WHITE PAPER:
               March 15, 1999



This  draft  was prepared under Work Assignments 3-1 and 4-2 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.


Avoided Costs - The  costs  that an  electric utility avoids  by purchasing  power from  an
independent producer rather than generating and delivering power itself, purchasing power from
another source, or constructing new power plants.

Base Load Units - Generating units which run nearly continuously to serve electricity demand
that remains steady.

Bilateral Transaction - A direct-purchase transaction between a buyer and a seller.

British Thermal Unit (Btu) - The amount  of energy necessary to raise the temperature of one
pound of water one degree Fahrenheit.

Btu Substitution - Substituting different fuels such as coal, gas, wind,  etc. depending on the
market, to generate electricity.

Demand - The rate at which electric energy or natural gas is  delivered to or by a system at a
given instant or averaged over a designated period, usually expressed in kilowatts or megawatts
(electricity) or cubic feet per second (gas).

Dispatchability - The ability of a generating unit to respond to a signal to increase or decrease
its generating capacity or be brought on line or shut down.

Distributed  Generation - Power produced away from a  central station designed to meet the
requirements of that load using on-site small scale generating  equipment such  as gas turbines,
reciprocating engines, fuel cells, and micro-turbines.

Efficiency - A percentage indicating the  available Btu input that is converted to useful purposes.

Exempt Wholesale Generator (EWG) - A class of generators  defined by the Energy Policy Act
of 1992  that includes the owners  and/or operators of facilities used to  generate electricity
exclusively for the wholesale power market or generation capacity that is leased to utilities.

Federal  Energy Regulatory Commission (FERC) - A quasi-independent regulatory agency
within the Department of Energy having jurisdiction over  interstate electricity sales, wholesale
electric  rates,  hydroelectric licensing,  natural gas transmission and related pipeline rates and

Grid - Network of electric or gas transmission and distribution lines along which  energy moves.

Hedging - To offset a position with the  intent of managing risk.  The process of protecting the
long-term value of an investment with an offsetting short-term position in a related investment.

Holding Company - A parent company set up to hold shares in other companies.

Independent Power Producer (IPP) -  Private entrepreneurs  who develop, own,  and operate
electric power plants fueled by a variety of energy sources.

Independent System Operator (ISO) - An independent system  operator handles, in a non-
discriminatory manner, all the transmission assets of a fixed geographic area granted through
the authority of multiple utilities.

Merchant Plant - Power  plants that are  outside electric  utility  rate bases  and are without
purchase power agreements. Merchant power plants are built to sell power  in a deregulated
wholesale power market without long-term power purchase agreements.

North American Electric Reliability Council (NERC) - An electric utility council  formed in
1968 to promote the reliability and adequacy of bulk power supply in the electric utility systems
of North America.

Peak Units - Generating units which run only when demand is  highest such as hot summer
afternoons on workdays. Peaking units may operate less than 5% of the time.

Qualifying Facilities (QFs) - A designation created  by the 1978  Public Utility Regulatory
Policies Act for  non-utility power producers  that meet certain operating,  efficiency, and fuel
standards set by the Federal Energy Regulatory Commission.  To receive  status as a QF,  the
facility must produce electric energy and "another form of  useful thermal  energy through  the
sequential use of energy".  QFs may be cogeneration or combined  heat and power systems
using renewable energy sources.

Real-time metering - Monitoring electricity use in 15 or 30 minute increments to coordinate with
hourly price fluctuations in electricity  sales.

Retail Wheeling - The ability of end-use customers to purchase electricity generated from
anyone other than the local electric utility facilitated by movement of such power over the local
utility's transmission or distribution lines.

Spot Market - Commodity transactions in  which the transaction commencement is near term
(usually within 10 days) and the contract duration is relatively short (usually within 30 days).

Stranded Costs - An investment with a cost recovery that was initially approved by regulatory
action that  subsequent  regulatory  action or market  forces  has  rendered  not  practically
recoverable.   Electric utilities  are  currently recovering  stranded  costs through  their  rate

Time-of-Use Rates  or Pricing  - A rate design imposing  charges during periods of the day
when relatively higher generation and transmission costs are incurred to meet  higher than peak
demands  of electricity.  Prices could be based on 30 minute intervals, or less, depending on
distribution service.


Electric industry  restructuring  has brought  about a  transitional market  environment  where
utilities, power marketers,  and large  industrial customers are developing  strategies to gain a
competitive edge for the future. Restructuring is creating new opportunities for coal mine gas1
projects, particularly for those coal mines and energy developers who are innovative and  are
willing to form strategic  alliances.  The  purpose  of  this  paper is to  describe how project
developers  may be able to take advantage of these opportunities.  The potential for profitable
coal mine  methane projects appears promising, considering the various  options available to
energy developers.

The extent to which  electric industry restructuring encourages the construction of new gas-
fueled power generation, and the extent to which coal production increases to meet demand,
will have a significant impact on opportunities for coal mine gas use in  the future. This, along
with the continued evolution of coal mine gas drainage technologies, will determine  the degree
to which coal mines can benefit from new market opportunities.

Several of the benefits of coal mine gas use include:

       1)  ability to generate electricity for on-site use at a coal mine and/or sale of electricity to
           the local grid;
       2)  lower  NOX and SO2 emissions for utility companies through cofiring;
       3)  lower  greenhouse gas emissions from coal mines; and
       4)  bundling of coal, gas, electricity,  SO2, and/or  NOX emission  credits to maximize
           opportunities in today's changing energy markets.

Section  II of  this  paper reviews the  history of electric  industry restructuring  to  provide a
background for readers who may not be familiar with its evolution.  Readers with  a thorough
knowledge of this background may wish to move directly to Section III, which discusses today's
electric industry and the potential role of coal mine gas therein.

Emergence of Electric Utilities

Independent power generators and distributors, competing for customers,  began supplying
electricity to the public in the early  part of this century. The electric industry was divided into
three segments, generation, transmission, and distribution, all of which  were controlled by a
single investor-owned utility.   In  the 1920s,  public enthusiasm  for the growth of municipal
electric systems resulted in the formation of  many large power holding companies, and by the
next decade, a  handful of large companies controlled the majority of the  marketplace.  Private
investor funds fueled the creation of early electric power production and distribution facilities.
1 The term "coal mine methane" refers to the 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 consituents 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".


This tradition has continued, as investor-owned utilities provide over 75% of all power generated
in  the U.S. (Edison Electric Institute,  1998).   In  response to market  abuses  by  holding
companies, which resulted in increased costs paid by consumers, Congress passed the Public
Utilities Holding Company Act (PUHCA) in 1935 to regulate finances and corporate structure of
holding  companies  that controlled  public utility  companies.  However,  the  electric industry
continued to  evolve in a  monopolistic  environment where  utility  companies, assigned  to
designated geographic areas, produced power at progressively lower rates due to increases in
economies of scale, technological improvements, and only moderate increases in fuel  prices.
By the 1960s, the electric industry  developed regional transmission networks,  which allowed
power plants to be located up to 1,000 miles from consumers. Regulation of the industry proved
to  be beneficial  to  both the electric companies and  their  customers  by producing low-cost
electricity at a reasonable profit.
Federal Initiatives

During the 1970s, a sharp rise in energy prices due to the oil crises of 1973 and 1979 spurred
changes in U.S. energy policy.  Because of high fuel costs, rapid inflation,  high interest rates,
and the need for greater energy security, regulators began to shift their perceptions of traditional
rate-based regulation of utilities and as a result, they attempted to encourage competition within
the electricity generation market. Three milestones that marked this regulatory shift were the
enactment of the Public Utility Regulatory Policies Act of 1978 (PURPA), the Energy Policy Act
of 1992 (EPAct), and most recently, the  issuance of Federal Energy Regulatory Commission
(FERC) Orders 888 and 889 in 1996.

PURPA required utilities to increase energy efficiency and conservation and  purchase electricity
from certain cogeneration and small power production facilities (termed qualifying facilities, or
QFs) that were exempt from the requirements of PUHCA and most state laws governing utility
rates.  PURPA defined these QFs as non-utility, renewable power generators and cogenerators,
and required electric utilities to purchase electricity from QFs at rates not to exceed the avoided
energy costs.  As a result, the number of QFs in the U.S. grew to 1,200 by 1993 (Mauel, 1996).
Prompted by  the success of QFs,  other independent power producers (IPPs)  that were
regulated separately from QFs  began to  build  new capacity (primarily with  smaller gas-fired
plants) to compete  in bulk power  markets.   However,  ownership restrictions  under PUHCA
hindered the development of IPPs.

The passage of EPAct set the stage for competition in the electric utility industry.  Its thrust was
to promote  greater  competition in  bulk power markets  by eliminating some of the obstacles
facing IPPs such as the  alternative energy fuel  requirements.   EPAct revised  PUHCA by
creating a new class of exempt wholesale generators (EWGs) that could be owned by utilities or
holding companies.  Furthermore, EPAct  expanded  FERC's authority  to  approve  power
producer applications for non-discriminatory transmission access to other utilities' power lines.
 Issuance of FERC Orders 888 and 889

 An increasing number of IPPs, EWGs, and power marketers were created during the mid-1990s
 due to low natural gas prices and the ability to obtain non-discriminatory transmission access by
 FERC.  The issuance of FERC Orders 888 and 889 on April 24, 1996 opened wholesale power
 sales to competition by requiring public utilities that own, control, or operate transmission lines
 to  offer others the same  transmission services they provide themselves, under comparable
 terms and conditions.

FERC Order  888  also  allows public  utilities  and transmitting utilities to recover  100% of
"stranded costs". These are expenditures that investor-owned utilities  have invested in power
plants (most notably nuclear power plants) and are still paying off, and may not recover in a
restructured market.  Currently, individual state utility commissions and courts are grappling with
stranded costs decisions that shape the future of restructuring.  While  utilities lobby to recover
stranded costs, citizen action  groups have been fighting to assure that decisions are fair to

The second rule, FERC  Order 889, requires public utilities to implement a Standard of Conduct
and develop  an  Open Access  Same-time  Information  System (OASIS) to  electronically
communicate  information  about  their  transmission  systems  and  services  to all  potential
customers at  the same  time.  This ensures that transmission owners will not have  an unfair
competitive advantage in selling power as a result of inside information regarding transmission

The overall impact of FERC Orders 888 and 889, as well as legislation that created PURPA and
the Energy Policy Act of 1992, has been to create an industry in which generation, transmission
and distribution are unbundled.   Because the  vertically  integrated utilities  have traditionally
bundled the price of services, restructuring requires utilities to demonstrate that each function
remains competitive.  Most industry analysts agree that unbundling services,  coupled with
opening the utilities' transmission lines, facilitates open competition.
Ongoing Federal Actions

From 1996 through 1998 during the 104th and 105th Congresses, several members of the U.S.
Congress  introduced legislative initiatives that were aimed  at protecting consumers  by giving
them the  right to choose among  competitive providers of electricity.  However,  no Federal
legislation has been passed to date that applies directly to electric industry restructuring. The
House  and Senate are still  debating several bills that cover a  wide range of restructuring
actions.  Major issues being debated include energy  efficiency and conservation, the use of
renewable sources  of energy, specific dates for  mandated customer choice, FERC's  authority,
and the repeal of PUHCA.  It will be up to the 106th Congress to address these proposals.

The Clinton  Administration  proposed a  bill to  Congress on  June 27,  1998  called  the
Comprehensive  Electricity  Competition  Act  (CECA).   The bill  includes  a flexible  mandate
requiring full retail competition by 2003, but allows states to opt out of retail competition if FERC
determines that  deregulation would  have a negative  impact on a class  of customers.  Also
included is a  requirement that power providers  produce at  least 5.5% of their electricity from
renewable sources  (excluding hydropower) by 2009. The proposed bill seeks to fund $3 billion
to promote consumer education and  energy conservation and efficiency  programs for states.
Finally,  CECA would  allow  U.S.  EPA  to impose  a  NOX  allowance  cap  on  states whose
emissions are transported via air currents to other states, thereby making  it difficult  for those
states to attain ambient air quality standards.
  Citizens of California (which was the first state to allow retail competition in March 1998) and Massachusetts gathered enough
signatures to place initiatives on their November 1998 ballots to repeal recently implemented state restructuring laws. The
California petition argued that the $28 billion bailout of California utilities through a transmission surcharge  impeded fair retail
competition.   However, voters  in both states overwhelmingly rejected the  ballot initiatives, thereby endorsing the existing
restructuring laws. Nevertheless, consumer groups  nationwide are vowing to continue fighting the utilities' recovery of stranded
costs from ratepayers in other states.

Current State Initiatives

While power generation at the wholesale level is open to competition, the U.S. Congress left it
up to the individual states to implement their own rights to retail competition. State legislatures
must first pass legislation that authorizes deregulation so that the State regulatory commissions
can then implement restructuring plans.   In March 1998 California led the way by implementing
restructuring legislation that requires retail competition, and most states have  at least begun
addressing  electric industry changes.   As of January  1999, 18 states3  (including the five
Appalachian coal mining states) had mandated retail restructuring by passing legislation.

Over the next two years, policies and legislation relating to deregulation will have major impacts
on the long-term development of restructuring. Appendix A contains a partial list of public utility
commissions that can  provide current  restructuring information  for  the 11 gassy coal mine

Today's electric power industry is characterized by traditional, large, investor-owned and public
utilities as well as a smaller, but growing, class of independent power producers that are taking
advantage of  changes in the industry.  The electric industry is becoming  increasingly market-
driven, and innovative power  producers can profit from these  changes.  In particular,  the
emerging market-based  system provides new opportunities for using coal mine gas within the
power sector  such as on-site electricity generation, peak shaving, and electricity sales to the
grid.  The impact of electric industry restructuring on new gas-fired power  plants depends on a
number of factors,  including the speed and success of the transition to a competitive market,
gas prices, electricity demand, access to the grid,  and how states calculate and treat  stranded
costs for utilities.  Although FERC 888  lays the groundwork  for accelerated competition,
restructuring  may  proceed  slower than  expected  due to  a  reluctance  to  legislate retail
competition at the state level and delays in court decisions addressing stranded cost recovery.

Recovered  coal mine gas is an  energy source available  for  many different  applications.
Potential utilization methods include pipeline injection, direct use on-site in prep plants or mine
vehicles, cofiring in boilers, or electricity generation through  the use of internal combustion
engines or gas turbines.  The opportunities that arise for the sale, transportation, and delivery of
electricity generated from coal mine gas depend heavily on the direction in which market forces
will drive new  investment  in power generation.  New  technological  advances in  electricity
production should produce market niches for gas-fired generating units even in areas where
electric capacity is already built and electricity prices are low.

Electricity Demand

Electricity consumption in the U.S. has been, and will continue to be, closely tied to growth in
the nation's economy. Current projections by the U.S. DOE's Energy Information Administration
(EIA) indicate that overall electricity demand will grow by 1.3-1.5% per year through 2020 (EIA
1998a).  Both the coal and gas industries will benefit considerably from this increased demand
since over  90% of new generation capacity  is expected to  be either coal or gas-fired (Gas
Research Institute, 1997a). This expected increase in demand would provide  opportunities for
 3 The 18 states are Arizona, California, Connecticut, Illinois, Maine, Maryland, Massachusetts, Michigan, Montana, Nevada, New
 Hampshire, New Jersey, New York, Oklahoma, Pennsylvania, Rhode Island, Vermont, and Virginia.


new coal and  gas-fired  generating  capacity, with the potential for  300 GW of additional
One reason for the increased  need
for new coal and gas-fired capacity
is that no new nuclear power plants
are planned over the next 20 years,
while during the same time, 65 units
totaling 52 GW are scheduled  to be
retired  (EIA  1998a).  As a result,
nuclear  powered  generation  will
decline from 22% (GRI, 1997a)  of
net  U.S.  electricity  generation  to
about 9% (Figure 1).   In  addition,
hydroelectric  power   contributes
nearly   11%  of  U.S.  electrical
generation  today, but   the  lack  of
available sites limits  any  potential
increase in hydropower generation.
igure 1 - Projected Energy Sources for
Electric Utilities


\ \

v 1

\ ^

.-. Hit











1995 2000 2005 2010 2015 2020
1 Hydro

m Nuclear

• Petroleum

D Natural Gas

3 Coal
According to the EIA (1998a), gas-fired electricity generation is expected to increase from 9% to
24% of the total net generation by the year 2020 (Figure 1). Coal will remain the primary fuel for
electricity generation even though its market share will  decrease slightly by the year 2020.
Moreover, coal consumption is expected to rise in the  near-term as electric restructuring leads
to increased utilization of existing plants.

Increases in peak demand are not expected to keep pace with net increases in total electricity
demand.  When consumers face seasonal or diurnal  variations  in electricity prices, they are
likely to respond by  reducing their demand in high cost periods  and increasing it in low cost
periods (EIA, 1997). Studies indicate that the average annual price of electricity will  be relatively
low, with a moderate consumer response to time-of-use pricing, as compared with no time-of-
use pricing.  In view of this, time-of-use prices are  expected to gain acceptance under
Market Structure

As restructuring  continues,  decisions  concerning which  electric  generating systems are
dispatched will be  based on a combination of wholesale contracts and short-term spot market
bids made by generating companies.  These transactions will take place in  regional  Power
Exchanges, where electricity futures are traded. Contracts between generating  companies and
those who purchase the power will be governed by inter-utility agreements that are independent
of generating companies. On a regional basis, Independent System Operators (ISOs) ensure
suppliers  have equal access to transmission lines.   Ultimately, distribution  companies are
responsible for procuring an  adequate  electricity supply for  their  end-users, and thus will
generally  rely on base load units even though  it could be cheaper at times to purchase power
from spot market bids.

While  the specifics  are  uncertain,  most
analysts predict  that electric restructuring
will take place at a varying pace depending
on the state, and will be generally,  but not
completely, successful in creating an open
market.  This is because utility  regulatory
commissions  and legislatures  in  all  50
states are currently in different stages of the
implementation process.  Some  states are
still studying  the  idea informally,  others are
drafting   restructuring    legislation,   and
several  implemented retail  competition  in
1998.  Through activities of these regulators
and   lawmakers,   the   implications   of
restructuring  are  becoming more evident:
         Electricity Market Participants

Electricity Producers: Generate electricity and sell it
wholesale to energy brokers and power marketers at
competitive rates.
The Power Exchange:  The spot market for  the
buying and selling of energy within a region.
Energy Brokers: Buy energy from energy suppliers
and then re-market it to power marketers or retailers.
Power  Marketers:  Buy  energy wholesale  from
energy producers or brokers for resale to retailers, or
directly to consumers.
Distribution Companies: Distribute electricity and/or
gas to consumers.
       there will be considerable variation from state to state;
       the transmission and distribution sectors will still  be regulated but are likely to be
       subjected to performance-based rates;
       utilities will get out of existing high cost electricity purchase and fuel contracts;
       wholesale and retail electricity prices will vary widely based on time-of-day, time of year,
       and region;
       electric utility profits will drive new investment in power generation;
       resolution of stranded cost recovery mechanisms will remain controversial and vary from
       state to state;
       power marketers could market  green electricity produced from  renewable  or  clean
       energy fuels; and
       power produced from  coal mine gas  can be marketed to consumers  as  part  of an
       environmentally friendly energy portfolio.
 Restructured Marketplace in States with Coal Mine Gas Resources

 As of January 1, 1999, three states have opened their retail electricity markets to competition:
 California, Massachusetts and Rhode Island. In addition, Pennsylvania (a state with coal mine
 gas reserves) has implemented the nation's largest pilot program.   The strategies that coal
 mines undertake for the sale, transportation, and delivery of electricity generated from coal mine
 gas depend heavily on the rate at which restructuring occurs in that state.  The North American
 Electricity Reliability Council  divides the United  States into power market regions.  There are
 consumers in several of these regions that could directly benefit from power generated from
 increased coal  mine gas  recovery and use, however regulatory  and legislative activity varies
 greatly between the states containing gassy coal mines due to existing market parameters.

 With a restructured market in place, the proximity of high-demand and higher-priced electricity
 markets to coal mine gas sources is a key factor in the potential profitability of a coal mine's
 production and sale of power fueled by recovered coal mine gas. The principle coal mine
 regions with  large coal mine gas resources are located in the north  and central Appalachian,
 central Illinois,  Alabama,  and  south-central Rocky  Mountain regions.   Energy markets  near
 these regions vary greatly (Figure 2).

                               r-pbwDEfi RIVER
                               v BASIN
                     , BASIN
             POWER MARKET REGIONS                        >S8«i GASSY COALMINE REGIONS
        Figure 2 - Potentially Profitable Power Markets Located Near Gassy Coal Mines

Following  is  a restructuring and market  summary as of January  1,  1999  for the regions
containing  the greatest coal  mine  methane resources.   Appendix  A  contains  a list of
organizations  where  more  up-to-date information  on state restructuring  activities can  be

Northern Appalachian Region
Pennsylvania began its pilot program in July 1998,  and within four months nearly two million
customers  signed up.  All  customers received a  minimum 8% rate reduction  and began
receiving  power  from  the  supplier  of  their choice  in  January 1999.   Additionally, the
Pennsylvania  Public  Utility  Commission  has defined  coal  mine methane as a  renewable
resource, thus opening the renewable energy market to coal  mine gas projects (which CECA
encourages).  In  Ohio, representatives from the five major investor-owned utilities have  been
developing a consensus framework for a restructuring  proposal. The proposal includes  retail
choice for all consumers by January 2001.   Two of the  nation's energy markets yielding the
highest revenues for electricity sales are the Northeast  and Mid-Atlantic  regions.  Northern
Appalachian  coal  mining regions in  Pennsylvania and  Ohio could access  these markets,
although constraints exist via current transmission systems.

Central Appalachian Region
The West Virginia Public Service Commission has designed a deregulation plan for its state and
presented it to the legislature in January  1999.  In Virginia, the State legislature has passed a
bill  establishing a Regional Power Exchange and an ISO,  as well as competition by 2002. The
Mid-Atlantic Area Council (MAAC)  region  includes  Pennsylvania, New  Jersey,  Maryland,
Delaware  and Washington D.C.   MAAC  relies heavily on coal generation from  the central
Appalachian states and unfortunately for  new generation, the line capacity tends to be fully
loaded. Due to high operating  and maintenance charges, New Jersey consumers paid the
highest rates in the region.  Central Appalachian coal mines producing electricity could begin
selling electricity to this high-demand region once increased line capacity is installed.

Midwest Region
The state of Illinois  has enacted a restructuring  bill that  1)  required a  15% rate reduction
beginning August 1998, 2) allows some commercial and  industrial retail choice by  October
1999, and 3) allows residential customers full choice for their generation supplier by mid-year of
2002.  Illinois  introduced additional legislation to add environmental provisions to the current
law.  In Indiana, the State legislature defeated a bill to allow  retail access by 2004.   Indiana
plans to revisit restructuring issues in 1999.

Mid-America  Interconnected  Network   (MAIN)  includes  Illinois,   Wisconsin,  and   northern
Michigan. The regions are heavily dominated by low cost coal generation due to their proximity
to coal producing areas of the Illinois Basin.  With high  demand, however, electricity rates in
Illinois are above the national average.  Again, coal mines could sell coal  mine gas-fueled
electricity competitively to this nearby high priced power region.

Rocky Mountain Region
Colorado has failed to pass bills allowing retail competition. However, the legislature passed a
bill to study whether retail competition  will  benefit the  state's customers and will report its
findings by November 1999. In Utah, the State voted to recommend  no restructuring in  1998. A
task force  issued a  draft report favoring restructuring legislation for 1999 using a "go slow"

Southeast Region
The state of Alabama has appointed a task force that is preparing a report on restructuring.
Some of the largest coal mine gas recovery systems in the nation are located in Alabama's
Black Warrior  Basin, and are currently used for gas pipeline injection.  Alabama residents pay
some of the lowest  electricity  rates in the nation, but Florida consumers pay above average
prices.   External  transmission lines to Florida's  market are well interconnected  with  the
Southeastern  Regional Council, which operates with little constraint. This situation presents a
potential opportunity for Black Warrior Basin coal mines to generate electricity for sale to  the
Florida market.
         Figure 3 - Energy Prices for
            Electricity Generation
 Delivered Cost of Fuel

 According  to  EIA (1998b), gas prices
 should increase by 50% (from $2/mmBtu
 to $3/mmBtu) by the year 2015 (Figure 3),
 mostly   due  to  increased   wellhead
 production  costs.  The  Gas  Research
 Institute  predicts  a   similar  gas  price
 increase over the same time period. Coal
 prices have decreased  over  the  past
 decade and U.S. DOE predicts they will
 follow that trend in the future. Natural  gas
 prices are  also subject to more  seasonal
 fluctuation than coal.

 Higher gas  prices mean coal  mine  gas
 projects could become more economically
 viable.  Medium-quality coal mine gas is


3 $2.50 -
| $2.00

| $1.50

1 $1.00


- Natural Gas
       1995 2000 2005  2010  2015 2020

an attractive supplement/alternative fuel for power generation, particularly in light of the fact that
it does not require upgrading to pipeline quality.  In addition, most of the new merchant power
plants  currently planned or  under construction employ  highly efficient  gas-fueled  power
generation technologies that could use this medium quality gas.

Delivered fuel costs are a significant part of the total cost of generating electricity from a fossil-
fueled  generating  unit.   Incremental fuel costs include: the cost of fuel at the source (mine,
wellhead, or  refinery), transportation and handling costs, off-site storage costs, and broker or
marketer  premiums.  The delivered fuel cost,  which  is a major  component of the cost of
producing a kilowatt-hour of electricity,  generally  determines whether or not a generating unit is
economically competitive.  In the case  of coal mine gas, the unit cost of gas used on-site or to
fuel nearby gas-fired electric utilities could be significantly lower than conventional natural gas
because of reduced transmission and  distribution costs.  In view of this, siting new merchant
power plants adjacent  to coal  mines with this low-cost  fuel supply provides an  excellent
opportunity for the power plant to compete in a restructured market.  Table 1 in Appendix A lists
the potential for gas supplies from 31 of the gassiest coal mines in the U.S.

The Increased Role of  Gas-Fired Electric Generation Technologies

Several improved  gas-fired technologies are now affecting  the structure of electric generating
markets, and may provide opportunities for coal mine gas use, if  coal mine gas production
remains  competitive with conventional  natural gas.  Coal-fired base load units could cofire or
reburn  gas  to yield   environmental  as  well  as  economic benefits.  Small  gas  turbine
developments may afford coal mine operators the option of on-site power generation during
peak pricing  periods. In addition, the development of new technologies that reduce the cost of
producing, storing and transporting gas may increase the role  of coal mine  gas usage as well.
Total gas use in power generation, including on-site industrial cogeneration, is expected to grow
from 5.6 quadrillion (1015) Btus in 1995 to 9.7 quadrillion Btus by the year 2015 (Figure 4), with
combined-cycle turbines accounting for most of the increase (GRI, 1997a).
                             Figure 4 - Gas Use by Technology

            10 -

            8 •
            6 i <1% (Small Power)

                                    • Small Power Generation
                                    S Combined Cycle
                                    DGas Turbine/IC Engines
                                    ii Steam
The evolution of a competitive electricity market structure should produce market niches for coal
mine gas-fired generation technologies. The development of small-scale gas turbines, combined
cycle cogeneration systems, fuel cells, microturbines and other distributed generation processes
has moved beyond the research and development stage, and these technologies are now

commercially available. The success of these technologies, together with current usage of gas
turbines  and internal combustion engines  in the  electricity marketplace,  is  increasing  the
potential for coal mine gas use. U.S. EPA's Coalbed Methane Outreach Program (CMOP) has
published a Technical Options Series of case studies that provides more  information about
these technologies. Appendix B lists these and other CMOP publications.
Fuel Switching Generating Units

Electric power  generating companies generally prefer to have generating units that can use
more than one fuel so that they can take advantage of supply and price differentials between
fuels.  A coal-fired unit may  include fuel-switching capabilities that allow it to burn oil or natural
gas (including coal mine gas). Gas-fired generating units using today's turbine technology also
have the capability to switch to distillate fuel oil or diesel, which would allow them to continue
generating power if coal mine gas supplies were  disrupted.  In  this case,  the generator would
have to invest capital for on-site fuel storage equipment.

In a restructured market, generating units located at or near a coal mine  could use coal mine
gas piped directly from the mine. There would be  several economic advantages to both parties,
one being little or no charges for transporting  the gas.   Electricity  produced with minimal
transmission costs could be sent directly back to the mine for on-site use.  When considering
fuel  switching,  a power producer would have to evaluate performance, capital cost, operating
cost, and utilization rates.
Peak Period Sales

Generally occurring  on hot summer afternoons, peak time periods provide coal  mines with a
window of opportunity to sell coal mine gas-fueled electricity when prices are at their highest. In
June 1998 in the Midwest (a partially deregulated market) prices soared as high as $7,500 per
MWhr.  With the development of real-time metering, short-term, hourly electricity sales (or on-
site use to offset purchases of peak electricity) can be maximized by coal mines. As competition
increases, coal mine gas developers should seek opportunities for using coal mine gas to fuel
peak power units during maximum load periods.  Gas-fired combustion turbines tend to be ideal
for coal mine gas fuel and peak service use. To be economically attractive, however, such coal
mine gas projects must be able to  sell the gas to a pipeline or use it on-site during the off-peak
power months.

This type of  collaborative effort could benefit  both parties involved.   For  example, power
marketers look to spot market sales of electricity to supplement their  base loads during the
summer months. Traditionally, pipeline gas prices are lowest during these months, so operating
coal mine gas-fueled electric generators would maximize profits during this time.  A gas storage
facility could improve  the economics of operating a peak load unit at a coal mine, or could
supply gas to larger-scale peaking units.  A storage facility would also give a mine the  ability to
maximize gas sales during the winter months when gas prices are at their peak4.  Utilities may
have several peak period markets to which they can supply electricity, if available. Therefore,
utilities could maximize their profits by having the additional capacity to reach as  many  high-
priced, peak period customers as possible during short time periods.
  Select abandoned coal mines could be suitable for storing coal mine gas from active mines, and could provide significant
 economic advantages to coal mine gas projects.  Gas storage can be particularly advantageous to larger coal mine gas projects
 (U.S. EPA, 1998g).


Distributed Power Generation
"Distributed generation" is defined as the integrated  use of  small, modular power generation
systems typically ranging  from a few kilowatts up to 25 MW.  It differs from self-generation in
that power units are placed close to a limited number of consumers to enhance the capability of
the existing power grid. Large-scale power systems,  in contrast, require  direct access to large
quantities of fuel and serve larger  populations than  distributed generation  systems.  Areas
where the cost of power delivered to the point of use is high and/or those areas with high peak-
period electricity prices will benefit from distributed power generation systems. Figure 5 shows
examples of  the  distributed  power  generation  process,  showing  how internal combustion
engines, gas-fired turbines, and fuel cells might be used for distributed generation.

Both  local  utilities and coal mines can benefit from distributed power systems.  To  illustrate,
local  utilities could substitute a distributed generation  system for needed  upgrades or  additions
to existing generating capacity,  transmission,  or distribution systems.  They may be able to
reduce  their SO2 and NOX emissions by supporting coal mines in producing clean power for
sectors which are now supplied by older, less efficient power systems. As part of a distributed
power generation system, coal mines could generate electricity for themselves and sell power to
nearby  industrial plants, commercial centers, or residential customers.  In addition, any  excess
electricity could be sold back to the local grid for commercial or industrial customers that are
currently on power systems that may be near capacity. Moreover, if a power producer  arranges
a distributed power generation system for a coal mine and industrial customers, it could benefit
utilities  by allowing them  to shift electricity sales to higher-priced markets such  as residential
                                           Coal Mine(s)
         Local industry
                                                                       Coal Mine(s)
              On-site electricity
             generation for use at
             mine and/or sell to
              nearby industry
                                         On-site electricity
                                          generation for
                                      supplemental use at mine
On-site electricity
generation for use
 at mine, selling
 portion to grid
             Coal Mine(s)
                                      Main Power Station
                                                     Power Grid
       Figure 5: Examples Of Distributed Generation Systems Using Coal Mine Gas
 Based  on  estimates  of electricity demands of  mines  profiled  in  U.S.  EPA's  Identifying
 Opportunities for Methane Recovery at U.S.  Coal Mines, a power generating unit  ranging in
 capacity from 5-25 MW would meet the needs of 80% of the gassiest underground coal mines in
 the U.S. (U.S. EPA, 1997).  At a 60%  methane recovery rate, 12 of the 25 gassiest coal mines
 in the U.S.  could produce enough coal mine gas to supply 100% of their power requirements,

and in addition, provide electricity for market sales.  An additional eight of the 25 mines would
be capable of producing as least two thirds of their energy needs.  Overall, these gassy coal
mines have the potential to produce 10 to 30 MW each of electric generating capacity, while
reducing their greenhouse gas emissions. Table 1 in Appendix A lists the potential generating
capacity for each of these 25 mines.

Opportunities for Coal Mine Gas Use Resulting from Environmental Regulations

Title IV of the 1990 Clean Air Act Amendments (CAAA) sets as its primary goal the reduction of
SO2 and NOX emissions, mostly from coal-fired utility and industrial boilers. As a result, Title IV
has given industry the impetus to produce and commission new coal-fueled advanced power
systems, such as low-emission  boilers and pressurized  fluidized bed  combustion. Title IV
provides a significant opportunity for coal mine gas to play a cost-effective role in the  electricity
generating  sector, in that utilities can reduce emissions by  cofiring coal mine gas in  coal-fired
utility boilers.  In particular, U.S.  EPA's recent ozone rule may negate the price advantage
currently enjoyed by Midwestern coal-fired utilities.  A restructured market may make it easier
for such utilities to use coal mine gas as part of an alternative fuel strategy.

Below is a brief description of each type of environmental benefit associated with increased coal
mine gas use.

Sulfur Dioxide Emissions Allowances.  U.S. EPA's  Acid Rain Program introduced an SO2
allowance trading system that harnessed the incentives of the free market to reduce emissions
of this pollutant.  Under this system, the law sets a permanent cap on emissions nationwide.
Utilities are given a set  number of allowances.  Those that reduce emissions through energy
efficiency, pollution control devices,  or renewable energy are  able to sell or  bank their surplus
allowances, while those that  exceed their allowed emissions  must  buy additional allowances.
U.S.  EPA  has  instituted an  electronic record keeping and notification system called the
Allowance  Tracking System to track transactions and the  status  of allowance accounts.   The
market price of an SO2 allowance as of December 1998 was $196/ton (Cantor Fitzgerald, 1998).

Use of coal mine gas as a fuel for electricity generation, whether through co-firing, combustion
air or supplemental power systems, could be economically beneficial to a utility by reducing its
SO2 allowance purchases.  Based on the current value of SO2  allowances, a utility would realize
an  offset value of $0.11/MM  Btu of gas fired.  As Phase II of the program begins in the year
2000,  U.S. EPA will lower the cap on SO2  emissions  on  all  utility units, thus increasing
allowance trading and possibly prices, which will increase the value of coal mine gas for SO2
emission reductions.

Nitrogen  Oxide  Emissions  Allowances.  Phase II of the Acid  Rain  Program will subject all
utility boilers to  further reductions in  NOX emissions (a precursor  to ground-level ozone
formation)  in the year 2000.  The NOX program embodies many  of the same principles of the
SO2 trading program; however, it does not cap NOX emissions as does the SO2 program, nor
does it  employ an allowance trading system.  Compliance is based on individual emission rates
for boilers  using "reasonably achievable control technology" (RACT), which gives utilities  more
flexibility to meet emissions limitations in the most cost-effective way.

As an addition to the Acid Rain Program, U.S. EPA published  the proposed rule in May 1998 to
implement a program aimed at further reducing emissions of  NOX to less than half of the 1990
baseline levels (U.S. EPA, 1998d). U.S. EPA proposed the rule under the Ozone  Transport
Commission (OTC) NOX Program. Like the SO2 allowance trading  program, the OTC rule will


use a "cap and trade" system to reduce ground-level ozone in 22 states5, thus  affecting all
existing fossil-fuel fired boilers with an output greater than 15 MW.  Individual states that adopt
the program  will allocate  the  NOX allowances  and ensure that sources are in  compliance
through a State Implementation Plan (SIP), while U.S.  EPA will operate the only allowance and
emissions tracking systems for the program. The NOX reductions will be implemented in two
phases, the first phase beginning  May 1999 and the second phase in May 2003.  The market
price of OTC NOX credits  during  1998 ranged from $1,500 to  $3,400/ton, depending on the
month, state, and air quality designation (Cantor Fitzgerald, 1998).

Cofiring coal mine gas with coal in boilers can prove to be an economical strategy for helping
utilities comply with NOX regulations under Phase II of the U.S.  EPA's Acid Rain Program and
the more recent OTC program.  Utilities  affected by these  programs are responsible  for
demonstrating compliance with the requirements of  both programs.  For  existing power plants,
the calculated value of NOX reductions, based on OTC  NOX offset values ranging from $1,500 to
$3,400/ton, is $1.69 to $3.74/MM Btu of gas co-fired with coal, respectively (U.S. EPA, 1998b).
Although, the cost of implementing this post-combustion technology is approximately $1500/ton
NOx removed,  the  emissions  offset value can  easily exceed the value of the avoided coal
consumption and cost of implementing the technology.

Greenhouse Gas Emissions. Methane is a greenhouse gas, and when coal mines  emit it to
the atmosphere, rather than using it as fuel, it contributes to global warming. In fact,  methane
significantly contributes to global warming because it is approximately 21  times more potent (as
a greenhouse gas) than carbon dioxide (CO2).  U.S. EPA estimates that recovering and using
just 1 BCF of coal mine methane is equivalent (in terms of global warming reduction) to taking
nearly 90,000 cars off the road  (U.S. EPA, 1998e).

Congress's passage of Title XVI, Sec.1605(b) of the Energy Policy Act of 1992  directed  the
DOE's Energy Information Administration to establish a database for voluntary greenhouse gas
emissions reductions. The benefit of reporting reductions in greenhouse gas emissions is that
participating  companies have a  formal  record of their efforts to  reduce greenhouse gas
emissions.   Although  a  trading system  for  greenhouse  gas  reductions  has not  been
implemented, governments worldwide are examining  proposals for domestic and  international
greenhouse gas trading systems.  Recently, the Dutch government and the state of New Jersey
signed a "letter of intent" in June 1998 to design a prototype greenhouse gas emissions trading
system (U.S. EPA, 1998f).  U.S.  EPA has developed several  Voluntary Programs that allow
companies, agencies, and other organizations to report the results of actions taken  to reduce or
offset greenhouse gas emissions. U.S.  EPA's Coalbed Methane Outreach Program (CMOP)
works with coal mines to encourage the recovery and use of coal mine gas that would otherwise
be emitted to the atmosphere during mining operations.

At least two companies have already engaged in a greenhouse gas emissions trade.  In March
1998,  Suncor Energy of  Canada made an initial  purchase of 100,000 metric  tons of C02
emission reductions from Niagara Mohawk Power Corp. of the U.S., with  an option to purchase
up to an additional  10 million metric tons over a ten-year period. The trade, potentially worth
$U.S. 6 million, establishes Suncor and Niagara Mohawk as leaders in emissions credit trading.
Currently, Alternative Fuels Corporation operates the Green Valley Coalbed Methane Power
Plant that generates 1.2 MW of electricity using coal  mine gas from an  abandoned mine near
Terre Haute, Indiana.  The project reports approximately 38,000 tons per year of CO2 equivalent
credits per megawatt of generation. The Chicago Board of Trade lists the current market value
  The states that will be subject to this action are: Alabama, Connecticut, District ot Columbia, Delaware, Georgia, Illinois, Indiana,
 Kentucky, Massachusetts, Maryland, Michigan, Missouri, North Carolina, New Jersey, New York, Ohio, Pennsylvania, Rhode Island,
 South Carolina, Tennessee, Virginia, Wisconsin, and West Virginia.


of greenhouse gas credits, based on their carbon dioxide equivalent, as approximately $1 per
metric ton (Cantor Fitzgerald, 1998) depending on the industry, country, type of project, and
ability to validate the reduction.

Cofiring Gas in Coal Boilers to Reduce SO2, NOX and GHG Emissions. The ease of boiler
conversion and low capital cost make cofiring  a low-risk approach to using coal  mine gas.
Cofiring improves  ash quality, reduces slag buildup, and can slightly increase boiler efficiency.
The gas input may vary from less than 3% to 100% of the total fuel  input, increasing the short-
term peaking capability of the coal-fired boiler. One cofiring technology termed "gas  reburning"
can achieve a NOX reduction of 5% for each 1% of gas heat input (U.S. EPA, 1998b).  The value
of NOX benefits is not linear with the percentage of coal mine gas cofired, as it peaks at about
7% heat input.  As a result, a coal mine gas cofiring rate of 7% is able to reduce entire boiler
emissions by over 40%, making this NOX control technology an economically attractive gas use
option in some cases.

Approximately 370 utility  boilers in the U.S.  now have cofiring capability, of which many are
situated near gassy coal mines.  In order to determine  which boilers would be ideal for  cofiring
with coal mine gas, operators must consider gas demand and availability, pipeline distance, and
boiler conversion costs.  Cofiring is an ideal application for variable quality coal mine gas. U.S.
EPA is researching the economic potential of siting new coal-fired boilers at gassy coal mines to
employ coal, coal mine gas,  and ventilation air as fuels.  If successful, these new boilers could
assure the future sales of coal and coal mine gas for coal mine operators.

Economics of Cofiring with Coal Mine Gas. The economics of cofiring  gas at coal-fired
industrial and utility boilers makes a compelling argument for coal mine gas use, especially at
power plants located at coal mines.  As competition in the electric industry serves the  lowest-
cost producer,  the use of low  emissions technologies will become increasingly important to
utilities.  In addition, emission  credits and avoided penalties can substantially improve the
economics of most coal mine gas projects, therefore stabilizing coal  use for utilities that can
achieve low-cost environmental  compliance. Cofiring coal mine gas with coal can therefore help
utilities comply with environmental regulations without having to switch entirely from coal to gas.
Table 1 illustrates the potential  value of coal  mine gas when SO2, NOX, and greenhouse gas
reduction values are taken into account.

   Table 1 - Estimated Value of Coal Mine Gas Based on Emissions Reductions Achievable by
       Gas Reburning in Coal-Fired Boilers at Electric Utilities (modified from U.S. EPA I998d)
(S/MM Btu)
1 Avoided cost of coal based on 1997 U.S. average coal purchase prices
2 Assumes OTC NOx credit value of $1500-$3,400/ton and a 5% NOX reduction for each 1% of gas fired
3 Assumes SCk credit value of $1 96/ton SC>2 , and 1 .5% sulfur content in coal combusted
4 Assumes greenhouse gas credit value of $1 /metric ton COa equivalent (or $3.67/ton of carbon) and does
not include additional offset for reduced carbon emissions resulting from reduced combustion of coal
 In summary, environmental regulations are compelling utilities to find least-cost options for
 reducing SOX and NOX emissions. Opportunities arising from restructuring, such as bundling of
 energy services and advances in distributed power generation technologies, should make it
 more feasible than ever before for utilities to use coal mine methane for this purpose.

Green Energy Marketing

Green energy marketing capitalizes  on an expressed  public preference for cleaner energy
options,  such as  energy derived from  renewable sources.   Currently,  power  marketers
advertising green energy are suggesting to consumers that they can make a difference in
protecting the environment by purchasing electricity generated from "green" sources.  Several
companies are offering premium electricity rates based on 10,25 or 50% of a consumer's power
coming  from renewable or green sources. New energy companies  use names like "Green
Mountain" or "Earth Source" to promote their environmentally-friendly image.  Pilot programs in
several states have shown customers are willing to pay a 1-2 cent per kilowatt-hour premium for
green power (Swezey, 1997), and utilities in fifteen states, including Colorado and Indiana, have
developed or are developing green pricing programs.

Green marketing  has the  potential  to  expand domestic  markets  for  renewable  energy
technologies, although critics  argue that the current  marketing  of green  energy is merely
repackaging electricity from existing sources at higher  rates without additional benefits to the
environment (Public Citizen, 1998). While some states classify green power as only that which
is generated by  renewable (e.g. wind or  solar) power, several  states, such  as Pennsylvania,
New Hampshire, and Massachusetts have broadly defined green power to include other energy
sources. An expanded definition that includes coal mine gas-generated power may  attract a
larger market segment, and better serve to heighten environmental awareness of greenhouse
gas emissions. Based on recent electricity marketing approaches, it appears the reduction in
greenhouse gas  emissions resulting from coal mine  gas  use could  be  attractive to the
environmentally conscious consumer or business. Consumers may be willing to pay a premium
for coal  mine gas-generated power even if it does not receive an official "green" classification.

The  degree to which power marketers can sell  electricity in a given  market determines the
success of a green energy program.  If state restructuring rules are "market friendly" such that
power marketers can compete, green energy marketing will be present. However, restructuring
in states like California and Massachusetts has made it difficult for power marketers to compete
with  local utilities, therefore making green energy marketing difficult as well.  According to U.S.
DOE's Green Power Network (Houston, 1998), the fact  that Pennsylvania's restructuring rules
are favorable to power marketers make it the most friendly state toward green power marketing.
This, coupled with the state's designation of coal mine methane as a renewable resource, make
Pennsylvania an ideal green energy market for coal mine gas-fueled electricity projects.

Power producers that use coal mine gas should strive to be a part of this new, environmentally-
friendly  marketing  approach.  Under this marketing scenario, the higher rates that customers
would be willing to pay for electricity produced from coal mine gas could make recovery and use
projects  more attractive. Under restructuring, the  customer or end-user would not even have to
be located near gassy coal mine regions to take advantage of this energy source.


There are several ways in which restructuring creates potential opportunities for increased coal
mine gas use. The bundling of energy services can allow for coal mine gas to be sold as part of
a coal sales contract, pipeline gas sales, or with electricity. The convergence of the gas, coal
and  electricity industries may facilitate these opportunities.  In  addition,  the electric industry's
shift to cleaner-burning, gas-fired power generation will provide opportunities for coal mine gas
use as fuel (in cofiring for example) and as a means of reducing NOX and SOa emissions.  As a
result, restructuring may encourage coal mines to  form relationships with  energy  producers,


power marketers, or local utilities that could spawn joint ventures or alliances that can provide
the capital investment required to construct new co-fired or gas-fueled power systems. In many
cases, the mutual  benefits of forming alliances may overcome the advantages of energy
company mergers.   The following subsections  discuss  how  coal mine operators can take
advantage  of restructured power  markets  by bundling  energy services through mergers or
alliances, developing strategic partnerships with other energy companies, and planning gas-use
strategies with other investors based on changing market conditions.
Bundling of Energy Services

With the evolution of natural gas industry restructuring, competitive-based natural gas contracts
are becoming  more  target-oriented toward specific  industries and regions of the country.
Electric industry restructuring is envisioned to follow the same path, therefore, the link between
market prices for gas and power may become stronger.  Integration of gas producers, pipeline
companies, and power producers  supports  further  convergence of the  gas and electric
industries, therefore broadening markets for coal mine gas.

Bundling of coal, gas, and electricity sales along with SO2, NOX, greenhouse gas credits  and
avoided  penalties can maximize the value  of coal mine gas.  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 they require coal,  gas,  fuel oil, electricity, or  any
combination of these fuels. In addition, Btu bundling can also occur at the wholesale level, such
that a coal mine could offer to sell coal, coal mine  gas for cofiring, or coal mine gas-fired
electricity to a  utility company.  In  addition, a utility can purchase emission reduction credits
generated through coal mine gas use in cofiring or electricity generation.

Convergence  of Energy Industries

The unbundling of gas and electricity services and rates is contributing  to a convergence of
energy industries, where markets may soon be defined by a "Btu of energy service" rather than
by a kilowatt-hour of electricity or a thousand cubic feet (mcf) of natural gas.  Participants in the
new market will be able to offer customers functions and services from both industries, such as
Btu substitution and real-time metering for end-users,  along with various types of "full service"
functions such  as load management services and energy efficient equipment.

Many  gas and  electric companies that have merged over the past year are venturing into "one-
stop shopping" for consumers.  For example,  Atlanta-based Southern Company and Houston-
based Vastar  Resources joined forces  to  create  Southern  Company Energy  Marketing.
Similarly, Puget Sound Power & Light Co. acquired Washington Energy Company to form Puget
Sound Energy. Energy companies such as these could utilize and market coal mine gas as a
fuel and/or as gas-fueled electricity.

There are indications that economic conditions in some regional energy markets may foster the
convergence of the coal  industry with the gas and electricity industries.  If a  coal mine has
access to gas  pipelines and electric transmission lines through its parent company, coal mine
gas projects could become more accessible to energy  markets. A good example of this merging
of industries is PacifiCorp's6 recent attempt to buy Britain's largest supplier of electricity,  The
  Pacificorp owns two large electric utilities, Pacific Power and Utah Power, lists PacifiCorp Power Marketing as a subsidiary, owns
 five coal mines in the western U.S., and has alliances with several gas marketers.


Energy Group PLC (which is the parent company of Peabody Coal, the world's largest private
coal producer).

PacifiCorp's interest in acquiring The Energy Group apparently included a long-term strategy
with Peabody Coal (Ludwigson,  1997).   These intentions became  clear  when  PacifiCorp
announced a willingness to renegotiate the coal contracts held by Peabody Coal in exchange
for  the right to sell additional electricity  produced by  the  plants bound by these contracts.
PacifiCorp's scheme was to acquire access to prime generating capacity by lowering coal prices
to those plants.  If successful, this merger would  have redefined vertical mergers and added a
new dimension to coal/energy industry convergence, but an investor-owned holding company,
Texas Utilities Company, bought The Energy Group in May  1998 by outbidding PacifiCorp.  In
December  1998,  Pacificorp merged  with  another   leading  British  multi-utility  company,
Scottish Power.
Developing Strategic Partnerships

Coal mine operators considering coal mine gas recovery and use projects must weigh the risks
and benefits to their mining operations. In addition to increased mining efficiency, benefits may
include long-term relationships with utilities, royalty payments from gas revenues,  increased
cash flow,  and greenhouse gas credits. The key to maximizing  benefits from coal mine gas-
fueled power projects is the development of strategic partnerships or alliances between coal
mine  operators  and energy producers, marketers, or utilities. Table 2  in  Appendix A  lists
methane drainage systems currently employed at U.S. coal mines.

Coal mines with  drainage systems in place are in a strong position to seek out partners for joint
ventures, equity  investments, and debt financing for electric power project development. Mutual
interest between a merchant  power plant developer and an anchor tenant like a coal mine
makes a power project near a  coal mine very attractive for both parties. For example, a power
producer may be able to take  advantage of the availability of both coal and a coal mine's gob
gas.  In  turn, the coal mine may be able to purchase a portion of the electricity at a rate that
would  be  attractive for long  term, on-site use. Also, the two  parties could  include the
greenhouse gas credits generated by reduced greenhouse gas emissions in the transaction.

Coal Mine/Utility Partnerships. Electric utilities are looking for better ways to serve (and keep)
their clients. A utility that ventures  into an agreement with a  coal mine that allows the mine to
self-generate part of its electricity needs can profit by 1) retaining the coal mine as a customer,
2) redirecting electricity  sales from the coal mine to residential or commercial customers, who
pay higher rates (traditionally, utilities sell electricity to coal mines at low industrial rates),  and 3)
possibly reducing capacity  constraints of certain transmission lines. Furthermore, a utility may
profit from  financing a power project sited at a mine, where the mine supplies the gas and uses
a portion of the power, and the utility sells the remaining electricity to other customers.  A coal
company could become a total power supplier  in this case, including the potential for saleable
emissions reductions credits.

Some  coal suppliers  have been  reluctant to  develop coal  mine  methane fueled  power
generation projects because 1) they fear that this could jeopardize coal sales, since utilities are
the main customers of coal  suppliers, and 2) it would compete  with their  own coal  sales.
However, in this age of  restructuring and merging of energy industries,  there could  be many
cases  where a  coal supplier  could self-generate power, or sell power to the grid, without
necessarily alienating a utility  customer.  Furthermore,  in becoming a "total Btu provider", the

"coal  supplier"  becomes  an energy  supplier,  capable of selling  coal  or gas  in  whatever
combination is most profitable.

Coal  Mine/Gas Developer  Partnerships. A  restructured market will  encourage  bilateral
transactions between gassy coal mines and different parties within the electric power market.  In
some cases, agreements may involve participation of gas developers that supply gas to electric
utilities, and may provide the  best avenue for connecting coal  mines  with gas-fired  power

In addition to producing saleable gas, coal mine operators can realize economic benefits from
gas drainage projects through reduced  mine  ventilation costs  and fewer methane-related
production delays.  Recent research (Mutmansky, 1997) has shown that the use  of coal mine
methane drainage systems before or during the mining process can significantly  lower mining
costs and/or increase coal production, particularly if the levels of methane in the seam being
mined are relatively  high.

Coal mining companies that do not have corporate ties to gas developers can also look toward
independent gas developers to help finance coal mine gas recovery  projects.  If the mine is not
interested in operating the project itself, it can turn over project operations to the gas developer
who will determine the best use  of the  gas.   Coal  mine operators may be  able  to  obtain
financing for the project  based on the  economic  benefits  of increased coal  production,  in
addition to gas  sales. U.S. EPA has prepared several publications that can provide the  reader
with more information regarding financing of coal mine gas projects (Appendix B).

When entering  into agreements between coal mines and gas industry partners, it is important to
consider the coal mine's existing relationship with a  coal-fired power producer and the future of
its  coal  contracts.   Table  2  lists several strategic partnerships  that could develop from
restructuring, along  with their associated benefits.

  	Table 2 - Mutual Benefits of Various Partnerships	
  Coal Mine and Coal-fired
Cofiring, On-site use
Decreased SO2, NOx & GHG emissions
adds value to gas

Existing agreements may be in place
  Coal Mine and Gas
Gas sales to pipeline

Gas sales to gas-fired
power plant	
Revenues from gas sales

GHG reduction credits may be bundled
with coal sales or traded separately
  Coal Mine and Merchant
  Power Developer
Cofiring on site

Gas-fired power plant on
Reduced on-site electricity costs and
GHG emissions

Fuel to supply low-emissions power plant
  Coal Mine and Power
  Distribution Company
Distributed generation
power system

On-site use
Revenues from electricity sales & GHG

Reduced on-site electricity costs	
  Coal Mine and Power
Electricity sales to off-site
Revenues from electricity sales & GHG

Market green energy to consumers

Recommended Coal Mine Gas Use Strategies
Developers of coal mine gas-fueled electricity projects must choose the gas-use strategies that
best suit the needs of the mine(s) supplying the gas, and must also consider the influence of the
regional power market on gas sales. This subsection discusses six different recommended gas-
use strategies that could be mutually beneficial to the parties involved.  Table 3 summarizes
these strategies, along with their potential benefits and issues.

  	Table 3 - Benefits and Potential Issues of Various Gas Use Options	
     Sell coal mine gas to
     coal-fired utility for co-
                             Could bundle gas with coal
                             Emissions reduction for both
Gas pipeline system may be
Cost of boiler conversion
     Sell electricity
     wholesale to power
     marketer to wheel over
     transmission lines
                             Long-term recovery solution
                             for coal mine gas
                             Electricity sales can be used
                             to generate revenue
                             Reduce load on system
Capital costs
Profits depend on regional
     Produce distributed
     power or produce and
     consume on-site
                             Electricity can be used to
                             meet coal mine's needs
                             Excess electricity can be sold
                             to local consumers
Capital costs
Higher O&M costs for
smaller projects
Electricity is dependent on
consistent gas flow	
     Bundling of coal, gas
     and electricity sales to
     power producer
                             Long term recovery solution
                             for coal mine gas
                             Could maximize value of
                             each commodity through
                             bilateral contract with power
Capital costs
Managing both electric
generating unit and gas
pipeline system
     Sell coal mine gas-
     generated electricity to
     power marketer for green
     energy sales	
                             Added value to electricity
                             Generate revenue
Capital costs
     Sell either coal mine
     gas or coal mine gas-
     generated electricity
     depending on market
                             Maximize gas value
                             Capture market for both peak
Capital costs
Gas must be stored, used or
sold separately at different
times of year
Selling coal mine gas directly to a coal-fired utility for cofiring or fuel switching is one of
the simplest  strategies.   This arrangement benefits  both the coal  producer and coal
customer,  and with the  possible exception  of  an independent  gas  developer,  no new
companies would need to enter into the relationship.  As discussed earlier, both parties can
reap the economic benefits of reduced emissions.

Selling  coal  mine  gas-generated  electricity wholesale  to  power  marketers can
generate revenue for the coal mine.   A restructured  market allows electricity sales to
customers anywhere in the  U.S., provided there  is transmission  capacity available.  As
previously discussed,  there are highly prospective regional markets located near several
gassy underground coal mine regions.

3.  Producing coal mine gas-generated electricity for use on-site with a distributed power
   generation system has many advantages, especially if a coal mine is currently located in a
   high-priced region.  Electricity costs to the coal mine will decrease and any excess power
   can be sold back to the grid.  Joint ventures with coal mines may be attractive to utilities if
   the reduced load on the utilities' system allows increased sales (from their existing capacity)
   to higher-priced end users.

4.  Bundling of coal, gas, and electricity sales along with S02, NOX, and greenhouse gas
   credits would maximize the value of coal mine gas.  Coal mines that sell coal to a nearby
   power plant with fuel switching or cofiring capability  could negotiate a. combined gas and
   coal sales contract.  Electricity produced by the coal mine could also be bundled into the
   sales agreement, and greenhouse gas credits  could be incorporated into an agreement as

5.  Marketing coal mine gas as green energy can prove to be an excellent strategy for a
   power  marketer. Environmentally conscious customers are choosing  green power  over
   conventionally  produced power and are willing to pay a premium for it.  Power marketers
   and consumers will likely embrace the opportunity to  reduce greenhouse gas emissions via
   coal mine gas recovery and use.

It  is clear that restructuring of the electricity industry will have far-reaching implications for all
energy sources, including coal mine gas. The outcome is difficult to predict at this early stage of
restructuring.  Most indicators show an increased dependence on gas for electricity generation
over the next few decades,  where competition will  most likely favor the  low-cost  electricity
producer. Coal mine gas producers who can supply low-cost fuel may become an essential part
of this equation.

The following areas appear to present key opportunities for coal mine gas producers:

•   On-site power generation. On-site power generation eliminates distribution and transmission
    costs, and gas-fired  electric generating units  have low capital costs relative to  coal-fired
    units. Medium-quality coal mine gas is ideal for fueling power generation units.

•   Bundling of energy services. The convergence of the gas and electric industries will allow for
    Btu substitution, such as  combined coal, gas and electricity sales, which will open the door
    for greater flexibility in coal mine gas use options.  Coal mines could sell either coal, gas or
    electricity to  an  integrated power market based on energy  prices, seasonal  or diurnal
    demand, and regional demands. Greenhouse gas emission credits can be incorporated into
    energy contracts as well.

•   Advances in distributed power generation technologies.  Distributed generation systems are
    expected to  account for over 20% of all new  electricity  generation  capacity.  Several
    advanced gas technologies such as fuel cells, micro turbines, and  1C engines are ideal
    options  for distributed  power or on-site use  at coal mines.   Coal mine  gas-fired power
    generation  can supplement distributed  power  systems, while  restructuring will enable coal
    mines to sell power locally.

•   Cofiring coal mine gas with coal. Cofiring can reduce overall 862 and NOx emissions and
    would be particularly cost effective in states located within the Ozone Transport Corridor. By
    siting at coal mines, new merchant power plants could assure both coal and coal mine gas

•   Electricity sales in high-priced markets. Many gassy coal mines are located in regions of the
    country with  relatively  high-priced electricity markets  that  will need  additional  power
    generation capacity. In some instances, utilities may allow coal  mines to produce  on-site
    power at peak periods, reducing electricity costs for the mine while allowing the utility to sell
    the displaced electricity to higher priced markets.

The U.S. energy marketplace is dynamic and complex. Coal mines and project developers can
best capitalize on opportunities in the present marketplace by forming strategic alliances with
other energy industry partners.  Ideal partners are those that are well-positioned to help the coal
mine or project developer  meet its short- and long-term goals.


Cantor Fitzgerald Environmental Brokerage Services. 1998. "Continuous Clean Air Auction
Bulletin." http://www.cantor.com/ebs/mb0327nx.htm

Edison Electric Institute. "Electricity Issues: Historical Background." 1998.

EIA (Energy Information Administration).  1997.  Electricity Prices in a Competitive Market -
Preliminary Analysis Through 2015.  Chapter 3 - Competitive Electricity Price Projections.

EIA (Energy Information Administration).  1998a. "Annual Energy Outlook 1998 Forecasts".
Market Trends - Electricity.  http://www.eia.doe.gov/oiaf/aeo98/ele_pri.html

EIA (Energy Information Administration).  1998b. "Annual Energy Outlook 1998 Forecasts".
Forecast Comparison,  http://www.eia.doe.gov/oiaf/aeo98/forecomp.html

GRI (Gas Research Institute). 1997a.  "Electric Generation Sector Summary." GRI-97-0014.
http://www.gri. ../elec-gen/sect-sum/e-gensectr.htm

Houston, Ashley. U.S.DOE (Department of Energy) "Green Power Network."  1998.  Email.
Houston_ashley@nrel.gov  (9-10 July 1998).

ICF Kaiser Consulting Group. 1998.  "Wholesale Power Market Model."

Ludwigson, Jon, and Lynn Kendall. 1997. "PacifiCorp and Peabody Offer Relief...At a Price."
Coal Age. September  1997: 45-46.

Mauel, John G. 1997.  A Summary of Electricity Industry Restructuring and Possible Effects on
Natural Gas Contracts,  http://www.thompson.com/tpg/energy/trac/tracaug.html

Mutmansky, Jan M. 1997.  "Analysis of Mining-Related Costs Affected by Coalbed Methane
Degasification Systems," presentation at  the North American Coalbed Methane Forum.
November 6-7, 1997.

Public Citizen. 1998. "Green Buyers Beware: A Critical Review of Green Electricity Products."
Executive Summary. October 24,1998.

Swezey, B.G.  1997. "Second National Green Pricing and Green Power Marketing Conference
- Final Report." May 13-14, 1997. National Renewable Energy Laboratory.

U.S. EPA (Environmental Protection Agency).  1997. "Identifying Opportunities for Methane
Recovery at U.S. Coal  Mines: Draft Profiles of Selected Gassy Underground Coal Mines."
Office of Air and Radiation (6202J).  U.S. EPA 430-R-97-020. September 1997.

U.S. EPA (Environmental Protection Agency).  1998a.  "White Paper: The Impacts of FERC
Order 636 on Coal  Mine Gas Project Development."  March 27,1998.

U.S. EPA (Environmental Protection Agency).  1998b.  "Technical and Economic Assessment of
Coal Mine Methane in Coal-Fired Utility and Industrial Boilers in Northern Appalachia and
Alabama." Office of Air and Radiation (6202J).  U.S. EPA 430-R-98-007.  ApriM998.

U.S. EPA (Environmental Protection Agency).  1998c.  "Cofiring Coal Mine Methane in Coal-
Fired Utility and Industrial Boilers." Coalbed Methane Outreach Program Technical Options
Series. June 1998.

U.S. EPA (Environmental Protection Agency).  1998d.  U.S. EPA Fact Sheet on "Proposed Rule
For Reducing Regional Transport of Ground-Level Ozone." Federal Register - (62 FR-60317.
November?, 1997).  April 28, 1998.

U.S. EPA (Environmental Protection Agency).  1998e.  "What is Coal Mine Methane?" Office of
Air and Radiation (6202J).  U.S. EPA 430-F-98-009. March 1998.

U.S. EPA (Environmental Protection Agency).  1998f. "Worldview - Climate Change II: New
Jersey, Netherlands To Trade Emissions." U.S. EPA Global Warming Web Site.
http://www.epa.gov/oppeoee1/globalwarming/news.greenwire/index.html  June 8,1998.

U.S. EPA (Environmental Protection Agency).  1998g.  "Technical and Economic Assessment of
Coalbed Methane Storage in Abandoned Mine Workings." June 1998.

Appendix A


Alabama Public Service Commission
P.O. Box 991
Montgomery, AL  36101-0991
Telephone: 334242-5025
Web site: www.psc.state.al.us

Colorado Public Utilities Commission
1580 Logan Street
Office Level 2
Denver, CO  80203
Telephone: 303894-2000
Web site:

Illinois Commerce Commission
527 E. Capitol Avenue
P.O. Box19280
Springfield, IL  62794-9280
       Springfield: 217782-7295
       Chicago: 312814-2850
Web site:  http://icc.state.il.us/

Indiana Utility Regulatory Commission
302 West Washington St. - Suite E306
Indianapolis, IN 46204
Telephone: 800851-4268
Web site:  http://www.ai.org/iurc/index.html

Kentucky Public Service Commission
730 Schenkel Lane
P.O. Box 615
Frankfort, KY 40602-0615
Telephone: 502 564-3940
Fax: 502564-3460
Web site:  http://www.psc.state.ky.us

New Mexico Public Utility Commission
224 East Palace Ave., Marian Hall
Santa Fe, NM  87501
Telephone: 505 827-6940
Fax: 505827-6973
Web site:
Public Utilities Commission of Ohio
180 E. Broad St.
Columbus, Ohio  43215-3793
Telephone: 614466-3292
Web site:

Pennsylvania Public Utility Commission
P.O. Box 3265
Harrisburg, PA 17105-3265
Web site:

Utah Division of Public Utilities
4th Floor, Heber M. Wells Bldg.
160 East 300 South
Box 146751
Salt Lake City, UT 84114-6751
Telephone: 801 530-6651
Fax: 801 530-6512
Web site:
erce/pubutls/dpuhpl .htm

Virginia State Corporation Commission
Division  of Energy Regulation
4th Floor-Tyler Building
1300 EMain Street
P.O. Box 1197
Richmond, VA 23218
Telephone: 804371-9611
Web site:

Public Service Commission of West Virginia
201 Brooks Street
Charleston, WV 25323
Telephone: 800 642-8544
Web site:




« >
and pric
— _i
« "J


' '
CO <£
S s

Q: ?
u. —

*^ UJ
jij -J
EC 0 2-
7 LU
-i co —
< UJ i-
nts per kW/h
5 r: m
3 o o
< UJ ^
0 >
E b
I- O
0 < _
*" "• ra
UJ z ~
z a
o ct:
Q- U.
3 ff
_l > ^
-1 CD ~ '

< £
j !3 ~
S  -«T- CM T- T-
•*— o oo cr> co


m ^T CD in T—
•^ ^ CO CO CO

_l < < _J _J


Is- C CO
, •<- o
O • .U O
zz 8Z
-* _ 0 •% ID
CD ^ n ® ">
CD ra "- CD o
6 ra ~ 6 o
9» o 5) » ^
5 ^ .i .2  CQ O

CD' — CO^f^T^T— ^-(DlOOsimCM CD CO' — ^J"OOCnCsloO O CNJ ' — CM

r^r^^cDio^tmoi — LncsicoT-cncNj^T'— •^••^roaiLntoiDCNoo



ooooooooo oooo ooooooooooo
ooooooooo oooo ooooooooooo
mcMomoouncoo -^ounun mcDOocMOOincooo
OCMCMinOCMCMCDCO •^-^OO COLOCMCNCMrOLnr--T-h~cocD<-cocD'^ T-cococo r^cDCJ)O>coLni^-CMOoo
r^ co co m ^" in co co ^~ co co CM CM ^~ ^— T— v- T— T— T— T—
< <
z z




in en
2 rj 2
c CN ^y T—
o1* ocxl1" '"-cxlZ^, JCQ
^Z ^g^-,^2^1"^ Z§ -'S "§ ^^^


§ aj
S g;
£=i S
ra S
S o
^ o 1 1
| 5 o «
> R B -S
o aj c
S S » e
s Ii!
1 S 1 5
O '!=: -= ro
U Q. QJ 0)
Q) -a "° p
|| If
^ ^ ^ "ra
"D 10 "S '-
QJ CD ^ -=.
2 ™ -5 B
"o c a. "ra

o §* ro ™
-^ ID CD ^
CD > > £
.C CD CD ^
w CO 00 S
3 ID CD g1
w CT) cn —
-^ CM en -^




|C          °












                    Ol  tf>  CO  (/)  U3

                    TO  TO  TO  TO  CO

                    CO CO CO CO  

                    0  0  CD  CD  0
                    C  C  C  C  C

                    Q. Q. Q. Q- Q.

                    IX il (X iX  0.


          Q  O  £.

          X  o,
          I- Z

          H Q

                        ra ra
                        co co
                        0 0
                        9- 9-
                        Q. CL
      0 0
      oL ol

      Nj N

      o o
      X X

      o o
      O O

      r -c

      o o
      O O

      •c r











                       5 2 2  2
                                      CD „





            ra ro
            CO co
            CD 0
            c c

            "0 "0
            9- 9-
            h. b.
                                            o g o ^
                                            x i x i

                                                           CD 0 0
0  0 CD
o)  in o>
13 D =>
                                                             c  c  c:
                                                       c  c  c


N  N N


                            C  C  C


      ^•^3"^rm^T3-T3-t— •^•^•^rTr^j-'^r^r^-Tr^r^zz
             oo           w

       S  S ~r ~r  K  O    tt!  O  <2  Q  ,-  O _0  O  O  O
                    oooicnocU— ogy-ooooo    ooo
                    °  °  c  c  ° c ,, s° °- looooo rnooo
                    t  t 22
                                                        .3 .3 o o o
>~ i_ «£ -^ i_ ^z  to  =; '•*-  »~ c: "n ~^ '-^ '-^ ~-i= '-^
^>^[j — — ji)  o ^ o ^ -ffi m c m ro coco  co
                                                                          .9  o  o
                    r--  ro

                    o  6

Appendix B


Related Publications
 EPA has published many coal mine methane reports, including:

 Technical and Economic Assessment of Coal Mine Methane Use in Coal-Fired Utility and
 Industrial Boilers in Northern Appalachia and Alabama, April 1998. Provides information about
 potential opportunities of cofiring coal mine methane in coal-fired utility and industrial boilers.

 White Paper: The Impacts of FERC Order 636 on Coal Mine Gas Project Development, March 1998.
 Provides information about opportunities for coal mine methane use resulting from the passage of FERC
 Order 636.

 Identifying Opportunities for Methane Recovery at U.S. Coal Mines: Draft Profiles of Selected
 Gassy Underground Coal Mines - Office of Air and Radiation, September 1997. Provides information
 about specific opportunities to develop methane recovery projects at large underground coal mines in the
 United States.

 A Guide to Financing Coalbed Methane Projects - Office of Air and Radiation, January 1997
 Addresses issues related to coalbed methane project finance.

 A Guide for Methane Mitigation Projects: Gas-to-Energy at Coal Mines - Office of Air and
 Radiation, February 1996. Provides guidance for developing programs to reduce methane emissions
 from coal mines through coal mine methane recovery and use.

 Finance Opportunities for Coal Mine Methane Projects: A Guide for West Virginia - Office of Air
 and Radiation, August 1995.  Provides information regarding financial assistance opportunities available
 in West Virginia.

 Finance Opportunities for Coal Mine Methane Projects: A Guide for Southwestern Pennsylvania -
 Office of Air and Radiation, June 1995. Provides information regarding financial assistance
 opportunities available in Southwestern Pennsylvania.

 Economic Assessment of the Potential for Profitable Use of Coal Mine Methane: Case Studies of
 Three Hypothetical U.S. Mines - Office of Air and Radiation, May 1995. Provides information on the
 economics of methane use.

 Finance Opportunities for Coal Mine Methane Projects: A Guide to Federal Assistance, March
 1996. Provides information regarding financial assistance opportunities available through federal

 Coalbed Methane Outreach Program Technical Options Series, October 1997 - July 1998. Provides
 information on how to maximize a coal mine's methane resource.
To order these reports, or to obtain a list of other coal mine methane publications, call
1-888-STAR-YES  (1-888-782-7937).

For More Information
To learn more about coal mine methane opportunities, please contact:
Coalbed Methane Outreach Program
U.S. EPA (6202J)
401 M Street, SW
Washington, DC 20460 USA
Tel:  (202) 564-9468 or (202) 564-9481
Fax:  (202) 565-2077

e-mail:      fernandez.roger@epa.gov
Internet:     www.epa.gov/coalbed
C  O  A  '
                                                   PROG  RAM