v°/EPA
United States Air and Radiation
Environmental Protection (6202-J)
Agency
430-R-98-007
April 1998
Technical and Economic
Assessment of Coal Mine
Methane in Coal-Fired
Utility and Industrial Boilers
in Northern Appalachia and
Alabama
o
M E
o u
p R
A
THAN
T R E A C H
O C R A M
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C O A
METHANE
OUTREACH
PROGRAM
Technical and Economic Assessment of
Coal Mine Methane in Coal-Fired Utility and
Industrial Boilers in Northern Appalachia
and Alabama
Coalbed Methane Outreach Program
Atmospheric Pollution Prevention Division
U.S. Environmental Protection Agency
April 1998
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COALBED METHANE OUTREACH PROGRAM
The Coalbed Methane Outreach Program (CMOP) is a part of the U.S. Environmental
Protection Agency's (U.S. EPA) Atmospheric Pollution Prevention Division. CMOP is a
voluntary program that works with coal companies and related industries to identify
technologies, markets, and means of financing profitable recovery and use of coal mine
methane (a greenhouse gas) that would otherwise be vented to the atmosphere.
CMOP assists the coal mine methane industry by profiling project opportunities at the nation's
gassiest mines, conducting mine-specific technical and economic assessments, and identifying
private, state, local and federal institutions and programs that could catalyze project
development.
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DISCLAIMER
This report was prepared for the U.S. Environmental Protection Agency (U.S. EPA). This
preliminary analysis uses publicly available information. U.S. EPA does not:
(a) Make any warranty or representation, expressed or implied, with respect to the
accuracy, completeness, or usefulness of the information contained in this report, or that
the use of any apparatus, method, or process disclosed in this report may not infringe
upon privately owned rights; or
(b) Assume any liability with respect to the use of, or damages resulting from the use of, any
information, apparatus, method, or process disclosed in this report.
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ACKNOWLEDGMENTS
This report was prepared under Environmental Protection Agency Contract 68-W5-0017
by Alternative Energy Development, Inc. (AED).
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Contents
1.0 INTRODUCTION AND BACKGROUND 1
2.0 BENEFITS OF COFIRING 3
2.1 MINIMAL PROCESSING 3
2.2 FLEXIBLE MARKETS 3
2.3 BENEFITS TO PURCHASER 3
2.3.1 Environmental Benefits 3
2.3.2 Operational Benefits 5
2.3.3 Carbon Offsets 6
3.0 SELECTION CRITERIA 8
3.1 REGIONS 8
3.2 PROJECT SCENARIOS 8
3.2.1 Mine to Power Plant Combinations 9
3.2.2 Mine to Industrial Boiler Combinations 9
4.0 TYPICAL PROJECT CONFIGURATION 12
5.0 ECONOMIC ANALYSIS 13
5.1 COFIRING IN UTILITY BOILERS 13
5.1.1 Illustrative Case #1: Bailey and Enlow Fork Mines to Hatfield's Ferry Power
Plant 13
5.1.2 Results of Other Utility Boiler Cofiring Cases 14
5.2 COFIRING IN INDUSTRIAL BOILERS 16
5.2.1 Illustrative Case #2: Enlow Fork, Bailey, Cumberland, and Emerald 1 to
PPG Industries 16
5.2.2 Results of Other Industrial Boiler Cofiring Cases 16
6.0 LIMITS TO THE ANALYSIS 18
7.0 CONCLUSION 19
APPENDIX A - MODELING ASSUMPTIONS A-1
APPENDIX B - MINE TO UTILITY BOILER ECONOMIC ANALYSIS B-1
APPENDIX C - MINE TO UTILITY BOILER MAPS C-1
APPENDIX D - MINE TO INDUSTRIAL BOILER ECONOMIC ANALYSIS D-1
APPENDIX E - MINE TO INDUSTRIAL BOILER MAPS E-1
APPENDIX F - REFERENCES F-1
APPENDIX G - CMOP CONTACT INFORMATION G-1
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1.0 INTRODUCTION AND BACKGROUND
Coal mine methane (CMM) emissions are those that directly result from coal mining and
occur as the following general types:
• Fumigant, the very dilute mixture of CMM in air that flows out of mine ventilation
systems.
• High-grade CMM suitable for injection into natural gas pipelines.
• Gob gas, normally a mixture of CMM and air from active and abandoned mines,
although gob gas may be almost all methane in certain cases.
Although there are currently few options for using fumigant, one that will benefit power
production facilities is its use as combustion air in internal combustion engines and gas
turbines. Researhc is ubderway to find other markets for fumigant. The coal mining
industry has made good progress in delivering high-grade CMM to natural gas markets.
Using gob gas has proven more challenging, although pioneers in the coal, gas, and
power industries also have identified several potentially beneficial gob gas uses, as
listed below.
• Fuel for coal dryers and other gas-fueled mine equipment.
• Fuel for electrical production.
• Feedstock for gas enrichment systems that upgrade the gas to pipeline quality.
• Supplemental fuel for industrial and utility boilers (delivered in dedicated pipelines).
The last option is the subject of this U.S. Environmental Protection Agency (U.S. EPA)
report. Since gob gas (as well as any medium- to high-quality methane) may be cofired
with the primary fuel in a variety of existing combustion units including boilers, furnaces,
and kilns, it can partially replace common fuels (e.g. coal, oil, and natural gas). The fuel
that cofired gob gas replaces is referred to herein as "avoided" fuel. Cofiring gob gas, as
explained in the next section, can provide greater value to the buyer than that of the
avoided (replaced) primary fuel. This report refers to an "enhanced" gob gas value
which is the sum of the avoided fuel plus associated environmental and operational
benefits.
The report provides the following:
• A review of the benefits of cofiring.
• A methodology for selecting markets and cofiring projects that have the greatest
likelihood for technical and economic feasibility.
• An explanation of the key variables that determine whether or not a project may be
viable.
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• Two typical cases which appear to exhibit economic viability.
• A summary of several other potential cofiring scenarios for Northern Appalachia and
Alabama locations that appear to be feasible and economically attractive.
The purpose of this report is to acquaint potential coal mine operators and energy
project developers with the fundamentals of project selection of cofiring gob gas with
coal in utility and industrial boilers. These individuals should keep in mind that additional
in-depth searches may yield other potential opportunities. For example, a given project
may indicate a low return on investment until the developer secures an additional gob
gas supply from another nearby mine. Gob gas supplies and available cofiring
opportunities will both undergo change as time goes on, so a developer should not be
limited to the portfolio of projects suggested in this report.
The reader should also keep in mind that this report presents a screening-level
economic analyses based on publicly available data an d standard U.S. EPA
assumptions. The analysis described herein investigated the potential viability of CMM
cofiring. It foes not account for site-specific factors such as gathering well-field
configuration (with respect to compressor stations), geological factors affecting pipeline
placement, pipeline right-of-way availability, existing gas sales commitments uncertainty
of the economic life of a given boiler, etc. This report, therefore provides an illustrative
analysis to determine if future investigation is appropriate for specific settings. As is
detailed in Section 5, the analysis does reveal many CMM cofiring opportunities that
appear to warrant in-depth evaluation. U.S. EPA will be pleased to conduct a more
refined analysis of those potential opportunities if case-specific input data can be made
available.
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2.0 BENEFITS OF COFIRING
Cofiring with gob gas provides a project many benefits that are not available with other
potential uses (such as natural gas pipeline injection or electric power generation).
Cofiring markets would require less gas processing than do natural gas markets and are
normally very flexible (from an engineering viewpoint), allowing for fluctuations in gob
gas flow and quality. Benefits from gob gas cofiring accrue to energy buyers as well
(e.g. air pollution mitigation and operational improvements). The following sections
discuss various benefits of cofiring gob gas.
2.1 Minimal Processing
The major contaminants contained in gob gas are nitrogen, carbon dioxide, oxygen,
water, and particulate matter. Most boilers can accept all of these constituents with little
or no deleterious effects. Therefore, a project developer need not install expensive
processing systems to clean the fuel. Instead, the existing boiler system may require
only simple processing steps such as removing free moisture and particulates to protect
compressors, pipelines, and other components of the transport system.
2.2 Flexible Markets
A typical market for cofired gob gas will be a coal-fired boiler which operates most of the
available hours in a year. The gas will usually represent a minor portion of a facility's
total fuel requirements, so fluctuations in the quality and quantity of gob gas deliveries
will have little impact on operational stability. Modern boiler control systems can easily
adjust primary fuel feed rates to accommodate gas changes.
2.3 Benefits to Purchaser
The buyer of cofired gob gas, perhaps an operator of a utility or industrial coal-fired
boiler, may receive many advantages over and above the costs saved by not burning an
equivalent amount of primary fuel. The following sections discuss the environmental,
operational, and carbon offset benefits. Technical information on these benefits comes
from two undated reports published by the Gas Research Institute, U.S. EPA (1997a and
1997b, and Glickert (1997).
2.3.1 Environmental Benefits
The most important and valuable environmental benefits can be achieved by cofiring gob
gas in quantities that are small as compared with total boiler heat (Glickert 1997). The
benefits include reductions in NOx, SOx, and particulates (opacity):
• NOx Reduction. When properly configured and optimized, gob gas cofiring may be
able to reduce NOx emissions from the entire boiler. Glickert (1997) estimates that a
coal plant can achieve a NOx reduction of about 5.0 percent or more for each 1.0
percent of gas heat input using the Fuel Lean Gas Reburning method. For example,
using a methane cofiring rate of just 7 percent of total heat input, NOx emissions
were reduced by 40 percent in tests run at ComEd's Joliet Generating Station.
In addition to improving regional air quality, such reductions can offer substantial
monetary value to boiler operators. Glickert cites the potential economic benefits
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that gob gas cofiring could provide for NOx emitters in non-attainment zones after
U.S. EPA finalizes its proposal to tighten federal standards for ground-level ozone
(smog) in 22 eastern states.1 Because NOx is a precursor to ozone formation, any
method of significantly reducing NOx emissions will be worth many dollars per ton of
NOx abated. Some utilities located in ozone non-attainment regions will face NOx
offset costs between $500 and $1,500 per ton to comply with the new regulations.
Using the low end of that range and data on costs and operating details from a
typical cofiring case, Glickert calculated a value for NOx reduction from cofiring of
$0.56 per million British thermal units (mmBtu) of CMM used (see Exhibit 1).
The optimum range for Fuel Lean Gas Reburning is between about 2 and 8 percent
(methane) gas as a percent of total heat input (Glickert, 1997). Many of the
mine/plant pairings in this report are within that range, assuming 40 percent of mine
emissions are available for a cofiring project. Gob gas flows that exceed the 8
percent range will begin to create less NOx reduction per unit of input (mmBtu ).
Therefore, even though the boiler's emissions continue to decline as it consumes
more than 8 percent cofired methane, the effect diminishes on a per-unit basis,
resulting in a reduced NOx credit per mmBtu.
Exhibit 1
Sample Estimation of the Value of NOx Reductions Due to Cofiring
(Assuming that Each 1% of Fuel Input Contributed by methane Reduces NOx by 5%)
(from Glickert, 1997)
Given:
• Coal-fired 340 MW boiler.
• Heat rate 10,000 Btu/KWH, or 10 mmBtu per MWH.
• Baseline NOx emissions rate 0.45 Ib/mmBtu.
Tons NOx reduced per hour:
5% x 340MW x 10mmBtu/MWH x 0.45 Ib/mmBtu / 2000lb/ton = 0.03825 tons/hour
(This increment represents up to 335 tons of NOx during a full year.)
Value of reduction:
$5007 ton x 0.03825 tons/hour = $19.13/hour
Gas burned per hour:
1% x 340MW x 10mmBtu/MWH = 34mmBtu/hour
"NOx value" of cofired gob gas:
$19.13/hour / 34mmBtu/hour = $0.56/mmBtu
Please note that this example, like all others, contains case-specific parameters. Thus each case
will result in a different NOx reduction value per unit of cofired CMM.
1 U.S. EPA plans to issue final rules by September 1998.
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• SOx Reduction. Cofiring methane reduces SOx emissions. These reductions may
allow boiler operators to avoid SOx offset purchases, defer other abatement
strategies, or even sell the excess SOx credits above their allotment. Currently SOx
credits are worth about $100 per ton. Based on that value and case-specific cost
estimates, a utility would realize a credit of approximately $0.06 per mm Btu of gas
fired.
• Reduced Opacity. Utilities may be able to use gas to reduce stack opacity and
thereby avoid plant derating.
2.3.2 Operational Benefits
Utilities use cofired gas in small or large quantities to effect a variety of cost-effective
operational improvements (listed below). Not all of these benefits apply to every case.
Some benefits will only be available if the utility has access to more substantial CMM
quantities (7 to 8 percent or more) or is willing to purchase natural gas in large quantities
under certain conditions explained below.
• Improved Ash Quality. If a utility intends to sell its ash to the concrete industry to
avoid high disposal costs, gob gas cofiring may enhance this possibility by reducing
carbon levels in the ash to saleable limits. Further research is necessary to prove
this concept and to determine how much gob gas is required to cause meaningful
reductions. There may be another potential benefit from lower carbon in the flyash.
Utilities sometimes experience sparking problems in their electrostatic precipitators.
Studies show that gas cofiring may mitigate the condition.
• Derate Mitigation. If coal processing equipment inadequacies limit a boiler (either
during pulverizer or feeder outages or because the plant has been forced to use low-
sulfur coal that contains less heat per pound), gob gas use may mitigate the derating
condition by allowing more fuel to enter the boiler.
• Rating Increase. In some cases, a boiler's operating limit may be driven by its forced
draft fan rating, even though it may not have reached its total heat release capacity.
In this event, the operator may be able to cofire small increments of gob gas without
backing off the coal feed - thus ending up with an increased plant rating.
• Lower Turndown. If a boiler can rely primarily on gas during periods of low demand,
the minimum operating load can be reduced by almost half of its coal-fired minimum
(e.g. from 45 to 25 percent of full load). Having lower turndowns will result in fewer
shutdowns and reduced boiler start-up costs. Not only does gas retain its flame
stability at low loads, its heat rate is much better than coal in this range. To gain this
benefit, however, the boiler operator must have access to larger gas flows than are
typically available from a gob gas project.
• Reduction of Slag Buildup. Some utilities have fired gas in coal boilers for short
periods or continuously to remove harmful slag deposits. This removal strategy is
much less expensive than shutting the boiler down and mechanically removing the
deposits. As with the improved turndown ratio described above, however, an
operator must have access to an adequate gas supply.
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The following two benefits are intangible and probably minor:
• Increased Efficiency (Lower Heat Rate). Methane often burns in large coal boilers
with somewhat better combustion characteristics than the coal itself. This results in
a small efficiency gain that is partially offset by the need to evaporate the water
formed during methane combustion and the fact that the boilers were built to
maximize radiant heat transfer from coal and not gas.
• Reduced O&M Costs. There are many ancillary systems operating in a coal-fired
boiler that process, handle, and transport coal, as well as remove coal ash.
Theoretically, these systems will cost less to operate and maintain when gas is fired
as a partial substitute for coal because they are handling less coal. Potential cost
reductions from small gas inputs, however, are not proportional to the reduced coal
flow and are very hard to identify. For example, in actual practice it is probably
impossible to reduce plant payroll because of a 2 to 4 percent reduction in coal
throughput.
To accurately quantify the operational benefits discussed above, an analyst must have a
detailed knowledge of each boiler, its dispatch profile, it's location with respect to ozone
non-attainment zones, its operating history, etc. For the purposes of this report, the
analysis of gob gas cofiring options only takes credit for estimated NOx and SOx
benefits (in terms of dollars per mmBtu) plus an allowance to cover other possible
credits that a typical plant operator would recognize and acknowledge. Exhibit 2
represents an illustrative cofired CMM case with an enhanced valuation of $0.70 per
mmBtu for operational improvements and SOx and NOx reductions plus the value of the
avoided coal.
Exhibit 2: Sample Valuation of CMM when Cofired with Coal
$2.50 -i
$2.00
^^^^"
1 ' \ ^ * *
; ,;t :\; X
* v i
„ ' > , i
' f , <•*
1
• Value of Operational
Improvement -$0.09
D Value of SOx Reduction -
$0.06
D Value of NOx Reduction -
$0.55
• Value of Coal (Avoided)
per mmBtu -$1.30
2.3.3 Carbon Offsets
Another type of benefit that has the potential to enhance cofired gob gas' value to future
buyers relates to the reduction of greenhouse gas emissions. These emission
reductions accrue from beneficially using gob gas instead of venting it to the
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atmosphere. Because methane has approximately 21 times the global warming effect of
carbon dioxide, on the basis of weight (IPCC, 1995), gob gas cofired projects have the
potential for significant reduction of greenhouse gas emissions. For example, a project
that consumes 6 million cubic feet per day (mmcfd) of CMM would eliminate the
equivalent of 0.976 million tons of carbon dioxide per year. When a project developer
sells gob gas to a boiler operator, therefore, the sale may carry the option of owning
substantial present and future carbon offsets.
One greenhouse gas emissions trade that has broken new ground is between Niagara
Mohawk Power Corp., a New York electric utility, and Suncor Energy Inc., a Canadian oil
and gas company. The agreement, announced in March of 1998, contains options for
10 million tons of carbon dioxide reductions. It will help Suncor achieve its voluntary
greenhouse gas emission reduction targets, while providing Niagara Mohawk with
additional funding for new projects that will further reduce global concentrations of
greenhouse gases. The company's existing projects include power plant performance
improvements, use of less polluting fuels, and development of renewable energy
resources (EconSkip@aol.com, 1998).
It is widely expected that greenhouse gas offset trades will increase in frequency and
value in the future, either to sell on the open market or to allow the credit holder to emit
equivalent amounts of greenhouse gas elsewhere. It is beyond the scope of this report
to speculate on the value and timing of such credits.
7
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3.0 SELECTION CRITERIA
3.1 Regions
The report includes outcomes from a search throughout the Appalachian Region for
gassy underground mines that were near large coal-burning boilers. The search
identified three concentrations of gassy mines which were close enough to cofiring
markets to warrant further study. The selected sections (listed below) include parts of
the four states with the highest CMM emissions from underground mines in the country -
Alabama, Pennsylvania, Virginia, and West Virginia (U.S. EPA, 1997a).
Cofiring opportunities may exist in other mining regions, but the only one identified to
date is the Carbon Mine in Utah with its proximity to the Willow Creek Power Plant. This
report, however, focuses only on the Appalachian Region and Alabama.
3.2 Project Scenarios
The following are the steps and criteria used to select cofiring project scenarios for
further economic analysis.
1. Assembled a list of gassy coal mines with active drainage systems from emissions
data (U.S. EPA, 1997a).
2. Addressed areas where mines were adjacent to other mines, and combined
emissions from these mines to take advantage of markets with longer delivery
distances. Appendices C and E present maps that show the proximity of the mines to
the power plants and industrial boilers, respectively.
3. Used GASMAP (Argonne National Laboratory, 1997) to determine the approximate
location of the coal mines and large industrial and power plant boilers. GASMAP is a
computer database that identifies the locations of facilities involved in natural gas
production (including CMM), transportation, and use. GASMAP also provides data
on mines and boilers. The database allowed a good first cut in developing coal
mine/boiler combinations for analysis.
4. Used topographical maps from the U.S. Geological Survey to plot dedicated pipeline
routes from the mine to the boiler location. In general, the routes follow established
rights-of-way including existing pipelines, power lines, railroads, and roadways. To
the extent possible, selected routes avoid population centers, protected areas, and
major river and highway crossings. Once a route was determined, the analyst
evaluated the difficulty of the terrain and assigned a terrain factor, which typically
added 10 to 20 percent to the overall cost of the pipeline. In cases where the
pipeline crosses major rivers, such as the Ohio River, the analysis assumed the use
of existing bridges and added an allowance of $500,000 to the overall cost of the
pipeline.
5. Applied the following criteria to the list of boilers derived from GASMAP to develop a
short list of utility and industrial boilers that would have a realistic possibility of
success:
8
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• Each boiler must be close to the gob gas source to minimize pipeline transport
cost. This analysis assumed a maximum straight-line distance between each
mine and boiler pairing ratio of 5 miles per one mmcfd of CMM.2
• The boiler should operate as many hours per year as possible. Only boilers
fueled by coal remain on the utility list because they have a greater chance of
continuous operation. This is a difficult criterion to apply without data from actual
site interviews.
• The boiler should be large enough, at a minimum, to consume the entire gob gas
flow without decreasing the combustion efficiency of the unit. Because coal
plants are designed to burn coal, not gas, they cannot run entirely on gas.
Therefore, each coal boiler has a practical gas cofiring limit which is much less
than 100 percent of fuel input.
• A cofiring market should provide the highest possible value for the gob gas. That
should present no problem for gas and oil boilers. When gas displaces coal,
however, the gas value will be low unless coal displacement is in or near the 8
percent range in order to take full value of NOx rand SOx eduction credits.
3.2.1 Mine to Power Plant Combinations
The analysis used the above criteria to identify candidate power plants located
reasonably close to each mine and mine cluster. Utility power plant project scenarios
that met all criteria are listed in Table 1, and Section 5.1 presents a preliminary
economic analysis for an illustrative case. Appendix C contains maps showing the
locations of the possible scenarios. The reader should note that many other project
combinations are possible; those shown in this report are strictly illustrative.
3.2.2 Mine to Industrial Boiler Combinations
The task of selecting mine and industrial boiler cofiring scenarios proved to be
somewhat more complex because the boilers are normally smaller, they burn a variety of
fuels, and some markets are far from gob gas sources. Therefore, the analysis used
combinations where boilers were clustered together. A cluster of end-users allows the
developer to transport the gob gas more efficiently. In some of the selected cases, a
pipeline collects gob gas from several mines and distributes it to multiple end-users.
The end-users may be several miles apart, but the overall increased gas flow allows
transport across greater pipeline distances. Although the economic analyses of these
cases (in Section 5) show positive results, some of them should be viewed as
speculative because of the long distances involved, the multiple boiler owners that need
coordination, and the possibility that business conditions may reduce market capacity
unexpectedly.
2 It would be possible to save construction cost by using existing natural gas pipelines for
transport, but the cost of bringing the gob gas up to pipeline specifications may entail greater
expense than the necessary pipeline construction.
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Table 1
A Sampling of Mine to Utility Combinations
Region
Alabama
Mid-Appalachia
North-
Appalachia
Power Plant
Gaston
Gorgas
James Miller Jr
Clinch River
Glen Lyn
Kanawha
R E Burger
Cardinal
Elrama
Fort Martin
Harrison
Hatfield's Ferry
Kammer
Mitchell
Rivesville
WH Sammis
Toronto
Mine
Blue Creek 3/Oak Grove
Blue Creek 4, 5, 7
Blue Creek 3/Oak Grove
Blue Creek 4, 5, 7
Shoal Creek
Blue Creek 3/Oak Grove
Buchanan/VP 8
Buchanan/VP 8
Pinnacle 50
Bailey/Enlow Fork
McElroy
Bailey/Enlow Fork
Cumberland/Emerald
Bailey/Enlow Fork
Blacksville 2
Cumberland
Emerald 1
Federal 2
Cumberland/Emerald 1
Cumberland/Emerald plus
Bailey/Enlow Fork
Federal 2
Loveridge 22
Robinson Run 95
Federal 2/Robinson Run 95
Cumberland
Emerald 1
Federal 2
Cumberland/Emerald 1
Bailey/Enlow Fork
Cumberland/Emerald plus
Bailey/Enlow Fork
Bailey/Enlow Fork
McElroy
Bailey
Enlow Fork
Bailey/Enlow Fork
Blacksville 2
Federal 2
Loveridge 22
Bailey/Enlow Fork
Bailey/Enlow Fork
Estimated
Distance
(miles)
43.0
48.0
25.6
25.6
16.8
40.0
22.3
71.3
49.6
37.4
11.0
30.0
52.0
47.2
16.4
21.6
21.6
25.6
21.6
32.6
18.0
16.8
3.2
17.6
14.0
14.0
36.0
14.0
25.0
25.0
42.0
9.6
35.2
35.2
35.2
17.6
13.2
8.4
50.4
47.2
CMM Available @
40% Recovery
(mmcfd)
18.2
24.8
18.2
24.8
3.3
18.2
10.4
10.4
8.6
9.0
1.4
9.0
8.2
9.0
4.0
4.4
3.9
5.7
8.2
17.2
5.7
2.9
1.8
7.5
4.4
3.9
5.7
8.2
9.0
17.2
9.0
2.3
3.3
5.7
9.0
4.0
5.7
2.9
9.0
9.0
10
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A summary of selected industrial cofiring project scenarios appears in Table 2.
Appendix E also shows maps of these projects. Section 5.2 presents the economic
results.
Table 2
A Sampling of Mine to Industrial Boiler Combinations
Industrial Boilers
Alabama
Amoco, American
Fructose, Monsanto
North, Champion
Hunt Oil, Gulf States,
James River
U.S. Alliance
Northern Appalachia
PPG Industries
PPG Industries
Weirton Steel
Mine
Oak Grove, Shoal Creek,
Blue Creek 4, 5, 7
Blue Creek 4, 5, 7
Oak Grove, Shoal Creek
Blacksville 2, Loveridge,
Federal 2
Enlow Fork, Bailey,
Cumberland, Emerald 1
Enlow Fork, Bailey,
Cumberland, Emerald 1
Estimated
Distance
(miles)
112
89.2
54.0
48.8
32.0
47.2
CMM Available @
40% Recovery
(mmcfd)
36.7
24.8
11.9
12.6
17.2
17.2
11
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4.0 TYPICAL PROJECT CONFIGURATION
A typical project will begin in the gathering lines, just downstream of each wellhead. The
mine operator is responsible for establishing and maintaining the wells. The CMM
developer connects gathering lines to a central pipeline and uses satellite compressors
to transport the gob gas to a processing facility. The gob gas goes through water
separation and dehydration units and enters a sales compressor that has sufficient
pressurization to bring the gob gas through a dedicated buried pipeline to its destination.
At the industrial or utility plant site, the gob gas enters a gas feed system and is injected
into a fossil fuel-fired boiler. The project's capitalization includes the boiler retrofit.
Exhibit 3 presents a simplified project scenario.
Exhibit 3
Typical Project Configuration
Gas Sales
Gob Processing Compressor Retrofitted
Wells Boiler
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5.0 ECONOMIC ANALYSIS
A preliminary cash flow model computed the internal rate of return (IRR) and net present
value (NPV) for each selected cofiring scenario. Each analysis includes a summary table
with all of the parameters for each power plant - mine combination, and a separate table
showing cash flows over an assumed 10-year project life. The parameters table is linked to
the spreadsheet allowing a sensitivity analysis to be performed by changing the input values.
Capital and operating cost estimates, financial assumptions, and other project parameters
that went into the model are summarized in Appendix A. It must be emphasized that the cost
parameters assumed for this report are only approximations and reasonable assumptions
that are appropriate for the screening model. A potential developer must revise each of the
estimates using case-specific data.
To compute annual revenue for each project, the model assumes the plant is in a non-
attainment region. It uses a first-year sales price of $2.00 (and below) per mmBtu of cofired
gas when gob gas replaces coal, or a somewhat higher rate when gob gas replaces oil or
natural gas or a mixture of all three fossil fuels. Appendix A includes the price worksheet for
coal boilers which takes into account that NOx credits diminish as a function of methane
inputs that are above 8 percent of total fuel.
5.1 Cofiring in Utility Boilers
5.1.1 Illustrative Case #1: Bailey and Enlow Fork Mines to Hatfield's Ferry Power Plant
The Bailey and Enlow Fork Mines, operated by a subsidiary of CONSOL Coal Group,
are located in Greene County, Pennsylvania. In 1996, the mines produced
approximately 16.2 million tons of steam coal from the Pittsburgh seam. U.S. EPA
estimates that the mines emit about 22.5 mmcfd of CMM, of which about 40 percent is
drained. The cofiring case assumes that this 40 percent, or 9.0 mmcfd of CMM would
be available for sale to a nearby coal-fired boiler.
The Hatfield's Ferry plant, owned by Appalachian Power Systems (APS), may be a
viable market candidate for gob gas from these mines. Hatfield's Ferry is located on the
west bank of the Monongahala River, about 25 miles from Bailey and Enlow Fork along
an assumed route plotted for this analysis (see map in Appendix C). The analysis
assumes that terrain will add 10 percent to the cost of the dedicated pipeline, which is
computed at $25 per foot. The Hatfield's Ferry coal-fired units are rated at 576 MW,
large enough so retrofitting only one boiler with gas-firing capability would still keep the
CMM-to-total-fuel ratio below 8 percent in order to qualify for the assumed enhanced
CMM price of $2.00.
Appendix B contains the input table and cash flow analysis for the Bailey/Enlow Fork -
Hatfield's Ferry case. It shows a project capital cost of $9.9 million which includes $3.6
million for the dedicated pipeline, $1.7 million for the boiler retrofit, and a 15%
contingency factor. The preliminary analysis produced an IRR of 34.8% and an NPV of
$13.6 million which should attract developer interest.
Another version of the Bailey/Enlow Fork - Hatfield's Ferry case would include gob gas
from the either the Cumberland or the Emerald No.1 Mine, or both. Due to the additional
fuel available, and the fact that these mines are located near the pipeline route to
13
-------
Hatfield's Ferry, the version combining gob gas from all four mines yields a significantly
higher IRR (see Table 3).
5.1.2 Results of Other Utility Boiler Cofiring Cases
Table 3 presents the preliminary financial results of other possible utility cases.
The results, as expressed by each case's IRR, fall into three general categories:
• 21 economically attractive cases (i.e., after-tax IRR above 25 percent).
• 17 marginally attractive cases (i.e., after-tax IRR above 15 but below 25 percent).
• 2 unattractive cases (i.e., after-tax IRR below 15%).
Each of the 40 utility boiler results shows the effect of mathematical relationships that
are largely dependent on three parameters:
• Length of pipeline. A longer pipeline impacts the project by increasing costs
associated with pipeline construction, higher sales compressor lease, and line and
equipment maintenance.
• Quantity of gob gas flow. A higher flow means more revenue, but it also means that
the gathering and transportation costs will rise, albeit at a lower rate.
• Gob gas price. A project that can replace a higher-priced fuel such as natural gas
provides greater revenue than one that replaces coal, and the effect on IRR may be
dramatic. This impact shows clearly when one compares the two cases involving
CMM from Enlow Fork, Bailey, Cumberland, and Emerald 1. The project with the
lower fuel price assumption, PPG Industries, has a lower IRR even though it is closer
to the mines than the Weirton Steel case where the composite fuel price is about 50
percent higher.
14
-------
Table 3
Mines to Utility Boilers Financial Results
Region
Alabama
Mid-
Appalachia
North-
Appalachia
Power Plant
Gaston
Gorgas
James Miller Jr
Clinch River
Glen Lyn
Kanawha
R E Burger
Cardinal
Elrama
Fort Martin
Harrison
Hatfield's Ferry
Kammer
Mitchell
Rivesville
WH Sammis
Toronto
Mine
Blue Creek 3/Oak Grove
Blue Creek 4, 5, 7
Blue Creek 3/Oak Grove
Blue Creek 4, 5, 7
Shoal Creek
Blue Creek 3/Oak Grove
Buchanan/VP 8
Buchanan/VP 8
Pinnacle 50
Bailey/Enlow Fork
McElroy
Bailey/Enlow Fork
Cumberland/Emerald 1
Bailey/Enlow Fork
Blacksville 2
Cumberland
Emerald 1
Federal 2
Cumberland/Emerald 1
Cumberland/Emerald
plus Bailey/Enlow Fork
Federal 2
Loveridge 22
Robinson Run 95
Federal 2/Robinson Run 95
Cumberland
Emerald 1
Federal 2
Cumberland/Emerald 1
Bailey/Enlow Fork
Cumberland/Emerald
plus Bailey/Enlow Fork
Bailey/Enlow Fork
McElroy
Bailey
Enlow Fork
Bailey/Enlow Fork
Blacksville 2
Federal 2
Loveridge 22
Bailey/Enlow Fork
Bailey/Enlow Fork
Estimatd
Distance
(miles)
43.0
48.0
25.6
25.6
16.8
40.0
22.3
71.3
49.6
37.4
11.0
30.0
52.0
47.2
16.4
21.6
21.6
25.6
21.6
32.6
18.0
16.8
3.2
17.6
14.0
14.0
36.0
14.0
25.0
25.0
42.0
9.6
35.2
35.2
35.2
17.6
13.2
8.4
50.4
47.2
IRR
(%)
37.2
43.0
46.3
50.2
23.7
38.3
39.6
18.7
22.1
27.0
11.7
31.7
22.0
24.6
23.4
22.8
19.8
24.6
36.0
44.3
27.6
16.1
16.9
34.0
27.7
24.4
20.2
37.7
34.8
44.3
26.0
25.8
12.8
22.8
29.5
23.9
33.1
31.5
23.6
20.7
NPV
($000)
25,745
37,415
28,361
36,568
3,749
28,680
16,949
7,371
8,242
10,409
321
12,842
8,538
9,614
4,530
4,880
3,646
6,666
12,719
28,108
7,342
1,916
1,367
11,043
5,837
4,603
5,356
11,588
13,574
29,087
10,084
2,766
1,146
6,175
11,151
3,648
6,318
3,482
10,104
6,404
15
-------
5.2 Cofiring in Industrial Boilers
5.2.1 Illustrative Case #2: Enlow Fork, Bailey, Cumberland, and Emerald 1 to PPG
Industries
Enlow Fork and Bailey, operated by a subsidiary of CONSOL Coal Group, and
Cumberland and Emerald 1, operated by a subsidiary of Cyprus Amax, are located
within approximately 11 miles of each other in Greene County, Pennsylvania. In 1996,
the mines produced a total of 24.6 million tons of coal and emitted 43.1 mmcfd of CMM,
of which about 14.5 mmcfd was drained. Based on an assumption of 40 percent CMM
recovery, this analysis estimated that 17.2 mmcfd will be available for sale to an
industrial boiler.
PPG Industries operates a production plant located about 32 miles west of the mines
(see map in Appendix E). The analysis assumes a terrain factor of about 19 percent to
be added to the cost of the dedicated pipeline which is computed at $25 per foot. PPG
Industries' power plant has three coal-fired units totaling 108 MW. To use all the gob
gas available from this project the developer would have to retrofit all three boilers.
Because the gas-to-total-fuel ratio is well over 8 percent (it is about 66.4 percent, see
Appendix D), the environmental benefits are worth somewhat less on a unit basis as
discussed in Section 2.3.1. Table A-3 in Appendix A calculates a CMM sales price of
$1.53 per mmBtu for a CMM-to-total-fuel ratio in the 61 to 70 percent range.
Appendix D contains the input table and cash flow analysis for the Enlow Fork, Bailey,
Cumberland, and Emerald 1 to PPG Industries case. It shows a project capital cost of
$12.4 million which includes $5 million for the dedicated pipeline and a 15% contingency
factor. Additionally, a 15% contingency factor is applied to the operating cost for all of
the industrial boiler cases because they tend to involve more entities and uncertainty,
and may require greater management costs. The preliminary economic analysis
indicated an IRR of 36.7 % and an NPV of $18.6 million.
5.2.2 Results of Other Industrial Boiler Cofiring Cases
Table 4 presents the preliminary financial results of six industrial cases analyzed by the
screening model. Three are located in Alabama and three are in the Pennsylvania -
West Virginia region.
16
-------
Table 4
Mines to Industrial Boilers
Financial Analysis
Industrial
Boilers
Alabama
Amoco, American
Fructose, Monsanto
North, Champion
Hunt Oil, Gulf States,
James River
Kimberly-Clark
Northern Appalachia
PPG Industries
PPG Industries
Weirton Steel
Mines
Oak Grove, Shoal Creek,
Blue Creek 4, 5, 7
Blue Creek 4, 5, 7
Oak Grove, Shoal Creek
Blacksville 2, Loveridge,
Federal 2
Enlow Fork/Bailey,
Cumberland/Emerald 1
Enlow Fork/Bailey,
Cumberland/Emerald 1
Estimted
Distance
(miles)
112
89.2
54.0
48.8
32.0
47.2
IRR
(%)
47.1
39.9
18.4
25.2
36.7
46.7
NPV
($thousands)
66,735
34,808
4,852
10,627
18,565
33,073
The results, as expressed by each case's IRR, fall into two general categories:
• 5 economically attractive cases (i.e., after-tax IRR above 25 percent).
• 1 marginally attractive case (i.e., after-tax IRR above 15 but below 25 percent).
As with the utility boiler cases, the industrial cofiring cases are heavily influenced by the
same three major factors: length of pipeline, quantity of CMM flow, and sales price.
17
-------
6.0 LIMITS TO THE ANALYSIS
One must view the results of the screening model as very preliminary, partially due to
the fact that little direct (site-specific) information was available on which to base the
cases. Instead, this analysis applied best-case assumptions to see if the results
warranted further analysis. Many cases fall into that category and are candidates for
further attention using more refined input data.
Some analytical uncertainties include:
• Scale. Many industrial boiler cases, especially in Alabama, tended to exceed the
scale of more typical, small-scale, dedicated pipe projects from which the simple cost
estimating techniques and rules of thumb used in this analysis derive.
• Complex Pipelines. Not only are the pipelines quite long, but there are complexities
brought about by clustering of both gob gas producers and industrial users. For
example, the only section of line that contains gob gas flowing at full capacity is from
the last mine to the first user. The less-used sections at either end may cost more
per mmBtu. More estimating work is necessary to reduce this potential analytical
uncertainty to an acceptable level.
• CMM Availability. All of the potential cases assume available CMM flows of 40
percent of the total 1996 volume of CMM liberated (ventilation emissions plus CMM
drainage). This CMM may already be in use. Jim Walter Resources mines, for
example, sell about 46 percent of the volume of CMM liberated according to a U.S.
EPA report (U.S. EPA, 1997a). This is true to a lesser extent at some of the other
mines.
18
-------
7.0 CONCLUSION
This preliminary report shows that a substantial number of economically viable CMM
cofiring projects may exist in Appalachia and Alabama. U.S. EPA hopes that mine
operators and developers will consider these potentially profitable project options.
Technical Advantages
Gob gas is a fuel that is well suited for cofiring with a primary fuel (e.g., coal, oil, and
natural gas) in a variety of existing combustion units including boilers, furnaces, and
kilns.
Gob gas cofiring offers a project many benefits:
• Only modest processing is required.
• Markets may tolerate fluctuations in flow and quality
• Cofiring yields operational benefits.
• Cofiring yields substantial NOx and SOx reductions.
Project Economics
These benefits plus the technical simplicity of a cofiring system result in opportunities for
many feasible and potentially profitable projects. The major characteristics of a
successful project are:
• Proximity between the mine and boiler.
• Substantial gob gas flows.
• Reasonable value for the CMM.
Potential Projects
A preliminary economic screening performed for this report shows that over half of the
46 projects examined would yield internal rates of return of over 25 percent. Many other
project possibilities may be feasible.
Potential for Development
An alternative energy project developer normally requires assurance that a project can
pass three tests. It must be technically feasible, economically viable, and practical to
install. Many, but not all, candidate gob gas cofiring projects will meet those tests:
1. Cofiring gob gas is technically uncomplicated and very feasible, and many projects
using natural gas, landfill gas, and other fuels have fully demonstrated the concept.
19
-------
2. Economic analyses in this report demonstrate that cofiring projects can be very
profitible if the pipeline distance is proportional to the flow of CMM and the market
price is fair. Using conservative cost and revenue projections, most of the projects
studied indicated strong after-tax returns on investment.
3. In many cases, the cofiring technique can be quite practical and have a good chance
of success. If the developer can secure rights-of-way for the dedicated pipeline,
obtain a substantial and steady flow of CMM, and negotiate a realistic price for the
fuel, there may be few barriers to implementation. If, however, the pipeline must
pass through many land parcels, gas flows are inadequate or not secure, or energy
customers are unwilling to pay full value for the fuel, the project will face an uncertain
future.
The reader is invited to make use of the report by:
• Using the methodologies presented and applying them to new mine-boiler
combinations.
• Modifying the profiled cases with more accurate data and more realistic system
configurations.
U.S. EPA welcomes inquiries from potential developers and is available to support
further analysis of these projects within its capabilities and charter. For example, to
benefit project developers, U.S. EPA offers assistance in using the model developed for
this report to analyze actual field data and or in running sensitivity analyses on key
parameters.
See Appendix G for more information.
20
-------
APPENDIX A
MODELING ASSUMPTIONS
A-1
-------
APPENDIX A
This appendix provides a brief explanation of the steps involved in analyzing candidate
cofiring cases. Tables A-1 through A-4 list specific data, assumptions, and formulae
used in the model.
Model
The analysis employed a very simple Excel spreadsheet model for the utility cofiring
cases and modified it slightly for the industrial boiler cases. Each model consists of an
input table and an associated discounted cash flow analysis. The tables and cash flow
analyses are linked electronically so that changes to any input parameter will recalculate
the IRR and NPV. Where several gob gas sources are cofiring candidates for a single
energy market, they are grouped onto one table, and each individual cash flow follows
sequentially on the same worksheet.
Data Input
To apply the models, data is input as follows:
• First, enter the assumptions shown in Table A-1. These normally remain constant
throughout the development of all cases unless there are special circumstances or
the analyst possesses actual field data.
• Next, enter the CMM flow and distance data found in Tables 1 and 3 from the report.
Knowing the daily CMM flow determines the appropriate value for the number of
satellite compressors, water separation, and dehydration units from Table A-2.
Other required data include boiler sizes, terrain factors, and the price of displaced
natural gas or oil. When coal is the displaced fuel, use Table A-3 to find the
appropriate enhanced fuel value which includes potential and operational credits. In
some cases this analysis assumed the retrofit of a second or third boiler to keep the
fuel replacement ratio below 8 percent to maximize the NOx credit.
Sales Compressor Power
The calculations for pressure drop in the dedicated pipeline and the horsepower needed
to transport the gob gas are shown in Table A-4. These computations are more complex
and were carried out separately from the model. The analysis solved for total
horsepower for all stages and divided by 800, the nominal size of the assumed
compressor unit. After rounding up to the nearest integer, the number of units was
entered into the cases.
Results
The resulting IRR's and NPV's are presented at the bottom of the cash flow sheets.
Observing when the cumulative cash flow changes to a positive indicates Payback,
expressed in years.
A-2
-------
Table A-1
Modeling Assumptions for Cofired Boiler Model
(Assumptions Based on U.S. EPA Estimates and Reasonable Allowances)
Item
Gas Quality
Capital Cost Assumptions
Project Development
Cost
Gathering Lines
Satellite Gas
Compression
Gob Gas Upgrade
Monitoring and Metering
Pipeline to Sales
Compressor
Sales Compressor Site
Construction
Dedicated Pipeline
Boiler Conversion
Annual Operating Costs
Sales Compressors
Project Labor and
Operational Costs
Satellite Compressor
Operating Costs
Royalties
Compressor Fuel
Financial Information
Capital Source
Project Life
Inflation Rate
Depreciation
Taxation
NPV
Description
Range between 50% and 90% methane. Gas flow calculations use
a 75/25 methane/air blend.
Fixed cost regardless of project size. Includes all legal, engineering,
transaction, and other project development and financing costs.
High density polyethylene pipelines. Allowance of 30,000 feet of
pipe for each satellite compressor.
Compressors purchased. Approximately one satellite compressor
per 2.1 mmcfd recovered CMM.
Water and moisture are removed with water separation and
dehydration units. Each unit can treat approximately 4.2 and 3.5
mmcfd (CMM), respectively.
Allowance based on daily CMM flow.
Six inch high density polyethylene (HOPE). Allowance of 30,000
feet per project.
Capital costs include site preparation and installation of a power line
to the site.
Six inch steel pipe.
Assumed equal cost per MW for all boiler types. One boiler
converted unless more capacity required to remain below 8%
replacement limit to maximize NOx reduction credits.
See separate calculation for sales compressor power requirements.
Units are fueled with gob gas. Cost of each leased unit (about 800
hp) includes O & M costs. This rate is not escalated
Budgeted annual cost based on methane flow. Includes labor,
expenses, and overheads at both the mine and boiler plant.
Budgeted annual costs includes O & M costs.
Assumed as a percentage of gross revenue.
Gob gas at no cost to the project.
All equity, no debt.
1 0 years.
Four percent annually.
Straight line method over life of project.
Tax allowance is 40 percent of income net of depletion allowance
(includes state, local, and U.S. taxes).
Calculated at 10 percent.
Cost
N/A
$350,000.
$5.25/foot
$280,000/unit
$20,000/unit
$25,000/unit
$20,000/mmcfd
$6.50/foot
$60,000/unit
$25.00/foot
$3,000/MW
$10,100/month
$51,840/mmcfd
$18,000/unit
12.5%
0
N/A
N/A
N/A
N/A
N/A
N/A
A-3
-------
Table A-2
Compression and Processing Unit Assumptions
(Source: U.S. EPA Estimates)
Total Methane
Flow (mmcfd)
Greater Than:
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
Satellite
Compressor
1
1
1
2
2
3
3
4
4
5
5
6
6
7
7
8
8
9
9
10
10
10
11
11
12
12
13
13
14
14
15
15
16
16
17
17
18
Water Separation
Unit
1
1
1
1
1
2
2
2
2
3
3
3
3
4
4
4
4
5
5
5
5
6
6
6
6
7
7
7
7
7
8
8
8
8
9
9
9
Dehydration Unit
1
1
1
1
2
2
2
2
3
3
3
4
4
4
4
5
5
5
6
6
6
6
7
7
7
8
8
8
8
9
9
9
10
10
10
10
11
A-4
-------
Table A-3
Enhanced CMM Price as a Function of
Percent of Boiler Coal Input
(Source: U.S. EPA Estimates)
Methane Input
Range
(% of Total)
1 -7.99
8-12.99
13-20.99
21 -30.99
31 -40.99
41 -50.99
51-60.99
61 -70
Value of Coal
Replaced
(Avoided)
($/mmBtu)
1.30
1.30
1.30
1.30
1.30
1.30
1.30
1.30
EValue of SOx
Reduction and
Operational
Benefit
($/mmBtu)
0.14
0.14
0.14
0.14
0.14
0.14
0.14
0.14
Value of NOx
Reduction
Benefits
($/mmBtu)
0.56
0.41
0.29
0.19
0.15
0.12
0.10
0.09
Total Value of
Cofired Methane
($/mmBtu)
2.00
1.85
1.73
1.63
1.59
1.56
1.54
1.53
Table A-4
Formulae for Pressure and Horsepower
Of Sales Compressors
Formula
Formula
to
to
find
find
Pressure
Horsepower
Pi =
Hp =
[P22 + L
0.0838
* ((Q*G°'425)/(2826*D2J25))
K'1 * q * T *(CK
-1)
1.739-1 0.5
Where: P! = inlet pressure, psia
P2 = outlet pressure, psia
Q = gas flow rate in standard cubic feet per hour, scfh
G = specific gravity
L = pipeline length, feet
D = inside diameter, inches
Hp = horsepower per stage
q = volume flow rate in mmscf
T = gas temperature in degrees Rankine (520 stage 1; 553 other stages)
C = compression ratio (P outlet / P inlet)
K = (Cp/Cv - 1) / (Cp/Cv); (assumed Cp/Cv for 75 % gob gas = 1.325)
A-5
-------
APPENDIX B
MINE TO UTILITY BOILER ECONOMIC ANALYSIS
B-1
-------
Illustrative Case #1 - Parameters
Hatfield's Ferry Power Plant
Parameters
Methane Recovered
Gathering Infrastructure and Gob Gas Cleanup
Gathering Pipelines
Water Separation Units
Dehydration Unit
Satellite Compressor
Pipeline to Sales Compressor
Gob Gas Transport
Sales Compressor
Dedicated Transportation Line
Terrain Factor for Transport Line
Boilers
Coal Replacement
Boiler Size
No. of Boilers Converted
Royalty Payments
Inflation Rate
Tax Rate
Enhanced Gas Value
Capital Cost
Development Costs
Gathering Pipelines
Water Separation
Dehydration Unit
Satellite Compressors
Monitoring/Metering
Pipeline to Sales Compressor
Sales Compressor
Dedicated Transportation Line
Boiler Conversions
Subtotal
Contingency
Total
Units
mmcfd
mmcfy
feet
feet
feet
%/Bcf
MW
$/mmBtu
$/project
$/foot
$/Unit
$/Unit
$/Unit
$/mmcfd
$/Unit
$/Unit
$/Unit
$/MW
Unit Costs
350,000
5.25
20,000
25,000
280,000
20,000
6.50
60,000
25.00
3,000
15%
Mines
Bailey/En low
Fork
Combined
9
3,285
150,000
3
3
5
30,000
3
132,000
1.1
6.5%
576
1
12.5%
4%
40%
2.00
350,000
787,500
60,000
75,000
1,400,000
180,000
195,000
180,000
3,630,000
1,728,000
8,585,500
1 ,287,825
9,873,325
B-2
-------
Illustrative Case #1 - Cash Flow Analysis
Bailey/Enlow Fork to Hatfield s Ferry
Revenue ooo
Operating Costs
Satellite Compressor O&M 18,000 If/Unit
Sales Compressor Lease and Operation 121,200 VUnit
System Operations 51 ,840 $/mmcfd
Total Operating Costs
000
0
Gross Revenue
Capital Costs P.873)
Operating Costs
Royalty Payments
Gross Income
Depreciation Straight Line Method
Depletion Allowance
Net Income
Taxes
Cash Flow P.873)
Pay Back
NPV 13,574
IRR 34.8%
1
5,913
90,000
363,600
466,560
920,160
920
1
5,913
0
P20)
(739)
4,254
PS7)
P87)
2,379
P52)
3,302
(6,571)
2
6,150
93,600
363,600
485,222
942,422
942
2
6,150
0
P42)
(769)
4,438
P87)
P22)
2,529
(1,011)
3,427
(3,144)
3
6,396
97,344
363,600
504,631
965,575
966
3
6,396
0
P66)
(799)
4,630
P87)
P59)
2,684
(1 ,074)
3,557
413
4
6,651
101,238
363,600
524,817
989,654
990
4
6,651
0
(990)
(831)
4,830
PB7)
(998)
2,845
(1,138)
3,692
4,105
5
6,917
105,287
363,600
545,809
1,014,696
1 ,015
5
6,917
0
(1 ,015)
(865)
5,038
(987)
(1 ,038)
3,013
(1 ,205)
3,833
7,937
6
7,194
109,499
363,600
567,642
1,040,740
1,041
6
7,194
0
(1,041)
(899)
5,254
(987)
(1 ,079)
3,188
(1 ,275)
3,979
11,916
7
7,482
113,879
363,600
590,347
1 ,067,826
1,068
7
7,482
0
(1 ,068)
P35)
5,479
P87)
(1,122)
3,369
(1 ,348)
4,131
16,048
8
7,781
118,434
363,600
613,961
1,095,995
1,096
8
7,781
0
(1 ,096)
P73)
5,712
P87)
(1,167)
3,558
(1 ,423)
4,289
20,337
g
8,092
123,171
363,600
638,520
1,125,291
1,125
9
8,092
0
(1 ,125)
(1,012)
5,956
P87)
(1,214)
3,754
(1 ,502)
4,454
24,791
10
8,416
128,098
363,600
664,860
1,155,758
1,156
10
8,416
0
(1 ,156)
(1 ,852)
6,208
P87)
(1 ,262)
3,959
(1 ,583)
4,625
29,416
B-3
-------
APPENDIX C
MINE TO UTILITY BOILER MAPS
C-1
-------
Mine to Utility Boiler Maps
Mississippi
Georgia
,'i' Gorgas •
,' Blue Creek No. 3 4
• Blue Creek No. 4, 5, and 7
^ James H Miller Jr
t Oak Grove, Shoal Creek
A ^ E C Gaston
Alabama
utility
Mine
1 inch = 50 miles
WH Sammis J^
Toronto •
Cardinal!
Ohio
Kammer/'X
RE Burger 1
Pennsylvania
Elrama
Dilworth
t Maple Creek
Enlow Fork
Cumberland, Emerald No. 1
McEIy
Bailey
Hatfield's Ferry
Utility
Mine
Fort Martin
Blacksville No.2
*
Federal No. 2, Loveridge No. 22 I Rivesville
t Robinson Run No. 95
Harrison J. t Shoemaker
West Virginia
Maryland
1 inch = 24 miles
C-2
-------
Mine to Utility Boiler Maps
Kentucky *
Kanawha
West Virginia
Pinnacle No. 50
Buchanan No.1
VPNo. 8
Clinch River
Virginia
Glen Lyn
1 inch = 24 miles
C-3
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APPENDIX D
MINE TO INDUSTRIAL BOILER ECONOMIC ANALYSIS
D-1
-------
Illustrative Case #2 - Parameters
PPG Industries
Parameters
Methane Recovered
Gathering Infrastructure and Gob Gas Clean Up
Gathering Lines
Water Separation Units
Dehydration Units
Satellite Compressors
Pipeline to Sales Compressor
Gob Gas Transport
Sales Compressors
Dedicated Pipeline
(diameter)
Terrain Factor for Transport Line
Boilers
Coal Replacement
Total Boiler Size
Royalty Payments
Inflation Rate
Tax Rate
Enhanced CMM Value
Capital Cost
Development Costs
Gathering Pipelines
Water Separation
Dehydration Unit
Satellite Compressor
Monitoring/Metering
Pipeline to Sales Compressor
Sales Compressor
Dedicated Transportation Line
Boiler Conversions
Units
mmcfd
mmcfy
feet
each
each
each
feet
each
feet
inches
%
MW
$/mmBtu
$/project
$/foot
$/Unit
$/Unit
$/Unit
$/mmcfd
$/foot
$/Unit
$/foot
$/MW
Subtotal
Contingency
Total
Unit Costs
350,000
5.25
20,000
25,000
280,000
20,000
6.50
60,000
25.00
3,000
15%
Mines
Enlow Fork/Bailey,
Cumberland/Emerald
17.2
6,278
270,000
5
5
9
30,000
6
168,960
6
1.19
66.4%
108
12.5%
4%
40%
1.53
350,000
1,417,500
100,000
125,000
2,520,000
344,000
195,000
360,000
5,026,560
324,000
10,762,060
1,614,309
12,376,369
D-2
-------
Illustrative Case #2 - Cash Flow Analysis
Enlow Fork/Bailey, Cumberland/Emerald Mines -
PPG industries
Revenue ooo
Operating Costs
Satellite Compressor O&M 18,000 (/Unit
Sales Compressor Lease and Operation 121,200 (/unit
System Operations 51 ,840 (/mmcfd
Subtotal
Contingency 15%
Total
000
0
Gross Revenue
Capital Costs (12,376)
Operating Costs
Royalty Payments
Gross Income
Depreciation Straight Line Method
Depletion Allowance
Net Income
Taxes
Cash Flow (12,376)
Pay Back
IMPV 18,565
IRR 36.7%
2
8,991
168,480
727,200
927,314
1,822,994
273,449
2,096,443
2,096
2
8,991
0
(2,096)
(1,124)
5,770
(1 ,238)
(1 ,349)
3,184
(1 ,274)
4,497
(3,556)
3
9,350
175,219
727,200
964,406
1,866,826
280,024
2,146,850
2,147
3
9,350
0
(2,147)
(1,169)
6,035
(1 ,238)
(1 .403)
3,394
(1 ,358)
4,677
1,121
4
9,724
182,228
727,200
1,002,983
1,912,411
286,862
2,199,272
2,199
4
9,724
0
(2,199)
(1,216)
6,309
(1 ,238)
(1 ,459)
3,613
(1 ,445)
4,864
5,985
5
10,113
189,517
727,200
1,043,102
1,959,819
293,973
2,253,792
2,254
5
10,113
D
(2,254)
(1 ,264)
6,595
(1 ,238)
(1,517)
3,841
(1 ,536)
5,059
1 1 ,044
6
10,518
197,098
727,200
1,084,826
2,009,124
301 ,369
2,310,492
2,310
6
10,518
0
(2,310)
(1,315)
6,893
(1 ,238)
(1 ,578)
4,077
(1,631)
5,262
16,305
7
10,938
204,982
727,200
1,128,219
2,060,401
309,060
2,369,461
2,369
7
10,938
0
(2,369)
(1 ,367)
7,202
(1 ,238)
(1,641)
4,323
(1 ,729)
5,472
21 ,778
a
1 1 ,376
213,181
727,200
1,173,348
2,113,729
317,059
2,430,788
2,431
8
1 1 ,376
0
(2,431)
(1 ,422)
7,523
(1 ,238)
£1 ,706)
4,579
(1 ,832)
5,692
27,469
9
1 1 ,831
221 ,708
727,200
1,220,282
2,169,190
325,379
2,494,569
2,495
9
1 1 ,831
0
(2,495)
(1 ,479)
7,858
(1 ,238)
(1 ,775)
4,845
(1 ,938)
5,919
33,389
10
12,304
230,577
727,200
1,269,093
2,226,870
334,030
2,560,900
2,561
10
12,304
0
(2 ,561)
(1 ,538)
8,205
(1 ,238)
(1 ,846)
5,122
(2,049)
6,157
39,545
D-3
-------
APPENDIX E
Mine to Industrial Boiler Maps
E-1
-------
Mine to Industrial Boiler Maps
Ohio
Weirton Steel
1 Boiler
# Mine
Enlow Fork/Bailey
*
PENNSYLVANIA
Cumberland/Emerald 1
Blacksville No. 2
Federal 2
Loveridge
WEST VIRGINIA
MARYLAND
1 inch = 20 miles
Mississippi
1 inch = 50 miles
Champion
Amoco X
American Fructose
Monsanto North
Oak Grove/Shoal Creek
Blue Creek No. 4,5,7
1 Kimberly-Clark
1 Hunt Oil
Alabama
1 Gulf States
James River
E-2
-------
APPENDIX F
REFERENCES
F-1
-------
REFERENCES
Argonne National Laboratory. 1997. GASMAP. Argonne, Illinois. January.
Econskip@aol.com, March 6, 1998.
Gas Research Institute. Cofiring Case Studies: Competing in a Changing Market. Chicago IL.
Gas Research Institute. Reburning Case Studies: Complying with Emissions Regulations.
Chicago IL.
Glickert, Roger. 1997. Information on Boiler Cofiring Opportunities: Letter Report to AED.
Energy Systems Associates. September 10.
IPCC (Intergovernmental Panel on Climate Change). 1992. Climate Change 1992: The
Supplementary Report to the IPCC Scientific Assessment. Cambridge University Press.
Cambridge, United Kingdom.
U.S. EPA (U.S. Environmental Protection Agency). 1997a. Identifying Opportunities for Methane
Recovery at U.S. Coal Mines: Draft Profiles of Selected Gassy Underground Coal Mines. Office
of Air and Radiation. (6202J). EPA 430-R-97-020. September.
U.S. EPA (U.S. Environmental Protection Agency). 1997b. EPA Coalbed Methane Outreach
Program Technical Options Series, COFIRING COAL MINE METHANE IN COAL-FIRED
UTILITY AND INDUSTRIAL BOILERS. Office of Air and Radiation. (6202J). Draft report,
September.
F-2
-------
APPENDIX G
CMOP CONTACT INFORMATION
G-1
-------
CMOP CONTACT INFORMATION
CMOP can offer technical expertise to analyze specific cofiring cases for gob gas producers interested in
estimating gas valuations. To obtain such technical assistance, or for more information on coal mine
methane recovery experiences, project potential, a full listing of reports, or program activities and
accomplishments, contact::
Coalbed Methane Program Manager
U.S. Environmental Protection Agency
Atmospheric Pollution Prevention Division
401 M Street, SW(6202-J)
Washington, DC 20460
Facsimile: 202565-2077
Email: fernandez.roger@epa.gov
schultz.karl@epa.gov
Homepage: http://www.epa.gov/coalbed
To Order Documents: Call 1-888-STAR-YES
G-2
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