cvEPA
United States
Environmental Protection Agency
Agency
Air and Radiation
(6202 J)
EPA/430-R-95-006
May 1995
Economic Assessment of
the Potential for Profitable
Use of Coal Mine Methane:
Case Studies of Three
Hypothetical U.S. Mines
PUBLIC REVIEW DRAFT
-------
Table of Contents
Page #
Introduction 1
Case Studies of Hypothetical Mines
Sample Mine A 7
Sample Mine B ,. . 13
Sample Mine C 19
Conclusion 25
Appendix A: Calculations and Assumptions Used in the Sample Mine Assessments .... A-1
Appendix B: List of Gassy U.S. Coal Mines B-1
Information About the Coalbed Methane Outreach Program C-1
-------
Introduction
Methane recovery and utilization can be a profitable undertaking for many large and
gassy underground coal mines. Eleven U.S. mines have already developed projects involving
the sale of recovered methane to pipeline companies, and at least one additional mine is
using recovered methane to generate electricity. While pipeline projects have been
developed at some of the gassiest mines in the U.S., there are at least 20 mines with high
methane emissions (greater than 3 million cubic feet per day) that have not yet developed
projects.
The purpose of this report is to provide information on the economics of methane
utilization and to demonstrate that utilization can be profitable for mines with high methane
emissions. This report presents economic assessments of the potential for profitable
utilization of methane using three hypothetical "Sample Mines." Each Sample Mine case
study presents an assessment of several different project options. While these three Sample
Mines are hypothetical, their defining characteristics (e.g., level of methane emissions, annual
coal production, degasification systems employed, and on-site electricity needs) are
representative of the characteristics of gassy U.S. mines that have not yet developed
utilization projects. Consequently, the economic results presented for these mines are
indicative of results that could be achieved by developing a project at a very gassy mine.
The first section of this report presents an overview and a comparison of the relevant
characteristics of each of the Sample Mines. The second section presents case studies
showing how an evaluation of potential project options was performed for each mine. A
general conclusions section follows the case studies. Appendix A of the report provides a
detailed description of the assumptions that were used in the economic assessments of each
of the Sample Mines. This Appendix may also be used by those interested in evaluating
costs of methane recovery for specific projects. Appendix B provides a list of mines in the
U.S. that have high methane emissions. Finally, the last section provides information about
the Coalbed Methane Outreach Program.
The Coalbed Methane Outreach Program prepared these Sample Mine case studies in
order to provide information to parties interested in developing coal mine methane projects or
in purchasing gas or electricity from such projects. One of the main goals of this report is to
facilitate the. development of a dialogue between mine operators and other entities that may
benefit by either investing in these projects or purchasing gas or electricity from them. By
showing that a preliminary assessment indicates that there are opportunities for profitable
utilization, this report may serve to stimulate interest in coal mine methane projects. Some of
the groups that may benefit from reading these assessments include:
• Operators of large, gassy coal mines that are evaluating the possibility of
developing utilization projects at their mines;
• Natural gas companies and pipeline companies interested in purchasing or
transporting coal mine methane;
• Electric utilities interested in identifying greenhouse gas emissions reductions
projects or in purchasing electricity from an environmentally beneficial project;
Introduction May 1995 Page 1
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• Industries or large institutions with high demands for natural gas that may be
interested in purchasing gas from mines;
« Communities in which gassy mines are located - methane recovery projects
create jobs that mining communities may be seeking; also, local governments
could potentially attract new industries by demonstrating the significant cost
savings resulting from the use of coal mine methane; and
• Gas recovery developers or private financiers who may be interested in
providing funding for coal mine methane projects.
By showing that a range of utilization options can be profitable for gassy mines, this
report should be of assistance to organizations evaluating the potential for specific coal mine
methane projects. An earlier report published by the Coalbed Methane Outreach Program -
entitled "Identifying Opportunities for Methane Recovery at U.S. Coal Mines: Draft Profiles of
Selected Gassy Underground Coal Mines" - was developed in order to assist organizations in
identifying specific mines that are candidates for utilization projects.
While this report presents analyses for hypothetical mines, the Coalbed Methane
Outreach Program is also preparing similar assessments for some of the mines identified in
the Draft Profiles of Selected Gassy Underground Coal Mines report. Mine operators or other
organizations interested in obtaining assistance in performing a site specific assessment
should contact the Coalbed Methane Outreach Program. Information regarding the Program
is provided in the last section of this report.
In summary, the Coalbed Methane Outreach Program developed this report in order to
decrease the informational barriers constraining the development of coal mine methane
projects that have the potential to be both profitable and environmentally beneficial. Each
project at the largest and gassiest mines could result in over 2 billion cubic feet per year of
methane emissions reductions (the equivalent of nearly one million tons of carbon dioxide per
year). These reductions are roughly equal to the annual carbon dioxide emissions of 200,000
cars. By contributing to the dialogue between coal mine operators and others interested in
methane recovery, this report should help to encourage the development of profitable
emissions reductions projects.
Overview of Sample Mine Assessments
This report presents assessments for three Sample Mines, referred to as Mine A, Mine
B, and Mine C. This overview describes the characteristics of each of the Sample Mines,
presents the project options evaluated for each mine, and discusses the methodology used
to determine the profitability of each option.
Characteristics of the Sample Mines
As mentioned previously, the Sample Mines shown in this report are hypothetical
mines. However, while the mines are hypothetical, their defining characteristics (emissions,
coal production, etc.) are representative of the relevant characteristics of gassy U.S. mines
that have not yet developed utilization projects. Table 1 presents a comparison of the key
characteristics assumed for each of the Sample Mines.
Introduction May 1995 Page 2
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Table 1: Characteristics for Sample Mines
Mine A
Mine B
MineC
General Information
Mining Method
Remaining Lifetime
Annual Coal Production
Longwall
20 years
2 million tons
Longwall
20 years
3 million tons
Longwall
30 years
2 million tons
s Methane Emissions ; .*
Emissions Per Ton
Total Annual Methane Emissions
Annual Ventilation Emissions
Annual Degasification Emissions
Degasification Method Employed
Degasification System Recovery
Efficiency
Percent of Degasification Emissions
that is Pipeline Quality Gas (>95%)
1000 cf/ton
2.0 Bcf
1.4 Bet
0.6 Bcf
Gob Wells
30%
5%
2000 cfAon
6.0 Bcf
3.0 Bcf
3.0 Bcf
Gob Wells and
Horizontal Boreholes
50%
30% (70% from in-
mine boreholes, 30%
from gob wells)
1500 cf/ton
3.0 Bcf
1.8 Bcf
1.2 Bcf
Gob Wells
40%
25%
Utilization Information
Distance to Pipeline
Wellhead Gas Price
Mine Electricity Price
Utility Avoided Cost
Nearby Industry or Institution with
Large Natural Gas Needs?
Local Industrial End-user Gas Price
Distance to Nearby Industry or
Institution
Annual Demand for Gas by Nearby
Industry or Institution
Coal-fired Thermal Dryer Used On-
Site?
Current Price Received for Coal
5 miles
$1 .50/mcf
5.5«/kwh
4.5t/kwh
No
NA
NA
NA
No
NA
1 mile
$1. 50/mcf
4«/kwh
3«/kwh
No
NA
NA
NA
No
NA
1 mile
$1. 50/mcf
4«/kwh
2«/kwh
Yes
$5/mcf
5 miles
0.36 Bcf
Yes
$1.00/MMBTU
Introduction
May 1995
PageS
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Mine A
Mine A is the smallest mine in terms of annual coal production (2 million tons) and
annual methane emissions (2 billion cubic feet). The gob wells employed at the mine account
for 30% of total methane emissions. In comparison to Mine B and Mine C, Mine A pays a
relatively high average rate for its electricity (5.5 cents/kwh) and is located in the service
territory of a utility that has a high avoided cost (4.5 cents/kwh).
Mine B
Of the three mines, Mine B has the highest total methane emissions (6 billion cubic
feet). Mine B uses both horizontal boreholes and gob wells to remove large quantities of
methane from the mine. Emissions from these degasification systems account for 50% of
total methane emitted from the mine. Furthermore, of the methane emitted from
degasification systems, 30% of the gas recovered has a methane content greater than 95%
(which is considered to be suitable for sale to a pipeline company without requiring
enrichment).
Mine C
Mine C has the same annual coal production as Mine A (2 million tons), but is
significantly gassier (1,500 cf/ton as compared to 1,000 cf/ton for Mine A). Of the three
mines, only Mine C employs a coal-fired thermal dryer. Furthermore, Mine C is the only mine
that is assumed to be located near an industry that could potentially purchase recovered
methane.
As shown in Table 1, all of the Sample Mines already have degasification systems in
place. This analysis examines the possibilities for utilization of the methane recovered from
these degasification systems.
Project Options Evaluated
The following project options were evaluated: 1) sale to a pipeline company, 2) power
generation, 3) use in on-site facilities, and 4) sale to a local industry or institution with high
demands for natural gas.
For the Sample Mines, two different types of pipeline sales projects were evaluated:
1) sale of only the portion of recovered gas that is suitable for pipeline sales without requiring
enrichment, and 2) sale of all of the recovered gas, by enriching the off-spec gas to pipeline
quality. For a pipeline project, the critical factors determining project profitability are the
quantity and quality of gas produced, the proximity to a pipeline that can purchase the gas,
and the price at which the gas can be sold. For coal mine methane projects, gas quality is a
special concern. Mines that employ degasification methods that recover methane in advance
of mining (e.g., vertical wells, horizontal boreholes) typically produce nearly pure methane that
is suitable for pipeline sales. Degasification systems that recover methane post-mining
(primarily gob wells), however, recover methane that is sometimes mixed with mine air.
During the first few weeks of production, a gob well may produce nearly pure methane. Over
time, however, substantial quantities of mine air may flow into the gob well and mix with the
methane, rendering the gas unsuitable for pipeline sales. Once the methane content drops
below 95%, enrichment is required before the gas can be sold to a pipeline company.
Introduction May 1995 Page 4
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Enrichment consists of removing oxygen, nitrogen, and carbon dioxide from the gas stream.
Enrichment of the gas may be expensive and tends to be profitable primarily at very large
projects.
In comparison to pipeline projects, gas quality is not an issue for power generation
projects, since gas with a methane content as low as 30% can be used to generate electricity.
Two power generation projects are evaluated for the Sample Mines. The first power
generation project consists of generating electricity to meet on-site needs and selling any
electricity produced in excess of on-site needs to a utility. The second project involves
generating just enough electricity to meet continuous on-site electricity demands. The
primary factors in determining the profitability of a power generation project are the level of
electricity that can be generated, the on-site electricity needs of the mine, the price the mine
currently pays for electricity, and the buy-back rate offered by the local utility (the utility's
avoided cost of generating electricity). Additionally, some utilities may charge high rates for
emergency back-up power for projects that generate electricity to meet their on-site needs.
The rates charged for back-up power can also have a significant impact on the profitability of
a power generation project.
In addition to evaluating the potential for a pipeline sales or power generation project,
the possibility of selling methane to a nearby industry or institution with large natural gas
needs was also evaluated for Mine C. For this option, it was assumed that an industry could
use the medium to high quality gas recovered from the mine. The primary factors
determining the profitability of a local use project are the natural gas needs of the potential
user, the distance between the user and the mine, the price at which the gas can be sold,
and the cost of converting an existing fuel system to operate on coal mine methane.
Finally, the potential for use of the gas in an thermal dryer at a preparation plant was
evaluated. Not all mines have thermal dryers. Furthermore, of the mines that have thermal
dryers, some rely solely on electricity and not on coal as a source of fuel. Of the Sample
Mines, only Mine C relies on a coal-fueled thermal dryer. Accordingly, this option is feasible
only for this mine. The primary factors determining the profitability of using coal mine
methane on-site are the price of the coal that would be displaced and the cost of converting
the thermal dryer to operate on methane instead of coal.
Methodology
The Sample Mine characteristics shown in Table 1 were used to develop the basic
assumptions used in the economic analysis of the various project options assessed for each
mine. In addition to the specific characteristics shown in Table 1, general assumptions
regarding likely project costs were used. These general assumptions are based on data from
existing coal mine methane projects and are discussed in Appendix A.
For each of the options evaluated, a discounted cash flow analysis was used to
determine the net present value of the project for the private mine operator. Additionally, the
internal rate of return of the project was calculated. The discounted cash flow analysis
consisted of several steps, including 1) calculating potential gas and electricity production, 2)
estimating capital and operating costs incurred, and, 3) determining revenues and savings
realized. After these calculations were made, annual project cash flows were determined over
the lifetime of the project. These annual cash flows were then discounted to determine the
net present value of each of the projects evaluated for the three different Sample Mines.
Introduction May 1995 Page 5
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Detailed information on the specific assumptions that were used to estimate gas and
electricity production and costs and revenues is shown in Appendix A. Additionally, the
financial assumptions used in the discounted cash flow analysis, including the discount rate,
inflation rate, and tax rate, are discussed in Appendix A.
The following case studies show the results of the discounted cash flow analysis for
the range of projects evaluated at each of the Sample Mines.
Introduction May 1995 Page 6
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SAMPLE MINE A
Two Profitable Options
Overview
Production and Emissions Data
Annual Coal Production
Emissions Per Ton
Total Annual Emissions
Ventilation Emissions
Degas Emissions
Current Degas Method
Degas % of Emissions
2 MM tons
1000cf/ton
2.0 Bcf
1.4Bcf
0.6 Bcf
Gob Wells
30%
A longwall mine, Mine A produces 2 million tons of coal
per year and has 20 years of minable reserves. Mine A emits
1000 cubic feet of methane for every ton of coal mined (for a
total of 2 billion cubic feet per year or about 5.5 million cubic
feet per day). In addition to its ventilation systems, Mine A
employs gob wells to improve safety and to increase coal
productivity.
The gob wells recover 0.6 billion cubic feet of methane
per year (30% of total methane emitted from the mine). During
the first few days of production, gob wells at the mine normally
recover gas with a methane content greater than 95% (pipeline
quality gas). After the first week, however, the methane content
begins to decline steadily until, after about three months, the methane content is less than 40% and the vacuum
pump used on the well is removed. Of the total gas recovered from gob wells, about 5% is pipeline quality.
Mine A is not located near any industries that have a high demand for natural gas. Furthermore, Mine
A does not use a coal-fired thermal dryer at its preparation plant. Accordingly, potential utilization options
involve either power generation or pipeline injection. The following specific utilization options were evaluated
for Mine A:
Project 1: Electricity generation for on-site use and sale to a utility,
Project 2: Electricity generation to meet on-site continuous demand only,
Project 3: Pipeline injection using high quality gas that does not require enrichment,
Project 4: Pipeline injection using all recovered gas.
For all projects, a 20-year lifetime is assumed.
Power Generation
A prefeasibility assessment shows that Mine A can make
a prof it from using recovered methane to generate electricity for
on-site use and sale to a utility (Project 1). The estimated NPV
of such a project is $4.8 million, while the IRR is 18.1%. The
prefeasibility assessment shows positive results for three
reasons. First, Mine A currently is paying a high price for
electricity (5.50/kwh). With annual electricity needs of 60 million
kwh/yr, Mine A's annual cost of electricity exceeds $3.3 million.
As shown in the tables at the end of this assessment, an on-site
power generation project could reduce electricity purchases by
38 million kwh and result in annual savings of $2.1 million. The
assessment assumes that the utility does not charge increased
rates for any backup power purchased by the mine.
Power Generation Project 1
NPV (million $) $4.8
Internal Rate of Return 18.1%
Electric Capacity 5.8 MW
CO2 Avoided (tons) 311,000
Mine Electricity Price 5.50/kwh
Utility Avoided Cost 4.50/kwh
The second factor contributing to the profitability of a power generation project is that the local utility
has a relatively high buyback rate (4.50/kwh). Accordingly, Mine A can generate substantial revenues from
selling 'excess' electricity to the utility (electricity generated in excess of on-site needs occurs during times that
the mine is not in full operation).
Mine Assessments
May 1995
Page?
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Mine A, continued
A final factor is that the electricity project could operate on the methane already recovered from gob
wells. No additional degasification systems need to be installed and no processing of the gas is required. The
project simply involves collecting gas that would otherwise be emitted from gob wells and moving it to a centrally
located generator. The project utilizes 0.6 Bcf of gas per year to generate 50 million kwh/yr of electricity.
Mine A could also profit from developing a smaller power
generation project (Project 2) that is designed to generate just
enough electricity to meet the continuous on-site needs of the mine
only. Project 2 would utilize only 58% of the recovered gas (0.348
Bcf/yr) to generate roughly 29 million kwh/yr of electricity. Internal Rate of Return 17.4/c
Power Generation Project 2
NPV (million $)
Electricity Generated 3.3 MW
CO2 Avoided (tons) 176,000
Mine Electricity Price 5.50/kwh
The assessment shows that Project 2, with an NPV of $2.5
million and an IRR of 17.4%, is also a profitable alternative for Mine
A. The NPV for Project 2, however, is considerably lower than the
NPV for Project 1. The emissions reductions that would be
achieved by this project are also significantly lower (the equivalent
of 0.176 million tons of carbon dioxide for Project 2 as compared to 0.311 million tons for Project 1). One
advantage of this smaller project, however, is that initial capital costs are significantly lower than for Project 1
($4 million, as compared to $7.1 million for Project 1).
Pipeline Sales
With a transmission line located five miles from the mine, pipeline injection is also a possibility for Mine
A. Two project options were evaluated: 1) use of only the methane recovered from gob wells that would not
need to be enriched prior to pipeline injection; and 2) enrichment of the methane currently recovered from gob
wells. These options are referred to as Project 3 and Project 4, respectively.
The economic assessment shows that Project 3 is not profitable. Since only 5% of the methane currently
recovered from gob wells would not need to be enriched prior to sale to a pipeline, the revenues gained from
the sale of this small portion of gas do not offset the high initial capital costs required for the project. For some
mines, however, it may be possible to produce substantial volumes of pipeline quality methane from gob wells
by blocking off certain areas of the longwall panel and through careful monitoring of the recovered gas. The
analysis shows that, in order for Mine A to break even on this project, 75% of the gas recovered from gob wells
(0.45 Bcf/yr) would need to have a high enough methane content so that it would not need to be enriched prior
to pipeline injection. Alternatively, the mine could switch to a pre-mining degasification, which recovers nearly
pure methane. Furthermore, two pre-mining degasification methods - use of vertical wells and longhole
horizontal boreholes - can produce substantially higher volumes of methane than can gob wells, if drilled far
enough in advance of mining.
The assessment further shows that Project 4 is not economically viable. Since only 5% of the methane
released from the gob wells is of pipeline quality, enrichment will be required for 95% of the gas. The capital
costs of the equipment needed for the enrichment process are high - over $2 million dollars for a system that
removes oxygen, nitrogen, and carbon dioxide. Additionally, construction costs for a pipeline between the mine
and the existing pipeline are estimated to be $1 million (5 miles x $200,000 per mile). The annual revenues
generated would not be enough to offset the high initial capital investment required for the project. In order to
break even, Mine A would need to be able to sell the gas for $2.10/mcf, rather than $1.50/mcf.
Mine Assessments May 1995 Page 8
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Mine A, continued
Conclusion
The results of the analysis show that power generation projects are profitable for Mine A. While both
Project 1 and Project 2 are economic, the NPV of Project 1 is much higher. Furthermore, Project 1 utilizes all
of the recovered methane. A pipeline project does not appear to be feasible for Mine A, unless a pre-mining
degasification system were to be installed in place of or in addition to the gob wells. As shown in the
assessments for Mine B and Mine C, however, pipeline sales can be an extremely lucrative option for mines with
higher emissions.
Mine Assessments May 1995 Page 9
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Mine A
Costs and Revenues for Power Generation (Project 1)
STANDARD CAPITAL
Coal Production
Tonnage to Well Ratio
Number of Wells Drilled Each Year
Pen-Well Annual Costs
Drilling Costs *
Gathering Lines from Well to Satellite
Total Per-Well Annual Costs
Standard Annual Operating Costs
Salaries, Wages, Benefits **
Insurance
General Maintenance
Total Annual Operating Costs
Initial Project Costs
Wellhead Blower/Exhauster ***
Wellhead Knock-Out Separators ****
Wellhead Gas Flow/Quality Meters ****
Satellite Compressor Site Preparation
Satellite Compressor ($/HP x HP)
Safety Equipment
Total Initial Project Costs
* Cost for incremental wells only.
** Minimum of $100,000 or $/well x # of wells
AND OPERATING COSTS
2,000,000
250,000
8
Cost/Well Wells/Year
$0
$12,000
$12,000
Cost/Unit #
$10,000
$30,000
$30,000
Cost/Unit #
$0
$2,000
$5,000
$70,000
$600
$100,000
val ue .
*** For incremental wells only, initial capital cost because blowers
**** Considered initial capital cost because
they can be moved.
8
8
8
of Units
8
1
1
of Units
8
8
8
1
320
1
can be
Total Cost
$0
$96,000
$96,000
Total Cost
$100,000
$30,000
$30,000
$160,000
Total Cost
$0
$16,000
$40,000
$70,000
$192,000
$100,000
$418,000
moved.
COSTS/REVENUES
Per-Project Initial Capital Costs
Line from SatComp to Generator ($/ft x ft)
Generator ($/kw x kws)
Interconnection Costs
Total Per-Project Initial Capital Costs
Annual Operating Costs
Compression
Generator Operating Costs ($/kwh x kwh)
Total Annual Operating Costs
Rev/Savings from Elec Use & Sales
Savings from On-Site Use
Revenue from Sale to Utility
Total Revenue
FOR POWER GENERATION
$/Unit
$10
$1,100
$300,000
$/Unit
$12,000
$0.01
$/kwh
$0.055
$0.045
# of Units
2000
5,750
1
# of Units
1
50,369,455
kwh
38,184,986
12,184,468
Total Cost
$20,000
$6,324,932
$300,000
$6,644,932
Total Cost
$12,000
$503,695
$515,695
Total Revenues
$2,100,174
$548,301
$2,648,475
Mine Assessments
May 1995
Page 10
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Mine A
Annual Cash Flows for Power Generation Project 1
Initial
Capital Annual
Cost Revenue
Investment & Savings
Year -
Annual
Operating
Costs
Initial
Royalty Capital Cost
Payments Depreciation
Income
Before
Taxes
Taxes
Owed
Net Income
(Accounting)
(Purposes)
0 $7,067,736
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Net Present Value of
$2,753,929
$2,864,086
$2,978,649
$3,097,795
$3,221,707
$3,350,575
$3,484,599
$3,623,982
$3,768,942
$3,919,699
$4,076,487
$4,239,547
$4,409,129
$4,585,494
$4,768,914
$4,959,670
$5,158,057
$5,364,379
$5,578,954
$5,802,113
Project: $4,751
$802,463
$834,562
$867,944
$902,662
$938,769
$976,319
$1,015,372
$1,055,987
$1,098,226
$1,142,155
$1,187,842
$1,235,355
$1,284,770
$1,336,160
$1,389,607
$1,445,191
$1,502,999
$1,563,119
$1,625,643
$1,690,669
,659
$344,241
$358,011
$372,331
$387,224
$402,713
$418,822
$435,575
$452,998
$471,118
$489,962
$509,561
$529,943
$551,141
$573,187
$596,114
$619,959
$644,757
$670,547
$697,369
$725,264
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$353,387
$1,253,838
$1,318,127
$1,384,987
$1,454,522
$1,526,838
$1,602,047
$1,680,265
$1,761,611
$1,846,211
$1,934,195
$2,025,698
$2,120,861
$2,219,831
$2,322,760
$2,429,806
$2,541,134
$2,656,914
$2,777,327
$2,902,555
$3,032,793
$501,535
$527,251
$553,995
$581,809
$610,735
$640,819
$672,106
$704,644
$738,484
$773,678
$810,279
$848,345
$887,933
$929,104
$971,922
$1,016,453
$1,062,766
$1,110,931
$1,161,022
$1,213,117
$752,303
$790,876
$830,992
$872,713
$916,103
$961,228
$1,008,159
$1,056,967
$1,107,727
$1,160,517
$1,215,419
$1,272,517
$1,331,899
$1,393,656
$1,457,884
$1,524,680
$1,594,149
$1,666,396
$1,741,533
$1,819,676
Total
Cash Flow
Of Project
($7,067,736)
$1,105,689
$1,144,263
$1,184,379
$1,226,100
$1,269,490
$1,314,615
$1,361,546
$1,410,353
$1,461,113
$1,513,904
$1,568,806
$1,625,904
$1,685,286
$1,747,043
$1,811,270
$1,878,067
$1,947,535
$2,019,783
$2,094,920
$2,173,062
Discounted
Cash Flows
Of Project
($7,067,736)
$1,002,984
$941,559
$884,042
$830,174
$779,710
$732,425
$688,110
$646,568
$607,619
$571,092
$536,831
$504,690
$474,530
$446,226
$419,658
$394,715
$371,295
$349,300
$328,642
$309,235
Internal Rate of Return: 18.1%
Real Discount Rate:
Inflation Rate: 4%
Tax Rate: 40%
Royalties: 12.5%
Depreciation Method:
6%
Straightline
Mine Assessments
May 1995
Page 11
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Mine Assessments May 1995 Page 12
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SAMPLE MINE B
Five Profitable Options
Overview
Mine B produces about 3 million tons of coal
annually and has 20 years of minable reserves. This
mine emits 2,000 cubic feet of methane for every ton of
coal mined (for a total of 3 billion cubic feet per year or
about 8.2 million cubic feet per day). In addition to its
ventilation systems, Mine B employs both horizontal
boreholes (drilled in advance of mining) and gob wells.
About 30% of the gas recovered by Mine B's
degasification systems has a methane content greater
than 95% (pipeline quality gas); 70% of this pipeline
quality gas is recovered through pre-mining techniques,
while 30% is recovered through gob wells. The remaining
70% of the methane recovered is medium to high BTU
gas.
Production and Emissions Data
Coal Production
Emissions Per Ton
Total Emissions
Ventilation
Degas
Current Degas
Method
Degas % of
Emissions
3 MM tons/yr
2000 cf/ton
6.0 Bcf/yr
3.0 Bcf/yr
3.0 Bcf/yr
Gob Wells,
In-Mine
Boreholes
50%
Mine B does not have any large natural gas consumers nearby and does not use a thermal dryer
on-site. Accordingly, only pipeline projects and power generation projects were evaluated. Specifically,
the following five projects were assessed:
Project 1: Sale of High Quality Gas to a Pipeline,
Project 2: Sale of All Recovered Gas to a Pipeline,
Project 3: On-site Use and Sale of Electricity to a Utility,
Project 4: On-site Use of Electricity to Meet Continuous Demand,
Project 5: Combination of Project 1 and Project 4.
All projects are assumed to have a twenty-year lifetime.
Pipeline Results
Wellhead Gas Price
Distance to Pipeline
$1.50
1 mile
Project 1 Project 2
Pipeline Sales
Since Mine B recovers both high quality and
medium quality gas, two pipeline sales options were
assessed. The first option (Project 1) involves selling
only the recovered gas that would be suitable for
pipeline sale without enrichment. The second option
(Project 2) involves selling both the high quality gas
and the lower quality gas, after it has been enriched
to pipeline standards.
While 30% of the gas recovered at Mine B is
suitable for sale to a pipeline without enrichment, an
additional 10% of slightly lower quality gas can also
be sold without being enriched if it is blended with the
higher quality gas. Therefore, a total of 40% of the gas can be sold to a pipeline. The total amount of
gas that would be recovered for pipeline sale is 1.2 Bcf/yr.
The results of the analysis show that Project 1 would be profitable for Mine B. The NPV is $6.7
million, and the IRR is 64.7%. Initial capital costs of the project are $1.2 million. Though only 40% of the
NPV (MM $)
IRR
CH4 Used (Bcf)
CO2 (MM tons)
$6.7
64.7%
1.2
0.559
$14.4
44.7%
3.0
1.397
Mine Assessments
May 1995
Page 13
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Power Generation Project Results
Mine Electricity Price 40/kwh
Utility Avoided Cost 30/kwh
Project 3 Project 4
NPV (MM $) $3.6 $0.2
IRR 11.6% 10.7%
CH4 Used (Bcf) 3.0 0.5
CO2 (MM tons) 1.397 0.237
Mine B, continued
gas is utilized, this project still achieves high emissions reductions. The equivalent of 0.6 million tons of
carbon dioxide emissions are avoided every year.
The analysis shows that Project 2 would be profitable as well. Under Project 2, 100% of the
recovered gas would be sold to a pipeline. Of this amount, 60% would require enrichment prior to
pipeline injection. Although the capital costs of the equipment needed for the enrichment process are
high - over $2 million for a system that removes oxygen, nitrogen, and carbon dioxide - these expenses
are offset by the revenue generated from gas sales. Total initial capital costs are $4.2 million, while annual
revenues are $3.6 million. The NPV of Project 2 is much higher than for Project 1 ($14.4 million, as
compared to $6.7 million). The IRR for Project 2, however, is lower than for Project 1 (44.7%, as compared
to 64.7%).
Power Generation
In addition to the two pipeline project options,
two power generation options were also evaluated.
The first such project (Project 3) involves using all of
the recovered gas to generate electricity. Electricity
produced would first be used to meet on-site needs.
Any power generated above on-site needs would be
sold to a utility. The second project (Project 4)
involves generating electricity to meet continuous on-
site electricity demand at the mine only. The
advantages of this second project are that it requires
a much smaller generator (and, thus, has lower initial
capital costs) and that the mine would not need to sell
power to a utility. For the power generation options,
the analysis assumes that Mine B currently pays 40/kwh for electricity. The local utility has an avoided
cost (buyback rate) of 30/kwh.
Under Project 3, the project capacity is 28.7 MW, and 252 million kwh of electricity are generated
each year. Of this 252 million kwh, roughly 90 million are used to meet on-site needs and 162 million are
sold to a utility. Accordingly, annual electricity savings are about $3.6 million, and annual revenues from
electricity sales are $4.8 million. Initial capital costs are high ($33.2 million), primarily as a result of the
cost of the gas turbine ($1,100 per Kw installed capacity).
The NPV of Project 3 is $3.6 million, and the IRR is 11.6%. While this project is profitable, both
pipeline projects are preferable since they have higher NPVs and IRRs. Furthermore, the initial capital
costs of the project are much higher for Project 3 than for the pipeline projects ($33.2 million, as
compared to $1.2 million for Project 1, and $4.2 million for Project 2). Since 100% of the recovered gas
would be utilized, the emissions reductions achieved by this project are identical to those achieved under
pipeline Project 2 - 3.0 Bcf/yr of methane (1.397 million tons of carbon dioxide equivalent).
In comparison Project 3, the second power generation project (Project 4) ~ use of electricity to
meet continuous on-site demands only - has significantly lower initial capital costs ($5.8 million, as
compared to $33.2 million). The initial capital costs for this project, however, are still higher than for both
pipeline projects. Under Project 4, annual savings realized are $1.7 million.
The results of the analysis show that Project 4 is also a profitable option. The NPV is $0.2 million,
and the IRR is 10.7%. However, since both the NPV and IRR are lower than for Project 3 and for both
pipeline sales options, this project appears less preferable.
Mine Assessments May 1995 Page 14
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Mine B, continued
Combination Project
Combination Project Results
In addition to the options discussed above, Mine
B could undertake a combined project consisting of
Project 1 (sale of high quality gas to a pipeline) and
Project 4 (use of electricity to meet on-site continuous
needs). Since pipeline sales Project 1 uses 40% of the
recovered gas and power generation Project 4 requires
17% of the gas, the total gas utilized would be 57% (1.7
Bcf/yr). Total emissions avoided would be the equivalent
of 0.796 million tons of carbon dioxide. Assuming that
many of the collection costs and gathering costs would
not need to be duplicated for both projects, the initial
capital costs of the project are $6.7 million. Based on the
results of the analysis, such a combination project would
be economically beneficial for Mine B, with an NPV of $9.3 million and an IRR of 25.3%. The NPV of this
project is not as high as that of pipeline Project 2, but is higher than the other options.
NPV (million $)
IRR
Methane Used
CO2 Avoided (tons)
Initial Capital Costs
(million $)
$9.3
25.3%
1.7Bcf
0.796 MM
$6.7
Project
1. Sale of High Quality Gob Gas
to Pipeline
2. Sale of All Recovered Gas to a
Pipeline, Enrichment Required
3. Electricity Generation for On-site
Use and Sale to a Utility
4. Electricity Generation to Meet
Continuous On-Site Needs Only
5. Combination of Project 1 and
Project 4
Results for
Percent of
Recovered
Gas
Utilized
40%
100%
100%
17%
57%
Mine B
Profitable Options
Annual
Amount
Used
Bcf CH4
1.2
3.0
3.0
0.5
1.7
Emissions
Avoided
million
Initial NPV
Capital
Cost
tons CO2 million
0.559
1.397
1.397
0.237
0.796
$1.2
$4.2
$33.2
$5.8
$6.71
$
$6.7
$14.4
$3.6
$0.2
$9.31
IRR
64.7%
44.7%
11.6%
10.7%
25.3%
1 The sum of the initial capital costs for pipeline projects 1 and 4 is higher than the capital costs for the
combined project due to economies of scale that result from developing a larger project. Annual operating
costs for the combined project are also somewhat lower than the sum of the annual operating costs for the
individual projects. Accordingly, the NPV for the combined project is higher than the sum of the NPVs for the
individual projects.
Conclusion
For Mine B, at least five utilization projects are profitable - two pipeline projects, two power
generation projects, and one combined pipeline and power generation project. The NPV of the pipeline
project involving sale of all recovered gas (Project 2) has the highest NPV, followed by the combined
pipeline injection and power generation project (Project 5). Project 1 has the lowest initial capital costs
Mine Assessments
May 1995
Page 15
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Mine B, continued
($1.2 million) and the highest internal rate of return. Project 2 and Project 3 utilize all of the recovered gas
and therefore have the highest avoided emissions (3.0 Bcf/yr).
The analysis for Mine B shows that a wide range of projects may be profitable at a particular mine.
Furthermore, under certain circumstances, combined projects that feature more than one use of the gas
can also be feasible. Finally, the results for the pipeline projects show that large emissions reductions
may be achieved for a relatively low initial capital investment.
Mine Assessments May 1995 Page 16
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Mine B
Costs and Revenues for Pipeline Project (1)
(Sale of High Quality Gas Only — No Enrichment)
Standard Collection Costs
Coal Production
Tonnage to Well Ratio
Number of Wells Drilled Each Year
Per-Well Annual Costs
Drilling Costs *
Gathering Lines from Well to Satellite
TOTAL Per-Well Annual Costs
Standard Annual Operating Costs
Salaries, Wages, Benefits **
Insurance
General Maintenance
TOTAL Annual Operating Costs
Initial Project Costs
Wellhead Blower/Exhauster ***
Wellhead Knock-Out Separators ****
Wellhead Gas Flow/Quality Meters ****
Satellite Compressor Site Preparation
Sales Compressor Site Preparation
Ancillary Equipment
TOTAL Initial Project Costs
* Cost for incremental wells only.
** Minimum of $100,000 or $/well x # of wells value.
*** For incremental wells only, initial capital cost
3,000,000
250,000
12
Cost/Well
$0
$12,000
$12,000
Cost/Unit
$10,000
$30,000
$30,000
Cost/Unit
$0
$2,000
$5,000
$70,000
$70,000
$100,000
[rounded to integer]
Wells/Year
12
12
12
# of Units
12
1
1
# of Units
12
12
12
1
1
1
Total Cost
$0
$144,000
$144,000
Total Cost
$120,000
$30, -000
$30,000
$180,000
Total Cost
$0
$24,000
$60,000
$70,000
$70,000
$100,000
$324,000
because blowers can be moved.
**** Considered initial capital cost because they can be moved.
Costs Specific
Per-Project Initial Capital Costs
Satellite Compressor ($/HP x HP)
Sales Compressor ($/HP x HP)
Pipeline Lateral ($/mile x miles)
Oehydrator, Processor
Meter Run
TOTAL Per-Project Initial Capital Costs
Annual Operating Costs for Pipeline Sales
Compression (assumes 2 units)
Dehydration (assumes 1 unit)
TOTAL Annual Operating Costs
mcf Gas Sold to Pipeline (No Enrichment)
Revenue from Pipeline Sales
Revenue Based on Wellhead Gas Price
TOTAL Revenue
to Pipeline Utilization
Cost/Unit
$600
$600
$200,000
$40,000
$20,000
$/unit
$12,000
$3,000
1,113,276
$/mcf gas
$1.50
$1.50
# of Units
660
330
1
1
1
Units
2
1
-
mcf Gas
1,113,276
1,113,276
Total Cost
$396,000
$198,000
$200,000
$40,000
$20,000
$854,000
Total Cost
$24,000
$3,000
$27,000
Total Revenue
$1,669,914
$1,669,914
Mine Assessments
May 1995
Page 17
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Mine B
Gas Production for Pipeline Sales
Gas Production for Project 1
Methane Recovered (cf/yr): 1,200,000,000
Compressor Loss Calculations
HP Requirements for Satellite Compressor 660
HP Requirements for Sales Compressor 330
Compressor Loss Ratio (CF/BHP HR) 10
Gas Used to Fuel Satellite Compressor (cf/yr) 57,816,000
Gas Used to Fuel Sales Compressor (cf/yr) 28,908,000
Production Adjusted for Compressor Loss
Gas for Pipeline Sales (No enrichment) 1,113,276,000
Gas Production for Project 2
Methane Recovered (cf/yr): 1,800,000,000
Compressor Loss Calculations
HP Requirements for Satellite Compressor 990
HP Requirements for Sales Compressor 490
Compressor Loss Ratio (CF/BHP HR) 10
Gas Used to Fuel Satellite Compressor (cf/yr) 86,724,000
Gas Used to Fuel Sales Compressor (cf/yr) 42,924,000
Gas Used in Enrichment Process (cf/yr) 400,884,480
Production Adjusted for Compressor Loss and Shrinkage (cf/yr)
Gas for Pipeline Sales (assuming enrichment) 1,269,467,520
Mine Assessments
May 1995
Page 18
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SAMPLE MINE C
Five Profitable Options
Overview
Mine C is a longwall mine with annual coal
production of 2 million tons and a remaining lifetime of
approximately 30 years. Total annual emissions are 3
Bcf, of which 1.8 Bcf (60%) are emitted from ventilation
systems and 1.2 Bcf (40%) are emitted from
degasification systems (gob wells). Of the methane
emitted from the gob wells, 25% has not been mixed with
significant quantities of mine air and, therefore, would be
suitable for sale to a pipeline without requiring
enrichment. The remaining gas would require enrichment
prior to pipeline injection, but would also be suitable for
power generation, sale to an industrial user, or use on-
site.
Production and Emissions Data
Annual Coal Production 2 MM tons
Emissions Per Ton 1500 cf/ton
Total Annual Emissions 3.0 Bcf
Ventilation Emissions 1.8 Bcf
Degas Emissions 1.2 Bcf
Current Degas Method Gob Wells
Degas % of Emissions 40%
Mine C is located only one mile from an existing pipeline that could transport the gas recovered
at the mine. Additionally, an industry that could purchase 0.36 Bcf/yr of recovered methane is located
5 miles from the mine. Finally, Mine C uses a coal-fired thermal dryer that may be retrofitted for methane
use. An economic assessment of the data for Mine C shows that there are five different profitable options
for utilization of the methane currently recovered from degasification systems.
Pipeline Sales
Pipeline Results
Wellhead Gas Price
Distance
$1.50
1 mile
Project 1 Project 2
NPV (MM $)
IRR
CH4 Used (Bcf)
CO2 (MM tons)
$0.1
11.2%
0.30
0.144
$3.0
18.3%
1.20
0.559
Two different options involving the sale of gas
to a pipeline were evaluated: 1) sale of the higher,
quality gob gas that would not require enrichment;
and 2) sale of all recovered methane (both high
quality and lower quality gas). The analysis shows
that both of these options would be profitable.
The first option requires a relatively low initial
capital cost of $0.7 million. The NPV for the project is
$0.1 million, and the IRR is 11.2%. As with Mine B,
the results indicate that, for some large and gassy
mines, pipeline projects that involve the sale of only a
small portion of the total amount of methane emitted
can be profitable. Annual emissions reductions associated with this project are equivalent to 0.14 million
tons of carbon dioxide.
The second option involves selling both the higher quality gas and the lower quality gas (after it
has been enriched) to a pipeline. This option results in a higher capital cost ($3.2 million) than does the
first option due to the $2.1 million cost of purchasing the enrichment equipment. Additionally, larger
compressors will be needed for the project to handle the higher volumes of gas. The NPV for the project,
however, is also much higher ($3 million as compared to $0.1 million), and the IRR is 18.3%. The results
show that projects requiring gas enrichment can still be very profitable. Finally, emissions reductions
associated with this project are also much higher than for the first project. Since all of the gas is utilized,
the emissions reductions are the equivalent of avoiding the emission of 0.559 million tons of carbon
dioxide.
Mine Assessments
May 1995
Page 19
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Mine C, continued
Sale to Local Industry
Although not feasible for Mines A and B, the sale
of gas to a nearby industrial user is a possibility for Mine
C. The economic assessment assumes that Mine C is
located 5 miles from an industry that could purchase
0.36 Bcf/yr of recovered methane. The analysis further
assumes that the user would pay for any necessary
retrofitting of its fuel systems to operate on coal mine
methane if the mine would sell gas at a price 25% lower
than the local industrial gas price ($5/mcf). Accordingly,
the assessment assumes that the user would pay
$3.75/mcf for the gas.
Sale to Local Industry Results
NPV (million $) $5.7
Internal Rate of Return 40.3%
Methane Used 0.36 Bcf
CO2 Avoided (tons) 0.168 MM
Gas Sales Price $3.75/mcf
Distance to Industry 5 miles
The results of the economic assessment show
that sale of recovered methane to a local industrial user would be very profitable for Mine C. The NPV
of the project is $5.7 million, and the IRR is 40.3%. The initial capital costs required for such a project are
$1.5 million. Of the $1.5 million, $1 million is associated with the cost of constructing the pipeline from
the mine to the user. While the industry is assumed to be located five miles from the mine, a potential
customer could be much further from the mine and the project would still be profitable; the break-even
distance for the project is 36 miles.
Use In Thermal Dryer
Mine C is the only one of the sample mines that
uses a coal-fired thermal dryer as part of its preparation
plant facilities. A few U.S. mines reportedly have been
able to retrofit their thermal dryers to operate on
recovered methane instead of coal. In order to evaluate
the potential for substituting recovered methane for coal
in the thermal dryer, the analysis assumes that Mine C
uses one ton of coal for every 150 tons of coal processed
in the thermal dryer. Annual fuel requirements for the
thermal dryer at Mine C would be about 13,300 tons of
coal, or 347 billion BTUs per year. Accordingly, 0.48
Bcf/yr of methane would be required, which represents
40% of the total amount of gas that could be recovered
from the mine degasification system.
Use in Thermal Dryer Results
NPV (million $)
IRR
Methane Used
CO2 Avoided (tons)
Savings from
Replacing Coal Use
$0.02
10.4%
0.48 Bcf
0.223 MM
$17 MMBTU
For the analysis, the cost of converting the thermal dryer to operate on coal mine methane is
$750,000. Furthermore, the market value of coal replaced with recovered methane is assumed to be
$1/MM BTU.
Despite the high conversion cost, the project would be profitable. The analysis shows that the
NPV is $0.02 million, and the IRR is 10.4%. The annual emissions avoided as a result of the project are
the equivalent of 0.22 million tons of carbon dioxide.
Mine Assessments
May 1995
Page 20
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Mine C, continued
Power Generation
The following assumptions were used to
determine whether power generation would be a
profitable project for Mine C. First, though the
analysis assumes that the mine's lifetime will be 30
years, a 20-year project lifetime was used because the
analysis also assumes that the generator will have a
lifetime of 20 years. The mine electricity price is
assumed to be 40/kwh; the utility avoided cost is
20/kwh. Finally, the assessment assumes that a gas
turbine would be used to generate electricity and that
the heat rate of the generator would be 11,000
BTUs/kwh.
Power Generation Results
(On-site Use
Mine
Price
0/kwh
4
4
5
Avoided
Cost
0/kwh
2
3
2
and Sale)
NPV
MM$
< 0
$1.6
$2.6
IRR
—
11.8%
12.6%
The project would generate about 100 million kwhs/year, of which 58 million kwhs/yr would be
used to meet on-site needs and 42 million kwhs/yr would be sold to a nearby utility. The maximum
capacity of the project would be 11.5 MW. Based on these assumptions, power generation would not be
a profitable project for Mine C. The high initial capital cost required for the project ($13.6 million) would
not be offset by the revenues and savings achieved.
While the results were not profitable assuming a mine electricity price of 40/kwh and a utility
avoided cost of 20/kwh, increasing either of these prices by one cent results in a profitable project.
Assuming a mine electricity price of 40/kwh and an avoided cost of 30/kwh results in a project NPV of $1.6
million and an IRR of 11.8%. Similarly, assuming a mine electricity price of 50/kwh and an avoided cost
of 20/kwh leads to an NPV of $2.6 million and an IRR of 12.6%.
Finally, the analysis examined the possibility of developing a smaller project that would be
designed to meet only the continuous on-site electricity needs of the mine. The advantages of such a
project are that a smaller generator would be used, no utility interconnection costs would be included,
and all electricity generated would be valued at the mine's electricity price. The results showed that the
NPV for the project would be negative, assuming a mine electricity price of 40/kwh. However, at a mine
electricity price of 50/kwh, the project would have a positive NPV of $1.5 million and an IRR of 14.8%.
Based on the assumptions for Mine C, the power generation projects do not appear profitable.
If the utility avoided cost or the mine price for electricity were higher, however, power generation would
be profitable.
Combination Project
Finally, the analysis examined the feasibility of
combining the three projects that did not utilize all of the
recovered methane: 1) sale of high quality gas to a
pipeline; 2) sale to a nearby industrial user; and 3) use in
the thermal dryer. For this combination project, it was
assumed that many of the initial capital costs would not
vary regardless of the amount of gas produced. For
example, the compressor-site preparation costs would
remain fairly constant even though the size of the
compressors would increase for a combination project.
Furthermore, other costs (such as for wellhead gas flow
meters) would be the same regardless of the amount of
gas recovered. Accordingly, the initial capital costs
Combination Project Results
NPV (million $)
IRR
Methane Used
CO2 Avoided (tons)
Initial Capital Costs
(million $)
$10.4
25.6%
1.14Bcf
0.531 MM
$3.0
Mine Assessments
May 1995
Page 21
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Mine C, continued
required for the combination project were significantly lower than the sum of the initial capital costs for
the three projects individually.
The assessment showed that a combination project would be the most profitable for the mine.
The NPV of the project would be $10.4 million, and the IRR would be 25.6%. Together, the three projects
would utilize 95% of the recovered methane. Emissions reductions achieved would be the equivalent of
0.53 million tons of carbon dioxide.
Conclusion
In summary, the results of the economic assessment show that Mine C has at least five profitable
options for utilizing methane: 1) sale of only high quality gas to a pipeline; 2) sale of all gas to a pipeline
by enriching the lower quality gas; 3) sale of gas to a nearby industry; 4) use of the gas in an on-site
thermal dryer; and 5) a combination project consisting of options 1), 3), and 4). The results show that
the combination project is the most profitable (with a NPV of $10.4 million), followed by the sale of gas
to a nearby industry ($5.7 million) and the sale of all recovered gas to a pipeline ($3 million).
MineC
Results for Profitable Options
Utilization Option
Percent of
Recovered
Gas
Utilized
Annual
Amount
Used
Bcf CH4
Emissions
Avoided
MM tons
CO2
Initial
Capital
Cost
MM$
NPV
MM$
IRR
1. Sale of High Quality Gob Gas to 25% 0.30 0.144 $0.7 $0.1 11.2%
Pipeline, No Enrichment
2. Sale of All Gas to a Pipeline, 100% 1.20 0.559 $3.2 $3.0 18.3%
Enrichment Required
3.
4.
5.
Sale to Nearby
Use in Thermal
Combination of
Industry
Dryer
#1, #3, and #4
30%
40%
95%
0.36
0.48
1.14
0.168
0.223
0.531
$1.5
$1.2
$3.01
$5.7
$0.02
$10.4
40.3%
10.4%
25.6%
1 The sum of the initial capital costs for projects 2, 3, and 4 is higher than the capital costs for the combined
project due to economies of scale that result from developing a larger project. Annual operating costs for the
combined project are also somewhat lower than the sum of the annual operating costs for the individual
projects. Accordingly, the NPV for the combined project is higher than the sum of the NPVs for the individual
projects.
Mine Assessments
May 1995
Page 22
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Nine C
Results for Combination Project
STANDARD COLLECTION AND OPERATING COSTS
Coal Production
Tonnage to Well Ratio
Number of Wells Drilled Each Year
Per-Well Annual Costs
Drilling Costs *
Gathering Lines from Well to Satellite
TOTAL Per-Well Annual Costs
Standard Annual Operating Costs
Operating Cost of Satellite Compressor
Dehydration, Processing
Salaries, Wages, Benefits **
Insurance
General Maintenance
TOTAL Annual Operating Costs
Initial Project Costs
Wellhead Blower/Exhauster ***
Wellhead Knock-Out Separators ****
Wellhead Gas Flow/Quality Meters ****
Satellite Compressor Site Preparation
Ancillary Equipment
TOTAL Initial Project Costs
2,000,000
250,000
8 [rounded to integer]
Cost/Well
$0
$12,000
$12,000
Cost/Unit
$12,000
$3,000
$10,000
$30,000
$30,000
Cost/Unit
$0
$2,000
$5,000
$70,000
$100,000
Wells/Year
8
8
# of Units
1
# of Units
8
8
8
1
1
Total Cost
$0
$96,000
$96,000
Total Cost
$12,000
$3,000
$100,000
$30,000
$30,000
$175,000
Total Cost
$0
$16,000
$40,000
$70,000
$100,000
$226,000
* Cost for incremental wells only. Cost based on degas cost% specified.
** Minimum of $100,000 or $/well x # of wells value.
*** For incremental wells only, initial capital cost because blowers can be moved.
**** Considered initial capital cost because they can be moved.
Incremental Costs/Revenues for
(Using 20% of the Gob Gas that
Per-P-roject Initial Capital Costs
Satellite Compressor ($/HP x HP)*
Sales Compressor Site Preparation
Sales Compressor (J/HP x HP)
Pipeline Lateral ($/mile x miles)
Dehydrator, Processor
Meter Run
TOTAL Per-Project Initial Capital Costs
Annual Operating Costs for Pipeline Sales
Sales Compressor Operating Cost
TOTAL Annual Operating Costs
Revenue from Pipeline Sales
Revenue Based on Wellhead Gas Price
TOTAL Revenue
* Incremental HP and cost needed in order to sale
Pipeline Sales Project
is Nearly Pure Methane)
Cost/Unit.
$600
$70,000
$600
$200,000
$40,000
$20,000
S/unit
$12,000
$/mcf gas
$1.50
$1.50
gas to a nearby
# of Units
160
1
80
1
1
1
Units
1
mcf Gas
278,976
278,976
industry.
Total Cost
$96,000
$70,000
$48,000
$200,000
$40,000
$20,000
$474,000
Total Cost
$12,000
$12,000
Total Revenue
$418,464
$418,464
Mine Assessments
May 1995
Page 23
-------
Nine C
Results of Combination Project, Continued
Incremental Costs/Revenues for Project
Per-Project Initial Capital Costs
Line to Nearby User ($/mile x miles)
Dehydrator for Off -Site Sale
Satellite Compressor*
Add. Compressor: Off-Site Sales
SitePrep for Additional Compressor
TOTAL Per-Project Initial Capital Costs
Annual Operating Costs for On-Site/Local Use
Add. Sales Compressor
TOTAL Annual Operating Costs
Revenue/Savings
Revenue: Sas Sales to Local Users
TOTAL Revenue
* Incremental HP and cost needed in order to
Involving Sale of Gas to Nearby Industry
Cost/Unit
$200,000
$40,000
$600
$600
$70,000
$/Unit
$12,000
$/mcf gas
$3.75
sale gas to a nearby
# of Units
5
1
200
100
1
# of Units
1
mcf Gas
342,480
industry.
Total Cost
$1,000,000
$40,000
$120,000
$60,000
$70,000
$1,290,000
Total Cost
$12,000
$12,000
Total Revenue
$1,284,300
$1,284,300
Incremental Costs/Revenues for Using
Per-Project Initial Capital Costs
Conversion Cost: PPlant Coal Replace
Line to On-site Facilities ($/ft x ft)
Satellite Compressor ($/HP x HP)*
TOTAL Per-Project Initial Capital Costs
Revenue/Savings
Savings: PrepPlant Coal Displacement
TOTAL Revenue
* Incremental HP and cost needed in order to sale
Gas in an On-Site Thermal Dryer
Cost/Unit
$750,000
$10
$600
$/mcf gas
$1.00
gas to a nearby
# of Units Total Cost
1 $750,000
2000 $20,000
260 $156,000
$926,000
mcf Gas Total
457,224
industry.
Revenue
$457,224
$457,224
Mine Assessments May 1995 Page 24
-------
Conclusion
This report demonstrates that the utilization of methane currently emitted from
degasification systems could be profitable for several different types of mines. Moreover, several
different types of projects may be feasible at a particular mine. The specific findings of the report
are as follows:
Power Generation
• Coal mine methane power generation projects can generate substantial levels of
electric capacity. The level of electric capacity that could be generated at the
sample mines ranges from 5.8 MW (Mine A) to 28.7 MW (Mine B).
• Power generation projects can be a profitable option for utilizing recovered
methane. Despite very different characteristics, both Mine A and Mine B showed
the potential to make a profit from power generation projects.
• The profitability of a power generation project is extremely sensitive to the
assumed mine electricity price and the utility avoided cost. For example, a power
generation project is not profitable for Mine C when a mine electricity price of
40/kwh and a utility avoided cost of 20/kwh are assumed. However, increasing
either the mine electricity price or the utility avoided cost by 10/kwh results in a
very profitable project.
• Though Mine A produces significantly less gas than do Mines B and C, a power
generation project is lucrative for Mine A because of the relatively high rates
assumed for the mine electricity price (5.50/kwh) and the utility avoided cost
(4.50/kwh).
• In comparison to pipeline projects, power generation projects require higher initial
capital investment due to the high cost of installing gas turbines (on the order of
$1100/kW). This means that a project may have relatively high NPVs but lower
IRRs compared to pipeline and local use projects.
• Smaller power generation projects that are designed to generate electricity just to
meet the continuous on-site needs of coal mines are also cost-effective. These
smaller projects have significantly lower initial capital costs, because a smaller
turbine is used. For the sample mines, however, these smaller projects were not
as profitable as the projects involving generation of electricity for on-site use and
off-site sale.
Pipeline Injection
• The sale of recovered methane to a pipeline may be a very lucrative option for
mines with high methane emissions. This analysis examined the following two
types of pipeline sales projects: 1) sale of high quality gas that would not require
enrichment; and 2) sale of all gas recovered from a degasification system, with
enrichment required for lower quality gas. For Mines B and C, both pipeline
alternatives are profitable.
Conclusion May 1995 Page 25
-------
Local Use
The results for Mines B and C show that, for very large and gassy mines, the sale
of a small portion of recovered gas can still result in a profitable project. For Mine
B, 40% of the recovered gas could be sold to a pipeline without requiring
enrichment. For Mine C, only 25% of the gas was assumed to be suitable for sale
to a pipeline without enrichment.
For both Mine B and Mine C, pipeline projects that included enrichment of lower
quality gas were more profitable than the projects that did not utilize the lower
quality gas. Accordingly, the results show that enrichment of gob gas may be a
profitable option for some mines. Moreover, these projects result in larger
emissions reductions than do projects that do not utilize the lower quality gas.
For both Mine B and Mine C, the pipeline projects were more lucrative than were
the power generation projects. These results are due to the low mine electricity
prices and utility avoided costs assumed for these mines, as well as the close
proximity of the mines to an existing pipeline.
For Mine A, however, neither the sale of only high quality gas nor the enrichment
of low quality gas was profitable. At the relatively low gas price that was assumed
in this analysis ($1.50/mcf), Mine A did not produce enough gas to offset the initial
capital costs of the project.
The sale of gas to a nearby industry or institution with a high demand for natural
gas can be a very profitable way of utilizing recovered gas. This analysis
assumes that a local industrial or institutional consumer would be willing to
purchase recovered coal mine methane gas at a price 25% less than the existing
industrial end-user rate. Based on this assumption, local use projects can
generate large revenues, due to the high industrial end-user gas prices charged
in many regions.
The key factors determining whether a local use project will be profitable are the
potential user's annual demand for natural gas and the distance between the mine
and the user.
In this assessment, only Mine C is assumed to have an industrial user located in
close proximity. For Mine C, even though it is assumed that the nearby industrial
user can only purchase 30% of the recovered methane and that the user is five
miles from the mine, a project would still be very profitable.
While local use projects appear to be extremely profitable, many mines may not
be located near facilities that have large natural gas demands. For these mines,
it may be worthwhile to identify industries or institutions that would be willing to
relocate near the mine-site to take advantage of the low-cost energy.
Conclusion May 1995 Page 26
-------
Use in a Thermal Dryer
• This assessment shows that it may be profitable for a mine to switch from using
coal in a thermal dryer to using recovered coal mine methane.
• The economics of switching from a coal-fired to a gas-fired thermal dryer were
evaluated for Mine C. For this mine, even though a high conversion cost is
assumed, the project was still shown to be profitable (the NPV was $0.02 million).
• At Mine C, about 40% of the recovered methane was utilized in the thermal dryer.
Combined Projects
• Projects that involve more than one utilization option can also provide a significant
source of revenue for the mine. At Mine B, a project involving 1) sale of high
quality methane to a pipeline and 2) use of lower quality methane to generate
electricity to meet continuous on-site needs results in a NPV of $9.3 million and
an IRR of 25.3%.
• At Mine C, a project involving 1) the sale of gas to a pipeline, 2) sale of gas to
an end-user, and 3) use of gas in an on-site thermal dryer, results in a NPV of
$10.4 million and an IRR of 25.6%. Under this combined approach, 95% of the
recovered gas is utilized.
Emissions Avoided
• For all mines, large emissions reductions were achieved. Several types of projects
evaluated at each of the mines involved utilization of all of the methane recovered
from the degasification systems. For these projects, emissions reductions
achieved ranged from 0.311 million tons of C02 equivalent at Mine A to 1.397
million tons at Mine B.
• Several options evaluated did not utilize the full amount of methane currently
emitted from degasification systems at the sample mines. The portion of
recovered gas that was utilized ranged from 17% (for an electricity project solely
to meet continuous on-site needs at Mine C) to 40% (for a project involving sale
of high quality methane at Mine B). Even though only a portion of the gas was
used, these projects still resulted in large emissions reductions. For Mine B,
utilizing 17% of the recovered methane yields emissions reductions equivalent to
0.5 million tons of carbon dioxide. Utilizing 40% of the methane recovered at Mine
B results in emissions reductions equivalent to 0.2 million tons of carbon dioxide.
Projects that combined one or more of these utilization options achieved much
higher emissions reductions.
In conclusion, the analysis has shown that methane recovery and utilization projects can be
profitable for mines with very different characteristics. Furthermore, several different types of
projects may be feasible for an individual mine. The preferred project will depend on the quantity
and quality of the recovered gas, the relative gas and electricity prices, initial capital costs, and
other site-specific factors. In all cases, methane utilization projects can lead to very large
emissions reductions.
Conclusion May 1995 Page 27
-------
APPENDIX A
CALCULATIONS AND ASSUMPTIONS USED IN THE ANALYSIS
This Appendix provides a detailed description of the steps used to perform the
discounted cash flow analysis of the potential for profitable methane recovery and utilization
at the Sample Mines evaluated in this report. Specifically, for each step in the analysis, this
Appendix provides information on:
1) The equations/formulas used in the analysis;
2) The assumed values used in the equations; and
3) The sources used to develop the equations and assumptions.
In addition to describing the assumptions used in the discounted cash flow analysis for the
Sample Mines, this Appendix should be useful to anyone desiring to evaluate the economics
of utilizing coal mine methane.
The Appendix is divided into the following five sections: 1) Methane Emitted and
Recovered, 2) Gas and Electricity Production and On-Site Energy Needs, 3) Capital and
Operating Costs, 4) Revenues Generated and Savings Realized, and 5) Financial
Assumptions. Throughout this Appendix, Sample Mine A is used to demonstrate how project
costs and revenues and a net present value are estimated for the mines evaluated in the
report. The table below shows the basic characteristics for Sample Mine A.
Sample Mine A Characteristics
Coal Production:
Ventilation Emissions:
Degasification Emissions
Total Emissions
Degasification Systems Used:
Mine Electricity Price
Utility Avoided Cost
Local Industrial End-User Gas Price
Distance to Local Industrial User
Wellhead Gas Price
Distance teL
2.0 million tons/yr
1.4 Bcf/yr, 3.84 MMcf/d
0.6 Bcf/yr, 1.64 MMcf/d
2.0 Bcf/yr, 5.49 MMcf/d
Gob Wells
$0.055/kwh
$0.045/kwh
$3/mcf
20 miles
$1.50/mcf
B miles
1. Methane Emitted and Recovered
This section describes the process for estimating the quantity of methane emitted from
the mines and the amount of gas that could potentially be recovered and utilized.
Appendix A
May 1995
Page A-1
-------
Methane Emissions
The first step in performing an evaluation for each mine is to estimate the quantity of
methane currently being emitted to the atmosphere. Total emissions are comprised of
emissions from ventilation systems and emissions from degasification systems.
All underground coal mines have ventilation systems that pump large quantities of air
through the mine to ensure that methane levels remain within safe tolerances. These
ventilation systems emit large volumes of methane in low concentrations (typically less than
1.5%). Currently, there are no commercially viable techniques for utilizing methane emitted
from ventilation systems.
Methane is also emitted from degasification systems. Approximately 30 underground
mines in the U.S. use degasification systems as a supplement to their ventilation systems.
These systems, which are described in detail in the background section of the Mine Profiles
report (EPA, 1994), are either wells drilled from the surface or boreholes drilled from inside the
mine. Degasification systems recover large quantities of highly concentrated methane.
The portion of total methane emissions that are released from degasification systems
may vary from as low as 10 percent (for mines that only employ in-mine boreholes) to over 80
percent (for mines that employ a combination of pre-mining and post-mining recovery
techniques). For the Sample Mines, recovery efficiencies of 30, 50, and 40 percent were
assumed for Sample Mines A, B, and C, respectively.
While the Sample Mines evaluated in this report are assumed to employ degasification
systems, some mines with high emissions only use ventilation systems for methane control.
By installing degasification systems, these mines would potentially be able to use the
recovered gas as an energy source and would also enhance mine safety, improve
productivity, and reduce ventilation costs.
Methane Recovered and Utilized
For mines currently using degasification systems, potential methane recovered and
utilized may be less than, equal to, or greater than estimated current degasification emissions.
Most of the options examined for each mine assume that the total amount of methane
currently emitted from degasification systems at the mine could be utilized. These options
include use of the gas to generate power for on-site use and sale to a utility. Other options
examined for each mine assume that less than 100% of the methane recovered from
degasification systems is utilized. For example, for Mine C, the nearby industry that could
purchase the gas does not have a high enough annual demand to be able to use all of the
methane recovered from the mine. Furthermore, for all the mines, only a portion of the gas
recovered is suitable for pipelien sales without requiring enrichment. Accordingly, these
scenarios assume that less than 100 percent of the recovered gas is utilized. It is also
possible that the amount of methane recovered for utilization could exceed current methane
emitted from degasification systems. For example, if a mine were to drill additional gob wells
or boreholes or switch to using vertical wells in advance of mining, the amount of gas
produced from degasfication systems could be increased.
Appendix A May 1995 Page A-2
-------
Quality of Recovered Gas. The quality of the gas recovered depends upon the degasification
system employed and site-specific conditions. Methods that recover methane in advance of
mining (e.g., horizontal boreholes and vertical wells) produce nearly pure methane. In
contrast, methods that recover methane after mining (e.g., gob wells and cross-measure
boreholes) may produce methane mixed with mine air. While several U.S. mines are
producing methane from gob wells for sale to pipelines, some mines may not be able to
produce pipeline quality gas from gob wells. For the Sample Mines, it is assumed that only a
small portion of the total amount of methane recovered from gob wells would be suitable for
pipeline sales without enrichment. For power generation, gas quality is less of an issue since
the gas would be mixed with air prior to combustion. Similarly, gas quality may not be an
issue for local use, if a nearby industry or institution can utilize a medium BID gas.
2. Gas and Electricity Production, On-Site Energy Needs
This section shows the calculations used to determine the amount of gas that could be
produced for pipeline sales or local use and the level of electricity that could be generated.
Additionally, this section describes how mine energy needs are estimated.
Gas Produced for Pipeline Sales and Local Use. The amount of gas that could be produced
for sale to a pipeline or a local user is the amount of methane recovered minus the amount of
gas needed to fuel the compressors. Compressors are estimated to require fuel at a rate of
10 cf per brake horsepower hour. The brake horsepower needed for compression is
discussed in more detail in Section 3. As shown in that section, the total brake horsepower
needed for a pipeline sales project (horsepower for a satellite compressor and a sales
compressor) is 493. Compressor loss is calculated as follows:
493 hp x 10 cf/hp hr x 8760 hrs/yr = 43 MM cf/yr
In general, about 5 to 10 percent of the methane recovered will be used to fuel the
compressors. For Sample Mine A, the amount of gas used to fuel the compressors
represents 7.2% of the total gas recovered.
Additional fuel is used during the production process when enrichment of the gas is required.
An estimated 24 percent of the recovered gas is required to fuel the enrichment equipment.
For Mine A, the total amount of gas recovered each year minus the amount used to fuel the
compressors is 557 MM cf/yr. Assuming that all of this gas will be enriched prior to sale to a
pipeline, 24 percent (about 134 MM cf/yr) is used in the enrichment process, leaving 423 MM
cf/yr of gas that can be sold to a pipeline.
Electricity Generation. Potential electricity production is estimated from the gas flow rate and
the heat rate (BTUs/kwh) of a gas turbine.1 Gas turbine heat rates may range from 8000 to
14000 BTUs/kwh. For this analysis, the heat rate of a gas turbine is assumed to be 11,000
BTUs/kwh. For Sample Mine A, potential electricity generation is estimated as follows.
600 MMcf/yr - 28.8 MMcf/yr used to fuel the satellite compressor = 571.2 MMcf/yr
used to generate electricity.
1 Internal combustion engines could also be used, gas turbines, however, are more suitable since they are less
sensitive to fluctuations in gas quality.
Appendix A May 1995 Page A-3
-------
571.2 MMcf/yr x 970 BTUs/cf x kwh/11000 BTUs = 50.4 MM kwh/yr
The kW capacity needed for the generator would be 50.4 million kwh/yr x yr/8760 hrs
= 5.75 MW.
Mine Electricity Demand (kwh/vr). Electricity generated from recovered methane may be used
to meet a mine's on-site electricity needs. Electricity demand at underground coal mines
varies widely, with the more gassy mines requiring greater amounts of electricity per ton of
coal mined due to higher ventilation demands. Based on conversations with mine operators
and U.S. Bureau of Mines officials, it appears that electricity demands at gassy underground
mines may range from as low as 10 kwh/ton to over 50 kwh/ton. This analysis assumes that
the Sample Mines require a value of 24 kwh/ton for the mine and an additional 6 kwh/ton for
the preparation plant. For Sample Mine A, annual electricity needs would be calculated as
follows: 2 million tons/yr x (24 + 6) kwh/ton = 60 million kwh/yr.
Mine Electric Capacity Demand (kW). A mine's electricity capacity demand pattern is also
examined in order to determine how much electricity may be used on-site. As a simplifying
assumption, this analysis divides electricity demand into two components: continuous
demand and operating demand. Continuous demand is the amount of electricity required 24
hours a day, 365 days a year, regardless of whether the mine is in operation. Operating
demand is the additional demand for electricity when the mine is in full operation. The
analysis assumes that the sample mines are in operation for 16 hours per day, 220 days per
year (3,520 hrs/yr) and that 50 percent of annual electricity needs (kwh/yr) are accounted for
by operating demand. Using these assumptions, Sample Mine A's operating demand (in kW)
is: (50% x 60 million kwh/yr)/3520 hrs/yr = 8,523 kW. Continuous demand is (50% x 60
million kwh/yr)/8760 hrs/yr = 3,425 kW. Therefore, total electricity demands when the mine is
operating are 11,948 kW.
Energy Demand at Preparation Plant. Some coal mines currently use coal as a primary
source of fuel for thermal dryers at their preparation plant facilities. In some cases, it may be
possible to used recovered gas in place of coal at in thermal dryers. In this analysis, only
Mine C uses a thermal dryer. This analysis assumes that Mine C consumes roughly 1 ton of
coal for each 150 tons of coal processed in a thermal dryer.
3. Capital and Operating Costs
This section describes the capital and operating costs that are included in the
analysis. Table A-1 shows the specific costs that are used and provides sample calculations
using data for Sample Mine A.
Degasification Systems. For those mines that already employ degasification systems, the
costs of drilling and installing degasification systems are not an incremental cost associated
with a utilization project. Accordingly, drilling costs are not included in the economic
assessment for Sample Mines A, B, and C. In the Appalachian basin, costs for drilling gob
wells typically range from $28 to $42 per foot for a 7 to 10 inch diameter hole, depending on
the rock strata above the coal seam. A typical gassy underground coal mine might require a
gob well to be drilled to a depth of from 400 to 1300 feet. The number of wells needed varies
from 2 to 6 per longwall panel, with an average longwall panel producing about 1 million tons
of coal. This analysis assumes that one gob well is drilled for every 250,000 tons of coal
mined.
Appendix A May 1995 PageA-4
-------
TABLE A1: SUMMARY OF COST ASSUMPTIONS USED IN THE ANALYSIS ||
Cost Item
Number or
Size of Units
Needed
Cost Per
Unit
Cost Calculation for Sample
Mine A
Applicable for All
Utilization Options?
Pipe
Line
Power
Local/
OnSlte
Notes I
Degaslflcatton Systems ||
Annual Well
Drilling and
Installation Costs
1 well for every
250,000 tons of
coal mined
Per well drilling
costs are $28 to
$42 per foot
The number of wells drilled each year at
Sample Mine A is 2,000,000 tons of coal
mined per year x 1 well/250,000 tons of coal
= 8 wells per year.
Drilling costs are not included for Sample
Mine A because the Mine already employs
degasification systems.
X
X
X
For an economic assessment of
a methane utilization project, the
cost of Installing degasification
system should not be included
for mines that already employ
these systems.
I
.-'.'•...•..'•'' : '.""•• II
Compression Costs ||
Wellhead
Exhauster/blower
Initial capital cost
since blowers can
be moved from
well to well
Compressor Site
Preparation
Satellite
Compressor
Capital Cost
Sales
Compressor
Capital Cost
Compressor
Operating Cost
1 blower for each
well
Applicable for
satellite and sales
compressor
200 HP/MMCFD
100 HP/MMCFD
$20,000/well
$70,000 for each
compressor
required
$600/hp
$600/hp
$12,000 per compressor per year
Cost of blower not included for Sample Mine
A since mine already uses gob wells.
If Sample Mine A did not use gob wells, cost
would be estimated as follows:
$20,000 per well x 8 wells per year =
$160,000 initial capital cost.
For pipelines sales options: site preparation
for Sample Mine A will be $140,000. For
other options, where only a satellite
compressor is required, site preparation will
be $70,000.
Gas flow rate for the Sample Mine A is 1.6
MMCFD; 1.6 MMCFD x 200 HP/MMCFD =
320 HP; 320 HP x $600/HP = $192,000
Gas flow rate for the Sample Mine A Is 1.6
MMCFD; 1.6 MMCFD x 100 HP/MMCFD =
160 HP; 160 HP x $600/HP = $96,000
For pipeline projects, $24,000 per year.
For other projects, $12,000 per year.
X
X
X
X
X
X
X
X
X
X
X
X
X
Cost of wellhead
blower/exhausters are not
included for mines that already II
employ gob wells since it is I
assumed the mine already
would use a blower at each well. II
Initial capital cost. II
Satellite compressors will pick |(
up the gas coming from the
wellhead exhauster/blower at II
about 16 to 17 psia and will
boost the gas to 150 to 250 psia |
Sales compressor will pick up II
the gas coming from the satellite II
compressor at about 250 psia
and boost it to 800 to 1000 psia,
the typical pressure for a sales
pipeline. ||
Annual operating cost.
-------
TABLE A1: SUMMARY OF COST ASSUMPTIONS USED IN THE ANALYSIS
Cost Item
Number or
Size of Units
Needed
Cost Per
Unit
Cost Calculation for Sample
Mine A
Applicable for All
Utilization Options?
Pipe
Line
Power
Local/
OnSlte
Notes
Gathering Line Costs . -.: || • V <% . - . >•.• ':,-.• ^.. ..••..••-.-•.: . ••. :,: .'. ', - - : .-„'.;.}•• -,,,:•-.: ... *.. ;. w '.
Annual cost of
Installing
Gathering Lines
Between
Individual Wells
and Satellite
Compressors
Initial Capital Cost
of Main Line from
Satellite
Compressor to
Sales
Compressor
Located At
Commercial
Pipeline
Initial Capital Cost
of Main Line from
Satellite
Compressor to
On-Sfte Generator
or Prep Plant
Initial Capital Cost
of Main Line from
Satellite
Compressor to
Local End User
Average 1200ft
per well
Estimated
distance between
a mine and the
nearest
commercial
pipeline is shown
in background
information for
each mine
evaluated
2000 feet
Estimated
distance between
a mine and the
nearest
commercial
pipeline is shown
In background
Information for
each mine
evaluated
$10/ft.
$4 to $6/ft for
HPDE pipe not
buried; $8/ft to
$12/ft for buried
lines
$200,000/mile 6 to
8 Inch lateral line
Range $30,000 to
$300,000 per mile,
depending on
terrain and right-
of-way costs
$10/ft
$200,000/m!le
Annual cost for Sample Mine A: 8 wells per
year x 1200 ft per well x $10/ft = $96,000/yr
As a conservative assumption, it is assumed
that gathering lines are not reused.
Sample Mine A is located five miles from a
commercial pipeline.
Cost would be $200,000 mile x 5 miles =
$1,000,000.
Sample Mine A: 2000 ft x $10/ft = $20,000
Sample Mine A is estimated to be 25 miles
from a local Industry that can use the
recovered gas. Costs are 20 miles x
$200,000/mile = $6,000,000.
X
X
X
X
X
X
on-site
use
X
off-site
sale
For some mines, it may be
possible to reuse gathering
lines. For this analysis, it is
assumed that the lines are not
reused. Therefore, installation
costs for lines between new
wells and the satellite
compressor are included every
year.
Main lateral line from mine to
sales pipeline may be a low
pressure line. Sales compressor
used to boost the gas from 250
psia to 800 to 1000 psia would
be located near the sales
pipeline, allowing the mine to
run a less expensive, low
pressure line from the satellite
compressor to the sales
compressor.
Initial capital cost.
Initial capital cost.
-------
TABLE A1: SUMMARY OF COST ASSUMPTIONS USED IN THE ANALYSIS ||
Cost Item
Number or
Size of Units
Needed
Dehydration
Wellhead Drip-pot
separator
Dehydrator,
Processing
Equip.
Operating Cost
for Dehydrator
1 separator for
each well
$40,000 per project
Cost Per
Unit
Cost Calculation for Sample
Mine A
Applicable for All
Utilization Options?
Pipe
Line
Power
Local/
OnSlte
Notes I
I
$2,000
$3,000 per unit per year
Sample Mine A has 8 wells x $2,000 per well
-$16,000
Sample Mine A will require a dehydration
system at $40,000
Annual dehydration operating costs for
Sample Mine A are $3,000.
X
X
X
X
X
X
X
Considered an initial capital cost
since separators can be moved |(
Initial capital cost.
Annual operating cost.
II
Other Standard Equipment ||
Gas Flow Meters;
Other Equipment
Gas flow meters are $5,000/well; other
equipment is $100,000 per project
Initial Capital Costs for Sample Mine A are
$140,000
X
X
X
Initial capital cost. II
1
Equipment Costa for Pipeline Sales Projects ||
Gas Sales Meter
and Gas Analyzer
Enrichment
Equipment
Enrichment
Operating Cost
Combined costs for gas sales meter
and gas analyzer are $20,000
$2,100,000 per project
$0.10/mcf
Initial Capital Costs for Sample Mine A are
$20,000
Initial capital costs for an enrichment project
are $2.1 million.
$0.10/mcf x 600,000 mcf/yr = $60,000/yr
X
X
X
Initial capital cost. II
Initial capital cost.
Annual operating cost.
I
Equipment Costa for Power Generation Projects ||
Gas Turbine
Turbine Operating
Costs
Utility
Interconnection
Cost
Size of turbine
(kW) = Gas Flow
Rate cf/hr x 970
BTUs/cf x 1
kwh/11000BTUs
$1,100 per kW
Installed capacity
$0,01/kwh generating capacity
$300,0000 Initial project cost.
Range: $100,00 to $500,000
Mine A's gas flow rate is 0.6 Bcf/yr (65,200
cf/hr after compression loss). 65,200 cf/hr x
970 BTU/cf x kwh/11000 BTUs = 5,750 kW
capacity needed. 5,750 kW x $1100/kW =
$6.32 million
Sample mine 11,900 kW x 8760 hours/yr =
50.4 million kwh/yr. 50.4 million kwh/yr x
$0.01/kwh = $503,695/yr
Sample Mine Cost: $300,000 per project
X
X
X
Initial Capital Cost
Annual Operating Cost
If a mine only used electricity to
meet on-slte needs, this cost
would not be included. ||
-------
TABLE A1: SUMMARY OF COST ASSUMPTIONS USED IN THE ANALYSIS
Cost Item
Number or
Size of Units
Needed
Cost Per
Unit
Cost Calculation for Sample
Mine A
Applicable for All
Utilization Options?
Pipe
Line
Power
Local/
OnSite
Notes
Equipment Costs for On-Slte Use of Gas or Sale to Local User
Conversion Cost
for Using Gas in
On-site Prep
Plant
Conversion Cost
for Industrial/
Institutional User
Purchasing Coal
Mine Gas
$750,000 initial project cost.
Range: $500,000 to $1 ,000,000
$800,000
Range: $400,000 to $1 ,200,000
Initial capital costs for Mine A would be
$750,000 per project.
Initial capital costs for Mine A would be
$800,000 per project
X
X
Initial capital cost
Initial capital cost
: pther Annual Options post? ^;: . '• . . : . : .: : -^ ; ' •., :; ' ,. .• ^,- - j^ ; .;;::: . ;,.>;,:;;;.- ;,;\ •. . . ;.; .,' : -:|: x ^ j\ 7 : ;>|;: . , .^^ ;;: ;,:;; ':: ; :; i ;; ;. .;: : ^j';;r^|^;.;;
General
Operations and
Maintenance
Employee Wages
and Benefits
*
Insurance
$30,000/yr
Minimum of either $100,000 or $10,000
x Number of wells drilled each year
$30,000/yr
For Sample Mine A, additional annual
operations expenses are $30,000 per year.
For Sample Mine A, labor costs are
$10,000/well x 8 wells per year = $80,000.
Since $80,000 < $100,000, an estimate of
$100,000/yr is used.
For Sample Mine A, insurance costs are
$30,000 per year.
X
X
X
X
X
X
X
X
X
Includes parts, supplies, fuel,
etc.
Annual operating cost
Annual operating cost
-------
Compression
The analysis assumes that all utilization options will require compression of the gas in
order to move it from the wellhead to the point of sales or end-use. The number and size of
compressors needed depends upon the gas flow rate, the distance to the point of use or
sale, and the pressure to which the gas must be compressed. All systems will include
wellhead blower/exhausters and a satellite compressor. Sale to a high pressure pipeline may
require an additional sales compressor. Exhibit A-1 shows the location of wellhead, satellite,
and sales compressors at Mine A.
Gob wells that vent methane to the atmosphere are normally equipped with a
blower/exhauster to enhance gas production for mine safety reasons. These units typically
apply a suction pressure of 2.5 to 5 psi (negative gauge) to the wellbore and discharge a few
psi above atmospheric pressure (16 to 17 psi). These blower/exhausters would provide
sufficient pressure to move the gas along the gathering lines to a satellite compressor. Costs
for wellhead blower/exhausters, which range from $10,000 to $30,000 depending on size and
prime mover, are not included for mines that already are assumed to have degasification
systems in place.
For all utilization options, a satellite compressor would be used boost the gas from 16
to 17 psi to 150 to 250 psi, a pressure sufficient for on-site use in a turbine or preparation
plant. As shown in Table A-1, the estimated brake horsepower needed for the satellite
compressor is 200 HP per million cubic feet of gas per day. The total estimated cost of a
satellite compressor includes a flat cost for site preparation ($70,000 per unit) plus a cost of
$600 per brake horsepower.
For options involving sale of the gas to a high pressure pipeline, an additional sales
compressor would be needed to boost the gas from 250 psi to 800 to 1000 psi, the typical
pressure for a sales pipeline. The size of compressor needed is calculated by assuming that
100 HP are needed per million cubic feet of gas produced per day. Normally, the sales
compressor would be located near the sales pipeline so that low pressure gathering lines
could be used to transport the gas to the pipeline.
Annual operating costs for compressors are assumed to be $12,000 for each
compressor.
Gathering Line Costs
For each mine, gathering lines will need to be installed between individual wells and
the satellite compressor. Additionally, a main gathering line will need to be installed that
leads from the satellite compressor to either: an on-site generator or preparation plant, a
sales compressor located at a commercial pipeline, or a local gas consumer. A diagram of
the layout for Mine A is shown in Exhibit A-1. As shown in this Exhibit, the length of
gathering line needed between individual wells and the satellite compressor is estimated to
be 1200 feet, while the length of line between the satellite compressor and an on-site
preparation plant or gas turbine is assumed to be 2000 feet. The estimated distance between
the satellite compressor and a sales compressor or local gas consumer is determined on a
mine-by-mine basis and is reported in the Mine Characteristics table of each assessment.
Appendix A
May 1995 Page A-9
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Exhibit A-1
Schematic of Gob Well Gas Gathering System
800 ft
TO:
GENERATOR
PIPELINE SALES COMPRESSOR
LOCAL INDUSTRIAL USER
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This analysis assumes that High Density Polyethylene (HPDE) pipe is used for the
gathering lines. Given the range of gas flows that would be common for a coal mine
methane recovery project, the diameter of the pipe is assumed to be from 4 to 6 inches On
mine property, the lines may potentially be left above ground. In other areas, the lines will
likely need to be buried. Costs for a 4-inch HPDE line installed on the surface range from
$4.00 to $6.00 per foot, depending on terrain. If burial of the lines is required, costs would
likely range from $8 to $12 per foot. As a conservative assumption, this analysis assumes a
cost of $10 per foot for gathering lines. In many cases, it may be possible to reuse
gathering lines leading from wells to the satellite compressor (lines may be moved as one
well stops producing and another well comes on line). As a conservative assumption, this
analysis assumes that gathering lines could not be reused.
Dehydration/Processing. All utilization options will require gas/water separation at the
wellhead, which is accomplished by using a small drip-pot, two-phase water separator placed
at each gob well. Capital costs for each unit are about $2,000 dollars and operating costs
are negligible. Utilization options involving gas sales to a pipeline or local user or use of the
gas in an on-site preparation plant will require additional dehydration. Glycol dehydrators
may be used to remove remaining water vapor in the gas. For sale to a pipeline, the
dehydration unit is normally used after compression to sales specifications. A large scale (2
MMcfd), high pressure (1000 psi) glycol separator unit can be obtained for between $20,000
and $50,000. This analysis assumes a capital cost of $40,000. Operating costs for glycol
dehydrators are assumed to be $3,000 per year.
Additional Gathering System Equipment. Additional gathering system equipment include
wellhead gas flow meters and other safety and processing equipment, which are estimated to
cost $5,000 per well and $100,000 per project, respectively.
Enrichment Equipment for Pipeline Sales. While some U.S. mines have been able to sell
methane recovered from gob wells to pipeline companies, enrichment of the gas to pipeline
standards may be required. For each of the Sample Mines, it is assumed that enrichment will
be required for a large portion of the methane recovered from gob wells. Enrichment consists
of removing nitrogen, oxygen, and carbon dioxide from the gob gas. Initial studies (e.g., DOE
1993) indicate that it should be technically and economically feasible to enrich gob gas using
a facility consisting of 1) a pressure swing adsorption (PSA) or selective absorption nitrogen
rejection unit, 2) a catalytic combustion deoxygenation process, 3) an amine or membrane
carbon dioxide removal system (if required), and 4) a conventional dehydration unit. Total
capital costs for a system relying on PSA for nitrogen removal are about $2.1 million
(excluding dehydration costs, which are discussed above). Operating costs are estimated to
be $0.10/mcf. These capital and operating costs are assumed in the analysis.
Additional Equipment for Pipeline Sales. In addition to the gathering system equipment
described above, an additional gas flow meter and gas analyzer are needed for sale to a
pipeline. The cost of this equipment is estimated to be $20,000.
Capital and Operating Costs for Power Generation Projects. The primary capital cost for
projects involving the use of recovered methane to generate electricity is the cost of a gas
turbine. Capital costs for gas turbines range from $800 to $1200 per kW installed capacity.
For this analysis, a capital cost of $1100 per kW is used. Operating costs are about
$0.01/kwh. In cases in which the mine could sell electricity generated in excess of on-site
needs to a utility, the analysis includes an additional "interconnection cost" of $300,000. The
interconnection cost includes all capital costs associated with upgrading electric lines and
Appendix A May 1995 PageA-11
-------
installation of other equipment needed so that the mine can sell electricity to the local grid.
Interconnection costs are likely to be in the range of $100,000 to $500,000 for typical small
power production projects (less than 80 MW).
An additional cost that may be incurred by mine operators desiring to generate electricity to
meet on-site electricity needs is the cost of "backup power." Utilities may charge high rates
for the "backup power" needed at the mine during times when the on-site generator is not
functioning. While the Public Utility Regulatory Policies Act (PURPA) stipulates that utilities
must supply backup power at nondiscriminatory rates, these charges may be much higher
than the normal rates paid by the mine due to the utility's need to maintain sufficient capacity
levels to meet the electricity demands of the mine. The additional costs of backup power are
not included in this assessment.
Conversion Cost for On-Site Use of Gas in a Preparation Plant or Sale of Gas to Nearby User.
For on-site and local direct gas use options, in addition to the costs required for gathering,
compression, and dehydration, the analysis includes a cost for conversion of existing
equipment to run on recovered coal mine methane. For the Sample Mines, the cost for
converting an on-site thermal dryer to operate on coal mine methane is estimated to be
$750,000. This estimate includes all converstion costs associated with switching from using
coal to using gas in a thermal dryer. For sale to a nearby industrial or institutional user, a
conversion cost of $800,000 is assumed. These conversion costs are assumed to include all
capital costs, fees, and permits associated with converting a system to operate on medium to
high BTU coal mine methane gas.
General Operations. Maintenance, and Insurance
In addition to the compression, dehydration, enrichment, and power generation
operating costs listed above, annual operating expenses are included for the following three
items: 1) employee salaries and benefits 2) general equipment maintenance, and 3)
insurance.
For employee salaries and benefits, the analysis assumes that a project would require
at least two full-time personnel to maintain and operate a gas recovery system. Salaries and
benefits for each person are estimated at $50,000 per year, for a total of $100,000. Since
larger projects may require additional personnel, this analysis assumes that employee salaries
and benefits are a minimum of either $100,000 or $10,000 per number of wells drilled each
year.
In addition to the operating costs discussed above for compression, dehydration,
enrichment, and power generation, a flat annual cost of $30,000 is also included for
equipment maintenance and materials.
Finally, insurance costs associated with a methane utilization project are estimated to
be $30,000 per year.
4 Revenue and Savings
This section describes how annual revenues and savings are calculated in the
economic assessment.
Appendix A May 1995 Page A-12
-------
Revenues from Pipeline Sales. Sale of recovered coal mine methane gas may yield high
revenues, depending upon the amount of gas recovered and the wellhead gas price. For the
Sample Mines, it is assumed that the wellhead gas price is $1.50 per mcf. For Sample Mine
A, assuming that the mine recovers methane from gob wells and that enrichment is required,
total gas produced for sale is 423,000 mcf/yr (see discussion above regarding amount of gas
produced for pipeline sales). At a wellhead gas price of $1.50/mcf, total annual revenues for
Mine A are $634,500.
Savings from On-site Use of Electricity and Revenue from Electricity Sales. In the analysis,
mines are assumed to first use all electricity generated to meet on-site electricity needs and
then to sell any excess electricity to a utility. This analysis shows that many of the gassiest
mines could generate more electricity than is needed on-site. The annual savings that may
be achieved from on-site use of electricity is determined by multiplying the electricity used to
meet on-site needs (kwhs/yr) by the assumed price the mine currently pays for its electricity
(which varies by mine and is shown in the Mine Characteristics table).
For Mine A, the electricity used to meet on-site needs is calculated as follows. As
shown in Section 2 of this Appendix, the level of electric capacity that could be generated at
the Sample Mine is roughly 5.75 MW, which is higher than the mine's continuous demands of
3.4 MW, but lower than the mine's total operating demands of 11.9 MW. The price the mine
pays for its electricity is $0.055/kwh. The savings associated with generating electricity to
meet continuous demands would be 3.4 MW x 8760 hrs/yr x $0.055/kwh, or approximately
$1.6 million per year. During times when the mine is in full operation (16 hours/day, 220 days
a year, or 3520 hours/yr), the full 5.75 MW of capacity may be used to meet on-site needs.
The electricity savings associated with meeting this additional operating demand are:
5.75 MW total demand - 3.4 MW continuous demand = 2.35 MW
2.35 MW x 3,520 hours/year x $0.055/kwh = $0.5 million per year.
Accordingly, for Mine A, the total savings that can be achieved from using recovered methane
to meet on-site needs are $2.1 million ($1.6 million to meet continuous needs plus $0.5 million
to meet additional operating needs).
The annual revenue that may be realized from selling "excess" electricity to a utility is
estimated by multiplying the electricity generated in excess of on-site needs by the assumed
avoided cost of the local electric utility (the utility avoided cost assumed for each mine is
shown in the Mine Characteristics table). For Sample Mine A, the utility avoided cost is
$0.045/kwh. Furthermore, electricity will be generated in excess of on-site needs only during
times when the mine is not fully operating. Since the mine is assumed to be in full operation
3520 hours per year, it is not fully operating the remaining 5,240 hours per year. Since 3.4
MW are required for continuous demand, an additional 2.35 MW of capacity are available
during times when the mine is not fully operating. Revenues are calculated as: 2.35 MW x
5,240 hours/yr x $0.045/kwh, or nearly $0.6 million per year.
Revenue from Sale of Gas to a Nearby Industrial or Institutional User. Sale of recovered gas
to a nearby industrial or institutional user may generate high revenues due to the high
commercial and industrial gas prices charged in many coal mining areas (typically in the
range of $4/mcf to $6/mcf). The analysis assumes that Mine C could sell recovered methane
at a price that 75 percent lower than the local industrial gas price, which was assumed to be
$5/mcf.
Appendix A
May 1995 Page A-13
-------
Savings from On-Site Use of Gas in a Thermal Dryer. Some mines currently use coal to fuel
thermal dryers at their preparation plant facilities. In some cases, the coal used in thermal
dryers is lower quality coal that would not be suitable for sale. In other cases, higher quality
coal that could be sold is used as fuel. Assuming higher quality coal is used in the
preparation plant, the mine operator could achieve savings by using methane in place of coal.
The annual savings that may be achieved are calculated by multiplying the market rate for
bituminous coal by the amount of coal that would be "saved" by using gas in the preparation
plant. Of the Sample Mines, only Mine C uses coal to fuel a thermal dryer at its preparation
plant.
5 Financial Assumptions
In order to perform a net present value analysis of a methane utilization project, the following
financial assumptions are used.
Project Lifetime: For the Sample Mines, unless otherwise noted, the assumed remaining
lifetime of the mine is used as the lifetime of the project.
Inflation Rate: The annual rate of inflation is assumed to be 4 percent.
Discount Rate: A real discount rate of 6 percent is assumed, which is roughly equal to a
nominal discount rate of 10 percent (6 percent real discount rate + 4 percent inflation rate).
Financing of Capital Investments: As a conservative and simplifying assumption, all equity
financing is assumed for capital investments.
Depreciation Method: Straight-line depreciation is used for all capital items. The depreciation
period is assumed to be the same as the project lifetime. No salvage value is included in the
assessment.
Depletion: No depletion allowance is included.
Tax Rate: A marginal combined state and federal tax rate of 40 percent is assumed.
Nonconventional Fuel Tax Credit: Coalbed methane produced from wells drilled between
December 31, 1979, and January 1,1993, may qualify for the nonconventional fuel tax credit
established under Section 29 of the Internal Revenue Code. Since it is assumed that gob
wells would be drilled after January 1993, this tax credit is not included in this analysis.
Royalties: Royalty payments of 12.5 percent are included in the analysis.
Appendix A May 1995 Page A-14
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Appendix B.
1990 Coal Production and Methane Emissions for Mines
Known or Believed to Have Degasification Systems
Mine Name
Amonate2
Arkwright No.1
Bailey3
Blacksville No. 2
Cumberland
Deserado
Emerald No. 1
Federal No. 2
Golden Eagle
Humphrey
Loveridge No. 222
Mine 844
Old Ben No. 26
Osage No. 3
Pinnacle No. 505
Robinson Run No. 95
Shawnee5
Wheatcroft No. 9
Reported
Coal
Production
(mmtons/yr)
1.0
1.9
5.6
3.8
3.0
1.7
1.6
4.2
1.5
3.3
2.8
1.3
2.6
1.8
3.4
1.9
1.1
2.7
Reported
Vent
Emissions
(Bcf/yr)
0.8
1.4
1.8
3.4
2.1
0.5
1.1
3.8
2.2
2.3
1.9
1.1
0.7
1.4
2.8
0.8
0.5
0.2
Estimated
Degas
Emissions1
(Bcf/yr)
0.4
0.8
0.9
1.8
1.1
0.3
0.6
2.1
1.2
1.2
1.0
0.0
0.4
0.7
2.8
0.4
0.3
0.1
Estimated
Total
Emissions
(Bcf/yr)
1.2
2.2
2.7
5.2
3.2
0.8
1.8
5.9
3.4
3.5
2.8
1.1
1.0
2.1
5.6
1.2
0.7
0.3
Estimated
Emissions
Per Ton
(cf/ton)
1222
1153
483
1369
1080
487
1062
1405
2216
1069
1033
853
395
1171
1669
635
672
127
1 Degasification emissions were estimated to be 35% of total emissions for all mines except
Pinnacle No. 50. For this mine, it was reported that degasification emissions represent 50% of total
emissions.
2 These mines are currently idle.
3 This mine is part of the Bailey/Enlow Fork mine complex. Enlow Fork began producing coal in
the early 1990s.
4 It is unclear whether this mine had a degasification system in 1990, or has one at present.
5 Pinnacle No. 50 and Shawnee have recently merged to form one mine, Pinnacle No. 50.
Detailed information on these mines is provided in the EPA report Identifying Opportunities for
Methane Recovery at U.S. Coal Mines: Draft Profiles of Selected Gassy Underground Coal Mines.
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FOR MORE INFORMATION...
For more information on coalbed methane recovery experiences, project potential, or
program activities and accomplishments, contact:
Karl Schultz, Coalbed Methane Program Manager
US Environmental Protection Agency
Mail Code 6202J
Atmospheric Pollution Prevention Division
401 M Street, SW
Washington, DC 20460
Telephone: 202 233-9468
Facsimile: 202 233-9569
Internet: schuttz.karl@epamail.epa.gov
Automated Faxback: Call 202 233-9659 and enter #1740
Selected list of EPA Coalbed Methane Outreach Reports:
• USEPA (U.S. Environmental Protection Agency). Identifying Opportunities for
Methane Recovery at U.S. Coal Mines: Draft Profiles of Selected Gassy
Underground Coal Mines. Office of Air and Radiation (6202J). Washington,
D.C. EPA-430-R-94-012. September 1994.
• USEPA (U.S. Environmental Protection Agency). The Environmental and
Economic Benefits of Coalbed Methane Development in the Appalachian
Region. Office of Air and Radiation (6202J). Washington, D.C. EPA-430-R-94-
007. April 1994.
• USEPA (U.S. Environmental Protection Agency). Opportunities to Reduce
Anthropogenic Methane Emissions in the United States. Report to
Congress. Office of Air and Radiation (6202J). Washington, D.C.
EPA-430-R-93-012. October 1993.
USEPA (U.S. Environmental Protection Agency). Anthropogenic Methane
Emissions in the United States: Estimates for 1990. Report to Congress.
Office of Air and Radiation (6202J). Washington, D.C.
EPA-430-R-93-003. April 1993.
In addition, EPA reports exploring the various state and federal financing assistance
available for coalbed methane projects will be available soon.
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