domestic and international emissions trading
becomes a reality, bundling of these credits into the economics of most coal mine gas projects

make them very attractive to potential investors. The value of these credits alone can attract
many companies that may enter the  market for offset credits,  and  otherwise  might  not be
attracted to coal mine gas projects.

As an example, Niagara Mohawk Power Corp. of Syracuse, N.Y.  recently announced that they
have negotiated  an agreement with Suncor Energy Inc., a Canadian oil and gas company, to
sell them 100,000 metric tons of greenhouse  gas emission offset  credits, with an option to sell
up to an additional 10 million tons of reductions over a 10-year period. This agreement has  a
potential value of $6 million dollars US,  and will  help Suncor achieve  its voluntary emission
reduction targets while providing Niagara Mohawk with additional  funding for new projects that
will further reduce  greenhouse gas emissions.  These companies, as well as both the United
States and Canadian governments, have stated that it is their hope that this agreement will be
the first  step toward creating a global market and an international trading system for greenhouse
gas emissions reductions.

Marketing of Environmental Benefits.  Credits associated with SO2 emissions allowances and
avoided  penalties  from NOX emissions  are now becoming an integral component  of the
economics of energy projects. Substituting or  co-firing coal mine methane with coal in industrial
and utility boilers and kilns in most cases reduces the SO2 and NOX emissions, adding value to
projects. Other economic benefits include reduced opacity, improved ash quality, and improved
boiler rating.

Gas Storage in Abandoned Mines. One other option is gas storage in abandoned mines. Today,
the Leyden Mine in Colorado is the only undergorund coal mine being used for gas storage.
Underground abandoned coal mine workings are potentially excellent gas storage sites under
suitable geologic and hydrologic conditions. Because they have a large amount of void space,
abandoned coal  mines have the high  deliverability of abandoned salt mines, with the added
advantage of high  gas capacity due to the unique adsorptive characteristics of the unmined

Analysts predict that gas storage capacity in the US will increase  by at least 20 percent by the
year 2000 over pre-FERC 636 levels. The continued development of  high deliverability gas
storage  in the US  makes methane recovery  from mining more attractive. Methane from coal
mining can be stored for sale on the spot market, or stored by contract for peak shaving  by a
consumer. The option of cost-competitive  storage affords a potential methane recovery program
the benefits of inventorying recovered gas so that the market advantages are realized.

For active mines that own or have access to abandoned underground coal mine workings, this
may provide an alternative to leasing or  incurring the costs of storage space. Because many
abandoned mines  have large  potential capacity,  they could  store coal mine gas as well as
conventional  natural gas  for  sale at peak  demand times,  a strategy which  enables gas
producers to significantly increase profits in today's marketplace.

How To Identify Marketing Opportunities

Prior to  the implementation of FERC 636, if an producer desired  to sell gas production, it had
only to  contact the local pipeline  company and negotiate a contract. Today,  because of the
complexity of the market, identifying the most  appropriate gas marketing arrangement for a coal
mine can be more difficult.  As most  coal  mines do not have experience in marketing gas,  a
recommended first step is to contact the local pipeline companies to determine what marketing
companies are operating in the area. Since most of the gassy  coal mines are in relatively close

proximity to conventional oil and gas fields, a mine could also contact one or more of the local
producers  of conventional natural gas or coalbed methane. At the  same  time, a mine can
contact a local or regional oil and gas association (Appendix A). These associations cannot
recommend specific marketing groups, but would be able to  put the mine in touch with one or
more of their members (such as a gas producer) that may offer advice. In addition, some oil and
gas associations offer an association directory for sale, which the mine could purchase.


Coal mine gas producers have numerous potential markets and opportunities to sell gas, or use
it on-site. Among the uses for coal mine gas are:

       •   injection into pipelines (the gas  may first require enrichment or blending) for a wide
           variety of end uses;
       •   direct on-site use of methane, for coal drying, space or hot water heating;
       •   on-site power generation, with possible off-site sale of excess electricity; and
       •   substitution or co-firing with coal in industrial  and utility boilers.

EPA has prepared a series of Technical Options Case Studies on these and other uses for coal
mine methane.

There are many options for marketing coal mine gas, and various approaches that can increase
gas sales. These include:

       •  formation of a coal mine gas marketing group to pool gas resources for sale;
       •   bundling of coal mine gas with electricity, fuel  oil,  and/or  energy management
          services to provide consumers with a "total Btu"  package;
       •   marketing of greenhouse gas offset credits and/or other environmental benefits; and
       •   using abandoned coal mines to store coal mine gas for sale during peak demand.

It is  clear  that  Order 636 has created many opportunities for the coal mine  gas producer.
Companies interested in selling coal mine gas should research all potential marketing options in
order to choose the approach that best suits a mine  and/or operator's specific situation and
needs. The ultimate success of a coal mine gas project  will depend on the ability  of the operator
to best utilize the  options available  in today's market, in  order to secure the most favorable
pricing terms and conditions.


                                 APPENDIX A
                       LIST OF OIL & GAS ASSOCIATIONS

Coalbed Methane Association of Alabama        Independent Oil & Gas Association of West
Dennis Lathem, Executive Director              Virginia
1855 Data Drive, Suite 150                     Mike Herron, Executive Director
Birmingham, AL 35226                        410 Washington Street East, Suite 301
(205) 733-8087                               Charleston, WV 25301-1522
(205) 985-0042 fax                            (304) 344-9867
                                            (304) 344-5836 fax
Colorado Oil & Gas Association
Greg Schnacke, Executive Director
1776 Lincoln St., Ste 1008
Denver, CO 80203
(303) 861-0373 fax

Kentucky Oil & Gas Association
John Gabbard, Executive Director
3520 New Hartford Road, Suite 403
Owensboro, KY 42303-1782
(502) 683-5347 fax

Pennsylvania Oil & Gas Association
Steve Rhoads, Executive Director
106 Locust Grove Rd.
Bainbridge. PA 17502

Independent Oil & Gas Association of
Lou D'Amico, Executive Director
234 State Street
Harrisburg, PA 17101

Utah Petroleum Association
Lee Peacock,  Executive Director
311 S. State, Suite 320
Salt Lake City, Utah 84111
(801) 363-5757
(801) 322-5002 fax

Virginia Oil & Gas Association
Laura M.  Batemen, President
P.O. Box  35674
Richmond, VA 23235-0674
(804) 323-5357


To obtain additional information about coal mine methane project opportunities, and for copies
of reports referenced, contact:
Coalbed Methane Outreach Program
U.S. EPA (6202J)
401 M Street, SW (6202J)
Washington, DC  20460 USA
      (202) 564-9468 or (202) 564-9481
Fax:  (202) 565-2077
e-mail: fernandez.roger@epamail.epa.gov