430R98023
WHITE PAPER:
The Impacts of FERC Order 636 on
Coal Mine Gas Project Development
March 27,1998
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ACKNOWLEDGMENT
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.
DISCLAIMER
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.
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PREFACE
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.
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THE IMPACTS OF FERC ORDER 636 ON
COAL MINE GAS PROJECT DEVELOPMENT
Introduction
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
gas".
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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
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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
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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).
COAL MINE METHANE
PRODUCERS
Producer/LDC
Contract
GATHERING SYSTEM
AND TRANSMISSION
PIPELINES
Producer/End-user
Contract
Marketer/End-User
Contract
DISTRIBUTED
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.
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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.
SONAT
Gas Exploration And Production
SONAT EXPLORATION COMPANY
Natural Gas Transmission
SOUTHERN NATURAL GAS COMPANY
Energy Marketing
SONAT MARKETING COMPANY
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
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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.
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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.
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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
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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
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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
coal.
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
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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.
Summary
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.
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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)861-0362
(303) 861-0373 fax
Kentucky Oil & Gas Association
John Gabbard, Executive Director
3520 New Hartford Road, Suite 403
Owensboro, KY 42303-1782
(502)226-1955
(502) 683-5347 fax
Pennsylvania Oil & Gas Association
Steve Rhoads, Executive Director
106 Locust Grove Rd.
Bainbridge. PA 17502
(717)426-0067
Independent Oil & Gas Association of
Pennsylvania
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
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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
schultz.karl@epamail.epa.gov
http://www.epa.gov/coalbed
COAL
METHANE
OUTREACH
PROGRAM
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