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<pubnumber>430R99013</pubnumber>
<title>U.S. Methane Emissions 1990-2020 Inventories, Projections, and Opportunities for Reductions</title>
<pages>160</pages>
<pubyear>1999</pubyear>
<provider>NEPIS</provider>
<access>online</access>
<operator>mja</operator>
<scandate>11/04/09</scandate>
<origin>PDF</origin>
<type>single page tiff</type>
<keyword>methane emissions gas emission reductions mmtce epa manure exhibit coal natural cost production tce systems landfills mines bleed dairy estimates</keyword>
<author></author>
<publisher></publisher>
<subject></subject>
<abstract></abstract>

United States
Environmental Protection
Agency
Office of Air
and Radiation
(6202J)
EPA430-R-99-013
September 1999
&EPA U.S. Methane Emissions 1990 - 2020:
Inventories, Projections, and
Opportunities for Reductions
Natural Gas Systems
Emissions Forecast
Landfills
1990 2000 2010 2020
Livestock Manure
Management
Marginal
Abatement Curves
Greenhouse
Gas Emissions
Methane
Enteric
Fermentation
image:

How to Obtain Copies

You may electronically download this document from the U.S. EPA's web page on Climate
Change - Methane and Other Greenhouse Gases at http://www.epa.gov/ghginfo. To obtain
additional copies of the report, call +1(888)STAR-YES (1(888) 7827-937).
For Further Information

The results presented in this report are available to analysts in an electronic format. For
additional information, contact Mr. Francisco de la Chesnaye, Office of Air and Radiation,
Office of Atmospheric Programs, Climate Protection Division, Methane Energy Branch, Tel
+1(202) 564 - 0172, Fax +1(202) 565 - 2077, or e-mail delachesnaye.francisco@epa.gov.
image:

U.S. Methane Emissions 1990-2020
Inventories, Projections, and
Opportunities for Reductions
September 1999
U.S. Environmental Protection Agency
Office of Air and Radiation
401 M St., SW
Washington, DC 20460
U.S.A.
image:

image:

Abbreviations, Acronyms, and Units
AF Activity factor kW
AS AE American Society of Agricultural kWh
Engineers LMOP
Bcf Billion cubic feet MAC
BMP Best management practice Mcf
CAA Clean Air Act MMBtu
CCAP Climate Change Action Plan MMcf/d
C&D Construction and demolition MMTCE
CFC Chlorofluorocarbon MMT
CH4 Methane MSHA
CMOP Coalbed Methane Outreach Program MSW
CO2 Carbon dioxide MW
DI&M Directed inspection and maintenance NMOC
DOE Department of Energy NPV
EF Emission factor O&M
EIA Energy Information Administration PRO
EPA Environmental Protection Agency RLEP
E-PLUS Energy Project Landfill Gas Utilization Tcf
Software Tg
GAA Government Advisory Associates TCE
GHG Greenhouse gas UNFCCC
GSAM Gas Systems Analysis Model
GWP Global warming potential USDA
1C Internal combustion VOC
IPCC Intergovernmental Panel on Climate WIP
Change
kilowatt
kilowatt-hour
Landfill Methane Outreach Program
Marginal abatement curve
Thousand cubic feet
Million British thermal units
Million cubic feet per day
Million (metric) tons of carbon equivalent
Million (metric) tons
Mine Safety and Health Administration
Municipal solid waste
Megawatt
Non-methane organic compound
Net present value
Operation and maintenance
Partner-reported opportunity
Ruminant Livestock Efficiency Program
Trillion cubic feet
Teragram
Metric ton of carbon equivalent
United Nations Framework Convention on
Climate Change
United States Department of Agriculture
Volatile organic compound
Waste-in-place
Conversions
1 Mcf Methane = 1 MMBtu
lBcf=l,OOOMMcf
lTg=lxl012g
1 Tg CH4 = 1 MMT CH4
1 MMT CH4 = 5.73 MMTCE
GWPofCO2=l
GWPofCH4 = 21
image:

Acknowledgements
This report was produced by the U.S. EPA's Methane Energy Branch in the Office of Air and Radiation,
Office of Atmospheric Programs, Climate Protection Division. The report would not have been complete
without the efforts and contributions of many individuals and organizations. The following individuals
reviewed a preliminary version of this report and provided useful comments, many of which were
addressed for this final version. The reviewers included: Peter Carothers (Alternative Energy
Development), Tom Conrad (SCS Engineers), Kimberly Denbow (American Gas Association), Lorna
Greening (Hagler Bailly Services, Inc.), Matthew R. Harrison (Radian International), William Jewell
(Cornell University), Barry L. Kintzer (USDA), Eugene Lee (USEPA), Bob Lott (Gas Research Institute),
Richard Mattocks (Environomics), John Reilly (Massachusetts Institute of Technology), Glenda E. Smith
(American Petroleum Institute), Pramod C. Thakur (Consol Inc.), Lori Traweek (American Gas
Association), Greg Vogt (SCS Engineers), Ann C. Wilkie (University of Florida), and Peter Wright
(Cornell University). Although these individuals participated in the review of this analysis, their efforts
do not necessarily constitute an endorsement of the report's results or of any U.S. EPA policies and
programs.
In particular, the Methane Energy Branch staff contributed significantly to the report. They are: Ed Coe,
Shelley Cohen, and Brian Guzzone on Landfills; Paul Gunning and Carolyn Henderson on Natural Gas
Systems; Karl Schultz and Roger Fernandez on Coal Mining; Kurt Roos on Livestock Manure; Mark
Orlic and Tom Wirth on Enteric Fermentation; Bill Irving on Inventories; and Michele Dastin-van Rijn on
the preliminary version of the report. Francisco de la Chesnaye directed the final analysis and completion
of the report with support from Reid Harvey and oversight from Dina Kruger.
The staff of the Global Environmental Issues Group at ICF Consulting deserves special recognition for its
expertise, efforts in preparing many of the individual analyses, and for synthesizing this report.
image:

Table Of Contents
Abbreviations, Acronyms, Units, and Conversions i
Acknowledgements ii
Table of Contents iii
EXECUTIVE SUMMARY ES-1

1.0 INTRODUCTION AND AGGREGATE RESULTS 1-1
1.0 Overview of Methane Emissions 1-1
2.0 Sources of Methane Emissions 1-2
2.1 Natural Methane Emissions 1-2
2.2 Anthropogenic Methane Emissions 1-4
3.0 Options for Reducing Methane Emissions 1-6
4.0 Economic Analysis of Reducing U.S. Methane Emissions 1-7
5.0 Achievable Emission Reductions and Composite Marginal Abatement Curve 1-8
6.0 Significance of This Analysis 1-11
7.0 Background to This Report 1-11
8.0 References 1-13
9.0 Explanatory Notes 1-15
2.0 LANDFILLS 2-1
1.0 Methane Emissions from Landfills 2-2
1.1 Emission Characteristics 2-2
1.2 Emission Estimation Method 2-2
1.3 Emission Estimates 2-3
1.3.1 Current Emissions and Trends 2-4
1.3.2 Future Emissions and Trends 2-4
1.4 Emission Estimate Uncertainties 2-5
2.0 Emission Reductions 2-5
2.1 Technologies for Reducing Methane Emissions 2-6
2.2 Cost Analysis of Emission Reductions 2-6
2.2.1 Electricity Generation 2-7
2.2.2 Direct Gas Use 2-8
2.3 Achievable Emission Reductions and Marginal Abatement Curve 2-9
2.4 Reduction Estimate Uncertainties and Limitations 2-11
U.S. Environmental Protection Agency - September 1999 Table of Contents iii
image:

3.0 References 2-13
4.0 Explanatory Notes 2-15
3.0 NATURAL GAS SYSTEMS 3-1
1.0 Methane Emissions from Gas and Oil Systems 3-2
1.1 Emission Characteristics 3-2
1.2 Emission Estimation Method 3-3
1.2.1 Natural Gas System Emissions 3-3
1.2.2 Oil Industry Emissions 3-3
1.3 Emission Estimates 3-4
1.3.1 Current Emissions and Trends 3-5
1.3.2 Future Emissions and Trends 3-5
1.4 Emission Estimate Uncertainties 3-6
2.0 Emission Reductions 3-7
2.1 Technologies for Reducing Methane Emissions 3-7
2.2 Cost Analysis of Emission Reductions 3-7
2.3 Achievable Emission Reductions and Marginal Abatement Curve 3-9
2.4 Reduction Estimate Uncertainties and Limitations 3-11
3.0 References 3-12
4.0 Explanatory Notes 3-14
4.0 COALMINING 4-1
1.0 Methane Emissions from Coal Mining 4-2
1.1 Emission Characteristics 4-2
1.2 Emission Estimation Method 4-3
1.2.1 Underground Mines 4-3
1.2.2 Surface Mines 4-5
1.2.3 Post-Mining 4-5
1.2.4 Methodology for Estimating Future Methane Liberated 4-5
1.3 Emission Estimates 4-5
1.3.1 Current Emissions and Trends 4-5
1.3.2 Future Emissions and Trends 4-6
1.4 Emission Estimate Uncertainties 4-6
2.0 Emission Reductions 4-7
2.1 Technologies for Reducing Methane Emissions 4-7
2.1.1 Methane Recovery 4-7
2.1.2 Methane Use 4-7
2.2 Cost Analysis of Emission Reductions 4-8
2.3 Achievable Emission Reductions and Marginal Abatement Curve 4-10

iv U.S. Methane Emissions 1990 - 2020: Inventories, Projections, and Opportunities for Reductions
image:

2.4 Reduction Estimate Uncertainties and Limitations 4-11
3.0 References 4-13
4.0 Explanatory Notes 4-14
5.0 LIVESTOCK MANURE MANAGEMENT 5-1
1.0 Methane Emissions from Manure Management 5-2
1.1 Emission Characteristics 5-2
1.2 Emission Estimation Method 5-3
1.3 Emission Estimates 5-4
1.3.1 Current Emissions and Trends 5-4
1.3.2 Future Emissions and Trends 5-4
1.4 Emission Estimate Uncertainties 5-5
1.4.1 Current Emissions 5-5
1.4.2 Future Emissions 5-6
2.0 Emission Reductions 5-6
2.1 Technologies for Reducing Methane Emissions 5-6
2.1.1 Switch to Dry Manure Management 5-7
2.1.2 Recover and Use Methane to Produce Energy 5-7
2.2 Cost Analysis of Emission Reductions 5-8
2.2.1 Costs 5-9
2.2.2 Cost Analysis Methodology 5-9
2.3 Achievable Emission Reductions and Marginal Abatement Curve 5-11
2.4 Reduction Estimate Uncertainties and Limitations 5-15
3.0 References 5-16
4.0 Explanatory Notes 5-17
6.0 ENTERIC FERMENTATION 6-1
1.0 Methane Emissions from Enteric Fermentation 6-2
1.1 Emission Characteristics 6-2
1.2 Emission Estimation Method 6-2
1.2.1 Factors Affecting Methane Emissions from Enteric Fermentation 6-2
1.2.2 Method for Estimating Current Methane Emissions 6-3
1.2.3 Method for Estimating Future Methane Emissions 6-3
1.3 Emission Estimates 6-4
1.3.1 Current Emissions and Trends 6-4
1.3.2 Future Emissions and Trends 6-4
1.4 Emission Estimate Uncertainty 6-5
2.0 Emission Reductions 6-6
2.1 Technologies for Reducing Methane Emissions 6-6

U.S. Environmental Protection Agency - September 1999 Table of Contents v
image:

2.2 Achievable Emission Reductions 6-8
2.3 Reduction Estimate Uncertainties and Limitations 6-10
3.0 References 6-11

Appendix I: Supporting Material for Composite Marginal Abatement Curve 1-1
Appendix II: Supporting Material for the Analysis of Landfills 11-1
Appendix III: Supporting Material for the Analysis of Natural Gas Systems 111-1
Appendix IV: Supporting Material for the Analysis of Coal Mining IV-1
Appendix V: Supporting Material for the Analysis of Livestock Manure Management V-1
Appendix VI: Supporting Material for the Analysis of Enteric Fermentation VI-1
vi U.S. Methane Emissions 1990 - 2020: Inventories, Projections, and Opportunities for Reductions
image:

Executive Summary
Methane gas is a valuable energy resource and the leading anthropogenic contributor to global warming after car-
bon dioxide. Atmospheric methane concentrations have doubled over the last 200 years and continue to rise, al-
though the rate of increase is slowing (Dlugokencky, et al., 1998). By mass, methane has 21 times the global
warming potential of carbon dioxide over a 100-year time frame. Methane accounts for 10 percent of U.S. green-
house gas emissions (excluding sinks) and reducing these emissions is a key goal of the U.S. Climate Change Ac-
tion Plan (EPA, 1999).
The major sources of anthropogenic methane emissions in the U.S. are landfills, agriculture (livestock enteric fer-
mentation and manure management), natural gas and oil systems, and coal mines. Smaller sources in the U.S. in-
clude rice cultivation, wastewater treatment, and others. Unlike other greenhouse gases, methane can be used to
produce energy since it is the major component (95 percent) of natural gas. Consequently, for many methane
sources, opportunities exist to reduce emissions cost-effectively or at low cost by capturing the methane and using
it as fuel.
This report has two objectives. First, it presents the U.S. Environmental Protection Agency's (EPA's) baseline
forecast of methane emissions from the major anthropogenic sources in the U.S., and EPA's cost estimates of re-
ducing these emissions. Emission estimates are given for 1990 through 1997 with projections for 2000 to 2020.
The cost analysis is for 2000, 2010, and 2020. Second, this report provides a transparent methodology for the cal-
culation of emission estimates and reduction costs, thereby enabling analysts to replicate these results or use the
approaches described herein to conduct similar analyses for other countries.

Baseline Methane Emission Estimates

EPA estimates annual emissions for 1990 to 1997 and forecasts emissions for 2000, 2010, and 2020. In 1990, the
U.S. emitted 169.9 million metric tons of carbon equivalent (MMTCE) or 29.7 Teragrams (Tg) of methane. By
1997, estimated methane emissions were slightly higher at 179.6 MMTCE (31.4 Tg) (EPA, 1999). The baseline
U.S. methane emission forecast for 2010 is 186.0 MMTCE (32.5 Tg) which is almost a ten percent increase over
the 1990 levels. However, this forecast excludes the expected reductions associated with U.S. voluntary programs.
When these programs are taken into account, methane emissions are expected to remain at or below 1990 levels
through 2020. Exhibit ES-1 shows current methane emissions and projections by industry.

Exhibit ES-1: U.S. Methane Emissions (MMTCE)
Source Breakdown of 1997 U.S. Methane Emissions
Source Breakdown of Baseline Forecast Emissions
MMTCE @
21 GWP
Enteric
Fermentation 1
Manure 10%
%^
k Landfills 37%
Coal 10%

Other 4%
Natural Gas and Oil 20%
Total = 179.6 MMTCE
Source: EPA, 1999.
CH4
200 - - 35

172 --30

143 --25

115 --20

86 --15

57 --10

29 -- 5
Other

Enteric Fermentation

Livestock Manure

Coal Mining

Natural Gas and Oil

Landfills
1990 2000 2010 2020
Year
U.S. Environmental Protection Agency - September 1999
Executive Summary ES-1
image:

To estimate historic and future emissions, EPA char-
acterizes the source industries in detail and identifies
the specific processes within those industries that pro-
duce emissions. Forecasts are based on a consistent
set of industry factors, e.g., consumption, prices, tech-
nological change, and infrastructure makeup. The
major emission sources are outlined below.
> Landfills. The largest source (accounting for 37
percent) of U.S. anthropogenic methane emis-
sions, landfills generate methane during anaerobic
decomposition of organic waste. In 1990, landfills
generated 56.2 MMTCE (9.8 Tg) of methane,
which increased to 66.7 MMTCE (11.6 Tg) by
1997 (EPA, 1999). Baseline emissions are ex-
pected to decrease to 52.0 MMTCE (9.1 Tg) in
2010, due to the Clean Air Act New Source Per-
formance Standards and Emissions Guidelines
(Landfill Rule). The Landfill Rule requires the
nation's largest landfills to reduce emissions of
non-methane organic compounds and results in a
simultaneous reduction in methane emissions.
The principal technologies for reducing emissions
from landfills involve collecting methane and us-
ing it as fuel for electric power generation or for
sale to nearby industrial users.
> Natural Gas Systems. Emissions of methane
occur throughout the natural gas system from
leaks and venting of gas during normal operations,
maintenance, and system upsets. In 1990, meth-
ane emissions from the U.S. natural gas system
totaled about 32.9 MMTCE (5.7 Tg), and by 1997
methane emissions were estimated at 33.5
MMTCE (5.8 Tg) (EPA, 1999). EPA expects
emissions to increase as natural gas consumption
increases, although at a lower rate than gas con-
sumption growth. Baseline emissions reach 37.9
MMTCE (6.6 Tg) in 2010. Improved manage-
ment practices and technologies can reduce leaks
or avoid venting of methane from all parts of the
natural gas system.
> Coal Mining. Methane and coal are formed to-
gether by geological forces during coalification.
As coal is mined, the methane is released. Be-
cause methane is hazardous to miners, under-
ground mines use ventilation systems to dilute it
and additional techniques to recover it during or in
advance of mining. In 1990, coal mine methane
emissions were estimated at 24.0 MMTCE (4.2
Tg). By 1997, emissions fell to 18.8 MMTCE
(3.3 Tg) mainly due to reduced coal production at
"gassy" mines and increased methane recovery
(EPA, 1999). Baseline methane emissions reach
28.0 MMTCE (4.9 Tg) by 2010 due to growth in
coal mining from deep mines. The major tech-
nologies for reducing emissions include recovery
and sale to pipelines, use for power generation, or
on-site use. Catalytic oxidation of methane in
ventilation air may also be undertaken to reduce
emissions.
> Livestock Manure Management. Methane is
produced during the anaerobic decomposition of
livestock manure. The major sources of U.S. live-
stock manure methane include large dairy and
cattle operations and hog farms that use liquid
manure management systems. In 1990, livestock
manure emitted about 14.9 MMTCE (2.6 Tg) of
methane. Emissions from this source increased to
17.0 MMTCE (3.0 Tg) by 1997 (EPA, 1999).
Baseline emissions reach 22.3 MMTCE (3.9 Tg)
in 2010 due to animal population growth driven
by increases in total meat and dairy product con-
sumption and increasing use of liquid waste man-
agement systems that produce methane. Existing
cost-effective technologies can be used to recover
this methane to produce energy.
> Enteric Fermentation. Methane emissions from
livestock enteric fermentation were 32.7 MMTCE
(5.7 Tg) in 1990 and 34.1 MMTCE (6.0 Tg) in
1997 (EPA, 1999). Baseline methane emissions
reach 37.7 MMTCE (6.6 Tg) by 2020 due to in-
creased domestic and international demand for
U.S. livestock products. Emissions can be re-
duced through the application of improved man-
agement practices. The cost-effectiveness of these
practices has not been quantified as part of this
analysis, however.
ES-2 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Costs of Reducing Emissions

This report presents the results of extensive benefit-
cost analyses conducted on the opportunities (tech-
nologies and management practices) to reduce meth-
ane emissions from four of the five major U.S.
sources: landfills, natural gas systems, coal mining,
and livestock manure. To date, most economic analy-
ses of U.S. greenhouse gas (GHG) emission reductions
have focused on energy-related carbon emissions since
carbon dioxide (CO2) currently accounts for about 82
percent of the total U.S. GHG emissions (weighted by
100-year global warming potentials) (EPA, 1999). The
cost estimates for reducing methane emissions pre-
sented in this report can be integrated into economic
analyses to produce more comprehensive assessments
of total GHG reductions. By including methane emis-
sion reductions, the overall cost of reducing GHG
emissions in the U.S. is reduced. At increasing values
for emission reductions, in terms of dollars per metric
ton of carbon equivalent ($/TCE), more costly CO2
reductions can be substituted by lower cost methane
reductions, when available, thereby lowering the mar-
ginal cost and the total cost of a particular GHG emis-
sion reduction level.
The cost analysis is conducted for the years 2000,
2010, and 2020. All values are in 1996 constant dol-
lars. Results for the source-specific analyses are sum-
marized below.
> Landfills. The cost analysis focuses on technolo-
gies for recovering and using landfill methane for
energy. Two options are evaluated: use of landfill
methane for electricity generation and as a fuel for
direct use by a nearby end-user. After accounting
for emission reductions due to the Landfill Rule,
at $0/TCE, about 21 percent of baseline emissions
from landfills could be captured and used cost-
effectively in 2000. Cost-effective reductions de-
crease slightly to 20 percent, at $0/TCE, in 2010,
in part reflecting greater coverage of total emis-
sions by the Landfill Rule. At S30/TCE, emis-
sions could be reduced by 38 percent from the
baseline in 2000, and by 41 percent in 2010.
Emission reductions approach their maximum at
$100/TCE in 2000, and S40/TCE in 2010. EPA
projects the incremental benefits of higher values
for carbon equivalent to be slightly smaller in
2020 due to the Landfill Rule.
> Natural Gas Systems. Cost curves for reducing
methane emissions from natural gas systems are
based on technologies and practices for reducing
leaks and venting of natural gas in the natural gas
system. EPA evaluates 118 technologies and
practices that have been identified by the gas in-
dustry in conjunction with EPA's Natural Gas
STAR Program. EPA's analysis assesses the cost-
effectiveness of each technology and practice
based on the value of methane as natural gas. In
2000, 2010, and 2020, about 30 percent of the
projected emissions from natural gas systems can
be avoided cost-effectively, based on the value of
the saved methane. When a value of S30/TCE for
avoided emissions is added to the market price for
gas, about 35 percent of the emissions can be re-
duced. At $100/TCE, about 49 percent of emis-
sions can be reduced. Additional technologies
could likely emerge in this sector to reduce emis-
sions at high values for carbon equivalent, how-
ever, EPA only examines current technologies in
this analysis.
> Coal Mining. EPA's analysis for reducing coal
mine methane emissions focuses on recovering
methane from underground mining, which com-
prises 65 percent of the emissions from this
source. Two emission reduction strategies are
analyzed: recovering methane from mines for sale
as natural gas and using new catalytic oxidation
technologies. The results suggest that in 2010, 37
percent of emissions from coal mines can be cost-
effectively reduced at energy market prices, or
$0/TCE. Up to 71 percent of emissions can be re-
duced at S30/TCE, which represents essentially all
of the technically recoverable methane from this
source. In 2020, the same pattern exists with 41
percent recoverable at $0/TCE and 71 percent re-
coverable at $30/TCE.
> Livestock Manure Management. Cost curves
for reducing methane emissions from livestock
manure are based on recovering and utilizing
U.S. Environmental Protection Agency - September 1999
Executive Summary ES- 3
image:

methane produced at dairies and swine farms.
EPA's analysis focuses on anaerobic digestion
technologies (including covered and complete mix
digesters) that capture methane for use on-site to
generate electricity. At current energy prices,
emissions from livestock manure could be re-
duced by 14 percent in 2000 and 2010. Emission
reductions increase slightly to 15 percent in 2020.
With an additional S30/TCE, emission reductions
reach 30 percent in 2000, 31 percent in 2010, and
32 percent in 2020. At S100/TCE, emissions can
be reduced by about 63 percent in 2000, 65 per-
cent in 2010, and 67 percent in 2020.
> Enteric Fermentation. Emissions from livestock
enteric fermentation can be reduced through en-
hanced feeding and animal management tech-
niques. The costs and cost-effectiveness of these
reductions have not been quantified for this report.
The aggregate results of the analysis are presented in
two ways. Exhibit ES-2 summarizes potential reduc-
tions across all sources at various carbon equivalent
values. These reductions are the summation of source-
specific results where different discount rates are ap-
plied to each source: 8 percent for landfills, 20 percent
for natural gas systems, 15 percent for coal mining,
and 10 percent for livestock manure management. For
2010, EPA estimates that up to 34.8 MMTCE (6.1 Tg)
of reductions are possible at energy market prices or
$0/TCE. Consequently, methane emissions could be
reduced below 1990 emissions of 169.9 MMTCE
(29.7 Tg) if many of the identified opportunities are
thoroughly implemented. At higher emission reduc-
tion values, more methane reductions could be
achieved. For example, EPA's analysis indicates that
with a value of S20/TCE for abated methane added to
the energy market price, U.S. reductions could reach
50.3 MMTCE (8.8 Tg) in 2010.
EPA also constructs marginal abatement curves
(MACs) for each of the four sources along with an
aggregate curve for 2010 which is shown in Exhibit
ES-3. In order to properly construct the MAC for
2010, a discount rate of eight percent is equally applied
to all sources.1 MACs are derived by rank-ordering
individual opportunities by cost per emission reduction
amount. Methane values and marginal costs are de-
nominated in both energy values (natural gas and elec-
tricity prices) and emission reduction values in terms
of $/TCE. On the MACs, energy market prices are
aligned to $0/TCE, where no additional price signals
from emission reduction values exist to motivate re-
ductions. At and below $0/TCE, all emission reduc-
tions are due to increased efficiencies, conservation of
methane, or both. As a value is placed on methane
emission reductions in terms of $/TCE, these values
are added to the energy market prices and allow for
additional reductions to clear the market. Any "below-
the-line" reduction amounts, with respect to $0/TCE,
illustrate this dual price-signal market, i.e., energy
prices and emission reduction values.
The aggregate U.S. MAC for 2010 in Exhibit ES-3
illustrates the following key findings. First, substantial
emission reductions, 36.8 MMTCE (6.4 Tg), can be
achieved at energy market prices with no additional
emission reduction values ($0/TCE). Second, at
Exhibit ES-2: U.S. Baseline Emissions and Potential Reductions (source-specific discount rates) (MMTCE)
MMTCE
@21GWP
200-

172-

143-

115-
57-

29-

0
2000
2010
2020
Cost-Effective Reductions
Baseline Emissions
Emission Levels at
Different S/TCE
Remaining Emissions
1990 2000 2010 2020
Year
Baseline Emissions
Cumulative Reductions
at$OITCE
at$10/TCE
at$20/TCE
at$30/TCE
at$40/TCE
at$50/TCE
at$75/TCE
at$100/TCE
at$125/TCE
at$150/TCE
at$175/TCE
at$200/TCE
Remaining Emissions
173.9

30.8
36.4
41.7
54.6
56.2
59.5
64.3
67.2
68.4
68.7
69.0
69.2
104.7
186.0

34.8
42.3
50.3
61.7
63.5
66.9
71.9
74.9
76.2
76.5
76.8
77.0
108.9
183.7

35.0
40.9
47.4
58.7
61.0
64.8
70.7
74.0
75.5
75.9
76.2
76.5
107.2
ES-4 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit ES-3: Marginal Abatement Curve for U.S. Methane Emissions in 2010 (at an 8 percent discount rate)
LU
O
t
3
s
C
O
.Q
re
O
14-
o
<u
$250

$200

$150

$100

$50

($50)
Observed Data
45
$/TCE=30e102-MMTCE-60
HI
O ~
•- .c
D) <»
<u
c
UJ
D)
C
to
re
HI
Market Price
10 20 30 40 50

Abated Methane (MMTCE)
60
70
80
S20/TCE and $50/TCE total estimated reductions are
52.6 MMTCE (9.2 Tg) and 70.0 MMTCE (12.2 Tg),
respectively. Third, at $100/TCE, total achievable
reductions are estimated at 75.5 MMTCE (13.2 Tg).
Finally, above $100/TCE, the MAC becomes inelastic,
that is, non-responsive to increasing methane values.
This inelasticity indicates the limits of the options con-
sidered. The magnitude of the cost-effective and
low-cost reductions reflects methane's value as an
energy source and emphasizes that many proven
technologies can be used to recover it. For several
sources, the inelastic section of the curve at the
higher end of the cost range indicates a limitation
of the analysis, namely that only available tech-
nologies are assessed. Additional technologies
may become available to reduce methane emis-
sions at these prices; however, EPA has not yet
assessed this possibility.
EPA has developed a number of voluntary pro-
grams as part of the Climate Change Action Plan
(CCAP) to overcome market barriers and encour-
age cost-effective methane recovery projects. In
this report, the emission reductions associated
with these CCAP programs have not been sub-
tracted from the baseline emission projections.
However, EPA expects that approximately 50 per-
cent of the reductions available in 2010 at $0/TCE
will be captured by these programs. These pro-
grams have reduced emissions by 8 MMTCE in
1998 and are expected to reduce emissions by 12
MMTCE in 2000, and 20 MMTCE in 2010.
U.S. Environmental Protection Agency - September 1999
Executive Summary ES- 5
image:

References

Dlugokencky, E.J., K.A. Masarie, P.M. Lang, and P.P. Tans. 1998. "Continuing Decline in the Growth Rate of the
Atmospheric Methane Burden," Nature, v. 393,4 June 1998.
EPA. 1999. Inventory of Greenhouse Gas Emissions and Sinks 1990-1997. Office of Policy, Planning, and
Evaluation, U.S. Environmental Protection Agency, Washington, DC. (Available on the Internet at
http ://www.epa.gov/globalwarming/inventory/index.html.)
ES-6 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Endnotes
1 In the construction of a national or aggregate marginal abatement curve, a single discount rate is applied to all
sources in order to equally evaluate various options. Given a particular value for abated methane, all options up to
and including that value can be cost-effectively implemented. An eight percent discount rate, the lowest in the
range of the source-specific rates (8 to 20 percent), is used since it is closer to social discount rates employed in na-
tional level analyses. The results from the single, eight percent discount rate analysis are slightly higher than the
results where source-specific discount rates are used because a lower discount rate reduces project costs enabling
additional reductions.
U.S. Environmental Protection Agency - September 1999 Executive Summary ES- 7
image:

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1. Introduction and Aggregate Results
Introduction

This report has two objectives. First, it presents the U.S. Environmental Protection Agency's (EPA's) baseline
forecast of methane emissions from the major anthropogenic sources in the U.S., and EPA's cost estimates of re-
ducing these emissions. Emission estimates are given for 1990 through 1997 with projections for 2000 to 2020.
The cost analysis is for 2000, 2010, and 2020. Second, this report provides a transparent methodology for the cal-
culation of emission estimates and reduction costs, thereby enabling analysts to replicate these results or use the
approaches described herein to conduct similar analyses for other countries.
The information presented in this report can be used in several ways. The emission estimates and forecasts repre-
sent the most up-to-date estimates of methane emissions in the U.S.; thus, this report replaces and expands upon
EPA''s Anthropogenic Methane Emissions in the United States, Estimates for 1990, Report to Congress (1993a).
As such, this report can be used where estimates of future emissions are required. The report also summarizes the
state of knowledge on methane emissions from the major anthropogenic sources.
While the emission estimations are refinements of earlier approaches, the cost analyses presented in this report
represent a major contribution to the literature on mitigating emissions. To date, most economic analyses of
greenhouse gas (GHG) emission reductions have focused on the energy-related carbon emissions since carbon
dioxide (CO2) currently accounts for about 82 percent of the total U.S. emissions (weighted by 100-year global
warming potentials) (EPA, 1999). The cost-estimates for reducing methane emissions presented in this report can
be integrated into economic analyses to produce more comprehensive assessments of total GHG reductions. By
including methane emission reductions, the overall cost of reducing GHG emissions in the U.S. is reduced. At
increasing values for emission reductions, more costly CO2 reductions can be substituted by lower cost methane
reductions, when available, thereby lowering the marginal cost and the total cost of a particular GHG emission
reduction level.
The marginal abatement curves (MACs) developed in this report can be used to estimate possible emission reduc-
tions at various prices for carbon equivalent emissions or conversely, the costs of achieving certain amounts of
reductions. EPA recognizes that the cost analyses will change with the introduction of new technologies and addi-
tional research into methane emission abatement technologies. Other countries, nevertheless, can use the cost
analyses presented in this report as the basis for estimating emission reduction costs.
1.0 Overview of Methane
Emissions

Next to carbon dioxide, methane is the second largest
contributor to global warming among anthropogenic
greenhouse gases. Methane's overall contribution to
global warming is significant because, over a 100-year
time frame, it is estimated to be 21 times more effec-
tive at trapping heat in the atmosphere than carbon
dioxide. As illustrated in Exhibit 1-1, methane ac-
counts for 17 percent of the enhanced greenhouse ef-
fect (IPCC, 1996a).!
Over the last two centuries, methane's concentration in
the atmosphere has more than doubled from about 700
parts per billion by volume (ppbv) in pre-industrial
times to 1,730 ppbv in 1997 (IPCC, 1996a). Exhibit
1-1 illustrates this trend. Scientists believe these at-
mospheric increases are largely due to increasing
U.S. Environmental Protection Agency - September 1999
Introduction
1-1
image:

Exhibit 1-1: Global Enhanced Greenhouse Effect and Methane Concentrations
Contribution of Anthropogenic Gases to Enhanced
Greenhouse Effect Since Pre-lndustrial Times
(measured in Watts/m2)
Methane 17%
Carbon
Dioxide 55%
PFCs, SF6<1%
Tropospheric O314%

CFCs, MFCs 9%
N,O 5%
Total = 2.85 Watts/m2
Source: IPCC, 1996a.
emissions from anthropogenic sources. Although at-
mospheric methane concentrations continue to rise, the
rate of increase appears to have slowed since the
1980s. If present trends continue, however, atmos-
pheric methane concentrations will reach 1,800 ppbv
by 2020 (Dlugokencky, et al., 1998).
Atmospheric methane is reduced naturally by sinks.
Natural sinks are removal mechanisms and the greatest
sink for atmospheric methane (CH^) is through a reac-
tion with naturally-occurring tropospheric hydroxyl
(OH).2 Methane combines with OH to form water
vapor (H2O) and carbon monoxide (CO), which in turn
is converted into carbon dioxide (CO2). Atmospheric
methane, nevertheless, has a clearly defined chemical
feedback that decreases the effectiveness of the hy-
droxyl sink. As methane concentrations rise, less hy-
droxyl is available to break down methane, producing
longer atmospheric methane lifetimes and higher
methane concentrations (IPCC, 1996a).
On average, the atmospheric lifetime for a methane
molecule is 12.2 years (± 3 years) before a natural sink
consumes it (IPCC, 1996a). This relatively short life-
time makes methane an excellent candidate for miti-
gating the impacts of global warming because emis-
sion reductions could lead to stabilization or reduction
in methane concentrations within 10 to 20 years.
Historical Global Atmospheric Methane Concentrations

2,000''
1,750"
1800
2000
Source: Boden, et al., 1994; Dlugokencky, et al., 1998.

2.0 Sources of Methane
Emissions

Methane is emitted into the atmosphere from both
natural and anthropogenic sources. Natural sources
include wetlands, tundra, bogs, swamps, termites,
wildfires, methane hydrates, and oceans and fresh-
waters. Anthropogenic sources include landfills, natu-
ral gas and oil production and processing, coal mining,
agriculture (livestock enteric fermentation and live-
stock manure management, and rice cultivation), and
various other sources. By 1990, anthropogenic
sources accounted for 70 percent of total global meth-
ane emissions (EPA, 1993a; IPCC, 1996a). This sec-
tion summarizes the natural and anthropogenic sources
of methane.

2.1 Natural Methane Emissions
In 1990, worldwide natural sources emitted 916 mil-
lion metric tons of carbon equivalent (MMTCE) or
160 Teragrams (Tg) of methane into the atmosphere,
or about 30 percent of the total methane emissions
(IPCC, 1996a). The leading natural methane sources
are described below in descending order of their con-
tribution to emissions (see Exhibit 1-2).
Wetlands. Methane is generated by anaerobic (oxy-
gen poor) bacterial decomposition of plant material in
wetlands. Natural wetlands emit about 659 MMTCE
1-2 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 1-2: Worldwide Natural and Anthropogenic Methane Emissions in 1990
Anthropogenic (70%)
Natural (30%)
Other 4%
Termites 13%
Livestock Manure 7%
Domestic Sewage 7%

Coal 8%

Landfills 11%

Biomass Burning 11%
Enteric Fermentation 23%
Rice Paddies 16%
Oceans 6%
Other 9%
Wetlands 72%
Natural Gas and Oil 15%
Total = 2,150 M MICE
Total = 916 M MICE
World Total = 3,066 MMTCE
Source: IPCC, 1995 and 1996a.
(115 Tg) of methane per year, which is 72 percent of
natural emissions and 20 percent of total global meth-
ane emissions (IPCC, 1995). Methane emissions from
wetlands will probably increase with global warming
as a result of accelerated anaerobic microbial activity.
In addition, climate change models predict increased
precipitation as global temperatures rise, which could
create more wetlands (EPA, 1993b). Tropical wet-
lands (between 20° N and 30° S) represent 17 percent
of total wetland area and 60 percent of emissions from
wetlands. These relatively high emissions are due to
higher temperatures, more precipitation and more in-
tense solar radiation, which encourage higher plant
growth and decomposition rates (EPA, 1993b).
Northern Wetlands (those above 45° N) are usually
underlain with near-surface permafrost that prevents
soil drainage and creates wetland conditions. Northern
wetlands represent nearly 80 percent of the wetland
area and 35 percent of methane emissions from wet-
lands (EPA, 1993b).
Termites. Microbes within the digestive systems of
termites break down cellulose, and this process pro-
duces methane. Emissions from this source depend on
termite population, amounts of organic material con-
sumed, species, and the activity of methane-oxidizing
bacteria. While more research is needed, some experts
believe that future trends in termite emissions are more
influenced by anthropogenic changes in land use, i.e.,
deforestation for agriculture, than by climate change.
Termites emit an estimated 115 MMTCE (20 Tg) of
methane each year (IPCC, 1995).
Oceans and Freshwaters. The surface waters of the
world's oceans and freshwaters are slightly supersatu-
rated with methane relative to the atmosphere and
therefore emit an estimated 57 MMTCE (10 Tg) of
methane each year (IPCC, 1995). The origin of the
dissolved methane is not known. In coastal regions it
may come from sediments and drainage. It also has
been suggested that methane is generated in the an-
aerobic gastrointestinal tracts of marine zooplankton
and fish (EPA, 1993b). Methane in freshwaters can
result from the decomposition of wetland plants. (In
this report, methane emissions from freshwaters are
included in the estimates for wetlands.) As atmos-
pheric methane concentrations increase, the proportion
of methane supersaturated in oceans and freshwaters
will decline relative to the atmospheric concentrations
of methane, assuming that the methane concentration
in oceans and freshwaters remains constant.
Gas Hydrates. Methane is trapped in gas hydrates,
which are dense combinations of methane and ice lo-
cated deep underground and beneath the ocean floor.
Recent estimates of hydrates suggest that around 44
billion MMTCE (7.7 billion Tg) of methane is trapped
in both oceanic and continental gas hydrates (DOE,
1998). Scientists agree that increasing temperatures
U.S. Environmental Protection Agency - September 1999
Introduction 1-3
image:

will eventually destabilize many gas hydrates, but are
unsure about the timing and the amount of methane
emissions that would be released from the deeply bur-
ied hydrates (EPA, 1993b).
Permafrost. Small amounts of methane are trapped in
permafrost, which consists of permanently frozen soil
and ice. (To be classified as permafrost, the ice and
soil mixture must remain at or below 0° Celsius year-
round for at least two consecutive years.) Due to the
large amount of existing permafrost, the total amount
of methane stored in this form could be quite high,
possibly several thousand Tg (EPA, 1993b). This
methane is released when permafrost melts. However,
no estimates have been made for current emissions
from this source.
Wildfires. Wildfires are primarily caused by lightning
and release a number of greenhouse gases, including
methane which is a product of incomplete combustion.
However, no estimates are available for methane emis-
sions from this source.

2.2 Anthropogenic Methane
Emissions
Methane emissions from anthropogenic sources ac-
count for 70 percent of all methane emissions and to-
taled 2,150 MMTCE (375 Tg) worldwide in 1990
(IPCC, 1996a). The leading global anthropogenic
methane sources are described below in descending
order of magnitude. The two leading sources of an-
thropogenic methane emissions worldwide are live-
stock enteric fermentation and rice production. By
contrast, in the U.S., the two leading sources of meth-
ane emissions are landfills and natural gas and oil sys-
tems (see Exhibit 1-3). In 1997, the U.S. emitted 179.6
MMTCE (31.4 Tg) of methane, about 10 percent of
global methane emissions for that year (EPA, 1999).
The U.S. is the fourth-largest methane emitter after
China, Russia, and India (EPA, 1994).
Enteric Fermentation. Ruminant livestock emit
methane as part of their normal digestive process,
during which microbes break down plant material con-
sumed by the animal into material the animal can use.
Methane is produced as a by-product of this digestive
process, and is expelled by the animal. In the U.S.,
cattle emit about 96 percent of the methane from live-
stock enteric fermentation. In 1994, livestock enteric
fermentation produced 490 MMTCE (85 Tg) of meth-
ane worldwide (IPCC, 1995), with the emissions
coming from the former Soviet Union, Brazil, and In-
dia (EPA, 1994). EPA estimates that U.S. emissions
from this source were 34.1 MMTCE (6.0 Tg) in 1997
(EPA, 1999). Under EPA's baseline forecast, livestock
enteric fermentation emissions in the U.S. will increase
to about 37.7 MMTCE (6.6 Tg) by 2020 (Exhibit 1-4).
The projected increase is due to greater consumption
of meat and dairy products.
Rice Paddies. Most of the world's rice, including rice
in the United States, is grown on flooded fields where
organic matter in the soil decomposes under anaerobic
conditions and produces methane. The U.S. is not a
Exhibit 1-3: U.S. Methane Emissions
U.S. Greenhouse Gas Emissions in 1997
Weighted by Global Warming Potential
Methane 10%
Nitrous Oxide 6%
MFCs, PFCs, SF62%
Source Breakdown of 1997 U.S. Methane Emissions
Carbon Dioxide 82%

Total = 1,814 MMTCE
Source: EPA, 1999.
Enteric
Fermentation 19%
Livestock
Manure 10%
Coal 10%
Other 4%
Landfills 37%
Natural Gas and Oil 20%
Total =179.6 MMTCE
Source: EPA, 1999.
1-4 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 1-4: Baseline Methane Emissions in the United States (MMTCE)
Source
Landfills
Natural Gas Systems
Oil Systems
Coal Mining
Livestock Manure Management
Enteric Fermentation
Otherb
Total
1990a
56.2
32.9
1.6
24.0
14.9
32.7
7.3
169.9
1997a
66.7
33.5
1.6
18.8
17.0
34.1
7.4
179.6
2000
51.4
35.6
1.6
23.9
18.4
35.2
7.8
173.9
2010
52.0
37.9
1.6
28.0
22.3
36.6
7.6
186.0
2020
41.1
38.8
1.7
30.4
26.4
37.7
7.6
183.7
a Source: EPA, 1999.
b These estimates developed by EPA for the 1997 Climate Action Report (DOS, 1997).
Totals may not sum due to independent rounding.
major producer of rice and therefore emits little meth-
ane from this source. Worldwide emissions of meth-
ane from rice paddies were 345 MMTCE (60 Tg) in
1994 (IPCC, 1995), with the highest emissions coming
from China, India, and Indonesia (EPA, 1994). EPA
estimates U.S. emissions from this source at 2.7
MMTCE (0.5 Tg) in 1997 and expects emissions to
remain stable in the future (EPA, 1999).
Natural Gas and Oil Systems. Methane is the major
component (95 percent) of natural gas. During pro-
duction, processing, transmission, and distribution of
natural gas, methane is emitted from system leaks,
deliberate venting, and system upsets (accidents).
Since natural gas is often found in conjunction with
petroleum, crude petroleum gathering and storage
systems are also a source of methane emissions. In
1994, natural gas systems worldwide emitted 230
MMTCE (40 Tg) of methane and oil systems emitted
85 MMTCE (15 Tg) of methane (IPCC, 1995). EPA
estimates that 1997 U.S. emissions were 33.5
MMTCE (5.8 Tg) from natural gas systems and 1.6
MMTCE (0.27 Tg) from oil systems (EPA, 1999).
EPA expects emissions from oil systems to remain
near 1997 levels through 2020. The baseline emission
forecast is 38.8 MMTCE (6.8 Tg) from natural gas
systems in 2020 (Exhibit 1-4). The increase results
from higher consumption of natural gas and expan-
sions of the natural gas system.
Biomass Burning. Biomass burning releases green-
house gases, including methane, but is not a major
source of U.S. methane emissions. In 1994, biomass
burning produced 230 MMTCE (40 Tg) of methane
worldwide (IPCC, 1995). EPA estimates that U.S.
emissions from this source were 0.2 MMTCE (0.03
Tg) in 1997 and that emissions will remain stable
through 2020 (EPA, 1999).
Landfills. Landfill methane is produced when organic
materials are decomposed by bacteria under anaerobic
conditions. In 1994, landfills produced 230 MMTCE
(40 Tg) of methane worldwide (IPCC, 1995). EPA
estimates that U.S. emissions from this source were
66.7 MMTCE (11.6 Tg) in 1997 (EPA, 1999). The
baseline forecast is 41.1 MMTCE (7.2 Tg) from U.S.
landfills in 2020 (Exhibit 1-4). Landfill methane is the
only U.S. source that is expected to decline in the
baseline over the forecast period. This decline is due
to the implementation of the New Source Performance
Standards and Emissions Guidelines (the Landfill
Rule) under the Clean Air Act (March 1996). While
the Landfill Rule controls greenhouse gas emissions
that form tropospheric ozone (smog), it also will lead
to lower methane emissions. The Landfill Rule re-
quires large landfills to collect and combust or use
landfill gas emissions.
Coal Mining. Methane is trapped within coal seams
and the surrounding rock strata and is released during
coal mining. Because methane is explosive in low
concentrations, underground mines install ventilation
systems to vent methane directly to the atmosphere. In
1994, coal mining produced 170 MMTCE (30 Tg) of
methane worldwide (IPCC, 1995). EPA estimates that
U.S. emissions from this source were 18.8 MMTCE
U.S. Environmental Protection Agency - September 1999
Introduction 1-5
image:

(3.3 Tg) in 1997 (EPA, 1999). EPA's baseline estimate
indicates that emissions from coal mines could reach
30.4 MMTCE (5.3 Tg) by 2020 (Exhibit 1-4). The
increase results from greater coal production from
deep mines.
Domestic Sewage. The decomposition of domestic
sewage in anaerobic conditions produces methane.
Domestic sewage is not a major source of methane
emissions in the U.S., where it is collected and proc-
essed mainly in aerobic (oxygen rich) treatment plants.
In 1994, domestic sewage produced 145 MMTCE (25
Tg) of methane worldwide (IPCC, 1995). EPA esti-
mates that emissions from sewage in the U.S. were 0.9
MMTCE (0.2 Tg) in 1997 and expects emissions to
increase only slightly by 2020 (EPA, 1999). This in-
crease will be due primarily to population increases.
Livestock Manure Management. The decomposi-
tion of animal waste in anaerobic conditions produces
methane. Over the last eight years, methane emissions
from manure have generally followed an upward
trend. This trend is driven by: (1) increased swine and
poultry production; and (2) increased use of liquid
manure management systems, which create the an-
aerobic conditions conducive to methane production.
In 1994, manure management produced 145 MMTCE
(25 Tg) of methane worldwide (IPCC, 1995). EPA
estimates that U.S. emissions from this source were
17.0 MMTCE (3.0 Tg) in 1997 (EPA, 1999). Emis-
sions from livestock manure in the baseline are pro-
jected to increase to 26.4 MMTCE (4.6 Tg) by 2020
(Exhibit 1-4) mainly due to increases in livestock
population and milk production.

3.0 Options for Reducing
Methane Emissions

One of the key elements of the U.S. Climate Change
Action Plan (CCAP) is the implementation of cost-
effective reductions of methane emissions through
voluntary industry actions.3 Because methane is a
valuable energy resource, recovering methane that
normally would be emitted into the atmosphere and
using it for fuel reduces greenhouse gas emissions.
The methane saved from these voluntary actions often
pays for the costs of recovery and also can be cost-
effective even without accounting for the broader so-
cial benefits of reducing greenhouse gases (GHG).

Beginning in the early 1990s, EPA launched five vol-
untary programs to promote cost-effective methane
emission reductions:
> AgSTAR Program - works with livestock
producers to encourage methane recovery
from animal waste;
> Coalbed Methane Outreach Program (CMOP)
- works with the coal and natural gas indus-
tries to collect and use methane that is re-
leased during mining;
> Landfill Methane Outreach Program (LMOP)
- works with states, municipalities, utilities,
and the landfill gas-to-energy industry to col-
lect and use methane from landfills;
> Natural Gas STAR Program - works with the
companies that produce, transmit, and distrib-
ute natural gas to reduce leaks and losses of
methane; and
> Ruminant Livestock Efficiency Program
(RLEP) - works with livestock producers to
improve animal nutrition and management,
thereby boosting animal productivity and cut-
ting methane emissions.
Under these voluntary programs, industry partners
voluntarily undertake cost-effective efforts to re-
duce methane emissions. EPA works with part-
ners to quantify the results of their actions and
account for reductions in historical methane emis-
sion estimates. One of the principal benefits of
these voluntary programs is the sharing of infor-
mation between government and industry and
within industry on emissions, and emission reduc-
tion opportunities and associated costs. These
programs have contributed significantly to EPA's
understanding of the opportunities for emission
reductions.

Many of these opportunities involve the recovery of
methane emissions and use of the methane as fuel for
electricity generation, on-site heat uses, or off-site sales
of methane. These actions represent key opportunities
for reducing methane emissions from landfills, coal
mines, and livestock manure management. Other op-
1-6 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

tions may include oxidizing or burning the methane
emissions. Catalytic oxidation is a new technology
potentially applicable at coal mines; flaring is an op-
tion available at landfills and other sites.
The natural gas industry offers the most robust array of
emission reduction options. The Natural Gas STAR
Program has identified a number of best management
practices for reducing leaks and avoiding venting of
methane. In addition, partners in the program have
employed a number of other strategies for reducing
emissions. These strategies are described in the chap-
ter on natural gas systems.
Conversely, few technology-specific reduction options
have yet been identified for the ruminant livestock
industry, where methane production is a natural by-
product of enteric fermentation. The principal options
are improving the efficiency of feedlot operations and
animal feeds for ruminant livestock. Better feeds and
animal management can increase yields of meat and
dairy products relative to methane production.
A principal benefit of the various voluntary programs
is abundant information developed on the efficacy of
the emission reduction options and the costs of imple-
menting these options. EPA uses this information to
estimate the costs of reducing emissions. Partners in
the various voluntary programs are already undertak-
ing emission reduction efforts because they have been
found to be cost-effective. While some of the emission
reduction options are cost-effective in some settings,
they are not in others, e.g., methane recovery and use
may be more cost-effective at large coal mines and
landfills than at small ones. In the next section the
economics of decision making in the implementation
of reduction options is discussed.

4.0 Economic Analysis of
Reducing U.S. Methane
Emissions

Methane has a value as a source of energy since it is
the principal component of natural gas. Therefore,
avoided methane emissions in natural gas systems are
valued in terms of dollars per million British thermal
units ($/MMBtu). Similarly, methane also can be
combusted to generate electricity and is valued in dol-
lars per kilowatt-hour ($/kWh). The value of potential
methane emission reductions is calculated relative to
carbon equivalent units using methane's 100-year
global warming potential (GWP) of 21 (IPCC, 1996a).
The value of abated methane, as well as other GHGs,
can thus be stated in terms of dollars per metric ton of
carbon equivalent ($/TCE). Throughout the analysis,
energy market prices are aligned to $0/TCE. This
value represents a scenario where no additional price
signals from GHG abatement values exist to motivate
emission reductions; all reductions are due to re-
sponses to market prices for natural gas. As a value is
placed on GHG reductions in terms of $/TCE, these
values are added to energy market prices and allow for
additional emission reductions to clear the market.
A benefit-cost analysis is applied to the opportunities
for emission reductions and is defined as:
> Benefits. Benefits are calculated from the
amount of methane saved by implementing the
options multiplied by the value of the methane
saved as its use as an energy resource; plus the
value of methane as an emission reduction of
a GHG, if available;
> Costs (including capital expenditures and
operation and maintenance expenses). The
costs of implementing specific reduction op-
tions are estimated for four of the five major
anthropogenic sources. The applied discount
rates are particular to each source-specific
U.S. Environmental Protection Agency - September 1999
Introduction
1-7
image:

analysis and set at eight percent for the aggre-
gate analysis. In the source-specific analyses,
different discount rates are used to determine
cost-effective reductions.

Because nearly all of the technologies and practices for
reducing methane emissions produce or save energy,
energy prices are a key driver of the cost analyses. The
value of the energy produced or saved offsets to vari-
ous degrees the capital and operating costs of reducing
the emissions. Higher energy prices offset a larger
portion of these costs, and in some cases make the
technologies and practices profitable.5

In the source-specific analyses, energy market prices,
in 1996 U.S. dollars, are used to establish whether an
option is cost-effective. These prices are established
based on the following approaches:

> For landfills, both electricity and natural gas
prices are used in the analysis since landfills
sell gas directly to consumers or use the re-
covered gas to generate electricity. For elec-
tricity prices, the analysis uses an estimated
price of $0.04/kWh to represent the value of
electricity close to distribution systems and
receiving a renewable energy premium. For
natural gas, the price used is $2.74/MMBtu.
In this case, the analysis uses the average in-
dustrial gas price discounted by 20 percent to
adjust for the lower Btu content of landfill gas
(EIA, 1997).

> Coal mine methane is sold as natural gas to
interstate pipelines, used to generate electric-
ity, or used on-site. For natural gas, coal mine
methane is valued at $2.53/MMBtu, which is
the average delivered price for natural gas in
Alabama, Indiana, Kentucky, and Ohio. The
electricity generated from coal mines is valued
at $0.03/kWh to reflect the greater distance
from distribution systems.

> The set of energy prices for natural gas sys-
tems depends on where the emissions are re-
duced. Production emission reductions are
valued at the average wellhead price of
$2.17/MMBtu; transmission savings are val-
ued at $2.27/MMBtu; and distribution system
savings are valued at $3.27/MMBtu (EIA,
1997).
> Livestock manure methane is used to generate
electricity for farm use and offset electricity
consumption from a utility grid. The analysis
uses $0.09/kWh for dairy farms and
$0.07/kWh for swine farms. These prices are
weighted averages of retail commercial elec-
tricity rates based on dairy and swine popula-
tions, respectively. The national average price
was discounted by $0.02/kWh to reflect the
effects of interconnect and demand charges
and other associated costs.
In order to incorporate methane emission reduction
values into the analysis, various $/TCE values are
translated into equivalent electricity and gas prices
using the heat rate of the engine-generator (for elec-
tricity), the energy value of methane (1,000 Btu/cubic
foot), and a GWP of 21. See individual chapters for
greater detail.

5.0 Achievable Emission
Reductions and
Composite Marginal
Abatement Curve

The aggregate results of the analyses are presented in
this section. Exhibit 1-5 shows estimated total U.S.
reductions at various values for abated methane in
$/TCE. These reductions are the summation of
source-specific results where different discount rates
are applied to each source: 8 percent for landfills, 10
percent for livestock manure management, 15 percent
for coal mining, and 20 percent for natural gas sys-
tems. For 2010, EPA estimates that up to 34.8
MMTCE (6.1 Tg) of reductions are possible at energy
market prices or $0/TCE. Consequently, methane
emissions could be reduced below 1990 emissions of
169.9 MMTCE (29.7 Tg) if many of the identified
opportunities are thoroughly implemented. At higher
emission reduction values, more methane reductions
could be achieved. For example, EPA's analysis indi-
cates that with a value of S20/TCE for abated methane
1-8 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 1-5: U.S. Baseline Emissions and Potential Reductions (source-specific discount rates) (MMTCE)
MMTCE
@ 21 GWP
200-

172-

143-

115-

86-

57-

29-

0
2000 2010 2020
Cost-Effective Reductions
^Baseline Emissions
Emission Levels at
Different SATCE
Remaining Emissions
1990 2000 2010 2020
Year
added to the energy market price, U.S. reductions
could reach 50.3 MMTCE (8.8 Tg) in 2010.
Exhibit 1-6 presents EPA's aggregate U.S. methane
marginal abatement curve (MAC) for 2010 which is
calculated using a discount rate of eight percent
equally applied to all sources in order to properly con-
struct the curve4 The MAC illustrates the amount of
reductions possible at various values for methane and
is derived by rank ordering individual opportunities by
cost per emission reduction amount (IPCC, 1996b).
Any point along a MAC represents the marginal cost
of abating an additional amount of methane. A com-
Baseline Emissions
Cumulative Reductions
at $0/TCE
at$10/TCE
at $20/TCE
at $30/TCE
at $40/TCE
at $50/TCE
at $75/TCE
at$100/TCE
at$125/TCE
at$150/TCE
at$175/TCE
at $200/TCE
Remaining Emissions
173.9

30.8
36.4
41.7
54.6
56.2
59.5
64.3
67.2
68.4
68.7
69.0
69.2
104.7
186.0

34.8
42.3
50.3
61.7
63.5
66.9
71.9
74.9
76.2
76.5
76.8
77.0
108.9
183.7

35.0
40.9
47.4
58.7
61.0
64.8
70.7
74.0
75.5
75.9
76.2
76.5
107.2
plete picture is revealed when the prevailing market
prices for energy and GHG reductions are applied to
the MAC to show the amount of available emissions
that clear the market. Any "below-the-line" reduction
amounts, with respect to $0/TCE, illustrate this dual
price-signal market, i.e., energy market prices and
emission reduction values.
The MAC illustrates the following key findings. First,
substantial emission reductions, 36.8 MMTCE (6.4
Tg), can be cost-effectively achieved, that is, at energy
market prices with no additional emissions reduction
values or $0/TCE. Second, at $20/TCE and $50/TCE
Exhibit 1-6: Marginal Abatement Curve for U.S. Methane Emissions in 2010 (at an 8 percent discount rate)
W
o
t
«»
(O
o>
O)
ff
re
O
$250

$200

$150

$100

$50
($50)
Observed Data
45
$/TCE=30e102-MMTCE-60
V
Z *
£ §
> ^
o) «»
1 °
LLJ D
O) S
E S
« ^
re g
Market Price
10 20 30 40 50 60
Abated Methane (MMTCE)
70
80
U.S. Environmental Protection Agency - September 1999
Introduction 1-9
image:

estimated reductions are 52.6 MMTCE (9.2 Tg) and
70.0 MMTCE (12.2 Tg), respectively. Third, at
$100/TCE, achievable reductions are estimated at 75.5
MMTCE (13.2 Tg). Finally, above $100/TCE, the
MAC becomes inelastic, that is, non-responsive to
increasing methane values which indicates the limits of
the options considered. At higher energy and emission
reduction values, additional options, which have yet to
be developed, will likely become available. By not
estimating potential, future higher-cost options, this
analysis under-estimates the ability to reduce emis-
sions at higher values for abated methane.
The MAC is based on approximately 160 observa-
tions. These results are from the benefit-cost analyses
conducted on the identified opportunities to abate
methane emissions.
An analytic approximation of the MAC is calculated in
order to make these results useful to larger economic
models concerned with GHG reduction costs. The
estimated relationship is obtained by using an expo-
nential trendline, expressing the relationship between
methane values/abatement costs and the quantity of
abated methane.6 This function is described as:
$/TCE = 30 exp [457(102 - MMTCE)]-60.
Exhibit 1-7 illustrates the relative contribution of each
of the sources to reducing methane emissions. Of the
four sources, landfills contribute the most to the emis-
sion reductions, i.e., over one-quarter of the reductions.
Coal mining and natural gas systems each account for
about one-quarter of total emission reductions. Live-
stock manure contributes up to about one-fifth of the
reductions, primarily at higher energy prices and emis-
sion reduction values. Several key aspects of the
analysis are highlighted below:
> The methane recovery efficiency at landfills is
estimated at 75 percent for all landfills and is
assumed to remain constant. Below $0/TCE,
using the recovered methane directly in boil-
ers or similar equipment is more cost-effective
than producing electricity in most cases.
> Because of the diverse sources of methane
emissions from natural gas systems, a large
number of technologies and practices are
evaluated. Among the options evaluated, re-
placing high-bleed pneumatic devices and
techniques for reducing emissions from com-
pressor stations are the most significant in
terms of cost-effective emission reductions.
> The coal mine methane analysis includes a
catalytic oxidation technology for recovering
heat energy from the low concentration of
methane in coal mine ventilation air. This
technology becomes profitable at approxi-
mately $30/TCE, leading to substantial emis-
sion reductions from underground mining.
Below this value, methane recovery is the
primary method of reducing emissions.
> The principal methods for reducing methane
emissions from livestock manure are to collect
and combust the methane that would other-
Exhibit 1-7: Portion of Emission Reductions from Each Source in 2010 (at an 8 percent discount rate) (MMTCE)
36.8
52.6
70.0
100%-
^ 80%'
D
TJ
0)
!= 60%
40%--

I
S. 20%--

0
$0
$20 $50
$/TCE
75.5 •«- Total Reductions (MMTCE)

•4— Livestock Manure

•^— Coal Mining

•4— Natural Gas

.«— Landfills

$100
1-10 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

wise be emitted from liquid manure manage-
ment systems. Anaerobic digester technolo-
gies, the principal technology evaluated, pro-
duce multiple benefits, including odor reduc-
tion at swine farms as well as producing en-
ergy for on-farm use.

6.0 Significance of This
Analysis

To date, most economic analyses of GHG reduction
opportunities have focused on energy-related carbon
emissions since CO2 currently accounts for about 82
percent of the total U.S. emissions (weighted by 100-
year global warming potentials) (EPA, 1999). The
analyses provided in this report can be integrated with
CO2 economic analyses to provide a broader under-
standing of reducing the total cost of achieving GHG
emission reductions. Recent comprehensive studies by
the Joint Program on the Science and Policy of Global
Change, Massachusetts Institute of Technology (Reilly,
1999) and the Australian Bureau for Agricultural and
Resource Economics (Brown, 1999) show that a multi-
gas mitigation strategy can reduce the costs of achiev-
ing GHG emission reductions. Both of these studies
utilized EPA's preliminary cost analysis on methane
reductions (EPA, 1998).
The economic benefits of pursuing a mitigation strat-
egy that includes methane is shown in Exhibit 1-8.
Illustrative MACs are presented for methane (CHO,
CO2, and for the summation of the two showing addi-
tional emission reductions with increases in $/TCE.
Given a reduction target, A*, for both gases, the total
cost of achieving that target is lower if available meth-
ane reductions are included than if only CO2 reduc-
tions are made. At increasing values for emission re-
ductions, more costly CO2 reductions can be substi-
tuted by lower cost methane reductions, when avail-
able, thereby lowering the marginal cost, shown as the
movement from P to P*, and decreasing the total cost
(the integral or area under the curve).

7.0 Background to This
Report

EPA's first major report on methane appeared in 1993
as Anthropogenic Methane Emissions in the United
States, Estimates for 1990, Report to Congress
(1993a). This report was the first effort to increase
general knowledge about methane emissions by pre-
senting a detailed and comprehensive treatment of the
sources of methane emissions as part of the effort to
quantify these emissions. Following this report, EPA
published Opportunities to Reduce Anthropogenic
Exhibit 1-8: Illustrative MACs for Methane and Carbon Dioxide
LU
_0>
TO
HI
c
o
•e
o
0)
Total
A*
O)

I
LU
Market Price
Abated GHG (MMTCE)
U.S. Environmental Protection Agency - September 1999
Introduction 1-11
image:

Methane Emissions in the United States (EPA, 1993b).
For all major sources of methane emissions - landfills,
natural gas systems, coal mines, livestock manure, and
livestock enteric fermentation - this report described
the technologies available that could reduce emissions.
Using these technologies, the report estimated the
amount of emission reductions that would be techni-
cally feasible and the amount of emission reductions
that would be economically justified. The latter in-
cluded taking into account the value of methane (as a
fuel) as well as a value for emission reductions.
Since the publication of these reports, EPA has spon-
sored additional work in the estimation of baseline
emissions and the costs of emission reductions. These
efforts include, for example, a 15-volume report on
Methane Emissions from Natural Gas Systems co-
sponsored with the Gas Research Institute (EPA/GRI,
1996).
The information from the various voluntary programs
in addition to other research was used extensively in
the EPA's Costs of Reducing Methane Emissions in
the United States, Preliminary Report (EPA, 1998).
This report first developed the overall approach for
estimating the cost of emission reductions and was
reviewed by a number of industry and source experts.
Their subsequent recommendations as well as other
improvements have been incorporated into the current
document.
1-12 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

8.0 References

Boden, T.A., D.P. Kaiser, R.J. Sepanski, and F.W. Stoss. 1994. Trends '93: A Compendium of Data on Global
Change. World Data Center for Atmospheric Trace Gases, Carbon Dioxide Information Analysis Center, Envi-
ronmental Sciences Division, Oak Ridge National Laboratory, Oak Ridge, TN, ORNL/CDIAC-65, BSD Publi-
cation No. 4195.
Brown, Stephen, Darren Kennedy, Cain Polidano, Kate Woffenden, Guy Jakeman, Brett Graham, Frank Jotzo, and
Brian S. Fisher. 1999. "Assessing the economic impacts of the Kyoto Protocol Implications of accounting for
the three major greenhouse gases." Australian Bureau for Agricultural and Resource Economics (ABARE).
ABARE Research Report 99.6, Canberra, Australia, May 1999. (Available on the Internet at http://www.
abare.gov.au/pdf/RR99.6pdf.)
Dlugokencky, E.J., KA. Masarie, P.M. Lang, and P.P. Tans. 1998. "Continuing Decline in the Growth Rate of the
Atmospheric Methane Burden,"Nature, v. 393,4 June 1998.
DOE. 1998. Statement of Robert S. Kripowicz, Principal Deputy Assistant Secretary for Fossil Energy, U.S. De-
partment of Energy Before the Subcommittee on Energy, Research, Development, Production, and Regulation,
U.S. Senate, Washington, DC, 21 May 1998.
DOS. 1997. Climate Action Report: 1997. Submission of the United States of America Under the United Nations
Framework Convention of Climate Change. Bureau of Oceans and International Environmental Scientific Af-
fairs, Office of Global Climate Change, U.S. Department of State, Washington, DC, DOS 10496. (Available on
the Internet at http://www.state.gov/www/global/oes/97climate_report/index.html.)
EIA. 1997. Natural Gas Annual 1996. Office of Oil and Gas, Energy Information Administration, U.S. Depart-
ment of Energy, Washington, DC, DOE/EIA-0540(96). (Available on the Internet at http://www.eia.doe.
gov/oil^as/natural^as/nat_frame .html.)
EIA. 1998. Annual Energy Outlook (AEO) 1998. Reference Case Forecast, Energy Information Administration,
U.S. Department of Energy, Washington, DC.
EPA. 1993a. Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress,
Atmospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental Protection
Agency, Washington, DC, EPA 430-R-93-003. (Available on the Internet at http.//www.epa.gov/ghg
info/reports .htm.)
EPA. 1993b. Current and Future Methane Emissions from Natural Sources, Report to Congress. Atmospheric
Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental Protection Agency, Washing-
ton, DC, EPA 430-R-93-011. (Available on the Internet at http://www.epa.gov/ghginfo/reports.htm.)
EPA. 1994. International Anthropogenic Methane Emissions: Estimates for 1990, Report to Congress. Atmos-
pheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental Protection Agency,
Washington, DC, EPA 230-R-93-010.
EPA. 1998. Costs of Reducing Methane Emissions in the United States, Preliminary Report, Draft. Methane and
Utilities Branch, Atmospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental
Protection Agency, Washington, DC.
EPA. 1999. Inventory of Greenhouse Gas Emissions and Sinks 1990-1997. Office of Policy, Planning, and
Evaluation, U.S. Environmental Protection Agency, Washington, DC; EPA 236-R-99-003. (Available on the
Internet at http://www.epa.gov/globalwarming/inventory/1999-inv.html.)
U.S. Environmental Protection Agency - September 1999 Introduction 1-13
image:

EPA/GRI. 1996. Methane Emissions from the Natural Gas Industry, Volume 1: Executive Summary. Prepared by
M. Harrison, T. Shires, J. Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Manage-
ment Research Laboratory, Air Pollution Prevention and Control Division, U.S. Environmental Protection
Agency and Gas Research Institute, Research Triangle Park, NC, EPA-600-R-96-080a.
IPCC. 1990. Climate Change: The IPCC Scientific Assessment. Intergovernmental Panel on Climate Change
(IPCC), Cambridge University Press, Cambridge, United Kingdom.
IPCC. 1995. Climate Change 1994: Radiative Forcing of Climate Change. Intergovernmental Panel on Climate
Change (IPCC), Cambridge University Press, Cambridge, United Kingdom.
IPCC. 1996a. Climate Change 1995: The Science of Climate Change. Intergovernmental Panel on Climate
Change (IPCC), Cambridge University Press, Cambridge, United Kingdom.
IPCC. 1996b. Climate Change 1995: Economic and Social Dimension of Climate Change. Intergovernmental
Panel on Climate Change (IPCC), Cambridge University Press, Cambridge, United Kingdom.
Reilly, I, RG. Prinn, J. Uarnisch, J. Fitzmaurice, H.D. Jacoby, D. Kickligher, PH. Stone, A.P Sokolov, and C.
Wang. 1999. Multi-Gas Assessment of the Kyoto Protocol, Report No. 45, MIT Joint Program on the Science
and Policy of Global Change, Boston, MA, January 1999. (Available on the Internet at
http ://web .mit.edu/globalchange/www/rp 145 .html.)
1-14 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

9.0 Explanatory Notes
1 The enhanced greenhouse effect is the concept that the natural greenhouse effect has been enhanced by anthropo-
genic emissions of greenhouse gases. Increased concentrations of carbon dioxide, methane, and nitrous oxide,
CFCs, HFCs, PFCs, SF6, and other photochemically important gases caused by human activities such as fossil fuel
consumption, trap more infra-red radiation, thereby exerting a warming influence on climate. Exhibit 1-1, which
illustrates relative contributions to the enhanced greenhouse effect by gas, is based on the increase in atmospheric
concentrations at each gas between pre-industrial times and 1992. This exhibit does not include methane's indirect
effect of tropospheric ozone and stratospheric water vapor production, which are estimated to be equivalent to
about 25 percent of the direct effects.
2 Microbial communities in upper soils constitute a much smaller methane sink.
3 The U.S. CCAP was initiated in 1993 and designed to reduce U.S. emissions of greenhouse gases. CCAP Pro-
grams promote actions that are both cost-effective for individual private sector participants as well as beneficial to
the environment.
4 In the construction of a national or aggregate marginal abatement curve, a single discount rate is applied to all
sources in order to equally evaluate various options. Given a particular value for abated methane, all options up to
and including that value can be cost-effectively implemented. An eight percent discount rate, the lowest in the
range of the source-specific rates (8 to 20 percent), is used since it is closer to social discount rates employed in
national level analyses. The results from the single, eight percent discount rate analysis are slightly higher than the
results where source-specific discount rates are used because a lower discount rate reduces project costs enabling
additional reductions.
5 The effects of energy price changes are analyzed only from the revenue side and do not consider effects to capital
and O&M expenses. Therefore, the projected methane reductions may be overestimated for increases and underes-
timated for decreases to energy prices.
6 For the estimated relationship, $/TCE = 30 exp [457(102 - MMTCE)] - 60, the regression analysis yielded an R2 of
0.95. Conversely, the relationship also can be expressed in standard economic terms as the quantity of abated
methane as a function of price ($/TCE): MMTCE = 102 - 45/ln [($/TCE+60)/30].
U.S. Environmental Protection Agency - September 1999 Introduction 1-15
image:

image:

2. Landfills
Summary

Landfills are the largest source of U.S. methane emissions and emitted approximately 66.7 MMTCE (11.6 Tg) of
methane or 37 percent of total U.S. emissions in 1997 (EPA, 1999). Municipal solid waste landfills, which receive
about 61 percent of U.S. solid waste, generate 93 percent of U.S. landfill emissions, while industrial landfills ac-
count for the remaining emissions. Over 2,500 landfills currently operate in the U.S. with a small number of the
largest landfills receiving most of the waste and generating the majority of methane emissions (BioCycle, 1998).
EPA expects future landfill methane emissions to decline due to the Landfill Rule (New Source Performance
Standards and Emissions Guidelines), which was promulgated under the Clean Air Act in March 1996 and
amended in June 1998 (EPA, 1996, 1998). The Landfill Rule requires landfill gas to be collected and either flared
or used at landfills that: (1) have a design capacity greater than 2.5 million metric tons (MMT) and 2.5 million
cubic meters; and (2) emit at least 50 metric tons (MI) per year of non-methane organic compounds (NMOCs).
Although the Landfill Rule controls NMOC emissions because they contribute to tropospheric ozone (smog) for-
mation, the process of reducing them also reduces methane emissions. Under the Landfill Rule, EPA expects
landfill methane emissions to decline to 52.0 MMTCE (9.1 Tg) in 2010, excluding possible additional Climate
Change Action Plan and other reductions.1
Landfill methane emissions can be reduced through methane recovery and use projects, as well as flaring. Cur-
rently, over 250 U.S. landfills have methane utilization projects. The recovered methane is used as on-site fuel,
used to generate electricity, or sold to energy end-users, such as factories. Recovering landfill methane also re-
duces odors and the risk of methane migration through soil.
Exhibit 2-1 shows baseline emissions decreasing between 1990-2020. Although not shown, baseline emissions
increase between 1990-1997. After 1997, emissions decrease due to the Landfill Rule. In addition, Exhibit 2-1
shows that by implementing cost-effective technologies and practices, the U.S. could reduce methane emissions
from landfills by up to 10.5 MMTCE (1.8 Tg) in 2010 at energy market prices (in 1996 US$) or $0/TCE. At
higher emission reduction values, more methane reductions could be achieved. For example, EPA's analysis indi-
cates that with a value of S20/TCE for abated methane added to the energy market price, baseline emissions could
decrease to 31.8 MMTCE and U.S. reductions could reach 20.2 MMTCE (3.5 Tg) in 2010.

Exhibit 2-1: U.S. Methane Emissions from Landfills (MMTCE)
Percent of Methane Emissions in 1997
Enteric
Fermentation 19%
Manure 10%
Emission Estimates and Reductions
Coal 10%
MMTCE
@ 21 GWP
Other 4%
Natural Gas and Oil 20%
Total = 179.6 MMTCE
Source: EPA, 1999.
/ Cost-Effective Reductions
/ Baseline Emissions
/ '
» Emission Levels at
Different S/TCE
$20
$50
Remaining Emissions
1990
2000 2010
Year
2020
U.S. Environmental Protection Agency - September 1999
Landfills 2-1
image:

1.0 Methane Emissions
from Landfills

Solid waste landfills produce methane as bacteria
decompose organic wastes under anaerobic condi-
tions. Methane accounts for approximately 45 to 50
percent of landfill gas, while carbon dioxide and
small quantities of other gases comprise the re-
maining 50 to 55 percent. Methane production be-
gins six months to two years after waste disposal and
may last for decades, depending on disposal site
conditions, waste characteristics, and the amount of
waste in the landfill. Methane migrates out of land-
fills and through zones of low pressure in soil,
eventually reaching the atmosphere. During this
process, the soil oxidizes approximately ten percent
of the methane generated by a landfill, and the re-
maining 90 percent is emitted as methane unless
captured by a gas recovery system and then used or
flared (Liptay,etal., 1998).
This section presents background information on the
factors influencing methane generation and the
methods EPA uses to estimate both current and fu-
ture emissions. A description of the five primary
factors that influence landfill methane production
are discussed first, followed by a discussion of the
emission estimation method used for this analysis.
Next, the current and projected emission estimates
for U.S. landfills are presented. Lastly, the uncer-
tainties associated with the emission estimates are
discussed.

1.1 Emission Characteristics
The amount and rate of methane production over
time at a landfill depends on five key characteristics
of the landfilled material and surrounding environ-
ment. These characteristics are briefly summarized
below.
Quantity of Organic Material. The most signifi-
cant factor driving landfill methane generation is the
quantity of organic material, such as paper and food
and yard wastes, available to sustain methane-
producing microorganisms. The methane produc-
tion capacity of a landfill is directly proportional to
its quantity of organic waste. Methane generation in-
creases as the waste disposal site continues to receive
waste and gradually declines after the site stops receiving
waste. However, landfills may continue to generate
methane for decades after closing.

Nutrients. Methane generating bacteria need nitrogen,
phosphorus, sulfur, potassium, sodium, and calcium for
cell growth. These nutrients are derived primarily from
the waste placed in the landfill.
Moisture Content. The bacteria also need water for cell
growth and metabolic reactions. Landfills receive water
from incoming waste, surface water infiltration, ground-
water infiltration, water produced by decomposition, and
materials such as sludge. Another source of water is
precipitation. In general, methane generation occurs at
slower rates in arid climates than in non-arid climates.

Temperature. Warm temperatures in a landfill speed
the growth of methane producing bacteria. The tem-
perature of waste in the landfill depends on landfill
depth, the number of layers covering the landfill, and
climate.
pH. Methane is produced in a neutral environment
(close to pH 7). The pH of most landfills is between 6.8
and 7.2. Above pH 8.0, methane production is negligi-
ble.

1.2 Emission Estimation Method

Estimating the quantity of municipal solid waste-in-place
(WIP) that contributes to methane emissions requires a
characterization of the current and expected future
population of landfills. EPA characterizes each landfill
in terms of its year of opening, waste acceptance during
operation, year of closure, and design capacity. The
landfill population as of 1990 is based on EPA's landfill
survey (EPA, 1988). The future population of landfills is
modeled by simulating the closure of existing landfills as
they reach their design capacity and the opening of new
landfills when a significant shortfall in disposal capacity
is predicted. Simulated new landfills are assumed to be
larger, on average, than the landfills they are replacing,
reflecting the trend toward fewer and larger regional
waste disposal facilities.
2-2 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

EPA simulates the opening and closing of landfills
based on waste disposal estimates. For 1990
through 1997, waste disposal estimates are based on
annual BioCycle data (BioCycle, 1998).2 The un-
certainty in predicting future waste disposal levels is
due to significant shifts in waste disposal practices.
Therefore, for the years after 1997, this analysis uses
a constant overall disposal rate based on the average
rate from 1990 to 1995. This simplification is based
on the assumption that the total amount of municipal
solid waste (MSW) generated will increase while
the percentage of waste landfilled will decline due to
rising recycling and composting rates (EPA, 1997a).
The current and future national quantity of waste
disposed is apportioned across an assumed popula-
tion of landfills. Exhibit 2-2 shows the landfill siz-
ing assumptions for each category used in the popu-
lation analysis. (See Appendix n, Exhibit n-3 for
the distribution of waste disposal across the landfill
categories). The analysis annually updates the land-
fill characteristics, i.e., the total WIP and years of
operation. The result is a simulated population of
landfills reflecting the national MSW disposal rates
overtime.
Exhibit 2-2: Landfill Capacity Assumptions
Landfill Category
Small
Small-Medium
Medium
Large
Very Large
Capacity (MT)
500,000
1,000,000
5,000,000
15,000,000
> 15,000,000
MT = metric tons
1.3 Emission Estimates
EPA uses the results of the landfill population analy-
sis to calculate the methane emissions from MSW
landfills. The quantity of waste in landfills over
time drives methane generation. An emissions
model uses this landfill-specific data to estimate the
amount of methane produced by MSW landfills in a
given year (EPA, 1993). The model is based on in-
formation from 85 landfills that represent the popu-
lation of U.S. landfills and vary in terms of depth, age,
regional distribution, and other factors.
As indicated in Exhibit 2-3, annual landfill methane
emissions are calculated by summing annual methane
generated from MSW landfills, subtracting methane re-
covered and oxidized, and adding methane emissions
from industrial solid waste.

Exhibit 2-3: Components of Methane Emissions from
Landfills
Total Landfill Methane Emissions
Equals
Methane Generated from Municipal Solid Waste
(MSW Landfills)
Less
Methane Recovered and Flared or Used for Energy
Less
Methane Oxidized from MSW Landfills
Plus
Methane Emissions from Industrial Waste Sites

Exhibit 2-4 presents estimates of the amount of munici-
pal solid waste contributing to methane emissions for the
years 1990 to 1997. Methane generation coefficients are
applied to the WIP to determine total methane generated
for individual landfills for the same period.3
The analysis also assesses the applicability of the Land-
fill Rule based on methane generated for each landfill.
The Landfill Rule (New Source Performance Standards
and Emissions Guidelines) was promulgated in March
1996 under the Clean Air Act and amended in June
1998. The Landfill Rule requires gas collection and
flaring or other combustion at landfills whose design
capacity exceeds 2.5 million metric tons (MMT) and 2.5
million cubic meters (million m3), and that emit 50 met-
ric tons per year (MT/yr) of non-methane organic com-
pounds (NMOCs). EPA estimates that up to 350 existing
and 50 new landfills will install gas control systems by
2000 under the Landfill Rule.4 The emission model
identifies which landfills are subject to the Landfill Rule
and projects baseline emissions accordingly. Thus, for
the purposes of the cost analysis presented in this chap-
ter, EPA analyzes only landfills with emissions below the
Landfill Rule threshold.
U.S. Environmental Protection Agency - September 1999
Landfills
2-3
image:

Although not explicitly modeled in this analysis,
EPA has estimated methane reductions under the
Climate Change Action Plan (CCAP). Under
CCAP, the Landfill Methane Outreach Program
(LMOP) has promoted methane recovery and utili-
zation. LMOP/CCAP reductions reflect those land-
fills at which LMOP has provided assistance.

1.3.1 Current Emissions and Trends
The amount of MSW in landfills contributing to
methane emissions increased from approximately
4,900 MMT in 1990 to approximately 5,800 MMT
in 1997. Methane emissions also increased between
1990 and 1997, from 56.2 million metric tons of
carbon equivalent (MMTCE) or 9.8 Teragrams (Tg)
to 66.7 MMTCE or 11.6Tg, respectively (EPA,
1999). Exhibit 2-5 shows this gradual increase of
1.5MMTCE/yr (0.26Tg/yr). Although emissions
increased, methane collection and combustion by
landfill operators also increased from an estimate of
8.6 MMTCE (1.5 Tg) in 1990 to 10.3 MMTCE
(1.8 Tg) in 1992. Since 1992, the number of landfill
gas recovery projects has increased substantially.
EPA is developing annual recovery estimates for gas
utilization projects for the period 1990-1998. These
estimates will be published in 2000, and may result in a
stable emissions trend over the period 1990-1998.
For purposes of electricity generation, the U.S. recovered
6.9 MMTCE (1.2 Tg) of landfill methane in 1990 and
8.1 MMTCE (1.4 Tg) in 1992 (GAA, 1994). To account
for methane flared without energy recovery, the recovery
estimate is increased by 25 percent to arrive at the total
methane recovered (EPA, 1993). Due to a current lack
of information on annual recovery rates, the 1990 esti-
mate is used for 1991, and the 1992 estimate is used for
1993 through 1997.

1.3.2 Future Emissions and Trends
As previously stated, total emissions are based on a char-
acterization of the surveyed U.S. landfill population.
The surveyed population, however, excludes industrial
landfills and landfills with a WIP less than 500,000 MT;
therefore, the emissions from these landfills are esti-
mated as a percentage of MSW emissions from the sur-
veyed population. Emissions for the small landfills
(containing less than 500,000 MT) are based on an esti-
mate of the portion of total waste disposed in small land-
fills. This portion is estimated to decline from 12 percent
of current MSW emissions to six percent of the MSW
emissions by 2020. Industrial landfill emissions are as-
Exhibit 2-4: Municipal Solid Waste Contributing to Methane Emissions (MMT)
Description
Total MSW Generated3
Percent of MSW Landfilledb
Total MSW Landfilled
Cumulative MSW Contributing to Emissions0
1990
267
77%
206
4,926
1991
255
76%
194
5,027
1992
265
72%
191
5,162
1993
279
71%
198
5,292
1994
293
67%
196
5,428
1995
297
63%
187
5,560
1996
297
62%
184
5,677
1997
309
61%
189
5,791
MMT = million metric tons
aj) Source: BioCycle, 1998.
cThe EPA emission model (EPA, 1993) assumes all waste that has been in place for less than 30 years emits methane.
Exhibit 2-5: Methane Emissions from
Activity
MSW Landfilling
Recovery
Oxidation from MSW
Industrial Waste Landfilling
Total
1990
66.4
(8.6)
(5.8)
4.2
56.2
Landfills (MMTCE)
1991
67.8
(8.6)
(5.9)
4.3
57.6
1992
69.7
(10.3)
(5.9)
4.4
57.8
1993
71.6
(10.3)
(6.1)
4.5
59.7
1994
73.6
(10.3)
(6.3)
4.6
61.6
1995
75.7
(10.3)
(6.5)
4.8
63.6
1996
77.3
(10.3)
(6.7)
4.9
65.1
1997
78.9
(10.3)
(6.9)
5.0
66.7
MMTCE = million metric tons of carbon equivalent
Totals may not sum due to independent rounding.
2-4 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

sumed to equal seven percent of the total methane
generated from MSW at all landfills, including those
with less than 500,000 MT. The emissions from
industrial and small landfills are added to the total
MSW methane emissions and are included in base-
line emissions. Excluding the small and industrial
landfills, approximately 3,900 existing and future
landfills are simulated in the U.S. landfill popula-
tion. Of these, approximately 2,030 existed in 1990.
Future landfill methane emissions will decline due
to the Landfill Rule and increased recycling and
alternative waste disposal methods. Based on the
annual quantity of waste disposed and the criteria for
the Landfill Rule, EPA simulates candidate landfills
for methane recovery. Since the analysis incorpo-
rates projected waste quantities, it reflects the fact
that certain landfills will not be subject to the Land-
fill Rule, and others will not have enough waste to
cost-effectively recover and use methane until some
time in the future. Exhibit 2-6 shows estimated
landfill methane emissions with and without the
Landfill Rule for 2000 through 2020. Baseline
emission projections include emission reductions
achieved as a result of the Landfill Rule.

1.4 Emission Estimate Uncertainties
The primary source of uncertainty with the landfill
emission estimates is the characterization of the cur-
rent and future landfill population. The characteri-
zation is based on an EPA survey of a small number
of landfills rather than landfill-specific information
from the population of U.S. landfills. For example,
the analysis simulates the opening and closing of
landfills, waste disposal over time, and the installa-
tion of landfill gas-to-energy recovery systems. In
addition, the baseline emission estimates do not include
emission reductions associated with landfills that flare
their gas and do not have landfill gas-to-energy recovery
systems. Such data are not currently available, but EPA
is working to develop it. Thus, the analysis underesti-
mates current emission reductions.

2.0 Emission Reductions

Two approaches exist for reducing methane emissions
from landfills: (1) recovering and either flaring or using
landfill methane for energy; and (2) modifying waste
management practices to reduce waste disposal in land-
fills, through recycling and other alternatives. The first
approach is an increasingly common practice as demon-
strated by the over 250 landfills that currently collect and
use their gas for energy (Kruger, et al., 1999). This re-
port focuses on evaluating the cost-effectiveness of
methane recovery for energy. The second approach is
not assessed, although expected changes in MSW dis-
posal rates due to recycling are reflected in the emission
projections.
The costs and benefits of emission reductions (through
the implementation of gas recovery projects) at landfills
not subject to the Landfill Rule are analyzed for the years
2000, 2010, and 2020. In addition, a marginal abatement
curve (MAC) is constructed showing a schedule of emis-
sion reductions that could be obtained at increasing val-
ues for methane. The analysis considers the value of
abated methane as the sum of its value as a source of
energy, i.e., natural gas and electricity, and as an emission
reduction of a greenhouse gas (GHG).
A description of the various technologies and practices
that can reduce methane emissions is provided in this
section. In addition, this section also presents the cost
Exhibit 2-6: Projected Baseline Methane Emissions from Landfills (MMTCE)
Activity
MSW Landfilling
Oxidation from MSW
Industrial Waste Landfilling
Total Emissions (without the Landfill Rule)
Landfill Rule Emission Reductions
Projected Baseline Emissions
2000
83.4
(8.3)
5.3
80.3
(28.8)
51.4
2005
87.5
(8.8)
5.5
84.3
(30.3)
54.0
2010
87.0
(8.7)
5.5
83.8
(31.8)
52.0
2015
82.5
(8.2)
5.2
79.4
(32.0)
47.4
2020
76.1
(7.6)
4.8
73.3
(32.2)
41.1
Totals may not sum due to independent rounding.
U.S. Environmental Protection Agency - September 1999
Landfills
2-5
image:

analysis for evaluating emission reductions as well
as the MAC for emission reductions in 2010. Fi-
nally, the uncertainties and limitations associated
with EPA's reduction estimates are described.

2.1 Technologies for Reducing
Methane Emissions

Gas collection, by vertical wells and horizontal
trenches, typically begins after a portion of a landfill,
called a cell, is closed. Vertical wells are most
commonly used for gas collection, while trenches
are sometimes used in deeper landfills, and may be
used in areas of active filling. The collected gas is
routed through lateral piping to a main collection
header. Ideally, the collection system should be de-
signed so that an operator can monitor and adjust the
gas flow if necessary. Once the landfill methane is
collected, it can be used in a number of ways, in-
cluding electricity generation, direct gas use (injec-
tion into natural gas pipelines), powering fuel cells,
or compression to liquid fuel. EPA's analysis fo-
cuses on the first two options, summarized below.
Electricity Generation. Almost 80 percent of land-
fill electric power generation projects use recipro-
cating internal combustion (1C) engines (Kruger, et
al., 1999). 1C engines are relatively inexpensive,
efficient, and appropriate for smaller landfills where
gas flows are between 625 thousand cubic feet per
day (Mcf/day) to 2,000 Mcf/day at 450 British ther-
mal units per cubic feet (Btu/ft3) (Jansen, 1992).
This gas flow and energy content is sufficient to
produce one to three megawatts (MW) of electricity
perproject(Thorneloe, 1992).

Direct Gas Use. Landfill gas is used as a medium-
Btu fuel for boilers or industrial processes, such as
drying operations, kiln operations, and cement and
asphalt production. In these projects, the gas is
piped directly to a nearby customer where it is used
as a replacement or supplementary fuel. If medium-
Btu fuel is sold to a customer that is in close prox-
imity to the landfill, ideally within five miles, usually
only minimal gas processing is required. Ideal gas
customers have a steady, annual gas demand com-
patible with a landfill's gas flow.
The analysis does not assess the following technologies
for reducing emissions because they are typically more
costly than electricity generation or direct gas use proj-
ects and the extent of their use in the landfill gas-to-
energy industry is difficult to predict.
> Reduced Landfilling. Landfilling is reduced
through recycling, waste minimization, and waste
diversion to alternative treatment and disposal meth-
ods, such as composting and incineration. The U.S.
is making significant efforts at both the federal and
state level to reduce landfilling. Although the analy-
sis does not evaluate the cost-effectiveness of re-
duced landfilling, the baseline methane emission es-
timates include the anticipated impacts of changes in
waste management practices.
> Turbine Generators. Similar to 1C engines, turbine
generators generate electricity. While turbines are
often better for large projects in excess of three MW,
1C engines are more cost-effective for the sizes of
projects examined in this analysis. Because the
largest landfills in the U.S. are expected to recover
and combust their gas under the Landfill Rule by the
year 2000, this analysis focuses on the smaller land-
fills for which 1C engines are preferred.
> Natural Gas Pipeline Injection. Landfill gas can
be sold to the natural gas pipeline system once it has
met certain process and treatment standards. This
option is appropriate in limited cases, such as when
very large quantities of gas are available.
> Liquid Vehicle Fuel. Landfill gas is processed into
liquid vehicle fuel for use in trucks hauling refuse to
a landfill.
> Flare-Only Option. Several U.S. landfills have
implemented flare systems without energy recovery
systems. These landfills are either required to flare
their landfill gas or they flare to control odor and gas
migration. EPA's analysis did not address flaring as
a stand-alone option.

2.2 Cost Analysis of Emission
Reductions
EPA evaluates both electricity generation and direct gas
use projects for landfills not subject to the Landfill Rule.
2-6 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

A project is considered cost-effective when the value
for its abated methane (revenue) is equal to or
greater than the project's cost. The analysis evalu-
ates the cost-effectiveness over a range of compara-
ble values for abated methane in terms of electricity
prices (dollars per kilowatt-hour or $/kWh), gas
prices (dollars per million Btu or $/MMBtu), and
emission reduction values (dollars per metric ton of
carbon equivalent or $/TCE).
EPA first evaluates electricity generation projects for
each modeled landfill and determines if such a proj-
ect is cost-effective. For those landfills where elec-
tricity generation projects are not cost-effective, the
analysis then evaluates whether direct gas use proj-
ects are cost-effective at an equivalent value in gas-
price terms, $/MMBtu. For landfills that cannot
cost-effectively implement either project, methane
emission reductions are zero. The analysis is re-
peated at a range of values for abated methane and
the results of the analysis are used to construct a
MAC.
Both electricity and direct gas use projects require a
gas collection system and involve capital and opera-
tion and maintenance (O&M) costs for various proj-
ect components. Capital costs for a collection sys-
tem include the purchase and installation of extrac-
tion wells, lateral well connections, a header system,
a gas mover system, and a condensate handling sys-
tem. Annual O&M figures include labor costs of
two to three person-years and indirect costs includ-
ing overhead, insurance, and administration. The
expected cost of replacing components of the col-
lection system are small relative to the overall cost
of the collection and recovery and utilization
systems. Additional component costs for electricity
and direct gas use are described in more detail be-
low.5

2.2.1 Electricity Generation
The cost analysis for landfill gas-to-electricity proj-
ects consists of the following three steps.
Step 1: Define Project Components. Each project
includes a collection system, flare system, and elec-
tricity production system. Appendix n, Exhibit II-5 de-
tails the factors used to estimate project costs.
> Collection System. As discussed above, all gas
recovery projects start with a gas collection system.
These costs are driven primarily by the amount of
WIP. Gas collection efficiency is assumed to be 75
percent of emitted methane.
> Flare System. All gas recovery projects require a
flare system because excess gas may need to be
flared at any time. Peak gas flow from the collection
system drives these costs.
> Electricity Production. Electricity production re-
quires a variety of equipment including: compres-
sors to move the gas, a prime mover (1C engines in
this case), an electric generator, an interconnect with
the local grid, and a monitoring and control system.
Total costs equal the sum of the components listed
above. Exhibit 2-7 lists estimated costs for projects of
various sizes as defined by a landfill's WIP and the elec-
tricity production capacity in MW. The size of each gen-
erator is based on the maximum gas flow rate during the
life of the project. In most cases the gas produced is less
than the maximum capacity of the engine generator. No
downtime is assumed since the unit is modeled to run at
less than capacity during most of the project's lifetime.
Step 2: Estimate Project Revenue. EPA estimates
revenues for a range of electricity prices and values of
abated methane. The rate at which landfill owners sell
electricity depends on local and regional electric power
market conditions, and often varies by time of day and
season. This analysis uses a market price of $0.04/kWh
(1996 US$) as a representative figure6 The analysis
does not consider additional revenues from state and
federal incentives for landfill gas-to-energy projects.
EPA estimates the annual total electricity production
from the project based on the amount of gas produced
and collected each year.
For modeling purposes, electricity prices are converted
to $/TCE using methane's Global Warming Potential
(GWP) of 21 and the heat rate (10,000 Btu/kWh) of the
engine-generator.7
U.S. Environmental Protection Agency - September 1999
Landfills
2-7
image:

Exhibit 2-7: Electricity Generation - Example Cost Estimates by Project Size
Size
WIP
(MT 000)
318
476
635
953
1,271
1,127
2,918
All estimates are in
Collect and Flare System
(MW)
0.50
0.75
1.00
1.50
2.00
3.00
5.00
1996 dollars.
Capital
($000)
$272
$353
$428
$568
$699
$654
$1,310

O&M
($000)
$61
$64
$67
$73
$78
$77
$103

1C Engine/Generator
Capital
($000)
$693
$1,011
$1,322
$1,927
$2,517
$3,957
$6,000

O&M
($000)
$66
$99
$131
$197
$263
$394
$657

Total Costs
Capital
($000)
$965
$1,364
$1,749
$2,495
$3,216
$4,611
$7,310

O&M
($000)
$127
$163
$199
$270
$341
$471
$760

Step 3: Evaluate Cost-Effectiveness. EPA as-
sesses the cost-effectiveness of implementing a proj-
ect at each landfill using a benefit-cost analysis with
the costs and revenues described above, and the cost
parameters listed in Exhibit 2-8. Electricity produc-
tion is assumed to take place for 20 years, with an
option at the end of that period to replace the engines
and generate electricity for another 20 years. If the
net present value (NPV) of the project is zero or
positive, the project is considered cost-effective.
Exhibit 2-8: Financial Assumptions for Emission
Reduction Analysis
Parameter
Value
Discount Rate
Depreciation Period
Marginal Tax Rate
Duration of Project

Collection Efficiency
8 percent real
10 years
40%
Electricity: 20 years; Di-
rect Gas Use: 15 years
75%
2.2.2 Direct Gas Use
EPA evaluates the cost-effectiveness of direct gas
use projects at landfills not subject to the Landfill
Rule and for which electricity generation projects
are not cost-effective. The evaluation is based on the
three steps indicated below.
Step 1: Define "Model" Project Components.
The costs of a model project include a gas collection
and flare system, gas treatment, gas compression to
50 pounds per square inch (psi), and a five-mile gas
pipeline to a customer. For each landfill size, EPA esti-
mates the capital and O&M costs for each component
using the unit costs presented in Appendix n, Exhibit II-6
and the cost parameters in Exhibit 2-8. The unit costs are
taken from the Energy Project Landfill Gas Utilization
Software (E-PLUS), an EPA-distributed software used to
evaluate the cost-effectiveness and feasibility of landfill
gas-to-energy projects (EPA, 1997b).8 Exhibit 2-9 pres-
ents the costs and break-even gas prices as defined by a
landfill's WIP.
EPA estimates the break-even gas prices ($/MMBtu)
required to support a "model" direct gas use project for
landfills with a WIP ranging from 50,000 to 11,000,000
MT. The break-even gas price is the value required to
produce a zero NPV over the 15-year life of the project.
Step 2: Define Methane Abatement Values. A market
price of gas of $2.74/MMBtu (1996 US$) is used in the
analysis. This price is 80 percent of the national average
industrial natural gas price of $3.42/MMBtu (EIA,
1997). The national average price is discounted by 20
percent to account for the fact that the landfill gas is a
medium-grade gas. EPA converts gas prices, in
$/MMBtu, to methane abatement values, in $/TCE, us-
ing methane's GWP of 21 and a Btu content of 1,000
Btu/ft3for methane.9
In order to compare direct gas use with electricity gen-
eration projects and combine them on the same MAC,
gas prices are aligned with the electricity prices based on
equivalent emission reductions values. For example, 150
percent of the market electricity price or $0.06/kWh, is
2-8 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 2-9: Direct Gas Use Cost Estimates by Project Size
WIP
(MT 000)
50
100
200
300
400
500
600
700
800
900
1,000
11,000
Collection and
Flare
Capital
($000)
$124
$156
$215
$269
$319
$364
$412
$458
$500
$540
$581
$3,522
O&M
($000)
$52.0
$54.5
$56.0
$57.3
$59.8
$62.3
$64.6
$68.0
$68.6
$70.0
$70.8
$189.0
Estimates are an average for arid
Compression
Capital
($000)
$3.3
$6.6
$13.4
$20.1
$26.7
$33.4
$40.1
$46.8
$53.5
$60.2
$129.0
$603.0
O&M
($000)
$12.6
$13.3
$14.6
$15.9
$17.2
$18.5
$19.8
$21.1
$22.3
$23.6
$37.0
$129.0
Gas Treatment
Capital
($000)
$3.25
$3.31
$3.42
$3.53
$3.64
$3.74
$3.85
$3.96
$4.07
$4.18
$5.30
$19.00
O&M
($000)
$10.0
$10.0
$10.0
$10.0
$10.0
$10.1
$10.1
$10.1
$10.1
$10.1
$10.2
$10.9
Pipeline
Capital
($000)
$924
$924
$924
$924
$924
$924
$924
$924
$924
$924
$924
$924
O&M
($000)
$18.5
$18.5
$18.5
$18.5
$18.5
$18.5
$18.5
$18.5
$18.5
$18.5
$18.5
$18.5
Total
Capital
($000)
$1,054
$1,090
$1,156
$1,216
$1,273
$1,325
$1,380
$1,432
$1,481
$1,529
$1,639
$5,068
O&M
($000)
$93
$96
$99
$102
$105
$109
$113
$118
$120
$122
$136
$347
Break- Even
Gas Price
($/MMBtu)
$55.03
$27.72
$14.92
$10.36
$8.11
$6.74
$5.83
$5.20
$4.67
$4.27
$2.16
$1.35
and non-arid conditions and represent 1996 dollars.
Source: EPA,1997b.
paired with 150 percent of the market gas price or
$4.10/MMBtu.

Step 3: Evaluate Cost-Effectiveness. For direct
use projects, EPA estimates the break-even WIP for
each gas price by interpolation; as shown in Exhibit
2-9. The analysis categorizes a landfill as imple-
menting a direct gas use project when its methane-
producing WIP is equal to or greater than the break-
even WIP for a given gas price.
Emission reductions from direct gas use projects
equal the gas that is collected and combusted. EPA
assumes that only 75 percent of these cost-effective
direct gas use projects are implemented to account
for the uncertainty in identifying an energy end-user.

As energy prices increase, the break-even WIP de-
clines allowing smaller landfills to cost-effectively
invest in direct gas use projects. This trend is im-
portant because while the Landfill Rule is reducing
emissions from larger U.S. landfills, many small
landfills exist where cost-effective reductions also
can be achieved.
2.3 Achievable Emission Reductions
and Marginal Abatement Curve
The result of this analysis is an assessment of the cost-
effectiveness of two types of landfill gas recovery and
use projects: electricity generation and direct gas use.
For 2010, EPA estimates that U.S. landfills could reduce
methane emissions by up to 10.5 MMTCE (l.STg)
through implementing these types of cost-effective proj-
ects at energy market prices (1996 US$). These potential
reductions are without any additional value for abated
methane in terms of $/TCE. If emission reduction values
are added to the energy market prices, greater methane
reductions are achieved. For example, EPA's analysis
indicates that with a value of $20/TCE for abated meth-
ane added to the energy market price, U.S. reductions
could reach 20.2 MMTCE (3.5 Tg) in 2010.
Exhibit 2-10 shows the amounts of abated methane in-
cremental to the Landfill Rule that can be cost-
effectively achieved for a range of comparable values of
abated methane through $200/TCE. For some landfills,
both electricity and direct gas use projects are cost-
effective. However, for modeling purposes, EPA as-
sumes that these landfills implement an electricity gen-
eration project. Consequently, the eligible landfills for
direct use projects indicated in Exhibit 2-10 represent
U.S. Environmental Protection Agency - September 1999
Landfills 2-9
image:

Exhibit 2-10: Schedule of Emission Reductions Over and Above the Landfill Rule by Price in 2010

Value of
Carbon
Equiva-
lent
($/TCE)
(10)
(6)d
0
10
20
30
40
50
75
100
125
150
175
200

Electricity Production3

Price
(S/kWh)
0.03
0.03
0.04
0.05
0.06
0.07
0.08
0.09
0.12
0.15
0.18
0.20
0.23
0.26

Break-Even
WIP
(MT)
Infeasible
Infeasible
2,900,493
538,232
273,860
177,368
129,583
101,309
66,064
48,086
Negligible
Negligible
j J
Negligible
Negligible
j J

Eligible
Landfills
0
0
64
773
1,919
2,319
2,505
2,615
2,685
2,720
2,720
2,720
2,720
2,720

Incremental
Reductions
(MMTCE)
0.00
0.00
1.98
11.25
6.96
1.27
0.29
0.11
0.05
0.02
0.00
0.00
0.00
0.00

Direct Gas Use

Price
(S/MMBtu)
1.64
2.05
2.74
3.84
4.94
6.03
7.13
8.23
10.98
13.73
16.48
19.23
21.98
24.73

Break-Even
WIP
(MT)
7,436,565
2,330,467
972,739
920,668
749,467
576,422
468,324
393,655
283,477
222,143
182,893
152,742
134,836
118,155

Eligible
Landfills
0
114
498
106
7
0
0
0
0
0
0
0
0
0

Incremental
Reductions
(MMTCE)
0.00
3.48
5.09
(7.35)'
(1.16)
(0.05)
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Total Emission
Reductions

Cumulative
Reductions
(MMTCE)
0.00
3.48
10.55
14.44
20.23
21.45
21.75
21.85
21.90
21.91
21.91
21.91
21.91
21.91

%of
base-
line
0%
7%
20%
28%
39%
41%
42%
42%
42%
42%
42%
42%
42%
42%

Label on
MACb
N/AC
A
B
C
D
E
F
G
H
I
J
K
L
M
Includes emission reductions for landfills at which either a gas or an electricity project is modeled as cost-effective. By default, the analy-
sis selects electricity projects over gas projects where both are cost-effective.
Point on marginal abatement curve (see Exhibit 2-11) indicating minimum break-even WIP for electricity and direct gas use projects.
Although cost-effective reductions at landfills of this size exist, they are subject to the Landfill Rule (over 2.5 MMT WIP), and thus, are not
counted as emission reductions in this analysis.
The potential emission reductions associated with the modeled prices of $2.05/MMBtu or -$6fTCE are "below the line" reductions in carbon
equivalent terms.
Negative incremental reductions indicate that emission reductions attributed to gas projects at lower prices are modeled as electricity
projects at higher prices because electricity projects become cost-effective as values increase above $0/TCE.
those landfills that find only direct gas use projects
cost-effective. As indicated in the exhibit, above
S20/TCE, no landfills find only direct gas use cost-
effective. The negative incremental reductions un-
der the direct gas option indicate the direct use proj-
ects for which electricity production also becomes
cost-effective at the higher methane values.
Exhibit 2-11 illustrates the MAC for landfill elec-
tricity generation and direct gas use projects not
subject to the Landfill Rule for 2010. Exhibit 2-12
presents the cumulative emission reductions for se-
lected values of carbon equivalent in 2000, 2010,
and 2020. The MAC can similarly be called a cost
or supply curve since it shows the marginal cost per
emission reduction amount. Energy market prices
are aligned with $0/TCE given that this price represents
no additional values for abated methane and where all
price signals come only from the respective energy mar-
kets. The "below-the-line" reduction amounts, with re-
spect to $0/TCE, illustrate this dual price-signal market,
i.e., energy market prices and emission reduction values.
Each point on the MAC represents the quantity of meth-
ane that is cost-effectively abated at a given energy price
combination and emission reduction value. In addition,
each point on the graph reflects the minimum break-even
WIP between electricity projects and direct gas use proj-
ects. The minimum break-even WIP for electricity gen-
eration and direct gas use projects determines the size of
the smallest landfill for which a landfill gas-to-energy
project is cost-effective. As shown in the exhibit, emis-
2-10 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 2-11: Marginal Abatement Curve for Methane Emissions from Landfills in 2010
Abated Methane (% of 2010 Baseline Emissions of 52.0 MMTCE)
Natural Gas
(1996$/MMBtu)

£
o
1
01
II 1

c
ro
0
2
2
z
•5

1 0% 5% 10% 15% 20% 25% 30% 35% 40% 45%
1
$27.26 $0.29"

$21.21 $0.23"

$15.27 $0.17"

$9.22 $0. ll-

Sa 29 $0.05-

$0.00 $0.00"

i i i i i i i i

J
Axis set to energy
market prices of H
$2.74/MMBtu and
$0.04/kWh F/
M

K
1

G
/ P D^— •— '
/ B
' — '*
A

-$250

-$200

-$150
-$100

-$50

•$o

•($50)
f iii.
1 0 5 10 15 20
(1996 ?ftWh) Abated Methane (MMTCE)

ul
o
t
i
o
^,
'£
«
re

o-
UJ
|
re
O
0)
3.
>

sion reductions approach their maximum at ap-
proximately S36/TCE which is comparable to
$0.08/kWh and $6.69/MMBtu.
The analysis indicates that at and below energy mar-
ket prices, only direct gas use projects are cost-
effective and electricity production projects do not
contribute to emission reductions. This modeled
result, however, underestimates the potential for
emission reductions since many landfills are cur-
rently implementing electricity projects. Many of
these landfills take advantage of state and federal
incentives that are not reflected in this analysis.
Emission reductions from both landfills impacted by
the Landfill Rule and "non-Rule" landfills reach
approximately 65 percent of total MSW methane
emissions, only 10 percent below the maximum pos-
sible given the estimated recovery efficiency of
75 percent. The analysis assumes that small and
industrial landfills, which were not evaluated for
purposes of the MAC, continue to emit methane.
Therefore total emission reductions do not approach
the 75 percent maximum.
Exhibit 2-12: Emission Reductions at Selected Values of
Carbon Equivalent in 2000,2010, and 2020 (MMTCE)

Baseline Emissions
Cumulative Reductions
at $0/TCE
at$10/TCE
at $20/TCE
at $30/TCE
at $40/TCE
at $50/TCE
at $75/TCE
at$100/TCE
at$125/TCE
at$150/TCE
at$175/TCE
at $200/TCE
Remaining Emissions
2000
51.4

11.0
14.1
18.2
19.7
20.1
20.5
21.2
21.4
21.5
21.6
21.6
21.7
29.8
2010
52.0

10.5
14.4
20.2
21.5
21.7
21.9
21.9
21.9
21.9
21.9
21.9
21.9
30.1
2020
41.1

7.6
10.1
13.9
15.0
15.5
15.7
15.8
15.9
15.9
15.9
15.9
15.9
25.2
2.4 Reduction Estimate Uncertainties
and Limitations
Most of the uncertainties associated with emission re-
duction estimates relate to the landfill population uncer-
tainties described in the first section. Additional data are
needed to improve the basis for characterizing the land-
fill population and the potential to collect and use gas
cost-effectively at each landfill.
U.S. Environmental Protection Agency - September 1999
Landfills 2-11
image:

Other uncertainties involve landfill gas recovery
technologies and the costs for recovering landfill
gas. For both electricity and direct gas use projects,
EPA estimates the costs using aggregate cost factors
and a relatively simple set of landfill characteristics.
Costs vary depending on the depth, area, WIP, and
waste materials for each landfill. Uncertainty is as-
sociated with the electricity analysis because EPA
bases costs on a representative WIP. Although the
costs for direct gas use projects account for depth,
area, and WIP (along with unit costs), they are only
representative of average costs.
The price at which landfills sell electricity also is an
important driver in the analysis. At higher rates,
more landfills find it cost-effective to implement
electricity projects. In addition, efforts to reduce
landfilling, including waste management policies
that go beyond existing programs, are potentially
cost-effective in further reducing future methane
emissions. The costs and benefits of such alternative
waste management policies are not included in this
assessment.
Lastly, project revenues only reflect market prices of
electricity and gas and do not reflect state and fed-
eral incentives or subsidies. Incorporating these cur-
rently available incentives in the analysis would re-
sult in additional cost-effective emission reductions.
2-12 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

3.0 References

EIA. 1997. Natural Gas Annual 1996. Office of Oil and Gas, Energy Information Administration, U.S. Depart-
ment of Energy, Washington, DC, DOE/EIA-0131(96). (Available on the Internet at http://www.eia.doe.gov/
oil^as/natural_gas/nat_rrame .html.)
EPA. 1988. National Survey of Solid Waste (Municipal) Landfill Facilities. Office of Solid Waste, U.S. Envi-
ronmental Protection Agency, Washington, DC, EPA 530-SW-88-011.
EPA. 1993. Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress.
Atmospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental Protection
Agency, Washington, DC, EPA 430-R-93-003. (Available on the Internet at http://www.epa.gov/ghginfo/re-
ports.htm.)
EPA. 1996. Standards of Performance for New Stationary Sources and Guidelines for Control of Existing
Sources: Municipal Solid Waste Landfills: 40 CFR Part 60. Federal Register, U.S. Environmental Protection
Agency, Washington. DC, EPA 61-FR-9905. (Available on the Internet at http://www.epa.gov/docs/fedrgster/
EPA-AIR/1996/March.)
EPA. 1996. Turning a Liability into an Asset: A Landfill Gas To Energy Project Development Handbook. At-
mospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental Protection Agency,
Washington, DC, EPA 430-B-96-0004. (Available on the Internet at http://www.epa.gov/lmop/products.htm.)
EPA. 1997a. Characterization of Municipal Solid Waste in the United States: 1996 Update. Office of Solid
Waste, Municipal and Industrial Solid Waste Division, U.S. Environmental Protection Agency, Washington,
DC, EPA 530-S-98-007. (Available on the Internet at http://www.epa.gov/epaoswer/non-hw/muncpl/
msw96.htm.)
EPA. 1997b. Energy Project Landfill Gas Utilization Software (E-PLUS), Project Development Handbook. At-
mospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental Protection Agency,
Washington, DC, EPA 430-B-97-006. (Available on the Internet at http://www.epa.gov/lmop/products.html.)
EPA. 1998. Standards of Performance for New Stationary Sources and Guidelines for Control of Existing
Sources: Municipal Solid Waste Landfills: 40 CFR Subparts Cc. Federal Register, U.S. Environmental Protec-
tion Agency, Washington, DC, EPA 63-FR-32743. (Available on the Internet at http://www.epa.gov/docs/
fedrgstr/EPA-AIR/1998/June.)
EPA. 1999. Inventory of Greenhouse Gas Emissions and Sinks 1990-1997. Office of Policy, Planning, and
Evaluation, U.S. Environmental Protection Agency, Washington, DC, EPA 236-R-99-003. (Available on the
Internet at http://www.epa.gov/globalwarming/inventory/1999-inv.html.)
GAA. 1994. 1994-1995 Methane Recovery from Landfill Yearbook. Government Advisory Associates, Inc.,
New York, NY.
Glenn, Jim. 1998. "BioCycle Nationwide Survey: The State of Garbage in America." BioCycle, no. 4.
Jansen, G.R. 1992. The Economics of Landfill Gas Projects in the United States. Presented at the Symposium on
Landfill Gas Applications and Opportunities, Melbourne, Australia.
Kruger, Dina, et al. 1999. 7999 Update of U.S. Landfill Gas-to-Energy Projects. Presented at the 22nd Annual
Landfill Gas Symposium, Orlando, FL.
U.S. Environmental Protection Agency - September 1999 Landfills 2-13
image:

Liptay, K., et al. 1998. "Use of Stable Isotopes to Determine Methane Oxidation in Landfill Cover Soils." JGR-
Atmospheres, 103D, 8243-8250 pp.
Thorneloe, Susan A. 1992. Landfill Gas Recovery/Utilization - Options and Economics. Global Emissions and
Control Division, Air and Energy Engineering Research Laboratory, U.S. Environmental Protection Agency,
Research Triangle Park, NC.
2-14 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

4.0 Explanatory Notes
1 Climate Change Action Plan or CCAP reductions are achieved as a result of voluntary industry actions. For exam-
ple, under CCAP, EPA created the joint EPA-industry Landfill Methane Outreach Program (LMOP). Under this
program, landfill industry partners undertake cost-effective efforts to reduce methane emissions from landfills. This
analysis does not evaluate specific emission reductions associated with LMOP, rather, the analysis focuses on pro-
jected cost-effective emission reductions at landfills not impacted by the Landfill Rule. EPA expects that 40 per-
cent of the cost-effective emission reductions available in 2010 will be taken as a result of LMOP.

2 BioCycle includes construction and demolition (C&D) debris in their estimates of waste generation. However, the
definition of municipal solid waste (MSW) is not uniform for each state in BioCycle's survey. Some states report
C&D because many of their landfills accept waste from a variety of sources (BioCycle 1998). Although the waste
estimates prior to 1990 exclude C&D waste, EPA did not adjust the BioCycle estimates due to the inconsistent
definition of MSW for each state.

3 Equations for calculating methane generation as a function of methane generating waste-in-place (WIP):

Methane Generating WIP Methane Emissions (MT/year)
Less than or equal to 0.04 106 MT 0
Greater than 0.04 106 MT and less than or equal 7.43 x (WIP/106) x Conversion Factor3 x Scaleb
to 2.0 x 106 MT
Greater than 2.0 x 106 MT (8.22 + 5.27 x (WIP/106)) x Conversion Factor3 x Scaleb
a Conversion Factor (mVmin to MT/year) = (365 days/yr) x (24 hrs/day) x (60 min/hr) x (662 g CEL/m3) x
(MT/106g).
b The landfills in the landfill population data set are weighted in order to adjust the sample landfill population to
the national level. The weighted numbers are 2, 3, and 7. Hence, a simulated landfill may account for 2, 3, or 7
landfills (Scale = 2, 3, or 7).

These equations are based on a survey of 85 landfills with a WIP ranging from 1.2 million MT to 30 million MT.
The third equation is based on a regression analysis of the survey results. The second equation is based on the av-
erage rate of methane generation per unit of WIP.

4 EPA conducts the emission analysis using a range of high and low average NMOC concentration values based on
the number of landfills expected to trigger under the Landfill Rule by 2000. EPA calibrates the model by adjusting
the average methane NMOC concentration to 500 parts per million by volume in order to simulate 350 existing and
approximately 50 new landfills that will trigger under the Landfill Rule by 2000.

5 EPA assumes that capital and O&M costs are constant for the 30-year time horizon and do not change due to de-
velopment of more efficient and less costly technologies.

6 The electricity rates in the U.S. that landfills are able to obtain for their generation, i.e., electric buyback rates, vary
depending on several factors, including: the cost of system power on the grid (peak or off-peak), transmission (and
in some cases distribution charges), region, and pricing. In addition, renewable power commands a premium that
historically has been in the form of regulated buy-back rates or tax credits. More recently it has taken the form of
green power premiums. Historically, under a regulated environment, landfill gas power projects have received
electric buyback rates ranging from $0.02/kWh to $0.10/kWh, averaging about $0.06/kWh (EPA, 1996). For this
study, EPA assumes a price of $0.04/kWh. This value represents the price of electricity close to distribution sys-
tems and receiving a renewable energy premium.
U.S. Environmental Protection Agency-September 1999 Landfills 2-15
image:

7 Equation to calculate the equivalent electricity price for a given value of carbon equivalent:

$ IQ6 TCE 5.13MMTCE Tg 19.2 g CH 4 ft3 10,000 Btu
• x x x x x ~
TCE MMTCE TgCH^ 1Q12 g ft3 CH4 1,000 Btu kWh kWh

Where: 5.73 MMTCE/Tg CH4 = 21 CO2/CH4 x (12 C / 44 CO2)
Density of CH4= 19.2 g/ft3
Btu content of CH4 = 1,000 Btu/ft3
Heat rate of 1C Engine = 10,000 Btu/kWh

3 The costs for electricity production and direct gas use are based on different algorithms. Both options include col-
lection and flare project components because some amount of gas will be flared. The landfill depth and area, and
the collection system variable O&M costs are adjusted in E-PLUS so that the direct gas use collection capital and
O&M costs are calibrated within five to ten percent of the electricity project collection system costs.

5 Equation to calculate the equivalent gas price for a given value of carbon equivalent:

$ 106 TCE 5.73MMTCE Tg 19.2 g CH4 ft3 W6 Btu $
TCE MMTCE TgCH4 1012 g ft3 CH. 1,000 Btu MMBtu MMBtu
Where: 5.73 MMTCE/Tg CH4 = 21 CO2/CH4 x (12 C / 44 CO2)
Density of CH4= 19.2 g/ft3
Btu content of CH4 = 1,000 Btu/ft3
2-16 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

3. Natural Gas Systems
Summary

EPA estimates 1997 U.S. methane emissions to be 33.5 MMTCE (5.8 Tg) from natural gas systems and 1.6
MMTCE (0.3 Tg) from oil systems, which together accounted for approximately 20 percent of total U.S. anthro-
pogenic methane emissions (EPA, 1999). In 1997, the U.S. produced 18.9 trillion cubic feet (Tcf) (364 Tg) and
consumed 22.0 Tcf (422 Tg) of natural gas (the balance was imported), which is 95 percent methane (EIA, 1999).
Natural gas is produced at thousands of gas and oil wells, purified at hundreds of processing plants, transported
through a continental network of pipelines, and delivered to millions of customers. Natural gas consumption is
divided among industrial (44 percent), residential (25 percent), commercial (16 percent), and electric utility (15
percent) uses (EIA, 1998). Methane is emitted to the atmosphere through leaks and by accidental and deliberate
venting of natural gas during normal operations, i.e., production, processing, transmission, and distribution.
Because natural gas is often found in conjunction with oil, its production and processing also emits methane.
EPA expects baseline emissions from natural gas systems to grow as natural gas consumption increases. The U.S.
Department of Energy anticipates U.S. gas consumption will increase 1.6 percent each year between 1996 and
2020, leading to annual consumption of about 32 Tcf (618 Tg) by 2020. Demand is expected to increase in all
sectors, especially from electric utilities (EIA, 1998). However, equipment turn-over along with new and more
efficient technologies will result in a methane emission growth rate that is lower than the growth in consumption.
EPA estimates that methane emissions from natural gas systems will reach 37.9 MMTCE (6.6 Tg) by 2010, ex-
cluding possible Climate Change Action Plan (CCAP) reductions.
CCAP's Natural Gas STAR Program, a voluntary EPA-industry partnership, has identified cost-effective tech-
nologies and practices that can reduce methane emissions. In 2010, EPA estimates that up to 10.1 MMTCE (1.8
Tg) of reductions are cost-effective at energy market prices (in 1996 US$) or $0/TCE, as Exhibit 3-1 shows.
Methane emissions could be reduced below 1990 emissions of 32.9 MMTCE (5.7 Tg) for natural gas systems if
these cost-effective technologies and practices are thoroughly implemented. More reductions could be achieved
with the addition of higher carbon equivalent values.

Exhibit 3-1: U.S. Methane Emissions from Natural Gas Systems (MMTCE)
Percent of Methane Emissions in 1997

Natural Gas and Oil 20%
. (35.1 MMTCE)
Emission Estimates and Reductions
Landfills 37%
Manure 10%
Enteric Fermentation 19%
Total = 179.6 MMTCE
Source: EPA, 1999.
MMTCE
@ 21 GWP
40

6
Tg
CH.
--7
Cost-Effective Reductions
^-Baseline Emissions
Emission Levels at
Different $/TCE
Remaining Emissions
2000 2010
Year
2020
U.S. Environmental Protection Agency - September 1999
Natural Gas Systems 3-1
image:

1.0 Methane Emissions from
Gas and Oil Systems

This section summarizes the sources of emissions from
oil and gas systems and describes EPA's methodology
for estimating these emissions. The section also pres-
ents EPA's emission estimates and forecast.

1.1 Emission Characteristics
Natural Gas. The natural gas sector is comprised of
four major sub-sectors: production, processing, trans-
mission, and distribution. Methane emissions occur
during normal operations in all sub-sectors as de-
scribed in Exhibit 3-2. During production, gas exits
wells under very high pressure, often greater than
1,000 pounds per square inch (psi). The gas is routed
to dehydrators, where water and other liquids are re-
moved, and then to small-diameter gathering lines for
transport to either processing plants or directly into
interstate pipelines. Processing plants further purify
the gas by removing natural gas liquids, sulfur com-
pounds, particulates, and carbon dioxide. The proc-
essed gas, which is about 95 percent methane, is then
injected into large-diameter transmission pipelines
where it is compressed and transported to distribution
companies, often hundreds of miles away. Distribu-
tion companies take the high-pressure gas (averaging
300 psi to 600 psi) and reduce the pressure to as low as
a few pounds or even ounces per square inch for deliv-
ery to homes, businesses, and industry.
From wellhead to end user, the gas moves through
hundreds of valves, processing mechanisms, compres-
sors, pipes, pressure-regulating stations and other
equipment. Whenever the gas moves through valves
and joints under high pressure, methane can escape to
the atmosphere. In many instances, gas is vented to the
atmosphere as part of normal operations. For example,
a major source of vented emissions are pneumatic de-
vices, that operate valves using pressure in the system
and bleed small amounts of gas to the atmosphere
when valves are opened and closed. Another example
of venting is the common industry practice of shutting
down a compressor and purging the gas in the com-
pression chamber to the atmosphere.
Oil. Most oil wells produce some natural gas, which is
usually dissolved in the crude oil stream. Methane and
other volatile hydrocarbon compounds dissolved in oil
escape the solution as the oil is processed and stored in
Exhibit 3-2: Sources of Methane Emissions from Oil and Gas Activities (1997)
Industry Sector

Production

Processing

Transmission &
Storage

Distribution

Total

Totals may not sum
Source: EPA, 1999
Natural Gas Industry
Sources of Emissions

Wellheads, dehydrators, separators,
gathering lines, and pneumatic devices

Compressors and compressor seals,
piping, pneumatic devices, and processing
equipment
Compressor stations (blowdown vents,
compressor packing, seals, valves),
pneumatic devices, pipeline maintenance,
accidents, injection/withdrawal wells,
pneumatic devices, and dehydrators
Gate stations, underground non-plastic
piping (cast iron mainly), and third party
damage

due to independent rounding.

Percent of
Total and
Amount
25%
8.4 MMTCE
or1.5Tg
12%
4.1 MMTCE
or 0.7 Tg
37%
12.4 MMTCE
or2.2Tg

26%
8.6 MMTCE
or1.5Tg
33.5 MMTCE
or5.8Tg

Crude Oil Industry
Sources of Emissions

Wellheads, separators, venting
and flaring, other treatment
equipment
Waste gas streams during
refining

Transportation tanker
operations, crude oil storage
tanks

Not applicable

Percent of
Total and
Amount
49%
0.7 MMTCE or
0.1 3 Tg
2%
0.1 MMTCE or
0.01 Tg
48%
0.7 MMTCE or
0.1 3 Tg

1.6 MMTCE or
0.27 Tg

3-2 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

holding tanks before being transported off the well site.
Depending on how much gas is associated with the oil,
field operators may install equipment to capture and
sell much of the gas.

1.2 Emission Estimation Method
The method for estimating emissions from natural
gas systems is different from the method for oil
systems. These methods are described below.
1.2.1 Natural Gas System Emissions
EPA relies on three types of data to generate the annual
methane emission inventory: emission factors, activity
factors, and activity factor drivers. These elements are
described below:
>- Emission Factors. Emission factors describe the
rate of methane emissions measured or estimated
at a piece of equipment or facility during normal
operations. The source of the emission factors is a
detailed study, Methane Emissions from the Natu-
ral Gas Industry, sponsored by EPA and the Gas
Research Institute (EPA/GRI, 1996). Based on
this study, EPA has developed emission factors for
about 100 sources within the natural gas industry,
e.g., gas well equipment, pipeline compressors
and equipment, and system upsets.
>~ Activity Factors. Activity factors are statistics on
pieces of equipment or facilities that are associ-
ated with given emission factors. Examples in-
clude number of wells, miles of pipe of a similar
type and operating regime, or hours of operation
by compressor type. Activity factors are critical
for extrapolating from a limited set of emission
measurements at individual pieces of equipment to
larger facilities and ultimately to the entire indus-
try. The EPA/GRI study developed activity fac-
tors corresponding to the emission factors. Addi-
tional sources of activity data are publications
from the Energy Information Administration
(EIA), American Petroleum Institute (API),
American Gas Association (AGA), and others.
>^ Activity Factor Drivers. Activity factor drivers
are used to adjust the magnitude of activity factors
from year to year consistent with gas market and
industry changes in order to update or forecast
emission estimates. Examples of drivers include
gas sales, miles of distribution main, number of
wells, and hours of compressor operations. In
some cases, the relationship between activity fac-
tor drivers and emission estimates may be indirect.
For example, to estimate emissions from glycol
dehydrates, EPA first estimates an average num-
ber of dehydrates per well. The number of wells,
i.e., the activity factor driver, is updated annually
and used to update emissions from glycol dehy-
drates. EPA obtains activity driver data from
EIA, API, AGA, and other industry sources.
Appendix HI, Exhibits m-1 and m-2 summarize the
emission factors, activity factors, and activity factor
drivers used in this analysis.
The emission inventory estimate begins with a func-
tional segmentation of the industry and the activities
that occur within each segment: production, process-
ing, transmission and storage, and distribution (See
Exhibit 3-2). For each segment, EPA estimates emis-
sions by multiplying emission factors (EF) by associ-
ated segment-wide activity factors (AF) as shown in
this formula:

Total emissions = EF x AF

The multi-volume EPA/GRI report, Methane Emis-
sions from the Natural Gas Industry, analyzes emis-
sions from all gas industry segments for the year 1992
and sums these emissions. EPA uses this estimate for
the 1992 national estimate. For the period 1990 to
1997, EPA uses the activity factor drivers to adjust the
1992 estimate to reflect annual changes in the industry.
While EPA annually adjusts activity factors to reflect
year-to-year changes in the industry, emission factors
are treated differently. For the period 1990 to 1995,
the emission factors are held constant. However, EPA
assumes that a gradual improvement in technology and
practices along with equipment replacement will lower
emission factors by a total of five percent between
1995 and 2020.

1.2.2 Oil Industry Emissions
The current estimates of methane emissions from the
oil industry depend on emission factors and activity
U.S. Environmental Protection Agency - September 1999
Natural Gas Systems 3-3
image:

factors based on broad categories of activities in the oil
industry and not on a detailed, bottom-up approach as
used for the natural gas sector estimates. The major oil
sector activities are summarized in Exhibit 3-3.
Production Field. Emission factors for oil production
are taken from Anthropogenic Methane Emissions in
the United States: Estimates for 1990, Report to Con-
gress (EPA, 1993). Emission factors are multiplied by
updated activity factors (for the portion of oil wells
that do not produce associated gas) as reported by API
(1997).
Crude Oil Storage. Baseline emissions from crude
oil storage are from Tilkicioglu and Winters (1989),
who developed emission factor estimates by analyzing
a model tank battery facility. These emission factors
are applied to published crude oil storage data to esti-
mate total emissions across the industry. Crude oil
storage data are obtained from the Department of En-
ergy (EIA, 1991-97).
Refining Waste Gas Streams. Tilkicioglu and Win-
ters estimated national methane emissions from waste
gas streams based on measurements at ten refineries.
These data were extrapolated to total U.S. refinery
capacity to estimate total emissions from waste gas
streams for 1990. To estimate emissions for 1991 to
1996, the 1990 emission estimates were scaled using
updated data on U.S. refinery capacity (EIA, 1991-96,
1997).
Transportation. EPA uses proxies to estimate emis-
sions from crude tanker operations. For domestic
crude, the estimate is for Alaskan crude offloaded in
the continental U.S.; for imports, the estimate is for the
total imported less imports from Canada. An emission
factor from Tilkicioglu and Winters (1989) based on
the methane content of hydrocarbon vapors emitted
from crude oil is multiplied by the crude oil tanker
handling estimates. Data on crude oil stocks, crude oil
production, utilization, and imports are obtained from
EIA (1991-96, 1997).
Venting and Flaring. Of the five activity categories,
venting and flaring can occur at all stages of crude oil
production and handling. However, for EPA methane
emission estimates, venting and flaring is treated as a
separate activity. Data from EIA (1991-96, 1997) indi-
cate that venting and flaring activities have changed
over time for a variety of reasons. Given the consider-
able uncertainty in the emission estimate for this cate-
gory, and the inability to discern a trend in actual emis-
sions, the 1990 emission estimate is used for the years
1991-1997.
EPA is revising the method for estimating methane
emissions from oil production so that it will be more
similar to the approach for natural gas systems. The
revised approach, based on EPA and API work (1997),
uses a much more disaggregated description of the
crude oil production sector and activity and emission
factors for specific equipment to generate the emission
estimates. EPA expects to employ the new method for
EPA's 1998 U.S. inventory estimates which will be
published in 2000.

1.3 Emission Estimates
This section presents the current emission estimates
for natural gas and oil systems and a forecast of emis-
sions from natural gas systems.
Exhibit 3-3: Oil Industry Activities for Current Emission Estimates
Activity
Description
Production Field

Crude Oil Storage

Refining Waste Gas Streams
Transportation (Tanker Operations)
Venting and Flaring
Fugitive emissions from oil wells and related production field treatment and separation
equipment
Crude oil storage tanks emit methane when oil is cycled through the tanks and hydro-
carbons escape solution
A variety of sources within refinery operations emit gas
Emissions occur as tankers are loaded and unloaded
Gas that cannot be captured during production is vented or flared
3-4 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

1.3.1 Current Emissions and Trends
U.S. natural gas systems emitted 33.5 million metric
tons of carbon equivalent (MMTCE) or 5.8 Teragrams
(Tg) of methane in 1997 or about 19 percent of total
U.S. anthropogenic methane emissions, as Exhibit 3-4
shows. These methane emissions from gas systems
account for about one percent of the natural gas con-
sumed in the U.S. in 1997. Emissions have increased
slightly from 1990 reflecting an increase in the number
of producing gas wells and distribution pipeline mile-
age. The increase in emissions was slowed by the
emission reductions reported by Partners in EPA's
Natural Gas STAR Program, one of the U.S. Climate
Change Action Plan (CCAP) programs. The Natural
Gas STAR Program was initiated in 1994 and works
with natural gas and oil companies to identify and
promote Best Management Practices (BMPs) and
Partner Reported Opportunities (PROs) that reduce
methane emissions cost-effectively.
From 1990 to 1997, methane emissions from oil sys-
tem activities remained relatively constant at approxi-
mately 1.6 MMTCE (0.3 Tg). Currently, no CCAP
program is devoted to reducing methane emissions
from oil systems; however, the Natural Gas STAR
Program includes BMPs that reduce methane emis-
sions from oil systems. Exhibit 3-5 presents the emis-
sion estimates from oil systems. EPA is revising the
estimation method for oil systems and expects esti-
mates to increase.

1.3.2 Future Emissions and Trends
Natural Gas. Future emissions from natural gas sys-
tems are estimated by forecasting both emission fac-
tors and activity factors from the 1992 base year fac-
tors developed by EPA and GRI (1996). As noted
above, EPA assumes that emission factors decline by a
total of five percent between 1995 and 2020 as the
existing stock of equipment is gradually replaced with
newer and more efficient equipment.
Exhibit 3-4: Methane Emissions from Natural Gas Systems (MMTCE)
Source
Production
Processing
Transm ission/Storage
Distribution
Sub-Total
CCAP Reductions3
Total
1990
8.0
4.0
12.6
8.3
32.9
32.9
1991
8.2
4.0
12.7
8.4
33.3
33.3
1992
8.5
4.0
12.9
8.6
33.9
33.9
1993
8.7
4.0
12.6
8.8
34.1
34.1
1994
8.8
4.2
12.5
8.7
34.2
(0.7)
33.5
1995
9.1
4.1
12.5
8.7
34.3
(1.2)
33.2
1996
9.5
4.1
12.4
9.1
35.0
(1.3)
33.7
1997
9.5
4.1
12.7
8.9
35.1
(1.6)
33.5
a CCAP reductions are from the Natural Gas STAR Program.
Totals may not sum due to independent rounding.
Source: EPA, 1999.
Exhibit 3-5: Methane Emissions from Oil Systems (MMTCE)
Source
Production
Crude Oil Storage
Transportation
Refining
Venting & Flaring
Total
Totals may not sum
Source: EPA, 1999.
1990
0.14
0.01
0.03
0.06
1.32
1.56
1991
0.14
0.01
0.03
0.06
1.32
1.56
1992
0.14
0.01
0.03
0.06
1.32
1.56
1993
0.14
0.01
0.03
0.06
1.32
1.56
1994
0.14
0.01
0.03
0.06
1.32
1.56
1995
0.13
0.01
0.03
0.06
1.32
1.55
1996
0.13
0.01
0.03
0.05
1.32
1.55
1997
0.13
0.01
0.06
0.05
1.32
1.55
due to independent rounding.

U.S. Environmental Protection Agency - September 1999
Natural Gas Systems 3-5
image:

The principal drivers of future activity factors are the
levels of gas consumption and domestic production,
including the necessary expansions in industry infra-
structure to meet these market levels. Using the con-
sumption and production forecasts from the EIA's An-
nual Energy Outlook (EIA, 1998), EPA estimates the
changes in infrastructure necessary to meet these con-
sumption and production levels. Exhibit 3-6 presents
forecasts of baseline methane emissions from natural
gas systems through 2020. Unless actions are taken to
reduce emissions, natural gas systems will emit 13
percent more methane in 2020 than in 1992, mostly
due to growth in natural gas consumption and the as-
sociated growth in infrastructure. The forecast meth-
odology is described below.
>^ Production Sector. Methane emissions from
natural gas production depend on the number of
wells needed for the forecast level of production
and the location of the wells, since operating char-
acteristics and equipment profiles vary by region.
EPA uses the Gas Systems Analysis Model
(GSAM) to estimate the number of wells. GSAM
represents over 16,000 reservoirs, the entire gas
transmission network and gas markets, and it
identifies the number of wells needed to generate
the forecast output and the location of these wells.
From these forecasts, EPA estimates the emissions
associated with ancillary well equipment, such as
dehydrators, separators, heaters, and meters.
>- Processing Sector. Processing and related
equipment associated with emissions are scaled to
domestic production.
>^ Transmission and Storage Sector. Transmission
and storage emissions are related to forecasts of
domestic consumption (sum of net production and
imports). For compressors and their operations
(hours in service per year), EPA generates emis-
sion estimates based on the pipeline throughput
necessary to meet projected consumption. An in-
crease in customers leads to an increase in pipe-
line mileage. Emission increases from storage op-
erations and related equipment are associated with
growth in consumption.
>^ Distribution Sector. The major sources of emis-
sions from the distribution sector are gate stations,
metering and pressure regulating equipment, and
cast iron and unprotected steel distribution pipe.
Emissions depend on the number of customers,
consumption, and the rate of cast iron and unpro-
tected steel pipe replacement. The forecast
method uses consumption and pipe replacement
statistics to estimate future distribution activity
factors (EPA/GRI, 1996).
Oil. EPA's current forecast of emissions from oil sys-
tems—1.6 MMTCE in 2010, 1.7 MMTCE in 2020—
is being revised. The new estimate will reflect that
methane emissions from oil systems are directly pro-
portional to the overall size of the petroleum industry.
DOE expects U.S. demand for petroleum products to
grow by 1.2 percent annually between 1996 and 2020,
from 18.4 million barrels per day in 1996 to 24.3 mil-
lion barrels per day in 2020 (EIA, 1998).

1.4 Emission Estimate Uncertainties
Natural Gas. Uncertainties in the emission estimates
stem from the size, complexity, and heterogeneity of
the infrastructure of the U.S. natural gas industry. In
this analysis, the estimate of methane emissions from
natural gas systems is accurate to within plus or minus
25 percent. The estimate of overall accuracy is based
on separate assessments of the uncertainties sur-
rounding each activity factor and emission factor used
Exhibit 3-6: Projected Baseline Methane Emissions from Natural
Source 2000
Production 9.2
Processing 4.2
Transmission 13.5
Distribution 8.8
Total 35.6
2005
9.8
4.4
13.7
8.8
36.7
Gas Systems (MMTCE)
2010
10.6
4.6
14.0
8.8
37.9
2015
11.1
4.6
14.3
8.7
38.7
2020
10.8
4.8
14.6
8.7
38.8
Totals may not sum due to independent rounding.
3-6 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

in developing the emission estimate. The total uncer-
tainty range is the sum of the individual uncertainties
for each emission source.

Oil. Compared to the natural gas industry, greater un-
certainties are associated with all aspects of the meth-
ane emission estimates for the oil industry. EPA be-
lieves that the current estimation method significantly
understates emissions and that methane emissions may
be four to five times greater than the estimated 1.6
MMTCE (0.3 Tg) presented here. As noted above, the
method for estimating methane emissions from petro-
leum systems is being updated.
2.0 Emission Reductions

This section describes how EPA estimates the costs
and benefits of achieving emission reductions at dif-
ferent potential values for methane. The value of
abated methane is the market price of the methane as
natural gas, in $/MMBtu, and also may include a car-
bon equivalent value for emission reductions, if avail-
able. The analysis only assesses reductions from
natural gas systems and does not include oil systems.

2.1 Technologies for Reducing
Methane Emissions
A number of technologies and practices have been
identified that can reduce methane emissions from
natural gas systems. EPA and the natural gas industry,
through the Natural Gas STAR Program, have identi-
fied several Best Management Practices (BMPs) that
are cost-effective in reducing methane emissions. The
Natural Gas STAR Program has sponsored a series of
Lessons Learned Studies of these BMPs and several
other practices. These studies provide detailed infor-
mation on the costs of achieving methane emission
reductions (EPA, 1997a-h). In addition, companies that
are Natural Gas STAR Partners have identified other
practices that also reduce methane emissions. The cost
analysis described herein is based on the BMPs and
Partner-Reported Opportunities (PROs) listed in
Exhibit 3-7. More details of these BMPs and PROs
are found in Appendix HI, Exhibits m-3 and m-4.
2.2 Cost Analysis of Emission
Reductions
The objective of the cost analysis is to develop a
marginal abatement curve (MAC) from the available
options for reducing methane emissions. The MAC is
presented as a schedule of emission reductions that
could be obtained at increasing values for methane.
The analysis considers the value of methane as the
sum of its market value as natural gas and a market
value for emission reductions represented in dollars
per metric ton of carbon equivalent (S/TCE).1 The
MAC is based on a discounted cash flow analysis of
the reduction options listed in Exhibit 3-7. The steps
in this analysis are described below.
Step 1: Characterize the Reduction Options. Each

Exhibit 3-7: Methane Emission Reduction Options
Natural Gas STAR Best Management Practices
^ Replace or repair high-bleed pneumatic devices with low-
bleed devices
^ Practice directed inspection and maintenance at
compressor stations
^ Install flash tanks on glycol dehydrators
s Practice directed inspection and maintenance of gate
stations and surface facilities
s Replace cast iron distribution mains with steel or plastic pipe
^ Replace cast iron distribution services pipe with steel or
plastic pipe
Natural Gas STAR Partner-Reported Opportunities
^ Practice directed inspection and maintenance at production
sites, processing sites, transmission pipelines, storage
wells, and liquid natural gas stations
s Practice enhanced directed inspection and maintenance,
i.e., more frequent survey and repair at production sites,
surface facilities, storage wells, offshore platforms, and
compressor stations
s Install electric starters on compressors
^ Install plunger lifts at production wells
s Use capture vessels for blowdowns at processing plants
and other facilities
s Install instrument air systems
^ Replace/repair chemical injection pumps
s Use portable evacuation compressors for pipeline repairs
^ Install catalytic converters on compressor engines
s Conduct electronic metering at gate stations
^ Install fuel gas retrofit systems on compressors to capture
otherwise vented fuel when compressors are taken off-line
^ Install static seal systems on reciprocating compressor rods
s Install dry seal systems on centrifugal compressors
^ Reduce circulation rates on glycol dehydrators
U.S. Environmental Protection Agency - September 1999
Natural Gas Systems 3-7
image:

option for reducing methane emissions is defined in
the following terms: the emission source to which it
applies; capital cost; the number of years that the
capital equipment lasts (typically 5 to 15 years de-
pending on the technology); annual operating and
maintenance costs; and its efficiency, i.e., achievable
emission reduction (up to 100 percent).
The options are matched to emission source definitions
in the emission inventory analysis (EPA/GRI, 1996).
In addition, in some cases the technologies and prac-
tices must be considered in proper order. For example,
when identifying potential emission reductions from
glycol dehydrates (which remove water during natural
gas processing), the option of reducing the glycol re-
circulation rate must be considered before the higher-
cost option of installing flash tanks. EPA assumes that
lower-cost options are implemented first, and so the
potential emission reductions from flash tanks depend
on the remaining volume of emissions after glycol re-
circulation rates have been reduced. In this way, rela-
tionships are defined so that incremental emission re-
ductions are analyzed for each option. In Appendix HI,
Exhibits m-5 and m-6 list the data used to define the
reduction options.
Options can be applied in different segments of the
industry and in different settings within each segment.
For example, replacing high-bleed pneumatic devices
with low-bleed pneumatic devices is applicable in the
production, transmission, and distribution sectors.
Within each sector, pneumatic devices can be applied
at sites with high or low volume throughput.
Step 2: Calculate Break-Even Gas Prices. A dis-
counted cash flow analysis is performed for each emis-
sion reduction option to estimate the price of natural
gas needed to offset the cost of the option for reducing
emissions. The analysis is conducted from the per-
spective of a private decision-maker in the natural gas
industry. Exhibit 3-8 shows the financial assumptions
used.
Step 3: Estimate Cost-Effective Emission Reduc-
tions for Each Option. The analysis compares the
needed break-even price for each methane reduction
option against the total value of the abated methane
which is the sum of the market value of gas and any
emission reduction values. If the value for the abated
methane (revenue) is equal to or greater than an
option's cost, that option is considered cost-effective.
Overall for the gas industry, about one-third of the
baseline emissions in 2010 can be cost-effectively
reduced at the market value of gas alone, that is, with
no additional carbon equivalent values or $0/TCE.
More reductions could be achieved with the addition
of higher carbon equivalent values. The estimates of
achievable reductions are option-specific, which
means they are also sector-specific.
Step 4: Generate the Marginal Abatement Curve.
The MAC is derived by rank ordering the cost-
effective individual opportunities at each combination
of gas price and carbon-equivalent emission reduction
values. The MAC can also be called a cost or supply
curve since it shows the cost per emission reduction
amount.
Exhibit 3-8: Financial Assumptions for Emission Reduction Analysis
Parameter
Description
Value of Gas Saved (1996 US$)
Discount Rate
Project Lifetime
Tax Rate
Capital Costs
Depreciation Period
Operating & Maintenance Costs
Wellhead: $2.17/MMBtu
Pipeline: $2.27/MMBtu
Distribution citygate: $3.27 / MMBtu
20 percent real
5 years
40 percent
Vary with equipment
Maximum 5 years for large investments; 1 year for small investments
Expressed as annual costs
3-8 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

2.3 Achievable Emission Reductions
and Marginal Abatement Curve
Exhibit 3-9 presents the cumulative emission reduc-
tions for selected values of carbon equivalent in 2000,
2010, and 2020. Exhibit 3-10 illustrates how the tech-
nologies and practices for reducing methane emissions
are applied to the natural gas industry. Given the ge-
neric nature of some of the options, e.g., directed in-
spection and maintenance (DI&M), the options can
have different cost and savings when applied to differ-
ent sectors of the industry, and within sectors to differ-
ent kinds of equipment.

Exhibit 3-9: Emission Reductions at Selected Values
of Carbon Equivalent in 2000,2010, and 2020 (MMTCE)

10.1
11.6
11.7
12.5
12.5
14.4
15.3
17.4
18.0
18.1
18.1
18.1
17.5
2010
37.9

10.8
12.4
12.5
13.3
13.3
15.3
16.3
18.4
19.2
19.2
19.2
19.3
18.6
2020
38.8

11.0
12.7
12.8
13.6
13.6
15.6
16.7
18.9
19.6
19.7
19.7
19.7
19.1
The cost effectiveness of an emission reduction option
is higher when applied to operations that have greater
opportunities to reduce emissions, i.e., components
with high throughputs and components that operate
continuously versus intermittently. For example,
among meter and regulating stations in the distribution
sector, DI&M is more cost-effective at larger stations
with greater flows of gas than at smaller stations.
The value of natural gas to the system operator also
affects the cost-effectiveness of an emission reduction
option. Broadly speaking, natural gas is least valuable
at the wellhead, i.e., the production sector, and most
valuable in the citygate market, i.e., the distribution
sector. The cost analysis recognizes this market char-
acteristic by using three sector-specific natural gas
prices: $2.17/MMBtu for wellhead, for $2.27/MMBtu
for pipeline, and $3.27/MMBtu for citygate.
While a limited number of options are considered,
applying these options to various segments of the in-
dustry (with corresponding different gas values) and to
different equipment types results in the evaluation of
118 opportunities to reduce emissions. Appendix ID,
Exhibit ni-7 provides a full list of these opportunities.
Exhibit 3-11 is derived from Exhibit 3-10 and presents
the MAC showing the additional amounts of abated
methane per increases in the price of natural gas—the
left vertical axis—and additional carbon equivalent
values ($/TCE)—the right vertical axis. The horizon-
tal axis is the amount of abated methane.
The energy market price, $2.43/MMBtu in 1996,
is aligned to $0/TCE. At $0/TCE, no additional
price signals exist from carbon equivalent values
to motivate emission reductions; all emission re-
ductions are due to a response to the price of natu-
ral gas. As a value is placed on avoided emissions
in terms of $/TCE, these values are added to the
energy market prices and allow for additional
emissions to clear the market. The "below-the-
line" amounts, with respect to $/TCE, illustrate
this dual price-signal market.
While the detailed analysis uses three different natural
gas prices to reflect the increasing value of natural gas
as it moves through the system, these three prices were
averaged into a single price of $2.43/MMBtu to sim-
plify Exhibit 3-10. Average natural gas prices were
also used to calculate carbon equivalent values and
cumulative emission reductions in Exhibit 3-10. Sec-
tor-specific natural gas prices were used to calculate
incremental emission reductions.
The MAC shows that approximately 30 percent of
baseline emissions can be cost-effectively reduced at
$2.43/MMBtu, the average market natural gas price.
At approximately $100/TCE, the MAC becomes ine-
lastic, that is, non-responsive to any increases in the
value for abated methane. Further reductions in meth-
ane emissions beyond about 50 percent of the baseline
are limited given the current set of options evaluated
(see below).
U.S. Environmental Protection Agency - September 1999
Natural Gas Systems 3-9
image:

Exhibit 3-10: Schedule of Selected Methane Emission Reduction Options in 2010
Option
Based on Sector-Specific
Natural Gas Prices
Break-Even Incremental
Gas Price Reductions
(MMTCE)
Based on Industry Average
Natural Gas Price
Value of
Carbon Cumulative
Equivalent Reductions
(StfCE) (MMTCE)
Label
on
MAC
Install fuel gas retrofit systems on compressors to capture $0.12
otherwise vented fuel when compressors are taken off-line
Replace high-bleed pneumatic devices with low-bleed $0.20
pneumatic devices (applies to high-bleed, continuous-bleed
pneumatic devices)
Reduce glycol circulation rates in dehydrators (not applicable $0.45
to Kimray pumps, this option applies to dehydrators with gas
assisted pumps but without flash tanks)
Practice directed inspection and maintenance at gate stations $0.75
and surface facilities
Replace high-bleed pneumatic devices with low-bleed $1.00
pneumatic devices (applies to high bleed, intermittent bleed
devices)
Install reciprocating compressor rod packing (Static-Pac) $1.81
Install dry seals on centrifugal compressors $1.91
Replace high-bleed pneumatic devices with low-bleed $2.50
pneumatic devices (applies to medium-bleed, intermittent-
bleed devices)
Install flash tank separators $3.42
Conduct electronic monitoring at large surface facilities only $4.84
Replace high-bleed pneumatic devices with compressed air $7.21
systemsa (applies to high-bleed, intermittent-bleed devices)
Replace high-bleed pneumatic devices with compressed air $9.68
systemsa (applies to high-bleed turbine devices)
Replace high-bleed pneumatic devices with compressed air $12.34
systemsa (applies to low-bleed, continuous-bleed devices)
Replace high-bleed pneumatic devices with compressed air $14.77
systemsa (applies to medium-bleed, intermittent-bleed
devices)
Replace higher-bleed pneumatic devices with lower-bleed $18.00
pneumatic devices (applies to low-bleed, intermittent-bleed
devices)
Replace high-bleed pneumatic devices with compressed air $20.81
systemsa (applies to medium-bleed turbine devices)
Practice directed inspection and maintenance at production $25.88
sites
0.42 ($21.06) 0.47

0.59 ($20.28) 0.78
0.28 ($18.03)
0.02
0.06
0.32

0.10

0.78

0.22

0.01
$9.01
$21.87
$43.46

$65.97

$90.15

$112.20

$141.56
3.76
0.14 ($15.26) 4.87

0.90 ($13.01) 7.13
0.06 ($5.61) 9.54
0.12 ($4.73) 9.93
0.68 $0.63 10.78
At

Dd
11.66
12.72
13.79

15.57

18.42

18.45

19.22
Et
Ft
Gt
Ht

IP
0.04 $167.11 19.26

0.02 $213.24 19.29
Dp
a This option is coordinated with the option of replacing high-bleed pneumatic devices with low-bleed pneumatic devices.
3-10 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 3-11: Marginal Abatement Curve for Methane Emissions from Natural Gas Systems in 2010
o%
Abated Methane (% of 2010 Baseline Emissions of 37.9 MMTCE)
10% 20% 30% 40%
50%
$27 -
^__
3 $24 -
1 $21 -
8 $18 "
~ $15 -
8
- $12 -
CO

CD ^
z
"5 $6 -
$0 -
/<tQ\

AtBt
($3) i
0 2

It
Bp J
IP /
It)
Axis set to weighted ^____>r
average natural gas market ^^
price of $2.43/MMBtu |p ^_^-/
^<*J*-T
~ ~~Ti —
Ct Dd Bp

4 6 8 10 12 14 16 18 2
Abated Methane (MMTCE)
LEGEND
Emission Reduction Options
A =
B =
C =
D =
E =
F =
G =
H =
1 =
fuel gas retrofit
replace higher-bleed pneumatic devices with lower-bleed devices
reduce glycol circulation rates in dehydrators
directed inspection and maintenance (DI&M)
reciprocating compressor rod packing (Static-Pac)
dry seals on reciprocating compressors
flash tank separators
electronic monitoring at large surface facilities
replace high-bleed pneumatic devices with compressed air
Natural Gas Industry Sectors
P =
t =
d =
Note
applied to the production sector
applied to the transmission sector
applied to the distribution sector
More than one point can have the same code because the same emission
reduction option can be applied to different components of a sector.

- $200
(O
CT)
CT)
$150 ~
'c
.3!
CO
3
0"
UJ
C
o
•E
CO
O
•5
CD
_3
CO
- $100
-$50
$0
2.4 Reduction Estimate
Uncertainties and Limitations
The two major areas of uncertainty related to the
MAC are: (1) an exclusive focus on currently avail-
able technologies; and (2) a lack of data on some of
the technologies currently used by industry. By fo-
cusing on options that have been reviewed by the
Natural Gas STAR Program, the study has not in-
cluded the possibility that other technologies will be
developed in the future that can further reduce meth-
ane emissions more efficiently In addition, data on
the PROs is incomplete in many cases. EPA's Natu-
ral Gas STAR Program has an ongoing effort to de-
velop more detailed analyses of these opportunities.
U.S. Environmental Protection Agency - September 1999
Natural Gas Systems 3-11
image:

3.0 References

API. 1997. API Basic Petroleum Data Book. Volume XVQ, No.2, American Petroleum Institute, Washington,
DC.
EIA. 1991. Petroleum Supply Annual 1990. Energy Information Administration, U.S. Department of Energy,
Washington, DC, DOE/EIA-03 40971 (91).
EIA. 1992. Petroleum Supply Annual 1991. Energy Information Administration, U.S. Department of Energy,
Washington, DC, DOE/EIA-03 40971 (92).
EIA. 1993. Petroleum Supply Annual 1992. Energy Information Administration, U.S. Department of Energy,
Washington, DC, DOE/EIA-03 40971 (93).
EIA. 1994. Petroleum Supply Annual 1993. Energy Information Administration, U.S. Department of Energy,
Washington, DC, DOE/EIA-03 40971 (94).
EIA. 1995. Petroleum Supply Annual 1994. Energy Information Administration, U.S. Department of Energy,
Washington, DC, DOE/EIA-03 40971 (95).
EIA. 1996. Petroleum Supply Annual 1995. Energy Information Administration, U.S. Department of Energy,
Washington, DC, DOE/EIA-03 40971 (96). (Available on the Internet at http://www.eia.doe.gov/oilgas/petrol-
eum/perframe.html.)
EIA. 1997. Petroleum Supply Annual 1996. Volume 1. Energy Information Administration, Washington, DC,
DOE/EIA-03 40971 (97). (Available on the Internet at http://www.eia.doe.gov/oilgas/petroleum/pet-
frame.html.)
EIA. 1998. Annual Energy Outlook 1998. Energy Information Administration, Department of Energy, Washing-
ton, DC, DOE/EIA-0383 (98). (Available on the Internet at ftp://ftp.eia.doe.gov/pub/pdf/multi.fuel/038398.pdf)
EIA. 1999. Natural Gas Monthly June 1999. Energy Information Administration, Department of Energy, Wash-
ington, DC, DOE/EIA-0130 (99/06). (Available on the Internet at http://www.eia.doe.gov/oilgas/naturalgas/nat-
frame.html.)
EPA. 1993. Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress,
Atmospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental Protection
Agency, Washington, DC, EPA 430-R-93-003. (Available on the Internet at http://www.epa.gov/ghginfo/re-
ports.htm.)
EPA. 1997a. Lessons Learned from Natural Gas STAR Partners - Directed Inspection and Maintenance at
Compressor Stations. Methane and Utilities Branch, Atmospheric Pollution Prevention Division, Office of Air
and Radiation, U.S. Environmental Protection Agency, Washington, DC, EPA 430-B-97-009. (Available on the
Internet at http://www.epa.gov/outreach/gasstar/direcprn.htm.)
EPA. 1997b. Lessons Learned from Natural Gas STAR Partners - Directed Inspection and Maintenance at Gate
Stations and Surface Facilities. Methane and Utilities Branch, Atmospheric Pollution Prevention Division, Of-
fice of Air and Radiation, U.S. Environmental Protection Agency, Washington, DC, EPA 430-B-97-009.
(Available on the Internet at http://www.epa.gov/outreach/gasstar/dircprn2.htm.)
3-12 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

EPA. 1997c. Lessons Learned from Natural Gas STAR Partners - Installation of Flash Tank Separators. Meth-
ane and Utilities Branch, Atmospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Envi-
ronmental Protection Agency, Washington, DC, EPA 430-B-97-008. (Available on the Internet at
http://www.epa.gov/outreach/gasstar/flashprn.htm.)
EPA. 1997d. Lessons Learned from Natural Gas STAR Partners - Options for Reducing Methane Emissions
from Pneumatic Devices in the Natural Gas Industry. Methane and Utilities Branch, Atmospheric Pollution
Prevention Division, Office of Air and Radiation, U.S. Environmental Protection Agency, Washington, DC,
Draft. (Available on the Internet at http://www.epa.gov/outreach/gasstar/pneuprn.htm.)
EPA. 1997e. Lessons Learned from Natural Gas STAR Partners - Reducing Emissions When Taking Compres-
sors Off-line. Methane and Utilities Branch, Atmospheric Pollution Prevention Division, Office of Air and Ra-
diation, U.S. Environmental Protection Agency, Washington, DC, EPA 430-B-97-010. (Available on the Inter-
net at http://www.epa.gov/outreach/gasstar/reducprn2.htm.)
EPA. 1997f. Lessons Learned from Natural Gas STAR Partners - Reducing Methane Emissions from Compres-
sor Rod Packing Systems. Methane and Utilities Branch, Atmospheric Pollution Prevention Division, Office of
Air and Radiation, U.S. Environmental Protection Agency, Washington, DC, EPA 430-B-97-010. (Available on
the Internet at http://www.epa.gov/outreach/gasstar/packprn.htm.)
EPA. 1997g. Lessons Learned from Natural Gas STAR Partners - Reducing the Glycol Circulation Rates in De-
hydrators. Methane and Utilities Branch, Atmospheric Pollution Prevention Division, Office of Air and Radia-
tion, U.S. Environmental Protection Agency, Washington, DC, EPA 430-B-97-014. (Available on the Internet at
http://www.epa.gov/outreach/gasstar/reducprn.htm.)
EPA. 1997h. Lessons Learned from Natural Gas STAR Partners - Replacing Wet Seals with Dry Seal s in Cen-
trifugal Compressors. Methane and Utilities Branch, Atmospheric Pollution Prevention Division, Office of Air
and Radiation, U.S. Environmental Protection Agency, Washington, DC, EPA 430-B-97-011. (Available on the
Internet at http://www.epa.gov/outreach/gasstar/sealsprn.htm.)
EPA. 1999. Inventory of Greenhouse Gas Emissions and Sinks: 1990-1997. Office of Policy, Planning, and
Evaluation, U.S. Environmental Protection Agency, Washington, DC; EPA 236-R-99-003. (Available on the
Internet at http://www.epa.gov/globalwarming/inventory/1999-inv.html.)
EPA/GRI. 1996. Methane Emissions from the Natural Gas Industry, Volume 1: Executive Summary. Prepared by
Harrison, M., T. Shires, J. Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Manage-
ment Research Laboratory, Air Pollution Prevention and Control Division, Research Triangle Park, NC, EPA-
600/R-96-080a.
EPA. Forthcoming. Methane Emissions from the U.S. Petroleum Industry. U.S. Environmental Protection
Agency, Washington, DC.
Tilkicioglu, B.H. and D.R. Winters. 1989. Annual Methane Emissions Estimates of the Natural Gas and Petro-
leum Systems in the U.S. Pipeline Systems Inc., Walnut Creek, CA.
U.S. Environmental Protection Agency - September 1999 Natural Gas Systems 3-13
image:

4.0 Explanatory Notes
Equation to calculate the equivalent gas price for a given value of carbon equivalent:

$ W6TCE 5.11MMTCE Tg 19.2 g CH4 ft3 \Q6 Btu
- x x-
TCE MMTCE TgCH4 1012 g ft3 CH. 1,000 Btu MMBtu MMBtu

Where: 5.73 MMTCE/Tg CH4 = 21 CO2/CH4 x (12 C / 44 CO2)
Density of CH4= 19.2 g/ft3
Btu content of CH4 = 1,000 Btu/ft3
3-14 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

4. Coal Mining
Summary
EPA estimates 1997 U.S. methane emissions from coal mines at 18.8 MMTCE (3.3 Tg), accounting for 10 percent
of total U.S. anthropogenic methane emissions (see Exhibit 4-1). Methane, formed during coalification, is stored
in coal seams and the surrounding strata and released during coal mining. Small amounts of methane are also re-
leased during the processing, transport, and storage of coal. Deeper coal seams contain much larger amounts of
methane than shallow seams. Accordingly, 65 percent of 1997 U.S. coal mine methane emissions were from un-
derground mines, even though underground mines accounted for only 39 percent of coal production.
EPA expects methane emissions from U.S. coal mines to increase faster than total U.S. coal production because
underground coal production - mined at increasingly greater depths - is projected to grow faster than surface pro-
duction. EPA estimates that methane emissions from coal mines will reach 28.0 MMTCE (4.9 Tg) by 2010, ex-
cluding possible Climate Change Action Plan (CCAP) reductions.
Methane emissions from coal mines can be reduced by methane recovery and use projects at underground mines
and by the oxidation of methane in ventilation air using new technologies. In 1997, 14 underground U.S. coal
mines recovered and used methane, achieving annual reductions of 4.6 MMTCE (0.8 Tg). Methane recovery
technologies include vertical wells drilled from the surface or boreholes drilled from inside the mine. Depending
on gas quality, methane recovered from underground mines may be sold to natural gas companies, used to gener-
ate electricity, used on-site as fuel for drying coal, or sold to nearby industrial or commercial facilities. The oxidi-
zation of coal mine ventilation air produces heat that can be used directly on-site or to produce electricity. Coal
mines in the U.S. do not currently use the oxidization technology, but it has been successfully demonstrated in
Great Britain.
The Coalbed Methane Outreach Program (CMOP), a voluntary EPA-industry partnership, has identified cost-
effective technologies and practices that could reduce projected 2010 U.S. coal mine emissions by 10.3 MMTCE
(1.8 Tg). EPA estimates that with a value of S20/TCE for abated methane added to the energy market price, U.S.
coal mine methane emissions could be reduced by 13.1 MMTCE (2.3 Tg) in 2010 as shown in Exhibit 4-1 below.

Exhibit 4-1: U.S. Methane Emissions from Coal Mining (MMTCE)
Percent of Methane Emissions in 1997
Other 4% _ Coal 10% (18.8 MMTCE)

Manure 10%
Emission Estimates and Reductions
MMTCE
@ 21 GWP
Total = 179.6 MMTCE
Source: EPA, 1999.
Cost-Effective Reductions
Baseline Emissions
Emission Levels at
Different S/TCE
$0
$20
$50
Remaining Emissions
1990
2000 2010 2020
Year
U.S. Environmental Protection Agency - September 1999
Coal Mining 4-1
image:

1.0 Methane Emissions from
Coal Mining

Methane and coal are formed together during coalifi-
cation, a process in which plant biomass is converted
by biological and geological forces into coal. Meth-
ane, stored within coal seams and the surrounding
strata, is liberated when pressure above or surrounding
a coalbed is reduced as a result of natural erosion,
faulting, or underground and surface mining. Small
amounts of methane also are liberated during the proc-
essing, storage, and transport of coal (referred to as
post-mining emissions). Abandoned underground coal
mines also contribute to the total amount of methane
liberated. This section summarizes the sources of
methane emissions from coal mining and details the
methodologies EPA uses to estimate current and future
methane emissions. The uncertainties associated with
these estimates are also presented.

1.1 Emission Characteristics
Emissions vary greatly by type of coal mine and min-
ing operations. This section describes the methane
emissions resulting from underground mines, surface
mines, post-mining operations, and abandoned mines.
Underground Mines. Deeper coal seams and sur-
rounding strata contain much larger volumes of meth-
ane than shallow coal seams. Geologic pressure,
which increases with depth, holds more methane in
place. Additionally, coal mined underground tends to
have a higher rank or carbon content, which correlates
to a higher methane content.
As a safety precaution, all underground coal mines
with detectable methane emissions must use ventila-
tion systems to ensure that methane concentrations
remain below one percent methane in the air of mine
workings.1 Methane is explosive at concentrations of
five percent or greater; thus for safety reasons mine
workings are operated at methane levels well below
the five percent threshold. Ventilation systems consist
of large fans that draw vast quantities of air into mine
workings to lower methane concentrations. The ven-
tilation air (extracted mine air containing low concen-
trations of methane) is then vented to the atmosphere
through ventilation shafts or bleeders.
Degasification systems, which are vertical wells drilled
from the surface or boreholes drilled within the mine,
remove methane contained in the coal or surrounding
strata before or after mining so that it does not enter
the mine. In contrast to ventilation systems, degasifi-
cation systems recover methane in high concentrations
ranging from 30 to over 90 percent, depending on the
degasification technique and coal geology.
Surface Mines. Surface mining is used to mine coal
located at shallow depths. Because the coalbed at sur-
face mines has little overburden, little pressure exists
to keep methane in the coal. Hence, coal at surface
mines tends to have a low methane content. As over-
burden is removed and the coal seam is exposed dur-
ing surface mining, methane is emitted directly to the
atmosphere. Although surface mines accounted for
over 61 percent of U.S. coal production in 1997, they
accounted for only an estimated 14 percent of methane
emissions.
Post-Mining Operations. Although a significant
amount of methane is released from the coal seam
during mining activities, some methane remains in the
coal after it is removed from the mine. This methane
may be emitted from the coal during processing, stor-
age, and transportation. The rate at which methane is
emitted during post-mining activities depends on the
characteristics of the coal and the way it is handled.
For instance, the highest releases occur when coal is
crushed, sized, and dried for industrial and utility uses.
Post-mining emissions can continue for months after
mining.
Abandoned Mines. Abandoned underground coal
mines are also a source of emissions. A few gas de-
velopers are recovering and using methane from aban-
doned mines. EPA is conducting further research into
this emission source. The current emission estimates
do not include emissions from abandoned mines.
The majority of methane emissions from coal mining
are from a few very large and gassy, i.e., high-emitting,
underground mines. The most gassy 125 (of 573) un-
derground coal mines account for over 97 percent of
underground methane liberated and about 65 percent
4-2 U.S. Methane Emissions 1990 - 2020: Inventories, Projections, and Opportunities for Reductions
image:

of methane liberated from all coal mines. Future
trends at these gassy mines, including the potential for
methane recovery and use, will have a large impact on
future emission levels.

1.2 Emission Estimation Method
Total methane emissions from coal mining are esti-
mated by summing methane emissions from under-
ground mines, surface mines, and post-mining activi-
ties.

1.2.1 Underground Mines
Methane liberated from coal mines includes emissions
from ventilation and degasification systems. Some
coal mines recover and use the methane collected from
degasification systems. Accordingly, this portion is
subtracted from total methane liberated to determine
methane emitted from underground mines.
Ventilation Systems. As mentioned previously, all
underground coal mines with detectable methane
emissions must use ventilation systems to ensure that
methane concentrations remain within safe levels.
Ventilation air typically contains methane concentra-
tions below one percent. The Mine Safety and Health
Administration (MSHA) measures methane emissions
from ventilation systems on a quarterly basis. Based
on these measurements, MSHA estimates average
daily methane emissions for each underground mine
(MSHA, 1998). For 1997, MSHA compiled the aver-
age daily methane emissions for all mines with detect-
able methane emissions into a single database, which
provides the basis for EPA's method of estimating
methane emissions from ventilation systems. First,
EPA estimates annual methane emissions for each
mine by multiplying the daily average by 365 days per
year. Next, total annual methane emissions from ven-
tilation systems were estimated by summing annual
ventilation emissions from individual mines.
The 1997 MSHA database includes methane emission
data for over 500 of the estimated 950 underground
mines in the United States. Those mines not listed in
the MSHA database do not have detectable levels of
methane and the emissions from this group of mines
are assumed to be negligible.
The methodology for estimating ventilation emissions
for the years prior to 1997 is slightly different than the
approach used for 1997 (see Exhibit 4-2). The 1997
MSHA database contains data for all mines with de-
tectable methane emissions, and, consequently, reports
on 100 percent of all ventilation emissions (MSHA,
1998). The MSHA data indicates that 97.8 percent of
ventilation emissions come from mines emitting at
least 0.1 million cubic feet per day (MMcf/d) and 94.1
percent of total emissions come from mines emitting at
least 0.5 MMcf/day. EPA uses these estimates to pro-
rate other data that are only representative of the mines
emitting methane above these levels. For example, the
estimates for 1990,1993, and 1994 are based on a U.S.
Bureau of Mines database that reported mine-specific
information for all mines emitting at least 0.1 MMcf/d
from their ventilation systems (DOI, 1995). Similarly,
Exhibit 4-2: Approach Used to Estimate Ventilation Emissions
Year Data/Method Used
1990 U.S. Bureau of Mines database listing all mines with ventilation emissions greater than 0.1 MMcf/d. EPA adjusted
total emissions to account for mines not included in the database. Assumed to account for 97.8% of total emis-
sions.
1991 Total underground coal mining emissions are estimated by using emission factors developed in 1990 and multiply-
ing those factors by 1991 coal production. Annual ventilation data are unavailable.
1992 Same approach as 1991, using 1992 coal production data.
1993 Same approach as 1990, using 1993 data. Assumed to account for 97.8% of total emissions.
1994 Same approach as 1990, using 1994 data. Assumed to account for 97.8% of total emissions.
1995 Obtained data from MSHA for all mines emitting at least 0.5 MMcf/d. Total was then adjusted to account for mines
for which data were not collected. Assumed to account for 94.1% of total emissions.
1996 Same approach as 1995, using 1996 data. Assumed to account for 94.1% of total emissions.
1997 MSHA database containing ventilation emissions for all underground coal mines with detectable emissions. As-
sumed to account for 100% of total.
U.S. Environmental Protection Agency - September 1999
Coal Mining 4-3
image:

the 1995 and 1996 data are based on MSHA mine-
specific ventilation emissions for all mines emitting at
least 0.5 MMcf/d. Due to a lack of mine-specific
emissions for 1991 and 1992, EPA estimates total un-
derground emissions by multiplying emission factors,
based on 1990 data, by coal production in the relevant
year.
Degasification Systems. In 1997, 24 U.S. coal
mines used degasification systems as a supplement to
their ventilation systems. In the U.S., the three most
common types of degasification methods are vertical
wells and horizontal boreholes, drilled in advance of
mining, and gob wells, drilled post mining. MSHA
reports the coal mines that are employing degasifica-
tion systems and the type of degasification systems
used. However, MSHA does not measure or report the
amount of methane liberated from degasification sys-
tems. Some U.S. coal mines provide EPA with infor-
mation about their emissions from degasification sys-
tems. In other cases, EPA estimates the amount of
methane liberated based on the type of degasification
system employed and mine characteristics. Exhibit 4-
3 shows U.S. coal mines employing degasification
systems, the type of system employed, and the esti-
mated amount of methane liberated and used.
Methane Used. Coal mines first began large scale
use of methane recovered from degasification systems
in the late 1970s. Since that time, methane recovery
and use has increased substantially. In 1997, 14 active
U.S. coal mines recovered and used or sold some or all
of the methane recovered by their degasification sys-
tems. For each of these mines, the quantity of methane
recovered is indicated in Exhibit 4-3. All of these ac-
tive mines sell methane to natural gas companies, since
methane is the principal component of natural gas. In
addition, one of the mines uses a portion of the meth-
Exhibit 4-3: Mines Employing Degasification Systems and Methane Use Projects in 1997
Mine Name
Buchanan No. 1
VP No. 8
VP No. 3
Blue Creek No. 7
Blue Creek No. 4
Blue Creek No. 3
Blue Creek No. 5
Pinnacle No. 50
Enlow Fork
Cumberland
Blacksville No. 2
Bailey
Oak Grove
Emerald No. 1
Federal No. 2
Loveridge No. 22
Dilworth
Robinson Run No.
Shoal Creek
McElroy
Shoemaker
Maple Meadow
Baker
Humphrey No. 7
Type of Degasification
System Used
Vertical, Horizontal, Gob
Vertical, Horizontal, Gob
Vertical, Horizontal, Gob
Vertical, Horizontal, Gob
Vertical, Horizontal, Gob
Vertical, Horizontal, Gob
Vertical, Horizontal, Gob
Vertical, Horizontal, Gob
Gob
Vertical, Horizontal, Gob
Horizontal, Gob
Gob
Vertical, Horizontal, Gob
Horizontal, Gob
Vertical, Horizontal, Gob
Horizontal, Gob
Gob
95 Horizontal, Gob
Vertical, Horizontal, Gob
Gob
Gob
Gob
Gob
Horizontal, Gob
Note: Although all of the mines listed above liberated methane in 1997,
Methane Liberated from Methane Used
Degas System (MMcf/year) (MMcf/year)
10,706
7,951
7,160
4,883
3,603
3,057
2,573
2,356
2,356
2,341
2,074
1,681
1,657
1,351
1,105
988
827
750
489
299
261
170
83
19
not all of them sold (used) the methane recovered
10,050
7,687
6,922
4,883
3,603
3,057
2,573
522
-
-
149
1,408
-
197
74
-
440
-
-
2

Source: MSHA, 1998; Mine Owners and Operators; State Petroleum and Natural Gas Agencies' Gas Sales Data; EPA, 1997a.
4-4 U.S. Methane Emissions 1990 - 2020: Inventories, Projections, and Opportunities for Reductions
image:

ane recovered from gob wells as fuel for an on-site
gas-fired coal dryer.
EPA estimates methane emissions avoided over time
for each U.S. recovery and use project. All of the
projects must report methane sales to state agencies
responsible for monitoring sales of natural gas. EPA
uses gas sales information reported by state agencies,
as well as information supplied by the coal mines, to
estimate the emission reductions for a particular year.
For coal mines that recover methane while mining, the
emission reductions are estimated as the reported gas
sales amount, adjusted for additional methane use in
gas-fired compressors.
For projects that recover methane in advance of min-
ing, estimating emission reductions is more complex.
For these projects, the emission reductions are counted
during the year in which the methane would otherwise
have been emitted, i.e., the year during which the well
is mined-through. The estimates are calculated based
on reported gas sales overtime, the portion of gas sales
coming from pre-mining degasification systems, and
the number of years in advance of mining that methane
is recovered. In some cases, the amount of gas sold or
used does not equal the amount liberated from degasi-
fication systems since part of the gas (up to 20 percent)
is simply vented (see Buchanan No. 1 in Exhibit 4-3
for one example). Currently, U.S. coal mines only use
methane that has been recovered from degasification
systems; however, in the future, U.S. coal mines could
potentially use methane from ventilation systems
(EPA, 1999b).2

7.2.2 Surface Mines
With the exception of a few field studies, methane
emissions from surface mines have not been measured
or estimated on a mine-specific basis. Methane emis-
sions from surface mines are estimated by multiplying
surface coal production for each coal basin by a basin-
specific emission factor. This factor is calculated by
multiplying the average methane in-situ content of
surface-mined coals by a factor of two to account for
methane contained in overlying or underlying coal
seams or other strata (EPA, 1993).
1.2.3 Post-Mining
Post-mining emissions are estimated by multiplying
basin-specific coal production for surface and under-
ground mines by a factor equal to 33 percent of the
average basin-specific in-situ content of the coal. Dif-
ferent average methane in-situ values are used for sur-
face mines and for underground mines (EPA, 1993).

1.2.4 Methodology for Estimating Future
Methane Liberated
To estimate the amount of methane that will be liber-
ated from coal production in the future, emission fac-
tors are multiplied by estimates of future coal produc-
tion. Emission factors have been developed for under-
ground mines, surface mines, and post-mining activi-
ties using 1997 data. These emission factors are then
multiplied by projected surface and underground coal
production levels to estimate future emissions. The
opening and closing of very gassy mines is also taken
into account since these changes significantly impact
overall emissions.3

1.3 Emission Estimates
This section presents estimated methane emissions
from coal mining from 1990 through 1997 and pro-
jected methane emissions through 2020.

1.3.1 Current Emissions and Trends
EPA estimates that the U.S. coal mining industry
emitted 18.8 MMTCE (3.3 Tg) of methane in 1997.
Mining in deep coal seams accounted for 65 percent of
methane emitted from coal mining in 1997, totaling
12.3 MMTCE (2.1 Tg). As shown in Exhibit 4-4,
methane emissions from coal mining declined from
1990 to 1997. This decline is due to three main fac-
tors. First, several gassy mines closed. These closures
are due in part to reduced demand for high-sulfur coal
in response to the Clean Air Act, which places strict
requirements on utilities to reduce their sulfur dioxide
emissions. Other mines closed due to declining coal
prices, while others simply reached the end of their
productive lifetime. Second, methane recovery and
use has increased significantly at underground mines;
EPA estimates that the amount of emissions avoided
increased from 1.6 MMTCE (0.3 Tg) in 1990 to 4.6
U.S. Environmental Protection Agency - September 1999
Coal Mining 4-5
image:

Exhibit 4-4: Methane Emissions from Coal Mining (MMTCE)
Activity
Underground Liberated
Underground Used
Net Underground Emissions
Surface Emissions
Post-Mining Emissions (Underground)
Post-Mining Emissions (Surface)
Total
1990
18.8
(1.6)
17.1
2.8
3.6
0.5
24.0
1991
18.1
(1.7)
16.4
2.6
3.4
0.4
22.8
1992
17.8
(2.1)
15.6
2.6
3.3
0.4
22.0
1993
16.0
(2.7)
13.3
2.5
3.0
0.4
19.2
1994
16.3
(3.2)
13.1
2.6
3.3
0.4
19.4
1995
17.7
(3.4)
14.2
2.4
3.3
0.4
20.3
1996
16.5
(3.8)
12.6
2.5
3.4
0.4
18.9
1997
16.8
(4.6)
12.3
2.6
3.5
0.4
18.8
Totals may not sum due to independent rounding.
Source: EPA, 1999a.
MMTCE (0.8 Tg) in 1997. Third, although total coal
production has increased, the percentage of total pro-
duction from underground mines has declined slightly.
Since underground production drives the total quantity
of methane liberated from coal mines, a decline in un-
derground production leads to a decline in methane
liberated. Appendix IV, Exhibit IV-1 provides histori-
cal and projected coal production data.

1.3.2 Future Emissions and Trends
Although the amount of methane liberated from coal
mining decreased over the past ten years, it is projected
to increase between 2000 and 2020, as Exhibit 4-5
indicates. This projection is based on forecasted levels
of coal production for both underground and surface
mines developed by the Energy Information Admini-
stration of the U.S. Department of Energy (EIA,
1998b). Estimates for 2000 may overstate under-
ground liberated emissions because of the closure of
some very gassy mines in 1998 and 1999 that have not
yet been taken into account.

1.4 Emission Estimate Uncertainties
The level of uncertainty associated with the emission
estimates varies for each of the emission sub-sources.
Underground Ventilation Systems. As described
above, methane emissions from ventilation systems are
based on quarterly measurements taken by MSHA at
individual mines. To the extent that the average of the
four quarterly measurements are not representative of
the true average at a given mine, average emissions at
a particular mine may be over- or under-estimated. In
addition, there are some limited uncertainties associ-
ated with the potential for measurement and reporting
errors.
Underground Degasification Systems. MSHA
reports which mines employ degasification systems
and the type of degasification system used, but the
agency does not record the quantity of methane liber-
ated from degasification systems. Although coal
mines are not required to publish methane liberation
data, some have provided it to EPA. For other mines,
EPA has estimated methane liberated based on the type
of degasification system employed. The uncertainty is
higher for those mines where EPA has estimated the
amount of methane liberated. However, EPA has more
data from gassy mines than from less gassy mines,
thereby reducing overall uncertainty.
Exhibit 4-5: Projected Baseline Methane Emissions from Coal Mining (MMTCE)
Activity 2000 2005 2010
Underground Liberated 17.1 19.3 20.4
Surface Liberated 2.8 2.8 2.9
Post-Mining Liberated (Underground) 3.5 4.0 4.2
Post-Mining Liberated (Surface) 0.5 0.5 0.5
Total 23.9 26.6 28.0
2015
21.5
3.0
4.5
0.5
29.5
2020
22.1
3.2
4.6
0.5
30.4
Totals may not sum due to independent rounding.
4-6 U.S. Methane Emissions 1990 - 2020: Inventories, Projections, and Opportunities for Reductions
image:

Methane Used at Underground Mines. As men-
tioned previously, all coal mines must report gas sales
to state agencies responsible for monitoring gas pro-
duction. While little uncertainty exists associated with
the reported gas sales, uncertainty exists associated
with the timing of the emission reductions. For coal
mines that recover methane in advance of mining, the
emission reduction is accounted for in the year in
which the coal seam is mined-through. Thus, without
knowing the exact timing of operations, there is un-
certainty associated with estimating the timing of
methane emissions avoided.
Surface Mines. Previous studies have indicated that
methane emissions from surface mines are likely to be
from one to three times greater than the in-situ content
of the coal. EPA's emission estimation methodology
assumes a value of two times the in-situ content of the
coal. Additional uncertainty is related to the estimated
average in-situ content for each basin.
Post-Mining Emissions. The uncertainties related
to post-mining emissions are similar to those for sur-
face mining emissions since a similar methodology is
used.
Uncertainties Associated with Future Emis-
sions. Future emissions are estimated for different
sub-sources by multiplying the average emissions per
ton of coal by projected future coal production levels.
Accordingly, two additional sources of uncertainty are
associated with the emission projections. First, the
average emissions per ton of coal may change over
time. Second, actual coal production levels may vary
from projected coal production levels.

2.0 Emission Reductions

This section surveys the technologies and practices
available for reducing coalbed methane emissions,
analyzes the cost of implementing three "model" proj-
ects that integrate these abatement options, and high-
lights which options are most achievable and cost-
effective through the development of a marginal
abatement curve (MAC).
2.1 Technologies for Reducing
Methane Emissions
Methane emissions from coal mines can be reduced
through the implementation of the methane recovery
and use projects described below.

2.1.1 Methane Recovery
Coal mines already employ a range of technologies for
recovering methane. These methods have been devel-
oped primarily for safety reasons, as a supplement to
ventilation systems. The major degasification tech-
niques used at U.S. coal mines are vertical wells, long-
hole and shorthole horizontal boreholes, and gob
wells. Exhibit 4-6 summarizes these technologies.
Vertical wells and in-mine horizontal boreholes, which
recover methane in advance of mining, produce nearly
pure methane. In contrast, gob wells, which recover
post-mining methane, may recover methane that has
been mixed with mine air. The quality of the gas de-
termines how it may be used.
Even where degasification systems are used, mines
still emit significant quantities of methane via ventila-
tion systems. Currently, technologies are in develop-
ment that catalytically oxidize the low concentrations
of methane in ventilation air producing usable thermal
heat as a by-product.

2.1.2 Methane Use
Methane recovered from degasification can be used
for the purposes described below.
Pipeline Injection. Natural gas companies may
purchase methane recovered from coal mines. Most
pipeline companies require gas with a methane
concentration of at least 97 percent. Since gas
recovered in advance of mining is nearly pure
methane, the only processing required may be
dehydration.
Gob gas, however, typically does not have a methane
concentration greater than 97 percent. U.S. coal mines
have developed different approaches for selling gob
gas to natural gas companies. Two major projects,
involving several coal mines in Alabama and Virginia,
recover methane from gob wells for sale to a natural
gas company. These coal mines have developed
U.S. Environmental Protection Agency - September 1999
Coal Mining 4-7
image:

Exhibit 4-6: Summary of Degasification Techniques
Method
Description
Methane Quality
Recovery
Efficiency3
Current Use in U.S.
Coal Mines
Vertical Wells
Gob Wells
Shorthole Horizon-
tal Boreholes

Longhole Horizontal
Boreholes

Cross-Measure
Boreholes
Drilled from the surface to coal
seam several years in advance
of mining.
Drilled from the surface to a few
feet above coal seam just prior
to mining.
Drilled from inside the mine to
degasify the coal seam just prior
to mining.
Drilled from inside the mine to
degasify the coal seam up to
several years before mining.
Drilled from inside the mine to
degasify surrounding rock
strata.
Recovers nearly pure
methane.

Recovers methane that
is sometimes contami-
nated with mine air.
Recovers nearly pure
methane.

Recovers nearly pure
methane.

Recovers methane that
is sometimes contami-
nated with mine air.
Up to 60% Used by at least 3 U.S.
mining companies in
about 11 mines.
Up to 50% Used by more than 21
U.S. mines.

Up to 20% Used by approximately
16 U.S. mines.

Up to 50% Used by over 10 U.S.
mines.

Up to 60% Not widely used in the
U.S.
3 Percent of total methane liberated that is recovered by degasification systems.
Source: EPA 1993,1997b, and 1999a; Expert comments.
strategies for controlling the amount of air entering the
gob and annually monitor gas quality in the well.
These methods are highly effective, especially during
the early stages of the productive lifetime of an indi-
vidual gob well.
Power Generation. Coal mine methane is also used
to generate electricity. In contrast to pipeline injection,
power generation does not require nearly pure meth-
ane. Accordingly, methane recovered from gob wells
may be used directly as fuel for a power generation
project. At present, only one active U.S. mine uses
recovered methane for power generation. In addition,
an abandoned coal mine in Ohio also recovers meth-
ane to generate electricity for a neighboring, active
coal mine4
The methane contained in ventilation air may be used
as combustion air in a turbine or internal combustion
(1C) engine. Currently, BHP has developed a power
generation project at the Appin and Tower coal mines
in Australia. The project involves using methane re-
covered from degasification systems as the main fuel
for 94 internal combustion engines rated at one MW
each. The project uses about 1.3 million cubic feet a
day of methane from ventilation air for this purpose
(EPA, 1998). The thermal energy recovered from the
oxidation of mine ventilation air can also be used in a
steam turbine to generate power (CANMET, 1998;
EPA, 1999b).
On-Site Use in a Thermal Coal Drying Facility. As
with power generation, a thermal dryer does not re-
quire pure methane. Currently, one coal mine in Vir-
ginia uses methane recovered from gob wells as fuel
for its thermal coal dryer. The thermal energy recov-
ered from the oxidation of mine ventilation air may
also be used for on-site drying operations.
Sale to Nearby Commercial or Industrial Facilities.
Another option is for coal mines to sell recovered
methane to nearby commercial or industrial facilities
with a high demand for natural gas. In the early 1990s,
gas recovered from coal mines in northern West Vir-
ginia was sold to a glass factory.

2.2 Cost Analysis of Emission
Reductions
EPA estimates potential emission reductions by evalu-
ating the ability of coal mines to cost-effectively build
and operate systems for recovering and using, or oxi-
dizing coal mine methane. EPA developed a MAC by
evaluating a range of energy prices along with a range
of emission reduction values. To determine cost-
effectiveness, EPA assumes that in addition to the
4-8 U.S. Methane Emissions 1990 - 2020: Inventories, Projections, and Opportunities for Reductions
image:

value of the energy produced, the mine owner/operator
receives income equal to the emission reduction value,
in $/ton of carbon equivalent ($/TCE), multiplied by
the amount of methane abated. The cost-effectiveness
of various options is estimated by comparing the value
of the energy and the emission reduction to the costs of
the system. The analysis is described below.
Step 1: Define the Current Underground Mines.
The analysis is performed on underground mines that
released at least 0.5 MMcf/d of methane from ventila-
tion systems in 1997. These 58 mines account for
about 94 percent of the methane released from U.S.
underground coal mining (MSHA, 1998). EPA char-
acterizes these mines in terms of coal basin, annual
coal production, methane released from the ventilation
system, existence of degasification system, methane
recovered by the degasification system (if one is pres-
ent), and mining method, i.e., long-wall or room and
pillar (EPA, 1999a). Where applicable, EPA estimates
the amount of methane recovered from existing de-
gasification systems. Using these data, EPA calculates
the amount of methane liberated per ton of coal mined.
EPA uses this liberation rate to estimate the amount of
gas available for recovery per ton of coal mined.
Step 2: Future Coal Production and Future Mines.
The Energy Information Administration estimates that
coal production will increase 16 percent by 2010 and
26 percent by 2020 relative to 1997 production (EIA,
1998a). See Appendix IV, Exhibit IV-1 for details.
Several characteristics of existing mines are assumed
to be the same for future mines, such as the methane
liberation rate per ton of coal. Therefore, the data set
of current mines is used to represent future mines, with
the exception that coal production at each mine is
scaled over time to correspond with projected changes
in underground U.S. coal production.
Step 3: Define "Model" Projects. The three types
of modeled recovery and use options analyzed are de-
scribed below and are also outlined in Exhibit 4-7.
> Option 1: Degasification and Pipeline Injec-
tion. Under this option, coal mines recover meth-
ane using vertical wells drilled five years in ad-
vance of mining, horizontal boreholes drilled one
year in advance of mining, and gob wells. All of
the gas recovered is sold to a pipeline. However,
only the high-quality gas produced during the
early stages of production from gob wells is as-
sumed to be sold due to the declining gas quality
over time. Methane recovery and use under this
option varies by basin. EPA assumes that the
technology to recover methane will improve over
time, leading to increased methane recovery. (See
Appendix IV, Exhibit IV-3 for a table of baseline
coal basin recovery efficiencies by year.)
> Option 2: Enhanced Degasification, Gas
Enrichment, and Pipeline Injection. This
option consists of gas recovery-and-use
incremental to Option 1. As in Option 1, EPA
assumes that coal mines recover methane using
vertical wells drilled five years in advance of
mining, horizontal boreholes drilled one year in
advance of mining, and gob wells drilled just prior
to mining and that gas is sold to a pipeline.
However, well spacing is tightened to increase
recovery efficiency. Additionally, mines invest in
enrichment technologies to enhance gob gas for
sale to natural gas companies. This combination
of tightened well spacing and gas enrichment
increases recovery efficiency by 20 percent above
what could have been achieved in Option 1.
Accordingly, Option 2 results in an additional 20
percent of gas that is available for pipeline sale.
Exhibit 4-7: Summary of Options Included in the U.S. Coal Mine Cost Analysis of Methane Emission Reductions
Option
Technologies
Assumptions
Degasification and Pipeline Injection
Enhanced Degasification, Gas Enrichment, and
Pipeline Injection

Catalytic Oxidation
All gas recovered from vertical wells and in-mine boreholes is
sold to a pipeline. Only high quality gob gas is sold to the pipe-
line.
Incremental to Option 1 with tightened well spacing and gas
enrichment. Recovery and use efficiency increases 20% over
Option 1.
Ventilation air is oxidized.
U.S. Environmental Protection Agency - September 1999
Coal Mining 4-9
image:

> Option 3: Catalytic Oxidation. Under this
option, coal mines eliminate methane in their
ventilation air using a catalytic oxidizer system
with a maximum capacity of 211,860 standard
cubic feet per minute (scf/min). The catalytic
oxidizer is estimated to oxidize up to 98 percent of
the methane that passes through the system. This
option can be implemented alone or in
conjunction with either of the other two options.
Although the heat produced by the system could
potentially be used to produce electricity, EPA did
not model this option due to the current lack of
operational data.
As shown in Appendix IV, Exhibit IV-4, the number of
wells required for any option is a function of the
amount of coal mined. The size and cost of other
equipment is driven by the amount of gas produced,
which depends on the amount of coal mined, the rate
of methane liberated per ton of coal produced, and the
recovery efficiency. For those mines that already have
degasification systems in place, these costs were con-
sidered sunk costs and were not included. Costs for
royalty payments are also not included.
Step 4: Calculate Break-Even Emission Reduction
Values. EPA performs a discounted cash flow analy-
sis to calculate the break-even emission reduction val-
ues for Options 1, 2, and 3 for each of the 58 mines in
2000, 2010, and 2020. Exhibit 4-8 shows the financial
assumptions. Costs are estimated for each mine using
these assumptions and the data defined in Step 3.
Project costs include only the incremental costs of
methane recovery and use. For example, to the extent
that a coal mine would already employ degasification
systems as part of normal mining practices, the cost of
drilling degasification wells or boreholes would not be
an incremental cost of a methane use project. EPA
estimates the revenue associated with the project as the
gas price times the amount of gas recovered and sold.
Step 5: Estimate Emission Reductions for Each
Option. The final step is to estimate cost-effective
national emission reductions for 2000, 2010, and 2020
within a range of gas prices and emission reduction
values in $/TCE. The base gas price is $2.53/MMBtu,
which is the average 1996 wellhead gas price in Ala-
bama, Indiana, Kentucky, and Ohio (EIA, 1997).5 The
additional emission reduction values, expressed in
$/TCE, range from $0/TCE to $200/TCE. The emis-
sion reduction values are translated into gas prices us-
ing a global warming potential (GWP) for methane of
21 and a methane energy content of l,OOOBtu/cubic
foot.6 If the break-even gas price for the mine is equal
to or less than the sum of the estimated gas price plus
the emission reduction value, the emissions can be
reduced cost-effectively For Options 1 and 2, EPA
estimates total emission reductions to be the sum of the
emissions that can be recovered cost-effectively at the
58 mines for each combination of gas price and emis-
sion reduction value. For Option 3, the break-even
emission reduction value is used to define the cases in
which this option is cost-effective. The emission re-
duction is applied to all underground mining ventila-
tion emissions that are calculated to be cost-effective.

2.3 Achievable Emission Reductions
and Marginal Abatement Curve
This analysis indicates that projected 2010 methane
emissions from U.S. coal mining can be reduced by
approximately 10.3 MMTCE (1.8 Tg) or 37 percent
below baseline projections by implementing currently
available technologies that are cost-effective at energy
market prices alone. Additional reduction options are
cost-effective at carbon equivalent values greater than
Exhibit 4-8: Financial Assumptions for
Parameters
Base Gas Price (1 996 US$)
Discount Rate
Project Lifetime
Tax Rate
Depreciation Period
Emission Reduction Analysis
Description
Options 1 and 2
$2.53/MMBtu
1 5 percent real
15 years
40 percent
15 years

Option 3
Not applicable
1 5 percent real
10 years
40 percent
5 years
4-10 U.S. Methane Emissions 1990 - 2020: Inventories, Projections, and Opportunities for Reductions
image:

$0/TCE. At S20/TCE, baseline emissions in 2010
from U.S. coal mines could be reduced by 13.1
MMTCE (2.3 Tg) or 47 percent.
Exhibit 4-9 presents the cumulative emission reduc-
tions at selected values of carbon equivalent in 2000,
2010, and 2020. Exhibit 4-10 provides a schedule of
selected emission reduction options for U.S. coal
mines for 2010. Option 1 has a lower break-even price
(lower cost) than Option 2 for any given mine. For
example, the break-even price for Option 1 at Bu-
chanan No. 1 is $0.54/MMBtu compared to
$1.63/MMBtu for Option 2. The same methane re-
duction option becomes cost-effective at different
break-even gas prices for different mines depending on
the incremental amount of methane that can be recov-
ered and used and the costs of methane recovery.

Exhibit 4-9: Emission Reductions at Selected Values
of Carbon Equivalent in 2000,2010, and 2020 (MMTCE)

7.1
8.0
8.2
16.8
16.8
16.8
16.8
16.8
16.8
16.8
16.8
16.8
7.1
2010
28.0

10.3
12.0
13.1
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
20.0
8.0
2020
30.4

12.5
13.9
15.3
21.7
21.7
21.7
21.7
21.7
21.7
21.7
21.7
21.7
8.7
Exhibit 4-11 presents the MAC which is derived by a
rank order of cost-effective individual opportunities at
each combination of gas price and carbon equivalent
emission reduction value, i.e., the cost per emission
reduction amount. The options shown in Exhibit 4-10
are labeled along the MAC at increasing break-even
prices through to $29.70/TCE.
At S29.70/TCE the catalytic oxidizer technology be-
comes cost-effective.7 The MAC becomes inelastic
because all methane emissions from ventilation air can
be reduced cost-effectively.8 The maximum amount of
emission reductions that can be achieved in 2010 as-
suming that the catalytic oxidizer is used is 20.0
MMTCE (3.5 Tg), or 71 percent of all methane liber-
ated from coal mines in the U.S., which is equivalent
to nearly all methane liberated from underground
mines in the U.S.

2.4 Reduction Estimate Uncertainties
and Limitations
Overall, this analysis is limited by the lack of detailed
site-specific assessments. Coal mine methane recov-
ery and use is greatly affected by site-specific condi-
tions. In general, average industry costs are used along
with conservative assumptions, so as not to overesti-
mate emission reductions that could be achieved.
The cost analysis only considers recovering methane
in advance of mining and selling the gas to natural gas
companies or oxidizing the methane in ventilation air.
For some smaller, less gassy mines, more limited re-
covery and use options may be cost-effective. Conse-
quently, the analysis is conservative in that additional
emission reduction opportunities may exist.
The analysis does not account for the incremental
benefits that will accrue from the installation of degasi-
fication systems, such as decreased ventilation costs or
increased productivity. Thus, the analysis is conserva-
tive to the extent that mines realize significant financial
benefits to their mining operations from the installation
of degasification projects.
Finally, uncertainty exists regarding the capital and
operation and maintenance (O&M) costs for the tech-
nologies. In particular, the catalytic oxidation technol-
ogy at coal mines is under development and limited
data are available to estimate costs. Consequently,
EPA bases the unit costs on an existing demonstration
project and assumes that the costs for catalytic oxida-
tion are proportional to the methane ventilated from
underground mines. Given that the cost is based on
only one project, EPA cannot assess the extent to
which the costs are being over- or under-estimated.
U.S. Environmental Protection Agency - September 1999
Coal Mining 4-11
image:

Exhibit 4-10: Schedule of Emission Reduction Options in 2010

Option
Used3
1
1
1
2
2
2
1
1
3
Sample Coal Mines
Representative
Mineb
Buchanan No. 1
Blue Creek No. 3
Oak Grove
Buchanan No. 1
Blue Creek No. 3
Sanborn Creek
McElroy
Maple Creek
All Underground Mines
Coal
Production
(Million Short
Tons/yr)
5.26
2.78
3.17
5.26
2.78
1.94
6.48
2.27
NAC
Break- Even
Gas Price
($/MMBtu)
$0.54
$0.60
$0.85
$1.63
$1.94
$3.33
$4.59
$5.63
$5.79
Value of
Carbon
Equivalent
($n"CE)
$(18.05)
$(17.51)
$(15.23)
$(8.14)
$(5.32)
$7.32
$18.78
$28.24
$29.70
Emission
Reductions
(MMTCE)
1.22
0.48
0.25
0.41
0.19
0.07
0.16
0.05
20.00
National
Incremental
Reductions
(MMTCE)
4.05
1.05
0.72
1.61
1.69
2.63
1.08
0.75
6.42
Cumulative
Reductions
(MMTCE)
4.05
5.10
5.82
7.42
9.12
11.74
12.83
13.58
20.00
Label
on MAC
A1
B1
C1
D2
E2
F2
G1
H1
13
Option 1 = Degasification and Pipeline Injection; Option 2 = Enhanced Degasification, Gas Enrichment, and Pipeline Injection; Option 3 =
Catalytic Oxidation of Ventilation Air Emissions.
This representative sample of coal mines existed in 1997. Although EPA uses data from these mines to model future emission reductions,
EPA does not evaluate whether any specific mine would be operating in 2010.
Not Applicable.
Exhibit 4-11: Marginal Abatement Curve for Methane Emissions from Coal Mining in 2010
Abated Methane (%of 2010 Baseline Emissions of 28.0 MMTCE)

0% 10% 20% 30% 40% 50% 60% 70% 80%

=
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$15 -

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price of $2.53'IVIVIBtu W1 f *\
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20
4-12 U.S. Methane Emissions 1990 - 2020: Inventories, Projections, and Opportunities for Reductions
image:

3.0 References

CANMET. 1998. Personal Communication with Richard Trottier of CANMET. July 6, 1998.
DOI. 1995. Underground Coal Mine Gas Emissions Data 1993. Bureau of Mines, U.S. Department of the Inte-
rior. Pittsburgh Research Center, Pittsburgh, PA.
EIA. 1997. Natural Gas Annual 1996. Office of Oil and Gas, Energy Information Administration, U.S. Depart-
ment of Energy, Washington, DC, DOE/EIA-0131(96). (Available on the Internet at http://www.eia.doe.gov/
oil_gas/natural^as/nat_frame.html.)
EIA. 1998a. Annual Energy Review 1997. Energy Information Administration, U.S. Department of Energy,
Washington, DC. July 1998.
EIA. 1998b. Annual Energy Outlook 1998. Energy Information Administration, U.S. Department of Energy,
Washington, DC. July 1998.
EPA. 1993. Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress.
Office of Air and Radiation, U.S. Environmental Protection Agency, Washington, DC, EPA 430-R-93-003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports.htm)
EPA. 1997a. Identifying Opportunities for Methane Recovery at U.S. Coal Mines: Draft Profiles of Selected
Gassy Underground Mines. Office of Air and Radiation, U.S. Environmental Protection Agency, Washington,
DC,EPA430-R-97-020.
EPA. 1997b. Technical and Economic Assessment of Potential to Upgrade Gob Gas to Pipeline Quality. Office
of Air and Radiation, U.S. Environmental Protection Agency, Washington, DC, EPA 430-R-97-012.
EPA. 1998. Marketing Your Coal Mine Methane Resource. Conference Proceedings, U.S. Environmental Pro-
tection Agency. Pittsburgh, PA.
EPA. 1999a. Inventory of Greenhouse Gas Emissions and Sinks 1990-1997. Office of Policy, Planning, and
Evaluation, U.S. Environmental Protection Agency, Washington, DC; EPA 236-R-99-003. (Available on the
Internet at http://www.epa.gov/globalwarming/inventory/1999-inv.html.)
EPA. 1999b. Technical and Economic Assessment: Mitigation of Methane Emissions from Coal Mine Ventilation
Air. Office of Air and Radiation, U.S. Environmental Protection Agency, Washington, DC.
MSHA. 1998. Methane Emissions Data for Mines with Detectable Emissions in 1997. U.S. Mine Safety and
Health Administration, Arlington, VA.
U.S. Environmental Protection Agency -September 1999 Coal Mining 4-13
image:

4.0 Explanatory Notes

1 The Mine Safety and Health Administration (MSHA) records coal mine methane readings with concentrations
greater than 50 ppm (parts per million) methane. Readings below this threshold are considered non-detectable.

2 One coal mine in Australia has recovered and used ventilation air as a fuel for a series of internal combustion en-
gine-driven generators. In addition, a British coal mine reported successful demonstration of oxidation technology.

3 In 1998 and 1999, the VP No. 3, VP No. 8, and Blue Creek No. 3 mines closed. These closures will significantly reduce total
U.S. methane emissions.

4 Additionally, coal mines in Australia, China, Germany, and the United Kingdom have successfully developed
power generation projects at active underground mines.

5 Gas prices in key coal mine states, e.g., West Virginia, Virginia, Pennsylvania, and Illinois, are assumed to fall
within the range of prices represented by the states with available data.

6 Equation to calculate the equivalent gas price for a given value of carbon equivalent:

$ 106 TCE 5.11MMTCE Tg 19.2 g CH4 ft3 W6 Btu $
TCE MMTCE TgCH^ 1012 g ft3 CH. 1,000 Btu MMBtu MMBtu

Where: 5.73 MMTCE/Tg CH4 = 21 CO2/CH4 x (12 C / 44 CO2)
Density of CH4= 19.2 g/ft3
Btu content of CH4 = 1,000 Btu/ft3

7 Although at this price, the catalytic oxidizer technology is cost-effective, a mine may still need to implement Op-
tions 1 and 2 for technical and safety reasons.

8 At the less gassy mines, the low methane concentration make serf-sustained oxidation impossible and supplemental
gas is required to combust the gas. Because EPA's analysis is based on the more gassy mines, the assumption that
all methane emissions from ventilation air can be reduced cost-effectively does not have a major impact on the
MAC results.
4-14 U.S. Methane Emissions 1990 - 2020: Inventories, Projections, and Opportunities for Reductions
image:

5. Livestock Manure Management
Summary

EPA estimates 1997 U.S. methane emissions from livestock manure management at 17.0 MMTCE (3.0 Tg),
which accounts for ten percent of total 1997 U.S. methane emissions (EPA, 1999). The majority of methane emis-
sions come from large swine (hog) and dairy farms that manage manure as a liquid. As shown below in Exhibit 5-
1, EPA expects U.S. methane emissions from livestock manure to grow by over 25 percent from 2000 to 2020,
from 18.4 to 26.4 MMTCE (3.2 to 4.6 Tg). This increase in methane emissions is primarily due to the increasing
use of liquid and slurry manure management systems which generate methane. This use is associated with the
trend toward larger farms with higher, more concentrated numbers of animals.
Cost-effective technologies are available that can stem this emission growth by recovering methane and using it as
an energy source. These technologies, commonly referred to as anaerobic digesters, decompose manure in a con-
trolled environment and recover methane produced from the manure. The recovered methane can fuel engine-
generators to produce electricity or boilers to produce heat and hot water. Digesters also reduce foul odor and can
reduce the risk of ground- and surface-water pollution. In addition, digesters are practical and often cost-effective
for most large dairy and swine farms, especially those located in warm climates.
The AgSTAR Program, a voluntary EPA-industry partnership initiated under the Climate Change Action Plan
(CCAP), has identified cost-effective opportunities that could reduce methane emissions by up to 3.2 MMTCE
(0.6 Tg) in 2010 at current energy market prices, i.e., $0/ton of carbon equivalent ($0/TCE), as Exhibit 5-1 shows.
Greater methane reductions could be achieved with the addition of higher values per TCE. For example, EPAs
analysis shows that in 2010, emission reductions could reach 4.5 MMTCE (0.8 Tg) with a value of $20/TCE
added to the energy market price (in 1996 US$).
Exhibit 5-1: U.S. Methane Emissions from Livestock Manure Management (MMTCE)
Percent of Methane Emissions in 1997

Manure 10% (17.0 MMTCE)
Coal 10%
Other 4% ^^
MMTCE
@ 21 GWP
Enteric
Fermentation
19%
Landfills 37%

Total = 179.6 MMTCE
Source: EPA, 1999.
29--5
23 — 4
17 — 3
11 --2
6 --1
Emission Estimates and Reductions
Tg
CH
Cost-Effective Reductions
Baseline Emissions
Emission Levels at
Different S/TCE
1990
2000 2010
Year
2020
U.S. Environmental Protection Agency - September 1999
Livestock Manure Management 5-1
image:

1.0 Methane Emissions from
Manure Management

Livestock manure is primarily composed of organic
material and water. Anaerobic and facultative bacteria
decompose the organic material under anaerobic con-
ditions. The end products of anaerobic decomposition
are methane, carbon dioxide, and stabilized organic
material. Several biological and chemical factors in-
fluence methane generation from manure. These fac-
tors are discussed below. In addition, this section dis-
cusses the methods EPA uses to estimate methane
emissions from manure in the U.S. Current and future
emissions are presented as well as a discussion on the
uncertainties associated with the emission estimates.

1.1 Emission Characteristics
The methane production potential of manure depends
on the specific composition of the manure, which in
turn depends on the composition and digestibility of
the animal diet. The amount of methane produced
during decomposition is also influenced by the climate
and the manner in which the manure is managed. The
management system determines key factors that affect
methane production, including contact with oxygen,
water content, pH, and nutrient availability. Climate
factors include temperature and rainfall. Optimal con-
ditions for methane production include an anaerobic,
water-based environment, a high level of nutrients for
bacterial growth, a neutral pH (close to 7.0), warm
temperatures, and a moist climate.
Before the 1970s, methane emissions from manure
were minimal because the majority of livestock farms
in the U.S. were small operations where animals de-
posited manure in pastures and corrals. Manure man-
agement normally consisted of scraping and collecting
the manure and later applying it as fertilizer to crop-
lands, allowing manure to remain in constant contact
with air.
Much larger dairy and swine farms have become more
common since 1990. To collect and store manure at
these large farms, farmers often use liquid manure
management systems that use water to flush or clean
alleyways or pits where the manure is excreted. This
liquid and manure mixture is generally collected and
stored until it can be applied to cropland using irriga-
tion equipment. While in storage, the submerged ma-
nure generates methane.
Dairy and swine farms are typically the only livestock
farms where liquid and slurry manure systems are
used. Beef, poultry, and other livestock farms gener-
ally do not use liquid manure systems, and therefore
produce much less methane.
The key factors affecting methane production from
livestock manure are the quantity of manure produced,
manure characteristics, the manure management sys-
tem, and climate.
> Quantity of Manure Production. Manure
production varies by animal type and is pro-
portional to the animal's weight. A typical
1,400-pound dairy cow produces about 112
pounds of manure per day and a typical 180-
pound hog produces about 11 pounds of ma-
nure per day.
> Manure Characteristics. Methane genera-
tion takes place in the volatile solids portion
(VS) of the manure.1 The VS portion depends
on livestock type and diet. Animal type and
diet also affect the quantity of methane that
can be produced per kilogram of VS in the
manure. This quantity is commonly referred
to as "B0" and is measured in units of cubic
meters of methane per kilogram of VS (m3
QrL/kg VS). Manure characteristics are
summarized in Appendix V, Exhibit V-l.
> Manure Management System. Methane
production also depends on the type of ma-
nure management system used. U.S. produc-
ers use "dry" and "liquid" manure manage-
ment systems. Dry systems include solid stor-
age, dry feedlots, deep pit stacks, and daily
spreading of the manure. In addition, unman-
aged manure from animals grazing on pasture
falls into this category. Liquid management
systems use water to facilitate manure han-
dling. These systems, known as liquid/slurry
systems, use concrete tanks and lagoons to
store flushed and scraped manure. The la-
5-2 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

goons are typically earthen structures such as
ponds or lagoons. Both types of systems store
manure until it is applied to cropland and cre-
ate the ideal anaerobic environment for meth-
ane production. Up to half of the manure on
large dairy farms and virtually all the manure
on large hog farms is managed using liquid
systems.
> Climate. Manure decomposes more rapidly
when climate conditions encourage bacterial
growth. For anaerobic manure systems, warm
temperatures increase methane generation.
Therefore, methane generation is greater in
warm states such as California and Florida
and lower in cool states such as Minnesota
and Wisconsin. For dry manure management
systems, wet climates have higher emissions
than arid climates, though emissions in either
case are very low.
The characteristics of manure systems and climate can
be represented in a methane conversion factor (MCF)
which quantifies the potential for emitting methane
and has a range from zero to one. Manure systems and
climates that promote methane production have an
MCF near one. Conditions that do not promote meth-
ane production have an MCF near zero. Appendix V,
Exhibit V-2 lists MCFs for different climates and ma-
nure management systems.

1.2 Emission Estimation Method
EPA estimates emissions by determining the amount
and type of manure produced, the systems used to
manage the manure, and the climate (Safley, et al.,
1992; EPA, 1993).
As shown in the equation in Exhibit 5-2, the national
emission estimate is the sum of emission estimates
developed at the state level, for the relevant animal
types and manure management systems. A detailed
description of the emission estimation method is con-
tained in Appendix V, Section V. 1.
By developing state-level estimates, key differences in
annual manure characteristics, populations, manure
management practices and climate are incorporated
into the analysis. EPA estimates manure production
Exhibit 5-2: Methane Emissions Equation
States Animal Manure
Types Mgmt.
System
CH4= Z Z Z
i J k
BO
CH4
Manure^
MFlj
ljk
BO
= Methane generated (ftVday)
= Total manure produced by animal
type j in state /' (Ib/day)
= Percent of manure managed by sys-
tem k for animal type j in state /'
= Percent of manure that is volatile
solids for animal type j in state /
= Maximum methane potential of ma-
nure for animal type j (ft3/lb of vola-
tile solids)
= Methane conversion factor for system
k in state /'
using livestock population data published by the U.S.
Department of Agriculture (USDA). The American
Society of Agriculture Engineers (ASAE) publishes
volatile solid production rates each year. The current
estimates use VS rates from the 1995 ASAE Standards
(ASAE, 1995).
Methane generation potentials (B0) were determined
through laboratory research performed by Hashimoto
and Steed (1992), and referenced in EPA (1993). EPA
determined state-specific emission factors for dairy
cows and swine based on the farm size distribution in
each state (USDC, 1995) and system MCF values de-
veloped by Safley, et al. (1992) and Hashimoto and
Steed (1992). Emission factors for other livestock
types were also determined by Safley, et al. (1992)
based on climate and manure management system us-
age.
The calculation of dairy cow emissions also includes a
dry matter intake (Dmi) scaling factor to account for
the improvement in the rations fed to dairy cows.
Dairy farmers use more digestible feed in the diets of
dairy cows to increase productivity. The improved
feed also increases the proportion of VS available in
U.S. Environmental Protection Agency - September 1999
Livestock Manure Management 5-3
image:

the manure, increasing methane production on a per-
animal basis.

1.3 Emission Estimates
EPA estimates current and historic emissions using
reported data and available research. Future emissions
are estimated using projections of livestock production
and changes in manure management practices. The
emissions estimates are described in detail in the fol-
lowing sub-sections.

1.3.1 Current Emissions and Trends
EPA estimates that 1997 U.S. methane emissions from
livestock manure were 17.0 million metric tons of car-
bon equivalent (MMTCE) or 3.0 Teragrams (Tg), as
shown in Exhibit 5-3 (EPA, 1999). Total emissions
from manure have increased each year from 1990 to
1995. Emissions declined in 1996, but displayed a
sharp rise in 1997, mostly due to fluctuations in the
swine populations. Steady shifts in the dairy cattle
population toward states with higher use of liquid sys-
tems caused an increase in emissions from this live-
stock category, despite a decrease in the dairy cattle
population.

1.3.2 Future Emissions and Trends
EPA estimates future emissions using forecasts for two
key factors: animal production and manure manage-
ment practices.
> Future Livestock Production. Forecasts of
livestock production are based on trends and
projections of consumption of dairy and meat
products, agricultural policy, and im-
ports/exports. USDA forecasts short-term
trends, usually six to seven years in the future.
Taking into account improvements in produc-
tivity, EPA uses these USDA production fore-
casts to project long-term trends in livestock
population to the year 2020. EPA assumes
that as consumption of livestock products in-
creases, the extent of intensive livestock pro-
duction will increase to meet that demand. A
16 percent increase in swine production and a
17 percent increase in milk production is ex-
pected between 1997 and 2010.
Future Manure Management Practices.
Future manure management practices have a
large impact on emission estimates. Because
forecasts of future livestock manure manage-
ment practices are not available in existing lit-
erature, EPA projects usage of manure man-
agement systems based on field experience. If
the use of confined and intensive livestock
production systems continues to increase, the
use of liquid-based manure management sys-
tems will probably increase. Such systems are
often preferred for large-scale livestock pro-
duction systems because they allow for the ef-
ficient collection, storage, and, in some cases,
treatment, of livestock manure. This shift to-
wards liquid systems would result in signifi-
cant increases in emissions because liquid
systems produce considerably more methane
than dry systems. However, due to increasing
pressure to minimize water quality and odor
problems, some producers are evaluating dry
Exhibit 5-3: Methane Emissions from Livestock
Animal Type
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
TOTAL
1990
4.3
1.1
7.8
0.0
0.0
1.5
0.2
14.9
1991
4.3
1.2
8.2
0.0
0.0
1.5
0.2
15.4
Manure Management (MMTCE)
1992
4.4
1.2
8.6
0.0
0.0
1.6
0.2
16.0
1993
4.4
1.2
8.6
0.0
0.0
1.6
0.2
16.1
1994
4.5
1.2
9.1
0.0
0.0
1.7
0.2
16.7
1995
4.6
1.3
9.2
0.0
0.0
1.7
0.2
16.9
1996
4.5
1.3
8.9
0.0
0.0
1.7
0.2
16.6
1997
4.6
1.3
9.3
0.0
0.0
1.8
0.2
17.0
Totals may not sum due to independent rounding.
Source: EPA, 1999.
5-4 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

systems and the use of grass-based dairies that
may result in fewer liquid-based manure man-
agement systems.
Over the last twenty years the share of the dairy
cattle population on large farms (greater than 500
cows) has risen from 8 to 18 percent. The propor-
tion of hogs raised on large farms (greater than
1,000 hogs) has increased from 31 percent in 1987
to 50 percent in 1992, directly corresponding with
increased use of liquid manure management sys-
tems (USDC, 1995). In 1995, 33 percent of all
cattle manure and 75 percent of all hog manure
was managed with liquid systems (EPA, 1993).
The next statistical data point will be available
when the next Census of Agriculture is available.
Field experience indicates that the use of liquid
systems is continuing to increase, perhaps at an
accelerating rate.
The two key factors contributing to emission growth
are increased manure volumes due to the expected
growth in animal populations needed to meet forecast
production levels, shown in Exhibit 5-4, and the
growing use of liquid management systems. Based on
livestock production projections, EPA estimates that
manure production in 2020 will be seven percent
higher than in 1990, and that 20 percent more manure
will be managed in liquid systems. Exhibit 5-5 pres-
ents U.S. manure methane emission estimates for 2000
through 2020.

1.4 Emission Estimate Uncertainties
The major sources of uncertainty in the emissions es-
timates are manure management practice data and pre-
dictions of future production. These uncertainties are
described in detail below.

1.4.1 Current Emissions
Uncertainties are associated with both the activity lev-
els and the emission factors used in the emission
analysis. The estimates of current animal populations
and manure characteristics (volatile solids) are fairly
certain because these data are regularly revisited and
updated by reliable sources, e.g., USDA and ASAE.
The methane production potential values, determined
Exhibit 5-4: U,
Animal Type
Dairy Cattle
Beef Cattle
Swine
Poultry
Sheep
Goats
Horses
.S. Livestock Production
Units
Billion Ibs milk/yr
Billion Ibs/yr
Billion Ibs/yr
Billion Ibs/yr
1,000 head
1,000 head
1,000 head
Source: 1995-2005 values are based on USDA,

1995
156
28
19
5
8,886
2,495
6,000

2000
166
28
19
5
7,998
2,495
6,325
1996; 2010-2020 are values from

2005
178
28
21
5
7,998
2,495
6,642
extrapolation

2010
185
29
22
5
7,977
2,495
6,970
analysis.

2015
193
30
23
5
7,939
2,495
7,314

2020
201
30
24
5
7,872
2,495
7,661

Exhibit 5-5: Projected Baseline Methane Emissions from Livestock Manure Management (MMTCE)
Animal Type
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
TOTAL
2000
5.2
1.2
9.9
<0.1
<0.1
1.8
0.2
18.4
2005
5.8
1.2
11.1
<0.1
<0.1
2.0
0.2
20.4
2010
6.3
1.2
12.3
<0.1
< 0.1
2.2
0.2
22.3
2015
6.9
1.3
13.5
<0.1
< 0.1
2.4
0.2
24.3
2020
7.5
1.3
14.8
<0.1
<0.1
2.6
0.2
26.4
Totals may not sum due to independent rounding.
U.S. Environmental Protection Agency - September 1999
Livestock Manure Management 5-5
image:

through laboratory research, are also relatively reliable.
Greater uncertainty exists in the estimates of the
amount of manure managed by each type of manure
system and the estimates of the MCFs for each manure
system. To best characterize the dairy and swine in-
dustry trends described in Section 1.3.1, farm-size dis-
tributions should be updated each year. Currently,
however, farm-size distribution data are published by
USDA every five years, which contributes to uncer-
tainty in this factor. Finally, methane production be-
tween similar systems can vary widely. The research
used to develop MCFs was extensive but does not
completely account for this variability.
The uncertainties in manure methane emission esti-
mates can be reduced by improving the characteriza-
tion of livestock manure management practices and by
improving the estimated MCFs. The current analysis
utilizes published farm-size distribution data to reduce
uncertainty in state manure management practices on
dairy and swine farms. The next Census of Agricul-
ture will be released in late 1999. Using this updated
data will further improve this characterization. MCF
estimates can be improved through additional field
measurements over the complete range of practices
and temperatures under which manure is managed.
Measurements should focus on liquid systems because
they are the largest source of manure methane emis-
sions.

1.4.2 Future Emissions
In addition to the uncertainties associated with current
emission estimates, future emission estimates are sub-
ject to uncertainty stemming from forecasts of future
dairy and meat product consumption and productivity.
USDA forecasts of future trends are the most reliable
projections that exist for the U.S. However, many un-
predictable factors can influence future production,
such as global market changes that impact the demand
for livestock exports.
Although the analysis of future emissions includes the
impacts of increased dry matter intake by dairy cows,
it does not include the impacts of changing feed for
other livestock. These impacts may contribute to an
underestimation of emissions for some livestock types,
particularly for swine, where recent data shows a trend
towards feed that increases VS production.
Additionally, accurately predicting future manure
management system usage is difficult. In the near
term, liquid system usage will continue to increase as
the dairy and swine industries move toward larger pro-
duction scales. However, potential regulations in live-
stock waste management may affect future manage-
ment strategies. The extent and direction of the impact
of such regulations is not yet known.
The uncertainty in estimates of future emissions will
be reduced by improving forecasts of manure man-
agement characterization, based on on-going monitor-
ing of trends and regulation. In addition, developing
more accurate projections of livestock product demand
and consumption will reduce the uncertainty of the
future estimates.

2.0 Emission Reductions

EPA evaluates cost-effective methane emission reduc-
tion opportunities at livestock facilities. The analysis
and discussion in this section focus on methane recov-
ery and utilization. It first describes the technologies,
costs, and potential benefits of methane recovery and
utilization. These costs and benefits are then translated
into emission reduction opportunities at various values
of methane, which are used to construct a schedule of
emission reductions and a marginal abatement curve
(MAC).

2.1 Technologies for Reducing
Methane Emissions
Reduction strategies focus on emissions from liquid
systems because these systems have large methane
emissions that can be feasibly reduced or avoided.
Two general options exist for reducing emissions from
liquid systems: (1) switching from liquid management
systems to dry systems; or (2) recovering methane and
utilizing it to produce electricity, heat or hot water.
Only the option of recovering and utilizing methane is
used in the cost analysis. Each option is described
below.
5-6 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
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2.1.1 Switch to Dry Manure
Management
Methane production is minimal in dry, aerobic condi-
tions. Switching from liquid to dry management sys-
tems would reduce methane emissions produced in
liquid systems. However, such a shift is largely im-
practical for both environmental impact and process
design reasons. Dry manure management systems can
lead to significant surface and ground water pollution.
In addition, the liquid manure management systems at
large dairy and swine farms are integrated with the
overall production process. Switching to dry systems
would require a fundamental shift in the entire pro-
duction scheme. For these reasons, EPA does not con-
sider this option in this analysis.

2.1.2 Recover and Use Methane to
Produce Energy
With the use of liquid-based systems, the only feasible
method to reduce emissions is to recover the methane
before it is emitted into the air. Methane recovery in-
volves capturing and collecting the methane produced
in the manure management system. This recovered
methane can be flared or used to produce heat or elec-
tricity.
Electricity generation for on-farm use can be a cost-
effective way to reduce farm operating costs. The
generated electricity displaces purchased electricity,
and the excess heat from the engine displaces propane.
The economic feasibility of electricity generation usu-
ally depends on the farm's ability to use the electricity
generated on-site. Selling the electricity to an electric
power company has seldom been economically bene-
ficial because the utility buy-back rates are generally
very low.
Three methane recovery technologies are available.
Covered anaerobic digesters may be used at farms that
have engineered ponds for holding liquid waste.
Complete-mix and plug-flow digesters can be used for
other farms. Each system attempts to maximize meth-
ane generation from the manure, collect the methane,
and use it to produce electricity and hot water. Meth-
ane recovery also significantly reduces odor, which is
important for many facilities.
Covered Anaerobic Digesters. Covered an-
aerobic digesters are the simplest type of re-
covery system and can be used at dairy or
swine farms in temperate or warm climates.
Larger dairies and swine farms often use la-
goons as part of their manure-management
systems. Recovering methane usually re-
quires an additional lagoon (primary lagoon),
a cover, and a collection system. The primary
lagoon is covered for methane generation and
a secondary lagoon is used for wastewater
storage. Manure flows into the primary la-
goon where it decomposes and generates
methane. The methane is collected under the
cover and used to power an engine-generator.
Waste heat from the generator is used for on-
farm heating needs. The digested wastewater
flows into the secondary lagoon where it is
stored until it can be applied to cropland. A
two-lagoon system also provides added envi-
ronmental benefits over a single-lagoon sys-
tem, including odor and pathogen reduction.
This technology is often preferred in warmer
climates and/or when manure must be flushed
as part of on-going operations.
Complete-Mix Digesters. Complete-mix di-
gesters are tanks into which manure and water
are added regularly. As new water and ma-
nure are flushed into the tank, an equal
amount of digested material is removed and
transferred to a lagooon. The digesters are
mixed mechanically on an intermittent basis to
ensure uniform digestion. The average reten-
tion time for wastewater in the tanks is 15 to
20 days. As manure decomposes, methane is
generated and collected. To speed decompo-
sition, waste heat from the utilization equip-
ment heats the digesters. Complete-mix di-
gesters can provide digestion and methane
production at both dairy and swine farms.
However, they are not recommended for use
at dairy farms because of the high solids con-
tent of dairy manure. Complete-mix digesters
are typically used at swine farms in colder
U.S. Environmental Protection Agency - September 1999
Livestock Manure Management 5-7
image:

climates where lagoons cannot produce meth-
ane year-round.
> Plug-Flow Digesters. Plug-flow digesters
consist of a long concrete-lined tank where
manure flows through in batches, or "plugs."
As new manure is added daily at the front of
the digesters, an equal amount of digested
manure is pushed out the far end. One day's
manure plug takes about 15 to 20 days to
travel the length of the digesters. Methane is
generated during the process and then col-
lected. To speed decomposition, waste heat
from the utilization equipment heats the di-
gester tank. Plug-flow digesters are almost
always used at dairies where the consistency
of the cow manure allows for the formation of
"plugs." Swine manure, as excreted, does not
possess the proper density to use in this sys-
tem. Manure digestion using plug-flow di-
gesters also provides the added benefit of di-
gested solids, which can be recovered and
used as a soil amendment or bedding for
cows. Plug-flow digesters are generally used
in colder climates or at newly constructed
dairies instead of lagoons.
Estimating methane recovery from plug-flow di-
gesters requires information on management sys-
tem usage at farms that may decide to install these
digesters. Plug-flow digesters generally receive
manure as excreted, which is usually scraped into
the digester. It is uncertain whether this scraped
manure would otherwise be handled using a liquid
system or simply stored or spread as a solid. Be-
cause manure handled as a solid produces very
little methane, the emission reduction from plug-
flow digesters can be minimal, depending on cli-
mate and waste systems. Additionally, it is also
unclear whether dairies that currently flush ma-
nure to lagoons would switch to scraping manure
to plug-flow digesters. Moreover, a significant
portion of the revenue from plug-flow digester
systems can arise from sales of the separated fiber.
This opportunity is dependent on securing buyers
for the fiber and negotiating a reasonable price.
Due to these complexities, emission reductions
from dairies are only estimated for covered la-
goons.

2.2 Cost Analysis of Emission
Reductions
The cost analysis for reducing manure methane emis-
sions focuses on methane recovery because it is gener-
ally the most feasible and cost-effective reduction op-
tion. Emission reductions are estimated to be the
amount of manure methane that can be cost-effectively
recovered at a variety of energy prices and emission
reduction values.
The costs of methane recovery vary depending on the
recovery and utilization option chosen and the size of
the farm. The general costs of recovery and electricity
generation are explained below and summarized in
Exhibit 5-6. Exhibit 5-7 summarizes the break-even or
cost-effective herd size for different digester projects.
Exhibit 5-6: Methane Recovery System Costs
Digester Capital Costs
Digester Type
Covered Digester
Dairy
Swine
Complete-mix Digester
Dairy
Swine
Cost ($/animal)
$245 - $380/cow
$130-$220/hog
$235-$410/cow
$130-$260/hog
Engine-Generator Capital Costs
Digester Type
Lagoon Digester
Complete-mix Digester
Cost ($/kW)
$750/kW
$750/kW
Source: EPA, 1997a.
Exhibit 5-7: Economics of Digester Projects
Break-Even Cost
Herd Size
Dairy
Covered Lagoon
Complete-mix
Hog
Covered Lagoon
Complete-mix

500
700

1,350
2,500

$150,000
$188,000

$193,000
$332,000
Annual
Revenue

$29,000
$34,000

$39,000
$62,200
Source: EPA, 1997a.
5-8 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
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EPA developed average costs based on actual project
costs from recent AgSTAR charter farm projects as
well as the AgSTAR FarmWare software, a project
analysis software tool used to assess project feasibil-
ity. A detailed cost breakdown is shown in Appendix
V, Exhibits V-3, V-4 and V-5.

2.2.1 Costs
EPA estimates the opportunity to reduce emissions by
evaluating the potential for farmers to cost-effectively
build and operate anaerobic digester technologies
(ADTs). The costs associated with installing and run-
ning the ADTs vary by system type and the volume of
manure that is to be handled. General costs for each
technology are described below.
Covered Anaerobic Digester. The cost of this system
includes the cost of the primary lagoon, its cover, and
the gas piping needed to deliver the gas to the utiliza-
tion equipment. For dairy farms, these costs are be-
tween $245 and $380 per milk cow. For large hog
farms (more than 1,000 head), the range is between
$130 and $220 per hog.
Complete-Mix Digester. The cost of the complete-
mix digester includes the cost of the vessel, the heat
exchange system, the mixing system, and the gas pip-
ing needed to deliver the gas to the utilization equip-
ment. For dairy farms, the digester costs between
$235 and $410 per milk cow. For large hog farms, the
digester costs range between $130 and $260 per hog.
Engine-Generator. Engine-generators are sized for
the available gas flow from the methane recovery sys-
tem. The cost of an engine-generator on a dairy farm
is roughly between $160 and $260 per cow. For large
hog farms, the engine-generator costs between $32 and
$90 per hog. An engine-generator for an anaerobic
digester, including the heat exchanger, costs about
$750/kW.

2.2.2 Cost Analysis Methodology
To develop a MAC, EPA evaluated a range of energy
prices along with a range of emission reduction values
in $/ton of carbon equivalent ($/TCE) where manure
methane emissions can be cost-effectively reduced.
EPA conducted the analysis for the years 2000, 2010,
and 2020. The steps in the analysis follow below.
Step 1: Define a "Model" Facility. Typical methane
recovery and utilization systems are defined for each
of the two ADTs used in the analysis:
> Covered Anaerobic Digester. EPA defines a
covered anaerobic digester system to include a
new lagoon, a cover for the lagoon, a methane
collection system, a gas transmission and han-
dling system, and an engine-generator. The
sizes of these components are estimated based
on the amount of manure handled, the hy-
draulic retention time for the manure required
in the specific climate area analyzed, and the
amount of gas produced. A new lagoon is as-
sumed to be required in all cases even though
some farms may have lagoons that are suitable
for covering. This assumption makes the
analysis conservative since it includes a cost
that may not be necessary.
> Complete-Mix Digester. A complete-mix
digester is defined to include the digester ves-
sel and cover, digester heating system, meth-
ane collection system, gas transmission and
handling system, and an engine-generator.
The sizes of these components are estimated
based on the amount of manure handled. The
system is designed to produce a 20-day hy-
draulic retention time for the manure. No
costs are included for modifying the existing
manure management practices to conform to
the minimal water requirements of the com-
plete-mix digester.
Step 2: Define "Model" Manure Management
Practices. The amount of manure managed in liquid
management systems, such as lagoons, determines
methane emissions and methane reduction potential.
Although manure management practices can vary
significantly, the large dairy and swine farms that
generate most of the methane emissions and mitigation
opportunities will generally use liquid or slurry
systems. The "model" manure management practices
chosen for dairy and swine farms are described for
each below.
U.S. Environmental Protection Agency - September 1999
Livestock Manure Management 5-9
image:

> Dairy Farms. Generally, large dairy farms
either flush or scrape their manure to a central
location, such as a lagoon or digester. Al-
though the proportion of dairy manure that is
handled in liquid systems for a given farm can
vary, this analysis uses a national average of
55 percent (EPA, 1997b). For this analysis,
EPA assumes that covered lagoon systems on
dairy farms can accept the entire 55 percent of
manure that can be handled in liquid systems.
> Swine Farms. Most large swine farms use
liquid flush systems to manage their manure.
For this analysis, EPA assumes that all of the
manure produced on large swine farms can be
managed in covered lagoon or complete-mix
digester systems to produce methane.
Step 3: Develop the Unit Costs for the System
Components. Unit costs for the system components
are taken from FarmWare (EPA, 1997a), the EPA-
distributed software tool used to assess project
feasibility. The component unit costs and total costs
for typical projects are shown in Appendix V, Exhibits
V-3 to V-5. As shown in the exhibits in the appendix,
covered lagoon systems are typically less costly to
build than complete-mix and plug-flow digester
systems.
Step 4: Determine Farmer Revenue. The revenues
accruing to the farmer are the value of the energy pro-
duced and the value of the emission reduction. Elec-
tricity production is estimated based on the amount of
biogas produced and the heat rate of the engine
(14,000 Btu/kWh). Biogas production at each facility
is modeled using FarmWare (EPA, 1997a) and ac-
counts for the amount and composition of the manure
managed in the lagoon, the lagoon hydraulic retention
time, the lagoon loading rate, and the impact of local
temperature on the methane production rate for lagoon
systems. Biogas is assumed to be 60 percent methane
and 40 percent carbon dioxide and other trace con-
stituents. The value of the electricity is estimated us-
ing published state average commercial electricity
rates (EIA, 1997). These rates are reduced by
$0.02/kiloWatt-hour (kWh) to reflect electricity prices
that farmers would likely be able to negotiate with
their local energy providers. This conservative rate
reduction is adopted even though the electricity pro-
duced displaces on-site electricity usage; experience
has shown that inter-connect charges and demand
charges can limit the amount of the energy savings
realized.
In addition to the electricity produced, the annual value
of heat recovery from the engine exhaust is estimated
at $8/cow at dairy farms. This energy is used for
heating wash water and other heating needs and dis-
places natural gas or propane. This value is a conser-
vative estimate based on actual projects at dairy farms.
The heat recovery value for swine farms is estimated
to be 20 percent of the value of the electricity pro-
duced, based on current projects. This heat is needed
for farrowing facilities and nurseries, with less re-
quired for growing and finishing operations.
The value of the emission reduction is estimated as the
amount of methane recovered times $/TCE. For mod-
eling purposes, the emission reduction value is con-
verted into an added value to the electricity produced
and modeled as additional savings realized by the
farmer. This conversion is performed using methane's
Global Warming Potential (GWP) of 21, the heat rate
of the engine, and the energy content of methane
(1,000 Btu/cubic foot)4
Step 5: Determine Break-Even Farm Sizes. EPA
conducted a discounted cash flow analysis for each
climate division in the U.S. to estimate the smallest
farm size in each climate division that can cost-
effectively install and operate each of the three ADTs.5
Swine and dairy farms are analyzed separately and
farm size is measured in terms of the number of head
of milk-producing cows for dairies and the total num-
ber of animals for swine farms. As the number of head
increases, the sizes and costs of the system compo-
nents also increase. The amount of manure managed
and biogas produced also increase with farm size.
The break-even farm size is the smallest number of
animals required to achieve a net present value (NPV)
of zero using a real discount rate of ten percent over a
ten year project life.6 The electricity value in each
climate division is the state average minus $0.02/kWh
as discussed above in Step 4. The break-even farm
5-10 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

size is estimated for each climate division for each
combination of electricity price and emission reduction
value. At higher electricity prices and emission reduc-
tion values, smaller farms can implement the projects
cost-effectively
Step 6: Estimate Emission Reductions. EPA esti-
mates national emission reductions separately for
swine and dairy farms for each combination of elec-
tricity price and emission reduction value using the
break-even farm sizes from Step 5. First, break-even
farm sizes are assigned to each county by mapping the
counties into the climate divisions. Second, the por-
tion of dairy cows and swine on farms that are greater
than the break-even size is estimated for each county
using the distribution of farm sizes in each county
(USDC, 1995). For covered digesters and complete-
mix digesters, emission reductions for each county are
estimated as the emissions from this portion of the
dairy cows and swine.
EPA estimates the total emission reductions from
swine farms by combining the results for the covered
digesters and the complete-mix digesters. In each
county, the preferred technology, based on a break-
even electricity price, is assumed to be implemented.
The emission reductions using the preferred system are
summed across all the counties and divided by the total
national emissions to estimate the percent emission
reductions.
Step 7: Estimate Reductions from Odor Control
As discussed above, some swine farms cover their
lagoons to reduce odor. U.S. EPA's AgSTAR program
has identified odor control as the principal motivation
behind several recently installed covered digesters and
one heated mix digester on swine farms. The reasons
driving these installations are site-specific and are not
reflected in the analysis. As a result, the analysis as-
sumes that a minimum emission reduction of
ten percent of total emissions will be achieved at all
swine farms for odor control purposes. However, the
costs of these emission reductions are not included in
the analysis.
Step 8: Generate the Marginal Abatement Curve.
The MAC displays cost-effective methane abatement
at each combination of electricity price and carbon
equivalent value for dairy and swine facilities. Exhibit
5-8 presents methane abatement at each of the addi-
tional emission reduction values.

2.3 Achievable Emission Reductions
and Marginal Abatement Curve
EPA uses the above analysis to estimate the amount of
methane emissions that could be reduced cost effec-
tively at various energy values and avoided emissions
in terms of carbon equivalent.
Exhibit 5-8 presents cost-effective emission reductions
at various prices per TCE for 2010. The electricity
prices shown are a weighted average of the state aver-
age retail electricity prices based on livestock popula-
tion. Exhibit 5-9 and Exhibit 5-10 present the MACs
for dairy cows and swine manure management sys-
tems, respectively. These curves are derived from the
values shown in Exhibit 5-8. The MACs can also be
referred to as cost or supply curves because they indi-
cate the marginal cost per emission reduction amount.
Energy market prices are aligned with $0/TCE given
that this price represents no additional values for
abated methane and where all price signals come only
from the respective energy markets. The "below-the-
line" reduction amounts, with respect to $0/TCE, il-
lustrate this dual price-signal market, i.e., energy mar-
ket prices and emission reduction values. Exhibit 5-11
presents total methane abatement at each value of car-
bon equivalent based on total manure methane emis-
sions. These values are presented in the MAC pro-
vided in Exhibit 5-12. Exhibit 5-13 presents the cu-
mulative emission reductions at selected values of car-
bon equivalent in 2000,2010, and 2020.
In general, at higher methane values of $/TCE, invest-
ing in manure management systems for smaller farms
becomes more cost-effective, i.e., the break-even farm
size decreases. The break-even farm size varies by
climate zone (temperature, precipitation) and size dis-
tribution of the farm by state. To simplify the presen-
tation, EPA summed the total achievable reductions
(from all farms) at each value of carbon equivalent to
generate the MAC. This process was done separately
for dairy cattle and swine.
U.S. Environmental Protection Agency - September 1999
Livestock Manure Management 5-11
image:

Exhibit 5-8: Schedule of Methane Emission Reductions for Dairy and Swine Manure Management in 2010
Label Value of Carbon
on Equivalent
Manure Type MAC
DAIRY COW: A
B
C
D
E
F
G
H
I
J
K
L
M
N
0
SWINE: A
B
C
D
E
F
G
H
I
J
K
L
M
N
0
($H"CE)
($30)
($20)
($10)
$0
$10
$20
$30
$40
$50
$75
$100
$125
$150
$175
$200
($30)
($20)
($10)
$0
$10
$20
$30
$40
$50
$75
$100
$125
$150
$175
$200
Electricity Price
with Additional Average
Value of Carbon Break-Even
Equivalent Farm Size
($/kWh)
$0.04
$0.06
$0.07
$0.09
$0.10
$0.12
$0.14
$0.15
$0.17
$0.21
$0.25
$0.29
$0.34
$0.38
$0.42
$0.02
$0.03
$0.05
$0.07
$0.08
$0.10
$0.12
$0.13
$0.15
$0.19
$0.23
$0.27
$0.32
$0.36
$0.40
(# of head)
1,025
1,134
828
753
787
733
654
575
521
414
294
219
172
140
114
> 20,000
> 20,000
5,112
5,120
3,906
4,339
2,990
1,932
1,390
821
602
510
500
500
500
Incremental
Reductions
(MMTCE)
0.23
0.52
0.33
0.88
0.29
0.27
0.19
0.17
0.14
0.37
0.38
0.31
0.26
0.24
0.21
1.23
0.00
0.00
0.00
0.00
0.79
2.25
1.36
1.10
3.52
0.51
0.25
0.01
0.00
0.00
Cumulative
Reductions
(MMTCE)
0.23
0.75
1.07
1.95
2.24
2.51
2.70
2.87
3.01
3.38
3.76
4.07
4.33
4.57
4.78
1.23
1.23
1.23
1.23
1.23
2.02
4.28
5.63
6.74
10.26
10.77
11.03
11.04
11.04
11.04
Cumulative
Reductions
(% of base)
4%
14%
20%
36%
41%
46%
49%
52%
55%
62%
68%
74%
79%
83%
87%
10%
10%
10%
10%
10%
16%
35%
46%
55%
83%
88%
90%
90%
90%
90%
At $0/TCE, approximately $0.09/kWh for dairy and
$0.07/kWh for swine, manure methane emissions
could be reduced by about 3.2 MMTCE (dairy
(2.0 MMTCE) plus swine (1.2 MMTCE)) or 0.6 Tg
(dairy (0.3 Tg) plus swine (0.2 Tg)). At an additional
carbon value equivalent of S20/TCE, 2010 methane
emissions from livestock manure could be reduced by
4.5 MMTCE (dairy (2.5 MMTCE) plus swine (2.0
MMTCE)) or about 0.8 Tg (dairy (0.4 Tg) plus swine
(0.4 Tg)). Dairy emission reductions are relatively
elastic throughout the series. Swine emission reduc-
tions, which include a ten percent reduction minimum
(explained in Section 2.2.2), remain at this level (1.2
MMTCE) until $20/TCE, when reductions begin to
increase. At and above S125/TCE, however, swine
manure emission reductions reach an upper bound at
about 11.0 MMTCE (1.9 Tg).
5-12 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 5-9: Marginal Abatement Curve for Methane Emissions from Dairy Cow Manure Management in 2010
Abated Methane (%of Dairy Cow Baseline Emissions of 5.5 MMTCE)
0%
20%
40%
60%
•s
0)
ED
•5
8
$0.50
$0.45
$0.40
$0.35
$0.30
$0.25
$0.20
$0.15
$0.10
$0.05
$0.00
Axis set to weighted
average energy market
price: $0.09/kWh
80%
100%
$250
234
Abated Methane (MMTCE)
$200

$150

$100

$50

($50)
nr
o
S
<o
iff
o
.a
nj
O
•5
o
_D
cu
Exhibit 5-10: Marginal Abatement Curve for Methane Emissions from Swine Manure Management in 2010
0%
Abated Methane (%of Swine Baseline Emissions of 12.3 MMTCE)
20% 40% 60% 80%
$0.50
$0.45
| $0.40 -
^ $0.35 -
to
I, $0.30
| $0.25 -
8 $0.20
ED
•5 $0.15
| $0.10
Q_
$0.05 -
$0.00
Axis set to
weighted average
energy market
price: $0.07/kWh
468
Abated Methane (MMTCE)
10
nr
o
.1
iff
I
re
o
•5
o
_
re
12
U.S. Environmental Protection Agency - September 1999
Livestock Manure Management 5-13
image:

Exhibit 5-11: Schedule of Total Methane Emission Reductions in 2010
Value of Carbon
Equivalent
($/TCE)
($30)
($20)
($10)
$0
$10
$20
$30
$40
$50
$75
$100
$125
$150
$175
$200
Incremental
Reductions
(MMTCE)
1.45
0.52
0.33
0.88
0.29
1.06
2.44
1.52
1.25
3.89
0.89
0.57
0.27
0.24
0.21
Cumulative
Reductions
(MMTCE)
1.45
1.98
2.30
3.18
3.47
4.53
6.98
8.50
9.75
13.64
14.53
15.10
15.37
15.61
15.82
Cumulative
Reductions
(% of base)
7%
9%
10%
14%
16%
20%
31%
38%
44%
61%
65%
68%
69%
70%
71%
Exhibit 5-12: Marginal Abatement Curve for Methane Emissions from All Livestock Manure Management in 2010
0%
Abated Methane (% of Total Baseline Emissions of 22.3 MMTCE)

20% 40% 60% 80% 100%
nr
o
to
o>
o>
$250
$200
+T $150

_0>
TO

= $100

iff

•£ $50
TO
O
0)

3
$0
($50)
6 8 10 12 14 16

Abated Methane (MMTCE)
18 20 22
5-14 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 5-13: Emission Reductions at Selected Values
of Carbon Equivalent in 2000,2010, and 2020 (MMTCE)

2.5
2.7
3.6
5.6
6.8
7.8
10.9
11.6
12.1
12.3
12.5
12.6
5.7
2010
22.3

3.2
3.5
4.5
7.0
8.5
9.7
13.6
14.5
15.1
15.4
15.6
15.8
6.5
2020
26.4

3.9
4.2
5.5
8.5
10.3
11.8
16.5
17.6
18.3
18.6
18.9
19.2
7.3
2.4 Reduction Estimate
Uncertainties and
Limitations

Uncertainties in the emission reduction estimates are
due to the assumptions used to develop the model farm
facility, the variability in the value of the methane re-
covered, and the incorporation of trends.
Site-specific factors influence the costs and benefits of
recovering and using methane from livestock manure.
In particular, the methane recovery system must be
built so that it is completely integrated with the farm's
manure management system. Costs and benefits of
methane recovery are well documented. However, this
analysis relies on a single model facility and is not
customized to individual farm requirements. Thus, it
may under- or over-estimate the cost-effectiveness of
emission reductions at individual farms. Additionally,
system prices are subject to change based on fluctua-
tions in the construction industry, as well as the cost of
biogas-fueled engine-generators. Such changes cannot
be accurately predicted. Moreover, the analysis does
not take into account possible changes in capital and
operation and maintenance (O&M) expenses for emis-
sion reduction estimates in future years (2010, 2020).
This may overstate benefits in the projection period.
For low emission reduction values the principal benefit
of the anaerobic digester technology is the value of the
electricity produced, which depends on the rate negoti-
ated with the farm's electric service provider. Conse-
quently, the value is considered uncertain in this analy-
sis. Because this value can vary as often as the amount
of projects, accurately determining electricity values
for this analysis is difficult. EPA estimates the values
as $0.02/kWh below state average commercial elec-
tricity prices. However, under restructuring of the
electric power industry, a premium value may be real-
ized for electricity produced from renewable resources
such as methane. The potential impact of this pre-
mium is not included in this analysis.
Some recent projects at swine farms have been initi-
ated primarily to reduce odor rather than produce
electricity. These projects may signal a trend towards
the growing importance of odor reduction at these fa-
cilities. Once quantified, including odor reduction
benefits in the analysis will improve the estimates of
emission reduction.
As discussed before, EPA estimates the emission re-
duction potential based in part on the distribution of
dairy and swine farm sizes as measured by numbers of
head. The farm size distribution data divide the farm
sizes into a relatively small number of categories. The
precision of the estimates would be improved with
more refined farm size categories.
Finally, the distribution of farm sizes has changed sig-
nificantly over the past ten years, particularly in the
swine industry. Since 1992, the most recent year for
which farm size data are available, the trend toward
larger dairy and swine farms has continued. Conse-
quently, the analysis likely under-estimates the portion
of livestock on large farms as of 1997. Because emis-
sions can more easily be reduced on large farms, the
analysis also likely under-estimates the emission re-
duction potential. Given that the trend toward larger
farms is expected to continue, applying this MAC to
future baseline emissions likely under-estimates cost-
effective emission reductions.
U.S. Environmental Protection Agency - September 1999
Livestock Manure Management 5-15
image:

3.0 References

ASAE. 1995. ASAE Standards 1995, 42nd Edition. American Society of Agricultural Engineers, St. Joseph, MI.
EIA. 1997. Electric Sales and Revenue 1996. Energy Information Administration, U.S. Department of Energy,
Washington, DC, DOE/EIA-0540(96).
EPA. 1993. Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress.
Office of Air and Radiation, U.S. Environmental Protection Agency, Washington, DC, EPA 430-R-93-003.
(Available on the Internet at http://www.epa.gov/ghginfo/reports.htm.)
EPA. 1997a. AgSTAR FarmWare Software, Version 2.0. FarmWare User's Manual. (Available on the Internet at
http ://www.epa.gov/methane/home .nsf/pages/agstar.)
EPA. 1997b. AgSTAR Handbook A Manual For Developing Biogas Systems at Commercial Farms in the United
States. Edited by K.F. Roos and MA. Moser. Washington, DC, EPA-430-B97-015. (Available on the Internet at
http ://www.epa.gov/methane/home .nsf/pages/agstar.)
EPA. 1999. Inventory of Greenhouse Gas Emissions and Sinks 1990-1997. Office of Policy, Planning, and
Evaluation, U.S. Environmental Protection Agency, Washington, DC; EPA 236-R-99-003. (Available on the
Internet at http://www.epa.gov/globalwarming/inventory/1999-inv.html.)
Hashimoto, A.G. and J Steed. 1992. Methane Emissions from Typical Manure Management Systems. Oregon
State University, Corvallis, OR.
Safley, L.M., M.E. Casada, Jonathan W Woodbury, and Kurt F. Roos. 1992. Global Methane Emissions From
Livestock And Poultry Manure. Office of Air and Radiation (ANR-445), U.S. Environmental Protection
Agency, Washington, DC, EPA-400-1-91-048.
USDA. 1996. Long-Term Agricultural Baseline Projections, 1995-2005. National Agricultural Statistics Serv-
ice, Agricultural Statistics Board, U.S. Department of Agriculture, Washington, DC. (Available on the Internet
at http://www.usda.gov/nass.)
USDC. 1995. 7992 Census of Agriculture. Economics and Statistics Administration, Bureau of the Census,
United States Department of Commerce, Washington, DC.
5-16 U.S. Methane Emissions: 1990 - 2020: Inventories, Projections, and Opportunities for Reductions
image:

4.0 Explanatory Notes
1 Volatile solids (VS) are the organic fraction of total solids in manure that will oxidize and be driven off as gas at a
temperature of 600°C.

2 For plug-flow digesters, fiber can be recovered using a separator and sold for about $4 to $8/cubic yard (yd3) as a
soil amendment. At larger farms the cost of the separator (approximately $50,000) is more than offset by the value
of the fiber, making this addition to the system profitable. The ability to realize these benefits is contingent on
finding a reliable buyer for the fiber material.
3 FarmWare can be downloaded from the AgSTAR homepage at www.epa.gov/agstar. Additional information on
these digesters can be requested from EPA (EPA, 1997b).

4 $/ton carbon equivalent ($/TCE) is converted to $/kWh by converting carbon into methane equivalent amounts
based on the Global Warming Potential (21), then by converting methane to Btu, and finally, by converting BTU
to kWh based on the average engine efficiency. The formula used to perform this conversion is shown below.

$ 106TCE 5.73MMTCE Tg 19.2 gC/^ ft3 U,000 Btu $
x-—x x x.
TCE MMTCE Tg CH4 IQIZ g ft CH ^ 1,000 Btu kWh kWh

Where: 5.73 MMTCE/Tg CH4 = 21 CO2/CH4 x (12 C / 44 CH4)
Density of CH4= 19.2 g/ft3
Btu content of CH4 = 1,000 Btu/ft3
Heat rate of 1C Engine = 14,000 Btu/kWh

5 The National Climatic Data Center (NCDC) defines up to 10 climate divisions in each state. Each climate division
represents relatively homogenous climate conditions. For purposes of this analysis, the climate division monthly
average temperatures are used to estimate biogas production from lagoons. The lagoon hydraulic retention time
and the maximum loading rate are set based on the area temperature as described in EPA (1997b). Climate does
not affect gas production from plug-flow and complete-mix digesters because they are heated.

6 A ten percent real discount rate is used to reflect the return required by the farmer for this type of investment. In
particular, the ADT systems are not integral to the farmer's primary food production business, and, consequently,
are estimated to require a higher rate of return than normal investments by the farmer.
U.S. Environmental Protection Agency - September 1999 Livestock Manure Management 5-17
image:

image:

6. Enteric Fermentation
Summary
EPA estimates 1997 U.S. methane emissions from livestock enteric fermentation at 34.1 MMTCE (6.0 Tg), which
accounts for 19 percent of total U.S. methane emissions in 1997. EPA expects methane emissions from livestock
enteric fermentation to increase through 2020 as livestock populations grow to meet domestic and international
demand for U.S. livestock products. In 2010, methane emissions are forecasted to reach 36.6 MMTCE (6.4 Tg) as
shown below in Exhibit 6-1.
When estimating methane emissions from livestock enteric fermentation, EPA categorizes livestock populations,
collects population data, and develops emission factors that account for the diversity of feed and animal character-
istics throughout the U.S. Among livestock, cattle are examined more closely than other livestock species because
they are responsible for the majority of U.S. livestock emissions, and significant variation exists in feed and animal
characteristics for cattle. The greatest opportunity for reducing methane emissions from cattle is to increase pro-
duction efficiency through improved management techniques.
This chapter describes methane emissions from livestock enteric fermentation, the methodology used to estimate
methane emissions, and the approaches underway to reduce emissions from cattle. Cost-effective management
practices and techniques can be used to improve animal health and nutrition, increase production efficiency, and
reduce methane emissions per unit of product. Based on assumptions about the use of these practices to improve
productivity, EPA has developed three scenarios (low, middle, and high) of future emissions from livestock enteric
fermentation. Unlike other chapters in this report, no cost estimates have yet been developed for methane reduc-
tions from enteric fermentation.
Exhibit 6-1: U.S. Methane Emissions from Enteric Fermentation (MMTCE)
Percent of Methane Emissions in 1997

Enteric Fermentation
19% (34.1 MMTCE)
Forecast Emissions
MMTCE
Total = 179.6 MMTCE
Source: EPA, 1999.
Baseline Emissions
1990
2000 2010 2020
Year
U.S. Environmental Protection Agency
Enteric Fermentation 6-1
image:

1.0 Methane Emissions from
Enteric Fermentation

Livestock emit methane as part of their normal diges-
tive processes. The U.S. livestock population consists
of ruminant livestock (cattle, sheep, and goats), mono-
gastric livestock (pigs), and pseudo-ruminants (horses
and mules). Cattle emit more than 90 percent of the
methane from livestock. The amount of methane pro-
duced is influenced significantly by animal and feed
characteristics.
This section describes the source of methane emissions
from livestock enteric fermentation and the method
EPA uses to estimate emissions. The emission esti-
mates and sources of uncertainty also are presented.

1.1 Emission Characteristics
Methane emissions from enteric fermentation depend
on animal type and diet. This chapter primarily fo-
cuses on emissions from ruminant livestock.
Ruminant Livestock. Cattle, sheep, and goats are the
primary ruminant livestock in the U.S. These animals
produce more methane per unit of feed consumed than
monogastric and pseudo-ruminant animals. Plant ma-
terial consumed by ruminant livestock is fermented by
approximately 200 species of microbes in the rumen,
the first of a four-part stomach. The microbes convert
the plant material into nutrients that livestock can use,
such as volatile fatty acids. Methane, a by-product of
this fermentation process, is released to the atmosphere
mainly via the mouth and nostrils.
Methane from ruminant livestock is derived from a
portion of the carbon energy in an animal's diet. Con-
sequently, methane emissions generally decrease when
production efficiency increases because a greater por-
tion of feed energy consumed goes to production (milk
or meat) rather than for methane.
Monogastric Animals and Pseudo-Ruminants.
These animals contribute a comparatively small pro-
portion of the total methane emitted by livestock in the
U.S. Monogastric animals (pigs) do not have a rumen,
but produce small amounts of methane during diges-
tion.
Pseudo-ruminants (horses and mules) produce less
methane than ruminant livestock and more methane
than monogastric animals. Pseudo-ruminants do not
have a rumen, but feed is fermented during digestion,
which allows them to obtain important nutrients from
coarse plant material.

1.2 Emission Estimation Method
Animal and feed characteristics have a significant im-
pact on methane emissions. Consequently, methods
used to estimate methane emissions from livestock
incorporate information on animal and feed character-
istics. The factors affecting methane emissions, and
the methods used to estimate past, current, and future
emissions are described below.

1.2.1 Factors Affecting Methane
Emissions from Enteric
Fermentation
Methane emissions are a function of the size of the
animal population, the quantity of feed consumed, and
the efficiency by which an animal converts feed to
product. The lower the efficiency, the greater the
amount of methane emitted.
Improving animal productivity decreases methane
emissions per unit of product. At the basic level, feed
goes to maintenance and product. Maintenance is the
proportion of feed needed to satisfy the basic meta-
bolic requirements that keep the animal alive. A sig-
nificant fraction of the methane emitted by cattle (40 to
60 percent) comes from the proportion of the feed used
for maintenance (EPA, 1993b). The remaining feed
energy is used for production. Maintenance require-
ments generally remain constant. Consequently, as
maintenance remains constant and animal productivity
increases, methane emissions go up slightly, but meth-
ane emissions per unit of product decrease.
Increasing animal productivity also reduces the num-
ber of animals needed to satisfy demand. By increas-
ing productivity, i.e., producing more meat or milk per
animal, meeting national demand for products is pos-
sible with fewer animals. As a result, overall methane
emissions decrease. In the U.S., the dairy industry has
demonstrated the impact of improved productivity on
methane emissions. Between 1960 and 1990, the dairy
6-2 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

industry increased annual milk production by ten mil-
lion tons with 7.4 million fewer cows, reducing esti-
mated methane emissions by almost one million metric
tons of carbon (MMTCE) (USDA, 1990; EPA,
1993a).
Dairy and beef producers can increase production effi-
ciency by improving feed conversion efficiency, which
is defined as the efficiency by which feed is converted
to product. Feed conversion efficiency is influenced
by feed type. For example, grain feeds are converted
to product more efficiently than forages, such as hay,
because they are more digestible and are higher in
protein.

1.2.2 Method for Estimating Current
Methane Emissions
Emissions are estimated for cattle, sheep, goats, pigs,
and horses. The methods used to estimate emissions
are presented below. Information on the emission
factors are presented in Appendix VI, Section VI.2.
Methane emissions from livestock in the U.S. are es-
timated by: (1) dividing animals into homogenous
groups; (2) developing emission factors for each
group; (3) collecting population data; (4) multiplying
the population by the emission factor for the respective
group; and (5) summing emissions across animal
groups and geographic regions (EPA, 1993a). The
relationship between the emission factor estimate and
the activity data is presented in the following equation:
animal region
Where:
= Total methane emissions (kg);
= Emission factor for animal type / in region
k (kg/animal); and
= Animal population for animal type /' in
region k.
Emission factors for different animal types are pre-
sented in Appendix VI in Exhibits VI-3 through VI-5 .
EPA uses a variety of data sources to develop emission
factors and estimate population sizes. Exhibit 6-2 pre-
sents the data sources for the emission factors and
population data used to estimate methane emissions, in
addition to criteria used to categorize the populations.
Because management practices affect methane emis-
sions, cattle are broken down into dairy and beef sec-
tors. However, sheep, goats, pigs and horses are not
broken down beyond the national level because they
make up a small proportion of emissions from live-
stock.

1.2. 3 Method for Estimating Future
Methane Emissions
EPA develops future emission estimates based on as-
sumptions regarding animal and feed characteristics.
Exhibit 6-2: Sources of Emission Factors and Population Data
Animal Type
Dairy Cattle

Beef Cattle

Sheep
Goats
Pigs
Horses
Emission Factor
Based on milk production data and on
the model by Baldwin, et al. (1987a-b) a
Based on the model by Baldwin, et al.
(1987a-b)
Based on Crutzen, et al. (1986) d
Based on Crutzen, et al. (1986)
Based on Crutzen, et al. (1986)
Based on Crutzen, et al. (1986)
Population Data
USDA, 1998a,db

USDA, 1998a-c

USDA, 1998e
USDA, 1998e
USDA, 1997
FAO, 1998
Categorization
Categorized by age, diet, and region c

Categorized by age, diet, and region

Not broken down beyond the national level
Not broken down beyond the national level
Not broken down beyond the national level
Not broken down beyond the national level
3 The model by Baldwin, et al. (1987) simulates digestion in growing and lactating cattle using information on animal and feed characteristics.
b The USDA National Agricultural Statistics Service collects data on the U.S. livestock population.
c Regions are West, North Central, South Central, North Atlantic, and South Atlantic.
d Crutzen, et al. (1986) developed emission factor estimates using information on typical animal size, feed intakes, and feed characteristics.
Emission factors for developed countries are used for the U.S. inventory, as well as emission estimates in this analysis (EPA, 1999).
Source: EPA, 1999.
U.S. Environmental Protection Agency
Enteric Fermentation
6-3
image:

These assumptions differ by animal type and sector,
and are summarized below.
Beef Cattle. Current emission factors (EPA, 1993a)
are used to estimate future emissions from beef cattle.
The beef cattle population is projected using future
production estimates.
Dairy Cattle. For dairy cows, emission factors used
to estimate future emissions are adjusted using pro-
jected milk production estimates. Consequently, future
emission factors are estimated under the assumption
that milk production per cow increases by 300 pounds
per year (Ibs/yr) through 2020. For dairy calves and
replacement heifers, current emission factors (EPA,
1993a) are used to estimate future emissions.
The dairy cow population is estimated by taking net
demand (including exports) and dividing it by the
projected milk production per cow. Populations of
calves and replacement heifers are estimated using the
1995 ratio of calves and replacement heifers to cows.
Sheep, Goats, Pigs, and Horses. Future population
estimates are multiplied by current emission factors
(EPA, 1993a) to estimate future emissions.
EPA estimates future animal populations using USDA
projections through 2005 (USDA, 1996). Populations
are projected beyond 2005 through 2020 for each spe-
cies using the following assumptions.
> Sheep. Consumption of lamb/mutton is expected
to decrease, causing a decrease in the sheep
population.
> Goats. The goat population is expected to remain
constant.
> Pigs. The pig population is expected to increase
in response to increased consumption per capita.
> Horses. The horse population is calculated by
estimating the future number of horses per capita,
and multiplying it by the extrapolated human
population.

1.3 Emission Estimates
The methods described in the previous section are
used to estimate methane emissions from livestock
enteric fermentation. This section presents emission
estimates from 1990 to 1997, and projected estimates
through 2020. Uncertainties in current and projected
estimates are also discussed.

1.3.1 Current Emissions and Trends
U.S. livestock emitted 34.1 MMTCE (6.0 Tg) of
methane in 1997. Cattle accounted for 96 percent of
these emissions (32.6 MMTCE or 5.7 Tg) and sheep,
goats, pigs, and horses for the remainder (1.5 MMTCE
or 0.3 Tg). Exhibit 6-3 presents emissions for 1990 to
1997. Emissions from cattle increased by five percent
from 1990 to 1997.
During 1990 to 1997, emissions from dairy cattle fell
slightly. The main factor slowing the growth in emis-
sions was the decrease in the cow and replacement
heifer populations because of increased production
efficiency in the dairy industry. As production effi-
ciency increases, fewer animals are required to satisfy
demand, and total methane emissions decrease.
As presented in Exhibit 6-3, beef cattle accounted for
approximately 75 percent of cattle emissions in 1997.
The growth in total emissions over the 1990 to 1997
period is largely due to an increase in emissions from
beef cattle. This increase is driven primarily by an
increase in the demand for beef, which is driven by
human population growth and food preferences.
Higher demand for meat increases the beef cattle
population and emissions. Non-cattle and dairy cattle
emissions over the period remain about the same.

1.3.2 Future Emissions and Trends
As presented in Exhibit 6-4, methane emissions from
livestock are projected to increase between 2000 and
2020, excluding possible Climate Change Action Plan
(CCAP) reductions. In 2020, emissions from livestock
are expected to reach 37.7 MMTCE (6.6 Tg), 36.2
MMTCE (6.3 Tg) from cattle and 1.5 MMTCE (0.3
Tg) from sheep, goats, pigs, and horses. The increase
in emissions will be driven by beef cattle, due to the
same factors that underlie the trends discussed above -
increased human population and food preferences
leading to higher beef consumption and more beef
cattle. Exports of beef also are expected to increase.
6-4 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 6-3: Methane
Animal Type
Non-Cattle
Sheep
Goats
Pigs
Horses
Total Non-Cattle
Emissions from

Dairy Cattle
Cows
Replacement Heifers 0-12 Months
Replacement Heifers 1 2-24 Months
Total Dairy
Beef Cattle
Cows
Replacements 0-1 2
Replacements 12-24
Slaughter-Weanlings
Slaughter-Yearlings
Bulls
Total Beef
Total Cattle
Total Livestock

Livestock (MMTCE)
1990
0.5
0.1
0.5
0.5
1.6
6.6
0.5
1.4
8.4
12.5
0.7
1.9
0.7
5.6
1.2
22.6
31.1
32.7
1991
0.5
0.1
0.5
0.6
1.7
6.6
0.5
1.4
8.4
12.6
0.7
2.0
0.7
5.6
1.3
22.8
31.2
32.8
1992
0.5
0.1
0.5
0.6
1.7
6.6
0.5
1.4
8.4
12.8
0.7
2.1
0.7
5.6
1.3
23.1
31.6
33.2
1993
0.5
0.1
0.5
0.6
1.6
6.6
0.5
1.4
8.4
13.0
0.8
2.2
0.7
5.6
1.3
23.6
32.0
33.6
1994
0.4
0.1
0.5
0.6
1.6
6.6
0.5
1.4
8.4
13.5
0.8
2.3
0.7
5.9
1.3
24.5
32.9
34.5
1995
0.4
0.1
0.5
0.6
1.6
6.6
0.5
1.4
8.4
13.6
0.8
2.3
0.7
6.1
1.4
24.9
33.3
34.9
1996
0.4
0.1
0.5
0.6
1.6
6.6
0.4
1.3
8.3
13.5
0.7
2.2
0.7
6.0
1.3
24.6
32.9
34.5
1997
0.3
0.1
0.5
0.6
1.6
6.6
0.4
1.3
8.3
13.2
0.7
2.1
0.8
6.2
1.3
24.3
32.6
34.1
Totals may not sum due to independent rounding.

Exhibit 6-4: Projected
Animal Type
Sheep
Goats
Hogs
Horses
Total Non-Cattle
Dairy Cattle
Beef Cattle
Total Cattle
Total Livestock
Baseline Methane Emissions from
2000
0.3
0.1
0.5
0.6
1.5
8.5
25.1
33.7
35.2

2005
0.3
0.1
0.6
0.7
1.7
8.8
25.4
34.1
35.9
Livestock (MMTCE)

2010
0.3
0.1
0.6
0.7
1.7
8.8
26.1
34.9
36.6

2015
0.3
0.1
0.6
0.7
1.8
8.9
26.7
35.6
37.3

2020
0.3
0.3
0.1
0.8
1.5
8.9
27.3
36.2
37.7
Totals may not sum due to independent rounding.
Future emissions will also be influenced by changes in
animal management and feed practices. In the next
section, some of these alternative management and
feeding practices are described. Depending on how
widespread these practices become, they will affect
future levels of methane emissions.
1.4 Emission Estimate Uncertainty
The methane emission estimates used in this analysis
are based on estimated animal and feed characteristics.
Although the animal and feed characteristics used in
the analysis represent the range of U.S. characteristics,
they may not represent the full diversity in the U.S.
U.S. Environmental Protection Agency
Enteric Fermentation
6-5
image:

For sheep, goats, pigs, and horses, emission factor es-
timates are based on data from developed countries
(U.S., Germany, and England), and not specifically
from the U.S. Consequently, there is moderate uncer-
tainty in how closely the emission factors represent
typical animal sizes, feed intake, and feed characteris-
tics in the U.S.

2.0 Emission Reductions

Unlike other methane emission sources for which there
are technologies or practices aimed specifically at re-
ducing emissions, no such control options are currently
available for enteric fermentation. For this reason,
EPA did not develop marginal abatement curves for
emission reductions from enteric fermentation. Nev-
ertheless, some aspects of livestock management can
result in lower emissions, principally by improving
dairy and beef production efficiency. This section de-
scribes techniques available or in-use that improve
production efficiency. Additionally, this section pro-
vides forecasts of emissions under various assump-
tions, and describes how improved techniques will be
implemented industry-wide.

2.1 Technologies for Reducing
Methane Emissions
Implementing proper management techniques to im-
prove animal nutrition and reproductive health is the
primary means of improving production efficiency.
Other reduction options, such as production enhancing
agents, trade, and pricing systems are also used to in-
crease production efficiency. Specific management
techniques that improve animal production efficiency
are discussed below.
Animal Nutrition and Health. The principal areas
for improving animal productivity involve applying
sound nutrition and veterinary practices. Feed that is
better tailored to the metabolic requirements of the
animal and that can be digested efficiently results in a
greater proportion of the energy consumed going to-
wards production, and less to waste and methane emis-
sions. Some feeds, such as distiller grains, are high in
protein and are highly digestible.
Combining proper nutritional management with proper
veterinary care promotes growth and leads to higher
levels of production than in the absence of such care.
This care includes applying proper management tech-
niques to maintain the comfort and health of the ani-
mals.
Grazing Management. Grazing cattle emit a signifi-
cant portion of the methane from enteric fermentation.
Consequently, implementing proper grazing manage-
ment practices to improve the quality of pastures in-
creases animal productivity and has a significant im-
pact on reducing methane emissions from livestock
enteric fermentation. By examining soil and plant
composition and implementing steps to improve the
health of the soil and ensuring the right mixture of
plants, producers can enhance the nutrition and health
of the cattle, and increase production.
Management intensive grazing is an effective form of
grazing management. Unlike continuous grazing, in
which cattle graze on large pastures for long periods of
time and deplete the pasture of healthy plants, man-
agement intensive grazing is a form of grazing in
which animals are rotated regularly among grazing
units (paddocks) to maximize forage quality and quan-
tity. This form of grazing management leads to vigor-
ous plant growth, healthy soil, and a constant, nutri-
tious source of food for the cattle. Overall, the health
of the pasture is increased significantly Production
efficiency increases as a result, thereby reducing meth-
ane emissions per unit product and total methane emis-
sions.
Artificial Insemination. An animal's genes have a
significant influence on its productivity. Artificial in-
semination enables farmers to improve the genes of
their herd by impregnating the animals with semen
from healthy and productive bulls. In the U.S., artifi-
cial insemination is widely used by dairy operations.
Artificial insemination is less popular in the beef in-
dustry with approximately seven percent of operations
using the procedure in 1997 (USDA, 1998f). Given
that genes affect animal productivity, artificial insemi-
nation is an excellent technique to improve the genes
of an animal herd. An increase in the use of artificial
insemination by beef operations could increase animal
6-6 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

productivity and reduce methane emissions per unit
product.
Production Enhancing Agents. With advances in
science and biotechnology, a number of production
enhancing agents are available that increase production
efficiency in cattle. Production enhancing agents are
meant to enhance the effect of proper animal health,
nutrition, and grazing management practices. Three
production enhancing agents are commonly available
and are discussed below.
> Bovine Somatotropin (Dairy Industry). Bovine
Somatotropin (bST), also known as bovine growth
hormone (BGH), is a naturally occurring growth
hormone in bovines produced by the pituitary
gland. Recombinant bST (rbST), an essentially
identical form of bST, is produced using modern
biotechnology. The use of rbST with dairy cows
can increase milk production per cow per year by
12 percent or by 1,800 Ibs (EPA, 1996). After the
U.S. Food and Drug Administration (FDA) ap-
proved the use of rbST, it was released on the
market in 1994. Approximately 15 percent of the
dairy cow population is treated with rbST (Mon-
santo, 1998). While there is still considerable
public debate regarding the health risks of rbST,
the FDA approved the use of rbST after perform-
ing a rigorous analysis of the potential health ef-
fects. Given that rbST is cost-effective and con-
sidered safe by the FDA, increased use of rbST is
expected to take place in the future. If adopted
widely by the dairy industry, the use of rbST could
increase production efficiency and reduce meth-
ane emissions from dairy cattle by one to three
percent, holding other factors constant (EPA,
1996).
> Anabolic Agents (Beef Industry). Anabolic
steroids increase the rate of weight gain and feed
intake in growing heifers and steers. The in-
creased rate of weight gain reduces the time it
takes for calves to reach slaughter weight. Steroid
implants are considered cost-effective (USDA,
1987) and have been approved by the FDA. Ster-
oids can reduce emissions by enhancing growth
rates, feed efficiency, and lean tissue accretion
(EPA, 1993b).
> lonophores (Beef Industry). lonophores are
polyether antibiotics produced by soil microor-
ganisms that gained attention in the 1970s for their
ability to improve feed digestibility in cattle. They
are administered to cattle by mixing them with
feed or by providing them as a component of a
multi-nutrient block, which is often a solid block
of molasses supplemented with nutrients. Two
types of ionophores, monensin and lasalocid, have
been approved for use in the U.S. (EPA, 1993b).
Market Based Strategies. Practices that are focused
on improving the health and nutrition of the animals
are key to improving production efficiency. However,
other strategies, such as trade and pricing systems, also
have a substantial influence on production and man-
agement techniques.
> Trade. Changes in beef and dairy trade policy
could result in higher U.S. emissions, but possibly
lower emissions worldwide. Because U.S. dairy
and beef operations are among the most efficient
operations in the world, increasing U.S. exports
could displace less efficient operations in other
countries, and lower emissions. Although U.S.
beef and dairy exports are currently low, they are
expected to increase in the future as the U.S. beef
industry seeks to gain greater access to foreign
markets.
> Dairy Prices. Changes in the pricing systems for
dairy products can reduce methane emissions. In
the U.S., milk is uniformly graded and priced ac-
cording to its butterfat content. This pricing sys-
tem was useful when the demand for high-fat milk
was stronger than it is today. With the demand for
low-fat milk increasing, the dairy industry has be-
gun changing from a single-component pricing
system to a multiple-component pricing (MCP)
system in which other components of milk, pri-
marily protein, are reflected in the price.
If this trend continues, producers will modify the
feeding regimes of their dairy cows to include or
increase the amount of high-protein feedstuffs,
such as grain, which is also highly digestible, fa-
U.S. Environmental Protection Agency
Enteric Fermentation
6-7
image:

creasing the proportion of high-protein feedstuff's
will increase production. In addition, producers
will breed cows that are genetically favored to
produce low-fat, high-protein milk. These modifi-
cations would reduce methane emissions by in-
creasing production efficiency.
> Beef Prices. Industry efforts are also underway to
improve the quality of beef through Value-Based
Marketing, an industry trend leading to more ac-
curate pricing of beef based on value. One effect
would be a reduction in incentives to produce ex-
cess fat in beef. Reducing fat in the animals
would be achieved through genetic improvements
and more efficient feeding practices. The result
would also lead to lower methane emissions.
This Value-Based Marketing trend may also pro-
vide incentives for a more efficient calf-slaughter
system. Generally, calves go through one of two
paths after they are weaned. Approximately 80
percent of calves pass through a stacker or back-
grounding phase for several months, before en-
tering the feedlot. The remaining 20 percent of
calves go straight to the feedlot. Calves that are
backgrounded are slaughtered at an older age and
consequently emit more methane during their life
cycle than calves that go straight to the feedlot.
The Value-Based Marketing trend may cause an
increase in the number of calves going directly to
feedlots, with a consequent reduction in methane
emissions (EPA, 1993a).

2.2 Achievable Emission Reductions
This section provides potential emission reductions
under varying assumptions about how some of the
practices and strategies described above are imple-
mented. Potentially achievable emissions for dairy
and beef cattle are presented in Exhibit 6-5 and Exhibit
6-7, respectively.
Dairy Cattle. Exhibit 6-5 provides future emission
estimates from dairy cattle using scenarios in which
rbST and MCP are adopted. USDA (1996) estimated
milk production per cow and demand for dairy prod-
ucts through 2005. Demand after 2005 is expected to
remain constant. In Exhibit 6-5, a constant baseline
increase of 300 pounds of milk per cow per year is
used to estimate future milk production. This increase
is a current trend that is expected to continue as the
dairy industry improves production efficiency. Future
cow populations are estimated by using projected es-
timates of demand and milk production.
The emission factor estimates are multiplied by pro-
jected population estimates to estimate future emis-
sions. The emission factor estimates for dairy cows
change through time to account for changes in milk
production levels.
Exhibit 6-5 shows the reduction in methane emissions
when rbST and MCP are adopted. Improvements in
animal and feed characteristics could potentially in-
crease production efficiency and reduce emissions
further.
Beef Cattle. EPA estimated methane emissions from
beef cattle for three sets of emissions scenarios: (1)
low; (2) medium; and (3) high emissions. The sce-
narios are presented in Exhibit 6-6, and the emissions
estimates for each scenario are presented in Exhibit 6-
7. For each of these sets, a baseline is defined by the
level of domestic consumption and exports. Within
Exhibit 6-5: Projected Dairy Methane Emissions (MMTCE)
Scenario
(1) Current emission factors
(2) Baseline increase of 300 Ibs of milk/yr
(3) Low rbST Adoption - no MCP
(4) High rbST Adoption- no MCP
(5) No rbST Adoption- with MCP
(6) Low rbST Adoption - with MCP
(7) High rbST Adoption - with MCP
2000
8.59
8.53
8.48
8.42
8.25
8.19
8.13
2005
9.05
8.82
8.71
8.65
8.48
8.42
8.36
2010
9.39
8.82
8.76
8.71
8.48
8.42
8.36
2015
9.62
8.88
8.82
8.76
8.53
8.48
8.42
2020
9.91
8.93
8.88
8.82
8.59
8.53
8.48
rbST = Recombinant Bovine Somatotropin; MCP = Multiple Component Pricing
6-8 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

each set, EPA evaluated alternative scenarios that are
defined in terms of improvements in the cow-calf
phase and the growth-to-slaughter phase. These char-
acteristics are described below.
> Domestic Consumption. As presented in Exhibit
6-6, future emissions are calculated under low,
middle and high beef consumption scenarios,
which combine different levels of domestic and
export consumption. Consumption projections are
the product of future per-capita consumption and
population estimates. USDA (1996) published
projected estimates of beef consumption through
2005.
> Exports. The U.S. cattle industry is highly effi-
cient compared to the cattle industries of other
countries. Consequently, increasing U.S. cattle
exports would displace less efficient operations,
and reduce methane emissions per unit product
worldwide. Exhibit 6-6 summarizes the low, me-
dium, and high export scenarios.
> Cow-Calf Phase. Improvements in management
and nutrition are underway in the cow-calf sector,
which accounts for a large portion of methane
emitted by cattle in the U.S. Researchers and ex-
tension agents are working with producers to im-
prove pasture management and implement better
management techniques that improve animal
health and nutrition. Because cow-calf operations
in the southeastern U.S. are less efficient than
cow-calf operations in other regions of the U.S.,
improving management practices in the southeast
could have significant impacts on reducing meth-
ane emissions. Consequently, the cow-calf phase
scenario in this analysis is for cow-calf operations
in the southeastern U.S.
Implementing these measures improves produc-
tion efficiency, which can be expressed in terms of
calving rates and two-year-old heifer calving rates.
The calving rate is the proportion of calves born
from the total number of mature cows. The two-
year-old heifer calving rate is the proportion of
heifers in the population that successfully produce
a calf by two years of age. Currently, the calving
rate and two-year-old heifer calving rate for cow-
calf operations in the southeast are approximately
70 and 50 percent, respectively. Improving these
efficiencies would reduce the number of mother
cows needed and, therefore, would reduce meth-
ane emissions. Exhibit 6-6 presents three cow-calf
scenarios for low, medium, and high emissions.
Exhibit 6-6: Scenarios for Estimating Future Emissions from Beef Cattle
Scenario
Low Emissions
Medium Emis-
sions
High Emissions
Domestic
Consumption
Scenario
Continues to decline
at the rate projected
for 2000 to 2005
Average of low and
high demand sce-
narios
Remains at the 2005
consumption level
Export Scenario
Increase by 25 million
pounds per year by
2020
Average of low and
high scenarios
By 201 5, equal to ten
percent of total con-
sumption
Cow-Calf Phase Scenario3 c
By 2010, the calving rate and
two year old heifer calving
rate increase to 85 and 75
percent, respectively
By 201 5, the calving rate and
two year old heifer calving
rate increase to 85 and 75
percent, respectively
By 2020, the calving rate and
two year old heifer calving
rate increase to 85 and 75
percent, respectively
Growth-to-Slaughter
Phase Scenario d
By 201 0,20/80 percent
weanling/yearling
changes to 80/20 per-
cent
By 201 0,20/80 percent
weanling/yearling
changes to 50/50 per-
cent
By 201 0,20/80 percent
weanling/yearling
changes to 30/70 per-
cent
3 For the baselines, the calving rate and two year old heifer calving rate are 70 and 50 percent, respectively.
b The calving rate is the proportion of calves born to the total number of cows in the population (expressed as a percentage).
c The two year old heifer calving rate is the proportion of heifers calving at two years of age to the total number of heifers that are two years
of age or older in the population (expressed as a percentage).
d For the baselines, the growth-to-slaughter phase is 20 percent weanling/80 percent yearling.
U.S. Environmental Protection Agency
Enteric Fermentation
6-9
image:

> Growth-to-Slaughter Phase. Efforts are also
underway to improve productivity in the growth-
to-slaughter phase by increasing the proportion of
calves that go directly from weaning to feedlots.
Currently, approximately 20 percent of the calves
go straight to feedlots, while 80 percent are held in
a stacker phase for backgrounding. For this
analysis, calves that go straight to feedlots are
called weanlings, while calves that go through
extended backgrounding are called yearlings. In-
creasing the percentage of weanlings would re-
duce the age at slaughter and would reduce meth-
ane emissions. In addition to increasing the pro-
portion of calves that are weanlings, improved
health and nutrition also increases production effi-
ciency in the growth-to-slaughter phase. EPA cre-
ated three scenarios to estimate projected emis-
sions in growth-to-slaughter (see Exhibit 6-6).
Exhibit 6-7 presents the methane emissions for each
scenario.
2.3 Reduction Estimate
Uncertainties and
Limitations

Considerable uncertatinty is associated with the
scenarios shown in Exhibit 6-7. The major source of
uncertainty are the forecasts of emission factors which
depend on the extent to which the various strategies to
improve production efficiency are implemented. In
addition, there are major uncertanities in forecasts of
demand for dairy and beef products that will influence
the future animal population.
Exhibit 6-7: Methane Emissions from Beef Cattle
Scenario
(MMTCE)
2000

2005

2010

2015

2020
Low Emissions Scenario
Baseline - Low
Large Weanling/Yearling shift to 80%
Improved cow-calf by 2010
Both - Low
25.1
24.4
24.9
24.1
25.4
23.9
24.8
23.3
25.4
23.0
24.5
22.1
25.4
23.0
24.4
22.1
25.2
22.9
24.2
21.9
Middle Emissions Scenario
Baseline - Medium3
Medium Weanling/Yearling shift to 50%
Improved cow-calf by 2015
Both - Medium
25.1
24.8
24.9
24.5
25.4
24.6
25
24.2
26.1
24.9
25.3
24.1
26.7
25.4
25.7
24.5
27.3
25.9
26.2
25.0
High Emissions Scenario
Baseline - High
Small Weanling/Yearling shift to 30%
Improved cow-calf by 2020
Both - High
25.1
25.0
25.0
24.9
25.4
25.2
25.1
24.8
a EPA used this scenario to estimate future methane emissions from beef cattle as indicated in
27.7
27.3
27.1
26.7
Exhibit 6-4.
30.2
29.8
29.4
28.9

31.4
31.0
30.3
29.8

6-10 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

3.0 References

Baldwin, R.L., J.H.M. Thornley, and D.E. Beever. 1987a. "Metabolism of the Lactating Cow. n. Digestive
Elements of a Mechanistic Model," Journal of Dairy Research, 54: 107-131.
Baldwin, R.L., J. France, D.E. Beever, M. Gill, and J.H.M. Thornley. 1987b. "Metabolism of the Lactating cow.
HI. Properties of Mechanistic Models Suitable for Evaluation of Energetic Relationships and Factors Involved
in the Partition of Nutrients," Journal of Dairy Research, 54: 133-145.
Crutzen, P.J., I. Aselmann, and W. Seiler. 1986. "Methane Production by Domestic Animals, Wild Ruminants,
Other Herbivorous Fauna, and Humans," Tellus, 386:271-284.
EPA. 1993a. Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress.
Atmospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental Protection
Agency, Washington, DC, EPA 430-R-93-003. (Available on the Internet at http://www.epa.gov/ghginfo/re-
ports.htm.)
EPA. 1993b. Opportunities to Reduce Anthropogenic Methane Emissions in the United States, Report to Con-
gress. Atmospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental Protection
Agency, Washington, DC, EPA 430-R-93-012.
EPA. 1996. An Environmental Study of Bovine Somatotropin Use in the U.S.: Impacts on Methane Emissions.
Prepared by: ICF Incorporated. Atmospheric Pollution Prevention Division, Office of Air and Radiation, U.S.
Environmental Protection Agency, Washington, DC, EPA 430-R-93-012.
EPA. 1999. Inventory of Greenhouse Gas Emissions and Sinks 1990-1997. Office of Policy, Planning, and
Evaluation, U.S. Environmental Protection Agency, Washington, DC; EPA 236-R-99-003. (Available on the
Internet at http://www.epa.gov/globalwarming/inventory/index.html.)
Food and Agriculture Organization (FAO). 1998. Statistical Database. June 12, 1998. (Accessed July 1998.)
(Available on the Internet at http://www.fao.org.)
Monsanto. 1998. Monsanto Release: Status Update: Posilac® Bovine Somatotropin. December 15, 1998, St.
Louis, MO.
USDA. 1987. Economic Impact of the European Economic Community's Ban on Anabolic Implants. Food
Safety and Inspection Service, U.S. Department of Agriculture, Washington, DC.
USDA. 1990. Agricultural Statistics. U.S. Government Printing Office, U.S. Department of Agriculture, Wash-
ington, DC.
USDA. 1996. Long-term Agricultural Baseline Projections, 1995-2005. National Agricultural Statistics Service,
Agricultural Statistics Board, U.S. Department of Agriculture, Washington, DC.
USDA. 1997. Hogs and Pigs. National Agricultural Statistics Service, Agricultural Statistics Board, U.S. De-
partment of Agriculture, Washington, DC. (Available on the Internet at http://www.usda.gov/nass.)
USDA. 1998a. Cattle. National Agricultural Statistics Service, Agricultural Statistics Board, U.S. Department of
Agriculture, Washington, DC. (Available on the Internet at http://www.usda.gov/nass.)
USDA. 1998b. Cattle on Feed. National Agricultural Statistics Service, Agricultural Statistics Board, U.S. De-
partment of Agriculture, Washington, DC. (Available on the Internet at http://www.usda.gov/nass.)
U.S. Environmental Protection Agency Enteric Fermentation 6-11
image:

USDA. 1998c. Livestock Slaughter Annual Summary. National Agricultural Statistics Service, Agricultural Sta-
tistics Board, U.S. Department of Agriculture, Washington, DC. (Available on the Internet at http://www.
usda.gov/nass.)
USDA. 1998d. Milk Production. National Agricultural Statistics Service, Agricultural Statistics Board, U.S. De-
partment of Agriculture, Washington, DC. (Available on the Internet at http://www.usda.gov/nass.)
USDA. 1998e. Sheep and Goats. National Agricultural Statistics Service, Agricultural Statistics Board, U.S.
Department of Agriculture, Washington, DC. (Available on the Internet at http://www.usda.gov/nass.)
USDA. 1998f Part W: Changes in the U.S. Beef Cow-Calf Industry, 1993-1997. National Animal Health
Monitoring System, Fort Collins, CO. (Available on the Internet at http://www.aphis.usda.gov/vs/ceah/cham.)
6-12 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Appendix I: Supporting Material for
Composite Marginal Abatement
Curve
This appendix presents the data EPA used to develop the composite marginal abatement curve (MAC). The first
section summarizes the incremental emissions reductions associated with each source, i.e., landfills, natural gas
systems, coal mining, and livestock manure. The second section presents the approach to fit an equation to the
MAC data.

1.1 Estimates for Composite Marginal Abatement Curve

This section presents estimates of the incremental emission reductions for each combination of carbon equivalent
value and methane source. Exhibit 1-1 presents these estimates. The exhibit also includes the cumulative
emission reductions. These cumulative emission reductions form the composite MAC for 2010.
Exhibit 1-1:
Value of
Carbon
Equivalent
$tfCE
($30.00)
($30.00)
($23.72)
($23.62)
($23.24)
($23.01)
($22.95)
($20.85)
($20.00)
($19.86)
($19.77)
($19.51)
($19.32)
($19.18)
($19.14)
($19.13)
($18.96)
($18.87)
($18.69)
($18.42)
($16.86)
($16.70)
$16.41)
Composite Marginal Abatement Curve Schedule of Options for 2010
Incremental
Reductions
(MMTCE)
0.29
1.23
0.45
0.23
0.64
0.12
0.24
0.32
0.77
0.33
0.42
0.87
1.63
0.01
0.79
0.59
1.63
0.77
0.57
0.48
0.39
0.43
0.47
Source
Manure-Dairy
Manure-Swine
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Manure-Dairy
Natural Gas
Natural Gas
Coal
Natural Gas
Natural Gas
Coal
Natural Gas
Coal
Coal
Coal
Coal
Natural Gas
Natural Gas
Coal
Cumulative
Reductions
(MMTCE)
0.29
1.52
1.98
2.20
2.85
2.96
3.20
3.52
4.29
4.62
5.04
5.91
7.54
7.55
8.34
8.93
10.55
11.32
11.89
12.37
12.76
13.20
13.67
Value of
Carbon
Equivalent
$tfCE
($16.32)
($16.00)
($15.74)
($15.67)
($15.11)
($14.45)
($14.41)
($14.14)
($14.02)
($13.41)
($12.17)
($11.78)
($11.50)
($11.32)
($11.01)
($10.65)
($10.59)
($10.50)
($10.39)
($10.28)
($10.00)
($9.51)
($9.23)
Incremental
Reductions
(MMTCE)
0.25
0.98
0.19
0.09
0.73
0.05
0.35
0.41
0.14
0.29
0.90
0.31
0.26
0.41
0.20
0.04
0.16
0.42
0.65
0.02
0.62
0.04
0.19
Source
Coal
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Coal
Natural Gas
Coal
Natural Gas
Coal
Coal
Coal
Natural Gas
Natural Gas
Coal
Coal
Natural Gas
Natural Gas
Manure-Dairy
Natural Gas
Coal
Cumulative
Reductions
(MMTCE)
13.91
14.89
15.08
15.17
15.89
15.95
16.30
16.71
16.86
17.15
18.04
18.35
18.61
19.02
19.22
19.27
19.43
19.84
20.49
20.52
21.14
21.18
21.37
U.S. Environmental Protection Agency - September 1999
Appendix! 1-1
image:

Exhibit 1-1 : Composite Marginal Abatement Curve Schedule of Options for 2010 (continued)
Value of
Carbon
Equivalent
$tfCE
($9.16)
($7.87)
($7.68)
($7.50)
($6.92)
($6.77)
($6.50)
($6.23)
($4.77)
($3.80)
($3.23)
($2.50)
($1.61)
($1.41)
($1.32)
($0.86)
($0.82)
($0.59)
($0.05)
$0.00
$0.00
$0.41
$0.95
$1.05
$1.32
$2.05
$3.51
$4.96
$5.23
$5.25
$6.45
$6.58
$6.60
$7.19
$7.62
$9.32
$9.59
$10.00
$10.00
$10.00
$11.23
$11.41
$11.69
$12.04
$12.14
Incremental Cumulative
Reductions Source Reductions
(MMTCE) (MMTCE)
0.56
0.47
0.38
0.39
0.06
0.33
0.09
0.22
0.34
0.01
0.20
0.14
0.01
0.17
0.07
0.27
0.60
0.03
0.10
0.50
10.55
0.06
0.16
0.07
0.25
0.15
0.15
0.02
0.24
0.02
0.14
0.04
0.10
0.03
0.21
0.18
0.03
0.31
0.12
3.89
0.03
0.04
0.07
0.00
0.09
Natural Gas
Coal
Coal
Natural Gas
Natural Gas
Coal
Coal
Coal
Coal
Natural Gas
Coal
Coal
Natural Gas
Coal
Coal
Coal
Natural Gas
Coal
Coal
Manure-Dairy
Landfills
Coal
Coal
Coal
Coal
Coal
Natural Gas
Coal
Coal
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Coal
Coal
Manure-Dairy
Manure-Swine
Landfills
Coal
Coal
Coal
Natural Gas
Coal
21.93
22.40
22.78
23.17
23.24
23.57
23.66
23.88
24.21
24.22
24.42
24.56
24.57
24.74
24.81
25.07
25.67
25.70
25.80
26.30
36.85
36.91
37.07
37.13
37.38
37.53
37.68
37.70
37.94
37.96
38.10
38.14
38.24
38.27
38.47
38.65
38.68
39.00
39.11
43.01
43.04
43.08
43.14
43.14
43.23
Value of
Carbon
Equivalent
$tfCE
$12.41
$12.78
$12.87
$14.32
$15.60
$16.23
$16.51
$16.78
$16.87
$17.51
$18.42
$18.71
$18.84
$18.84
$19.06
$19.69
$20.00
$20.00
$20.00
$21.14
$21.51
$22.87
$23.96
$24.51
$24.65
$27.87
$29.70
$30.00
$30.00
$30.00
$31.59
$35.52
$35.52
$38.14
$38.60
$39.77
$40.00
$40.00
$40.00
$40.88
$45.21
$47.09
$47.54
$50.00
$50.00
Incremental Cumulative
Reductions Source Reductions
(MMTCE) (MMTCE)
0.09
0.11
0.09
0.03
0.16
0.07
0.14
0.11
0.03
0.09
0.06
0.06
0.35
0.22
0.14
0.06
0.20
1.54
5.79
0.04
0.02
0.07
0.05
0.03
0.00
0.06
6.28
0.18
2.28
1.22
0.51
0.77
0.00
0.87
0.42
0.00
0.16
1.45
0.29
0.00
0.94
0.32
0.02
0.16
1.18
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Coal
Manure-Dairy
Manure-Swine
Landfills
Coal
Coal
Coal
Coal
Coal
Natural Gas
Coal
Coal
Manure-Dairy
Manure-Swine
Landfills
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Manure-Dairy
Manure-Swine
Landfills
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Manure-Dairy
Manure-Swine
43.32
43.43
43.52
43.55
43.71
43.78
43.92
44.03
44.06
44.15
44.21
44.27
44.63
44.84
44.98
45.04
45.24
46.78
52.57
52.62
52.63
52.70
52.75
52.77
52.77
52.83
59.10
59.28
61.57
62.79
63.30
64.07
64.07
64.94
65.36
65.36
65.52
66.97
67.26
67.26
68.20
68.52
68.54
68.70
69.88
I-2 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 1-1:
Value of
Carbon
Equivalent
$50.00
$52.10
$56.12
$65.77
$75.00
$75.00
$75.00
$76.24
$95.34
$95.47
$100.00
$100.00
Composite Marginal Abatement Curve Schedule of Options for 2010 (continued)
Incremental
Reductions
(MMTCE)
0.11
0.67
0.56
0.00
0.42
2.77
0.05
0.08
0.21
0.00
0.38
0.40
Source
Landfills
Natural Gas
Natural Gas
Natural Gas
Manure-Dairy
Manure-Swine
Landfills
Natural Gas
Natural Gas
Natural Gas
Manure-Dairy
Manure-Swine
Cumulative
Reductions
(MMTCE)
69.98
70.65
71.22
71.22
71.63
74.40
74.45
74.53
74.74
74.74
75.12
75.52
Value of
Carbon
Equivalent
$100.00
$113.08
$116.47
$125.00
$125.00
$140.29
$150.00
$166.22
$175.00
$188.35
$200.00

Incremental
Reductions
(MMTCE)
0.02
0.12
0.45
0.30
0.08
0.01
0.27
0.03
0.23
0.07
0.19

Source
Landfills
Natural Gas
Natural Gas
Manure-Dairy
Manure-Swine
Natural Gas
Manure-Dairy
Natural Gas
Manure-Dairy
Natural Gas
Manure-Dairy

Cumulative
Reductions
(MMTCE)
75.54
75.66
76.10
76.41
76.49
76.50
76.77
76.80
77.03
77.10
77.29

1.2 Equation for Composite Marginal Abatement Curve

The relationship between the additional value of carbon equivalent ($/TCE) and the cumulative emission
reductions, i.e., abated methane in MMTCE is shown in Exhibit II-2. The cumulative emission reductions
increases relatively slowly as a function of the value of carbon equivalent. As the cumulative emission reductions
reach about 75 MMTCE, the reduction plateau and cannot be further abated at higher $/TCE values. In order to
represent the steepness of the curve at values close to 75 MMTCE, EPA determined a best-fit curve based on the
data points. This equation is defined by:

y = parameter i * exp [parameter 2 / (max - x)] offset

where:
y = additional value of carbon equivalent ($/TCE)
x = cumulative emission reductions (MMTCE)
parameter i, parameter 2, offset, and max = determined parameters
All values of x, i.e., cumulative emission reductions, must be less than the value of max. This curve has the
property that as the x value increases to the value of max, the y value will tend to infinity, so the curve will
approximate the steep rise at the maximum x value.
EPA used the method of least squares to find the best fitting curve. This method estimates the parameters by
minimizing the mean square error (MSE), i.e., the average squared difference between the actual and fitted values
of y: MSE = (actual y fitted yf I n, where n is the number of pairs, i.e., 159 pairs of abated methane and
additional value of carbon equivalent. The minimum MSE is 68.6. The fitted parameters are:
> offset = 60
> parameter i =30
> parameter = 45
> max =102
U.S. Environmental Protection Agency - September 1999
Appendix I I-3
image:

The resulting equation is given by:
j = 30 *exp[45/(102-x)]-60

The squared correlation coefficient (R squared) between the actual and predicted values of y is 0.95, showing a
reasonably good fit on a scale of zero to one, one being a perfect fit. Although the model was fitted using the
method of least squares, the optimum least squares solution for this problem is also the solution with the
maximum possible R squared. Exhibit II-2 presents the 159 data points and the fitted curve.

Exhibit 11-2: Marginal Abatement Curve for U.S. Methane Emissions in 2010
LU
O
U>
a>
O
Si
re
O
14-
o
HI
$250
$200 -

$150 _.

$100 -.

$50 -.
$0 —
($50)
Observed Data
45
$/TCE=30e102-MMTCE-60
HI
O
•—
Q-
>,
O)
Market Price
10 20 30 40 50 60

Abated Methane (MMTCE)
70
80
I-4 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Appendix II: Supporting Material for the
Analysis of Landfills
In this appendix, EPA presents details on the methodologies to estimate the annual waste disposal rates and the
costs for recovering methane from landfills. The appendix is comprised of six sections. The first section dis-
cusses the approach for projecting waste landfilled, and the second presents the assumptions used to evaluate
costs and cost-effective emission reductions from landfill gas-to-energy projects (LFGTE). The third section de-
scribes the estimation method for the energy prices for which EPA conducts the analysis. The fourth section pre-
sents 84 break-even waste-in-place (WIP) and gas price combinations, a subset of which are used to construct a
marginal abatement curve (MAC). The fifth section presents the cost-effective methane emission reductions for
the energy prices and finally, the sixth section presents the uncertainties associated with the methods and analyses.

11.1 Waste Landfilled
This section provides an overview of the methods EPA uses to simulate waste in the population of U.S. landfills.
EPA simulates waste disposal in U.S. landfills for the years 1990 through 2050. EPA bases the waste disposal
data prior to 1990 on a 1988 landfill survey (EPA, 1988). For the years 1990 to 1997, EPA uses the BioCycle
data presented in Exhibit II-1 (BioCycle, 1998). After 1997, waste disposal remains constant at 179,418 metric
tons (MT). This estimate is the average of the BioCycle data from 1990 to 1995.
The analysis bases the total amount of waste disposed in each landfill on the design capacity and waste accep-
tance rate over time. Exhibit II-2 shows the design capacity for the categories of modeled landfills and Exhibit II-
3 shows the percent of municipal solid waste (MSW) disposed in each landfill category from 1990 to 2050. Ex-
hibit II-4 shows how EPA apportions total waste according to the waste disposal rates for each design capacity
provided in Exhibit II-2.
Exhibit 11-1: Landfill Waste Data
Year
1990
1991
1992
1993
1994
1995
1996
1997
Waste Generated3
('000 MT)
266,542
254,797
264,843
278,573
293,110
296,586
297,268
309,075
Percent Landfilledb
77%
76%
72%
71%
67%
63%
62%
61%
MSW Disposed in Land-
fills with Capacity
< 500,000 MTC
10%
9%
9%
8%
8%
7%
7%
7%
Waste Landfilled for
Categories 1-5d
184,714
175,443
173,907
181,568
181,458
173,770
171,405
175,338
a'b Source: BioCycle, 1998.
c These landfills are analyzed separately as they are excluded from EPA's 1988 landfill survey.
d The average between the beginning of 1990 to the beginning of 1995, is used to estimate total waste apportioned in each landfill category
(see Exhibit II-4).
U.S. Environmental Protection Agency - September 1999
Appendix II: Landfills 11-1
image:

Exhibit 11-2: Modeled
Landfill Category
1 - Small
2 - Small-Medium
3 - Medium
4 - Large
5 - Very Large

Exhibit II-3:
Category
1
2
3
4
5
Total

Landfill Categories
Capacity (MT)
500,000
1,000,000
5,000,000
15,000,000
> 15,000,000

MSW Landfill Waste Disposal Rates (Percent of Total MSW Landfill Disposed)
Base ('90)
3.0%
9.6%
39.4%
27.0%
21.0%
100.0%
1990-95
2.0%
9.0%
40.0%
29.0%
20.0%
100.0%
1995-00
2.0%
8.0%
40.0%
30.0%
20.0%
100.0%
2000-05
1.5%
7.0%
40.0%
30.5%
21.0%
100.0%
2005-10
1.0%
6.0%
40.0%
31.0%
22.0%
100.0%
2010-15
1.0%
5.0%
40.0%
31.5%
22.5%
100.0%
2015-20
0.5%
4.0%
40.0%
32.0%
23.5%
100.0%
2020-25
0.5%
3.0%
40.0%
32.0%
24.5%
100.0%
2025-50
0.5%
2.0%
40.0%
32.0%
25.5%
100.0%
Exhibit II-4:
Category
1
2
3
4
5
Total:
Total Waste Apportioned by Landfill Category (MT)
Base('90)
5,541
17,732
72,777
49,873
38,790
1 84,71 4"
1990-95
3,588
16,148
71,767
52,031
35,884
1 79,41 8b
1995-00
3,588
14,353
71,767
53,825
35,884
179,418
2000-05
2,691
12,559
71,767
54,722
37,678
179,418
2005-10
1,794
10,765
71,767
55,620
39,472
179,418
2010-15
1,794
8,971
71,767
56,517
40,369
179,418
2015-20
897
7,177
71,767
57,414
42,163
179,418
2020-25
897
5,383
71,767
57,414
43,957
179,418
2025-50
897
3,588
71,767
57,414
45,752
179,418
'•b Source: BioCycle, 1998.
' 1995-2050 estimates are based on the average of the beginning of 1990 to the beginning of 1995.
II.2 Costs For Implementing Electricity And Direct Gas Use
Projects
EPA uses different methods to estimate capital and operating and maintenance (O&M) costs for electricity gen-
eration and direct gas use. Exhibit II-5 presents the equations and assumptions used to calculate the total costs for
electricity generation and Exhibit II-6 presents those used for direct gas use projects.
Exhibit II-5: Landfill Gas-to-Energy Project Cost Factors For Electricity Generation Projects
Cost Component
Cost Factors or Equation
Comments
Collection System Capital Cost

Collection System O&M Annual Costs
[WIP(106MT)Fx $468,450

0.04 x Capital Cost + $49,019
The maximum amount of waste-in-place (WIP) during
the project lifetime is used to estimate the capital cost.
Flare System Capital Costs
Flare System O&M Costs
(Max Gas (ft3/min) x $31) + $64,828 Max Gas is the peak gas flow rate during the antici-
pated operating lifetime from the collection system in
cubic feet per minute.
1.697 x Max Gas (ft3/min) + $3,497
II-2 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 11-5: (continued)
Cost Component
Cost Factors or Equation
Comments
Electric System Capacity in Megawatts
Max Gas (ft3/min) x 500 Btu/ft3

10,000 Btu/kWhx1,000 kW/MW
Max Gas is the peak gas flow rate from the collection
system in cubic feet per minute. The heat rate of the
1C engine is 10,000 Btu/kWh. The landfill gas is 50%
methane, with a Btu content of 500 Btu/ft3.
Electric Generation System Capital Costs
Electric Generation System O&M Costs
Maximum of a) orb):
a) 1 Q0.903 xiog(MW) x 1,674,000 - Collec-
tion System Capital Costs; or
b) 1,200,000 xMW
$0.015 kWh
MW is the system capacity. Collection system costs
are as estimated above from the landfill WIP. Option
(a) developed from levelized costs and an 8% real
discount rate over 20 years.
All estimates in 1996 dollars.
Sources: EPA, 1991 a and 1991 b.
Exhibit II-6: Unit Costs for Direct Use Projects
System
Collection

Flare
Compression
Gas System

Pipeline
Capital
Component
Wells
Wellheads
Piping (main & branch)
Blowers
Condensate Knockout
Monitoring System
Flares
Compressor System Capital
Scrubber
Dessicator
Refrigeration
Filters
Gas Treatment Installation
Five-Mile Pipeline (12 inch di-
ameter)

Cost
$80 /foot of depth
$750 /wellhead
$35 /foot
$20/ft3/min
$8,000 / unit
$1,000 /unit
$75,000 / unit
$1,350/hp
$15/ft3/min
$10/ft3/min
$60/ft3/min
$3,220 /unit
$15/ft3/min
$35 /ft
O&M
Component
Collection System Variable O&M

Flare Fixed O&M
Compressor System Variable O&M
Gas Treatment Variable O&M
Gas Treatment Fixed O&M

Pipeline Variable O&M

Cost
$1,000 /acre3

$2,000 /yr
Calculatedb
$2.50 /mill ft3 /yr
$1 0,000 /yr

2% of capital cost
3 This number is calibrated in the Energy Project Landfill Gas Utilization Software (E-PLUS) so that the annual collection O&M cost for each
landfill is consistent with the annual collection O&M cost for electricity projects, i.e., within five to ten percent.
b The fixed O&M used in this analysis is calculated using the following formula: compressor qty (hp) x 8,760 (hrs/yr) x 0.7457 (hp-hr to kWh)
x $0.04 (price of electricity) + $12,000/unit/yr.
Source: E-PLUS, EPA, 1997.
II.3 Energy Prices
EPA translates a range of carbon equivalent values into energy prices to analyze how placing a value on reducing
emissions affects the cost-effectiveness of emission reductions from electricity generation. The equivalent elec-
tricity prices ($/kilowatt-hour (kWh)) for each carbon equivalent value ($/ton of carbon equivalent (TCE)) are
shown in Exhibit II-7. EPA calculates the electricity price at which landfill owners sell electricity by adding the
equivalent electricity prices to the market price of $0.04/kWh. These prices are also shown in Exhibit II-7. EPA
then evaluates each electricity price plus the additional value of carbon equivalent ($/TCE) to develop the MAC.
U.S. Environmental Protection Agency - September 1999
Appendix II: Landfills II-3
image:

Exhibit 11-7: Equivalent Electricity Prices for Carbon Equivalent Values
Carbon Equivalent Value ($fTCE)
$0 $10 $20 $30 $40 $50 $75 $100 $125 $150 $175 $200
$/kWh
$0.00 $0.01 $0.02 $0.03 $0.04 $0.05 $0.08 $0.11 $0.14 $0.16 $0.19 $0.22
Base Prices $0.04 $0.05 $0.06 $0.07 $0.08 $0.09 $0.12 $0.15 $0.18 $0.20 $0.23 $0.26

EPA uses a similar approach to calculate gas prices. A carbon equivalent value in $/TCE is converted into
$/million British thermal units (MMBtu). The equivalent gas prices for each carbon equivalent value are shown
in Exhibit II-8. EPA calculates the price at which landfill owners sell their gas by adding each equivalent gas
price to the market gas price of $2.74/MMBtu. EPA uses these gas prices plus the additional value of carbon
equivalent, shown in Exhibit II-8, to construct the MAC.
Exhibit II-8: Equivalent Gas Prices for Carbon Equivalent Values
Carbon Equivalent Value ($fTCE)
$0
$10 $20 $30 $40 $50 $75 $100 $125 $150 $175 $200
$/MMBtu
$0.00 $1.10 $2.20 $3.30 $4.40 $5.50 $8.25 $11.00 $13.75 $16.49 $19.24 $21.99
Base Prices $2.74 $3.84 $4.94 $6.03 $7.13 $8.23 $10.98 $13.73 $16.48 $19.23 $21.98 $24.73
II.4 Break-Even Waste-in-Place
In order to determine if direct gas use projects are cost-effective, EPA conducts a benefit-cost analysis and esti-
mates the break-even WIP for 84 gas prices. Each WIP and gas price combination is presented in Exhibit II-9. A
subset of these values is used to create the MAC presented in the Landfill Chapter (see Exhibit 2-11). These 84
gas prices reflect a range in energy values from 50 to 300 percent of base energy prices shown in Exhibit II-8.
Exhibit 11-9: Gas Price and Equivalent Break-Even WIP
Gas Price
($/MMBtu)
$1.37
$2.05
$2.47
$2.74
$3.15
$3.42
$3.57
$3.84
$4.10
$4.25
$4.52
$4.67
$4.94
$5.20
$5.35
$5.47
$5.62
Break-Even WIP
(MT)
10,733,415
2,330,467
985,447
972,739
953,057
940,349
933,376
920,668
907,960
900,986
837,428
800,200
749,467
698,987
675,817
656,765
633,595
Gas Price
($/MMBtu)
$7.82
$8.21
$8.23
$8.50
$8.77
$8.92
$9.31
$9.60
$9.62
$9.87
$10.30
$10.41
$10.97
$10.98
$11.51
$11.67
$12.35
Break-Even WIP
(MT)
419,389
394,982
393,655
380,051
366,448
358,983
341,640
330,039
329,523
319,468
302,581
298,865
283,826
283,477
269,487
265,202
247,859
Gas Price
($/MMBtu)
$16.47
$16.48
$17.17
$17.85
$17.86
$18.55
$19.20
$19.22
$19.23
$19.91
$20.60
$20.61
$21.30
$21.95
$21.97
$21.98
$22.66
Break-Even WIP
(MT)
183,036
182,893
175,391
167,889
167,746
160,244
153,030
152,886
152,742
147,367
143,216
143,137
138,986
134,995
134,915
134,836
130,685
II-4 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 11-9: (continued)
Gas Price
($/MMBtu)
$5.77
$6.03
$6.30
<hr* A c
$6.45
<hr* c~7
$6.57
$6.72
$6.87
$7.13
$7.40
$7.55
$7.67
Break-Even WIP
(MT)
610,424
576,422
545,669
530,436
517,911
502,678
490,135
468,324
447,136
437,304
429,221
Gas Price
($/MMBtu)
$12.36
$12.61
$13.05
$13.71
$13.72
$13.73
$14.42
$15.10
$15.11
$15.80
$16.46
Break-Even WIP
(MT)
247,615
243,106
234,879
222,631
222,387
222,143
209,407
198,039
197,896
190,394
183,180
Gas Price
($/MMBtu)
$23.35
$23.36
$24.04
$24.70
$24.72
$24.73
$25.41
$26.10
$27.45
$27.46
$30.20
Break-Even WIP
(MT)
126,535
126,456
122,305
118,313
118,234
118,155
114,004
109,854
101,632
101,553
95,459
II.5 Marginal Abatement Curve
EPA evaluates the cost-effectiveness of LFGTE systems for the combinations of electricity and gas prices. The
amounts of abated methane for 2000, 2010, and 2020 are displayed in Exhibit 11-10 and Exhibit II-11. Exhibit II-
10 shows the abated methane in million metric tons of carbon equivalent (MMTCE) and Exhibit II-11 shows the
abated methane as a percent of the baseline. In each exhibit, the abated methane is incremental to methane abated
as a result of the Landfill Rule. EPA estimates the percent abated methane as the emission reductions divided by
the baseline emissions for the individual years. The baseline emissions are the emissions that would occur after
the Landfill Rule emission reductions are taken into account. Each percent of abated methane represents cost-
effective emission reductions for the combination of gas and electricity prices plus the added value of carbon
equivalent. The market price, with no added value of carbon equivalent, is represented by $0/TCE.
An example of how percent abated methane is estimated at a combination of energy prices plus an additional car-
bon equivalent value is as follows. At S20/TCE in 2010, the emission reduction incremental to the Landfill Rule
is 20.2 MMTCE and the electricity and gas prices are $0.06/kWh ($0.04/kWh + $0.02/kWh) and $4.94/MMBtu
($2.74/MMBtu + $2.20/MMBtu), respectively. The percent of abated methane at this combination of energy
prices is 39%. This value is calculated as indicated in Exhibit 11-12.
Exhibit 11-10:

2000
2010
2020
Emission

$0
11.03
10.55
7.62
Reductions Incremental to the Landfill Rule by Year (MMTCE)

$10
14.08
14.44
10.12

$20
18.21
20.23
13.88

$30
19.74
21.45
15.00
Carbon
$40
20.13
21.75
15.46
Equivalent Value ($/TCE)
$50
20.55
21.85
15.69
$75 $100
21.23 21.41
21.90 21.91
15.84 15.88
$125
21.49
21.91
15.88
$150
21.56
21.91
15.90
$175
21.61
21.91
15.90
$200
21.66
21.91
15.92

Exhibit 11-11:

2000
2010
2020
Emission Reductions Incremental to

$0
21%
20%
19%

$10
27%
28%
25%

$20
35%
39%
34%

$30
38%
41%
37%
Landfill
Carbon
$40
39%
42%
38%
Rule by Year (Percent of Baseline
Emissions)
Equivalent Value ($/TCE)
$50
40%
42%
38%
$75 $100
41% 42%
42% 42%
39% 39%
$125
42%
42%
39%
$150
42%
42%
39%
$175
42%
42%
39%
$200
42%
42%
39%
U.S. Environmental Protection Agency - September 1999 Appendix II: Landfills II-5
image:

Exhibit 11-12: Percent Reduction - Example Calculation
Total Emissions from Landfills in 2010" 52.0 MMTCE (see Exhibit 2-6 in Chapter 2)
Landfill Rule Reductions in 2010 31.8 MMTCE (see Exhibit 2-6 in Chapter 2)
Total reductions incremental to the Landfill Rule in 2010 at $20ATCE 20.2 MMTCE (See Exhibit 11-10)
Percent reduction in 2010 at $20/TCE (20.2 / 52.0) MMTCE = 39 %
aThis value accounts for reductions associated with landfills that are impacted by the Landfill Rule.

The methane abatement potential for non-Rule landfills in 2020 is slightly less than in the previous years because
the Landfill Rule plays an increasingly large role in reducing emissions in the future. New landfills simulated to
open are estimated to be larger (on average) than existing landfills. These larger landfills are expected to trigger
under the Landfill Rule and, consequently, emissions decline in the future.
The collection efficiency for all landfill methane recovery projects, whether required by the Landfill Rule or not,
is 75 percent. However, the percent of abated methane, even at high carbon equivalent values, is lower than 75
percent (see Exhibit 11-11) due to EPA's methodology for estimating the percent of abated methane beyond regu-
lation requirements. As indicated in Exhibit 11-11, even at high additional carbon equivalent values, further
abatement is not achieved as methane emissions cannot be collected with 100 percent efficiency. The example in
Exhibit 11-13 illustrates this concept.
The analysis evaluates the percent of abated methane from non-impacted landfills against baseline emissions.
Baseline emissions represent a conglomerate of four sources: (1) methane from landfills not impacted by the
Landfill Rule; (2) residual methane not recovered from landfills that are impacted by the Landfill Rule, i.e., meth-
ane that is emitted due to 75 percent collection efficiency and not captured by the gas collection system; (3)
methane from industrial landfills; and (4) methane from small landfills. Consequently, the baseline emission
value includes emissions from landfills impacted by the Landfill Rule that cannot further reduce emissions.1

Exhibit 11-13: Calculating Percent Reductions - Hypothetical Example
> Emissions from landfills not impacted by the Landfill Rule:
Base emissions = 10.0 MMTCE
After installing LFGTE system = 2.5 MMTCE
Emissions reduced = 7.5 MMTCE
> Emissions from landfills impacted by the Landfill Rule:
Prior to installing LFGTE system = 20.0 MMTCE
Base emissions (after installing LFGTE system) = 5.0 MMTCE
> Base:
Emissions from landfills not impacted by the Landfill Rule plus resulting emissions from landfills impacted by Landfill Rule =
(10.0+ 5.0 = 15.0) MMTCE
> Percent emissions reduced due to implementing cost-effective LFGTE:
Emissions reduced from landfills not impacted by rule divided by base = (7.5/15.0) MMTCE = 50 %

II.6 Uncertainties
Exhibit 11-14 outlines the uncertainties with the methane estimation approach and Exhibit 11-15 describes the un-
certainties with the MAC.
1 As the share of landfills impacted by the Rule increases over time, fewer emission reductions are achieved beyond
the Landfill Rule requirements, i.e., the percent reduction approaches zero.

11-6 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 11-14: Emission Estimate Uncertainties
Basis
Characterization of landfills and total
WIP
Future waste disposal
Gas equation used for estimating meth-
ane emissions
Recovery prior to 1997
Flare-only option

Industrial waste landfilled

Methane oxidation rate
A simulation characterizes the entire U.S. landfill population based on characterizations of a subset
of U.S. landfills, including size, waste acceptance rate, and opening year.
Future waste disposal is assumed to remain constant at the average rate from the beginning of
1990 to the beginning of 1995. This average is based on the assumption that waste generation
increases along with population, but will subsequently be offset by increases in alternative disposal
methods such as recycling and composting.
Emission factors are derived from data on 85 U.S. landfills and are applied based on landfill WIP.

Recovery rates (after flared methane is accounted for) are assumed to remain constant at 1990
levels for 1991 and at 1992 levels for 1993 to 1997. In addition, the gas collected but not utilized is
assumed to equal 25 percent of the methane recovery.
For years following 1997, the analysis lacks sufficient information about the population of landfills
that flare without recovering methane for energy use.
Industrial methane production is assumed to equal approximately seven percent of MSW landfill
methane production.
Ten percent of methane generated is assumed to oxidize in soil.
Exhibit 11-15: Cost Analysis Uncertainties
Basis
Cost estimate

Revenue

Potential for landfills to collect and use
gas cost-effectively
Methane recovery technologies

Equipment and engineering costs
Costs are estimated using aggregate cost factors and a relatively simple set of landfill character-
istics. Electricity costs are estimated using representative WIP. Direct use costs are estimated
using hypothetical landfills in terms of depth, area, and WIP.
The rate at which electricity is sold from a landfill project depends on local and regional electric
power market conditions and often varies by time of day and season of year. However, this
analysis uses a representative figure that remains constant.
The extent to which electricity production and direct gas use are cost-effective depends on the
energy price and availability of end-users.
This analysis only focuses on internal combustion (1C) generators and direct gas use because
they are the most cost-effective technologies for projects examined in this analysis. However,
other technologies are available, e.g., electricity generation using turbine generators.
Information is based on current projects and industry experts.
U.S. Environmental Protection Agency - September 1999
Appendix II: Landfills II-7
image:

11.7 References
EPA. 1988. National Survey of Solid Waste (Municipal) Landfill Facilities, Office of Solid Waste, U.S. Envi-
ronmental Protection Agency, Washington, DC, EPA 530-SW-88-011.
EPA. 1991a. Analysis of Profits and Cost from Regulating Municipal Solid Waste Landfills. March 28, 1991.
Memorandum from Kathleen Hogan, Chief, Methane Programs to Alice Chow, Office of Air Quality Plan-
ning and Standards, U.S. Environmental Protection Agency, Washington, DC, EPA A-88-09/11-B-45.
EPA. 1991b. Air Emissions from Municipal Solid Waste Landfills - Background Information for Proposed Stan-
dards and Guidelines. Emissions Standards Division, Office of Air Quality Planning and Standards, U.S. En-
vironmental Protection Agency, Research Triangle Park, NC, EPA 450-3-90-011.
EPA. 1992. Landfill Gas Energy Utilization: Technology Options and Case Studies. Air and Energy Engineer-
ing Research Laboratory, U.S. Environmental Protection Agency, Research Triangle Park, NC, EPA 600-R-
92-116.
EPA. 1993. Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress.
Atmospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental Protection
Agency, Washington, DC, EPA 430-R-93-003. (Available on the Internet at http://www.epa.gov/ghginfo/ re-
ports .htm.)
EPA. 1997. Energy Project Landfill Gas Utilization Software (E-PLUS), Project Development Handbook. At-
mospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environmental Protection
Agency, Washington, DC, EPA 430-B-97-006. (Available on the Internet at http://www.epa.gov/lmop/ prod-
ucts.htm.)
GAA. 1994. 1994-1995 Methane Recovery from Landfill Yearbook. Government Advisory Associates, Inc.,
New York, NY.
Glenn, Jim. 1998. BioCycle Nationwide Survey: The State of Garbage in America. BioCycle, no.4.
11-8 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Appendix III: Supporting Material for the
Analysis of Natural Gas
Systems
This appendix presents the detailed data that EPA used to develop methane emission forecasts and to
estimate emission reduction costs. Exhibits III-l and III-2 describe the emission factors, activity factors,
and the activity factor drivers used to estimate annual changes in emissions and for forecasting future
emissions. Exhibits III-3 and III-4 describe the specific options available for reducing emissions from
gas systems. A summary of the costs of the specific options is summarized in Exhibits III-5 and III-6.
Finally, Exhibit III-7 presents the data used to generate the marginal abatement curve for natural gas
systems. The exhibits are summarized below.

> Exhibit III-l: Activity Factors and Emission Factors. This exhibit summarizes the activity and
emission factors and the resulting emissions by source for 1992, which is the year covered by the
EPA/GRI 1996 report, and the year on which emission estimates for all other years are based
(EPA/GRI, 1996). For this analysis, the natural gas industry is divided into sectors: production, gas
processing, transmission, and distribution. Within each sector, emissions are categorized as fugitives
(leaks) and vented and combusted. Each line represents an emission source in the industry and
sector. The emissions, expressed in tons of methane, are the product of the activity factor and the
annualized emission factor, which is expressed in cubic feet of methane (standard cubic feet per day
(scfd); thousand standard cubic feet per year (Mscfy)).

> Exhibit III-2: Driver Variables. The activity drivers and sources for the driver estimates are listed
in this exhibit. Activity drivers are used to estimate emissions based on changes in characteristics of
the natural gas industry. These characteristics include gas production, gas consumption, customers,
miles of pipeline, number of wells, distribution infrastructure and other variables. The sources of
data are primarily from publications produced by the Energy Information Administration, the
American Petroleum Institute, and the Independent Petroleum Association of America.

> Exhibit III-3: Best Management Practices. This exhibit presents the Best Management Practices
(BMPs) that EPA used to develop the cost curves for reducing methane emissions from the natural
gas industry. The BMPs were identified by the Natural Gas STAR Program, a voluntary industry-
EPA partnership created to identify cost-effective technologies and practices to reduce methane
emissions.

> Exhibit III-4: Partner-Reported Opportunities. This exhibit presents the Partner-Reported
Opportunities (PROs) that EPA used to develop the cost curves for reducing methane emissions from
the natural gas industry. The PROs were identified by the Natural Gas STAR industry Partners as
part of their efforts to reduce methane emissions cost-effectively.

> Exhibit III-5: Cost Analysis Data and Assumptions for Best Management Practices. This
exhibit describes the BMPs in terms of their applicability to the natural gas industry, potential
emission reductions once applied, capital and operation and maintenance costs, and break-even gas
price.

> Exhibit III-6: Cost Analysis Data and Assumptions for Partner-Reported Opportunities. This
exhibit describes the PROs in terms of their applicability to the natural gas industry, potential
U.S. Environmental Protection Agency - September 1999 Appendix III: Natural Gas Systems 111-1
image:

emission reductions once applied, capital and operation and maintenance costs, and break-even gas
price.
Exhibit III-7: Schedule of Emission Reduction Options for 2010. The 118 emission reduction
options used to generate the marginal abatement curve (MAC) for reducing methane emissions from
U.S. natural gas systems are provided in this exhibit. All options are described in terms of their
break-even gas price, base gas price type, value of carbon equivalent required in addition to the base
gas price to make the option cost-effective, and incremental emission reduction.
11-2 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 111-1: Activity Factors and Emission
Segment
PRODUCTION
Normal Fugitives
Gas Wells (Eastern on shore)
Appalachia (all non-associated)
N. Central
Associated Gas Wells
Non-Associated Gas Wells
Field Sep. Equip. (Eastern on shore)
Heaters
Separators
Appalachia
N. Central
Gathering Compressors
Small Reciprocating Compressor
Appalachia
N. Central
Associated Gas
Non-Associated Gas
Meters/Piping
Dehydrators
Gas Wells (Rest of U.S. on shore)
Associated Gas Wells Rest of U.S.
Gulf of Mexico Off-Shore Platforms
Rest of U.S. (Off-Shore platforms)
Field Separation Equipment - Rest of U.S.
On Shore
Heaters
Separators
Gathering Compressors
Small Reciprocating Compressor
Large Reciprocating Compressor
Large Reciprocating Compressor
Meters/Piping
Dehydrators
Pipeline Leaks
Vented and Combusted
Drilling and Well Completion
Completion Flaring
Normal Operations
Pneumatic Device Vents
Chemical Injection Pumps
Kimray Pumps
Dehydrator Vents
Compressor Exhaust Vented
Gas Engines
Routine Maintenance
Well Workovers
Gas Wells
Well Clean Ups (LP Gas Wells)
Slowdowns
Vessel BD
Pipeline BD
Compressor BD
Compressor Starts
Upsets
Pressure Relief Valves
Factors3
Activity
Factor

1 23,585 b

3,507 b
4,977 b

260

79,377
12,293

4,943

270b
324 b
11,693
674
142,771 b
256,226b
1,350b
22 b

50,740
74,670

16,91 5 b
96
12
177,438
24,289
340,200

400 b

249,111 b
16,971
7,380,194
8,200,215

27,460 b

9,392
114,139

242,302
340,200
17,112
17,112

529,440 b

Units

wells

wells
wells

heaters

separators
separators

compressors

compressors
compressors
meters
dehydrators
wells
wells
platforms
platforms

heaters
separators

compressors
compressors
stations
meters
dehydrators
miles

compl/yr

controllers
active pumps
MMscf/yr
MMscf/yr

MMHPhr

w.o./yr
LP gas wells

vessels
miles (gath)
compressors
compressors

PRV

Emission
Factor

7.11

-
7.11

14.21

0.90
0.90

12.10

12.10
12.10
9.01
21.75
36.40
-
2,914.00
1,178.00

57.70
122.00

267.80
15,205.00
8,247.00
52.90
91.10
53.20

733.00

345.00
248.05
992.00
275.57

0.24

2,454.00
49,570.00

78.00
309.00
3,774.00
8,443.00

34.00

Units

scfd/well

scfd/well
scfd/well

scfd/heater

scfd/sep
scfd/sep

scfd/comp

scfd/comp
scfd/comp
scfd/meter
scfd/dehy
scfd/well
scfd/well
scfd/plat
scfd/plat

scfd/heater
scfd/sep

scfd/comp
scfd/comp
scfd/station
scfd/meter
scfd/dehy
scfd/mile

scf/comp

scfd/device
scfd/pump
scf/MMscf
scf/MMscf

scf/HPhr

scfy/w.o.
scfy/LP well

scfy/vessel
scfy/mile
scfy/comp
scfy/comp

scfy/PRV

Emissions
(Tons of Methane)
1,476,877

6,157.85

-
247.99

25.89

500.64
77.54

419.18

22.93
27.48
738.30
102.73
36,419.53
-
27,568.77
181.62

20,517.14
63,841.09

31,745.18
10,229.44
693.54
65,780.56
15,506.55
126,835.09

5.63

602,291.32
29,501.85
140,566.12
43,386.88

126,535.33

442.52
108,630.91

362.87
2,018.34
1,239.95
2,773.96

345.62
U.S. Environmental Protection Agency - September 1999
Appendix III: Natural Gas Systems III-3
image:

Exhibit 111-1: Activity Factors and Emission Factors3 (continued)
Segment
PRODUCTION (continued)
Vented and Combusted (continued)
ESD
Mishaps
GAS PROCESSING PLANTS
Normal Fugitives
Plants
Recip. Compressors
Centrifugal Compressors
Vented and Combusted
Normal Operations
Compressor Exhaust
Gas Engines
Gas Turbines
AGR Vents
Kimray Pumps
Dehydrator Vents
Pneumatic Devices
Routine Maintenance
Blow downs/Venting
Fugitives
Pipeline Leaks
Compressor Stations (Trans.)
Station
Recip Compressor
Centrifugal Compressor
Compressor Stations (Storage)
Station
Recip Compressor
Centrifugal Compressor
Wells (Storage)
M&R (Trans. Co. Interconnect)
M&R (Farm Taps + Direct Sales)
Vented and Combusted
Normal Operation
Dehydrator Vents (Transmission)
Dehydrator Vents (Storage)
Compressor Exhaust
Engines (Transmission)
Turbines (Transmission)
Engines (Storage)
Turbines (Storage)
Generators (Engines)
Generators (Turbines)
Pneumatic Devices Trans + Storage
Pneumatic Devices Trans
Pneumatic Devices Storage
Routine Maintenance/Upsets
Pipeline Venting
Station venting Trans + Storage
Station Venting Transmission
Station Venting Storage
Activity
Factor

1,372
340,200

726b
4,092 b
726b

27,460 b
32,91 Ob
371
957,930
8,630,003 b
726

726

284,500 b

1,700
6,799
681

386 b
1,135
111
17,999
2,532
72,630

1,086,001
2,000,001 b

40,380 b
9,635 b
4,922 b
1,729b
1,976b
23 b

68,103
15,460

284,500

1,700
386
Units

platforms
miles

plants
compressors
compressors

MMHPhr
MMHPhr
AGR units
MMscf/yr
MMscf/yr
gas plants

gas plants

miles

stations
compressors
compressors

stations
compressors
compressors
wells
stations
stations

MMscf/yr
MMscf/yr

MMHPhr
MMHPhr
MMHPhr
MMHPhr
MMHPhr
MMHPhr

devices
devices

miles

cmp stations
cmp stations
Emission
Factor

256,888.00
669.00

7,906.00
11,196.00
21,230.00

0.24
0.01
6,083.00
177.75
121.55
164,721.00

4,060.00

1.54

8,778.00
15,205.00
30,305.00

21,507.00
21,116.00
30,573.00
114.50
3,984.00
31.20

93.72
117.18

0.24
0.01
0.24
0.01
0.24
0.01

162,197.00
162,197.00

31.65

4,359.00
4,359.00
Units

scfy/plat
scfy/mile

scfd/plant
scfd/comp
scfd/comp

scf/HPhr
scf/HPhr
scfd/AGR
scf/MMscf
scf/MMscf
scfy/plant

Mscfy/plant

scfd/mile

scfd/station
scfd/comp
scfd/comp

scfd/station
scfd/comp
scfd/comp
scfd/well
scfd/station
scfd/station

scf/MMscf
scf/MMscf

scf/HPhr
scf/HPhr
scf/HPhr
scf/HPhr
scf/HPhr
scf/HPhr

scfy/device
scfy/device

Mscfy/mile

Mscfy/station
Mscfy/station
Emissions
(Tons of Methane)

6,767.05
4,369.79
697,555

40,224.08
321,066.39
108,014.07

126,535.45
3,601.67
15,814.96
3,269.22
20,140.36
2,296.07

56,592.96

3,072.41

104,605.04
724,478.87
144,629.14

58,178.33
167,958.35
23,782.37
14,442.69
70,694.51
15,880.59

1,954.18
4,499.71

186,071.04
1,054.45
22,680.58
189.22
9,105.42
2.55

212,084.78
48,145.26

172,884.96

142,315.12
32,305.42
III-4
U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 111-1: Activity Factors and Emission Factors3 (continued)
Segment
Activity
Factor
Units
Emission
Factor
Units
Emissions
(Tons of Methane)
TRANSMISSION 2,228,280
LNG Storage
LNG Stations 64b stations 21,507.00 scfd/station 9,646.15
LNG Reciprocating Compressors 246b compressors 21,116.00 scfd/comp 36,403.31
LNG Centrifugal Compressors 58b compressors 30,573.00 scfd/comp 12,426.82
LNG Compressor Exhaust
LNG Engines 741b MMHPhr 0.24 scf/HPhr 3,414.53
LNG Turbines 162b MMHPhr 0.01 scf/HPhr 17.73
LNG Station Venting 64 cmp stations 4,359.00 Mscfy/station 5,356.34

DISTRIBUTION 1,495,565
Normal Fugitives
Pipeline Leaks
Mains - Cast Iron 55,288b miles 238.70 Mscf/mile-yr 253,387.12
Mains - Unprotected Steel 82,109b miles 110.19 Mscf/mile-yr 173,706.87
Mains - Protected Steel 444,768 miles 3.12 Mscf/mile-yr 26,623.73
Mains - Plastic 254,595 miles 19.30 Mscf/mile-yr 94,324.89
Total Pipeline Miles 836,760b
Services - Unprotected Steel 5,446,393b services 1.70 Mscf/service 177,815.33
Services Protected Steel 20,352,983b services 0.18 Mscf/service 69,000.53
Services - Plastic 17,681,238 services 0.01 Mscf/service 3,161.82
Services - Copper 233,246b services 0.25 Mscf/service 1,138.36
Total Services 43,713,860b
Meter/Regulator (City Gates)
M&R>300psi 3,580 stations 179.80 scfh/station 108,277.61
M&R 100-300 psi 13,799 stations 95.60 scfh/station 221,882.88
M&R<100psi 7,375 stations 4.31 scfh/station 5,346.34
Reg>300psi 4,134 stations 161.90 scfh/station 112,573.59
R-Vault >300 psi 2,428 stations 1.30 scfh/station 530.82
Reg 100-300 psi 12,700 stations 40.50 scfh/station 86,512.45
R-Vault 100-300 psi 5,706 stations 0.18 scfh/station 172.75
Reg 40-100 psi 37,593 stations 1.04 scfh/station 6,575.79
R-Vault 40-100 psi 33,337 stations 0.09 scfh/station 485.01
Reg<40psi 15,913 stations 0.13 scfh/station 355.96
Customer Meters
Residential 40,049,306b outdr meters 138.50 scfy/meter 106,499.11
Commercial/Industry 4,607,983b meters 47.90 scfy/meter 4,237.87
Vented
Routine Maintenance
Pressure Relief Valve Releases
Pipeline Slowdown
Upsets
Mishaps (Dig-ins)
TOTAL
836,760
1, 297,569 b
1,297,569

mile main
Miles
miles

0.05
0.10
1.59

Mscf/mile
Mscfy/mile
mscfy/mile

803.29
2,541.16
39,612.18
5,898,278
a Data are for base year 1992, the year covered by the EPA/GR11996 report, and the year from which emission estimates for all other years
are based.
b Main driver for the emission inventory.
Source: EPA/GRI, 1996.
U.S. Environmental Protection Agency - September 1999
Appendix III: Natural Gas Systems III-5
image:

Exhibit 111-2: Driver Variables
Variable
Units
Source
Dry Gas Production: National Total
Tcf/yr
Dry Gas Production: National Total minus Alaska Tcf / yr
Gas Production: Alaska Tcf / yr

Gas Consumption: National Total Tcf / yr

Gas Consumption: Residential Tcf / yr

Gas Consumption: Commercial Tcf / yr

Gas Consumption: Industrial Tcf / yr

Gas Consumption: Electrical Generators Tcf / yr

Gas Consumption: Lease and Plant Fuel Tcf / yr

Gas Consumption: Pipeline Fuel Tcf / yr

Gas Consumption: Transportation Tcf / yr

Transmission Pipelines Length Miles
Appalachia Wells Wells
North Central Associated Wells Wells

North Central Non-Associated Wells Wells
Rest of U.S. Wells Wells
Rest of U.S. Associated Wells Wells

Appalachia, North Central (Non-Associated), and Wells
Rest of U.S.
Gulf of Mexico Off-Shore Platforms Platforms
Rest of U.S. Off-Shore Platforms Platforms

North Central (Non-associated) and rest of U.S. Wells
Number of Gas Plants Plants
Distribution Mains - Cast Iron Mains
Distribution Mains - Unprotected Steel Miles
Distribution Mains - Protected Steel Miles
Distribution Mains - Plastic Miles
Services - Unprotected Steel Services
Services - Protected Steel Services
Services - Plastic Services
Services - Copper Services
EIA (www.eia.doe.gov), Natural Gas Monthly, Table of Supply
and Disposition of Dry Natural Gas in the United States, 1992-
1997
Calculated, based on an estimate of gas production in Alaska
Estimate, based on EIA data (www.eia.doe.gov), Natural Gas
Monthly, Table of Marketed Production of Natural Gas By State
EIA (www.eia.doe.gov), Natural Gas Monthly, Table of Natural
Gas Consumption in the United States, 1992-1997
EIA (www.eia.doe.gov), Natural Gas Monthly, Table of Natural
Gas Consumption in the United States, 1992-199
EIA (www.eia.doe.gov), Natural Gas Monthly, Table of Natural
Gas Consumption in the United States, 1992-1997
EIA (www.eia.doe.gov), Natural Gas Monthly, Table of Natural
Gas Consumption in the United States, 1992-1997
Estimate, based on EIA data (www.eia.doe.gov), Natural Gas
Monthly, Table of Natural Gas Deliveries to Electric Utility
Consumers
EIA (www.eia.doe.gov), Natural Gas Monthly, Table of Natural
Gas Consumption in the United States, 1992-1997
EIA (www.eia.doe.gov), Natural Gas Monthly, Table of Natural
Gas Consumption in the United States, 1992-1997
NGA1993 (1990-1992) & NGA97 (1993-two years before
current year), Table 1 - Summary Statistics
American Gas Association, Gas Facts
IPAA, 777e Oil and Gas Producing Industry in Your State
Calculated as 8.6% of oil wells reported in IPAA, The Oil and
Gas Producing Industry in Your State
IPAA, 777e Oil and Gas Producing Industry in Your State
IPAA, 7"/7e Oil and Gas Producing Industry in Your State
Calculated as 46.1% of oil wells reported in IPAA, The Oil and
Gas Producing Industry in Your State
Calculated using data for two years prior to 1997

Minerals Management Service
May include platforms off the shore of Alaska, Minerals
Management Service
Calculated using data for two years prior to 1997
Oil and Gas Journal
American Gas Association, Gas Facts
American Gas Association, Gas Facts
American Gas Association, Gas Facts
American Gas Association, Gas Facts
American Gas Association, Gas Facts
American Gas Association, Gas Facts
American Gas Association, Gas Facts
American Gas Association, Gas Facts
III-6
U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 111-3: Best Management Practices
Best Management Practice
Description
Replace or repair high bleed
pneumatics devices with low bleed
devices
High bleed rate pneumatic devices that employ gas to operate the actuators are
ubiquitous in the industry and are a major source of emissions. Replacing them with
low bleed devices where possible reduces emissions considerably.
Practice directed inspection and
maintenance of compressor stations
Compressor stations have a vast number of pipes, valves, and other equipment that
leaks. As with gate stations, a very few leaks account for the total volume of
emissions. The same strategy applied to compressor stations will reduce the vast
majority of emissions at a low cost.
Reduce glycol recirculation rates on
glycol dehydrators
Glycol dehydrators remove water from gas at the wellhead. The glycol also absorbs
methane, which is vented to the atmosphere when the glycol is regenerated, at a rate
directly proportional to the glycol circulation rate. Glycol is often over-circulated.
Proper circulation rates can achieve pipeline water content requirements and reduce
methane emissions.
Install flash tanks on glycol
dehydrators
Glycol dehydrators remove water from gas at the wellhead. The glycol also absorbs
methane, which is vented to the atmosphere when the glycol is regenerated. Flash
tanks capture 90 percent of the methane before it reaches the reboiler.
Install fuel gas retrofit systems on
compressors to capture otherwise
vented fuel when compressors are
taken off-line
When compressors are not running and are taken "offline," they are often purged of
the gas in the compression chambers and isolated from the high-pressure pipeline
with much leakage occurring at the isolation valves. Keeping the isolated compressor
pressurized and bleeding off the gas into a fuel gas system reduces losses to the
atmosphere.
Install static-seal compressor rod
packing on reciprocating compressors
Compressor rod packing keeps gas from the compressor from escaping along the
shaft into the compressor housing. Packing leaks are greater while compressors are
off-line and remain pressurized. Static-packs clamp down on the compressor rod
when compressors are idle to reduce leakage.
Install dry seal systems on centrifugal
compressors
Centrifugal compressors have elaborate sealing systems to keep high-pressure gas in
the compressor from escaping. Wet seal systems use high-pressure oil as the seal.
The oil absorbs gas and which is vented when the sealing oil is circulated. Dry seal
systems use high pressure air to establish a seal and avoid these losses.
Practice early replacement of rings and By using company-specific financial objectives and monitoring data, natural gas
rods on centrifugal compressors transmission companies can determine emission levels at which it is cost effective to
replace rings and rods.
Practice directed inspection and
maintenance of gate stations and
surface facilities
Gate Stations are where high transmission pipeline pressures are dropped down to
distribution system pressures; other surface facilities also regulate pipeline pressures.
Emissions occur at the equipment, joints, valves at these facilities. A few stations and
equipment types account for most of the emissions. Directed inspection and
maintenance uses leak rate data and economic criteria to focus repairs on the
costliest leaks.
U.S. Environmental Protection Agency - September 1999
Appendix III: Natural Gas Systems
II-7
image:

Exhibit 111-4: Partner-Reported Opportunities
Partner-Reported Opportunities
Description
Practice directed inspection and maintenance of
production sites, processing sites, transmission
pipelines and liquid natural gas stations
Practice enhanced directed inspection and
maintenance at production sites, surface facilities,
storage wells, off-shore platforms and compressor
stations
Install electric starters on compressors
Install plunger lifts at production wells
Use capture vessels for blowdowns at processing
plants and other facilities

Install instrument air systems
Use portable evacuation compressors for pipeline
repairs

Install catalytic converter on compressor engines
Use electronic metering

Replace cast iron distribution mains with protected
steel or plastic pipe
Replace cast iron distribution services with
protected steel or plastic pipe
Emissions occur at the equipment, joints, valves at these facilities.
Directed inspection and maintenance uses leak rate data and economic
criteria to focus repairs on the costliest leaks.
Enhanced DI&M is a more aggressive DI&M program that involves
increased frequency of survey and repair. Enhanced DI&M costs more
but also achieves greater savings by further reducing gas leaks.

Compressor engines are often started using a blast of high-pressure
natural gas. Electric starters can replace these gas starters and avoid
methane emissions.
As gas fields mature, fluids can accumulate in the wellbore and the weight
of these fluids can impede gas production. Accumulated fluids can be
removed by swabbing, soaping, or "blowing down" the well, but these
operations often emit large volumes of methane to the atmosphere. A
plunger lift allows fluids to be removed without emitting methane. The
plunger acts as a bottom-hole plug, and the pressure of the reservoir
builds and slowly lifts the plunger to the surface. As the plunger is lifted,
the reservoir fluid above it is also lifted. Plunger lifts prolong well life,
increase productivity and reduce methane emissions.
A capture vessel can be used during blowdowns to avoid venting
methane to the atmosphere. The captured natural gas can be re-routed
to pipelines or used on-site as fuel.
Methane leaks from pneumatic devices can be avoided by installing
instrument air systems which open and close valves using electricity
instead of pressure from gas systems.
A portable compressor can be used to evacuate the gas in an area of
blocked-off pipeline that is about to be repaired. This gas can be re-
routed to the pipeline.
A catalytic converter is an afterburner that reduces pollution from
incomplete fuel combustion. Methane is combusted, and the energy from
combustion is unused, so benefits are restricted to the value placed on
reducing methane emissions.
Replacing old pneumatic-based meter runs at gate stations with electronic
meters will reduce methane emissions.
Cast iron and unprotected steel pipeline is replaced with materials less
prone to corrosion and leaks.
Cast iron services are replaced with materials less prone to corrosion and
leaks.
111-8
U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 111-5: Cost Analysis Data and Assumptions for Best Management Practices
Best Management Practice Applicability and Emission Reductions
Costs
Break-Even Gas Price (S/MMBtu)
Replace high-bleed
pneumatics with low-bleed
pneumatics
Practice directed inspection
and maintenance at
compressor stations

Use static-seal compressor rod
packing
Reduce glycol recirculation
rates on dehydrators
Install flash tank separators on
glycol dehydrators
Use fuel gas retrofits
Applicability: 50%-90% of pneumatic systems in the production
and transmission sector
Emission Reduction: 50%-90%; for all sectors, applicability and
emission reductions are higher for high-bleed devices
For the production sector, 6 cases were examined (low-med.-high
bleed; intermittent & continuous)
For the transmission sector, 9 cases were examined (low-med.-
high bleed; continuous, turbine & displacement)
Applicability: 100% of compressor stations in the transmission
sector
Emission Reduction: 12%

Applicability: 100% of reciprocating compressors in the
transmission sector
Emission Reduction: 6.0% of emissions from storage compressor
stations, 8.7% of emissions from transmission compressor stations
Applicability: 100% of dehydrators in production, processing and
transmission sector
Emission Reduction: 30-60% of emissions from production and
processing, 30% of emissions from transmission
For the production and processing sectors, 4 cases were examined
(with/ & without flash tanks; with & without pumps)
Applicability: 100% of glycol dehydrators without flash tanks in the
production, processing and transmission sectors
Emission Reduction: For the production and processing sectors,
12%-63% of emissions from dehydrator vents and 63% of
emissions from Kimray pumps; for the transmission sector, 90% of
emissions from dehydrators with gas-assisted pumps, 30% of
emissions from dehydrators without gas-assisted pumps
Applicability: 100% of reciprocating compressors in the
transmission sector
Emission Reduction: 36% of emissions from reciprocating
compressors in the transmission sector, 21.3% of emissions from
reciprocating compressors in gas processing plants
Capital: $750/device ($1,500 per
device x 0.5 to reflect early
replacement)
Annual O&M: $150
Capital: $5,000/station instrument
spread across 10 facilities yielding
$500/facility
Annual O&M: $2,065/station
Capital: $3,000/compressor
Annual O&M: none
Capital: $0
Annual O&M: $50/dehydrator
Capital: $8,000/dehydrator
Annual O&M: None
Capital: $1,250/compressor
Annual O&M: None
$0.49-$18.00 for the production sector; break-even
gas prices are lower for high-bleed devices
$0.20-$318 for the transmission sector; break-even
gas prices are lower for high-bleed devices
$0.55 for storage compressor stations
$0.61 for transmission compressor stations
$1.81 for storage compressor stations
$1.74 for transmission compressor stations
$0.45 for dehydrators without flash tanks in the
processing sector
$50.644101 for dehydrators with flash tanks in the
processing sector
$0.16 for dehydrators without flash tanks in
transmission sector
$0.68 for dehydrators with flash tanks in transmission
sector
$9.49 for dehydrators with gas assisted pumps and
$232 for dehydrators without gas assisted pumps on
dehydrator vents in the production and processing
sectors
$3.42 for transmission sector
$0.12 for storage compressor stations
$0.17 for transmission compressor stations
$0.40 for processing compressor stations
U.S. Environmental Protection Agency - September 1999
Appendix III: Natural Gas Systems III-9
image:

Exhibit 111-5: Cost Analysis Data and Assumptions for Best Management Practices (continued)
Best Management Practice Applicability and Emission Reductions
Costs
Break-Even Gas Price (S/MMBtu)
Change wet seals to dry
seals on centrifugal
compressors
Practice early replacement of
rings and rods on
reciprocating compressors

Practice directed inspection
and maintenance at gate
stations and surface facilities
Applicability: 100% of all centrifugal comp. in the processing and
transmission sectors
Emission Reduction: 77.2% of emissions from storage comp.,
70.9% of emissions from trans, comp. stations, 65.9% of emissions
from processing comp.
Applicability: 100% of reciprocating compressors in the
transmission sector
Emission Reduction: 1.4% of emissions from storage compressor
stations, 1.5% of emissions from trans, compressor stations
Applicability: For transmission sector, 100% of transmission co.
interconnect meter and regulator stations; for distribution sector,
100% of high pressure stations, 50% of medium pressure
stations, and 0% of low pressure stations
Emission Reduction: For transmission sector, 33% of emissions;
for distribution sector, 33% of emissions from high pressure, 25%
of emissions from medium pressure stations
Capital: $240,000/compressor
Annual O&M: savings in material
and labor relative to wet seals of
$63,000/compressor

Capital: $100/compressor
Annual O&M: $120
Capital: $5,000/survey instrument
spread across 20 facilities yielding
$250/station
Annual O&M: $295/station
$1.91 for storage compressor stations
$2.10 for transmission compressor stations
$3.22 for processing compressor stations

$2.09 for storage compressor stations
$2.66 for transmission compressor stations
For transmission sector:
$0.75 for transmission co. interconnect
$320 for farm taps and direct sales
For distribution sector:
$0.69 for M&R>300psi
$1.74 for M&R 100-300 psi
$96.58 for M&R<100 psi
11-10 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 111-6: Cost Analysis Data and Assumptions for Partner-Reported Opportunities
Partner Reported
Opportunity
Applicability and Emission Reductions
Costs
Break-Even Gas Price (S/MMBtu)
Practice directed inspection
and maintenance at
production sites
Use enhanced directed
inspection and maintenance
at production sites
Use electric starter

Use plunger lift well
Use surge vessel to capture
blowdowns
Use portable evacuation
compressors

Install instrument air
systems
Practice directed inspection
and maintenance at
processing sites
Applicability: 100% of non-associated gas wells, 100% of off-shore
platforms, and 100% of pipeline leaks in the production sector
Emission Reduction: 33% of emissions from non-associated gas
wells, 33% of emissions from off-shore platforms, and 60% of
emissions from pipeline leaks
Applicability: 100% of non-associated gas wells in the production
sector
Emission Reduction: 50%
Applicability: 100% of compressor starts in the production sector
Emission Reduction: 75%
Applicability: 20% of Appalachia (all non-associated) and 20% of
rest of U.S. on-shore wells in the production sector
Emission Reduction: 20%
Applicability: 100% of pipeline venting during routine maintenance
and upsets in production, processing and transmission sector
Emission Reduction: 50%
Applicability: 90% of pipeline venting during routine maintenance
and upsets in production and transmission sector
Emission Reduction: 80%
Applicability: 50%-90% of pneumatic systems in the production
and transmission sector
Emission Reduction: 100%
For pneumatic device vents in the production sector, 6 cases were
examined (low-med.-high bleed; intermittent & continuous)
For the transmission sector, 9 cases were examined (low-med.-
high bleed; continuous, turbine & displacement); applicability is
higher for high-bleed devices
Applicability: 100% of processing plants
Emission Reduction: 33%
Capital: $200/well, $6,000/off-shore
platform, $100/mile of pipeline
Annual O&M: $300/well, $2,000/off-
shore platform, $150/mile of pipeline
Capital: $500
Annual O&M: $700

Capital: $20,000/compressor
Annual O&M: $5,000/compressor
Capital: $2,500/well
Annual O&M: $100/well

Capital: $100,000/vessel-compressor-
station (unit depends on sector)
Annual O&M: $2,000/unit
Capital: $1,400/mile
Annual O&M: $10/mile

Capital: $4,200
Annual O&M: various ($750 for
pneumatic device vents in the
production sector)
Capital: $1,000/plant
Annual O&M: $2,000/plant
$415 for eastern on-shore non-associated gas
wells
$81.14 for rest of U.S. gas wells
$10.46 for Gulf of Mexico off-shore platforms
$25.88 for rest of U.S. off-shore platforms
$15.27 for pipeline leaks
$15.10 for chemical injection pumps
$647 for eastern on-shore non-associated gas
wells
$126 for rest of U.S. gas wells
$1,536

$1,330 for Appalachia wells
$260 for rest of U.S. on-shore wells

>$100,000 for vessel blowdowns in the production
sector
$13,576 for compressor blowdowns in the
production sector
$11.42 for processing
$10.63 for transmission
$1,239 for production sector
$12.10 for transmission sector

$4.66452.56 for pneumatic device vents in the
production sector; break-even gas prices are
lower for high-bleed devices
$3.28-$893 for the transmission sector; break-
even gas prices are lower for high-bleed devices
$2.39
U.S. Environmental Protection Agency - September 1999
Appendix III: Natural Gas Systems 111-11
image:

Exhibit 111-6: Cost Analysis Data and Assumptions for Partner-Reported Opportunities (continued)
PRO
Applicability and Emission Reductions
Costs
Break-Even Gas Price (S/MMBtu)
Use catalytic converters on
engine exhaust
Practice directed inspection
and maintenance at LNG
stations
Practice directed inspection
and maintenance of trans.
pipelines
Use enhanced directed
inspection and maintenance
at compressor stations
Applicability: 75% of engines and turbines in the transmission
sector (including LNG storage)
Emission Reduction: 75%
Applicability: 100% of LNG stations in transmission sector
Emission Reduction: 60%

Applicability: 100% of pipeline leaks in the transmission sector
Emission Reduction: 60%

Applicability: 100% of compressor stations in the transmission
sector
Emission Reduction: 26.5% of emissions from storage
compressors, 18.9% of emissions from trans, compressor stations
Capital: $3,386/MM HP-Hr
($20,000/engine)
Annual O&M: $168/MM HP-Hr
($1,000/engine)
Capital: $500/station
Annual O&M: $2,065/station

Capital: $100
Annual O&M: $150

Capital: $1,000/station
Annual O&M: $6,000/station
$4.74429.53 for compressor exhaust (production)
$5.35 for engines (transmission)
$94.63 for turbines (transmission)
$7.33 for engines (storage)
$85.95 for turbines (storage)
$10.56 for engines (LNG storage)
$479 for turbines (LNG storage)
$1.87
$527

$0.69 for storage compressor stations
$1.11 for transmission compressor stations
Practice directed inspection Applicability: 100% of storage wells in the transmission sector
and maintenance at storage Emissjon Reduction. 33%
wells
Capital: $200/well
Annual O&M: $200/well
$18.54
Practice enhanced directed
inspection and maintenance
at storage wells

Practice enhanced directed
inspection and maintenance
at gate stations and surface
facilities

Use electronic metering
Applicability: 100% of storage wells in the transmission sector
Emission Reduction: 50%
Applicability: 100% of gate stations and surface facilities in the
distribution sector
Emission Reduction: 30%-80% of emissions; higher pressure
stations have greater emission reductions

Applicability: 100% of trans, co. interconnect M&R stations in the
transmission sector; 100% of meter and regulator stations at city
gates in distribution sector
Emission Reduction: 95%
Capital: $300/well
Annual O&M: $400/well

Capital: $1,000/station
Annual O&M: $1,000/station
Capital: $15,000/station
Annual O&M: $2,500/station
$23.14
$1.01 for M&R >300 psi
$2.35 for M&R 100-300 psi
$113 for M&R <100 psi
$4.84 for the transmission sector
For the distribution sector:
$4.46 for M&R >300 psi
$8.40 for M&R 100-300 psi
$186 for M&R <100 psi
11-12 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit 111-6: Cost Analysis Data and Assumptions for Partner-Reported Opportunities (continued)
PRO Applicability and Emission Reductions Costs Break-Even Gas Price (S/MMBtu)
Replace pipeline Applicability: 100% of cast iron and unprotected steel mains in Capital: $1,000,000/mile $1,229 for cast iron pipeline
distribution sector Annual O&M: $50/mile $2,662 for unprotected steel pipeline
Emission Reduction: 95%
Replace services Applicability: 100% of unprotected steel services in distribution Capital: $250,000/service $43,155 for unprotected steel services
sector Annual O&M: $50/service
Emission Reduction: 95%
U.S. Environmental Protection Agency - September 1999 Appendix III: Natural Gas Systems 111-13
image:

Exhibit
III-7: Schedule of Emission Reduction Options for 2010

Break-Even
Number Option Gas Price
(S/MMBtu)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
Practice directed inspection and maintenance at gate stations and
surface facilities (Meter/Regulator stations > 300 psi)
Practice directed inspection and maintenance at gate stations and
surface facilities (Reg. > 300 psi)
Practice enhanced directed inspection and maintenance at gate
stations and surface facilities (Meter/Regulator stations > 300 psi)
Install fuel gas retrofit systems on compressors to capture otherwise
vented fuel when compressors are taken off-line (storage
compressor stations)
Practice enhanced directed inspection and maintenance at gate
stations and surface facilities (Reg. > 300 psi)
Reduce glycol circulation rates in dehydrators (not applicable to
Kimray pumps - this option applies to transmission sector
dehydrators without flash tanks)
Install fuel gas retrofit systems on compressors to capture otherwise
vented fuel when compressors are taken off-line (transmission
compressor stations)
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to transmission sector, high-bleed, continuous-
bleed pneumatic devices)
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to transmission sector, medium-bleed, continuous-
bleed pneumatic devices)
Install fuel gas retrofit systems on compressors to capture otherwise
vented fuel when compressors are taken off-line (processing
compressor stations)
Practice directed inspection and maintenance at storage
compressor stations
Reduce glycol circulation rates in dehydrators (not applicable to
Kimray pumps - this option applies to production sector dehydrators
without flash tanks, with gas assisted pumps)
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to production sector, high-bleed, continuous-bleed
devices)
Practice directed inspection and maintenance at transmission
compressor stations
Reduce glycol circulation rates in dehydrators (not applicable to
Kimray pumps - this option applies to transmission sector
dehydrators with flash tanks)
Enhanced Directed Inspection and Maintenance at storage
compressor stations
Practice directed inspection and maintenance at gate stations and
surface facilities (Meter/Regulator stations 100-300 psi)
Practice directed inspection and maintenance at gate stations and
surface facilities (trans, co. interconnect)
Practice enhanced directed inspection and maintenance at gate
stations and surface facilities (trans, co. interconnect)
$0.69
$0.77
$1.01
$0.12
$1.13
$0.16
$0.17
$0.20
$0.50
$0.40
$0.55
$0.45
$0.49
$0.61
$0.68
$0.69
$1.74
$0.75
$1.10

_ _ Carbon
Base Gas .- • , .
„ • T » Equivalent
Pr.ce Type- Va|Hue ($/TCE)
Citygate
Citygate
Citygate
Pipeline
Citygate
Pipeline
Pipeline
Pipeline
Pipeline
Wellhead
Pipeline
Wellhead
Wellhead
Pipeline
Pipeline
Pipeline
Citygate
Pipeline
Pipeline
($23.42)
($22.72)
($20.51)
($19.60)
($19.49)
($19.18)
($19.06)
($18.83)
($16.10)
($16.09)
($15.69)
($15.67)
($15.24)
($15.05)
($14.45)
($14.40)
($13.90)
($13.80)
($10.65)

Incremental
Emission
Reduction
(MMTCE/yr)
0.23
<0.01
0.56
0.42
0.33
0.01
1.63
0.59
0.39
0.43
<0.01
0.28
0.98
<0.01
0.73
0.05
0.35
0.14
0.20
11-14 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit
III-7: Schedule of Emission Reduction Options for 2010 (continued)
Break-Even
Number Option Gas Price
(S/MMBtu)
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to production sector, high-bleed, intermittent-bleed
devices)
Practice enhanced directed inspection and maintenance at
transmission compressor stations
Reduce glycol circulation rates in dehydrators (not applicable to
Kimray pumps - this option applies to production sector dehydrators
without flash tanks)
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to production sector, medium-bleed, continuous-
bleed devices)
Practice enhanced directed inspection and maintenance at gate
stations and surface facilities (Meter/Regulator stations 100-300 psi)
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to transmission sector, high-bleed, turbine devices)
Use reciprocating compressor rod packing (Static-Pac, applies to
transmission sector)
Use reciprocating compressor rod packing systems (Static-Pac,
applies to storage)
Practice directed inspection and maintenance at LNG stations
Install dry seals on centrifugal compressors (storage sector)
Use reciprocating compressor rod packing systems (early
replacement of rings and rods on storage sector reciprocating
compressors)
Install dry seals on reciprocating compressors (transmission sector)
Practice directed inspection and maintenance at production and
processing sites
Replace higher-bleed pneumatic devices with lower-bleed
pneumatic devices (applies to production sector, medium-bleed,
intermittent-bleed devices)
Use reciprocating compressor rod packing systems (early
replacement of rings and rods on transmission sector reciprocating
compressors)
Practice directed inspection and maintenance at gate stations and
surface facilities (Reg. 100-300 psi)
Install instrument air systems (in place of transmission sector, high-
bleed, continuos bleed pneumatic devices)
Install dry seals on reciprocating compressors (processing sector)
Install flash tank separators on transmission sector glycol
dehydrators
Use electronic metering (Meter/Regulator stations > 300 psi)
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to transmission sector, low-bleed, continuous-
bleed devices)
$1.00
$1.11
$1.04
$1.23
$2.35
$1.47
$1.74
$1.81
$1.87
$1.91
$2.09
$2.10
$2.39
$2.50
$2.66
$4.11
$3.28
$3.22
$3.42
$4.46
$3.60
_ _ Carbon
Base Gas .- • , .
„ • T » Equivalent
Pr.ce Type- Va|Hue ($/TCE)
Wellhead
Wellhead
Wellhead
Wellhead
Citygate
Pipeline
Pipeline
Pipeline
Pipeline
Pipeline
Pipeline
Pipeline
Pipeline
Wellhead
Pipeline
Citygate
Wellhead
Pipeline
Pipeline
Citygate
Pipeline
($10.64)
($10.57)
($10.28)
($8.51)
($8.38)
($7.26)
($4.85)
($4.16)
($3.62)
($3.27)
($1.61)
($1.55)
($0.34)
$3.00
$3.51
$7.65
$9.57
$9.16
$10.47
$10.86
$12.07
Incremental
Emission
Reduction
(MMTCE/yr)
0.90
0.04
0.02
0.65
0.56
0.04
0.39
0.06
0.01
0.12
0.01
0.64
<0.01
0.68
0.07
0.14
0.23
0.45
0.02
0.10
0.02
U.S. Environmental Protection Agency
Appendix III: Natural Gas Systems 111-15
image:

Exhibit
III-7: Schedule of Emission Reduction Options for 2010 (continued)
Break-Even
Number Option Gas Price
(S/MMBtu)
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to transmission sector, medium-bleed, turbine
devices)
Practice enhanced directed inspection and maintenance at gate
stations and surface facilities (Reg. 100-300 psi)
Use catalytic converter (applies to compressor exhaust during
normal operations in the production and processing sectors)
Install instrument air systems (in place of production sector, high-
bleed, continuous-bleed pneumatic devices)
Install instrument air systems (in place of transmission sector,
medium-bleed, continuous-bleed pneumatic devices)
Use electronic monitoring (trans, co. interconnect)
Use catalytic converter (applies to compressor exhaust during
normal operations in the transmission sector)
Use catalytic converter (applies to storage engine compressor
exhaust during normal operation of transmission sector)
Install instrument air systems (in place of production sector, high-
bleed, intermittent-bleed devices)
Use electronic monitoring (Meter/Regulator stations 100-300 psi)
Use catalytic converter (applies to fugitive emissions from
compressor exhaust in the production and processing sectors)
Install instrument air systems (in place of production sector,
medium-bleed, continuous-bleed pneumatic devices)
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to production sector, low-bleed, continuous-bleed
devices)
Install flash tank separators on production-sector dehydrators with
gas-assisted pumps
Install instrument air systems (in place of production sector, high-
bleed, turbine devices)
Practice directed inspection and maintenance on Gulf of Mexico off-
shore platforms
Use catalytic converter (applies to LNG compressor exhaust)
Use portable evacuation compressors (applies to transmission
sector station venting)
Use surge vessels (applies to storage sector station venting)
Use surge vessels (applies to LNG station venting)
Use surge vessels (applies to blowdowns/venting in the production
sector)
Use surge vessels (applies to pipeline venting during routine
maintenance in the transmission sector)
Install instrument air systems (in place of transmission sector, low-
bleed, continuous-bleed devices)
$3.68
$5.54
$4.74
$4.66
$4.79
$4.84
$5.35
$7.33
$7.21
$8.40
$8.27
$8.39
$8.89
$9.49
$9.68
$10.46
$10.56
$10.63
$10.63
$10.63
$11.42
$12.10
$12.34
_ _ Carbon
Base Gas .- • , .
„ • T » Equivalent
Pr.ce Type- Va|Hue ($/TCE)
Pipeline
Citygate
NA
Wellhead
Pipeline
Pipeline
NA
NA
Wellhead
Citygate
NA
Wellhead
Wellhead
Wellhead
Pipeline
Wellhead
NA
Pipeline
Pipeline
Pipeline
Pipeline
Pipeline
Pipeline
$12.80
$20.69
$20.99
$22.63
$22.90
$23.33
$26.59
$44.58
$45.82
$46.62
$53.13
$56.58
$61 .09
$66.58
$67.43
$73.04
$73.90
$74.61
$74.61
$74.61
$81.73
$87.98
$92.60
Incremental
Emission
Reduction
(MMTCE/yr)
0.02
0.22
<0.01
0.35
0.14
0.06
<0.01
0.51
0.32
0.42
0.77
0.24
0.02
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
1.14
0.18
0.78
11-16 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit
III-7: Schedule of Emission Reduction Options for 2010 (continued)
Break-Even
Number Option Gas Price
(S/MMBtu)
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
Install instrument air systems (in place of production sector,
medium-bleed, intermittent-bleed devices)
Practice directed inspection and maintenance (applies to chemical
injection pumps)
Practice directed inspection and maintenance (applies to pipeline
leaks)
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to transmission sector, high-bleed, displacement
devices)
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to production sector, low-bleed, intermittent-bleed
devices)
Practice directed inspection and maintenance at storage wells
Install instrument air systems (in place of transmission sector,
medium-bleed, turbine devices)
Practice enhanced directed inspection and maintenance at storage
wells
Practice directed inspection and maintenance at production sites
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to transmission sector, low-bleed, turbine devices)
Install instrument air systems (in place of production sector, low-
bleed, continuous-bleed devices)
Use catalytic converters on compressor exhaust during normal
operations in the production and processing sector
Practice directed inspection and maintenance at surface facilities
(applies to Reg. 40-1 00 psi.)
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to transmission sector, medium-bleed,
displacement devices)
Practice enhanced directed inspection and maintenance at surface
facilities (applies to Reg. 40-100 psi.)
Reduce the recirculation rate on production sector glycol
dehydrators with flash tanks with gas assisted pumps
Install instrument air systems (in place of production sector, low-
bleed, intermittent-bleed devices)
Install instrument air systems (in place of transmission sector, low-
bleed, turbine devices)
Practice directed inspection and maintenance at U.S. gas wells on-
shore
Use catalytic converters on compressor exhaust (applies to turbine
engines in the storage sector)
Install instrument air systems (in place of transmission sector, high-
bleed, displacement devices)
$14.77
$15.10
$15.27
$17.67
$18.00
$18.54
$20.81
$23.14
$25.88
$26.48
$27.06
$29.53
$40.03
$44.18
$46.78
$50.64
$52.56
$76.41
$81.14
$85.95
$91.34
_ _ Carbon
Base Gas .- • , .
„ • T » Equivalent
Pr.ce Type- Va|Hue ($/TCE)
Wellhead
Wellhead
Wellhead
Pipeline
Wellhead
Pipeline
Pipeline
Pipeline
Wellhead
Pipeline
Wellhead
NA
Citygate
Pipeline
Citygate
Wellhead
Wellhead
Pipeline
Wellhead
NA
Pipeline
$115
$115
$117
$140
$144
$147
$169
$188
$213
$220
$226
$246
$334
$381
$396
$441
$458
$674
$716
$760
$810
Incremental
Emission
Reduction
(MMTCE/yr)
0.22
<0.01
<0.01
0.56
0.01
<0.01
0.04
<0.01
0.02
<0.01
0.04
<0.01
0.02
<0.01
0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
U.S. Environmental Protection Agency
Appendix III: Natural Gas Systems 111-17
image:

Exhibit
III-7: Schedule of Emission Reduction Options for 2010 (continued)
Number Option
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
Use catalytic converters on compressor exhaust (applies to turbine
engines in the transmission sector)
Practice directed inspection and maintenance at gate stations and
surface facilities (applies to Meter and Regulator stations < 100 psi)
Reduce the recirculation rate on production sector glycol
dehydrators with flash tanks without gas assisted pumps
Practice enhanced directed inspection and maintenance at gate
stations and surface facilities (applies to Meter and Regulator
stations < 100 psi)
Practice enhanced directed inspection and maintenance at U.S. gas
wells on-shore
Practice enhanced directed inspection and maintenance at gate
stations and surface facilities (R-vault > 300 psi)
Use electronic monitoring (Meter/Regulator stations < 100 psi)
Install instrument air systems (in place of transmission sector,
medium-bleed, displacement devices)
Install flash tank separators on production-sector glycol dehydrators
without gas-assisted pumps
Use plunger lift well (applies to U.S. on-shore wells)
Replace high-bleed pneumatic devices with low-bleed pneumatic
devices (applies to transmission sector, low-bleed, displacement
devices)
Practice directed inspection and maintenance at gate stations and
surface facilities (R-vault > 300 psi)
Practice directed inspection and maintenance at gate stations and
surface facilities (M&R Farm Taps + Direct Sales)
Practice directed inspection and maintenance at production sites
(Eastern on-shore, Appalachia non-associated gas wells)
Practice directed inspection and maintenance at production sites
(Eastern on-shore north central non-associated gas wells)
Use catalytic converters on compressor exhaust (applies to LNG
compressor emissions from turbine engines)
Practice directed inspection and maintenance at transmission
pipelines
Practice enhanced directed inspection and maintenance at
production sites (Eastern on-shore, Appalachia non-associated gas
wells)
Practice enhanced directed inspection and maintenance at
production sites (Eastern on-shore north central non-associated gas
wells)
Install instrument air systems (in place of transmission sector, low-
bleed, displacement devices)
Practice directed inspection and maintenance at wells and other
similar facilities (applies to cast-iron mains)
Break-Even
Gas Price
(S/MMBtu)
$94.63
$96.58
$101
$113
$126
$140
$186
$225
$232
$260
$318
$320
$320
$415
$415
$479
$527
$647
$646
$893
$1,229
Base Gas
Price Type3
NA
Citygate
Wellhead
Citygate
Wellhead
Citygate
Citygate
Pipeline
Wellhead
Wellhead
Pipeline
Citygate
Pipeline
Wellhead
Wellhead
NA
Pipeline
Wellhead
Wellhead
Pipeline
Citygate
Carbon
Equivalent
Value ($/TCE)
$838
$849
$901
$997
$1,127
$1,247
$1,664
$2,025
$2,087
$2,341
$2,872
$2,882
$2,891
$3,755
$3,755
$4,337
$4,771
$5,860
$5,860
$8,100
$11,155
Incremental
Emission
Reduction
(MMTCE/yr)
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
11-18 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit II
Number
106
107
108
109
110
111
112
113
114
115
116
117
118
II-7: Schedule of Emission Reduction Options for 2010 (continued)
Option
Use portable evacuation compressors (applies to production sector
pipeline blowdowns)
Practice enhanced directed inspection and maintenance at gate
stations and surface facilities (R-vault 100-300 psi)
Use plunger-lift wells (applies to Eastern on-shore, Appalachia non-
associated gas wells)
Use electric starter (applies to compressor starts in the production
and processing sector)
Practice directed inspection and maintenance at gate stations and
surface facilities (R-vault 100-300 psi)
Practice directed inspection and maintenance at wells and other
similar facilities (applies to unprotected steel mains)
Practice directed inspection and maintenance at gate stations and
surface facilities (Reg. < 40 psi)
Practice enhanced directed inspection and maintenance at gate
stations and surface facilities (Reg. < 40 psi)
Practice directed inspection and maintenance at gate stations and
surface facilities (R-vault 40-1 00 psi)
Practice enhanced directed inspection and maintenance at gate
stations and surface facilities (R-vault 40-100 psi)
Use surge vessels to capture gas during compressor blowdowns in
the production sector
Practice directed inspection and maintenance in the transmission
sector (replace unprotected steel services)
Use surge vessels to capture gas during vessel blowdowns in the
production sector
Break-Even
Gas Price
(S/MMBtu)
$1,240
$1,248
$1,330
$1,536
$2,313
$2,662
$3,130
$3,658
$4,813
$5,625
$13,576
$43,155
$656,849
Base Gas
Price Type3
Wellhead
Citygate
Wellhead
Wellhead
Citygate
Citygate
Citygate
Citygate
Citygate
Citygate
Wellhead
Citygate
Wellhead
Carbon
Equivalent
Value ($/TCE)
$11,253
$11,315
$12,075
$13,942
$21,002
$24,190
$28,434
$33,238
$43,735
$51,122
$123,433
$392,423
$5,973,306
Incremental
Emission
Reduction
(MMTCE/yr)
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
a Wellhead = $2.17/MMBtu, pipeline = $2.27/MMBtu, citygate = $3.27/MMBtu.
All prices are in real 1996 dollars.
U.S. Environmental Protection Agency
Appendix III: Natural Gas Systems 111-19
image:

Reference
EPA/GRI. 1996. Methane Emissions from the Natural Gas Industry, Volume 1: Executive Summary,
Prepared by Harrison, M., T. Shires, J. Wessels, and R. Cowgill, eds., Radian International LLC for
National Risk Management Research Laboratory, Air Pollution Prevention and Control Division,
Research Triangle Park, NC, EPA-600-R-96-080a.
11-20 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Appendix IV: Supporting Material for the
Analysis of Coal Mining
This appendix presents the coal mine data that EPA used to develop methane emission forecasts and to estimate
methane emission reduction costs. The exhibits are described below:

> Exhibit IV-1: Historical and Projected Coal Production. This exhibit details historic and
projected coal production data for surface and underground mines. These data underlie projections
of the quantity of methane liberated from coalbeds. Historical data are shown for the period 1990-
1997. Projected data are provided for the years 2000, 2005, 2010, 2015, and 2020.

> Exhibit IV-2: Coal Mine Methane Liberation Estimates by Year. The estimates of methane
liberated from coal mining in 1997 are presented in this exhibit. Projections of methane liberated are
also provided, based on the production data in Exhibit IV-1. These estimates are the basis for
determining achievable and cost-effective emission reductions.

> Exhibit IV-3: Coal Basin Recovery Efficiencies by Year. This exhibit summarizes the methane
recovery efficiencies by coal basin and by year. Methane recovery efficiencies vary by coal basin.
In addition, EPA assumes that the technology to recover methane will improve over time, leading to
increased methane recovery.

> Exhibit IV-4: Cost Data and Assumptions Used in the Coal Mine Analysis. The assumptions
and data underlying the cost analysis of methane recovery and use techniques are summarized in this
exhibit. Data are arranged by type of cost (well, compression, processing, etc.) and option number.

> Exhibit IV-5: Schedule of Emission Reduction Options for 2010. This exhibit provides a
schedule of emission reduction data by option and individual mine for 2010. Data include annual
coal production, liberated methane, projected "break-even" gas price, the value of carbon equivalent
($/TCE), and the cumulative amount of emissions reduced.
U.S. Environmental Protection Agency-September 1999 Appendix IV: Coal Mining IV-1
image:

Exhibit IV-1: Historical and
Projected Coal
Production (Million Short Tons)
Historical

Underground
Surface
Total Production
Underground
(% of Total)
Surface
(% of Total)
Source: EIA, 1998aand
1990
425
605
1,029
41%
59%
1998b.
1991
407
589
996
41%
59%

1992
407
590
998
41%
59%

1993
351
594
945
37%
63%

1994
399
634
1,034
39%
61%

1995
396
636
1,033
38%
62%

1996
410
654
1,064
39%
61%

1997
421
669
1,090
39%
61%
Projected
2000
427
718
1,145
37%
63%

2005
482
725
1,207
40%
60%

2010
510
756
1,265
40%
60%

2015
537
789
1,326
41%
59%

2020
552
824
1,376
40%
60%

Exhibit IV-2: Coal Mine Methane Liberation Estimates by Year
Year
(MM)
Underground Mining
(% of Total)
1997
2000
2005
2010
2015
2020
MMcf = million cubic feet
Source: Projections based on
212,312
217,142
241,501
254,966
268,377
276,454

EPA, 1999a,andEIA, 1998b.
153,203
155,570
175,490
185,614
195,592
201,091

72.2
71.6
72.7
72.8
72.9
72.7

Exhibit IV-3: Coal Basin Recovery Efficiencies by Year
Basin
Warrior
Illinois
Northern Appalachian
Central Appalachian
Western
1997
45.0%
50.0%
55.0%
55.0%
50.0%
2000
45.0%
50.0%
55.0%
55.0%
50.0%
Source: Experience with existing coal mine methane projects,
2005
47.5%
52.5%
57.5%
57.5%
52.5%
and EPA, 1997b.
2010
50.0%
55.0%
60.0%
60.0%
55.0%

2015
52.5%
57.5%
62.5%
62.5%
57.5%

2020
55.0%
60.0%
65.0%
65.0%
60.0%

IV-2 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit IV-4: Cost Data and Assumptions Used in the Coal Mine Analysis
Cost Item
Number or Size of Units Needed
Cost Per Unit
Costs for Wells
Vertical Well

Gob Wells

In-Mine Boreholes

Well Water Disposal Costs (Vertical
Wells Only)
Option 1 : 1 well for every 250,000 tons of coal mined
Option 2: 1 well for every 1 million tons of coal mined a
Option 1 : 1 well for every 500,000 tons of coal mined
Option 2: 1 well for every 1 million tons of coal mined a
Option 1 : 1 well for every 500,000 tons of coal mined
Option 2: 1 well for every 1 million tons of coal mined a
1 barrel of water is produced per Mcf (thousand cubic feet) of gas
produced
$150,000/well

$30,000/well

$75,000/well

$0.50 per barrel
per year
Compression Costs
Wellhead Compressor

Satellite Compressor
Sales Compressor
Gathering Lines from Wellhead to
Satellite
Gathering Lines from Satellite to
Point of End-Use
Cost of Moving Gathering Lines
1 perwellat200HP/MMcfd

1 per project at 150 HP/MMcfd
1 per project at 150 HP/MMcfd
Length of gathering lines from each well to satellite = 2000 ft
Length of gathering lines from satellite to point of end-use =
26,400 ft (5 miles)

Capital costs:
$600/HP; O&M
costs: $20/HP

$10/ft
$15/ft
$5/ft per year
Gas Processing Costs
Dehydrator

Gas Enrichment (Fixed Capital
1 per project

Required for Option 2 only
Capital Cost:
$40,000; O&M
cost: $3,000
$1,888,500
Cost) $/project
Gas Enrichment (Variable Capital
Cost) $/MMCFD
Gas Enrichment (Fixed Annual
Operating Cost) $/year
Gas Enrichment (Operating Cost
Based on Maximum Gas
Production) $/MMCFD
Required for Option 2 only

Required for Option 2 only

Required for Option 2 only
$526,000

$132,000

$37,167
Oxidizer Costs
Oxidizer (Without Electricity
Generation)
Option 3 only
Capital Cost: $6.2
million; O&M costs:
$541,740b
a Option 1 is degasification and pipeline injection. Option 2 is degasification and pipeline injection incremental to Option 1. Option 3 is
catalytic oxidation.
b Costs are for a system capable of handling 211,860 scf/min of ventilation air at 0.5% methane; for each mine, the cost was scaled based on
the mine's flow rate relative to 211,860 scf/min.
Source: EPA 1997a, b, and c; CANMET, 1998.
U.S. Environmental Protection Agency - September 1999
Appendix IV: Coal Mining IV-3
image:

Exhibit IV-5: Schedule of Emission Reductions for 2010
Mine Name
VP No. 8
VP No. 3
Blue Creek No. 5
Blue Creek No. 7
Buchanan No. 1
Blue Creek No. 4
Blue Creek No. 3
Pinnacle No.50 (Gary)
Oak Grove
Blacksville No. 2
VP No. 8
Sanborn Creek
Blue Creek No. 7
Buchanan No. 1
VP No. 3
Blue Creek No. 4
Blue Creek No. 5
Enlow Fork
Shoal Creek
Emerald No. 1
Blue Creek No. 3
Cumberland
Maple Meadow
Federal No. 2
Bailey
Loveridge No. 22
Mine 84
Soldier Canyon
Dilworth
Blacksville No. 2
Roadside North Portal
Sentinel Mine
Galatia Mine No. 56-1
Robinson Run No. 95
Oak Grove
Pinnacle No.50 (Gary)
Sanborn Creek
West Elk Mine
McClure No. 2 Mine
Bowie #1 Mine
Tanoma
Enlow Fork
Aberdeen
Boone No. 1
Bay Beck Mine
Option3
1
1
1
1
1
1
1
1
1
1
2
1
2
2
2
2
2
1
1
1
2
1
1
1
1
1
1
1
1
2
1
1
1
1
2
2
2
1
1
1
1
2
1
1
1
Coal
Production
(MM short
tons/yr)
1.60
2.69
1.44
3.17
5.26
2.75
2.78
6.46
3.17
4.18
1.60
1.94
3.17
5.26
2.69
2.75
1.44
10.15
4.86
5.85
2.78
7.71
1.28
5.32
9.11
5.82
5.80
1.39
5.38
4.18
0.52
1.39
6.03
5.79
3.17
6.46
1.94
6.93
0.44
0.92
0.65
10.15
2.27
1.03
1.19
Total Methane
Liberated
(MMcf/yr)
13,237
11,919
7,352
13,953
18,523
10,296
8,736
7,135
4,460
6,281
13,237
3,121
13,953
18,523
11,919
10,296
7,352
7,135
1,976
4,091
8,736
5,004
1,370
3,347
5,093
2,992
4,028
1,164
2,506
6,281
483
973
4,094
2,272
4,460
7,135
3,121
3,975
306
506
350
7,135
1,077
586
552
Break- Even
Cost
($/MMBtu)
0.47
0.52
0.54
0.54
0.54
0.57
0.60
0.84
0.85
1.13
1.41
1.54
1.60
1.63
1.64
1.77
1.79
1.88
1.90
1.91
1.94
2.01
2.03
2.09
2.26
2.45
2.66
2.66
2.67
2.77
2.84
2.86
2.92
3.09
3.11
3.14
3.33
3.37
3.56
4.01
4.03
4.11
4.18
4.19
4.20
Additional Value Cumulative
of Methane Emissions Avoided
(StfCE) (MMTCE/yr)
(18.69)
(18.23)
(18.05)
(18.05)
(18.05)
(17.78)
(17.51)
(15.32)
(15.23)
(12.69)
(10.14)
(8.96)
(8.41)
(8.14)
(8.05)
(6.87)
(6.68)
(5.87)
(5.68)
(5.59)
(5.32)
(4.68)
(4.50)
(3.96)
(2.41)
(0.68)
1.23
1.23
1.32
2.23
2.86
3.05
3.59
5.14
5.32
5.59
7.32
7.68
9.41
13.50
13.69
14.41
15.05
15.14
15.23
0.87
1.66
2.06
2.83
4.05
4.62
5.10
5.57
5.82
6.23
6.52
6.71
7.02
7.42
7.69
7.91
8.07
8.55
8.65
8.92
9.12
9.45
9.54
9.76
10.09
10.29
10.56
10.63
10.79
10.93
10.96
11.02
11.27
11.42
11.52
11.68
11.74
11.99
12.01
12.04
12.06
12.22
12.28
12.31
12.35
IV-4 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit IV-5: Schedule of Emission Reductions for 2010 (continued)
Mine Name Option3
Emerald No. 1
Brushy Creek Mine
Cumberland
Mine 84
McElroy
Galatia Mine No. 56-1
Shoemaker
North River
Bailey
Federal No. 2
Pattiki Mine
West Elk Mine
Wabash Mine
Urling No. 1 Mine
Maple Meadow
Maple Creek
All Mines
a Option 1 is degasification and
catalytic oxidation.
2
1
2
2
1
2
1
1
2
2
1
2
1
1
2
1
3
Coal
Production
(MM short
tons/yr)
5.85
1.07
7.71
5.80
6.48
6.03
5.79
2.41
9.11
5.32
2.43
6.93
1.92
0.73
1.28
2.27
pipeline injection. Option
Total Methane
Liberated
(MMcf/yr)
4,091
501
5,004
4,028
2,415
4,094
2,111
1,035
5,093
3,347
918
3,975
711
271
1,370
711
Break- Even
Cost
($/MMBtu)
4.54
4.56
4.57
4.58
4.59
4.63
4.70
4.98
5.03
5.06
5.13
5.16
5.32
5.50
5.55
5.63
5.79
Additional Value Cumulative
of Methane Emissions Avoided
(StfCE) (MMTCE/yr)
18.32
18.51
18.60
18.69
18.78
19.14
19.78
22.33
22.78
23.05
23.69
23.96
25.42
27.05
27.51
28.24
29.70
2 is degasification and pipeline injection incremental to Option 1 .
12.44
12.47
12.58
12.67
12.83
12.92
13.06
13.11
13.23
13.30
13.36
13.44
13.49
13.50
13.53
13.58
20.00
Option 3 is
U.S. Environmental Protection Agency - September 1999
Appendix IV: Coal Mining IV-5
image:

References

CANMET. 1998. Personal Communication with Richard Trottier of CANMET. July 6, 1998.
EIA. 1998a. Annual Energy Review 1997. Energy Information Administration, U.S. Department of Energy,
Washington, DC. July 1998.
EIA. 1998b. Annual Energy Outlook 1998. Energy Information Administration, U.S. Department of Energy,
Washington, DC. July 1998.
EPA. 1997a. Identifying Opportunities for Methane Recovery at U.S. Coal Mines: Draft Profiles of Selected
Gassy Underground Mines. Office of Air and Radiation, U.S. Environmental Protection Agency, Washington,
DC, EPA 430-R-97-020.
EPA. 1997b. Technical and Economic Assessment of Potential to Upgrade Gob Gas to Pipeline Quality. Office
of Air and Radiation, U.S. Environmental Protection Agency, Washington, DC, EPA 430-R-97-012.
EPA. 1997c. U.S. EPA Coalbed Methane Evaluation Model. Office of Air and Radiation, U.S. Environmental
Protection Agency, Washington, DC.
EPA. 1999a. Inventory of Greenhouse Gas Emissions and Sinks 1990-1997. Office of Policy, Planning, and
Evaluation, U.S. Environmental Protection Agency, Washington, DC; EPA 236-R-99-003. (Available on the
Internet at http://www.epa.gov/globalwarming/inventory/1999-inv.html.)
IV-6 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
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Appendix V: Supporting Material for the
Analysis of Livestock Manure
Management
In this appendix, EPA presents additional information to further explain selected components of the
emission and emission reduction analysis for methane from livestock manure, presented in Chapter 5.
These areas are: (1) the emission estimation methodology, (2) the specific project costs for anaerobic
digester based methane recovery and utilization systems, and (3) uncertainties.

V.I Methodology for Estimating Methane Emissions from
Livestock Manure Management

EPA uses the following approach to estimate methane emissions from livestock manure. This approach
calculates emissions based on the type and quantity of the manure, the characteristics of the manure
management system, and the climatic conditions in which the manure decomposes. As livestock farms
often use several systems to manage manure and each system usually has a different potential for
generating methane, several calculations may be necessary.
The methane emission relationship is shown below:
states animal systems
CH4 = 2 2 2 Manure, • MFi)k • VS,) • Bo) • MCFik
i j k

where CH4 = Methane generated (ft3/day)
Manure^ = Total manure produced by animal type y in state /' (Ibs/day)
MFljk = Percent of manure managed by system k for animal type j in state /'
VSy = Percent of manure that is volatile solids for animal typey in state /'
BOJ = Maximum methane potential of manure for animal y (ft /lb volatile solids)
= Methane conversion factor for system k in state /'

Each factor in the emission analysis is determined as follows:

Manure Production. The amount of manure generated depends on the type, number, and size of the
animals. The U.S. Department of Agriculture (USDA) publishes detailed state-level population data for
each year. These livestock data are used with published manure production characteristics (Exhibit V-l)
to determine manure generation for each livestock category.

Manure Management Systems. The manner in which manure is managed determines whether it
generates methane. Manure management use for swine and dairy cattle are determined using the latest
livestock population survey conducted by the U.S. Department of Commerce (USDC, 1995). The census
survey, conducted for 1992, includes population data by farm size. This distribution is used to determine
manure management system usage — larger farms (500 or more dairy cows, 1,000 or more swine) were
assumed to use liquid systems, and smaller farms are assumed to use dry systems. For all other animal
types, manure management system use figures published by EPA (Safely, et al., 1992) are used. These
U.S. Environmental Protection Agency - September 1999 Appendix V: Livestock Manure Management V-1
image:

data, collected from livestock manure management experts in each state, estimate the fraction of manure
managed using the most common manure management systems.
Manure Characteristics. EPA documents livestock and manure characteristics in Safely, et al., (1992),
which are industry standards in the design of livestock specific manure management systems. The
methane potential for manure (B0) values are based on laboratory measurements where the maximum
amount of methane that can be generated by manure is measured. Volatile solids (VS) production values
are published annually by the American Society of Agricultural Engineers (ASAE, 1995). Exhibit V-l
presents values for dairy cattle and swine.
Methane Conversion Factors. The methane conversion factor (MCF) data for each of the manure
systems in the different climates are based on field and laboratory measurements. The data for lagoons
and ponds are based on measurements at dairy and hog lagoons conducted continuously over several
years.: The MCF data for the other systems are based on laboratory measurements conducted at Oregon
State University (Hashimoto and Steed, 1992). Exhibit V-2 lists typical values for dairy and swine
manure and the most common manure management systems. A typical large dairy will manage up to half
the manure using liquid systems, whereas a typical large swine farm will manage almost all the manure
using liquid systems.
Exhibit V-1 : Manure Characteristics
Weight Manure
(Ibs) (Ibs/day)
Dairy
Milk cow
Dry cow
Heifers
Calves
Swine
Sow
Nursery
Grower
Finisher
Source: Safley,

1,400
1,300
900
500

400
30
70
180
etal.,

112
107
77
43

24
3.2
4.4
11.4
1992.
VS%

7
11
6
6

9
8
9
9

3.8
3.8
3.8
3.8

5.8
7.5
7.5
7.5

Exhibit V-2: Methane Conversion Factors (MCF)

Liquid/Slurry
Pits < 30 days retention
Pits > 30 days retention
Tanks
Pasture, Range
Drylots, Corrals
Daily Spread
Warm
30 C
.65
0.1
0.2
0.2
.02
.05
.01
Temperate
20 C
.35
0.2
0.4
0.4
.015
.015
.005
Cool
10 C
.10
0.4
0.8
0.8
.01
.01
.0001
Anaerobic Lagoons
Litter
Deep Pit Stacking
Average Annual MCF
.90
.10
.05
Source: EPA, 1993; Hashimoto and Steed, 1992.
Over the course of several years, Dr. Lawson Safley at North Carolina State University monitored the amount of methane
generated by a covered lagoon used to manage dairy manure. In addition to monitoring methane, Dr. Safley recorded the air
temperature and lagoon temperature and the characteristics of the wastewater entering and leaving the lagoon. These data were
then used to create a model called Lagmet that estimates methane generation based on wastewater characteristics, temperature,
and lagoon design. In addition to Dr. Safley's measurements, additional data were collected by Hashimoto and Steed (1992)
from lagoons in other parts of the country.
V-2 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

V.2 Anaerobic Digester Technology System Costs

Emission reductions were determined by analyzing the methane recovery opportunities at dairy and
swine farms. Methane recovery system costs for each Anaerobic Digestion Technology (ADT) from
EPA (1997a) are displayed in Exhibits V-3 through V-5. All costs are in 1996 US$.
Exhibit V-3: Livestock Manure Methane Recovery and Utilization Costs - Covered Anaerobic Digester
Component Unit Costs
Lagoon Costs
Component
Excavation ($/yd)
Attachment wall ($/yd)
Pipe and influent box
Soil test
Foam trap
Very high durability cover material ($/ft2)
Cover install labor ($/ft2)

Gas Handling Costs
Component
Gas filter ($/unit)
Gas pump ($/unit)
Gas meter ($/unit)
Gas pressure regulator ($/unit)
J-trap ($/unit)
Manhole ($/unit)
Manometer ($/unit)

Cost
$1.75
$200
$1,700
$1,200
$75
$0.85
$0.35

Cost
$700
$900
$800
$500
$100
$300
$500

Utilization Equipment Costs
Component
Electricity gen w/heat rec ($/kW cap)
Electricity gen O&M ($/kWh produced)
Electricity gen building ($/unit)
Switch gear ($/unit)
Boiler cost ($/unit)
Boiler shed ($/unit)
Chiller ($/ton cap)
Flare ($/unit)
Labor and Services Costs
Component
Labor crew ($/hr)
Engineering ($/job)
Backhoe ($/hr)

Pipe Costs
Component
2 in. Diameter PVC pipe ($/ft)
3 in. Diameter PVC pipe ($/ft)
4 in. Diameter PVC pipe ($/ft)
6 in. Diameter PVC pipe ($/ft)
7 in. Diameter PVC pipe ($/ft)

Cost
$750
$0.015
$10,000
$5,000
$10,000
$3,500
$1,050
$1,500

Cost
$150
$25,000
$60

Cost
$1.00
$1.50
$2.00
$2.25
$4.00
Typical Project Costs (including labor)
500 cow dairy (CA)
Lagoon Costs
Gas Handling Costs
Piping Costs
Utilization Equipment Costs
Engineering Costs
TOTAL

$42,579
$2,380
$3,306
$57,306
$25,000
$135,571
1000 sow swine farm (NC)
Lagoon Costs
Gas Handling Costs
Piping Costs
Utilization Equipment Costs
Engineering Costs
TOTAL

$14,400
$2,380
$3,306
$27,925
$25,000
$73,011
Source: EPA, 1997a.
U.S. Environmental Protection Agency - September 1999
Appendix V: Livestock Manure Management V-3
image:

Exhibit V-4: Livestock Manure Methane Recovery and Utilization Costs: Plug Flow Digester
Plug-Flow Digester Component Unit Costs
Plug Flow Digester Costs
Component
Excavation ($/yd)
Concrete tank & foundation ($/yd)
Curb & grade beam ($/yd)
Pipe and influent box ($)
Digester insulation ($/panel)
Very high durability cover material
Cover install labor ($/ft2)
Foam liner protector ($/ft)
Separator ($)
Cost
$1.75
$225
$6
$800
$28
($/ft2) $0.85
$0.35
$1.25
$50,000
Hot Water Transmission Costs
Components
Trench/sand/liner ($/ft)
Manometer ($)
Hot water pipe ($/ft)
Gas Handling Costs
Components
Gas filter ($/unit)
Gas pump ($/unit)
Gas meter ($/unit)
Gas pressure regulator ($/unit)
J-trap ($/unit)
Manhole ($/unit)
Manometer ($/unit)
$2.3
$500
$3.5
Cost
$700
$900
$800
$500
$100
$300
$500
Utilization Equipment Costs
Component
Electricity gen ($/kW cap)*
Electricity gen O&M ($/kWh produced)
Electricity gen building ($/unit)
Switch gear ($/unit)
Flare ($/unit)
* Includes heat recovery
Labor and Services Costs
Component
Labor crew ($/hr)
Engineering ($/job)
Backhoe ($/hr)
Pipe Costs
Component
2 in. Diameter PVC pipe ($/ft)
3 in. Diameter PVC pipe ($/ft)
4 in. Diameter PVC pipe ($/ft)
6 in. Diameter PVC pipe ($/ft)
7 in. Diameter PVC pipe ($/ft)
Cost
$750
$0.02
$10,000
$5,000
$1,500
Cost
$150
$25,000
$60
Cost
$1.00
$1.50
$2.00
$2.25
$4.00
Typical Project Costs for a 500 Cow Dairy - California (including labor)
Digester Costs $58,721
Hot Water & Gas Handling Costs $2,804
Piping Costs $1,163
Solid Separator $50,000
Utilization Equipment Costs $70,869
Engineering Costs $25,000
TOTAL $198,557
Source: EPA, 1997a.
V-4 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

Exhibit V-5: Livestock Manure Methane Recovery and Utilization Costs: Complete Mix Digester
Complete-Mix Digester Component Unit Costs
Complete Mix Digester Costs
Component
Excavation ($/yd)
Concrete tank & foundation ($/yd)
Curb & grade beam ($/ft)
Pipe and influent box ($)

Cost
$1.75
$225
$6
$1,700
Pipe/fit/rack/labor ($/ft3 digester volume) $.10
Very high durability cover material
Cover install labor ($/ft2)
Hot Water Transmission Costs
Component
Trench/sand/liner ($/ft)
Manometer ($)
Hot water pipe ($/ft)
Gas Handling Costs
Component
Gas filter ($/unit)
Gas pump ($/unit)
Gas meter ($/unit)
Gas pressure regulator ($/unit)
J-trap ($/unit)
Manhole ($/unit)
Manometer ($/unit)
($/ft2) $0.85
$0.35

$2.3
$500
$3.5

Cost
$700
$900
$800
$500
$100
$300
$500
Utilization Equipment Costs
Component
Electricity gen ($/kW cap)*
Electricity gen O&M ($/kWh produced)
Electricity gen building ($/unit)
Switch gear ($/unit)
Flare ($/unit)

* Includes heat recovery
Labor and Services Costs
Component
Labor crew ($/hr)
Engineering ($/job)
Backhoe ($/hr)
Pipe Costs
Component
2 in. Diameter PVC pipe ($/ft)
3 in. Diameter PVC pipe ($/ft)
4 in. Diameter PVC pipe ($/ft)
6 in. Diameter PVC pipe ($/ft)
7 in. Diameter PVC pipe ($/ft)

Cost
$750
$0.02
$10,000
$5,000
$1,500

Cost
$150
$25,000
$60

Cost
$1.00
$1.50
$2.00
$2.25
$4.00

Typical Project Costs for a 1,000 Head Swine Farm -North Carolina (including labor)
Complete
Mix Digester Costs $22,137

Gas Handling Costs $2,804

Piping Costs $1,163

Utilization Equipment Costs $36,000

Engineering Costs $25,000
TOTAL $87,104

Source: EPA, 1997a.
U.S. Environmental Protection Agency - September 1999
Appendix V: Livestock Manure Management V-5
image:

V.3 Uncertainty
This section summarizes uncertainties in the emission reduction analysis. Exhibit V-6 displays the
uncertainty level as well as the basis for the uncertainty.
Exhibit V-6: Summary of Emission Reduction Uncertainties
Uncertainty Basis
Livestock Demographics Latest existing farm-size distribution data is for 1992. Shifts in both dairy and swine
populations towards larger facilities is not reflected.
Effectiveness of Methane These technologies have been applied on dairy and swine farms throughout the country for
Recovery Technologies over two decades.
Value of Methane Recovered
Facility Energy Costs Energy rates vary by utility and within each state. Forecasts assume constant costs.
Restructuring of utility industry may affect rates.
Non-Monetary Benefits (odor, Value is difficult to quantify. Recent projects at swine farms have been initiated primarily to
pollution, etc.) reduce odor.
Methane Recovery Costs
Project Development/ Information based on current projects and industry experts. Site-specific factors can influence
Construction Costs costs of individual projects.
V-6 U.S. Methane Emissions 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

V.4 References

ASAE. 1995. ASAE Standards 1995, 42nd Edition. American Society of Agricultural Engineers, St. Joseph, MI.
EPA. 1993. Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress. Air
and Radiation, U.S. Environmental Protection Agency, Washington, DC, EPA 430-R-93-003. (Available on the
Internet at http://www.epa.gov/ghginfo/reports. 1999-inv.htm.)
EPA. 1997a. AgSTAR FarmWare Software, Version 2.0. FarmWare User's Manual. (Available on the Internet at
http ://www.epa.gov/methane/home .nsf/pages/agstar.)
EPA. 1997b. AgSTAR Handbook A Manual For Developing Biogas Systems at Commercial Farms in the United
States. Edited by K.F. Roos and MA. Moser. Washington, DC, EPA 430-B97-015. (Available on the Internet
at http ://www.epa.gov/methane/home .nsf/pages/agstar.)
Hashimoto, A.G. and J. Steed. 1992. Methane Emissions from Typical Manure Management Systems. Oregon
State University, Corvallis, OR.
Safley, L.M., M.E. Casada, Jonathan W Woodbury, and Kurt F. Roos. 1992. Global Methane Emissions From
Livestock And Poultry Manure. Air and Radiation, U.S. Environmental Protection Agency, (ANR-445),
Washington, DC, EPA 400-1-91-048.
USDA. 1996. Long-Term Agricultural Projections, 1995-2005. National Agricultural Statistics Service,
Agricultural Statistics Board, U.S. Department of Agriculture, Washington, DC.
USDC. 1995. 7992 Census of Agriculture. Economics and Statistics Administration, Bureau of the Census,
United States Department of Commerce, Washington, DC.
U.S. Environmental Protection Agency - September 1999 Appendix V: Livestock Manure Management V-7
image:

image:

Appendix VI: Supporting Material for the
Analysis of Enteric
Fermentation
This appendix provides additional information regarding the methods used to estimate emissions from
livestock enteric fermentation. Methane emissions associated with enteric fermentation from the U.S.
population of cattle, sheep, goats, pigs and horses are estimated. The estimates primarily depend on the
livestock population and associated emission factors.
The first section describes the livestock population and presents population data used to estimate 1997 emissions
from livestock enteric fermentation. The second section presents and describes the emission factors used for the
1997 emission estimates.

VI.1 Population Data

This section provides the population data used to estimate 1997 methane emissions from livestock enteric fer-
mentation. In addition, this section elaborates on the three main beef industry sectors. The U.S. Department of
Agriculture (USDA) collects population data at the state level annually. Population data from 1997 for cattle,
sheep, goats and pigs are presented in Exhibit VI-1. Cattle population data are broken down beyond the national
level to account for variation in management practices and type of feed throughout the country. Because these
factors affect methane emissions and are highly variable, breaking the population down into groups improves the
accuracy of the analysis. The animal groups are presented and described in Exhibit VI-2.
EPA divides the beef population into three main categories to account for different animal and feed characteristics.
The three main beef sectors are the cow-calf, stacker (backgrounding), and feedlot sectors.

>• Cow-Calf Sector. In the cow-calf sector, calves feed on their mother's milk for two to three months,
after which they start a diet of milk and forage. Calves are simulated to start producing methane at 165
days, and are weaned at 205 days.
>• Stocker Sector. Following the cow-calf sector, most calves enter the stacker sector, during which
they consume primarily forages. Animals are placed in the stacker phase to increase their weight be-
Exhibit VI-1 : Animal Population Sizes for 1997
Animal Type
Mature Dairy Cows
Dairy Replacement Heifers (0-1 2 Months)
Dairy Replacement Heifers (12-24 Months)
Mature Beef Cows
Beef Replacement Heifers (0-12 Months)
Beef Replacement Heifers (12-24 Months)
Weanlings
Population (000)
9,304
3,828
3,828
34,486
5,678
5,678
5,692
Animal Type
Yearlings
Bulls
Sheep
Goats
Horses
Pigs

Population (000)
22,767
2,320
7,607
2,295
6,150
58,671

Source: FAO, 1998; USDA, 1997 and 1998a-d.
U.S. Environmental Protection Agency Appendix VI: Enteric Fermentation VI-1
image:

fore being placed in the feedlot. Animals going through stockering are called Yearlings (see Ex-
hibit VI-2).
Feedlot Sector. Approximately 20 percent of the calves from the cow-calf sector enter the feedlot
sector directly after they are weaned at about 205 days. These animals are called Weanlings (see Ex-
hibit VI-2). The remaining calves (Yearlings) go through the stacker sector before entering the
feedlot. Once in the feedlot, animals consume a high energy, high protein diet until they reach
slaughter weight.
Exhibit VI-2: Animal
Animal Type
Dairy Replacement
Heifers 0-1 2 Months

Dairy Replacement
Heifers 12-24 Months

Beef Replacement
Heifers 0-1 2 Months

Beef Replacement
Heifers 12-24 Months
Yearling System

Weanling System

Dairy Cows

Beef Cows

Beef Bulls

Groups and Animal Characteristics
Initial
Weight
(kg)
170

285

165

270

170

550

450

650

Final
Weight
(kg)
285

460

270

390

480

550

450

650

Initial
Age
(days)
165

365

165

365

165

365

Final
Age
(days)
365

730

365

730

565

422

730

Other Characteristics
Calves feed on milk for first several months, a mixture of
milk and forage from 60-90 days, and are weaned at 205
days, after which they consume all forage.
Dairy replacements are simulated to give birth at about 24
months, and to increase in body weight to the size of a Holstein
cow, i.e., 550 kg.
Calves feed on milk for first several months, a mixture of
milk and forage from 60-90 days, and are weaned at 205
days, after which they consume all forage.
Beef replacements are simulated to give birth at about 24
months.
Yearling system steers and heifers enter and leave the back-
grounding phase at 1 65 and 425 days of age, respectively.
Subsequently, they spend 1 40 days in the feedlot.
Weanling system steers and heifers enter the feedlot at 1 65
days, and are simulated to stay in the feedlot for 422 days.
Mature dairy cows produce milk for 305 days, followed by a 60
day dry period. They are simulated to give birth at end of 60 day
dry period.
Mature beef cows produce milk for 205 days, and produce less
milk than mature dairy cows.
Beef bulls are simulated to lose weight during the 90 day breed-
ing period, and to gain weight during the rest of the year.
Note: Dairy bulls are not included in the inventory because the dairy bull population is small.
Source: EPA,1993a.
VI.2 Emission Factors

EPA uses emission factors specific to each animal type. These factors are based on research data and expert
opinion. This section presents the factors for cattle and sheep, goats, pigs, and horses.
Cattle. The emission factors for beef and dairy cattle are presented in Exhibit VI-3 and Exhibit VI-4, respectively.
Emission factors are developed using the model by Baldwin, et al. (1987a-b).
VI-2 U.S. Methane Emissions: 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

EPA uses diets in the model developed by Baldwin, et al. (1987 a-b) to estimate emissions from cattle. To account
for differences in diets throughout the U.S., thirty-two different diets are defined by EPA (1993a). Fourteen diets
are defined for dairy cattle, including six for dairy cows and four each for replacement heifers 0-12 months and 12-
24 months. The eighteen beef cattle diets include three each for beef cows, replacement heifers 0-12 months,
Weanling System heifers and steers, and Yearling System heifers and steers. Four diets are defined for beef re-
placement heifers 12-24 months, and two diets are defined for beef bulls. EPA (1993a) provides a breakdown of
the diets by region.
Exhibit VI-3: Emission Factors for Beef Cattle (kg/hd/yr)
Animal
Replacement Heifers (0-1 2) Months
Replacement Heifers (0-24) Months
Mature Cows
Weanlings
Yearlings
Bulls
kg/hd/yr = kilograms per head per year
Source: EPA, 1993a.
North
Atlantic
19.2
63.8
61.5
-
-
-

South
Atlantic
22.7
67.5
70.0
-
-
-

North Central
20.4
60.8
59.5
22.6
47.0
-

South
Central
23.6
67.7
70.9
24.0
47.6
-

West
22.7
64.8
69.1
23.5
47.6
100.0

Exhibit VI-4: Emission Factors for Dairy Cattle (kg/hd/yr)
Animal
Replacement Heifers (0-1 2) Months
Replacement Heifers (0-24) Months
Mature Cows
North
Atlantic
19.5
58.4
125.8
South
Atlantic
20.5
58.7
136.5
North Central
18.9
57.4
111.8
South
Central
20.3
61.7
120.5
West
20.7
61.2
139.4
Note: Emission factors for mature dairy cows change annually according to milk production. Mature dairy cow emission factors are for
1997.
Source: EPA, 1993a.
With the exception of mature dairy cows, the emission factors for cattle have remained unchanged since those re-
ported by EPA in 1993 (EPA, 1993a). Methane emission estimates from dairy cattle are adjusted annually to re-
flect increases in milk production per cow. Emission estimates are altered according to milk production levels
because milk production is related to feed intake, which influences methane production.
Sheep, Goats, Pigs, and Horses. Average emission factor estimates are from Crutzen, et al. (1986), who devel-
oped emission factors for developed and developing countries. These emission factors are shown in Exhibit VI-5.
For this analysis, emission factors for developing countries are used. Typical animal size, feed intakes, and feed
characteristics are considered in the estimates. Emission factors have not been developed for the U.S., specifically,
because emissions from non-cattle are small relative to emissions from cattle.
U.S. Environmental Protection Agency
Appendix VI: Enteric Fermentation VI-3
image:

Exhibit VI-5: Emission Factors for Sheep, Goats, Pigs, and Horses (kg/hd/yr)
Animal Emission Factor
Sheep 8.0
Goats 5.0
Pigs 1.5
Horses 18.0
Source: Crutzen, et al., 1986; EPA, 1993a.
VI-4 U.S. Methane Emissions: 1990-2020: Inventories, Projections, and Opportunities for Reductions
image:

VI.3 References

Baldwin, R.L., J.H.M. Thornley, and D.E. Beever. 1987a. "Metabolism of the Lactating Cow. II. Di-
gestive Elements of a Mechanistic Model," Journal of Dairy Research, 54: 107-131.
Baldwin, R.L., J. France, D.E. Beever, M. Gill, and J.H.M. Thornley. 1987b. "Metabolism of the Lac-
tating cow. III. Properties of Mechanistic Models Suitable for Evaluation of Energetic Relationships
and Factors Involved in the Partition of Nutrients," Journal of Dairy Research, 54: 133-145.
Crutzen, P.J., I. Aselmann, and W. Seiler. 1986. "Methane Production by Domestic Animals, Wild Ru-
minants, Other Herbivorous Fauna, and Humans," Tellus, 386:271-284.
EPA. 1993a. Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to
Congress. Atmospheric Pollution Prevention Division, Office of Air and Radiation, U.S. Environ-
mental Protection Agency, Washington, DC, EPA 430-R-93-003. (Available on the Internet at
http.//www.epa.gov/ghginfo/reports.htm.)
Food and Agriculture Organization (FAO). 1998. Statistical Database. June 12, 1998 (Accessed July
1998.) (Available on the Internet at http://www.fao.org.)
USDA. 1997. Hogs and Pigs. National Agricultural Statistics Service, Agricultural Statistics Board,
U.S. Department of Agriculture, Washington, DC. (Available on the Internet at http://www.
usda.gov/nass.)
USDA. 1998a. Cattle. National Agricultural Statistics Service, Agricultural Statistics Board, U.S. De-
partment of Agriculture, Washington, DC. (Available on the Internet at http://www.usda.gov/nass.)
USDA. 1998b. Cattle on Feed. National Agricultural Statistics Service, Agricultural Statistics Board,
U.S. Department of Agriculture, Washington, DC. (Available on the Internet at http://www.usda.
gov/nass.)
USDA. 1998c. Livestock Slaughter Annual Summary. National Agricultural Statistics Service, Agri-
cultural Statistics Board, U.S. Department of Agriculture, Washington, DC. (Available on the Internet
at http://www.usda.gov/nass.)
USDA. 1998d. Sheep and Goats. National Agricultural Statistics Service, Agricultural Statistics Board,
U.S. Department of Agriculture, Washington, DC. (Available on the Internet at http://www.usda.
gov/nass.)
U.S. Environmental Protection Agency Appendix VI: Enteric Fermentation VI-5
image:

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