United States
Environmental Protection
Agency
Air and Radiation
(6202J)
EPA430-R-93-012
October 1993
rxEPA
Opportunities to Reduce
Anthropogenic Methane Emissions
in the United States
PROPERTY OF
D 4. . r- DIVISION
Report to Congress OF
METEOROLOGY
Natural Gas Systems
Manure Management
<^> Recycled/Recyclable
r\ \\ Printed with Soy/Canola Ink on pape
XHC7 contains at least 50% recycled fiber
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OPPORTUNITIES TO REDUCE
ANTHROPOGENIC METHANE EMISSIONS
IN THE UNITED STATES
REPORT TO CONGRESS
Editor Kathleen B. Hogan
U.S. Environmental Protection Agency
Office of Air and Radiation
October 1993
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This document has been reviewed in accordance with the U.S. Environmental
Protection Agency's and the Office of Management and Budget's peer and
administrative review policies and approved for publication. Mention of trade
names or commercial products does not constitute endorsement or
recommendation for use.
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Table of Contents
EXECUTIVE SUMMARY ES-1
OPPORTUNITIES FOR EMISSIONS REDUCTIONS ES-6
Landfills ES-6
Domesticated Livestock ES-8
Coal Mining ES-10
Natural Gas Systems ES-13
Livestock Manure ES-15
OVERCOMING BARRIERS TO ECONOMIC EMISSIONS REDUCTIONS ES-17
Landfills ES-17
Domesticated Livestock ES-20
Coal Mining ES-21
Natural Gas Systems ES-22
Livestock Manure ES-24
CONCLUSION ES-24
REFERENCES ES-25
CHAPTER 1: INTRODUCTION 1
1.1 BACKGROUND: THE IMPORTANCE OF METHANE 1-1
1.1.1 What is Methane? 1-2
1.1.2 Atmospheric Levels of Methane Are Rising 1-3
1.1.3 Methane and Global Climate Change 1-6
1.1.4 Stabilization and Further Reductions of Global Methane Levels .... 1-7
1.2 SOURCES OF METHANE AND TECHNOLOGIES FOR EMISSIONS
REDUCTIONS 1-8
1.2.1 Natural Gas Systems and Oil Systems 1-9
1.2.2 Coal Mining 1-9
1.2.3 Landfills 1-12
1.2.4 Domesticated Livestock 1-12
1.2.5 Livestock Manure 1-13
1.3 PROFITABLE EMISSIONS REDUCTION PROJECTS IN THE U.S 1-13
1.4 OVERVIEW OF REPORT 1-14
1.5 REFERENCES 1-16
CHAPTER 2: OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM THE NATURAL
GAS SYSTEM
CHAPTER SUMMARY 2-1
2.1 BACKGROUND 2-7
2.1.1 Methane Emissions from the U.S. Natural Gas System 2-7
2.1.2 Future Methane Emissions 2-13
2.2 OVERVIEW OF OPTIONS FOR REDUCING EMISSIONS 2-13
2.2.1 Production Facility Options 2-14
2.2.2 Transmission System Options 2-21
2.2.3 Distribution Network Options 2-27
2.2.4 Emergina Technologies and Practices 2-32
2.3 NATIONAL ASSESSMENT OF EMISSIONS REDUCTIONS 2-35
2.3.1 Production Facilities 2-37
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Table of Contents (Continued)
2.3.2 Transmission Systems 2-41
2.3.3 Distribution Networks 2-47
2.3.4 Summary of Costs and Benefits of Reducing Methane Emissions . . 2-48
2.3.5 Sensitivity Analysis 2-50
2.4 BARRIERS 2-52
2.5 LIMITATIONS 2-55
2.6 REFERENCES 2-55
CHAPTER 3: OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM COAL MINING
CHAPTER SUMMARY 3-1
3.1 BACKGROUND 3-8
3.1.1 Factors Influencing Methane Emissions from Coal Mining 3-9
3.1.2 Candidate Mines for Profitable Methane Recovery 3-9
3.2 OVERVIEW OF METHANE RECOVERY AND UTILIZATION METHODS 3-11
3.2.1 Recovery Methods 3-11
3.2.2 Utilization Methods 3-15
3.3 METHODOLOGY 3-22
3.3.1 The Subjects of the Analysis: Mine Profiles and
Recovery/Utilization Strategies 3-23
3.3.2 Financial Analysis of Recovery and Utilization Investments for
Sample Mine Profiles 3-26
3.3.3 Economic Scenarios 3-30
3.3.4 Number of Mines with the Potential to Recover Methane for a
Profit 3-32
3.4 PROFITABLE EMISSIONS REDUCTIONS 3-35
3.4.1 Technologically Feasible Emissions Reductions 3-36
3.4.2 Profitable Emissions Reductions 3-36
3.4.3 Regional Impacts 3-40
3.4.4 Effective Methane Reduction Strategies 3-44
3.4.5 Benefits to Coal Mines 3-48
3.4.6 Impact of Including Environmental Benefits 3-50
3.5 BARRIERS TO THE RECOVERY AND USE OF METHANE FROM COAL
MINES 3-51
3.5*1 Ownership of Coalbed Methane 3-52
3.5.2 Coal Mining Industry Conditions and Characteristics 3-55
3.5.3 Qualifying Facility Status 3-56
3.5.4 Production Characteristics of Coalbed Methane Wells 3-57
3.5.5 Technical Issues 3-57
3.5.6 Summary of Problems and Available Options 3-59
3.6 STEPS TO REMOVING BARRIERS 3-59
3.6.1 Address Ownership Questions 3-59
3.6.2 Develop Mechanisms that Will Reduce Initial Project Risk and
Uncertainty 3-61
3.6.3 Develop New Technologies for Methane Recovery and Use 3-61
3.6.4 Reduce Barriers to Electricity Sale 3-62
3.6.5 Reduce Barriers to Pipeline Sale 3-62
3.6.6 Encourage Development in the Appalachian Basins 3-63
3.7 LIMITATIONS OF THE ANALYSIS 3-63
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Table of Contents (Continued)
3.7.1 Lack of Mine-Specific Data 3-63
3.7.2 Current Barriers to Coalbed Methane Projects 3-64
3.8 REFERENCES 3-64
APPENDIX 3A: CALCULATIONS AND DATA TABLES FOR COAL ANALYSIS 3A-1
Physical Calculations for Recovery 3A-1
Physical Calculations for Utilization 3A-7
Financial Calculations 3A-12
CHAPTER 4: OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM LANDFILLS
CHAPTER SUMMARY 4-1
4.1 BACKGROUND 4-9
4.1.1 Methane Emissions from Landfills 4-9
4.1.2 Other Major Factors Affecting Future Methane Emissions 4-12
4.2 OVERVIEW OF OPTIONS FOR REDUCING EMISSIONS 4-14
4.2.1 Landfill Gas Recovery and Utilization 4-14
4.2.2 Examples of Recovery and Utilization Projects 4-21
4.3 NATIONAL ASSESSMENT OF PROFITABLE METHANE REDUCTIONS 4-23
4.3.1 Landfill-Level Financial Analysis 4-23
4.3.2 Assessment of Profitable Options Nationally 4-34
4.3.3 Methane Emissions Mitigated 4-35
4.4 PROFITABLE EMISSION REDUCTIONS FROM LANDFILLS 4-35
4.4.1 Profitability for a Range of Electricity Prices 4-35
4.4.2 The Proposed Landfill Air Pollution Control Rule 4-38
4.4.3 Sensitivity Analysis 4-41
4.4.4 Impact of Including Environmental Benefits 4-47
4.5 BARRIERS 4-48
4.6 LIMITATIONS 4-50
4.7 REFERENCES 4-52
CHAPTER 5: OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM LIVESTOCK
CHAPTER SUMMARY 5-1
5.1 BACKGROUND 5-5
5.1.1 Livestock Methane Emissions 5-5
5.1.2 Approaches for Reducing Emissions from Cattle 5-11
5.2 OVERVIEW OF OPPORTUNITIES FOR EMISSIONS REDUCTIONS 5-15
5.2.1 Productivity Enhancing Agents and Practices 5-16
5.2.2 Marketing and Pricing System Refinements 5-27
5.2.3 Future Options for Reducing Emissions 5-33
5.3 NATIONAL ASSESSMENT OF PROFITABLE METHANE REDUCTION 5-36
5.3.1 Dairy Industry 5-37
5.3.2 Beef Industry 5-40
5.3.3 Total Methane Emissions Mitigated 5-42
5.4 BARRIERS 5-44
5.5 LIMITATIONS 5-46
5.6 REFERENCES 5-46
Mi
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Table of Contents (Continued)
CHAPTER 6: OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM LIVESTOCK
MANURE
CHAPTER SUMMARY 6-1
6.1 BACKGROUND 6-6
6.1.1 Livestock Manure Management and Methane Emissions 6-6
6.1.2 Trends in Livestock Manure Management 6-10
6.2 OVERVIEW OF OPTIONS FOR EMISSIONS REDUCTIONS 6-14
6.2.1 Methane Recovery Systems 6-14
6.2.2 Alternative Manure Management Systems 6-22
6.2.3 Methane Utilization 6-23
6.2.4 Typical Methane Recovery and Utilization Systems 6-25
6.3 NATIONAL ASSESSMENT OF PROFITABLE METHANE REDUCTION 6-28
6.3.1 Farm-Level Financial Analysis 6-29
6.3.2 Assessment of Profitable Options Nationally 6-41
6.3.3 Methane Emissions Mitigated 6-42
6.3.4 Comparison of Systems for Mitigating Methane Emissions 6-42
6.4 PROFITABLE EMISSION REDUCTIONS FROM LIVESTOCK MANURE 6-43
6.4.1 Profitable Emissions Reductions 6-45
6.4.2 Regional Pattern of Profitability 6-47
6.4.3 Sensitivity Analysis 6-50
6.4.4 Impact of Including Environmental Benefits 6-54
6.4.5 Future Emission Reduction Opportunities 6-55
6.5 BARRIERS 6-58
6.6 LIMITATIONS 6-63
. 6.7 REFERENCES 6-64
CHAPTER 7: BARRIERS TO METHANE REDUCTION PROJECTS
7.1 CONDITIONS IN THE ELECTRIC POWER INDUSTRY 7-1
7.1.1 Power Generation for On-Site Use 7-1
7.1.2 Off-Site Sale of Electricity 7-2
7.2 CONDITIONS IN THE PIPELINE AND NATURAL GAS INDUSTRIES 7-3
7.2.1 Pipeline Capacity 7-3
7.2.2 Third Party Sales 7-4
7.3 SUMMARY OF AVAILABLE OPTIONS 7-5
iv
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List of Exhibits
EXECUTIVE SUMMARY
Exhibit ES-1: Global Contribution to Integrated Radiative Forcing by Gas for 1990 .... ES-2
Exhibit ES-2: U.S. Anthropogenic Emissions Summary ES-3
Exhibit ES-3: Technically Feasible and Economically Justified Emissions Reductions:
2000 and 2010 ES-4
Exhibit ES-4: Methane Reductions Justified By Valuing Environmental Benefits ES-6
Exhibit ES-5: Opportunities to Reduce Methane Emissions from Coal Mining:
Regional Impacts ES-12
Exhibit ES-6: Key Near Term Barriers to Methane Recovery and Possible Solutions . . ES-18
Exhibit CHAPTER 1: INTRODUCTION
Exhibit 1 -1: Estimated Sources and Sinks of Methane 1-4
Exhibit 1 -2: Measurements of Global Methane Concentrations 1-5
Exhibit 1 -3: Global Contribution to Integrated Radiative Forcing by Gas for 1990 1-7
Exhibit 1 -4: Carbon Dioxide and Methane Reduction Comparison 1-8
Exhibit 1-5: U.S. Anthropogenic Emissions Summary 1-10
Exhibit 1-6: Summary of Technologies for Reducing Methane Emissions in the U.S. . . 1-11
Exhibit 1 -7: Summary of Discount Rates Used in This Report 1-15
CHAPTER 2: OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM THE NATURAL
GAS SYSTEM
Exhibit 2-1: Methane Emissions and Potential Reductions By Stage of the Natural
Gas System 2-3
Exhibit 2-2: Summary of Major Options for Reducing Methane Emissions from the
Natural Gas Industry 2-4
Exhibit 2-3: Stages of the U.S. Natural Gas System 2-8
Exhibit 2-4: 1990 Emissions and Major Features of the U.S. Natural Gas System 2-9
Exhibit 2-5: Future Methane Emissions from the U.S. Natural Gas System 2-14
Exhibit 2-6: Techniques for Reducing Methane Emissions 2-15
Exhibit 2-7: Example Pneumatic Device Bleed Rates 2-17
Exhibit 2-8: Possible Leak Areas in a Gate Valve 2-19
Exhibit 2-9: Costs Associated with Directed I/M Programs at Gas Wellsites 2-22
Exhibit 2-10: Costs of Directed I/M Program at Transmission Pipelines Compressor
Stations 2-24
Exhibit 2-11: Methane Emissions from Two Compressor Station Designs 2-28
Exhibit 2-12: Incremental Costs of Turbines vs. Reciprocating Engines 2-28
Exhibit 2-13: Costs of Directed I/M Programs at Gate Stations 2-30
Exhibit 2-14: U.S. Distribution Pipe Materials in 1990 and Their Leakage Rates 2-31
Exhibit 2-15: Methane Conversion with a Light Hydrocarbon Catalyst 2-34
Exhibit 2-16: Profitability of Techniques for Reducing Methane Emissions 2-37
Exhibit 2-17: Profitability of Reduction Options in the Production Stage 2-40
Exhibit 2-18: Profitability of Reduction Options in the Transmission Stage 2-44
Exhibit 2-19: Summary of Potential Methane Emission Reductions 2-49
Exhibit 2-20: Sensitivity Analysis Summary 2-51
Exhibit 2-21: Barriers to Implementing Profitable Methane Emission Reduction
Options 2-53
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List of Exhibits (Continued)
CHAPTER 3: OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM COAL MINING
Exhibit 3-1: Projected Emissions and Potential Profitable Emissions Reductions For
Underground Mines 3-3
Exhibit 3-2: Impact of Wellhead Gas Price on Projected Emission Reduction 3-3
Exhibit 3-3: Regional Impacts 3-4
Exhibit 3-4: Estimated Potential Profitable Emissions Reductions Comparison of
Results for Different Recovery Methods for Pipeline Projects 3-6
Exhibit 3-5: Current Coal Mine Methane Pipeline Projects 3-7
Exhibit 3-6: 1988 Coal Production and Estimated Methane Emissions-Surface and
Underground Mines 3-10
Exhibit 3-7: Estimated Number of Large Mines in 1988 with High Methane
Emissions per Ton of Coal Mined 3-11
Exhibit 3-8: Summary of Methods for Recovering Methane from Underground
Mines 3-12
Exhibit 3-9: Diagram of Methods for Recovering Methane from Underground Coal
Mines 3-13
Exhibit 3-10: Utilization Options for Coalbed Methane 3-16
Exhibit 3-11: Current Coal Mine Methane Pipeline Projects 3-16
Exhibit 3-12: Methodology Flow-Chart 3-26
Exhibit 3-13: Summary of Financial Factors 3-29
Exhibit 3-14: Key Base Case Assumptions 3-31
Exhibit 3-15: Coal Production and Degasification Emissions Levels used to Project
Emissions and to Estimate the Number of Large and Gassy Mines in
2000 and 2010 3-35
Exhibit 3-16: Projected Emissions and Potential Profitable Emissions Reductions 3-38
Exhibit 3-17: Estimated Potential Profitable Emissions Reductions: Comparison of
Results for Different Economic Scenarios Mid Case Emissions 3-39
Exhibit 3-18: Projected Emissions and Potential Emissions Reduction by Basin 3-41
Exhibit 3-19: Estimated Potential Profitable Emissions Reductions: Comparison of
Results for Different Recovery Methods for Pipeline Projects 3-46
Exhibit 3-20: Estimated Range of Net Present Values for Coal Mine Methane
Projects 3-49
Exhibit 3-21: Impact of Including Environmental Benefits 3-51
Exhibit 3-22: Barriers, and Related Options Facing Methane Recovery at Coal Mines . . 3-60
APPENDIX 3A: CALCULATIONS AND DATA TABLES FOR COAL ANALYSIS
Exhibit 3A-1: Sample Calculation for Determining Number of Wells Drilled for a Mine
Profile 3A-1
Exhibit 3A-2: Tonnage per well Ratios for Gob Wells 3A-2
Exhibit 3A-3: Tonnage per Well Ratios for Vertical Wells 3A-2
Exhibit 3A-4: Recovery Percentages for Vertical and Gob Wells 3A-4
Exhibit 3A-5: Methane Recovery from Vertical Wells Drilled Ten Years in Advance of
Mining For a Sample Mine Profile 3A-4
Exhibit 3A-6: Methane Recovered over Lifetime of a Project for a Sample Mine
Profile Two Year Vertical Well Recovery Method 3A-5
Exhibit 3A-7: Methane Recovered Over Lifetime of a Project for a Sample Mine
Profile Ten Year Vertical Well Recovery Method 3A-6
- Exhibit 3A-8: Gas Production to Water Production Ratios 3A-7
vi
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List of Exhibits (Continued)
Exhibit 3A-9: Equipment Needed for the Potential Recovery and Utilization Methods . . 3A-8
Exhibit 3A-10: Generator Heat Rates (Btu/kWh) 3A-9
Exhibit 3A-11: Calculations for Incremental Electric Capacity from Ventilation Air
Utilization 3A-10
Exhibit 3A-12: On-site Electricity Needs (kWh per ton of coal mined) 3A-10
Exhibit 3A-13: Calculations for Determining Energy Savings from a Reduction in
Ventilation Air Needs 3A-11
Exhibit 3A-14: Capital Costs for Gob Wells 3A-12
Exhibit 3A-15: Capital Costs for Vertical Wells 3A-13
Exhibit 3A-16: Capital Costs for Water Disposal (Vertical Wells Only) 3A-14
Exhibit 3A-17: Capital Costs for Pipeline Injection: All Equipment Needed Between
the Wellhead and a Central Compressor 3A-14
Exhibit 3A-18: Capital Costs for Pipeline Injection: Gathering Lines to Main
Commercial Pipeline 3A-15
Exhibit 3A-19: Capital Costs for Power Generation 3A-16
Exhibit 3A-20: Operating Costs for Recovery Wells 3A-16
Exhibit 3A-21: Operating Costs for Water Disposal From Vertical Wells 3A-17
Exhibit 3A-22: Operating Costs for Pipeline Injection: All Equipment Needed Between
the Wellhead and a Central Compressor 3A-17
Exhibit 3A-23: Operating Costs for Power Generation 3A-18
Exhibit 3A-24: Wellhead Gas Price (1990 $/mcf) 3A-18
Exhibit 3A-25: Avoided Cost (1990 dollars) 3A-19
Exhibit 3A-26: Projected Electricity Price Paid by Mine 3A-19
CHAPTER 4: OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM LANDFILLS
Exhibit 4-1: Profitable Methane Emissions Reductions and Remaining Emissions by
Electricity Price 4-4
Exhibit 4-2: Electricity Generating Capacity of Existing Landfill Projects 4-8
Exhibit 4-3: National Emission Estimates for 1990 4-11
Exhibit 4-4: State Source Reduction Efforts (1991) 4-13
Exhibit 4-5: Electricity Generating Capacity of Existing Landfill Projects 4-22
Exhibit 4-6: Methane Production, Recovery, and Emissions from Representative
Landfills 4-27
Exhibit 4-7: Representative Landfill Energy Recovery System Costs: Capital &
Annual O&M 4-28
Exhibit 4-8: Representative Landfill Energy Recovery System Costs: Total Lifecycle
Costs 4-30
Exhibit 4-9: Profitable Methane Mitigation at Existing Landfills: $0.04, $0.05, and
$0.06/kWh 4-37
Exhibit 4-10: Profitable Methane Mitigation at New Landfills: $0.04, $0.05, and
$0.06/kWh 4-39
Exhibit 4-11: Potentially Profitable Methane Mitigation: Engine Generator Capacity in
2000 4-40
Exhibit 4-12: Implications of Electricity Production for Landfill Air Pollution Control
Rule Costs 4-42
Exhibit 4-13: Profitable Methane Mitigation at Existing Landfills - Sensitivity Analysis . . 4-43
Exhibit 4-14: Profitable Methane Mitigation at New Landfills - Sensitivity Analysis .... 4-44
Exhibit 4-15: Sensitivity Analysis Results 4-46
vii
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List of Exhibits (Continued)
Exhibit 4-16: Barriers Limiting Implementation of Landfill Methane Recovery Projects . . 4-51
CHAPTER 5: OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM LIVESTOCK
Exhibit 5-1: Methane Emissions from U.S. Livestock and Profitable Emissions
Reductions 5-3
Exhibit 5-2: Summary of Livestock Methane Emissions Reduction Options 5-4
Exhibit 5-3: 1990 U.S. Methane Emissions from Livestock 5-9
Exhibit 5-4: Scenarios of Future Livestock Methane Emissions 5-11
Exhibit 5-5: Trend in Dairy Cow Productivity 5-12
Exhibit 5-6: Trend in Beef Production per Cow 5-12
Exhibit 5-7: Methane Emissions Associated with Maintenance and Production in
the Dairy and Beef Industries 5-13
Exhibit 5-8: Overview of Livestock Methane Emissions Reduction Options 5-17
Exhibit 5-9: Impacts of Implant Use in Beef Production 5-21
Exhibit 5-10: Return on Assets is Positively Correlated with Weaning Percentage 5-24
Exhibit 5-11: Cows Required Per 100 Calves Weaned for a Range of Weaning
Percentages and Heifer Calving Rates 5-26
Exhibit 5-12: PTAs for Protein and Fat for the Top Active Al Bulls in the U.S 5-31
Exhibit 5-13: Increases in Annual Milk Production Per Cow and Reductions in
Methane Emissions Per Unit Product: 2000 and 2010 5-38
Exhibit 5-14: Emissions Reductions in the Dairy Industry 5-39
Exhibit 5-15: Regional Cow-Calf Productivity 5-42
Exhibit 5-16: Emissions Reductions in the Beef Industry 5-43
Exhibit 5-17: Total National Livestock Emissions Reductions 5-44
CHAPTER 6: OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM LIVESTOCK
MANURE
Exhibit 6-1: Methane Emissions from U.S. Livestock Manure and Profitable
Emissions Reductions 6-4
Exhibit 6-2: Livestock Manure System Usage for the U.S 6-8
Exhibit 6-3: U.S. Methane Emissions from Livestock Manure - 1990 6-9
Exhibit 6-4: Dairy and Hog Facility Methane Emissions in Key States (1990) 6-9
Exhibit 6-5: Schematic of an Anaerobic Lagoon System 6-13
Exhibit 6-6: VS Reduction at a Covered Lagoon 6-15
Exhibit 6-7: COD Reduction at a Covered Lagoon 6-15
Exhibit 6-8: Organic Nitrogen Reduction at a Covered Lagoon 6-16
Exhibit 6-9: Schematic of a Covered Lagoon 6-18
Exhibit 6-10: Schematic of a Plug Flow Digester 6-19
Exhibit 6-11: Schematic of a Complete Mix Digester 6-21
Exhibit 6-12: Load Profile of a 1,000 Sow Farrow-to-Finish Operation 6-25
Exhibit 6-13: Typical Methane Recovery Systems Operating in the U.S 6-27
Exhibit 6-14: On-Farm Energy Savings at a Swine Operation 6-28
Exhibit 6-15: Representative Covered Lagoon Installation Costs 6-30
Exhibit 6-16: Representative Complete-Mix Digester Installation Costs 6-31
Exhibit 6-17: Representative Plug-Flow Digester Installation Costs 6-31
Exhibit 6-18: Average Gas Recovery Rates Per Unit of Manure Handled 6-33
Exhibit 6-19: On-Farm Electric Demand on Hog Farms 6-35
viii
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List of Exhibits (Continued)
Exhibit 6-20: Gas Utilization Equipment Costs 6-36
Exhibit 6-21: Total Costs of Representative Gas Recovery and Utilization Projects .... 6-38
Exhibit 6-22: State-Average Electricity Prices 6-39
Exhibit 6-23: Cost and Benefit Summary of Methane Recovery Systems 6-40
Exhibit 6-24: Comparison of Methane Mitigation Systems 6-44
Exhibit 6-25: Estimated Profitable Methane Recovery Using Covered Lagoons in the
U.S 6-46
Exhibit 6-26: Profitable Regions for Dairy Farms with 500 or More Cows 6-48
Exhibit 6-27: States with Greatest Potential for Profitable Methane Recovery (Dairy
Farms) 6-49
Exhibit 6-28: Profitable Regions for Swine Farms with 2,000 or More Hogs 6-51
Exhibit 6-29: States with Greatest Potential for Profitable Methane Recovery using
Covered Lagoons (Hog Farms) 6-52
Exhibit 6-30: Profitable Methane Mitigation Under a Range of Electricity Prices 6-53
Exhibit 6-31: Dairy Cows on Large Farms Over Time 6-57
Exhibit 6-32: Hogs on Large Farms Over Time 6-58
Exhibit 6-33: Emissions Reduction Potential for 2000 and 2010 6-59
Exhibit 6-34: Barriers Limiting Methane Recovery from Livestock Manure 6-63
CHAPTER 7: BARRIERS TO METHANE REDUCTION PROJECTS
Exhibit 7-1: Barriers to Methane Recovery Projects and Related Options 7-6
ix
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FOREWORD
Opportunities to Reduce Anthropogenic Methane Emissions in the United States
provides estimates of the potential in the United States for minimizing emissions of methane
caused by human activities. It is my pleasure to introduce this report, which is one of five
studies relating to methane emissions that were prepared in response to the requirements of
the Clean Air Act Amendments of 1990.
The primary impetus behind this report was the need to evaluate the numerous
options for reducing United States emissions of this potent greenhouse gas. This was no
small task, because a variety of human endeavors cause methane emissions, and several
methane mitigation strategies are applicable to each of these activities.
For each of the five major sources of emissions in the United States, the chapters of
this report describe the array of technologies and practices that are currently available to
reduce methane emissions, as well as those under development. For the most promising of
these mitigation options, detailed methods were developed to estimate technically feasible
reductions, as well as reductions that may be cost-effective for private owners/operators.
Based on these methods, the potential for emissions reductions over the next twenty years is
presented, taking into account the numerous factors that may impact methane mitigation
projects, such as future gas and electricity prices, future production and population growth,
and other economic, demographic, and regulatory trends. Furthermore, the types of facilities
for which such projects may be feasible and, where possible, the regions of the United States
containing large numbers of potentially profitable projects are identified for each source.
Finally, key barriers that may constrain the wider development of such projects are identified.
The following report makes a major contribution to our knowledge about the
potential to implement methane reduction programs and is a first step toward overcoming the
lack of information that may have inhibited the development of such programs in the past. It
establishes that substantial opportunities exist to reduce emissions of methane in the United
States - opportunities that in many cases are economically justifiable even without
consideration of environmental benefit. Importantly, this report shows that emissions
mitigation projects developed at landfills, coal mines, livestock operations, and natural gas
systems could make a large contribution to the goal of stabilizing United States emissions at
1990 levels.
Paul M. Stolpman
Acting Director
Office of Atmospheric Programs
Office of Air and Radiation
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ACKNOWLEDGEMENTS
This report would not have been possible without the dedicated efforts of a number
of people who contributed throughout the process of developing the report.
After much investigation and discussion, the lead authors of the main chapters
designed new and detailed methods (using the best available information) to estimate the
potential to reduce emissions from the major sources of methane in the United States. These
new methods incorporate large amounts of data on available technologies and practices for
mitigating these emissions and greatly refine our understanding of where and how emissions
reductions may be achieved. The lead authors are:
Natural Gas Systems Michael Gibbs
Pradeep Hathiramani
Gordon Weynand
Coal Mining Mary DePasquale
Dina Kruger
Landfills Jonathan Woodbury
Cindy Jacobs
Domesticated Livestock Michael Gibbs
Livestock Manure Jonathan Woodbury
Kurt Roos
For some chapters, significant research was performed to assist in the development
of emission reduction estimates. This includes efforts by Lee Baldwin (University of California
Davis) for domesticated livestock, Andy Hashimoto (University of Oregon) and Mark Moser
(RCM Digesters) for livestock manure, and R. Michael Cowgill (Radian Corporation) for natural
gas systems. Substantial analytical work was performed in support of other chapters. This
includes efforts by Tom Cantine, Mary DePasquale, Michael Gibbs, Pradeep Hathiramani, and
Jonathan Woodbury of ICF Incorporated.
Useful comments were provided by the following people throughout industry and the
U.S. government. All comments were greatly appreciated.
Introduction
Tony Janetos (NASA)
Natural Gas Systems
David Bays (ENRON Corporation/Gas Paul Goodson (Southern California Gas)
Pipeline Group) Nelson Hay (American Gas Association)
William Breed (US Department of Energy) Andy Hirsch (Southern California Gas)
Art Eberle (Columbia Gas) Theodore Kinne (INGAA)
John Goodrich-Mahoney (Electric Power David Kirchgessner (US Environmental
Research Institute) Protection Agency)
Xi
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Natural Gas Systems (continued)
Gary Klein (Oil Heat Task Force)
Steve Lawrence (Pacific Gas and Electric)
Robert Lott (Gas Research Institute)
Paul Martino (American Petroleum Institute)
Shahed Meshkati (Southern California Gas)
Brad Mitchell (ENRON Corporation)
Dr. Ralph Perhac (ret., Electric Power
Research Institute)
Don C. Porter (Director, Environmental
Protection Texas Eastern Transmission
Corporation)
Michael T. S. Reilly (West Ohio Gas)
Mike Riordan (Brooklyn Union Gas)
Vernon Schlievelbein (TEXACO)
Mark Sutton (Gas Processors Association)
Brian Tulloh (ARCO Oil and Gas Company)
Charles Urban (Southwest Research
Institute)
Bob Van Wyck (Consolidated Edison)
John Warner (AMOCO Production
Company)
Mike Webb (Star Environmental)
Ted Williams (US Department of Energy)
Robert J. Zlokovitz (Consolidated Edison
Co. of New York)
Coal Mining
William Breed (US Department of Energy)
Charlie Byrer (US Department of Energy)
Gerry Finfinger (US Bureau of Mines)
Carla Kertis (US Bureau of Mines)
Dave Kirchgessner (US Environmental
Protection Agency)
Bruce Levy (O'Brien Energy)
Joel Mize (Trigon Engineering, Inc.)
Patricia Patten (OXY USA Inc.)
Ray Pilcher (Raven Ridge Resources)
Joanne Reilly (Cyprus Emerald Resources)
R.G. Sanders (Black Warrior Methane)
Pramod C. Thakur (Consol Inc.)
Ted Williams (US Department of Energy)
Landfills
Chuck Anderson (SEC Donohue)
Dick Ay (Cummins Chesapeake, Inc.)
Richard Echols (BFI)
Ray Huitric (SWANA)
John Pacey (FHC, Inc.)
Eric Peterson (SCS Engineers)
Susan Thorneloe (US Environmental
Protection Agency)
Frank Wong (Pacific Energy)
Domesticated Livestock
James Anderson (Colorado Cattle Feeders
Association)
Don Augenstein (EMCON Associates)
Lee Baldwin (UC Davis)
Floyd Byers (TAMU)
Gary Evans (US Department of Agriculture)
Richard F. Failed (US Department of
Agriculture)
Donald R. Gill (Oklahoma State University)
Ronald A. Gustafson (US Department of
Agriculture)
Lowry A. Harper (US Department of
Agriculture)
Donald Johnson (Colorado State
University)
Gregory G. Ruehle (National Cattlemen's
Association)
xii
-------
Livestock Manure
Gary Evans (U.S. Department of Deane Morse (DC Davis)
Agriculture) Joseph Roetheli (U.S. Deparment of
Andy Hashimoto (University of Oregon) Agriculture)
David Lyons (U.S. Environmental L.M. "Mac" Safley (North Carolina State
Protection Agency) University)
Rick Mattocks (UNISYN) Lewis Smith (U.S. Department of
Agriculture)
xiii
-------
EXECUTIVE SUMMARY
Methane is second only to carbon dioxide as a major contributor to potential global
warming (Exhibit ES-1). Methane's contribution is large in part because it is a potent
greenhouse gas. Over a one hundred year time period, methane is about twenty times more
effective than carbon dioxide at trapping heat in the atmosphere. Furthermore, methane's
concentration in the atmosphere has increased rapidly. Atmospheric methane concentrations
have more than doubled over the last two centuries and continue to rise annually. These
increases are largely due to increasing emissions from anthropogenic (human related)
sources, which now constitute about 70 percent of global total emissions.
Reducing methane emissions provides an effective means of mitigating global
warming. This effectiveness results from methane's characteristics as well as the types of
facilities and systems that are generally large methane emitters.
• Substantial atmospheric benefits. Reductions in methane emissions can be fairly
rapidly translated into lower levels of radiative forcing in the atmosphere due to
methane's relatively short atmospheric lifetime and high potency. As a result,
reductions in methane emissions could have a significant impact on slowing the rate
of climate change. Stabilizing methane concentrations could have roughly the same
effect on limiting future warming as stabilizing CO2 emissions at 1990 levels, even
though C02 is a greater contributor to potential global warming.
• Economic and other environmental and social benefits. Because methane is an
energy source as well as a greenhouse gas, many emissions control options have
economic benefits. Methane emissions can be viewed as an inefficiency in a system,
and, in many cases, methane that otherwise would be emitted to the atmosphere can
be recovered and utilized. Therefore, methane emissions reduction strategies may be
low cost, or even profitable. Many technologies and practices that reduce methane
emissions also have collateral benefits of reducing air and water pollution and
increasing worker safety.
• Concentrated Emissions. In contrast to the numerous sources of other greenhouse
gasses, a few large facilities often account for a large portion of methane emissions.
Therefore, applying emission reductions strategies to a few facilities with high
emissions would result in a substantial decrease in the quantity of methane emitted.
In the United States, there are numerous opportunities to reduce methane emissions, many of
which are economically viable projects that are hindered by a variety of regulatory, financial,
or informational barriers. These opportunities exist for each of the major U.S. sources.
ES-1
-------
Exhibit ES-1
Global Contribution to Integrated Radiative Forcing by Gas for 1990a
Carbon Dioxide: 66%
N i trous
Ox i de ' 5%
CFCs' 11%
Methane• 18%
Estimated on a carbon dioxide equivalent basis using IPCC (1990) global warming
potentials (GWPs) for a 100-year time horizon. Anthropogenic emissions only.
This chart is used to present a general understanding of methane's contribution to future warming based on the GWPs
presented in IPCC (1990). However, these GWPs are continually being revised due to a variety of scientific and
methodological issues. The contribution of CFCs presented may decrease (although not likely to the extent indicated in
IPCC (1992)), and the contribution of other gases will be about the same or greater upon further investigation.
U.S. anthropogenic methane emissions are estimated to have been 25 to 30 Tg1 in
1990 and are projected to grow to 27 to 35 Tg in 2000 (as shown in Exhibit ES-2).2 The
analysis in this report supports the following general findings about the potential to reduce
these emissions:
• Technologically Feasible Emissions Reductions. It is technologically feasible to reduce
methane emissions from anthropogenic sources by about 50 percent using currently
available technologies and practices (see Exhibit ES-3). These currently available
technologies and practices include (1) recovering methane emitted from landfills, coal
mines, and livestock manure for use as an energy source; (2) improving the
production efficiency of cattle so as to reduce methane emissions per unit of product
(i.e., milk or meat) produced; and (3) reducing emissions from natural gas systems by
implementing such practices as enhancing inspection and maintenance programs and
using lower-emitting operational equipment.
1 Tg = Teragram = 1012 grams = 109 kilograms = 106 metric tons.
n
The range in the estimate reflects uncertainty about emissions from individual sources. These sources are a
variety of complex geological, biological, and energy systems, and emissions are difficult to estimate because they may
vary regionally, with seasons, over the course of a day, and from year to year.
ES-2
-------
Exhibit ES-2
U.S. Anthropogenic Emissions Summary (Tg/yr)
Source
Landfills3
Domesticated Livestock
Dairy Cattle
Beef Cattle
Other Animals
Total Domesticated Livestock
Coal Mining
Underground Coal Mines3
Surface Coal Mines
Post-Mining
Total Coal Mining
Natural Gas Systems
Production
Transmission
Distribution
Engine Exhaust
Other
Total Natural Gas Systemsb
Livestock Manure
Dairy
Swine
Other
Total Livestock Manure
Other Sources
Rice
Combustion
Oil Systems
Other0
Total Other Sources6
Total6
1990
8.1 to 11.8
1.2 to 1.8
3.2 to 4.8
0.2 to 0.4
4.6 to 6.9
3.0 to 4.8
0.2 to 0.7
0.5 to 0.8
3.6 to 5.7
0.7 to 1.8
0.6 to 2.1
0.2 to 0.8
0.3 to 0.6
<0.1 to 0.3
2.2 to 4.3
0.6 to 1.0
0.8 to 1.4
0.3 to 1.2
1.7 to 3.6
0.1 to 0.7
0.4 to 1.7
0.1 to 0.6
Not Estimated
1.0 to 2.4
25 to 30
2000
8.8 to 12.7
1.4 to 2.0
3.4 to 5.5
0.2 to 0.4
5.0 to 7.9
3.0 to 4.8
0.2 to 0.8
0.5 to 1.0
3.7 to 6.5
0.8 to 2.3
0.6 to 2.2
0.2 to 0.8
0.4 to 0.8
<0.1 to 0.3
2.4 to 5.0
1.1 to 1.7
1.7 to 2.6
0.3 to 1.3
3.1 to 5.6
0.1 to 0.7
0.4 to 1.7
0.1 to 0.5
Not Estimated
1.0 to 2.3
27 to 35
2010
9.5 to 13.4
1.4 to 2.4
3.1 to 5.4
0.2 to 0.4
4.8 to 8.2
4.1 to 6.6
0.3 to 0.9
0.7 to 1.2
5.0 to 8.7
0.8 to 2.5
0.7 to 2.4
0.2 to 0.9
0.4 to 0.9
<0.1 to 0.4
2.5 to 5.4
1.2 to 2.0
1.6 to 2.6
0.4 to 1.4
3.2 to 6.0
0.1 to 0.7
0.4 to 1.7
0.1 to 0.5
Not Estimated
1.0 to 2.3
29 to 39
Source: USEPA (1993)
a Does not include methane recovered and used as an energy source. For landfills,
about 1 .5 Tg was recovered and flared or used for energy purposes. For coal mines,
about 0.25 Tg was recovered and sold to pipelines.
b The uncertainty in the total is estimated assuming that the uncertainty for each
source is independent. Consequently, the uncertainty range for the total is more
narrow than the sum of the ranges for the individual sources. For natural gas systems,
total emissions are calculated assuming that some of the uncertainty for each source is
independent.
c Includes non-fuel biomass burning, wastewater from agricultural industries, ammonia
production, coke, iron, and steel production, and land use changes.
ES-3
-------
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Economically Justified Emissions Reductions. Methane emissions in the United States
can be reduced by about 20 to 30 percent using economically justified options (see
Exhibit ES-3).3 Most of the economically justified emissions reductions are
associated with capturing methane and using it as an energy source.
• An amount of methane equivalent to about 35 to 55 million metric tons of
carbon dioxide (as carbon) could be prevented from escaping into the
atmosphere.4
• An amount of methane equivalent to about 2 percent of total annual U.S.
natural gas consumption could be recovered.
• A relatively small number of facilities that emit large amounts of methane are
best situated to implement profitable methane recovery technologies. If about
10 to 15 percent of the landfills, one percent of the swine and dairy farms, and
10 percent of large underground coal mines (mines with annual production
greater than 0.5 million tons) implemented methane recovery projects, the
predicted economically justified methane reductions from these sources would
be achieved.
These economically justified reductions could increase over the next decade due to
further technological developments, trends toward consolidation of production facilities
and increased production levels, and more stringent environmental requirements.
Barriers Impeding Project Development. A host of barriers has impeded the
development of methane recovery/reduction projects at many facilities that would
otherwise indicate the possibility of profitable recovery. These barriers include
financial, informational, legal, regulatory, and institutional considerations. If some of
these barriers are overcome, the next decade will likely see an increased number of
facilities capable of profitable emissions reductions.
Collateral Benefits. Greater employment of methane reduction technologies and
practices will yield important collateral benefits, above those of profitability. These
benefits include contributions to fuel conservation, worker safety, public health, and
production efficiencies. Furthermore, in addition to reducing emissions of methane,
methane mitigation technologies result in other important environmental benefits:
• reduced emissions of air pollutants associated with fossil fuel burning (to the
extent that these fuels are displaced by methane recovered from landfills and
animal manure management), potentially amounting to over 5 million metric
tons of CO2 (as carbon) and 150 thousand metric tons of SO2;
• reduced emissions of air pollutants from landfills; and
• reduced odors and agricultural runoff from animal manure management.
3 Options are considered economically justified if they are estimated to be profitable for private owners and
operators of the affected facilities. For example, to be economically justified an option for reducing emissions for a
natural gas system must save enough gas to justify the cost of the option. The economic assumptions are somewhat
different for different sectors and are detailed in the report introduction (Exhibit 1-7) and in each chapter.
4 This estimate assumes a 100 year GWP for methane of 22.
ES-5
-------
Implications of Including Environmental Benefits. If monetary values are placed on the
environmental benefits of reducing methane emissions, these emissions could be cost-
effectively reduced to a much larger extent. At a value of $5 per ton of carbon
avoided, projected emissions could be reduced by an additional 1.2 to 1.3 Tg (a total
of nearly 40 percent of projected emissions). Moreover, at a value of $100 per ton of
carbon avoided, projected emissions could be reduced by an additional 5.0 to 5.7 Tg -
- a total of about 50 percent of projected emissions (see Exhibit ES-4).
Exhibit ES-4
Methane Reductions Justified By Valuing Environmental Benefits
Methane
Source
Landfills
Livestock
Coal Mining
Natural Gas
Livestock Manure
Other
TOTALb
Methane
Emissions
in 2000
09)
8.8 to 12.7
5.0 to 7.9
3.7 to 6.5
2.4 to 5.0
3.1 to 5.6
1.0 to 2.3
27 to 35
Reductions Justified with Value Placed on Environmental
Benefits
No
Value
5.0 to 7.4
0.6 to 1.7
1.0 to 2.2
0.3 to 1.2
0.5 to 0.8
8.8 to 11.8
Value of
$5/ton
carbon
7.0 to 8.0
0.6 to 1.7a
1.2 to 2.4
0.3 to 1.2
0.7 to 1.0
11.0 to 13.1
Value of
$20/ton
carbon
7.5 to 8.5
0.6 to 1.7a
1.4 to 2.6
0.3 to 1.2
1.1 to 1.5
12.1 to 14.3
Value of
$100/ton
carbon
8.5 to 9.5
0.6 to 1.7a
1.6 to 2.8
0.3 to 1.2
2.1 to 2.9
14.5 to 16.8
a The additional reductions that would be economically justified by monetizing the value of the
environmental benefits associated with emissions reductions were not estimated for livestock.
b The uncertainty in the total is estimated assuming that the uncertainty for each source is
independent. Consequently, the uncertainty range for the total is more narrow than the sum of
the uncertainty ranges for the individual sources.
The findings of this report are presented below for each of the major sources of
methane in the United States. The findings are followed by a summary of many of the key
barriers that currently inhibit the development of otherwise economically viable projects and a
discussion of possible options for overcoming these barriers.
OPPORTUNITIES FOR EMISSIONS REDUCTIONS
Landfills
The anaerobic (without the presence of free oxygen) decomposition of organic wastes
in landfills represents the largest source of methane emissions in the United States.
Emissions are estimated to have been between 8.1 and 11.8 Tg per year in 1990. The
ES-6
-------
majority of these emissions result from the disposal of wastes in municipal solid waste
landfills (90 to 95 percent), with the remaining methane emitted from the disposal of industrial
wastes. Although an estimated 6,000 U.S. landfills emit methane, about 1,300 account for
over 95 percent of all the methane emitted. Of these, about 900 landfills account for 75
percent of the methane emitted. By 2000, U.S. landfills are expected to contribute between
8.8 and 12.7 Tg per year and by 2010 between 9.5 and 13.4 Tg per year.
There are two main approaches to reducing methane emissions from landfills. One
approach involves reducing the total quantity of waste that is landfilled either by diverting a
portion of the waste stream toward alternative disposal and treatment methods or by
promoting measures to reduce the quantity of waste produced. Another approach is to
recover the methane and to use it as an energy source. This second option is the only
method currently available for reducing emissions from existing landfills and from landfills that
will contain degradable waste in the future.
For landfills that generate large amounts of gas, recovery of the gas for utilization in
electric power generation is usually the most cost-effective activity. Recovery systems
(consisting of wells drilled into the landfill to extract the gas and a vacuum system to bring
the gas to a common point) can be expected to capture the majority of the methane that
would otherwise be vented to the atmosphere. The recovered methane can be converted
into energy using common options such as internal combustion engines and gas turbines.
Alternatively, direct use of the landfill gas may be most cost-effective when there is nearby
demand for a medium-quality fuel.
The potential reductions in methane emissions from landfills may be summarized as
follows:
• Technologically Feasible Reductions It is technically feasible to recover about 85
percent of the methane produced by landfills (see Exhibit ES-3). The estimate of 85
percent is higher than the average landfill gas collection efficiency estimated for
existing recovery projects (75 percent), but is achievable with current technology. The
extent of reduction that is technically feasible varies among landfills and depends on
the site-specific design and waste factors. Technically feasible emissions reductions
may range from 50 percent for old landfills to nearly 100 percent for new landfills,
which are required to use impermeable liners. The 85 percent estimate represents an
average across many old and new landfills.
• Economically Justified Reductions Economically justified emissions reductions -
reductions that can be achieved at a profit to landfills operators if a variety of barriers
were removed - are highly dependent upon the market value of the energy produced
from the recovered gas. For example, at an electricity price of $0.05 per kWh, about
50 to 60 percent of landfill methane emissions could be recovered for a profit. At a
price of $0.06 per kWh, profitable emissions reductions increase to 60 to 80 percent.
At a price of $0.04 per kWh, it is profitable to recover only about 15 to 25 percent of
emissions.
In the year 2000, it is estimated that about 750 landfills of the over 6,000 existing
landfills could recover 6.7 Tg of methane and produce about 4,000 MW of electric
generating capacity if the electricity price were $0.05 kWh. For the same year, at a
price of $0.04 per kWh, only about 60 landfills would recover 1.5 Tg. At a price of
ES-7
-------
$0.06, however, about 1,400 landfills could profitably recover 8.2 Tg and produce
about 5,000 MW of electric generating capacity.
Barriers Impeding Project Development. There are a variety of informational and
institutional barriers that currently limit the economic recovery of landfill gas.
Consequently, there were only about 100 landfill gas recovery projects in operation in
1990. These projects recovered about 1.2 Tg of methane, or about 10 percent of the
methane generated by landfills. Overcoming these barriers with informational and
other programs could increase the profitable recovery of methane emissions from
landfills.
Implications of Including Environmental Benefits. The analysis of profitable recovery
projects does not include the value of the environmental benefits of recovering
methane from landfills. These environmental benefits include not only the reduction in
methane emissions, but also (1) reductions in air pollution from landfills (including
non-methane organic compound (NMOC) emissions), (2) better landfill gas migration
control, and (3) reductions in air pollutants associated with fossil based energy use
when the landfill gas is used as an energy source. Adding the value of these benefits
to the analysis improves the profitability of landfill gas recovery. For example, using a
range of costs of reducing carbon dioxide buildup in the atmosphere of $5 to $100 per
ton of carbon avoided, the environmental benefit of recovering methane emissions
from landfills translates into a value of about $0.0063 to $0.125 per kWh5 for avoiding
methane emissions from landfills. The addition of the value of the environmental
benefits would indicate that landfill gas recovery should be promoted at virtually all
large landfills with expected reductions of 8.5 to 9.5 Tg per year in the year 2000.
Domesticated Livestock
Domesticated livestock are the second largest source of methane emissions in the
United States. Ruminant animals (e.g., cattle, sheep, buffalo, and goats) exhale or eructate
methane as their feed is fermented in their large "fore-stomachs" or rumens by methanogenic
bacteria and converted into digestible products. This fermentation enables ruminant animals
to eat coarse forages such as grasses and straws that monogastric animals, including
humans, cannot digest. Methane emissions from domesticated livestock in the United States
are estimated to have been between 4.6 and 6.9 Tg in 1990. These emissions are largely
from beef cattle (69 percent) and dairy cattle (26 percent), with other animals contributing only
about 5 percent. Methane emissions from livestock are expected to be between 5.0 and 7.9
Tg per year in 2000 and between 4.8 and 8.2 Tg per year in 2010.
Methane emissions from domesticated livestock can be reduced by improving
production efficiency, which reduces emissions per unit of product produced (e.g., methane
emissions per unit of milk or meat produced). Total national emissions can decline from
current levels because emissions reductions per unit product are expected to exceed
increases in future production.
Specific strategies for reducing methane emissions per unit product have been
identified and evaluated for each sector of the beef and dairy cattle industry. Throughout the
5 Equivalence for $/ton carbon reduced
ES-8
-------
industry, proper veterinary care, sanitation, ventilation (for enclosed animals), nutrition, and
animal comfort provide the foundation for improving livestock productivity. For many
producers, focusing on these basics provides the best opportunity for improving productivity.
Within this context, a variety of techniques can help improve animal productivity and reduce
methane emissions per unit of product.
Significant improvements in milk production per cow are anticipated in the dairy
industry as the result of continued improvements in management and genetics. Additionally,
production-enhancing technologies that accelerate the rate of productivity improvement, such
as Bovine Somatotropin (bST), may become ready for deployment over the coming year. By
increasing milk production per cow, methane emissions per unit of milk produced declines.
Dairy industry emissions can also be reduced by refinements in the milk marketing
and pricing system. By eliminating reliance on fat as the method of pricing milk, and moving
toward a more balanced pricing system that includes the protein or other non-fat solid
components of milk, methane emissions can be reduced as the result of changes in dairy
cow rations. There is already a trend to reduce reliance on fat in the pricing of milk. To
realize methane emissions reductions from this trend, the effectiveness of alternative ration
formulations on protein synthesis must be better characterized.
The main options for reducing methane emissions from the beef industry are
refinements to the marketing system and improved cow-calf sector performance. The
refinements to the marketing system are needed to promote efficiency (which will reduce
methane emissions by eliminating unnecessary feeding) and shift production toward less
methane emissions intensive methods. To be successful, the refinements to the marketing
system require that the information flow within the beef industry be improved substantially.
Better grading measures are required to relate beef quality to objective carcass
characteristics. Additionally, the improved carcass data must be collected and used as a
basis for purchasing cattle so that the proper price incentives are given to improve cattle
quality and reduce unnecessary fat accretion.
The beef industry has several programs under way to achieve these objectives. The
major meat packers have initiated carcass data collection programs that provide detailed data
on carcass quality to participating producers. Also, a major initiative is ongoing to educate
retailers regarding the cost-effectiveness of purchasing more closely trimmed beef (less
trimmable fat). As these programs become more widely adopted, the information needed to
provide the necessary price incentives to producers will become available. A modified
grading system that is consistent with the new information must also be adopted.
The potential reductions in methane emissions from domesticated livestock may be
summarized as follows:
• Economically Justified Reductions. Emissions can be reduced by about 0.6 to 1.9 Tg
from expected future levels, or about 12 to 25 percent. About one-third of the
emissions reduction per unit product are estimated to be from the dairy industry, while
two-thirds are from the beef industry. Within the dairy industry, refining the milk
marketing system and continuing the trend in improvement in cow productivity are the
main sources of the emissions reductions. Within the beef industry, improving cow-
calf reproductive performance and refining the beef marketing system to increase the
portion of calves that move directly from cow-calf producers into feedlots are the two
ES-9
-------
main sources of emissions reductions. These four options account for about 65 to 85
percent of the total emissions reductions estimated.
Barriers Impeding Project Development. There are a variety of informational and
institutional barriers that currently limit economic reductions of methane emissions per
unit product produced from domesticated livestock. Consumer acceptance and FDA
approval are needed before bST can be used in the dairy industry. Changes in the
milk marketing and pricing system have been started; however, they must be
approved under individual milk marketing orders. Also, in order to move to a more
balanced pricing system that includes protein or other non-fat solids, data gaps for
ration formulations need to be identified and solved, and the data needs to be
incorporated into ration formulation software. In the beef industry, better grading
measures need to be developed and the grading system needs to be revised in order
to provide price incentives to producers. Within the cow-calf sector, producers must
be educated and trained in the importance of better nutritional management and the
use of supplements. Also, the special needs of small producers must be identified
and addressed.
Collateral Benefits. In addition to creating environmental benefits, decreasing methane
production by increasing livestock productivity is profitable because it reduces costs
per unit of product produced. Also, refinements in the marketing systems could
decrease excess fat in both the dairy and beef industries. These changes could assist
in matching milk and beef production more closely with consumer demand. In
addition, refinements in the dairy marketing system could assist in maintaining milk
supply-demand balance.
Coal Mining
Coal mines are a sizable source of methane emissions in the United States. During
and after mining, methane is released that has been stored in the coal seams and
surrounding rock strata since it was formed during coalification.6 Methane emissions from
coal mining are estimated to have been between 3.6 and 5.7 Tg in 1990. The majority of
these emissions (70 to 80 percent) result from underground mining operations. Furthermore,
a large portion of these emissions are emitted from the degasification systems used at
gassier mines, where the methane is emitted in concentrations between 30 and 95 percent.
Degasification system emissions account for 20 to 45 percent of underground emissions. By
2000, methane emissions from coal mining are expected to increase to between 3.7 and 6.5
Tg per year and by 2010 to between 5.0 and 8.7 Tg per year.
Methane released from underground mines can be recovered and sold to pipeline
companies or used to generate electricity for on-site use or for sale to utilities. Techniques
for recovery include drilling wells before, during, or after mining. Vertical wells, drilled several
years in advance of mining, will generally be the most expensive, but will recover large
amounts of nearly pure methane (up to 70 percent of the methane that would be emitted
otherwise). Gob wells, drilled during or after mining, can also recover substantial quantities of
high quality methane (up to 50 percent of emissions), but the methane may be contaminated
with mine ventilation air. While such a methane/air mixture is normally suitable for power
6 Coalification is a process in which vegetation is converted by geological and biological forces into coal.
ES-10
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generation, pipeline injection would require enrichment of the gas, which does not appear to
be economically feasible at present.
Techniques for recovering methane from vertical and gob wells are well established.
In fact, over 30 U.S. mines already use recovery wells as a supplement to their ventilation
systems to ensure that methane concentrations remain below acceptable levels. However,
the recovered methane is normally released to the atmosphere.
The potential reductions in methane emissions from coal mining may be summarized
as follows:
• Technologically Feasible Reductions. Methane recovery and utilization would be
technologically feasible for all large and gassy underground coal mines (i.e., coal
mines with annual production greater than 0.5 million tons and methane emissions per
ton greater than 500 cubic feet per ton); currently, over 65 mines (about 5 percent of
all underground mines) could be classified as large and gassy. Methane emissions at
each of these mines could be reduced by approximately 60 percent, which would
result in a total emissions reduction of approximately 1.6 to 2.7 Tg annually by the
year 2000 (between 50 and 55 percent of projected emissions).
• Economically Justified Reductions. Methane recovery and utilization can be a
profitable undertaking for coal mines. Currently, six mines in Alabama, five mines in
Virginia, and one mine in Utah are selling recovered methane to pipelines. Provided
that a number of critical barriers can be overcome, methane recovery could be
economically justified for a much larger number of mines in the future.
The potential for cost-effective emissions reductions from coal mining are estimated to
be between 1.0 and 2.2 Tg in 2000 and between 1.7 and 3.1 Tg in 2010 (32 to 44
percent of projected emissions in 2000 and 40 to 45 percent in 2010). These
reductions are equivalent to about 50 to 115 billion cubic feet (Bcf) in 2000 and 90 to
160 Bcf in 2010. These emissions reductions would be associated with a relatively
small number of large and gassy mines - about 16 to 25 mines in 2000 and 25 to 29
mines in 2010. In addition to size and gassiness, other indicators of profitability
include proximity to a commercial pipeline and certain geological characteristics.
Because the profitability of methane recovery and utilization is highly dependent on
gas and electricity prices, future prices will have a large impact on the number of
projects developed. For example, current projections for natural gas prices indicate
that, by the year 2000, the wellhead gas price could be $2.25 per thousand cubic feet
of gas produced. Based on this price, about 19 mines could profitably recover an
estimated 1.4 Tg of methane. However, if wellhead gas prices increased to $3.00 per
thousand cubic feet (mcf) by the year 2000, methane recovery would be economically
justified for about 26 mines - a substantial increase. On the other hand, if the
wellhead gas price is $1.50 per mcf in 2000, methane recovery would be profitable for
only about 10 mines.
• Regional Impacts. Projected emissions and the potential for methane emissions
reductions varied significantly among the five major underground coal producing areas
examined in this report - the Central Appalachian basin, the Northern Appalachian
basin, the Warrior basin, the western basins, and the Illinois Basin. Exhibit ES-5
presents results from individual basins.
ES-11
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Exhibit ES-5
Opportunities to Reduce Methane Emissions from Coal Mining: Regional Impacts
Year 2000
Methane Emitted and Recovered
2
Year 2010
Methane Emitted and Recovered (TgJ
2
0.5 -
Northern Central
Appalachian Appalachian
• Methane Recovered
Western 11 IInols
and Other
Methane Burned
Northern Central »Hrrlor
Appalachian Appalachian
• Methane Recovered i
Western Illinois
and Other
SMethane Bnitted
A majority of the gassiest mines in the United States are located in the Northern
Appalachian, Central Appalachian, and Warrior (Southern Appalachian) basins.
Accordingly, these basins account for a large portion of the potential cost-effective
emissions reductions -- about 78 percent in 2000 and 82 percent in 2010. In 2000, the
Central Appalachian and Warrior basins could potentially recover 0.4 Tg each, while
the Northern Appalachian basin would likely recover slightly less - about 0.3 Tg.
However, in 2010, based on comparatively high projections for increased coal
production in the basin, the largest profitable emissions reductions are likely to be
achieved by Northern Appalachian mines - 0.7 Tg per year. Warrior basin mines and
Central Appalachian basin mines are projected to recover slightly less - 0.6 Tg and
0.5 Tg per year, respectively.
As a result of acid rain legislation, coal production in low sulfur western mines is
expected to increase by about 180 percent between 1988 and 2010 - the largest
projected increase for any region. Accordingly, the number of large and gassy mines
in the western basins with the potential to recover and utilize methane is also
projected to increase. Between 2000 and 2010, cost-effective emissions reductions
are projected to double - from 0.2 to 0.4 Tg.
Due to the comparatively lower methane content of their coal seams, implementation
of emissions reduction techniques are not likely to be justified economically in other
coal producing areas.
Barriers Impeding Project Development. While a number of coal mines have already
undertaken methane recovery projects, a number of obstacles have constrained the
wider development of these projects. Ambiguity in certain state legal systems
ES-12
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concerning the ownership of coalbed methane resources has prevented the
development of projects, particularly in the Appalachian states. Even where ownership
issues have been resolved, however, certain conditions and characteristics of the coal
mining industry -- such as preferences for investments in coal mine productivity and
the relative newness of the concept of utilizing methane - have further slowed project
development. Yet another factor constraining project development is that coal mines
may be unable to gain access to existing pipelines due to limited capacity. While this
problem is not unique to coal mine methane pipeline projects, pipeline capacity is
severely limited in the major underground coal-producing Appalachian region.
Impact of Including Environmental Benefits. Placing a monetary value on the
environmental benefit to society of reducing emissions would lead to a significant
increase in the amount of methane recovered. Even at a low value of $5 per ton of
carbon emissions reduced ($.52 per mcf methane), an additional 0.2 Tg of methane
could be recovered in 2000 and in 2010. At a value of $20 per ton, the incremental
emissions reduction would be 0.4 Tg in 2000 and 2010. Finally, at a value of $100 per
ton, all technologically feasible emissions reductions could be achieved. The
emissions reductions would be about 2 Tg in 2000 and 2.8 Tg in 2010 - about 0.6 Tg
higher than if no financial subsidy were place. With a value of $100 per ton, nearly 70
mines in 2000 and 2010 would find it profitable to develop methane recovery projects.
Collateral Benefits. In addition to creating environmental and economic benefits,
methane recovery reduces the potential for explosion in underground mines because
the techniques for recovering methane prevent this dangerous gas from entering mine
working areas. In fact, vertical wells drilled several years in advance of mining can
recover a majority of the methane prior to the start of mining, thus substantially
reducing the chance that miners will be injured as a result of explosive methane levels.
Natural Gas Systems
Natural gas systems also emit methane to the atmosphere, as methane is the major
component of natural gas and any leakage or emission during the production, processing,
transmission, and distribution of natural gas contributes to emissions. Methane emissions
from natural gas systems are estimated to have been between 2.2 to 4.3 Tg in 1990. The
majority of these emissions result from the production, transmission, and distribution of
natural gas (90 to 95 percent). These emissions result from leakage (or fugitive emissions)
throughout all segments of the gas systems; the exhaust of compressor engines; starts and
stops of these engines; and the venting of pneumatic equipment frequently used in the
transportation of gas. By 2000, methane emissions from natural gas systems are expected to
increase to between 2.4 and 5.0 Tg per year and by 2010 to between 2.5 and 5.4 Tg per
year.
Methane emitted from the U.S. natural gas system can be controlled through the more
widespread use of a number of available technologies and practices. These technologies
address the major sources of emissions in the U.S. gas system, including: fugitive emissions;
venting from the normal operation of pneumatic devices and glycol dehydrators; reciprocating
engine exhaust; and purging during pipeline repair.
The U.S. natural gas industry is already a world leader in the development and
application of new technologies designed to further enhance public safety, increase system
ES-13
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efficiency, and reduce costs of operation, and as a result has one of the most efficient
systems in the world. Nevertheless, additional implementation of existing technologies is both
technologically feasible and economically justified. In addition, several emerging technologies
may become available over the next decade, further increasing potential reductions.
The potential reductions in methane emissions from natural gas systems may be
summarized as follows:
• Technologically Feasible Reductions. Technologically feasible reductions are
achievable for all sources of emissions. For example, venting from pneumatic devices
can be reduced with "low-bleed" designs; fugitive emissions can be reduced through
various improved detection and maintenance practices; and turbines can be used
instead of reciprocating engines to reduce methane in engine exhaust. These and
other technologies are currently available and have proven effective in operation in the
U.S. gas system. More widespread use of these options could reduce methane
emissions by roughly 0.8 to 1.6 Tg annually by the year 2000.
• Economically Justified Reductions. In many cases the value of the gas saved can
more than offset the cost of implementation of the emissions reduction technologies.
In addition, several technologies result in reduced operating costs, and may reduce
capital costs. Potential cost-effective emissions reductions from the U.S. natural gas
system are estimated to range from 0.3 to 1.2 Tg in 2000 and 0.3 to 1.3 Tg in 2010.
These emission reductions are anticipated to be achieved primarily by the larger
companies in the production, transmission, and distribution stages of the system.
Although the value of saved gas is the primary benefit of these emissions reduction
options, the results are insensitive to a range of future gas prices.
• Barriers. While many technologies and practices exist to reduce emissions from the
U.S. natural gas system, some natural gas companies may not be fully aware of the
potential magnitude and source of emissions from their systems and of the potential
for profitable application of emissions reduction technologies. In addition to these
informational barriers, certain existing regulations may dissuade pipeline companies
from making emissions reductions a top priority. For example, state Public Utility
Commissions typically allow the cost of "unaccounted-for-gas" (UFG) to be passed on
to the consumer as an acceptable operating cost, thus creating little incentive for gas
companies to reduce their emissions beyond the requirements of existing safety
regulations. Other barriers include that the costs of developing and testing new
technologies may be prohibitive for individual companies.
• Impact of Including Environmental Benefits. The environmental benefits of reducing
emissions from natural gas systems include not only methane reductions, but also
reductions in VOC emissions from some stages of the system. Although these
benefits may be considerable, the assessment of the profitability of the reduction
options is not very sensitive to their inclusion in the analysis.
• Collateral Benefits. In addition to the broad environmental and energy benefits, natural
gas companies and gas consumers would benefit economically from the more
widespread use of many of these technologies and practices, since the value of saved
gas exceeds the costs. Moreover, natural gas firms may also benefit from lower
operating costs and public safety may be improved.
ES-14
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Livestock Manure
When livestock manure from animals such as cattle, swine, and poultry is handled
under anaerobic conditions, microbial fermentation produces methane. Manure handled
using liquid waste management systems such as lagoons is particularly conducive to this
anaerobic fermentation. Overall methane emissions from livestock manure are estimated to
be between 1.7 and 3.6 Tg per year. Most of the emissions result from the management of
manure in liquid and slurry systems at dairy and swine production facilities. By 2000,
methane emissions from livestock manure are expected to increase to between 3.1 and 5.6
Tg per year and by 2010 to between 3.2 and 6.0 per year.
Methane released from liquid manure management systems can be recovered and
used to produce electricity or fuel gas-fired equipment such as boilers or chillers to meet a
portion of the farm's energy requirements. Techniques for recovery include covered
anaerobic lagoons, plug flow digesters, and complete mix digesters. Methane can be
captured from anaerobic lagoons by placing a floating impermeable cover over the lagoon
and then pulling a slight vacuum on a gas collection pipe. Methane can also be captured
from a plug-flow digester, which is a long trough with an airtight expandable cover, by pulling
a slight vacuum on a perforated pipe supported above the surface of the manure. Complete
mix digesters, which are designed as large covered mixing tanks, typically handle manure
with a lower solids content than plug-flow digesters and have improved digestion efficiency
due to mixing and heating. All three techniques produce medium BTU gas, but they have
different retention times and optimal operating temperatures.
Techniques for recovering methane from covered anaerobic lagoons and plug-flow
and complete mix digesters are well established. Liquid manure systems are common at
dairy and swine facilities, and the use of these systems is increasing. In addition to methane
recovery systems on individual farms, centralized recovery systems that process manure from
several farms are operational in the United States. These systems have larger labor and
capital requirements but are potentially more profitable due to economics of scale. However,
transporting the manure to the central facility can be costly.
The potential reductions in methane emissions from animal manure management may
be summarized as follows:
• Technologically Feasible Reductions. With methane recovery systems it is
technologically feasible to reduce total methane emissions from livestock manure by
80 percent to between 0.3 Tg and 0.7 Tg. Methane recovery and utilization would be
technologically feasible for virtually all farms using liquid based manure management
systems.
• Economically Justified Reductions. Methane recovery and utilization can be a
profitable undertaking on large farms in warm climates that use liquid based manure
management systems, provided a number of barriers can be overcome. At these
farms, it is profitable to collect the methane and use it to meet a portion of the farm's
energy requirements. Currently, over 20 methane recovery and utilization systems are
operating on private and university livestock facilities across the United States.
Covered lagoons are potentially profitable for about 4,000 large dairy and hog
production facilities. These facilities represent about 1 percent of dairy and swine
facilities in the United States and about 10 percent of the dairy and swine animals.
ES-15
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The best candidates for profitability are facilities that: have over 500 dairy cows or
over 1,500 hogs; are currently using liquid or slurry manure management systems; are
located in a relatively warm climate; and are currently paying relatively high energy
prices. Specifically, in the year 2000 methane emissions can be reduced at a profit to
the farmer by 0.5 to 0.8 Tg and by 0.6 to 1.0 Tg in 2010.
The value of methane and, therefore, the profitability of recovery and utilization are
principally dependent on electricity prices paid by the production facilities. Relatively
modest increases in the value of energy result in large increases in the number of
projects that would be profitable. For example, an increase in electricity prices of
$0.02 per kWh doubles the expected profitable methane reductions.
Regional Impacts. The potential for profitable methane emissions reductions varies
significantly from state to state. This regional pattern is determined by farm size,
climate, and energy prices. While many states have the climate conditions and energy
prices that are conducive to profitable methane recovery projects, relatively few states
have significant numbers of large farms. As a result, a few states account for the
majority of the profitable emissions reductions.
Because of their concentration of large hog farms, Illinois and North Carolina account
for about 70 percent of the profitable emission mitigation potential from hog farms.
Additionally, methane recovery projects are more profitable in these two states
because of the relatively high electricity prices in Illinois and the relatively warm climate
in North Carolina.
Methane recovery projects on dairy farms are profitable in states such as California,
Texas, Arizona, and Florida where large farms are common and the climate is
favorable for methane production. However, in the northern U.S. where a significant
portion of U.S. dairy production occurs, methane emissions reductions are not
profitable because the farms are relatively small and the cold winters reduce methane
production. Likewise, the implementation of emissions reduction techniques in Iowa,
which contains by far the most hogs of any state in the United States, is not likely to
be profitable because of the relatively small size of most Iowa hog farms.
Barriers Impeding Project Development. There are a variety of informational,
regulatory, and economic barriers that currently limit the economic recovery of
methane emissions from livestock manure. The primary barrier is the lack of
information on the cost-effectiveness and reliability of commercial-scale digesters,
which have been improved since their initial introduction in the 1970s. Because of
past operational failures, digesters have a reputation of being expensive and
unreliable. Financial barriers make it difficult for farmers to purchase the equipment
and economic barriers limit the value of the biogas produced. Regulatory barriers
such as air emission standards that may restrict the use of energy recovery equipment
and manure system permit modifications also discourage the use of methane recovery
systems. Overcoming these barriers with informational and other programs could
increase the use of methane recovery systems in manure management programs.
Impact of Including Environmental Benefits. The assessment of profitability is sensitive
to the value of additional environmental benefits. For example, by adding $0.006 to
the value of electricity to account for the environmental benefits of recovering
methane, profitable emission reductions from hog farms increase by about 50 percent
ES-16
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and profitable emission reductions from dairy farms increase by less than 10 percent.
If $0.025 per kWh is added, profitable emission reductions from hog farms increase by
150 percent and profitable emission reductions from dairy farms increase by almost 30
percent. If the environmental benefits of methane recovery are as high as $0.13 per
kWh, methane recovery would be desirable at nearly all large dairy and hog
production facilities.
Collateral Benefits. In addition to creating environmental and economic benefits, the
use of methane recovery systems on both dairy and hog farms reduces ground and
surface water pollution and air pollution. By utilizing methane recovery systems such
as anaerobic lagoons, livestock operations can contain runoff and manage manure in
compliance with environmental regulations under the Federal Clean Water Act.
OVERCOMING BARRIERS TO ECONOMIC EMISSIONS REDUCTIONS
While a large number of landfill, coal mining, natural gas, and livestock operations
have the necessary characteristics to be able to implement economically viable emissions
reduction projects, many have yet to develop these projects. The failure to implement
methane recovery and reduction projects stems both from lack of information about the
potential benefits and from transactional difficulties in instituting such projects. Depending on
the methane source, these transactional barriers may involve financial, legal, institutional, and
regulatory issues. Furthermore, coal mines, landfills, and livestock manure operations that
would use recovered methane as an energy source face economic and regulatory barriers
that are common to virtually all "alternative" energy sources. These barriers will need to be
effectively addressed so that the environmental and economic benefits of methane reduction
strategies can be realized. In the near term there are some key barriers that federal actions
could address and resolve. These barriers are summarized below and in Exhibit ES-6.
Landfills
Key barriers to landfill gas recovery projects are primarily informational and regulatory.
They include the following:
• Perception of High Risk. Most "alternative" energy production technologies tend to be
viewed as unproven or risky. As a result, such projects must earn high returns in
order to attract financing.
• Lack of Information. Landfill recovery technologies have been improving over the past
ten years, and some landfill operators may be unfamiliar with the latest methods.
Additionally, operators may be unaware of the opportunities for selling electricity to
utilities that are now available to independent power producers. These and other
informational barriers may constrain the wider development of landfill gas energy
projects. Another potential impediment stems from the fact that many landfills are
owned by local governments (nearly 60 percent, USEPA 1988); given their numerous
responsibilities, some local governments may be unable to place a high priority on
developing a landfill methane power project.
• Siting and Permitting. Landfill gas recovery projects must comply with local, state, and
federal regulatory and permitting requirements. The majority of these requirements
ES-17
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Exhibit ES-6
Key Near Term Barriers to Methane Recovery and Possible Solutions
Methane Source/Barrier
Possible Federal Actions
Landfills
+ Perception of high risk
> Lack of information on profitable
reduction opportunities
*• Low utility buy back rates
> Siting and permitting limitations
»• High cost of new technology
development
Develop outreach program to disseminate information on:
(1) successful projects; and, (2) standard techniques for
mitigating air and water releases
Encourage PUCs to allow higher buy back rates for
environmentally beneficial projects
Set up special permitting programs for environmentally
beneficial projects
Fund government and/or private research programs
Domesticated Livestock
> Consumer perception of new
technology
Current feeding practices
emphasize milk fat production
Low cow-calf sector performance
Contingent on FDA approval, develop outreach and
educational programs to inform consumers about the
productivity and environmental benefits of bST
Fund government/private research programs to collect
data needed to formulate protein-enhancing rations in key
dairy regions and to update ration formulation software.
Develop education and training programs tailored for
specific regions and conditions.
Coal Mining
»• Unclear ownership of gas
> Perception of high risk
> Capital constraints
> Technical issues
Ensure that provisions in the Energy Policy Act of 1992 are
implemented
Develop demonstration/outreach programs
Provide financial incentives
Fund R&D on key technologies
Natural Gas Systems
> Uncertain emissions
* Lack of information on profitable
reduction opportunities
»• Little incentive to reduce
emissions to fullest extent
profitable
* Cost of New Technology
Development
Create voluntary program with the natural gas industry to
develop better information and to promote emissions
reductions
Encourage PUCs to provide better incentives for achieving
lowest profitable emission rates
Fund government/private research program
ES-18
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Exhibit ES-6
Key Near Term Barriers to Methane Recovery and Possible Solutions
Methane Source/Barrier
Possible Federal Actions
Livestock Manure
>• Lack of information on current
technologies for profitable on-farm
energy use
>• Low utility buy back rates
Develop voluntary program to demonstrate the economic
viability of methane recovery and to promote more
widespread use of available technologies
Encourage PUCs to allow higher buy back rates for
environmentally beneficial projects
address environmental, safety, and zoning concerns. The costs of complying with
these rules can be substantial, and may involve greater costs than considered in the
financial analysis presented in this report.
Key requirements that must be addressed include air and water emissions. In some
areas, the siting of new combustion sources is difficult due to requirements to reduce
emissions of NOX or other combustion products in ozone non-attainment areas. The
availability of low-emissions engine technology helps to overcome this barrier,
although at a cost. Over the longer term, fuel cells may help to overcome this barrier
if they are successfully demonstrated using landfill gas and if their costs decrease.
Water emission issues center around leachate control. Landfills are currently required
to monitor groundwater quality and prevent off-site migration of contaminants in the
groundwater. In the process of collecting landfill gas, leachate will condense in the
collection system. This leachate can exhibit hazardous characteristics and must be
handled and disposed of properly, within the context of the landfill's leachate control
program.
• Technology Development. Several emerging technologies - including fuel cells and
processes that could convert gas into diesel, naptha, and high grade industrial waxes
- could provide additional options for the utilization of landfill gas. The advantage of
one of the most promising technologies ~ fuel cells - is that it is highly efficient, has
low by-product emissions, limited noise production, minimal labor requirements, and
can be used in modules. Converting gas into diesel, naptha, or other substances is
advantageous in that the economic benefits are not dependent upon the local electric
power system or on proximity to a suitable industrial customer. Currently, however,
fuel cells and conversion technologies are prohibitively expensive. Further research is
needed to lower the costs of these technologies, and technical demonstration utilizing
landfill gas in fuel cells and conversion processes is also needed.
Options are available for overcoming these barriers. In particular, the perception of
high risk for the technology can be overcome by disseminating information on the reliability of
the existing landfill gas recovery projects. Both landfill gas extraction and engine technology
have improved to increase the reliability of these systems. Disseminating key information may
also make more municipalities aware of the potential opportunities. Some of the permitting
and siting concerns can be addressed by providing information on the standard techniques
ES-19
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for mitigating water and air releases. Furthermore, provisions under the Energy Policy Act of
1992 provide an additional 1.50 per kWh for renewable energy projects. If the provision is
supported by an appropriation, it could encourage additional development to further serve as
demonstrations projects. Finally, funding research and development projects will enable
faster adaptation of promising new utilization technologies.
Domesticated Livestock
Key barriers to reducing methane emissions from domesticated livestock are primarily
informational and institutional. They include the following:
• Dairy Industry. Bovine Somatotropin (bST) is one of the methods that can be used to
improve productivity and reduce methane emissions from dairy cows. In addition to
FDA approval, which is required before bST can be used in the United States,
consumer acceptance of its use may also be required. Currently, some groups are
advocating that bST not be used, and intend to limit the adoption of bST. Education
and outreach programs could be conducted to inform consumers about the
productivity and environmental benefits of bST. These steps could help ensure that
bST can be used by those producers that find it profitable.
Refinements to the milk marketing system must be approved under individual milk
marketing orders. Movement toward this approach has started. Information exchange
among regions and focused analyses of the effects of changes in the regions that
have modified their pricing system may help accelerate the trend. To be fully effective,
these pricing system changes must also be reflected in the manner that dairy
cooperatives pay their members for the milk they produce. Based on discussions with
cooperative representatives, it is likely that changes in the pricing system will be
reflected by cooperatives in a timely manner.
To realize fully the emissions reduction associated with the change in the pricing
system, data are required that demonstrate how ration adjustments improve protein
synthesis, and these data must be integrated into ration formulation software. As a
priority, available data on the impacts of ration formulation on protein synthesis should
be reviewed and summarized. Gaps in data needed for formulating protein-enhancing
rations in key dairy regions should be identified and resolved. Most importantly, these
data must be added to the software used by nutritionists to formulate dairy rations.
The current software is based exclusively on maximizing profit based on milk quantity
and fat pricing. Protein pricing requires that the response of protein synthesis to
various ration formulations be quantified.
• Beef Industry. The main options for reducing methane emissions from the beef
industry are the refinements to the marketing system and improved cow-calf sector
performance. The refinements to the marketing system require that the information
flow within the beef industry be improved substantially. Better grading measures are
required to relate beef quality to objective carcass characteristics. Additionally, the
improved carcass data must be collected and used as a basis for purchasing the
cattle so that the proper price incentives are given to improve cattle quality and reduce
unnecessary fat accretion.
ES-20
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The beef industry has several programs under way to achieve these objectives. The
major meat packers have initiated carcass data collection programs that can provide
additional detailed data on carcass quality to participating producers. Also, a major
initiative is ongoing to educate retailers regarding the cost-effectiveness of purchasing
more closely trimmed beef (less trimmable fat). As these programs become more
widely adopted, the information needed to provide the necessary price incentives to
producers will become available. A modified grading system that is consistent with
the new information must also be adopted. Recently, a revised grading system was
rejected by one of the major industry groups. These objections must be resolved so
that an acceptable modification to the grading system can be implemented.
The principal barrier to improved productivity within the cow-calf sector is education
and training. The importance and value of better nutritional management and
supplementation must be communicated. The special needs of small producers must
also be identified and addressed. In particular, systems for delivering the supplements
that require less time and equipment would be valuable.
Coal Mining
Barriers to reducing methane emissions from coal mining hinder both the direct sale of
the recovered gas to pipelines and the use of the gas for on-site electricity generation. These
barriers include the following:
• Legal Barriers. Unresolved legal issues concerning the ownership of coalbed methane
resources have constituted one of the most significant barriers to coalbed methane
recovery, particularly in the Appalachian states. Ambiguity in certain state legal
systems provides a disincentive for investment in coalbed methane projects because
of the uncertainties as to which parties may demand compensation for development of
resources. Potentially, ownership could rest with the holder of the coal rights, the
owner of the oil and gas rights, the surface rights owner, or some combination of the
three. As part of the Energy Policy Act of 1992 (Public Law 102-486), states will be
required to develop a mechanism to address ownership issues.7 One option,
enacted by Virginia, is to force pooling of all potential interests in the resource. Under
forced pooling, until such time as ownership is decided, payment of costs or proceeds
attributable to the conflicting interests are paid into an escrow account. This
legislative effort has contributed to the rapid development of coalbed methane projects
in Virginia.
• Conditions in the Coal Mining Industry. Even where ownership issues have been
resolved, certain conditions and characteristics of the coal mining industry may still
prevent investment in methane recovery projects. Market uncertainty, preferences for
investments in coal mine productivity, and the relative newness of the concept of
utilizing methane from coal mines are factors that may deter methane recovery and
utilization in conjunction with coal mining operations. Furthermore, methane recovery
and utilization projects require relatively large capital investments; given declining
Those states determined by the Secretary of Interior to lack statutory or regulatory procedures for addressing
ownership concerns will have three years to enact such a program. If the state does not act, the Secretary of Interior
will impose a forced pooling mechanism similar to that enacted in Virginia.
ES-21
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profits in some areas of the industry, attracting this level of investment may be difficult.
These barriers partially could be addressed by disseminating information on
successful coal mine methane recovery projects at all levels of government. Capital
constraints could also be addressed through the development of targeted financial
incentives.
Limited Pipeline Capacity. For most mines, selling recovered methane to a pipeline is
likely to be more advantageous than using the methane to generate power. One of
the most significant barriers to pipeline sales, however, is that new gas producers may
be unable to gain access to existing pipelines due to limited capacity. Though this
barrier is not unique to coal mine methane pipeline projects, pipeline capacity is
severely limited in the major underground coal producing Appalachian region, due to
the large amount of gas being transported from major gas producing areas in the
southern U.S. to the northeastern demand centers. These constraints may make it
difficult for coalbed methane producers to gain firm access to pipelines or may
necessitate the construction of long gathering systems to move gas from production
areas to pipelines with capacity. Accordingly, it may be desirable to consider
legislative means of encouraging and/or expediting new pipeline construction.
Technology Development. Techniques for producing high-quality gas from gob wells
are being used successfully in several mines in Alabama. These techniques are not
difficult, but they do require close coordination of mining and methane recovery
operations. At some mines, however, it may be impossible to produce pipeline quality
methane from gob wells, which means that the gas must either be used for power
generation or enriched before injection into a pipeline. Currently, enriching gas for
pipeline injection is prohibitively expensive and additional research and development
into enrichment technologies is warranted given that pipeline injection will often be the
preferred method of utilization. To date, there are no enrichment facilities at U.S. coal
mines, although coal companies have expressed a strong interest in such projects.
Also, further research is needed to lower costs for utilization of ventilation air and for
the disposal of water produced from vertical wells. The Energy Policy Act of 1992
mandates the establishment of a demonstration and commercial application program
for advanced coalbed methane utilization technologies. To complement Federal
actions, it is essential that state governments, industry organizations such as the Gas
Research Institute, state universities, and other organizations with an interest in the
issue also be involved in research and demonstration projects.
Natural Gas Systems
Barriers to reducing methane emissions from natural gas systems include the
following:
• Information Barriers. In order for natural gas companies to implement technologies
that reduce methane emissions, they must be aware of the potential magnitude and
source of emissions from their systems, as well as the availability, applicability, and,
most importantly, the profitability of these options. This knowledge, however, is
lacking for many areas of the U.S. natural gas system. In addition, it is important to
emphasize that there are significant global and local environmental benefits associated
with reducing methane emissions. This information barrier could be overcome with a
ES-22
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variety of programs publicizing the economic, operational, and environmental benefits
of these options.
Voluntary programs have been successful in gaining the support and cooperation of
business and industry in implementing energy efficiency measures in cases in which
information barriers were impeding the introduction of beneficial technologies. Such a
program could help overcome informational barriers to reducing methane emissions
by providing outreach services to the gas industry, serving as an information
clearinghouse, assisting in assessing implementation programs, and publicizing
successful programs.
Economic and Regulatory Barriers. The U.S. gas industry is subject to economic
regulation at both the federal and state level. In particular, the rates that transmission
networks may charge are regulated, largely based on capital and operating costs
incurred. Similarly, the rates charged by distribution companies to consumers are
regulated by state Public Utility Commissions (PUCs). Currently, the cost of
"unaccounted-for-gas" (UFG) is typically passed on to the consumer as an acceptable
operating cost.8 As a result, the cost of gas lost through leakage and other
emissions is often not fully born by the company, reducing the incentive to invest in
technologies that reduce methane emissions. Thus, there is little incentive to go
beyond the requirements of existing safety regulations.
Given that there are profitable options for reducing methane emissions, it is in the
interest of PUCs (on behalf of consumers) to encourage gas companies to invest in
these technologies, where appropriate. For example, state PUCs might allow a
distribution company to include investments in methane reduction technologies in rate
calculations. Similarly, PUCs might require gas companies to estimate the component
of UFG accounted for by gas leakage and other emissions, and reduce the allowed
rate-of-return on this cost.
However, as with gas companies, lack of awareness of these technologies and their
potential creates an informational barrier to regulatory change. Programs encouraging
the implementation of these technologies could also provide information to PUCs and
the Federal Energy Regulatory Commission (FERC) concerning methane emission
reduction programs.
Technology Cost and Availability Barriers. In general, the costs of developing and
testing new technologies can deter individual companies from introducing improved
technologies and practices. In addition, information concerning new technologies may
not be readily available to the industry as a whole. These barriers can be overcome
by supporting targeted research to reduce costs and to develop improved
technologies and practices. Such research, already underway to some extent, could
be expanded under the auspices of the Department of Energy (DOE), the Gas
Research Institute (GRI), the American Gas Association (AGA), the Institute of Gas
Technology (IGT), or the EPA, and could include funding the initial deployment and
field testing of new technologies and practices.
Unaccounted-for-gas (UFG) is not synonymous with methane emissions. Other important factors contributing
to UFG include metering errors, accounting procedures and schedules, temperature and pressure effects, and gas used
as part of normal operations in the system.
ES-23
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Livestock Manure
Barriers to reducing methane emissions from livestock manure are primarily
informational, regulatory, and economic. They include the following:
• Lack of Information. The most important barrier to developing methane recovery
projects is informational. Many of the digester projects built in the early 1970s failed
because of poor designs, improper maintenance, or low energy prices. Operational
failures were primarily due to mechanical problems with the digesters and utilization
equipment and biological problems that restricted the amount of methane produced.
These failures gave digesters the reputation of being an expensive and mechanically
dubious technology. Most of these problems that limited the success of commercial-
scale digesters have been solved and digesters are now a cost-effective and reliable
source of energy. However, because of past failures, the systems must be
demonstrated to show that the problems that plagued the early digester systems have
been resolved.
• Economic, financial, and regulatory barriers. In addition to informational barriers,
economic, financial, and regulatory barriers limit the adoption of methane recovery
systems. Economic barriers include low utility "buy back" rates that limit the value of
the biogas produced. Financial barriers limit the ability of farmers to borrow to
purchase a biogas recovery and utilization system. Regulatory barriers include air
emission standards that may restrict the use of energy recovery equipment and
manure system permit modifications that are required in some areas to add a methane
recovery system to an existing manure management system.
• Barriers to On-Site Use of Electricity. Dairy or swine operations electing to generate
power for on-site use will also encounter barriers similar to those faced by co-
generators. One of these potential barriers is that a utility may levy high charges for
back-up power. A second issue is that a utility may approach a company considering
on-site generation and offer to renegotiate industrial power rates in order to
discourage the project.
Opportunities are available for overcoming these barriers. In particular, the perception
of high risk for the technology can be overcome by providing information on the reliability of
the existing methane recovery projects. Low utility "buy back" rates can be overcome by
emphasizing on-farm energy use that offsets energy purchases. Financial barriers can be
circumvented by providing lenders with information on the reliability and profitability of
recovery systems. Regulatory barriers can be surmounted by providing regulators with
information on the environmental benefits associated with recovery systems. Finally, state
PUCs could assist in removing obstacles to on-site use of electricity.
CONCLUSION
Reducing methane emissions is a promising way to slow global warming. Because
methane is such a potent greenhouse gas, small emissions reductions result in substantial
atmospheric benefits. Moreover, many methane mitigation strategies are low cost or even
profitable. Economically viable emissions reductions strategies include: 1) recovering the
methane emitted from landfills, coal mines, and liquid manure management systems for use
as an energy source; 2) reducing leaks from natural gas systems so the methane is utilized
ES-24
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rather than emitted; and 3) improving the production efficiency of cattle, which results in
reduced methane emissions per unit of product produced. In fact, due to the favorable
economics of these options, numerous emissions recovery/reduction projects are already
operating in the United States. For example, methane recovery projects exist at over 100
landfills, more than 20 livestock facilities, and at 11 coal mines.
Although numerous options exist for reducing emissions from the five major sources of
methane production in the U.S. -- landfills, livestock, coal mines, natural gas systems, and
livestock manure -- many potentially cost-effective projects are not being undertaken. In
many cases, such projects have not been developed due to a variety of informational,
regulatory, financial, legal or other transactional barriers. While these barriers have
constrained project development in the past, a number of steps could be undertaken to
remove some of the most critical of the barriers to methane emissions reductions. If these
impediments are overcome or mitigated, the institution of methane recovery projects at even a
relatively small number of the largest facilities could produce significant environmental
benefits.
REFERENCES
IPCC (Intergovernmental Panel on Climate Change). 1990. Climate Change: The IPCC
Scientific Assessment. Cambridge University Press, Cambridge, United Kingdom.
IPCC (Intergovernmental Panel on Climate Change). 1992. Climate Change 1992: The
Supplementary Report to the IPCC Scientific Assessment. Cambridge University Press,
Cambridge, United Kingdom.
USEPA (U.S. Environmental Protection Agency). 1993. Anthropogenic Methane Emissions in
the United States: Estimates for 1990. Report to the Congress. Office of Air and
Radiation. Washington, D.C. EPA 430-R-93-003. April 1993.
USEPA (United States Environmental Protection Agency) 1988. National Survey of Solid Waste
(Municipal) Landfill Facilities. Washington D.C. September 1988.
ES-25
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CHAPTER 1
INTRODUCTION
This report evaluates options for reducing methane emissions from anthropogenic
(human related) sources in the U.S. and presents estimates for the portion of current and
future emissions that could be reduced through the use of such options. This report is
written in partial fulfillment of Section 603 of the Clean Air Act Amendments of 1990, which
requires that the EPA prepare and submit to Congress a series of reports on domestic and
international issues concerning methane.
1.1 BACKGROUND: THE IMPORTANCE OF METHANE
Methane (CH4) is an important greenhouse gas and a major environmental pollutant.
Methane is also the primary component of natural gas and a valuable energy source.
Methane emissions reduction strategies offer one of the most effective means of mitigating
global warming in the near term for the following reasons:
• Methane (CH4) is one of the principal greenhouse gases, second only to
carbon dioxide (CO2) in its contribution to potential global warming. In fact,
methane is responsible for roughly 18 percent of the total contribution in 1990
of all greenhouse gases to "radiative forcing," the measure used to determine
the extent to which the atmosphere is trapping heat due to emissions of
greenhouse gases.
• Methane concentrations in the atmosphere have risen rapidly. Atmospheric
concentrations of methane have been increasing at about 0.6 percent per year
(Steele et al. 1992) and have more than doubled over the last two centuries
(IPCC 1990a). In contrast, CO2's atmospheric concentration is increasing at
about 0.4 percent per year.2
• Methane is a potent contributor to global warming. On a kilogram for
kilogram basis, methane is a more potent greenhouse gas than CO2 (about 22
times greater over a 100 year time frame). Methane is reported with a direct
Global Warming Potential (GWP) of 35 over a 20 year time frame, 11 over 100
years, and 4 over 500 years, and with indirect effects that could be comparable
in magnitude to its direct effect (IPCC 1992a). The GWP reflects the effect that
releasing a kilogram of methane would have over a specified time horizon,
relative to releasing a kilogram of carbon dioxide.
• Reductions in methane emissions will produce substantial benefits in the
short-run. Methane has a shorter atmospheric lifetime than other greenhouse
gases - methane lasts around 11 years in the atmosphere, whereas C02 lasts
Global contribution to radiative forcing by gas is estimated on a carbon dioxide equivalent basis using IPCC
(1990a) global warming potentials for a 100-year lime horizon, including direct and indirect effects of methane.
2 Based on measurements taken at Mauna Loa from 1970 to 1990 (Oak Ridge 1992).
1-1
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about 120 years (IPCC 1992a). Due to methane's high potency and short
atmospheric lifetime, stabilization of methane emissions will have an immediate
impact on mitigating potential climate change.
• Methane stabilization is nearly as effective as limiting CO2 emissions to
1990 levels. In order to stabilize methane concentrations at current levels,
total anthropogenic methane emissions would need to be reduced by about 10
percent. This methane concentration stabilization would have roughly the
same effect on actual warming as maintaining CO2 emissions at 1990 levels
(Hoganetal. 1991).
• In contrast to the numerous sources of other greenhouse gasses, a few
large and gassy facilities often account for a large portion of methane
emissions. Therefore, applying emissions reductions strategies to these
gassiest facilities would result in a substantial decrease in estimated current
and future methane emissions levels.
• Because methane is a source of energy as well as a greenhouse gas,
many emissions control options have additional economic benefits.
Methane emissions are usually an indication of an inefficiency in a system. In
many cases, methane that would otherwise be emitted to the atmosphere can
be recovered and utilized or the quantity of methane produced can be
significantly reduced through the use of cost-effective management methods.
Therefore, emissions reduction strategies have the potential to be low cost, or
even profitable. For example, methane recovered from coal mines, landfills,
and livestock manure systems can be used as an energy source, and
techniques for reducing methane emissions from livestock also improve the
productivity of each animal.
• Well demonstrated technologies are commercially available for profitably
reducing methane emissions. For all of the major sources of anthropogenic
methane emissions except rice cultivation and biomass burning, cost effective
methane reduction technologies are already commercially available.
Additionally, a number of other technologies are under development. While
offering substantial emissions reductions and economic benefits, these
technologies have not been implemented on a wide scale in the U.S. or
globally because of financial, informational, legal, institutional, and other
barriers.
The unique characteristics of methane emissions demonstrate the significance of
promoting strategies to reduce the amount of methane discharged into the atmosphere.
1.1.1 What is Methane?
Methane is a radiatively and chemically active trace gas.3 Being radiatively active,
methane traps infrared radiation (IR or heat) and helps to warm the Earth. It is currently
3 A trace gas is a gas that is a minor constituent of the atmosphere. The most important trace gases
contributing to the greenhouse effect include water vapor, carbon dioxide, ozone, methane, ammonia, nitrous oxide,
and sulfur dioxide.
1-2
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second only to CO2 in contributing to potential future warming from human activities. Being
chemically active, methane enters into chemical reactions in the atmosphere that help control
the atmospheric abundance of methane. Methane's chemical reactivity in the atmosphere
also affects the abundance of ozone,4 stratospheric water vapor, and other trace gases that
react with the hydroxyl radical (OH).
Methane is emitted into the atmosphere largely by anthropogenic sources, which
currently account for approximately 70 percent of the estimated 505 teragrams (Tg) of annual
global methane emissions.5 The major anthropogenic sources of methane emissions
include: natural gas and oil systems; coal mining; landfills; domesticated livestock; livestock
manure management; rice cultivation; and biomass burning. Natural sources of methane,
which currently account for the remaining 30 percent of global emissions, include natural
wetlands (e.g., tundra, bogs, swamps), termites, wildfires, methane hydrates, and oceans and
freshwaters.
The concentration of methane in the atmosphere is determined by the balance of the
input rate, which is increasing due to human activity, and the removal rate. The primary sink
(removal mechanism) for atmospheric methane is its reaction with the hydroxyl radical (OH) in
the troposphere. In this reaction, methane is converted into water vapor and carbon
monoxide, which is in turn converted into carbon dioxide (CO2). The atmospheric
concentration of OH is determined by complex reactions involving methane, carbon
monoxide, non-methane hydrocarbons (NMHC), nitrogen oxides, and tropospheric ozone.
The amount of methane removed from the atmosphere annually by reaction with OH may be
changing, and a reduced removal rate may be contributing to the build up of methane in the
atmosphere. It is expected, for example, that the removal rate would decline in response to
the observed increasing levels of methane (IPCC 1992a).
A small amount of methane is also removed from the atmosphere through oxidation in
dry soils. Compared to removal by reaction with OH, this oxidation mechanism is believed to
be relatively small. There are no significant anthropogenic activities that remove methane
from the atmosphere. Exhibit 1 -1 presents a summary of methane sources and sinks. Based
on the balance of these sources and sinks, methane's atmospheric lifetime is presently
estimated to be about 11 years (IPCC 1992a).
1.1.2 Atmospheric Levels of Methane Are Rising
The concentration of methane in the atmosphere has been steadily increasing. The
rise in methane concentrations has been well documented in recent studies and corroborated
by measurements from different locations and several monitoring groups. Analyses of ice
cores in Antarctica and Greenland have yielded estimates of atmospheric methane
concentrations of approximately 0.35 parts per million by volume (ppmv) to 0.65 ppmv for the
period between 10,000 and 160,000 years ago. Similar analyses of air in ice cores have
placed atmospheric methane concentrations at approximately 0.8 ppmv for the period
between 200 and 2,000 years ago. The level of methane rose to about 0.9 ppmv at the
beginning of this century (IPCC 1990a).
4 While methane does not contribute significantly to the formation of urban smog, methane is a major concern
in the formation of ozone in the free troposphere.
The estimate of the portion of total methane emissions that comes from anthropogenic sources is based on
IPCC (1992a). The estimate of total annual methane emissions is based on Crutzen (1991).
1-3
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Exhibit 1-1
Estimated Sources and Sinks of Methane
(Tg CH4 per year)
Global Estimate Global Range
Anthropogenic Sources:
Oil/Gas Systems3 50 30 - 70
Coal Mining 40 25 - 50
Landfills 30 20 - 70
Domesticated Livestock 80 65-100
Livestock Manure 25 20 - 30
Rice 60 20-150
Biomass Burning 40 20 - 80
Wastewater Treatment 25 N/A
Total Anthropogenic 350
Natural Sources:
Natural Wetlands 115 100 - 200
Termites 20 10 - 50
Oceans and Freshwaters 15 5-45
CH4 Hydrate Destabilization 0 0-5
Total Natural 150
Total Natural and Anthropogenic:13 505 400 - 610
Sinks:
Atmospheric removal 470 420-520
Removal by soils 30 15-45
Atmospheric Increase: 32 28-37
a It is estimated that natural gas systems account for 25 to 50 Tg and oil systems account for 5 to 20 Tg.
b Total annual emissions are well constrained based on observational data. The point estimates of the
individual source estimates do not sum to 505 Tg.
Sources: IPCC (1992a). The estimate of total natural and anthropogenic emissions is taken from Crutzen
(1991). This estimate of total emissions is based on observations of atmospheric concentrations and
independent estimates of methane's atmospheric lifetime, and is not estimated as the sum of the individual
emissions estimates shown here.
Note: Estimates of global methane emissions are continually being revised. Another EPA Report to Congress
on International Methane Emissions will contain new estimates of global methane emissions from individual
sources.
1-4
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Direct measurement of the global atmospheric methane concentration was begun in
1978. At that time the global atmospheric methane concentration was calculated to be 1.51
ppmv. In 1990, the level was approximately 1.72 ppmv - nearly double the concentration
level estimated for the beginning of this century (IPCC 1990a). A summary of the ice core
data and direct measurement data showing the increase in atmospheric methane
concentrations is provided in Exhibit 1-2. In addition to ice core data and direct atmospheric
measurements, analysis of infrared solar spectra has shown that the atmospheric
concentration of methane increased by about 30 percent over the last 40 years (Rinsland et
al. 1985).
Exhibit 1-2
Measurements of Global Methane Concentrations
1800-
JO
CL
Q.
m
O
1300-
800-
O
300-
• Modem record
• Slpte tee core
» Byrd toe core
• Dy» tee core
o \totoktee core
*
A
O
D
10« 10* 10s 10* 101
Years Before Present (1990 A.D.)
10*
Annn«l atmospheric CHU cooeentratfoiw during the put 160,000 years
(derived from ice cores and the NOAA/CMDL flask sampling network).
10°
Source: Oak Ridge (1990).
At present, the atmospheric abundance of methane is approximately 4,900 Tg (IPCC
1990a); this amount is thought to be increasing by about 30 to 40 Tg per year (Steele et al.
1992). Atmospheric methane concentrations are expected to continue to increase, although
global measurement programs indicate that the rate of increase appears to have slowed in
the last several years (Steele et al. 1992). However, given a continuation of the current
annual rate of increase of atmospheric methane of about 0.0095 to 0.0133 ppmv (Steele et al.
1-5
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1992), the atmospheric concentration of methane would exceed 2.0 ppmv by the year 2020.
Recent models of expected future emissions and atmospheric processes indicate that, without
controls, atmospheric concentrations could range from 3.0 ppmv to over 4.0 ppmv by the
year 2100 (USEPA 1989; IPCC 1992a), although these scenarios should be reinvestigated
using the most recent information on methane concentration trends.
1.1.3 Methane and Global Climate Change
Methane's increasing concentration in the atmosphere has important implications for
global climate change. Methane is very effective at absorbing infrared radiation (IR) given off
by the Earth's surface. By absorbing IR and inhibiting its release into space, the presence of
methane contributes to increased atmospheric and surface temperatures. This process is
commonly referred to as the "greenhouse effect."
A gram of methane is about 11 times more effective at warming the Earth's surface
than a gram of CO2 over a 100 year time frame (IPCC 1992a). In addition to this direct
radiative forcing, methane's participation in chemical reactions in the atmosphere indirectly
contributes to global warming by influencing the amount of ozone in the troposphere and
stratosphere, the amount of OH in the troposphere, and the amount of water vapor in the
stratosphere. Methane's indirect effect on warming resulting from these chemical reactions
could be comparable in magnitude to its direct effect, although considerable uncertainty
remains (IPCC 1992a).6 It has been estimated that approximately 18 percent of the
greenhouse effect is due to increasing atmospheric methane concentrations. The total
contribution to radiative forcing of all greenhouse gases in 1990 is shown in Exhibit 1 -3.
Models of atmospheric chemical processes have indicated that increasing methane
concentrations result in net ozone production in the troposphere and lower stratosphere and
net ozone destruction in the upper stratosphere. The overall effect is that methane by itself
causes a net increase in ozone (Wuebbles and Tamaresis 1992)7
As the most abundant organic species in the atmosphere, methane plays an influential
role in determining the oxidizing capacity of the troposphere. Through reactions with OH, 80
to 90 percent of methane destruction occurs in the troposphere (Cicerone and Oremland
1988). Increasing methane levels could reduce OH, which would result in a further increase
in the methane concentration. A decrease in the oxidizing capacity of the troposphere would
increase not only the atmospheric lifetime of methane, but also the lifetime other important
greenhouse gases, and would permit transport of pollutants over long distances, resulting in
atmospheric changes even in remote regions (Wuebbles and Tamaresis 1992).
6 The uncertainty in the GWPs for methane result largely from the indirect effects of methane in the
atmosphere, which have not been fully characterized, and from methodological issues in the GWP calculations.
Some of these uncertainties will be reduced over the next several years through the efforts of the Intergovernmental
Panel on Climate Change as well as others, including EPA's Office of Research and Development.
7 As described in IPCC (1990a), "Ozone plays an important dual role in affecting climate. While C02 and other
greenhouse gases are relatively well-mixed in the atmosphere, the climatic effect of ozone depends on its
distribution in the troposphere and stratosphere, as well as on its total amount in the atmosphere. Ozone is a
primary absorber of solar radiation in the stratosphere where it is directly responsible for the increase in temperature
with altitude. Ozone is also an important absorber of infrared radiation. The balance between these radiative
processes determines the net effect of ozone on climate."
1-6
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Exhibit 1-3
Global Contribution to Integrated Radiative Forcing by Gas for 1990a
Carbon Dioxide: 66%
N i trous
Ox i de ' 5%
CFCs ' 11'
Methane: 18%
Estimated on a carbon dioxide equivalent basis using IPCC (1990a) global warming
potentials (GWPs) for a 100-year time horizon. Anthropogenic emissions only.
a This pie chart is used to present a general understanding of methane's contribution to future warming based
on the GWPs presented in IPCC (1990a). However, these GWPs are continually being revised due to a variety
of scientific and methodological issues. Upon further investigation the contribution of CFCs may decrease
(although not likely to the extent indicated in IPCC (1992a)) and the contribution of other gases will be about
the same or greater.
Water vapor is one of the most important greenhouse gases. Stratospheric water
vapor concentrations should increase as concentrations of methane increase; methane
oxidation reactions roughly produce two moles of water vapor for each mole of methane that
is destroyed (Wuebbles and Tamaresis 1992). In addition to the impact on global warming,
increases in stratospheric water vapor concentrations as a result of increased methane
concentrations could contribute to the formation of polar stratospheric clouds (PSCs), which
have been identified as one factor that enables the chlorine and bromine from
chlorofluorocarbons (CFCs) and halon compounds to cause the severe seasonal loss of
stratospheric ozone over Antarctica (WMO 1990).
1.1.4 Stabilization and Further Reductions of Global Methane Levels
Since atmospheric methane has been increasing at a rate of about 30 to 40 Tg per
year, stabilizing global methane concentrations at current levels would require reductions in
methane emissions by approximately this same amount. Such a reduction represents about
10 percent of current anthropogenic emissions. This reduction is much less than the
percentage reduction necessary to stabilize the other major greenhouse gases: CO2 requires
a greater than 60 percent reduction; nitrous oxide requires a 70 to 80 percent reduction; and
chlorofluorocarbons require a 70 to 85 percent reduction (IPCC 1990b).
1-7
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Because methane has a relatively short atmospheric lifetime as compared to the other
major greenhouse gases, reductions in methane emissions will help to ameliorate global
warming relatively quickly. Therefore, methane reduction strategies offer an effective means
of slowing global warming in the near term. Exhibit 1-4 compares the effect on future
temperature increases of stabilizing methane concentrations versus maintaining CO2
emissions at 1990 levels. This exhibit illustrates that stabilizing atmospheric concentrations of
methane will have virtually identical effects on actual warming as capping CO2 emissions at
1990 levels. The recent evidence that the rate of annual increase in methane emissions is
slowing (Steele et al. 1992) may mean that reductions on the order of 30 to 40 Tg could
reduce concentrations to the extent that they fall below the level of stabilization. This result
would also have large benefits for the global atmosphere.
Exhibit 1-4
Carbon Dioxide and Methane Reduction Comparison8
Aetufl
Tmmptntun
Inentft f'C)
RougMy MtnOetl •«fcc» on actual mmlng
- CO,
~CH.
• »•••••*••• ^«W • • • •
»••*••>•••••• *\t * •
2000
3025
I
20SO
IPCC-BAU
CH. stablltetlon
CO2 capped it 1990
CH.andCO,
2O7S
2100
AaaumM 3° equilibrium warming
|| H III Constitutes uncertainty rang* du« to NO,
a Benefits of CH4 stabilization where CH4 emissions are capped at 540 Tg/yr as compared to capping CO2
emissions at 1990 levels (and concentrations grow to over 500 ppm by 2100).
Source: Hogan et al. (1991).
1.2 SOURCES OF METHANE AND TECHNOLOGIES FOR EMISSIONS REDUCTIONS
The U.S. is one of the largest contributors of global anthropogenic methane
emissions. However, compared to other nations on a source by source basis, the U.S. is
among the highest methane emitting nations for some of the sources, but among the lowest
for others. For example, the U.S. is estimated to have the largest emissions from landfills --
about one third of worldwide emissions from this source. In contrast, the U.S. accounts for a
very small portion of emissions from rice cultivation - Asia is responsible for 90 percent of
1-8
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emissions from this source. Methane emissions from livestock are fairly evenly distributed
worldwide, with the U.S. representing approximately 7 percent of the global total.
Methane released by anthropogenic activities is generally a wasted resource, opening
the possibility for low cost, if not profitable emissions reduction opportunities. Depending on
the source, a significant portion of the methane currently emitted to the atmosphere can be
reduced through the use of cost effective technologies. In the U.S. a variety of emissions
reductions technologies are available for each major anthropogenic source of emissions --
natural gas systems, coal mining, landfills, domesticated livestock and livestock manure.
However, in many cases, existing financial, political, and informational barriers often constrain
the wider application of these technologies. A summary of U.S. emissions from
anthropogenic sources is shown in Exhibit 1 -5; this exhibit also indicates which emissions
could be reduced through the use of cost effective technologies. Exhibit 1-6 summarizes the
technologies available for reducing methane emissions from the major anthropogenic sources
in the U.S.
1.2.1 Natural Gas Systems and Oil Systems
Methane is the primary component of natural gas and significant methane emissions
can result during all the major phases of the natural gas supply system - production,
processing, storage, transmission, and distribution. Emissions result from: normal operations
(including compressor exhaust emissions, emissions from pneumatic devices and fugitive
emissions); routine maintenance (including equipment blowdown and venting, well workovers
and scraper operations); and system upsets (including sudden, unplanned pressure changes
or other mishaps). Because natural gas is often found in conjunction with oil, gas leakage
during oil exploration and production is also a source of emissions. In 1990, emissions from
natural gas systems in the U.S. are estimated to have been between 2.2 and 4.3 Tg, while
emissions from oil systems are estimated to have been between 0.1 and 0.6 Tg. Global
emissions for both oil and gas systems are estimated to be 30 to 70 Tg per year.
The technical nature of emissions from natural gas systems is well understood, and
emissions are largely amenable to technological solutions including reduced venting during
production, improved compressor operation, leak detection and repair, and installation of low
emission technologies, such as improved pipeline control devices that reduce or eliminate
unnecessary venting. In many cases, application of these technical solutions can be very
cost-effective. Other benefits include improved safety and improved air quality.
1.2.2 Coal Mining
Methane and coal are formed together during coalification, a process in which
vegetation is converted by biological and geological forces into coal. Methane is stored
within coal seams and surrounding rock strata and is released to the atmosphere during
mining or through natural erosion. In underground mines, methane is hazardous because it
is explosive in low concentrations in air (5 to 15 percent). Therefore, underground mines use
ventilation and degasification systems to remove methane from mine workings; this methane
is usually vented to the atmosphere. In surface mines, methane is emitted directly to the
atmosphere as the rock strata overlying the coal seam is removed. The amount of methane
released from a mine depends mainly upon the type of coal and the depth of the coal seam -
coals with a higher carbon content and deeper coals generally hold more methane. U.S. coal
mine methane emissions in 1990 are estimated to have been 3.6 to 5.7 Tg, while current
global coal mine emissions are estimated to be 25 to 50 Tg per year.
1-9
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Exhibit 1-5
U.S. Anthropogenic Emissions Summary
Source
Landfills8
Domesticated Livestock
Dairy Cattle
Beef Cattle
Other Animals
Total Domesticated Livestock
Coal Mining
Underground Coal Mines
Ventilation Systems
Degasification Systems3
Surface Coal Mines
Post-Mining
Total Coal Mining
Natural Gas Systems
Fugitive Emissions
Pneumatic Devices
Engine Exhaust
Other
Total Natural Gas Systems'3
Livestock Manure
Liquid Based Systems
Solid Based Systems
Total Livestock Manure
Other Sources
Rice
Combustion
Oil Systems
Other0
Total Other Sources'3
Total6
U.S. Emissions
(Tg)
8.1 to 11.8
1.2 to 1.8
3.2 to 4.8
0.2 to 0.4
4.6 to 6.9
2.3
0.5 to 1.8
0.2 to 0.8
0.5 to 0.9
3.6 to 5.7
0.7 to 1.9
0.4 to 1.1
0.3 to 0.6
0.4 to 1.9
2.2 to 4.3
1.4 to 2.3
0.3 to 1.3
1.7 to 3.6
0.1 to 0.7
0.5 to 1.7
0.1 to 0.6
Not Estimated
1.1 to 2.5
25 to 30
Partially
Controllable
•
'
'
\
<
'
a Does not include methane recovered and used as an energy source. For landfills,
about 1 .5 Tg was recovered and flared or used for energy purposes. For coal mines,
about 0.25 Tg was recovered and sold to pipelines.
b The uncertainty in the total is estimated assuming that the uncertainty for each source
is independent. Consequently, the uncertainty range for the total is more narrow than the
sum of the ranges for the individual sources. For natural gas systems, total emissions
are calculated assuming that some of the uncertainty for each source is independent.
c Includes non-fuel biomass burning, wastewater from agricultural industries, ammonia
production, coke, iron, and steel production, and land use changes.
1-10
-------
Exhibit 1-6
Summary of Technologies for Reducing Methane Emissions in the U.S.
Source/Technologies
Availability
Natural Gas Systems
Reduce Venting
Modify Compressors
Detect/Repair Leaks
Low Emission Technologies
Now
Now
Now
Now
Coal Mining
Enhanced Gob Recovery
Pre-mining Degasification
Ventilation Air Use
Integrated Recovery
Now
Now
Needs
Demonstration
Now
Landfills
Recovery and Utilization
Aerobic Landfills
Source Reduction
Now
Now
Now
Ruminant Livestock
Improved Marketing System
Productivity Enhancers
Improved Genetics
Improved Reproduction
Now
Now
Now
Now
Livestock Manure
Covered Lagoons
Advanced Digesters
Low-Technology Digesters
Now
Now
Now
Applicability
Applicable for:
- Poor Conditions
- Older Systems
- System Expansion
Dependent upon:
- Gassy Mines
- Nearby Gas Use
- Available Technology
- Available Capital
Dependent upon:
- Landfill Design
- Nearby Gas Use
- Available Technology
- Available Capital
Dependent upon:
- Management System
- Available Technology
- Available Capital
- Available Markets
Dependent upon:
- Manure Management System
- Climate
- Available Technology
- Available Capital
Benefits
- Reduced Gas Loss
- Improved Air Quality
- Improved Mine Safety
- Increased Productivity
- Clean Energy Source
- Improved Safety
- Improved Air Quality
- Clean Energy Source
- Improved Productivity
- Improved Water Quality
- Reduced Health Risk
- Clean Energy Source
Source: IPCC (1992b).
1-11
-------
Several technologies are available for recovering and utilizing coalbed methane that
would otherwise be released to the atmosphere during mining in underground mines.
Degasification systems - including vertical wells, gob wells, and in-mine boreholes - recover
high quality methane that can be used as an energy source. These degasification systems
accounted for approximately 0.5 to 1.6 Tg of U.S. coal mine methane emissions in 1988
(USEPA 1993). However, using a combination of methane recovery approaches, it is possible
for underground coal mines to recover over 70 percent of the methane that would otherwise
be released during mining. Accordingly, the potential for emissions reduction is not limited to
current degasification emissions. Recovered methane can be sold to pipeline companies or
used to generate electricity at the mine for on-site use or for off-site sale to a utility. In
addition to revenue received from the sale of gas or electricity generated from recovered
methane, mines receive benefits associated with increased productivity, lower ventilation
requirements and costs, and improved mine safety.
1.2.3 Landfills
Methane is generated in landfills as a direct result of the natural decomposition of
solid waste primarily under anaerobic (in the absence of oxygen) conditions. The organic
component of landfilled waste is broken down by bacteria in a complex biological process
that produces methane, carbon dioxide, and other trace gases. Emissions from landfills in
the U.S. in 1990 are estimated to have been 8.1 to 11.8 Tg, while global emissions are
estimated to be 20 to 70 Tg per year.
There are two main approaches for reducing methane emissions from landfills. One
approach involves waste management practices that either divert a portion of the municipal
solid waste stream away from landfill disposal toward alternative disposal and treatment
methods or that promote measures to reduce the quantity of waste produced. Another
approach is to recover the methane and to use it as an energy source. This second option is
the only method currently available for reducing emissions from existing landfills and from
landfills that will contain degradable waste in the future.
Methane recovery is likely to be profitable only for large landfills, which account for a
very high percentage of emissions from this source. For example, although an estimated
6,000 landfills emit methane in the U.S., about 1,300 large landfills account for nearly all the
methane produced. Of these, about 900 landfills account for 85 percent of the waste in
landfills and 75 percent of the methane emitted. Moreover, 19 of the largest landfills account
for about 25 percent of the waste in landfills and 20 percent of the methane emitted (USEPA
1993). Additional benefits that result from landfill methane recovery projects include improved
air quality and reduced risk of fire and explosion.
1.2.4 Domesticated Livestock
Among the domesticated animals, ruminant animals (cattle, sheep, buffalo, goats, and
camels) produce significant quantities of methane as part of their normal digestive processes.
Ruminant animals are characterized by a large 'lore-stomach" or rumen, in which microbial
fermentation converts feed into products that can be digested and utilized by the animal. The
microbial fermentation enables ruminant animals to utilize coarse forages that monogastric
animals, including humans, cannot digest. Methane is produced by rumen methanogenic
bacteria as a byproduct of normal rumen fermentation, and then is exhaled or eructated by
the animal. The amount of methane produced is dependent upon both animal type and
1-12
-------
management practices. Domesticated animals accounted for approximately 4,6 to 69 Tg of
U.S. methane emissions in 1990; global emissions are estimated to be 65 to 100 Tg per year.
There are several main approaches for reducing methane emissions from cattle.
Improving livestock productivity so that less methane emitted per unit of product is the most
promising and cost-effective technique for reducing emissions in the U.S. Refinements to the
milk and beef marketing systems to better match production incentives with consumer
demand not only will improve efficiency and reduce costs, but also will reduce methane
emissions. These marketing refinements are the most important options for reducing
methane emissions from this source. Additional options for improving livestock productivity
include the use of productivity enhancing agents, such as bovine somatotropin (bST) in the
dairy industry and ionophore feed additives in the beef industry, and improved cow-calf sector
productivity (through better feeding and management) in the beef industry.
1.2.5 Livestock Manure
Methane is produced during the anaerobic decomposition of the organic material in
livestock manure. Many developed countries, including the U.S., have large confined cattle,
swine, and poultry facilities. The manure at these facilities is typically handled in a liquid form,
which promotes anaerobic fermentation of the manure and methane production. Methane
emissions from livestock manure in the U.S. are estimated to have been 1.7 to 3.6 Tg in 1990,
while global emissions are estimated to be 20 to 30 Tg per year.
The most promising option for reducing methane emissions from livestock manure is
to recover methane for use as an on-farm energy source. Methane can be recovered from
liquid-based animal manure management systems. These systems account for about 60 to
80 percent of livestock manure emissions. Recovered methane can be used to generate
electricity, to provide heating, or to produce cooling. In addition to reducing methane
emissions, methane recovery systems provide other benefits, including: reduced ground and
surface water pollution; improved public health; odor reduction and fly control; and reduced
manure handling expenses.
1.3 PROFITABLE EMISSIONS REDUCTION PROJECTS IN THE U.S.
Numerous methane recovery/reduction activities are currently in place in the U.S. In
fact, the U.S. has a long history of increasing productivity and profitability through reducing
methane emissions from coal mining, landfills, livestock manure, and domestic livestock.
• Coal Mining. U.S. experience demonstrates that selling recovered methane to
a pipeline can be profitable for mining companies. Eleven mines (5 in
Alabama, 5 in Virginia, and 1 in Utah) currently sell methane from their
degasification systems to local pipeline companies. These mines not only
generate revenue from the sale of recovered gas, but also realize significant
energy savings due to a reduced need for air to ventilate the mines. In 1988,
the mines in Alabama and Utah recovered and sold an estimated 0.25 Tg of
methane that would otherwise have been vented to the atmosphere.
• Landfills. The technologies for landfill gas recovery, processing, and electricity
generation are well developed. In the U.S., over 100 landfills currently recover
methane for electricity generation. These landfills recover approximately 1.5 Tg
1-13
-------
of methane annually and have an electric generating capacity of over 330 MW
(GAA1991).
• Livestock Manure. Over 20 methane recovery and utilization systems are
currently operating on private and university livestock facilities across the U.S.
These recovery systems demonstrate the operational and economic feasibility
of covered lagoons, plug flow digester, and complete mix digesters. These
recovery systems have been designed specifically for each livestock operation
based upon the type of livestock, number of livestock, manure management
system, energy requirements, and climate.
• Domestic Animals. A variety of techniques that increase animal productivity
and reduce methane emissions per unit product are already being used
successfully in the U.S. For example, production enhancing agents are used
profitably throughout much of the U.S. dairy and beef industries. There are
strong trends toward continued improved productivity, and industry efforts are
underway to refine the existing marketing systems for milk and beef products
to further improve efficiency and productivity.
These examples show that profitable opportunities are available to reduce methane
emissions. This report evaluates the extent to which profitable methane reduction
opportunities are available nationally. Profitability is defined with respect to an owner,
operator, or investor in a methane recovery project. Profitability is assessed by comparing
the net present value (NPV) of the costs and benefits of the mitigation opportunities. Projects
with a positive NPV are considered profitable. Discount rates for the NPV analysis were
selected based on the estimated uncertainty and riskiness of the methane mitigation projects
for each of the methane sources. Exhibit 1-7 summaries the discount rates used and
describes how they were selected.
This report shows that while numerous landfill, coal mining, natural gas, and livestock
operations have the necessary characteristics to be able to implement profitable emissions
reduction projects, many have yet to develop these projects. The failure to implement
emissions reductions projects stems both from lack of information about the potential benefits
and from transactional difficulties in instituting such projects. Depending on the methane
source, these transactional barriers may involve financial, legal, institutional, and regulatory
issues. Furthermore, coal mines, landfills, and livestock manure operations that would use
recovered methane as an energy source face economic and regulatory barriers that are
common to virtually all "alterative" energy sources.
1.4 OVERVIEW OF REPORT
Section 603 of the Clean Air Act Amendments of 1990 requires EPA to prepare and
submit to Congress a series of reports on domestic and international issues concerning
methane. The topics for the five required reports are: 1) Anthropogenic Methane Emissions
in the United States; 2) Options for Reducing Anthropogenic Methane Emissions in the United
States; 3) International Anthropogenic Methane Emissions; 4) Options for Reducing
International Anthropogenic Methane Emissions; and 5) Methane Emissions from Natural
Sources. This report fulfills the requirement for the second topic.
1-14
-------
Exhibit 1-7
Summary of Discount Rates Used in This Report
Chapter
Real Discount Rate
Comments
Natural Gas
Coal
Landfills
Livestock
Livestock Manure
6%
6%
8%
Not Applicable
(Discounted cash flow
analysis not performed)
10%
A real discount rate of 6 percent is used for
large industrial sectors such as natural gas
and coal. Coal and natural gas companies
are generally very large and have relatively
low capital costs and stable revenues. For
landfills a higher real discount rate of 8
percent is assumed because landfill gas
recovery projects will likely face higher
financing costs and greater uncertainty in
the future revenue stream. A real discount
rate of 10 percent is adopted for livestock
manure to reflect the higher capital costs
likely to be faced by farmers, which are
smaller operations.
For example, the real discount rate for coalbed methane projects can be estimated from the following equation
(adapted from Brealey and Myers (1984)):
T| = r0 + B | • [ rM - ra ]
where r-t = the nominal discount rate
the nominal risk free rate of return =
r =
= the nominal market rate of return =
B =
the "beta" for the project
5.8% The nominal rate of return on treasury
bills over the period 1956-1986.
12.4% The nominal rate of return on common
stock, long term corporate bonds, and
residential real estate over the period
1956-1986.
0.5 The assumed asset beta for coalbed
methane project. The equity beta for a
coal company is typically near 1.0.
Therefore, assuming an equity beta of 1
and assuming a debt beta of 0.0 and a
50/50 debt to equity ratio, the asset beta
would be 0.5.
Using these values, r, = 5.8% + 0.5 • |12.4% - 5.8%] = 9.1% which is rounded to 10 percent for this analysis.
Therefore, assuming an average 4 percent inflation rate, the 10 percent nominal discount rate corresponds to a
real discount rate of 6 percent.
The goal of this report is to evaluate the extent to which methane emissions can be
reduced through the use of technologies that are either currently in use or under
development. Each chapter estimates emissions reductions that are technically feasible and
the portion of such emissions reductions that could potentially be achieved at a profit to
private owners. Each chapter identifies the types of facilities where profitable recovery is
likely and discusses barriers and limitations to the implementation of otherwise cost-effective
emissions reduction technologies. Each chapter begins with a self-contained summary that
briefly describes the issues related to each methane source and the opportunities for
emissions reduction. The remainder of each chapter provides an in-depth discussion of each
emission source and the methodology and data used to evaluate emission reduction
opportunities.
1-15
-------
In addition to this introductory chapter, this report contains six chapters -- one on
each of the five major sources of methane emissions in the U.S and an additional chapter on
barriers that impede the development of all methane recovery projects. Each chapter also
describes the barriers that are specific to each of the sources. The chapters of this report
are:
1. Introduction
2. Natural Gas Systems;
3. Coal Mining;
4. Landfills;
5. Domesticated Livestock;
6. Livestock Manure; and,
7. Barriers to Methane Recovery Projects.
A synopsis of each of these chapters is provided in the Executive Summary.
1.5 REFERENCES
Brealey, Richard and Stewart Myers. 1984. Principles of Corporate Finance. Second Edition.
McGraw-Hill Book Company. New York.
Cicerone, R.J. and R.S. Oremland. 1988. "Biogeochemical Aspects of Atmospheric Methane,"
Global Biogeochemical Cycles, vol. 2, p. 299-327. December 1988.
Crutzen, P.J. 1991. "Methane's Sinks and Sources" Nature No. 350. April 1991.
GAA (Government Advisory Associates, Inc). 1991. 1991-92 Methane Recovery From Landfill
Yearbook. Government Advisory Associates, Inc. New York. 1991.
Hogan, K.B., J.S. Hoffman, and A.M. Thompson "Methane on the Greenhouse Agenda"
Nature Vol. 354. November 21, 1991.
IPCC (Intergovernmental Panel on Climate Change). 1990a. Climate Change: The IPCC
Scientific Assessment. Report Prepared for Intergovernmental Panel on Climate
Change by Working Group 1.
IPCC (Intergovernmental Panel on Climate Change). 1990b. Methane Emissions and
Opportunities for Control. Workshop Results of the IPCC Response Strategies
Working Group. September 1990.
IPCC (Intergovernmental Panel on Climate Change). 1992a. Climate Change 1992: The
Supplementary Report to the IPCC Scientific Assessment. Cambridge University Press,
Cambridge, United Kingdom.
1-16
-------
IPCC (Intergovernmental Panel on Climate Change). 1992b. Technological Options for
Reducing Methane Emissions: Background Document of the Response Strategies
Working Group. Draft Report. January, 1992
Oak Ridge. 1990. Oak Ridge National Laboratory/The Carbon Dioxide Information Analysis
Center. 1990. Trends '90. U.S. Department of Energy, Atmospheric and Climate
Research Division. Oak Ridge, Tennessee.
Oak Ridge. 1992. National Laboratory/The Carbon Dioxide Information Analysis Center. 1992.
Trends '91. U.S. Department of Energy, Atmospheric and Climate Research Division.
Oak Ridge, Tennessee.
Rinsland, C.P, J.S. Levine, and T. Miles. 1985. "Concentration of methane in the troposphere
deducted from 1951 infrared solar spectra." Nature No. 330 pp. 245-249. As cited in
IPCC (1990a).
Steele, L.P., E.J. Dlugokencky, P.M Lang, P.P Tans, R.C. Margin, and K.A. Masarie. 1992.
"Slowing down of the global accumulation of atmospheric methane during the 1980s."
Nature. Volume 358. July 23, 1992.
USEPA (U.S. Environmental Protection Agency). 1989. Policy Options for Stabilizing Global
Climate, Report to Congress. Office of Policy, Planning, and Evaluation. Washington,
D.C. 21P-2003.1. December 1990.
USEPA (U.S. Environmental Protection Agency). 1993. Anthropogenic Methane Emissions in
the United States, Report to the Congress, prepared by the Global Change Division,
Office of Air and Radiation, EPA, Washington, D.C.
WMO (World Meteorological Institute). 1990. Scientific Assessment of Stratospheric Ozone:
1989. World Meteorological Organization Global Ozone Research and Monitoring
Project - Report No. 20. Geneva, Switzerland.
Wuebbles, D.J. and J.S. Tamaresis. 1992. The Role of Methane in the Global Environment
Paper prepared for submittal to the NATO Advanced Research Workshop, NATO-ASI
Book: Atmospheric Methane, Lawrence Livermore National Laboratory, March 19,
1992.
1-17
-------
CHAPTER 2
OPPPORTUNITIES TO REDUCE METHANE EMISSIONS
FROM NATURAL GAS SYSTEMS
Natural Gas Methane Emission Reductions
Share of U.S
Emissions Reductions
0. 3
•2.
.2.3
Pr-oT 1 tat) I e
Reciuct i ons
RemaInIng
Em Iss i ons
Low Hlgri
-I93O
Low High
2DDD
Low H I gh
2D-IO.
Natural Gas System Methane Emissions
a
b
Year
1990
2000
2010
Baseline
Ranges
Baseline
2.2
2.4
2.4
Emissions3
-4.3b
-5.0
-5.4
Technically Feasible
Emission Reductions
0.78-
0.83-
emissions from USEPA (1993).
based on the Low and High Emissions
1.6
1.8
Scenarios.
ffg)
Profitable Emission
Reductions
0.26
0.26
-1.2
-1.3
CHAPTER SUMMARY
Methane is the principal component of natural
gas, and therefore leaks from the wide variety of
components, processes, and activities that make
up the natural gas system contribute to methane
emissions. Methane emissions from the U.S.
natural gas system in 1990 are estimated to
range from 2.2 to 4.3 Tg per year, with a central
estimate of about 3.0 Tg per year (USEPA 1993).
These emission estimates are based on analyses
of the activities in each of the major stages of the
natural gas system: production; processing;
transmission; storage; and distribution. Over 80
percent of the emissions originate in the produc-
tion, transmission, and distribution stages.
Methane emissions from the U.S. natural gas
industry are expected to increase over the com-
ing decade as gas consumption and system
throughput increase. Emissions will not increase
proportionately with consumption, however, as
total emissions depend partly on the size of the
system infrastructure and not solely on system
throughput. While gas consumption is estimated
to increase between 20 and 30 percent above
1990 levels by 2000, emissions are estimated to
increase by only 11 to 18 percent.
2-1
-------
Chapter Summary
It Is technically feasible to reduce
methane emissions from the natu-
ral gas system by about 33 per-
cent Methane emissions can be
reduced profitably by about 25
percent . I .
Based on an array of available technologies, it is
technically feasible to reduce methane emissions
from the natural gas system by about 33 percent.
Some of these technologies are estimated to be
profitable: the value of the gas emissions avoid-
ed exceeds the costs of implementing the tech-
nology. Using these technologies, methane
emissions from natural gas systems can be
reduced profitably by about 25 percent.
This potential for profitable methane reductions
reflects the continued development of new tech-
nologies in the natural gas industry. While the
U.S. natural gas industry is currently one of the
most efficient systems in the world, particularly in
terms of methane emitted per quantity of gas
produced or marketed, there remain substantial
opportunities to promote the more widespread
use of recently available technologies.
The main barriers to realizing these emission
reductions are informational and regulatory.
Information regarding the profitability of the
options for reducing emissions must be dissemi-
nated. In some cases the technologies are
relatively new, and their operating characteristics
and costs are not widely known. Rate regulations
also pose a barrier because in some cases
companies are able to recover the cost of lost
gas from customers, so that the incentive for
avoiding emissions is substantially reduced.
Profitable Emission Reductions
Through the more widespread use of a variety of
technologies and practices, which are currently
available and which have been shown to be cost-
effective in a number of settings, methane emis-
sions from the U.S. natural gas system can be
reduced from 1990 levels. Emission reductions of
about 0.8 Tg and 0.9 Tg can be achieved profit-
ably in 2000 and 2010, respectively. The profit-
able emissions reductions are about 25 percent
of baseline emissions in 2000 and 2010 (see
Exhibit 2-1).
These emission reductions are equivalent to
about 18 million metric tons of CO2,1 or the
annual CO2 output from approximately 3.7 million
cars.2 Furthermore, reducing emissions saves
gas that would otherwise be wasted, thus pro-
ducing annual energy savings equivalent to 43
billion cubif feet (bcf) of natural gas.3
Profitable emission reductions may be acheived
throughout the production, trasmission, and
distribution stages of the gas system - which
represent over 80 percent of emissions. The
technical and economic feasibility of eight key
options for reducing emissions from the major
sources within these three stages are analyzed.
Five of these options are profitable. The reduc-
tion estimates for these options are summarized
in Exhibit 2-2 and are briefly described below.
Reducing Methane Emissions from Natural Gas
Production
The production of natural gas accounts for about
35 percent of the total methane emissions from
the U.S. natural gas system, or roughly 1.1 Tg in
1990. About 70 percent of these emissions result
from fugitive emissions, pneumatic devices, and
dehydrator venting (USEPA 1993). There are
1 This assumes a global warming potential (GWP) of 22 for methane which is consistent with IPCC (1992). However,
significant uncertainty remains in methane's GWP, and if a different value is chosen, the estimate of the CO2-equivalent
emissions would need to be modified accordingly.
2 Average annual gasoline consumed by a car in the U.S. between 1985 and 1988 is about 585 gallons (Hoffman
1991). With a conversion of 0.0676 grams of CO2 per BTU of gasoline and 124,620 BTU per gallon of gasoline
(Unnasch and Moyer 1989) annual emissions of CO2 per car in the U.S. is estimated at about 4.9 metric tons.
3 Tg = Teragram = 1 million metric tons = 52 billion cubic feet (bcf) (one cubic foot of gas has about 19.2 grams of
methane at 1 atmosphere and 60° F).
2-2
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Chapter Summary
available cost-effective options for reducing
emissions from these sources.
The production of natural gas ao
cowt& f
-------
Chapter Summary
no-bleed designs where technically appropriate
throughout this stage is very cost-effective. By
replacing the high-bleed devices, methane emis-
sions can be reduced by about 0.12 Tg/yr in
2000 and 2010.
Reciprocating engines are used throughout the
industry to drive compressors that transport gas,
but are most highly concentrated in the transmis-
sion stage. In 1990, reciprocating engines in the
transmission stage were estimated to emit about
0.18 Tg/yr. The major option for reducing emis-
sions from reciprocating engines involves the
greater use of turbine engines for compression in
transmission pipelines, as new transmission lines
are constructed and as old reciprocating units
are replaced. This option could reduce emis-
sions by about 0.07 Tg/yr in 2000 and 0.13 Tg/yr
in 2010. However, there are many operational
factors that must be considered when choosing
between turbines and reciprocating engines, and
this choice must be made site by site.
Venting during routine maintenance of pipelines
occurs when the natural gas must be removed
from a section of pipe for safety reasons during
repairs. Options for reducing these emissions
include using portable evacuation compressors
(PECs) to pump the gas from the section of pipe
to be repaired to an adjoining section. The
utilization of PECs could reduce emissions by
about 0.02 Tg/yr in 2000 and 2010. While this
technology has been used cost-effectively in
Canada, differences in pipeline design and
operations between the two countries cause this
technology not to be cost-effective in the United
States with current gas prices.
Reducing Methane Emissions from Natural Gas
Distribution
The distribution of natural gas through smaller
diameter, low pressure pipes accounts for about
11 percent of methane emissions from the U.S.
natural gas systems, or about 0.3 Tg in 1990.
Nearly 90 percent of these emissions result from
fugitive emissions from subsurface pipes and
from the gate stations where the gas is trans-
ferred from the transmission to the distribution
system. There are available options, some of
which are cost-effective, for reducing emissions
from these sources.
The distribution of natural gas ac-
counts for about 11 percent of meth-
ane emissions from the IKS. natural
gas system or about (X3 Tg in 1990>
Neatly 30 percent of these emissions
result from fugitive emissions from
subsurtacft pipes arid from the gate
stations where the gas is transferred
from the transmission to the distribu-
tion system.
Fugitive emissions from gate stations are an
important methane source from distribution
systems. These emissions may be reduced
through implementation of directed inspection
and maintenance programs. This option is cost
effective and could reduce methane emissions by
about 0.10 Tg/yr in 2000 and 0.11 Tg/yr in 2010.
Fugitive emissions from subsurface piping are an
important source of methane emissions in the
distribution system. These emissions are re-
duced when pipeline segments are rehabilitated,
either through complete replacement of the
leaking pipe or joint, or through insertion of repair
materials into the old pipe. According to Watts
(1990), for every two miles of main or service
pipeline added in the late 1980s, about one mile
of existing line was replaced, usually with plastic.
The costs for these repairs generally far exceed
the value of saved gas and are justified princi-
pally on the basis of reducing potential safety
hazards to the public. Consequently, accelerated
rehabilitation of pipeline is not considered in this
analysis.
These existing options may be supplemented
over the next few years by a variety of technolo-
gies and practices currently under development.
These emerging technologies include metallic
coated seals, smart regulators, composite wraps
for pipeline repair, and catalytic converters for
engine exhaust. While the implications of these
emerging techniques for future emission reduc-
tions have not been evaluated in detail, wide-
spread implementation of these techniques could
reduce emissions by on the order of 0.2 Tg per
year.
2-6
-------
Chapter Summary
Implications of Considering Environmental
Benefits
The analysis of profitable emissions reduction
options does not include the value of the environ-
mental benefits of reducing methane emissions
from natural gas systems. These environmental
benefits include not only the reduction in meth-
ane emissions, but also reductions in VOC emis-
sions from some stages of the system. Although
these benefits may be considerable, the assess-
ment of the profitability of the reduction options is
not very sensitive to their inclusion in the analysis.
For example, using a range of costs of reducing
carbon dioxide build up in the atmosphere of $5
to $100 per ton of carbon, the environmental
benefit of mitigating methane emissions from
natural gas systems translates into a value of
about $0.52 to $10.45 per Mcf.4 These values do
not include the value of reduced VOC emissions.
However, using the highest value still does not
make the non-profitable options profitable.
Barriers to Reducing Methane Emissions
Achieving these potential reductions requires
addressing several barriers to implementation.
These include informational, economic and regu-
latory, and technology cost and availability barri-
ers that limit the current implementation of the
profitable options
Actions to overcome these barriers include
developing programs to assess and publicize the
benefits of these options, removing regulatory
disincentives to reduce methane emissions, and
supporting targeted and coordinated research on
new technologies and practices. For example,
Congress could authorize voluntary emission
reduction programs that provide information on
profitable emission reduction options. Additional-
ly, research and demonstration projects could be
funded.
2.1 BACKGROUND
2.1.1 Methane Emissions from the U.S. Natural Gas System
Methane is the principal component of natural gas, and therefore leaks from the wide
variety of components, processes, and activities that make up the natural gas system
contribute to methane emissions. Methane emissions from the U.S. natural gas system in
1990 are estimated to range from 2.2 to 4.3 Tg per year, with a central estimate of about 3.0
Tg per year (USEPA 1993).5 These emissions estimates are based on analyses of the
activities in each of the major stages of the natural gas system: production; processing;
transmission; storage; and distribution (see Exhibit 2-3).
The majority of the emissions occur in the production, transmission, and distribution
stages, with lesser quantities from gas processing and storage. The emissions associated
with each stage and the major features of the U.S. gas industry used to develop these
emissions are summarized in Exhibit 2-4. Emissions from gas-fired engines, which are used
in all five stages, were estimated separately in USEPA (1993) as shown in Exhibit 2-4.
The estimate of the value of avoiding methane emissions is calculated using the GWP for methane, 22, and the
ratio of the weight of carbon to the weight of carbon dioxide (12/44). See section 2.3.5
While a great deal of progress has been made in quantifying emissions, more work is warranted in some areas.
A joint research program sponsored by the Environmental Protection Agency and the Gas Research Institute (GRI)
is collecting data to improve the emissions estimates.
2-7
-------
Exhibit 2-3
Stages of the U.S. Natural Gas System
Production
T
Transmission
Storage
Gathering
Processing
Distribution
Jl]
Residential Commercial
Industrial Electric
Ut i I i ty
-------
Exhibit 2-4
1 990 Emissions and Major Features of the U.S. Natural Gas System
Stage
Production
Gross Production
Marketed Production
Dry Gas Production
Processing
Volume Processed
Storage
Additions
Withdrawals
Transmission
Gas Transported
Distribution
Gas Delivered
Compressor Engine Exhaust
from all 5 Stages
Pipeline fuel
Production Stage
Processing Stage
Gas Volume8
(Tcf)
21.5
18.6
17.8
14.6
2.5
1.9
20.9
16.8
0.7d
0.2e
0.2f
Infrastructure8
(1990)
269,790 gas wells
44,965 treatment facilities
288,165 oil wells
54,250 heaters0
180,653 separators0
19,776 gas dehydrators0
89,500 miles of gathering pipeline
734 gas processing plants
6,603 gas dehydrators0
397 storage pools with a capacity
of 7.8 Tcf
280,100 miles of pipeline
6,097 gas dehydrators0
836,700 miles of main pipes
474,038 miles of service pipes
3,713 gate stations'3
16.5 million horsepower
Total Emissions
1990 Emissions'*
(Tg/yr)
0.69- 1.82
0.04 - 0.27
0.01 - 0.06
0.59 - 2.06
0.17 - 0.75
0.27 - 0.64
2.18 - 4.26
a Sources for gas volume and infrastructure data are DOE (1991) and AGA (1991b) unless noted otherwise.
b USEPA (1993).
c Cowgill (1992).
d Fuel use for compressor engines used in the transmission, storage, and distribution stages (USEPA 1993).
e Fuel use for compressor engines used in the production stage (USEPA 1993).
f Fuel use for compressor engines used in the processing stage (USEPA 1993).
Tcf = trillion cubic feet.
The emission estimates are largely based on studies performed during the past
several years, which have greatly improved the previously limited information available on
emissions from the various stages of the system. These studies include: engineering
analyses of model facilities; case studies of facility operations; detailed studies of gas
reported as "unaccounted for" by two major distribution systems; systematic measurements of
fugitive emissions from oil and gas production and processing facilities; and a limited number
of measurements from distribution system components. These studies have examined
methane emissions from unintentional leaks (fugitive emissions), normal operation of various
devices, routine maintenance activities, and unplanned system upsets. The major sources
2-9
-------
within each stage are discussed in turn
below.
Natural Gas Production
Natural gas is produced either as
Methane errosssms Iroro the U.S. natural
gas system $ti 1990 are estimated to range
from 2>2 to 4*3 Tg per year, with a central
estimate of about 3,0 Tg per year. Tde
majority of tfce emissions occur in ihe
There were approximately 269,790 gas wells y
and 288,165 oil wells producing gas for
commercial sale in the U.S. in 1990 (USEPA
1993). The gas is collected from these wells using a network of gathering lines, and is
usually run through a field separator and related treatment facilities to remove water, acid gas,
other hydrocarbons (condensate), and particulates. After field separation, the gas usually
proceeds to a gas processing plant. In special circumstances, the gas is injected directly into
the transmission system following field separation.
Total 1990 methane emissions from the production of natural gas are estimated to be
about 0.7 to 1.8 Tg/yr, with a central estimate of 1.08 Tg/yr (USEPA 1993). These emissions
account for roughly 35 percent of methane emissions from the U.S. gas system in 1990. Over
70 percent of the total methane emissions from the production stage are accounted for by the
following three sources:
Fugitive Emissions from Wellsite Equipment. Fugitive emissions are
unintentional and usually continuous releases associated with leaks caused by
the failure of the integrity of the system, such as a damaged seal, or a
corrosion pit leading to a pinhole leak in a pipeline. While fugitive emissions
occur throughout production sites, wellsite equipment accounts for the majority
of these emissions. Thus, wellhead equipment and field treatment facilities at
gas wells are estimated to emit 0.23 Tg per year.
• High-Bleed Pneumatic Devices. Pneumatic devices are used on gathering
lines, heaters, separators, and dehydrators as valve controllers, valve actuators,
pressure regulators, and pressure transmitters. Pneumatic devices operate by
using gas pressure to drive their operating mechanisms. Because the
pressurized gas stream in the pipeline is a convenient source of pressurized
gas, most pneumatic devices use the pipeline as their source of pressurized
gas. High-bleed pneumatic devices are designed to use a significant amount
of pressurized gas, which is then emitted.
Total emissions from pneumatic devices in the production segment in 1990
were estimated to be 0.43 Tg per year (USEPA 1993). According to Radian
(1992b), about 25 percent of pneumatic devices on field equipment and all
pneumatic devices along gathering lines are "high-bleed" designs. These high-
bleed devices are estimated to account for about 0.37 Tg of the 1990 pneumat-
ic device emissions.
• Dehvdrators. Dehydrators are used throughout the natural gas production
stage to remove water vapor and liquid hydrocarbons from natural gas. This
process involves bringing the gas into contact with a desiccant, most often
glycol, which absorbs the water. The desiccant is then regenerated, usually
2-10
-------
through heating, which releases the water as steam. Because some methane
is absorbed in the glycol as well, this process also releases methane (and
other hydrocarbons) to the atmosphere. Dehydrators are estimated to emit
about 0.11 Tg per year.
Natural Gas Processing
Gas processing plants remove from the gas stream heavier hydrocarbons (referred to
as condensate) and moisture, and may also remove sulfur compounds, particulates, and
carbon dioxide. After processing, the natural gas is injected into the transmission system.
Total methane emissions from the processing stage are estimated to be about 0.04 to
0.27 Tg per year, with a central estimate of 0.09 Tg per year, or roughly 3 percent of methane
emissions from U.S. natural gas systems. Dehydrator venting accounts for roughly 0.04 Tg of
emissions.
Natural Gas Storage
Storage facilities are used to respond to seasonal fluctuations in demand. During
periods of low demand, gas is injected into underground storage reservoirs. During periods
of high demand, stored gas is withdrawn, processed to remove any water and particulates,
and injected into the gas system.
Methane emissions from storage facilities in the U.S. are estimated to be about 0.01 to
0.06 Tg per year, with a central estimate of 0.02 Tg per year (USEPA 1993). These emissions
represent only a small percentage of total methane emissions from U.S. natural gas system
because only a relatively small volume of gas, about 10 percent of annual natural gas
production, is injected and withdrawn from storage in the United States (DOE 1991).
Natural Gas Transmission
The transmission system is a network of high pressure pipelines used to transport the
gas from production, processing, and storage facilities to high-volume customers and
distribution networks. In addition to pipelines, transmission systems include various surface
facilities such as pressure regulation, metering, and compressor stations.
Emissions from the transmission stage of the industry in 1990 (excluding engine
exhaust) are estimated to be about 0.6 to 2.1 Tg per year, with a central estimate of 1.04 Tg
per year (USEPA 1993). These emissions are over one third of methane emissions from U.S.
natural gas systems. Three major sources account for over 70 percent of these emissions:
Fugitive Emissions from Compressor Stations. Compressor stations have a
large number of components and joints which are susceptible to unintentional
leakage. Moreover, because compressors contain many moving parts operat-
ing under high pressure, seals at these facilities have relatively high failure
rates (compared to static seas). Fugitive emissions from compressor stations
in 1990 were estimated to be about 0.33 Tg, or about 75 percent of all fugitive
emissions from the transmission stage (USEPA 1993).
High-Bleed Pneumatics Devices. As in the production stage, pneumatic
devices are used to control the flow of gas. The routine use of these devices
2-11
-------
is estimated to emit 0.20 Tg per year in the transmission stage (USEPA 1993).
Virtually 100 percent of the pneumatic devices in this stage are high-bleed
(Radian 1992b).
• Pipeline Maintenance. The routine maintenance of transmission pipelines and
surface facilities often requires evacuation of the pipeline section under repair.
In particular, repairing damaged or corroded pipe requires cutting out the
damaged section and welding new pipe in place. The purged gas is typically
vented to the atmosphere, emitting an estimated 0.22 Tg in 1990 (USEPA
1993).
Natural Gas Distribution
The distribution network is an extensive system of pipelines supplying natural gas to
end users. The pipelines are generally of smaller diameter and operate at lower pressures
than transmission pipelines. Natural gas entering the distribution network from transmission
pipelines generally pass through metering and pressure regulating facilities known as gate
stations (AGA 1991b). When gas is transferred from the distribution system to customers, the
gas also flows through metering and pressure regulating devices, although these are
generally much smaller and less complex than the gate station facilities. To maintain proper
operating conditions, pressure regulating devices are also used throughout the distribution
system.
In 1990 methane emissions from the distribution stage were estimated to be about
0.17 to 0.75 Tg per year, with a central estimate of 0.33 Tg per year (USEPA 1993). These
emissions account for about 11 percent of total gas system emissions. Nearly 90 percent of
emissions from distribution networks come from two major sources:
• Fugitive Emissions from Subsurface Piping. Distribution networks are typically
comprised of steel and plastic pipes, with some older systems having cast iron
pipes as well. Leakage primarily occurs from failed seals between cast iron
pipe joints and corroded steel pipe. The increasing use of plastic pipe is
reducing emissions from this source because plastic pipe is not subject to
corrosion. It is estimated that 0.17 Tg of methane was emitted in 1990 from
this source (USEPA 1993).
Fugitive Emissions from Gate Stations. Gate stations contain a relatively large
number of components and joints. Fugitive emissions from these facilities is
estimated to be 0.12 Tg per year in 1990 (USEPA 1993).
Compressor Engine Exhaust
Gas fired compressor engines are used throughout the entire gas industry. These
engines emit methane in their exhaust as the result of incomplete combustion of the gas fuel.
Reciprocating engines are the primary source of engine exhaust emissions, accounting for
over 95 percent of total methane emissions from this source. Although large turbine engines
are used extensively throughout the transmission stage of the U.S. system, these engines do
not contribute significantly to compressor exhaust emissions because turbines have very low
methane emission factors.
2-12
-------
To estimate emissions, USEPA (1993) estimated the amount of fuel used in reciprocat-
ing and turbine engines in each stage of the industry. Total emissions in 1990 are estimated
to be 0.3 to 0.6 Tg per year, with a central estimate of 0.42 Tg per year (USEPA 1993). The
emissions estimated by stage are as follows (USEPA 1993):
Production: 0.09 Tg;
• Processing: 0.11 Tg;
• Transmission: 0.18 Tg; and
• Storage and Distribution: 0.04 Tg.
The transmission stage is the largest source of these emissions. It is estimated that
69 percent of compressor engine horsepower is provided by reciprocating engines in this
stage (Jones 1992). As a contrast, virtually all the compressor engines used in the produc-
tion and processing stages are reciprocating engines (USEPA 1993).
2.1.2 Future Methane Emissions
Natural gas use is expected to in-
crease in the U.S. over the next two de-
cades and emissions of methane are ex-
pected to increase as a result. Assuming
Future emissions are
more slowly &ian ihe growth in eon)
sutnptssrv because many
depend OR te size
that the system will continue to operate
using current practices, USEPA (1993) esti-
mated methane emissions for 2000 and
2010 under three different demand scenarios. The range of the three demand scenarios
indicates that U.S. natural gas consumption could increase from 16.8 Tcf in 1990 to a range
of 20.2 to 22.3 Tcf in 2000 and 19.9 to 24.6 Tcf in 2010.
Methane emissions are not expected to rise proportionally with rising natural gas
consumption (USEPA 1993). This is mainly due to the fact that many emissions (e.g., fugitive
emissions) are more dependent on the size of the infrastructure (e.g., number of gate stations
or miles of pipeline) than on the volume of gas consumption. Because the size of the
infrastructure is expected to grow more slowly than the growth in consumption, emissions are
also expected to grow more slowly. Exhibit 2-5 summarizes the future emissions estimates.
As shown in the exhibit, total natural gas consumption is estimated to increase by 20
to 33 percent from 1990 to 2000, while emissions are estimated to increase by 11 to 18
percent. Similarly, natural gas consumption is estimated to grow by 18 to 46 percent above
1990 levels by 2010, while methane emissions are estimated to rise by about 12 to 26
percent.
2.2 OVERVIEW OF OPTIONS FOR REDUCING EMISSIONS
Cost effective technologies and practices exist that can reduce methane emissions
from natural gas systems. Many of these technologies and practices are already used to
some extent within the U.S. natural gas industry. In addition, existing technologies are
continually being improved, and several promising new technologies are under development.
2-13
-------
Exhibit 2-5
Future Methane Emissions from the U.S. Natural Gas System
Stage
Production
Processing
Storage
Transmission
Distribution
Engine Ex-
haust
Total
Total
1990
1.08
0.09
0.02
1.04
0.33
0.41
2.97
(2.18-4.26)
: Pr<^Boted«elhar»&*»ta«$onsfF^r) j
2000
Low
1.24
0.10
0.02
1.10
0.35
0.49
3.30
(2.43-4.74)
:::r.;.;: "• . ; Y Projwi
16.8
20.2
Base
1.30
0.10
0.02
1.10
0.35
0.51
3.38
(2.48-4.85)
High
1.37
0.10
0.03
1.10
0.35
0.54
3.49
(2.56-5.00)
ittd'iiijHttuMti'&Mtft ftanttiMftBtfatt M
21.1
22.3
2010
Low
1.22
0.09
0.02
1.15
0.37
0.48
3.33
(2.45-4.78)
Base
1.33
0.10
0.03
1.15
0.37
0.52
3.50
(2.57-5.02)
r^r^'y:-- --:.:-:.
19.9
21.9
High
1.49
0.11
0.03
1.16
0.37
0.59
3.75
(2.75-5.38)
24.6
Emissions estimated in USEPA (1993). Low, Base, and High Energy Demand Scenarios based on AGA (1990) and AGA
(1991 a) as follows:
Low Case: Strict energy conservation measures put into effect and environmental measures such as "sulfur tax" taken to
curb sulfur dioxide emissions and 'carbon tax" to reduce carbon dioxide emissions.
Base Case: Business as usual scenario.
High Case: Same environmental policies as low case, but with 50% less energy conservation.
This analysis focuses on eight techniques for reducing emissions in the three stages
of the natural gas system that account for the majority of emissions: production;
transmission; and distribution. Exhibit 2-6 summarizes the techniques, including the extent to
which each can reduce emissions. For each of these options, the following sections present
information on the costs of implementing the option, the anticipated reductions in methane
emissions to the atmosphere, and the associated potential gas savings. In addition to
reducing methane emissions, these options also result in other benefits such as improved
system safety and reduced emissions of volatile organic compounds (VOCs), which
contribute to tropospheric ozone formation, and in some cases are human health hazards.
This section concludes with a brief discussion of a number of emerging technologies
for reducing emissions. These approaches, which are in the development stage, may provide
additional future opportunities for reducing methane emissions from the natural gas system.
2.2.1 Production Facility Options
There are three major options for reducing methane emissions from natural gas
production facilities:
• Replacing high-bleed pneumatic devices;
2-14
-------
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• Installing flash tank separators on dehydrators; and
• Implementing directed inspection and maintenance (I/M) programs at gas wells
and treatment facilities.
Replacing "High-Bleed" Pneumatics
Natural gas-operated or pneumatic devices are used throughout production facilities
on gathering lines, heaters, separators, and glycol dehydrators to monitor and control the
flow of gas. Pneumatic devices include valve controllers, valve actuators, pressure regulators,
and pressure transmitters, as well as flow computers and gas samplers.
Pneumatic devices operate by using gas pressure to drive their operating
mechanisms. Because the pressurized gas stream in the pipeline is a convenient source of
pressurized gas, most pneumatic devices use the pipeline as their source of pressurized gas.
High-bleed pneumatic devices are designed to use a significant amount of pressurized gas,
which is then emitted. Devices with emissions or "bleed" rates of 0.1 to 0.5 cubic feet per
minute (ft3/min) are considered to be "high bleed" types (PG&E 1990).
One option for reducing emissions is to use an alternative source of pressurized gas
to operate the device. In circumstances where compressed air is available, this technique is
often used as a means of saving gas. In most situations, however, providing compressed air
is not cost effective.
The most cost effective technique for reducing the emissions from high-bleed
pneumatic devices is to replace high-bleed pneumatics with lower bleed designs at the end of
their service life (generally seven years) where technically feasible. A number of designs exist
which either bleed significantly less gas or do not emit gas at all. Exhibit 2-7 shows examples
of bleed rates from high and low-bleed devices. The costs and benefits of replacing the
devices in this manner are as follows:
• Benefits. Radian (1992b) estimates that the emissions from the average high-
bleed pneumatic device can be reduced by an average of 70 percent per
device, with no loss Jn performance. Given that high-bleed devices emit
77 Mcf/yr of gas on average, this 70 percent control efficiency would save
54 Mcf/yr per device (Radian 1992b). This saved gas has a value of roughly
$85, using a conservative wellhead price of $1.59/Mcf (DOE 1992). These
benefits estimates are conservative relative to the example estimates of emis-
sions and potential emission reductions summarized in Exhibit 2-7.
• Costs. High-bleed and low-bleed devices have similar installation costs of
about $100 each and similar operating and maintenance costs. The average
low- or no-bleed version of a pneumatic device costs about $1,000, which is
about 20 percent more than a high-bleed version of the same device. The only
incremental cost of implementing this option, therefore, is an additional capital
expense of about $167 per device (Radian 1992b).
2-16
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Exhibit 2-7
Example Pneumatic Device Bleed Rates
Device
Valve Positioner
Valve Actuator
Gas Supply Regulator
Bleed Rates (ft3/minute)
High-Bleed
0.628
0.085
0.268
Low-Lleed
0.0283
0.0113
0.0064
Reduction
0.5997 (95%)
0.0737 (87%)
0.261 6 (98%)
Sources: Tilkicioglu (1990) and PG&E (1990).
Not all high-bleed devices can be replaced with lower bleed devices. Because the
response time of the control device is directly related to the rate of venting, there are some
situations where a high-bleed device is necessary for the effective operation of the production
unit (Harrison 1992). Studies conducted by the U.S. gas industry have shown that there are
numerous opportunities for replacing high-bleed devices (PG&E 1990), and it is estimated that
80 percent of the high bleed devices can be replaced with low bleed devices.
Installing Flash Tank Separators on Dehydrators
Dehydrators are used throughout the production stage to remove water from natural
gas in order to prevent the formation of hydrate slugs in pipelines and to reduce corrosion.
Dehydrators work by bringing the gas into contact with a desiccant, usually glycol, which
absorbs the water from the gas. When the desiccant becomes saturated, it is removed to a
regenerating unit, where it is heated to drive off the absorbed water. The desiccant usually
contains quantities of absorbed methane and VOCs, which are also driven off and subse-
quently vented to the atmosphere.
Several states have initiated programs to .control air toxic emissions from glycol
regeneration at dehydration units.6 In Oklahoma, as part of their emission inventory, all
emissions from glycol dehydrators located after lease custody transfer must be evaluated and
reported annually. Compliance is to be maintained with the maximum acceptable ambient
concentration (MAAC) standards developed under the rule. Air toxics emissions are
considered during the permitting of new sources, and existing sources are evaluated based
on the data submitted in their emissions inventories (Pees and Cook 1992).
In Louisiana, hydrocarbon emissions associated with glycol dehydration units can be
controlled under two regulations: the Waste Gas Disposal Rule and the Air Toxics Program.
These regulations establish a permissible ceiling for the emissions of hydrocarbon air
The principal air toxics of concern are benzene, toluene, ethyl benzene and xylene isomers, collectively
referred to as BTEX.
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In response to state initiatives to reduce air emissions from glycol regeneration at
dehydration units, a variety of techniques have been explored for capturing and combusting
the vapors vented during glycol regeneration. The most cost effective technique identified for
most dehydrator designs is to install a flash tank separator (FTS) on the glycol line between
the water absorption step and the regenerating process. The FTS prevents the light hydro-
carbons, including methane, from reaching the regenerating unit, substantially reducing the
volume of light hydrocarbons vented from the dehydrator.
The FTS removes methane absorbed in the desiccant by rapidly reducing the pressure
(e.g., from 800 to 900 psi, down to 50 to 100 psi), causing most of the dissolved methane to
"flash" out of solution (back into a gaseous state). The methane gas is then recovered from
the FTS and used as boiler fuel in the regenerating unit. Installing flash tank separators on
dehydrators would have the following costs and benefits:
Benefits. Recovering methane from the desiccant in an FTS and using it as
boiler fuel can reduce methane emissions from a dehydrator by about 90
percent. Furthermore, this option can replace significant quantities of fuel used
in the regenerating unit (Radian 1992b). The average dehydrator unit vents
some 5.57 Mg or 290 Mcf of gas per year during desiccant regeneration
(Radian 1992c). Given a 90 percent control efficiency, an FTS could reduce
the vented methane by some 260 Mcf per dehydrator. Using this gas as fuel
would save about $410 per year, assuming a price of $1.59/Mcf (DOE 1992).
• Costs. The equipment costs for an FTS are about $3,000 on average.
Installation of a flash tank requires 48 man hours. Assuming a wage rate of
$25 per hour, the total installation costs are about $1,200. Operating and
maintenance costs are about $60 per year, over a lifetime of about 15 years
(Radian 1992b).
These estimates of the gas saved using an FTS are likely understated because the
model facility used to derive these values was relatively small. Installing an FTS on larger
dehydrators results in significantly larger amounts of gas saved without significantly
increasing the installed cost for the device.
Implementing Directed Inspection and Maintenance Programs at Gas Well Sites
Production "wellsites" generally consist of the wellhead and associated treatment
equipment such as heaters, gas/liquid separators, and dehydrators. Components such as
valves, flanges, and instruments are used to control and monitor gas flowing through the
system and to connect the various pieces of equipment together. Over time, heat, pressure,
moisture, contaminants, and general wear can cause leaks to develop in some of these
components. Exhibit 2-8 shows where leaks typically develop in gate valves.
Fugitive emissions (unintentional leaks from components) from gas wellsites can be
substantially reduced through directed inspection and maintenance (I/M) programs. In such a
program, a facility routinely inspects those components most likely to develop leaks with
sensitive leak detection equipment. Leaking components are identified, and then repaired or
replaced. Components are screened for leaks periodically to ensure a successful reduction
in the volume of fugitive emissions.
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Exhibit 2-8
Possible Leak Areas in a Gate Valve
vaiv« sum
Packing Gland , „ Po..lb««
L«ak Ar«a
Packing
Source: USEPA(1983).
Directed I/M programs have been implemented at oil and gas production and
processing facilities, chemical plants, and pipeline transfer stations in several air pollution
control and air quality management districts in California. By implementing directed I/M
programs, these facilities have reduced VOC emissions by about 40 to 70 percent. The cost
effectiveness for controlling fugitive VOC emissions in California is estimated to be about
$3.70 (in 1989 dollars) per pound of emissions reduced (ARB 1991).
The various California directed I/M programs have been designed with similar
requirements. The programs typically require a facility to inspect all accessible components
once every three months and all inaccessible components once every year. The inspection
frequency of pumps, compressors, and pressure relief valves varies among programs from
once every 8 hours to daily or weekly inspections. To inspect components for leaks, a
hydrocarbon analyzer such as an Organic Vapor Analyzer (OVA) is used to measure the
concentration of hydrocarbons close to the component. A reading greater than a specified
threshold value (usually 10,000 ppm) indicates that the component is leaking.
Leaking components must be repaired or replaced within a specified time period
(typically 1 day to 3 weeks) which varies among districts and by component type and rate of
emissions. After a component is repaired, it is re-inspected to verify that the component is no
longer leaking. Re-inspection typically is required within 1 week to 3 months. In addition,
directed I/M programs typically require facilities to physically identify all components and tag
leaking components. Records of components, inspections, leaks, and repairs must also be
maintained (ARB 1991).
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To further reduce fugitive VOC emissions in the state, the California Air Resources
Board (ARB) has proposed a set of requirements for directed I/M programs. The ARB
proposal is generally comprised of the more stringent requirements of existing directed I/M
programs. For example, the proposal recommends that pumps, compressors, and pressure
relief valves should be inspected once every 8 hours at oil and gas processing facilities and
chemical plants and once every 24 hours at other facilities. If the ARB recommendations
were adopted by all districts in the state, directed I/M programs could reduce fugitive VOC
emissions by about 80 percent, for a net incremental emission reduction from current
programs of about 25 percent (ARB 1991).
Directed I/M programs could be implemented more widely to reduce methane
emissions from gas production wellsites. Implementing directed I/M programs at production
wellsites would have the following costs and benefits:
Benefits. An average gas wellsite (wellhead and associated treatment
equipment) in the U.S. emits about 45 Mcf/yr of methane (USEPA 1993).
Radian (1992b) estimates that directed I/M programs can reduce these
methane emissions by 70 percent. As a result, 32 Mcf of gas would be saved
per wellsite on average each year, which would have a value of $50 per wellsite
at a wellhead price of $1.59/Mcf (DOE 1992).
• Costs. Directed I/M programs involve substantial costs. The costs of such
programs can be broken down into the following areas:
Screening Equipment Purchase Costs.7 Screening equipment primarily
consists of organic vapor analyzers (OVAs), which cost about $4,000 to
$9,000, with an average of $6,600 per unit. It is estimated that on
average, an analyzer can be used to screen 27,000 components per
quarter (i.e., per three month period). A typical gas wellsite is estimated
to have about 300 components (Tilkicioglu and Winters 1989).
Therefore, one analyzer could be used to screen components at 90
wellsites over the course of a quarter (27,000 + 300 = 90). However,
because wellsites are often areally dispersed, Radian (1992b) increased
the time required to screen component by 50 percent, so that the
estimate of the number of wellsites that could be screened with an OVA
in a quarter is reduced to 60 (27,000 •*• 300 + 1.5 = 60). OVAs are
estimated to last 4 years.
Screening Equipment Operating & Maintenance Costs. An average
screening equipment unit will have annual operating expenses (repair,
calibration, calibration gas, hydrogen fuel) of $3,000 including labor
costs (Webb 1992; Radian 1992b).
Screening Program Costs. Screening programs are labor-intensive
activities. These costs include the time'required for the screening tests
themselves, the associated recordkeeping, and overhead. Costs will
7 This estimate of screening equipment costs presumes that all new screening equipment is required. This
estimate is biased upward to the extent that existing flame ionization detectors (FIDs) can be used. The industry
currently uses FIDs routinely for conducting leak surveys.
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vary with the compactness of the facility being screened, the extent of
recordkeeping, and the screening interval. Directed I/M programs in
California screen all system components four times per year
(components that are found to be non-leaking through 5 or 6 quarterly
inspections are then inspected annually), and keep complete records
on all screened components (ARB 1991). The annual cost of screening
a typical 300 component wellsite four times a year using a two-person
crew that takes one minute per component is estimated at $1,000
(Radian 1992b). Again, because wellsites are often areally dispersed,
Radian (1992b) increased the time required to screen components at
wellsites by 50 percent, so that the estimate of the screening cost per
wellsite is increased to $1,500 per year.8
Repair Costs. The costs of the screening program also include the
costs of fixing the leaks identified. In some cases the leak can be
stopped by adjusting the component (e.g., tightening a nut). This step
is typically undertaken by the screening crew. If this approach is
unsuccessful, then a qualified repair person must be called in to
overhaul or replace the component (e.g., replace valve packing). Such
repairs involve both labor and material costs. Radian (1992b) estimates
that each quarterly survey of a well is assumed to find about 3 percent
of the components leaking. The time taken to repair a leak by a two
member crew is estimated to be 1.13 hours per leaking component
(Radian 1992b). Given a wage rate of $25 per hour per person the
average repair costs are about $3,050 per year for a gas wellsite
(Radian 1992b).9
The estimated costs of directed I/M programs for gas wellsites are summarized in Exhibit 2-9.
2.2.2 Transmission System Options
There are four major options for reducing methane emissions from natural gas
transmission systems:
• Implementing directed inspection and maintenance programs at compressor
stations;
Replacing high-bleed pneumatic devices;
• Capturing gas released during pipeline repairs; and
Using turbines more frequently for new pipelines.
8 The screening costs are estimated as: 300 components per well site * 60 components per hour x 2 person
crew x $25 per person x 4 times per year x 1.5 adjustment for areal dispersion of the wellsites = $1,500.
9 The repair costs are estimated as follows: 300 components per wellsite x 3 percent leaking x 4 times per
year x 1.13 hours per repair x 2 person crew x $25 per person x 1.5 adjustment for areal dispersion of
wellsites = $3,051.
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Exhibit 2-9
Costs Associated with Directed I/M Programs at Gas Wellsites
Category
Equipment Purchase
Equipment Mainte-
nance
Annual Screening
Cost Per Wellsite
Annual Repair Cost
Per Wellsite
Cost ($)
$6,600
$3,000
$1 ,500
$3,050
Comments
The OVA instrument could be used at 60 wellsites
over the course of a quarter and the costs spread
across the 60 wellsites.
Cost per OVA instrument.
Each wellsite is screened quarterly by a two-person
team costing $25/hr/person.
Each quarterly survey is assumed to find 3 percent of
the components leaking. Repairs are performed by a
two-person team costing $25/hr/person, requiring
about 1 .13 hours per leak repair.
Source: Radian (1992b).
Directed Inspection and Maintenance Programs at Compressor Stations
This option reduces fugitive emissions from compressor stations by implementing
directed I/M programs at these facilities. Compressor stations, which are used to maintain
the gas pressure in high pressure transmission pipelines, contain a large number of compo-
nents. Over time, these components may develop leaks. In particular, packing seals around
the moving parts of compressors and valves are important sources of fugitive methane
emissions (SOCAL 1992).
The most effective approach for reducing these emissions is to implement directed I/M
programs similar to those described for production wellsites. While transmission facilities are
already required by Department of Transportation regulations to be surveyed periodically with
Hydrogen Flame Ionizer instruments to protect public safety, directed I/M programs could
identify leaks which are not a threat to public safety but emit significant quantities of methane
to the atmosphere.
Implementing directed I/M programs at compressor stations is estimated to have the
following costs and benefits:
• Benefits. An average compressor station in the U.S. emits an estimated
12,200 Mcf/yr of methane from fugitive emissions sources (Radian 1992b). A
directed I/M program can reduce these emissions by 70 percent, saving about
8,500 Mcf/yr per station (Radian 1992b). This saved gas has a value of roughly
$17,200 per station, assuming a pipeline gas price of $2.01/Mcf which is the
average price paid by pipeline firms for gas in 1991 (DOE 1992).
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Costs. The costs of directed I/M programs are summarized in Exhibit 2-10, and
include the following:
Screening Equipment Purchase and O&M Costs. Directed I/M programs
will use the same OVA equipment described previously for the I/M
programs at gas wellsites. OVA purchase costs average about $6,600
per unit, and annual operating costs average $3,000 per unit (Webb
1992; Radian 1992b). Given that a typical compressor station has the
equivalent of 1,320 components,10 one analyzer can be used to
screen about 20 compressor stations per quarter (27,000 + 1,320 = 20)
(Radian 1992b).
Screening Program Costs. A two-person crew can screen components
at the rate of one component per minute. At a wage rate of $25 per
hour per person, the annual cost to inspect the 1,320 components of a
compressor station would be about $4,400 per station (Radian 1992b).
The cost estimate includes recordkeeping and other costs as described
previously.
Repair Costs. Each quarterly survey of a compressor station is estimat-
ed to find leaks at about 3 percent of the components. The time taken
to repair a leak by a two member crew is estimated to be 1.13 hours
per leaking component. Given a wage rate of $25 per hour per person,
the average repair costs for a compressor station are about $8,970 per
year (Radian 1992b).
Replacing "High-Bleed" Pneumatics
As in the production stage, significant quantities of methane are emitted from the
normal operation of high-bleed pneumatic devices at transmission facilities. Replacing these
"high-bleed" pneumatic devices with "low-" or "no-bleed" devices where technically and
economically feasible could reduce methane emissions from this source by an average of 70
percent per device (Radian 1992b).
The experience of Pacific Gas and Electric (PG&E) illustrates the system-wide costs
and benefits of swapping out high-bleed pneumatics. During the 1960s, PG&E and other
utilities elected to use natural gas as their source of pressurized gas to operate station
controlling valves. In the 1970s, PG&E experienced a substantial increase in the price of
natural gas. Because natural gas-powered valves, positioners, and controllers had been
designed to regularly bleed or vent gas, these components were prime candidates for new
designs that would limit or eliminate such emissions.
Tilkicioglu and Winters (1989) estimate that a typical compressor station has 1,260 components, including
valves, connectors, flanges, and instruments. Radian (1992b) increases the estimate by 5 percent to 1,320
components to reflect the slight areal dispersion of the components at the compressor station.
2-23
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Exhibit 2-10
Costs of Directed I/M Program at Transmission Pipelines Compressor Stations
Category
Equipment Pur-
chase
Equipment Main-
tenance
Annual Screening
Per Station
Annual Repair
Per Station
Cost ($)
$6,600
$3,000
$4,400
$8,970
Comments
The OVA instrument could be used at 20 compressor
stations over the course of a quarter and the costs
spread across the 20 stations.
Cost per OVA instrument.
Each station is screened quarterly by a two-person
team costing $25/hr/person.
Each quarterly survey is assumed to find 3 percent of
the components leaking. Repairs are performed by a
two-person team costing $25/hr/person, requiring
about 1.13 hours per leak repair.
Source: Radian (1992b).
In 1977, the company began a research project to identify designs that could reduce
or eliminate the venting of gas. Between 1979 and 1985, five demonstration projects were
completed installing these new designs at control stations along PG&E's system. These
projects introduced new designs for valve positioners, 20-psi regulators, gas saver circuits for
monitoring valve operators, electronic control loops, and low-bleed instrumentation.
Between 1979 and 1985, these applications have reduced emissions from pneumatic
devices by 96,406 Mcf. Over the period from 1986 to 1995, continuing installation of these
new devices is expected to save a further 810,060 Mcf, for a total savings of 906,466 Mcf.
Based on actual and projected PG&E average gas fuel expense, the total savings are
estimated to be more than $4 million (PG&E 1986).
In general, replacing high-bleed pneumatic devices with lower bleed designs can have
the following benefits and costs:
Benefits. The average high-bleed pneumatic device vents about 77 Mcf/yr of
gas. With an emissions control efficiency of 70 percent, the replacement of a
high-bleed with a low-bleed device would save some 54 Mcf/yr per pneumatic
device (Radian 1992b). This saved gas has a value of $110 at a pipeline price
of $2.01/Mcf (DOE 1992).
Costs. As described earlier for the production stage, high-bleed and low-bleed
devices have similar installation costs of about $100 and similar operating and
maintenance costs. The average low- or no-bleed version of a pneumatic
device costs about $1,000, which is about 20 percent more than a high-bleed
version of the same device. The only incremental cost of implementing this
2-24
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option, therefore, is an additional capital expense of about $167 per device.
(Radian 1S92b).
Capturing Gas Released During Pipeline Repairs
Routine maintenance work on transmission pipelines requires the removal of gas from
the pipeline section under repair to ensure safe welding conditions. In the U.S., this removal
of gas is usually accomplished by closing off a segment of transmission line, allowing local
users to draw on the enclosed volume to reduce the pressure, and venting the remaining gas
to the atmosphere. Since shut-off valves can be up to 15 miles apart, an extensive section of
pipe is often vented, and a significant volume of gas released.
Except where there is a very limited time for removing the gas from the pipeline (e.g.,
during peak demand conditions), the gas which would otherwise be vented from the section
under repair can be pumped into an adjoining section of pipe using a portable evacuation
compressor (PEC). This technique can reduce the amount of vented gas by about 80
percent.11
PEC units typically consist of a centrifugal compressor driven by a natural gas
powered turbine. These components, along with auxiliary equipment such as coolers,
scrubbers, and electric generators, are mounted on a standard trailer. A support truck carries
the necessary pipe and fittings to tie-in the compressor unit to the pipeline. Through a series
of adapters, such a unit can be coupled to pipelines with diameters ranging from 10 to 42
inches. A 3 to 4 person crew is needed to transport, set-up, and operate the unit. A typical
operation, evacuating a 20 mile section of 30 inch pipeline at 800 psi down to a pressure of
160 psi, takes approximately 10 hours. Setup and disassembly usually requires four hours.
PEC units have been used profitably in Canada by the Alberta Gas Transmission
Division of NOVA corporation, which operates 8,415 miles of gathering and transmission
pipeline ranging in size from 4 to 42 inches. In 1984, Alberta Gas handled 2.0 Tcf of gas,
much of it exported to the U.S. After a careful examination of line blowdown practices, vented
gas volumes, and the economics of purchasing equipment to save the gas, the firm decided
to purchase and deploy two portable evacuation compressor units. With one unit based in
Calgary and the other in Edmonton, the units can normally travel to any part of the NOVA
system in 2 to 10 hours.
The first unit was purchased for $4.2 million and entered service in November of 1979.
This unit was a Norwalk Turbo V-308C eight-stage centrifugal compressor driven directly by a
4000-hp AVCO-Lycoming gas turbine engine. The performance and gas savings of the first
unit exceeded expectations, and a second unit was brought on in May 1983 to provide
greater reliability, flexibility, and improved service. The second unit was built around the same
compressor but was driven by a 5,200-hp GE LM500 turbine engine. The second unit cost
$5.6 million. In addition to capital costs, operating costs (e.g., fuel and labor costs) can be
substantial, depending primarily on the size and length of pipeline to be evacuated.
1 Most units in operation have a compression ratio of 5:1, which limits the amount of gas that can be
captured to around 80 percent. That is, the pressure in the evacuated section can only be reduced to 1/5 of that in
the adjoining section, leaving the remaining 20 percent of the gas to be vented prior to maintenance.
2-25
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The units have been deployed an average of 25 times a year. Gas savings averaged
about 26 MMcf per blowdown from 1979 through 1984. Operating the two portable evacua-
tion compressor units has saved Alberta Gas a total of 3.2 bcf of gas from 1979 through
1984. During this same period, total net economic savings of $8.1 million were accrued
(Katemisz1985).
In general, capturing the gas released for pipeline repairs can have the following
benefits and costs:
Benefits. Total U.S. emissions from blowdowns in 1990 were about 0.22 Tg, or
about 11.7 bcf of natural gas (USEPA 1993). PECs could recover about 80
percent of the gas emitted per blowdown, for a maximum recovery of about
9.3 bcf per year. At a price of $2.01/Mcf (DOE 1992), the maximum value of
the saved gas would be approximately $18.8 million per year. It is unlikely that
this level of recovery could be achieved, however, because the PECs could
only be deployed at blowdowns that are scheduled in advance. Most
blowdowns are performed on an as-needed basis as the result of system
problems, such as emergency leak repair requirements.
• Costs. The costs associated with a PEC are substantial. A typical PEC unit
costs $5 million to purchase and mount. Operation and maintenance costs for
the fuel and labor are typically $7,800 per blowdown (Radian 1992b). PEC
units are expected to have a lifetime of about 15 years. The number of PECs
required to cover the U.S. natural gas system has not been estimated. The
Alberta Gas Transmission Division program has one PEC per 4,200 miles of
pipeline. Using this rate, approximately 67 PECs would be required to cover
the 280,000 miles of transmission pipeline in the U.S. Given the density of the
pipeline system throughout Texas, Louisiana, and the mid-west, fewer PECs
could probably be used to cover a substantial portion of the U.S. system.
Greater Use of Turbines in New Pipelines and When Retiring Reciprocators
The compressors used to maintain gas pressure in the natural gas system are driven
either by reciprocating engines or turbines. Currently, reciprocating engines provide 69
percent of the total 16.5 million hp in the transmission, storage, and distribution stages of the
U.S. natural gas industry, and turbines provide the remaining 31 percent (Jones 1992). About
83 percent of this compressor horsepower (13.7 million hp) is used in the transmission
system, with the rest used at storage facilities and in distribution networks (AGA 1991b).
Reciprocating engines are a significant source of methane emissions, which result
from incomplete combustion of the natural gas used to fuel the engine. Alternatively, the
emissions rate for turbines is at least an order of magnitude lower than the emissions factor
for reciprocating engines. For example, reciprocating engines emit an average of 500 kg of
methane per MMcf (million cubic feet) of fuel used, whereas turbines emit an average of only
9 kg of methane per MMcf used (USEPA 1993). Designing new transmission pipelines to use
turbines as opposed to reciprocating engines and replacing retiring reciprocating engines
with turbines would greatly reduce methane emissions from this source.
The decision to install reciprocating engines or turbines depends on economic
considerations, as well as site-specific and system-wide operational and technical factors.
While turbines cannot replace reciprocating engines in all transmission pipeline applications,
2-26
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using turbines is technically advantageous in several respects. Turbines are particularly
suitable where the transmission system work load is stable and relatively large. Gas turbines
are also environmentally advantageous with regards to NOX emissions. Despite their many
advantages, however, turbines use more fuel than reciprocators (though emitting less
methane per volume of fuel used). In addition, reciprocators operate more effectively at
partial loads than turbines, and only reciprocators can develop the high compression ratios
required for some transmission operations (Eberle 1992). Overall, it is estimated that turbines
are technically and operationally suitable candidates for 80 percent of new transmission
pipeline prime mover capacity in the U.S., including both new systems and the replacement of
old units.
When considering replacement of reciprocating engines with turbines, the
configuration of the existing compressor station must also be examined. Because the optimal
unit sizes are different for turbines and reciprocating engines, replacing a reciprocating
engine does not necessarily entail a one for one swap of individual engine units. Additionally,
a reconfiguration of the overall compressor station layout may be required, including the
location and design of piping and cooling systems. The cost of reconfiguration should be
weighed against related efficiency gains associated with a new configuration. These factors,
in addition to the work load requirements and any environmental regulations on air pollution
emissions, must be considered when selecting prime movers.
Using turbines in place of reciprocating engines would have the following costs and
benefits:
Benefits. The principal benefit of using turbine engines as opposed to
reciprocating engines is reduced emissions of methane and other pollutants.
Exhibit 2-11 compares the methane emissions from turbine- and reciprocator-
powered compressor stations with comparable capacity. Economic and
operational improvements due to the use of turbines may also be realized on a
case specific basis.
• Costs. The major costs associated with installing and operating new
compressor prime movers are equipment costs, operating and maintenance
costs, and fuel costs. In general, turbine engines have lower capital,
maintenance, and operating costs than reciprocators. However, they tend to
require more fuel than reciprocating engines, especially over a 30 year lifetime
(Shaw 1981; AGA 1985). The capital costs of installing a turbine are about
$186 per hp lower than the capital costs of a reciprocating engine (Shaw
1981). Also, the annual operating and maintenance costs are $25 per hp lower
for a turbine (Shaw 1981). The fuel use for reciprocators is estimated at
71.1 Mcf per hp per year, while the fuel use for turbines is estimated at
89.4 Mcf per hp per year (Jones 1992). At a price of $2.01/Mcf (DOE 1992),
the annual fuel costs are, therefore, $36 per hp higher for a turbine. These
costs are shown in Exhibit 2-12.
2.2.3 Distribution Network Options
Methane emissions from natural gas distribution networks can be reduced by
implementing directed inspection and maintenance programs and by rehabilitating leaky
pipelines. The continued rehabilitation of leaky pipeline is included in the baseline emissions
2-27
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estimates (USEPA 1993). Consequently, accelerated replacement would be required to
realize incremental emissions reduction.
Exhibit 2-11
Methane Emissions from Two Compressor Station Designs
Existing Compressor Station Built Around Reeiprocators
Engines
5 2000 hp reciprocators
3 1000 hp turbines
Total
Hp-Hrs/Yr
(millions)
74.5
18.5
93
Fuel Use
(MMcf/yr)
524
155
788
Methane
Emissions
(Mg/yr)
267
1
268
New Compressor Station BuBt Around Turbines
2 5800 hp turbines
Total
93
93
778
778
7
7
In this example, new turbines are being compared with a mix of reciprocators and turbines
in an existing compressor station. Although the fuel use per horsepower-hour of the new
turbines is about equal to the fuel use of the existing reciprocators, new reciprocators are
more fuel efficient than new turbines. Consequently, a new compressor station built
around reciprocators would use less fuel than a new compressor station built around
turbines.
Sources: Adapted from Erickson (1991) and Erickson (1993).
Exhibit 2-1 2
Incremental Costs of Turbines vs. Reciprocating Engines
Category
Capital Investment
1 st Year Operating & Maintenance
Annual Fuel Costs (@ $2/Mcf)
Incremental Costs ($/hp)
-$186
-$25
+ $36a
a Based on increased fuel use per hp of 1 8.3 Mcf.
Source: Radian (1992).
2-28
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Directed Inspection and Maintenance Programs
As with facilities in the production and transmission stages, above ground or "surface"
facilities in distribution networks are important sources of fugitive methane emissions. Gate
stations, where high-pressure gas from transmission companies is received into the distribu-
tion network, are the surface facilities that exhibit the highest levels of fugitive emissions
(McManus et al. 1992).
The most effective approach for reducing these emissions is to implement directed
inspection and maintenance (I/M) programs. While leak surveys of distribution facilities are
presently required by Department of Transportation regulations and state public utility
commissions (PUCs), supplementation with directed I/M programs at gate stations may
greatly reduce fugitive methane emissions to the atmosphere.
In general, implementing directed inspection and maintenance programs at gate
stations can have the following benefits and costs:
• Benefits. An average gate station emits almost 1,667 Mcf/yr of methane into
the atmosphere (McManus et al. 1992). A directed I/M program with an
effectiveness of 70 percent could annually save almost 1,167 Mcf per station
on average, which would have a value of about $3,400 per station at a city
gate gas price of $2.91/Mcf (DOE 1992).
• Costs. The costs of directed I/M programs are summarized in Exhibit 2-13, and
include the following:
Screening Equipment Costs. Directed I/M programs at gate stations will
use the same type of OVA equipment used for I/M programs in the
production and transmission stages. The capital cost averages about
$6,600 per analyzer (Webb 1992; Radian 1992b), and annual mainte-
nance costs are about $3,000. Based on an average of 150 compo-
nents per station (McManus et al. 1992), an analyzer can be used to
screen about 120 gate stations per quarter.12
Screening Program Costs. A two-person crew can screen components
at the rate of one component per minute. At a wage rate of
$25/hour/person, the annual cost to inspect the 150 components of a
typical gate station would be $500. This estimate is adjusted by
50 percent to $750 to account for the areal dispersion of the gate
stations. The cost estimates include recordkeeping and other costs as
described previously.
Repair Costs. Each quarterly survey of a gate station is assumed to
find about 3 percent of the 150 components leaking. The time taken to
12 Each analyzer can be used to screen about 27,000 components per quarter. Each gate station has about
150 components, which was increased by 50 percent to account for the areal dispersion of gate stations through
cities. The number of gate stations that can be screened each quarter by a single analyzer is therefore estimated
as: 27,000 components per quarter per analyzer * (150 components per gate station x 1.5 areal dispersion
adjustment) = 120 gate stations.
2-29
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repair a leak by a two member crew is estimated to be 1.13 hours per
leaking component. Given a wage rate of $25/hour/person, the average
repair costs for a gate station are about $1,525 per year, including the
50 percent adjustment for areal dispersion of the facilities (Radian
1992b).
Exhibit 2-1 3
Costs of Directed I/M Programs at Gate Stations
Category
Equipment Pur-
chase
Equipment Mainte-
nance
Annual Screening
Per Gate Station
Annual Repair Per
Gate Station
Cost ($)
$6,600
$3,000
$750
$1 ,525
Comments
The OVA instrument may be used at 1 20 gate sta-
tions over the course of a quarter and the costs
spread across the stations.
Cost per OVA instrument.
Each station is screened quarterly by a two-person
team costing $25/hr/person.
Each quarterly survey is assumed to find 3 percent of
the components leaking. Repair is performed by a
two-person team costing $25/hr/person, requiring
about 1.13 hours per leak repair.
Source: Radian (1992b).
Rehabilitating "Leaky" Pipe
Leaks in underground piping in distribution networks are an important source of
fugitive methane emissions. These pipes are usually constructed of steel, plastic, cast iron, or
copper. Leaks occur as a result of corrosion, joint failures (seal deterioration; pipe move-
ment), and fractures (third-party damage; subsidence; road traffic). Despite a wide range of
measures to prevent leakage, fugitive emissions generally occur.
Typically, plastic pipe leaks less than steel, which leaks less* than other materials such
as cast iron and copper (see Exhibit 2-14). Rehabilitating the leakiest pipe materials in
distribution networks, where appropriate, could reduce fugitive emissions from these sections
of the network by 85 percent or more.
Rehabilitation usually takes the form of either complete replacement with plastic pipe
(or sometimes other materials), or the insertion of new pipe material inside of the old one.
Because the cost of rehabilitating pipeline often greatly exceeds the value of avoided
maintenance requirements and gas savings, distribution firms justify their current extensive
rehabilitation programs principally on the basis of reducing safety hazards to the public.
2-30
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An example of an aggressive pipeline rehabilitation program can be found in the
Pacific Northwest. In 1987, Northwest Natural Gas Company of Portland, Oregon (NNG)
implemented a program to systematically reduce leaks by converting the company's low-
pressure (0.23 psi) cast iron and bare steel system to high-pressure (60 psi) operation. The
goal of the program was to combat repeated repairs and eliminate the maintenance dollars
spent on the low-pressure system.
Information collected from leak surveys and field supervisors along with the effects of
grading and sewer construction and dynamic changes to the system were plotted on maps to
set the priorities for conversion. The 264 miles of low-pressure lines in the system in 1990
consisted of 166 miles of cast iron and 98 miles of bare steel. The total NNG system consists
of 8,650 miles.
Exhibit 2-1 4
U.S. Distribution Pipe Materials in 1 990 and Their Leakage Rates
Pipe Type
Pipeline Mains
Pipeline Services
Total
Leak Rate (Mcf/mile/yr)
Pipe Material (length in miles)
Plastic
202,100
176,388
378,488
1.0
Steel
581 ,900
270,680
852,580
Other
52,700
26,970
79,670
9.4
Sources: Mileage data from Martin (1992); leak rates estimates from USEPA (1993).
NNG is currently replacing low-pressure mains at the rate of 30 to 33 miles per year,
and all of them should be eliminated in about 8 years. About 95 percent of low-pressure
conversion involves the insertion of 2-inch plastic (PE) pipe into cast iron mains. The other 5
percent of conversions involve the installation of coated steel main. The cost of NNG's
leakage reconstruction program was approximately $7 million in 1990.
Although past leakage efforts were focused on maintenance, the emphasis now is on
conversion. The program is monitored and evaluated through a monthly review of the
number of leaks, leak density (leaks per mile of cast iron, bare steel, etc.), and budget
expenditures. With the increasing deterioration of cast iron, the conversion program is
keeping the level of leaks per mile about constant (Haxton 1990).
The primary economic benefit of rehabilitating distribution pipeline is the reduction in
maintenance costs. Radian (1992b) estimated the cost savings at about $4.60 per foot of
pipeline per year. The costs associated with pipe rehabilitation vary depending on the
technique employed and the surface conditions encountered. Pipe replacement usually
requires excavation, which can be quite expensive in urban areas. Pipe rehabilitation, by
inserting replacement pipe directly into the leaky existing pipe, avoids expensive excavation
but requires extensive coordination and greater attention to timing. Depending on the
2-31
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method, rehabilitation costs (capital plus labor) using plastic can range from $80 to $200 or
more per foot of distribution pipe (Radian 1992b).
The baseline methane emission estimates for 2000 and 2010 include the continuation
of recent trends in distribution pipeline rehabilitation (USEPA 1993). These trends include the
rehabilitation of one mile of existing pipe for every two miles of new pipe installed (Watts
1990). Accelerating pipeline rehabilitation beyond this level would reduce emissions from the
projected baseline levels.
2.2.4 Emerging Technologies and Practices
A number of new or improved technologies and practices for reducing methane
emissions are being developed. These emerging technologies address emissions from each
stage of the U.S. gas system. In many cases, these technologies are already being field
tested, or are in limited use, and it is expected that they will be used more extensively in the
near future. Some of the technologies most likely to have an impact on efforts to reduce
emissions include:
• Installing catalytic converters on reciprocating engines;
• Using "smart" regulators in distribution systems;
• Using metallic coated seals;
Using sealant and cleaner injections in valves; and
• Using composite wraps for pipeline repair.
Each of these technologies is briefly described below. Other emerging technologies
include continuing improvements in systems analysis of transmission and distribution
networks; leak detection methods; and less-intrusive repair methods.
Installing Catalytic Converters on Reciprocating Engines
Exhaust from the reciprocating engines used to power compressors (primarily on
transmission pipelines) is a significant source of methane, as well as other air pollutants.
Installing catalytic converters to reduce methane emissions from reciprocating engines is an
alternative to replacing them with turbines, which, as discussed previously, is not always
technically or economically feasible. Catalytic converters installed on suitable reciprocating
engines have successfully reduced nitrogen oxide (NOX), carbon monoxide (CO), and non-
methane organic compounds (NMOCs) emissions. Ongoing developments indicate that this
technology could reduce methane emissions as well (Novak 1992).
Many air emissions in engine exhaust, including methane, NMOCs, and CO, result
from incomplete combustion. Catalytic converters use the ability of certain metals to promote
the further oxidation of engine exhaust, thereby reducing the emissions of these gases. The
catalyst, made of specially-blended metals, is positioned to come in contact with the exhaust
gas. The degree to which a compound such as a hydrocarbon is removed from the exhaust
gas increases with: (1) more contact with the catalyst; and (2) higher exhaust temperature.
2-32
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Until recently, catalyst technology has not been suitable for removing methane from
compressor engine exhaust because exhaust gas temperature must exceed 900°F before
current catalyst technology will significantly catalyze methane. Most reciprocating engines
operate in the region of 700 to 800°F, and engine operators can usually adjust exhaust
temperatures by only 30 to 40°F given engine specifications and the load characteristics of
the engine's function. Thus, standard catalytic converters have not typically been effective in
reducing methane from the exhaust of most reciprocating engines (Novak 1992).
However, recent developments are showing promise that may enable this technology
to reduce methane emissions. Research performed by British Gas PLC on stationary
reciprocating engines, which were being used in combined heat and power schemes,
reduced methane emissions by 50 percent using commercially available 3-way catalytic
converters (Lander & Broomhall 1991). According to a recent product announcement,
Johnson-Matthey has developed a catalyst that can reduce methane emissions by 40 to 60
percent at exhaust temperatures of only 600 to 700°F (See Exhibit 2-15) (Chu 1992). Further
research is needed to see if similar results can be achieved with reciprocating engines used
to drive pipeline compressors.
These types of catalysts are likely to be used more frequently due to trends in
regulations controlling NOX, NMOCs, and CO. Catalyst technology can reduce these
emissions by 95 percent or more under suitable conditions. The recent developments
described here indicate that catalysts may also be able to significantly reduce methane
emissions with minimal additional cost.
Utilizing "Smart" Regulators in Distribution Systems
Leakage from distribution pipelines is strongly related to the system pressure.
Reducing the time-averaged pressure in the distribution system will reduce gas losses (and
thus methane emissions). Currently, distribution system pressures are set to maintain the
minimum pressure needed to meet normal peak demand. Because demand varies signifi-
cantly depending on the time of day, season, and other factors, this minimum pressure is
generally higher than necessary most of the time.
"Smart" regulators are under development that will enable the system pressure to
fluctuate with demand conditions. Depending on how they are designed, these regulators will
be able to vary the system pressure based on historic demand patterns, or based on real-
time demand data. By varying system pressures to better match demand, the time-averaged
pressure of the system can be reduced. With the lower average pressure, emissions are also
reduced. This is an area of active research, and a technical report sponsored by the Gas
Research Institute is forthcoming.
Metallic Coated Seals
Seals made of elastomeric compounds13 are used on moving parts such as rotating
shafts and polished rods found on components at oil and gas well sites. The seals currently
in use do not seal well because if they are tightened enough to prevent leakage, they wear
out rapidly due to friction with the moving shaft or rod. Additionally, when tightened enough
to prevent leakage, the friction with the shaft or rod can cause the shaft or rod to seize up.
13 Elastomeric compounds are rubber-like synthetic polymers.
2-33
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Exhibit 2-15
Methane Conversion with a Light Hydrocarbon Catalyst
c
H
4
C
0
N
V
E
R
S
I
o
N
60
40 -
20
300 400 500 600 700 800 900 1000 1100 1200
C##Yttc Convenor
UgM Hydroewbon • Prnli
SMfidwd - FrMh
--- UgMHydrocwbon'Ag*d
TEMPER ATURE,*F
Fresh * Agtd (2 YMTS In FMd)
Source: Chu (1992).
Because of these problems, seals around rotating shafts and rods are an important source of
fugitive emissions. Additionally, seals must be replaced frequently due to excessive wear.
A new type of seal material, referred to as metallic coated seals, has recently become
available and holds promise for solving these difficulties for rotating shafts and rods. Using
an inexpensive metal lubricant in the sealing material allows operators to tighten the seals on
moving parts tight enough to prevent fugitive emissions. The metallic lubricant reduces the
friction between the seal and the rod or shaft, preventing seizing. Moreover, according to the
Larkin Company that markets the Magion Plated Seals, the reduced friction increases the
service life of the seal by about two weeks to three months, which significantly reduces
operating costs (White 1992).
Sealant and Cleaner Injections for Valves
Proper valve maintenance can significantly reduce fugitive emission from valves, which
are responsible for a large share of fugitive emissions. Although most valve manufacturers do
not mention the need for periodic maintenance and lubrication of their valves, practice has
demonstrated that valve seals dry out easily and leak. There are many new sealant and
cleaner injections available for maintaining valves. In addition to reducing emissions and
saving gas, proper valve maintenance reduces the need for valve replacement and pipeline
blowdown for repair (Oman Holding International Co. LLC. and Sealweld Corporation 1991).
2-34
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Composite Wraps for Pipeline Repair
Composite wraps is an innovative repair method for fixing pipeline leaks. Currently,
federal regulations require that damaged pipe be replaced completely, or in some cases,
repaired with a welded steel split sleeve. In order to replace a section of pipe, the pipeline
must be taken out of service and the section under repair must be vented. The damaged
section is then cut-out and a new section welded in place. Not only is this method time
consuming, disruptive, and expensive, but significant quantities of methane are released to
the atmosphere when the pipeline section is vented.
A Gas Research Institute supported program has developed a new repair method
using composite materials (Parr et al. 1992). A fiberglass-composite material, called "Clock
Spring," has been developed which is simply wrapped around the pipe in concentric layers,
with adhesive laid down between the layers. The fibers in the material run circumferentially
(i.e., around the pipe), and thus provide extremely high resistance to the hoop stresses of
high-pressure pipelines. Further research is investigating the performance of this repair
method under various conditions. The composite wrap repair method is scheduled to be field
tested in 1993. Because this repair method does not require removing the pipeline from
service and venting the gas, it is expected to both improve the cost-effectiveness of repairs
and reduce methane emissions.
2.3 NATIONAL ASSESSMENT OF EMISSIONS REDUCTIONS
The options for reducing methane emissions from natural gas systems were assessed
nationally using the cost and benefit data presented for each of the options in the previous
sections. First, the technically feasible emission reductions achievable through implementing
each option are estimated. These estimates only consider whether the option is technically
appropriate, and does not consider cost.
Second, the profitability of each option is analyzed using a discounted cash flow
analysis. This analysis compares the incremental capital and operating costs of each option
with the value of the gas saved and other quantifiable benefits to determine whether the
option is profitable. Options with a positive net present value are considered profitable. The
key parameters of this analysis include the following:
Discount Rate: A 6 percent real discount rate is used.
14
Labor Costs: Labor costs are estimated based on the incremental labor time
required to implement the option. A labor rate of $25 per hour is used, which
increases at a real rate of 2 percent per year.
Capital Costs: Incremental capital costs are incurred as a lump sum when the
equipment is installed. Additional incremental capital costs are incurred as the
equipment is replaced periodically throughout the time period of the analysis.
14 The 6 percent real discount rate was selected as appropriate for private decision making at the large firms
that comprise the natural gas industry. Different rates were selected for analyses of other industries in this study.
At a rate of inflation of 4 percent, a 6 percent real discount rate would translate into a 10 percent nominal rate. In
this analysis estimates are in real dollars and inflation is not considered.
2-35
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• Benefits: The gas saved by reducing emissions is the only benefit consid-
ered.15 The value of the gas saved is estimated as follows (DOE 1992):
wellhead gas: $1.59/Mcf;
pipeline gas: $2.01/Mcf; and
distribution system gas: $2.91/Mcf.
The gas values are estimated to increase at a real rate of 2 percent per year.
• Time Period: The analysis is conducted over a 30 year period.
The analysis was performed by considering the average conditions under which the options
would be implemented. Although the profitability of the options will vary based on site-
specific conditions, these factors were not considered.
Five options were found to be profitable (see Exhibit 2-16):
Production:
replacing high-bleed pneumatic devices;
installing flash tank separators on dehydrators;
• Transmission:
implementing directed inspection and maintenance programs at com-
pressor stations;
replacing high-bleed pneumatic devices;
• Distribution:
implementing directed inspection and maintenance programs at gate
stations.
For each of these profitable options, the emissions reduction achievable as the result
of implementation of the option by the largest U.S. firms was also estimated. In cases where
other factors such as regulatory programs have an impact, these are also taken into account.
The market share (or similar indicator) of these larger firms in each sector is used to calculate
the portion of profitable emission reductions which are likely achievable. These estimates of
potential industry penetration over the next two decades are referred to below as "achievable"
emission reductions.
The analysis is based on the base case scenario of future methane emissions (see
Exhibit 2-5). If natural gas production and use are greater than forecasted by this scenario,
then emissions and potential reductions in emissions could be larger. Conversely, if natural
gas production and use are less than indicated by the base case scenario, emissions and
15 In the case of promoting the use of turbines over reciprocating engines, the benefits are the lower capital
and operating costs of the turbines. The cost is estimated in terms of additional fuel required to operate the
turbines.
2-36
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potential reductions in emissions may be somewhat lower. A sensitivity analysis is presented
to investigate the effect of alternative assumptions in the results.
Exhibit 2-16
Profitability of Techniques for Reducing Methane Emissions
Stage
Production
Transmission
Distribution6
Engine Exhaust
(Transmission)
Source of Emissions
Venting from "High-
Bleed" Pneumatics
Venting from Glycol
dehydrators
Fugitive Emissions
Fugitive Emissions
Venting from "High-
Bleed" Pneumatics
Venting during Pipe-
line Repair
Fugitive Emissions
from Gate Stations
Reciprocating Engine
Exhaust
Technique for Reducing Emissions
Replace existing high-bleed pneumat-
ic devices with low-bleed devices.
Install flash tank separators to collect
the methane and use the methane to
fuel the dehydrator heater.
Directed Inspection and Maintenance
(I/M) programs at gas wells and treat-
ment facilities, requiring periodic leak
screening and repair.
Directed I/M programs at compressor
stations, requiring periodic leak
screening and repair.
Replace high-bleed pneumatic devic-
es with low-bleed devices.
Transfer gas prior to transmission line
blowdowns using portable compres-
sors.
Directed I/M programs at gate sta-
tions, requiring periodic leak screen-
ing and repair.
Promote the use of gas turbines
Results of Discounted
Cash Flow Analysis9
.-••••pFaBwbte-- .
Profitable ;
Not Profitable
. . P*of&3bte
f^offtabte
Not Profitable
.. HPw^abla :
Not Profitable
a Profitability based on the value of gas savings. See text.
b Accelerated rehabilitation of leaky distribution system pipeline is not listed because it is considered in the
baseline emissions estimates in USEPA (1993). The discounted cash flow analysis shows that the cost of
accelerating leaky pipeline replacement exceeds the value of gas saved.
Source: Radian (1992b).
2.3.1 Production Facilities
The principle options to reduce methane emissions from production facilities include
replacing high-bleed pneumatic devices, reducing emissions from dehydrators by installing
flash tank separators, and implementing directed inspection and maintenance programs at
gas wellsites. The cost-effectiveness of these options, summarized in Exhibit 2-17, are as
follows.
2-37
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Replacing High-Bleed Pneumatics
Replacseroent of hsgh-bteed pneumatic
Installation of no- or low-bleed devic-
es in place of high-bleed pneumatics during
the normal replacement of these devices is
profitable. Methane emissions may be re-
installation of fiasn tank
separators on dehydrators are profitable
.''&$$£&$[ functions eptferts for gas
iproductiqrJSfatsfities.
duced profitably by about 0.24 Tg/yr in 2000
and 0.25 Tg/yr in 2010, with a net present
value of about $189 million. The annualized
net benefit (value of gas saved minus costs) is about $14 million per year, or about $68 per
year per pneumatic device replaced. The costs of replacement are paid back in about 3
years, and this option is profitable at a gas price as low as $0.42 per Mcf. Exhibit 2-17
summarizes these estimates.
The costs and benefits of this option are as follows:
Technically Feasible Emission Reductions. There were an estimated 208,850
high-bleed pneumatic devices in operation on heaters, separators, and dehy-
drators in the production stage in 1990, plus an additional 43,000 high-bleed
pneumatic devices along the nation's 89,500 miles of gathering lines (Radian
1992b).16 Emissions from high-bleed devices average about 77 Mcf/yr per
device. Emissions from all the 251,850 high-bleed devices are, therefore,
estimated at 0.37 Tg in 1990 (Radian 1992b), accounting for about 85 percent
of the 1990 emissions from pneumatic devices in the production stage (USEPA
1993). The remainder of the emissions are from low-bleed devices which have
already been installed and are considered part of the baseline condition of the
industry. Emissions from high-bleed devices are expected to increase by 18
percent in 2000 and 21 percent in 2010 as the natural gas system expands
(USEPA 1993). Emissions from high-bleed devices, therefore, are expected to
increase to 0.44 Tg in 2000 and 0.45 Tg in 2010.
Because high-bleed devices are necessary for some system operations, it is
technically feasible to replace only about 80 percent of high-bleed devices with
low-bleed units. Of the 80 percent of the high-bleed devices that can be
replaced, one seventh of these devices can be replaced each year because
pneumatic devices have an average lifetime of about 7 years.
Low-bleed devices emit 70 percent less methane than high-bleed devices.
Given that 80 percent of high-bleed devices can be replaced by low-bleed
units, emissions from pneumatic devices can be reduced by 56 percent (70% x
80% = 56%). Total technically-feasible emissions reductions from pneumatic
devices are, therefore, estimated to be 0.24 Tg/yr in 2000 and 0.25 in 2010.
• Profitability. Because high-bleed and low-bleed devices have similar installation
and operating costs, the only additional cost of the replacement is an
incremental capital expense of $167 per device. Annually, one-seventh of the
high-bleed pneumatics are replaced with low- and no-bleed devices costing
and additional $167 per device. Therefore, annual increased expenditures for
16 One out of every four pneumatic devices on production units are assumed to be "high-bleed" devices. In
addition, 100 percent of the pneumatic devices along gathering lines are assumed to be high-bleed.
2-38
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replacing pneumatic devices nationally would be about $4.8 million (Radian
1992b). The incremental capital cost is considered each year throughout
the 30 year time period of the analysis.
The annual value of the gas saved would be about $85 per device replaced
(this value increases with the increase in real gas prices over time). Over the
industry as a whole, the value of the gas saved would reach about $20 million
per year once all the devices were replaced. Over a 30 year period, the net
present value of the replacement program to the industry would be $189 million
(Radian 1992b).
• Achievable Emission Reductions. Under present economic conditions, most of
the major 20 production companies are considering the use of low-bleed
pneumatic devices where technically feasible. Because these companies
account for 36 percent of U.S. natural gas production, by installing low-bleed
devices, these companies could reduce emissions by 36 percent of the
technically feasible estimate. Total emissions reductions by the major 20
production companies are, therefore, estimated to be about 0.09 Tg/yr in 2000
and 2010.
The 300 largest gas producers account for 46 percent of U.S. natural gas
production. By implementing a replacement program, these companies could
reduce emissions from pneumatics by 46 percent of the technically feasible
amount, or by about 0.11 Tg/yr in 2000 and 0.12 Tg/yr in 2010. If additional
companies participated in the program, even greater emissions reductions
could be achieved.
Installing Flash Tank Separators on Dehydrators
Methane emissions could be reduced by an estimated 0.12 Tg/yr in 2000 and 2010 if
flash tank separators (FTSs) were installed on all dehydrators. On average, this option
appears modestly cost-effective at current and projected future gas prices, with a net present
value of about $5.6 million. The annualized net benefit (value of gas saved minus costs) is
less than $1 million per year, or about $21 per year per dehydrator. It takes about 28 years
to pay back the costs of the FTSs, and this option is profitable at a gas price as low as $1.52
per Mcf. Exhibit 2-17 summarizes these estimates.
• Technically Feasible Emission Reductions. In 1990, there were about 19,776
dehydrators in operation in U.S. production fields. Emissions from these
dehydrators average 290 Mcf/yr per dehydrator. Total emissions are, therefore,
estimated to have been 0.11 Tg/yr in 1990 (Radian 1992a, USEPA 1993). In
2000 and 2010, emissions are expected to increase by 18 percent and 21
percent respectively as the gas system expands (USEPA 1993). Emissions
from dehydrator vents, therefore, are expected to increase to about 0.13 Tg/yr
in 2000 and 2010.
17 Annual incremental capital costs are estimated as follows: $167 per device x 251,850 devices x 80% that
can be replaced with no- or low-bleed devices x 1/7 replaced each year = $4.8 million per year.
2-39
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Exhibit 2-17
Profitability of Reduction Options in the Production Stage
Reduction Option
Replacement of High-Bleed
Pneumatic devices
Installation of Flash Tank Sep-
arators
Directed I/M Programs at gas
well sites
NPV
(106 $)
$189
$5.6
($21,500)
Annualized Net
Benefit (Cost)
per Unit
($/unrt)
$68/pneumatic
device replaced
$21/dehydrator
($5,790)/well site
Annualized Net
Benefit (Cost)
Nationally
(106$)
$13.7
$0.4
($1,562)
Payback
Period
(Years)
3
28
-
Break-even
Gas Price
($/Mcf)
$0.42
$1.52
>$100
Assumptions:
Benefits estimated using a wellhead gas price of $1.59/Mcf (DOE 1992).
Annualized net benefits (costs) estimated using a 6 percent discount rate over 30 years.
Payback period estimated as the time it takes for the net present value of the option to become positive.
Payback period is not estimated for options that do not have a positive net present value within 30 years.
Breakeven gas price is the 1992 gas price that produces a net present value of $0 over the 30 year analysis.
Installation of flash tank separators is technically feasible at virtually all dehy-
drator units. Consequently, emissions can be reduced by the option's full
control efficiency of 90 percent, or by about 260 Mcf/yr per dehydrator. Total
emissions reductions are, therefore, estimated to be 0.12 Tg/yr in 2000 and
2010.
Profitability. Installing a flash tank separator at each dehydrator would cost
about $84 million in capital expenses and installation costs ($4,200 per
dehydrator). The value of the gas saved industry wide would exceed $8 million
per year once all the FTSs were installed (this value would increase with the
real increase in the value of the gas). Over a 30 year period, the program
would have a positive net present value of about $5.6 million for the industry
(Radian 1992b)/"
18
Achievable Emission Reductions. Because of the profitability of flash tank
separators, most of the top 20 production companies are planning to
implement this technology over the next few years. Given that these
companies represent 36 percent of the production industry, emissions can be
reduced by 36 percent of the technically feasible reduction estimate or
0.04 Tg/yr in 2000 and 2010.
Smaller firms, however, are less likely to install flash tank separators because
the costs of installing FTSs might not justify the relatively small increases in
production efficiency. In addition, some smaller companies may not be aware
of the environmental benefits that can result from installing flash tank
18
The analysis includes the cost of replacing the FTS after 15 years.
2-40
-------
separators. More smaller companies might install FTSs if a national promotion
effort were created to encourage voluntary methane emissions reductions from
energy production and transmission facilities. These companies might also
install FTSs in combination with other more cost-effective options if the overall
program were profitable. The 300 largest producers account for 46 percent of
the production industry. By installing FTSs these 300 producers could reduce
emissions by 46 percent of the technically feasible reduction estimate. These
companies could, therefore, achieve emissions reductions of about 0.05 Tg/yr
in 2000 and 2010.
Directed Inspection and Maintenance Programs
Directed I/M programs are not estimated to be a profitable option for U.S. production
facilities. Because this study generalizes based on industry averages, however, it is possible
that well designed programs will be profitable at individual sites or regions.
Methane emissions may be reduced by about 0.19 Tg/yr in 2000 and 0.20 Tg/yr in
2010 with a negative net present value of about $21 billion. The annualized cost of the
program is estimated at about $1.5 billion per year, or about $5,800 per year per wellsite. A
gas price of over $100 per Mcf is needed to make this option profitable. Exhibit 2-17
summarizes these estimates.
Technically Feasible Emission Reductions. In 1990, there were 269,790 gas
wells operating in the U.S. (DOE 1991). Emissions per wellsite, including
wellsite treatment facilities, are estimated to be about 45 Mcf/yr, so that total
emissions were 0.23 Tg/yr in 1990 (USEPA 1993). By 2000 and 2010 emis-
sions are expected to increase by 18 percent and 21 percent respectively, so
that emissions from well sites in 2000 and 2010 are expected to increase to
0.27 and 0.28 Tg/yr, respectively (USEPA 1993). By implementing directed I/M
programs, emissions can be reduced by about 70 percent. Total technically
feasible emissions reductions are, therefore, estimated to be 0.19 Tg/yr in 2000
and 0.20 Tg/yr in 2010.
Profitability. If directed inspection and maintenance (I/M) programs were
implemented at all gas wellsites, the value of the gas saved during the first year
would be worth $13.8 million, while the cost of the program would be $1.3
billion. Nearly all these costs woufd be in labor. Over a 30-year period, the net
present value of the program would be a negative $21.5 billion (Radian 1992b).
• Achievable Emission Reductions. Given the unfavorable economics for
directed I/M programs at production facilities, widespread implementation is not
expected in the absence of regulatory requirements. Several companies are
investigating the potential for more focused and less costly programs.
2.3.2 Transmission Systems
Several of the methane reductions options for transmission systems could be cost-
effectively implemented in the United States, including directed I/M programs at compressor
stations and the replacement of high-bleed pneumatics. On average, replacing reciprocating
engines with turbines as compressor drivers does not appear to be profitable; however, site-
specific factors play an important role in the economics of this option. Using portable
2-41
-------
evacuation compressor units to reduce gas venting during blowdown operations appears not
to be cost-effective for average U.S. pipeline conditions. The cost-effectiveness of these
options, summarized in Exhibit 2-18, is as follows.
Directed Inspection and Maintenance Programs
Directed W$ programs at compressor
stations and $& ^placetrient of high-bleed
pneumatics are cost-effective options for
transmission %$*<»«& Ttw eoonomtes of
replacing reciprocating engines with
turbines abends on site-specific factors,
Directed I/M programs at compressor
stations are estimated to be profitable.
Methane emissions may be reduced by
about 0.24 Tg/yr in 2000 and 0.25 Tg/yr in
2010 with a net present value of about
$88 million. The annualized benefit of the
program is estimated at about $6.4 million
per year, or about $4,500 per year per com-
pressor station. A gas price of $1.59 per
Mcf is needed to make this option profit-
able. Exhibit 2-18 summarizes these estimates.
Technically Feasible Emissions Reductions. In 1990, there were an estimated
1,400 compressor stations along the 280,100 miles of transmission pipeline in
the U.S. Emissions per compressor stations average 12,200 Mcf/yr (Radian
1992b), so that total emissions are estimated to be 0.33 Tg/yr in 1990. These
emissions are expected to increase in 2000 and 2010 by 5 percent and
10 percent, respectively, so that emissions are estimated to be 0.34 Tg/yr in
2000 and 0.36 Tg/yr in 2010. Directed I/M programs at U.S. compressor
stations could reduce emissions from these sources by an estimated 70
percent. Total technically feasible emissions reductions are, therefore,
estimated to be 0.24 Tg/yr in 2000 and 0.25 Tg/yr in 2010.
Profitability. If directed inspection and maintenance (I/M) programs were
implemented at all existing stations, the value of the gas saved would be about
$25 million per year (this value would increase with the real increase in the
value of gas over time). The cost of the program would be about $20 million
per year, which is almost entirely labor costs. Each year the value of the gas
saved exceeds the program costs. Over a 30-year period, the net present
value of the program would be nearly $90 million (Radian 1992b).
• Achievable Emission Reductions. The 20 largest transmission companies (by
mileage) in the U.S. operate 63 percent of the nation's pipelines (Watts 1991).
Directed I/M programs at these companies could, therefore, reduce emissions
by about 63 percent of the technically feasible reduction estimates, or by about
0.15 Tg/yr in 2000 and 0.16 Tg/yr in 2010. If programs were developed to
encourage other large transmission firms to implement directed I/M programs,
further emissions reductions could be achieved.
Replacing High-Bleed Pneumatics
Installation of no- or low-bleed devices in place of high-bleed pneumatics during the
normal replacement of these devices is profitable. Methane emissions may be reduced
profitably by about 0.12 Tg/yr in 2000 and 2010 with a net present value of about
$136 million. The annualized net benefit (value of gas saved minus costs) is about
2-42
-------
$10 million per year, or about $92 per year per pneumatic device replaced.19 The costs of
replacement are paid back in about 3 years, and this option is profitable at a gas price as low
as $0.41 per Mcf. Exhibit 2-18 summarizes these estimates.
• Technically Feasible Emission Reductions. There were an estimated 134,000
high-bleed pneumatic devices in operation on transmission pipelines in 1990.
These high-bleed pneumatics emit an average of 77 Mcf/yr, so that total
emissions from high-bleed devices are estimated to have been 0.20 Tg/yr in
1990 (Radian 1992b).20 These emissions are expected to increase in 2000
and 2010 by 5 percent and 10 percent, respectively, so that emissions from
pneumatic devices increase to 0.21 Tg in 2000 and 0.22 Tg in 2010. Low-
bleed devices can reduce emissions from pneumatics by 70 percent. Given
that 80 percent of high-bleed devices can be replaced by low-bleed units over
a normal maintenance cycle of seven years, it is technically feasible to reduce
emissions by 56 percent (70% x 80% = 56%). Total emissions reductions are,
therefore, estimated to be 0.12 Tg/yr in 2000 and 2010.
Profitability. The net present value of the program to the industry would be a
positive $136 million over a 30-year period (Radian 1992b). Because low-bleed
devices cost an additional $167 per device, the annual increased capital
expenditure would be $2.6 million.21 The saved gas would be worth about
$1.6 million during the first year and over $11 million per year after the replace-
ment was complete (this value would increase with the real increase in gas
prices over time).
• Achievable Emission Reductions. If the 20 largest transmission firms imple-
mented a replacement program, almost two-thirds of the high-bleed devices
could be replaced. Emissions could, therefore, be reduced by about two-thirds
of the technically feasible reduction estimate, or by about 0.08 Tg/yr in 2000
and 2010. However, only a few firms have developed programs to replace their
high-bleed pneumatics. Replacement programs have not been implemented by
most companies because the industry lacks financial incentives to minimize
"lost gas" and also lacks knowledge concerning the environmental benefits of
emissions reductions. Until these barriers are overcome, relatively few trans-
mission companies are expected to implement the replacement program.
19 The annualized net benefit per device replaced is higher in the transmission stage than in the production
stage because the value of the gas saved is higher in the transmission stage.
20 Radian (1992b) assumes that 100 percent of the pneumatic devices on transmission lines are high-bleed.
The 1990 total emissions estimate of 0.2 Tg/yr, therefore, corresponds with the USEPA (1993) estimate of 0.2 Tg/yr
of total emissions from all pneumatic devices in the transmission stage in 1990.
21 Annual incremental capital costs are estimated as follows: $167 per device x 134,000 devices x 80% that
can be replaced with no- or low-bleed devices x 1/7 replaced each year = $2.6 million per year. The incremental
capital costs are considered each year throughout the 30 year time period of the analysis.
2-43
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Exhibit 2-18
Profitability of Reduction Options in the Transmission Stage
Reduction Option
Directed I/M Programs at
Compressor Stations
Replacement of High-Bleed
Devices
Recapturing Gas Released
during Pipeline Repairs
Greater Use of Turbines
NPV
(106 $)
$88
$136
($420)
($0.16)
Annualized Net
Benefit (Cost)
per Unit
($/unit)
$4,560/station
$92/pneumatic
device replaced
($50,000)/1,000
miles of pipeline
($2.28)/hp/yr
Annualized Net
Benefit (Cost)
Nationally
(106 $)
$6.4
$9.9
($14.0)
($0.01)
Payback
Period
(Years)
1
3
--
__a
Break-even
Gas Price
($/Mcf)
$1.59
$0.41
$27.65
$1.91b
a The payback period is not defined for this option because there is an initial savings in capital costs in year 1 ,
followed by increased fuel costs in subsequent years.
b Unlike the other options analyzed, the option to use turbines is [ess profitable at higher gas prices because
increased fuel use by turbines represents a cost. Consequently, although the option is not profitable at the
assumed gas price, the breakeven gas price is less than the assumed gas price.
Assumptions:
Benefits estimated using a pipeline gas price of $2.01/Mcf (DOE 1992).
Annualized net benefits (costs) estimated using a 6 percent discount rate over 30 years.
Payback period estimated as the time ft takes for the net present value of the option to become positive.
Payback period is not estimated for options that do not have a positive net present value within 30 years.
Breakeven gas price is the 1992 gas price that produces a net present value of $0 over the 30 year analysis.
Recapturing Gas Released During Pipeline Repairs
Recapturing gas released during pipeline repair is not estimated to be a profitable
option for U.S. facilities. This conclusion is based on industry averages, however, and it is
likely that focused programs in regions with a high density of pipeline activity could be
profitable.
Methane emissions may be reduced by about 0.02 Tg/yr in 2000 and 2010 with a
negative net present value of about $420 million. The annualized net cost of the program is
estimated at about $14 million per year, or about $50,000 per year per 1,000 miles of
transmission pipeline, or about $200,000 per year per PEC unit. A gas price of over $27 per
Mcf is needed to make this option profitable for average U.S. conditions. Exhibit 2-18
summarizes these estimates.
• Technically Feasible Emission Reductions. In 1990 emissions from pipeline
blowdowns were estimated to be 0.22 Tg/yr in 1990 (Radian 1992b; USEPA,
1993). These emissions are expected to increase in 2000 and 2010 by 5
percent and 10 percent, respectively, so that emissions from pipeline
blowdowns in the years 2000 and 2010 are 0.24 Tg/yr and 0.25 Tg/yr (USEPA
1993). If portable evacuation compressors (PECs) were used, roughly 80
2-44
-------
percent of the otherwise vented gas could be captured during a blowdown.
Given that PECs can be deployed at only 10 percent of the blowdowns,
emissions can be reduced by 8 percent (80% x 10% = 8%). Total emissions
reductions are, therefore, estimated to be 0.02 Tg/yr in 2000 and 2010.
• Profitability. As discussed above, about 67 PEC units are required in the U.S.
to have one PEC unit per 4,200 miles of pipeline. Purchasing these units
would cost about $335 million ($5 million per unit). If these units were de-
ployed at all blowdowns, the value of the gas saved would be about $19
million per year. Because the units could only be deployed at about 10
percent of the blowdowns, the value of the gas saved would only be about
$1.9 million per year. At these rates of gas savings per PEC unit (about
14,000 Mcf/PEC/yr), the program is not profitable. To be profitable, about
200,000 to 300,000 Mcf/PEC/yr must be saved, which is about 20 times the
average value calculated. Given the pipeline density in some areas of Texas,
Louisiana, and the mid-west, regionally-targeted PEC programs may be
profitable. Analysis of such targeted programs has not yet been performed.
• Achievable Emission Reductions. The widespread implementation of PECs is
unlikely due to their high equipment costs and limited opportunity for utilization.
In addition, the achievable emission reductions by utilizing PECs is relatively
small. The 20 largest transmission companies operate about 63 percent of
U.S. pipelines and can, therefore, reduce emissions from blowdowns by about
63 percent of the technically feasible reduction estimate by utilizing PECs.
Emissions reductions would then be only 0.01 Tg/yr in 2000 and 2010.
Greater Use of Turbines on New Pipelines and When Retiring Reciprocators
Significant methane emission reductions could be achieved by encouraging compa-
nies to: (1) replace reciprocating engines with turbines when they retire the existing engines;
and (2) install more turbines instead of reciprocators on new transmission pipelines. The cost
of using turbines is highly site-specific. Based on average values, the analysis shows that the
option is marginally not profitable, with a negative net present value of about $0.2 million, and
annualized net costs of about $0.01 million. Given the additional air quality benefits of using
turbines in place of reciprocators, this slight cost may be justified. Exhibit 2-18 summarizes
the estimates.
• Technically Feasible Emission Reductions. Annual pipeline fuel use in 1990 is
estimated at 415,684 MMcf for reciprocating engines and 244,132 MMcf for
turbines (USEPA 1993). About 83 percent of total compressor horsepower
provided to the transmission, distribution, and storage stages is used in the
transmission stage (AGA 1991b). Annual pipeline fuel use in the transmission
stage is, therefore, estimated to be about 345,018 MMcf for reciprocating
engines and 202,630 MMcf for turbines. Emissions from reciprocating engines
are estimated at 0.510 Mg per MMcf of fuel use, while emissions from turbines
are estimated at 0.009 Mg per MMcf of fuel use (USEPA 1993V Emissions from
reciprocating engines are, therefore, estimated to have been 0.18 Tg/yr in 1990,
while emissions from turbines are estimated to have been only 0.002 Tg/yr in
1990.
2-45
-------
Compressor engine pipeline fuel use is assumed to increase with the total
volume of gas consumed. Based on the USEPA (1993) base case scenario,
total pipeline fuel is expected to increase by 25 percent in 2000 and by 30
percent in 2010, so that emissions from reciprocating engines are estimated to
increase to 0.22 Tg in 2000 and 0.23 Tg in 2010. Using the same increment
factors, emissions from turbines show negligible increase and remain about
0.002 Tg in 2000 and 2010.
Of the reciprocating engines currently in place on U.S. transmission lines,
about 27 percent are expected to retire by 2000 and about 60 percent are
expected to retire by 2010 (Radian 1992b). If 80 percent of these reciprocating
engines were replaced by turbines and 80 percent of the compressors on new
pipelines are driven by turbines, the reductions in emissions can be estimated
by calculating the change in future fuel use for reciprocating engines and
turbines as follows:
Estimates for 2000:
The retirement and replacement of existing reciprocating engines would
reduce reciprocating engines to 78.4 percent (73% + (20% x 27%) =
78.4%) of the existing 1990 stock. This would reduce the 345,018 MMcf
of fuel used by existing reciprocating engines by 27.6 percent or
74,524 MMcf.
The 20 percent of new compressors installed as reciprocators would
use only 20 percent of the 86,945 MMcf of fuel estimated to be the
increase in reciprocating engine fuel use under the base case scenario
of 2000. This would further reduce fuel use by 69,556 MMcf. Thus total
fuel use by reciprocating engines in 2000 would be reduced by about
144,080 MMcf resulting in emission reductions of 0.07 Tg.22
The amount of turbine fuel use would exceed the 2000 base case
projected estimate of 253,693 MMcf. Given that 21.6 percent (80% x
27% = 21.6%) of existing reciprocators are replaced with turbines and
that turbines use 28 percent more fuel than reciprocators (Jones 1992),
the increase of fuel use by turbines as a result of such a replacement
would be about 27.6 percent (21.6% x 1.28 = 27.6%) of the 345,018
MMcf of reciprocating engine fuel use or 95,390 MMcf.
The 80 percent of new compressors installed as turbines would in-
crease turbine fuel use by 102.4 percent (80% x 1.28) of the 86,945
MMcf estimated to be the base case increase in reciprocating engine
fuel use. This increase of 89,031 MMcf added to 95,390 MMcf would
increase total turbine fuel use in 2000 by about 184,422 MMcf and
result in an increase in emissions by 0.002 Tg.
pp
The total reduction in fuel use in reciprocating engines is the sum of the fuel use from retired reciprocating
engines that are replaced by turbines, and the new engines that would have been reciprocating engines (under the
base case assumptions) that are instead installed as turbines. The methane emissions reduction is estimated as
the reduction in fuel use times the emissions factor per unit of fuel.
2-46
-------
Given a reduction of 0.07 Tg of emissions from reciprocators and an
increase of 0.002 Tg of emissions from turbines, the net emissions
reduction in 2000 from compressor exhaust is about 0.07 Tg.
Estimates for 2010: Repeating these calculations assuming that 60 percent of
reciprocators are retired by 2010 results in a reduction of fuel use by recipro-
cating engines by 247,861 MMcf. This reduces emissions from reciprocating
engine exhaust by about 0.13 Tg. Total increase in turbine fuel use in 2010 is
about 317,262 MMcf. This increases emissions from turbine exhaust by
0.003 Tg. Net emissions reductions in 2010 are, therefore, 0.13 Tg.
• Profitability. Assessing the relative cost of turbine and reciprocating engines is
complicated by a number of site-specific technical and operational factors
surrounding the use of either engine type. As a result, a comparison of annual
cost per hp is not the final determinant. Nevertheless, a representative exam-
ple is provided, which examines the economics surrounding the purchase of a
5,000 hp turbine in place of a reciprocating engine. The first year incremental
savings in installation and operating costs are an estimated $928,000 and
$126,000, respectively, for a total incremental savings of about $1.05 million.
The incremental increase in fuel costs is $187,000, which results in a first year
net cash flow of a positive $867,000. Because of the greater fuel use of the
turbine, the net cash flow for future years is negative. Over the 30 year lifetime
of the equipment, the net present value is a negative $156,600 and the annual-
ized net cost is $2.28/hp/yr (Radian 1992b).
• Achievable Emission Reduction. The decision to replace reciprocating engines
is site specific and the replacement of a given compressor capacity does not
necessarily involve a one for one swap. Therefore, achievable emissions were
not estimated based on the capacity or fuel use of the largest transmission
firms.
2.3.3 Distribution Networks
?rt gate staaons
provide aV
metfiflfie encjissions fr
-------
• Technically Feasible Emission Reductions. There were an estimated 3,713 gate
stations within the distribution networks of the U.S. in 1990, each emitting
about 1,667 Mcf/yr (USEPA 1993). Total emissions from gate stations are,
therefore, estimated at 0.12 Tg/yr in 1990. The number of gate stations is
expected to increase with the increase in distribution pipeline mileage, assum-
ing that the average ratio of 1 gate station per 353 miles remains constant.
From 1980 to 1990 distribution mains grew by 13,500 miles/yr, while from 1983
to 1990, services grew by 8,400 miles/yr (AGA 1984 and 1991b). Assuming
that these pipeline growth rates remain constant, gate stations are estimated to
increase to 4,334 in 2000 and 4,954 in 2010, and emissions from gate stations
are estimated to be 0.14 Tg/yr in 2000 and 0.16 Tg/yr in 2010 (USEPA 1993).
Because directed I/M programs could reduce emissions by about 70 percent,
total emission reductions are estimated to be 0.10 Tg/yr in 2000 and 0.11 Tg/yr
in 2010 (Radian 1992b).
• Profitability. If directed inspection and maintenance (I/M) programs were
implemented at all of these stations, the net present value of the program over
30 years would be about $85 million (Radian 1992b). The value of the gas
saved during the first year would be $13 million, while the cost of the program
would be about $9 million. Nearly all the costs are labor costs.
• Achievable Emission Reductions. Emissions could be significantly reduced if
the largest distribution companies could be successfully encouraged to
implement directed I/M programs at gate stations. The 33 largest distribution
companies account for about 60 percent of the national total miles of mains
and services (Watts 1989). These companies could, therefore, reduce emis-
sions through directed I/M programs by about 60 percent, or by about 0.06
Tg/yr in 2000 and 0.07 Tg/yr in 2010.
Although such programs are cost-effective, they may not have been widely
implemented due to the lack of knowledge about the size of methane emis-
sions from this source. This lack of knowledge may be compounded by the
rate policies of public utility commissions (PUCs). Most PUCs monitor the level
of unaccounted-for-gas, a small part of which can be attributed to leakage. As
long as these levels are not excessive, the cost of this "lost" gas is passed on
to rate payers. Such treatment may not encourage firms to conserve gas and
reduce emissions even when the value of the gas justifies such action.
Achieving the emissions reductions from gate stations will require a program to
promote the importance of this methane source and the benefit to companies
and customers of reducing lost gas.
2.3.4 Summary of Costs and Benefits of Reducing Methane Emissions
Exhibit 2-19 summarizes the results for each of the eight techniques that were
analyzed. The top portion of the exhibit lists the eight options and the technically feasible
and profitable emission reductions from each. As shown in the exhibit, in 2000 it is
technically feasible to reduce emissions by about 1.1 Tg, or about 55 percent of the baseline
emissions from the eight sources analyzed. Because only five of the eight options are
profitable, about 0.8 Tg can be reduced profitably in 2000.
2-48
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-------
The bottom half of the exhibit shows the baseline emissions for the sources for which
no emission reduction option was analyzed. Baseline emissions for these additional sources
are estimated at about 1.4 Tg for both 2000 and 2010. When all gas system emissions are
considered, technically feasible emissions reductions are about 32 to 34 percent of baseline
emissions, and profitable emissions reductions are about 24 to 25 percent of baseline
emissions. If emerging technologies can be implemented on a widespread basis, emissions
may be reduced by an additional 5 to 10 percent.
2.3.5 Sensitivity Analysis
While there is considerable uncertainty regarding the costs and effectiveness of the
options for reducing emissions, the estimates of profitable emission reductions are robust to
these uncertainties. The estimate of profitable emission reduction is sensitive to uncertainty
regarding emission rates, however. If emission rates are at the lower end of expectations,
fewer options are profitable because less gas is available to be saved. Three sets of
sensitivities were performed: costs of control; gas price; and emission rates. Additionally,
the sensitivity to including the value of environmental benefits is examined.
Sensitivity to Costs of Control
The estimate of profitable emission reduction is not sensitive to a 20 percent increase
or decrease in the costs of the emissions reduction options. When all costs were increased
by 20 percent, only the flash tank separators (FTS) switched from being profitable to being
unprofitable. Also, the increased cost savings associated with using turbines caused the
turbine option to become profitable. Because these two options produce comparable
emission reductions, increasing costs by 20 percent has essentially no impact on the
profitable emission reduction estimates. When costs are reduced by 20 percent, none of the
unprofitable options becomes profitable, and again there is no impact. Exhibit 2-20 summa-
rizes these results. The shaded portions of the exhibit show where the profitability of the
option was affected by the change in cost. The impact on the profitable emission reduction is
summarized at the bottom of the exhibit.
Sensitivity to Gas Price
A substantial change in gas price is required to influence the results. An increase of
$1.00/Mcf does not make directed I/M programs at gas wellsites or gas recovery prior to
pipeline blowdown profitable. Consequently, there is no change in the estimate of profitable
emission reductions. A reduction of $1.00/Mcf in the value of gas causes the FTSs and
directed I/M programs at compressor stations to switch to become unprofitable. Also, the
incremental cost of using turbines is reduced under the low gas price scenario,23 causing
the turbine option to become profitable. The net result of the low gas price sensitivity is that
the estimate of profitable emissions reduction is lowered by about 25 to 35 percent.
Exhibit 2-20 summarizes the results.
Sensitivity to Emission Rates
There is considerable uncertainty regarding emission rates from individual sources
(USEPA 1993). At low emission rates, three options become unprofitable because less gas
•23 Turbines require more fuel than reciprocating engines per horsepower-hour of compression supplied.
2-50
-------
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Replacement of High-Bleed Pneumatic Devices
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pairs
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a All costs were increased or decreased by 20 p<
b Using USEPA (1993) High and Low estimates c
c An increase in costs increases the benefit (i.e.,
d A decrease in the gas price reduces the increrr
e The range in emissions reductions reflects the I
and USEPA (1993).
N = Not Profitable
Pr = Profitable
-------
can be recovered: FTSs; directed I/M at compressor stations; and directed I/M at gate
stations. As a consequence, profitable emission reductions drop from about 25 percent of
baseline emissions to 11 percent of emissions (baseline emissions are lower under the low
emission rate sensitivity scenario).
Under the high emission rate sensitivity, none of the unprofitable options becomes
profitable. Therefore, profitable emission reductions remain at about 24 to 25 percent of
baseline emissions (baseline emissions are higher under the high emissions rate sensitivity
scenario). Exhibit 2-20 summarizes the results.
Impact of Including Environmental Benefits
The analysis of profitable emission reductions does not include the value of the
environmental benefits of recovering methane. Nevertheless, the estimates of profitable
emission reductions are not sensitive to a reasonable range of estimates for this value.
To assess the implications of including these benefits, the sensitivity of the results to a
range of values per Mcf of avoiding methane emissions was assessed. The proper value to
assign to avoiding methane emissions has yet to be determined. As a proxy, a range of
costs of reducing carbon dioxide build up in the atmosphere through reforestation was used.
These costs have been estimated in the range of $5 to $20 per ton of carbon contained in
carbon dioxide, with some estimates as high as $100 per ton. This range of costs for
avoiding carbon dioxide build up translates into a value of about $0.57 to $2.29per Mcf for
avoiding methane emissions, with a value potentially as high as $11.50 per Mcf. 4 Using
these values as a range, the estimate of profitable methane emissions reductions is not
sensitive to the inclusion of the value of the environmental benefits.
2.4 BARRIERS
The previous discussion indicates that there are many available technologies for
reducing emissions from the U.S. natural gas system. These technologies have proven to be
technically feasible in operation and, in many cases, are profitable in their own right.
Furthermore, ongoing research is expected to improve the technical and economic feasibility
of these technologies and practices.
While the analysis presented in the previous section shows that these options could
be more widely implemented, there are several barriers such as economic and regulatory
policies, as well as informational barriers, which hinder the widespread adoption of cost-
effective technologies. An additional barrier is the relatively high cost of researching,
developing, and demonstrating new technologies and practices. These barriers and possible
actions to overcome them are discussed below, and summarized in Exhibit 2-21.
24 If the benefit of reducing carbon dioxide emissions is $5 per metric ton of carbon contained in CO2 and
assuming a mass-based global warming potential (GWP) for CH4 of 22, then value of avoiding natural gas
emissions can be computed as follows:
$5 . 12mtC . ^ mt CO2 19.16 g / ft* CH4 I.QQQ ft3 = $057,,^
1 mt C 44 mt COZ mt CH4 106 g/mt 1 Mcf
Similar computations yield $2.29 per Mcf for $20 per ton carbon and $11.50 per Mcf for $100 per ton carbon.
2-52
-------
Information Barriers
In order for natural gas companies to implement technologies which reduce methane
emissions, they must be aware of the potential magnitude and source of emissions from their
systems, as well as the availability, applicability, and most importantly the profitability of these
options. This knowledge, however, is lacking for many areas of the U.S. natural gas system.
In addition, it is important to emphasize that there are significant global and local
environmental benefits associated with reducing methane emissions. This information barrier
could be overcome with a variety of programs publicizing the economic, operational, and
environmental benefits of these options.
Voluntary programs have been successful in gaining the support and cooperation of
business and industry in implementing energy efficiency measures, in cases where
information barriers were impeding the introduction of beneficial technologies. Such a
program could help overcome informational barriers to reducing methane emissions by
providing outreach services to the gas industry, serving as an information clearinghouse,
assisting in assessing implementation programs, and publicizing successful programs.
Exhibit 2-21
Barriers to Implementing Profitable Methane Emission Reduction Options
Barrier
Solution
Information Barriers
Emissions rates are not well known, so that
benefits of emissions reductions have not
been quantified. Also, information on
options for reducing emissions has not
been readily available.
Voluntary Programs
With support and cooperation of the
industry, voluntary programs to adopt
profitable emissions-reducing technologies
assist in disseminating needed information.
Economic and Regulatory Barriers
Government regulated rates allow the cost
of lost gas to be recovered by the gas
companies.
Provide Information
Information on profitable options could be
provided to rate regulatory bodies to
encourage the inclusion of emissions
reduction opportunities in rate calculations.
Technology Barriers
Costs of researching and demonstrating
technologies deter individual companies
from introducing improved technologies
and practices.
Support Targeted Research
Fund the initial deployment and
demonstration of new technologies and
practices.
2-53
-------
Economic and Regulatory Barriers
The U.S. gas industry is subject to
economic regulation at both the federal and
state level. In particular, the rates that
transmission networks may charge are
regulated, largely based on capital and
operating costs incurred. Similarly, the rates
charged by distribution companies to
consumers are regulated by state Public Utility Commissions (PUCs). Currently, the cost of
"unaccounted-for-gas" (UFG) is typically passed on to the consumer as an acceptable
operating cost.25 As a result, the cost of gas lost through leakage and other emissions is
often not fully born by the company, reducing the incentive to invest in technologies which
reduce methane emissions. Thus, there is little incentive to go beyond the requirements of
existing safety regulations.
economic, operattorai, and environmental
ffidSuefag aftetfiaae &ai$$kM!tt, ft Is ifc itae
Given that there are profitable op-
tions for reducing methane emissions, it is
in the interest of PUCs (on behalf of con-
sumers) to encourage gas companies to
invest in these technologies, where appro-
priate. For example, state PUCs might allow
a distribution company to include invest-
ments in methane reduction technologies in
rate calculations. Similarly, PUCs might
require gas companies to estimate the component of UFG accounted for by gas leakage and
other emissions, and reduce the allowed rate-of-return on this cost.
However, as with gas companies, lack of awareness of these technologies and their
potential creates an informational barrier to regulatory change. Programs encouraging the
implementation of these technologies could also provide information to PUCs and the Federal
Energy Regulatory Commission (FERC) concerning methane emission reduction programs.
Technology Cost and Availability Barriers
In general, the costs of developing and testing new technologies can deter individual
companies from introducing improved technologies and practices. In addition, information
concerning new technologies may not be readily available to the industry as a whole. These
barriers can be overcome by supporting
targeted research to reduce costs and to
develop improved technologies and practic-
es. Such research, already underway to
some extent, could be expanded under the
auspices of the Department of Energy
(DOE), the Gas Research Institute (GRI), the
oe
Unaccounted-for-gas (UFG) is not synonymous with methane emissions. Other important factors
contributing to UFG include metering errors, accounting procedures and schedules, temperature and pressure
effects, and gas used in the system.
2-54
-------
American Gas Association (AGA), the Institute of Gas Technology (IGT), or the EPA and could
include funding the initial deployment and field testing of new technologies and practices.
2.5 LIMITATIONS
This analysis is limited principally by the aggregate nature of the economic
evaluations. While national average conditions were used in the analysis, site-specific
conditions can have a significant influence on the technical feasibility and profitability of the
options. In particular, profitable opportunities to recover gas prior to pipeline blowdowns and
to use turbines in place of reciprocating engines probably exist for a portion of the U.S.
natural gas system. The aggregate nature of the analysis masks these opportunities, and
also masks site-specific conditions that are not profitable.
Similarly, diversity in leak rates among facilities, e.g., among gate stations, leads to
variations in the profitability of reducing emissions among facilities. In particular, the
profitability of directed I/M programs can be improved if they are focused on those facilities
with the highest leak rates. Tailoring of efforts over time to maximize cost effectiveness is not
considered in this analysis.
Finally, the comparison of costs and benefits is simplified because it does not
consider the regulatory environment in which costs are recovered. The implications of rate
regulations, including the ability to recover the costs of "unaccounted-for gas" in the portions
of the industry can have an important impact on the profitability of the options for the
perspective of companies and customers.
2.6 REFERENCES
AGA (American Gas Association). 1984. Gas Facts - 7983 Dafa, AGA, Arlington, VA.
AGA (American Gas Association). 1985. Transmission: Compressor Station Operations,
AGA,; Arlington, VA.
AGA (American Gas Association). 1990. The Outlook for Gas Energy Demand, 1990-2010,
AGA; Arlington, VA.
AGA (American Gas Association). 1991 a. The Gas Energy Supply Outlook, 1991-2010, AGA;
Arlington, VA.
AGA (American Gas Association). 1991b. Gas Facts - 1990 Data, AGA; Arlington, VA.
ARB (California Air Resources Board). 1991. Draft Proposed Determination of Reasonably
Available Control Technology for Control of Fugitive Emissions of Volatile Organic
Compounds from Oil and Gas Production and Processing Facilities, Chemical Plants,
and Pipeline Transfer Stations, State of California.
Chu, Wilson. 1992. Johnson Matthey new product press release on Light Hydrocarbon
Catalyst.
2-55
-------
Cowgill, M.R. 1992. Presentation at the GRI/EPA Gas Industry Methane Emissions Advisors
Committee Meeting, April 22-24, 1992, Austin, TX.
DOE (U.S. Department of Energy). 1991. Natural Gas Annual - 1990, US DOE; Washington,
DC.
DOE (U.S. Department of Energy). 1992. , Natural Gas Monthly (April 1992); US DOE;
Washington, DC.
Eberle, Arthur. 1992. Columbia Gas; personal communication - 7/29/92.
Erickson, John. 1991. "Net Benefit of Gas Pipeline Capacity Expansion," Gas Energy Review
(October 1991); pp. 5-9.
Erickson, John. 1993. Personal communication with John Erickson, American Gas Associa-
tion, Arlington, VA.
Haxton, Linda K.. 1990. "Renovating Cast Iron Lines," Pipeline and Gas Journal (December
1990); pp. 20-22.
Harrison, Matthew. 1992. Radian Corporation, telephone conversation on 8/12/92.
Hoffman, Mark S. (editor). 1991. , The World Almanac and Book of Facts 1992, Pharos
Books, New York, N.Y.
IPCC (Intergovernmental Panel on Climate Change). 1992. Climate Change 1992: The
Supplementary Report to the IPCC Scientific Assessment. Report prepared for
Intergovernmental Panel on Climate Change by Working Group 1.
Jones, Donna Lee. 1992. "National Estimates of Methane Emissions from Compressors in
the U.S. Natural Gas Industry," 7992 AWMA Paper, Kansas City, MO.
Katemisz, John P.. 1985. , "Portable Pipeline Evacuation Compressor," NOVA Corporation of
Alberta Technical Report; Calgary, Canada.
McManus, J.B., et al. 1992. Methane Emissions from Natural Gas Distribution Systems, Final
Report prepared for the U.S. Environmental Protection Agency Global Change Division
and the Gas Research Institute Environmental and Safety Research Department.
Lander, David and Diane Broomhall. 1991. "Reduced NOX Emissions from Internal Combus-
tion Engines Fuelled by Natural Gas," FUEL (April 1990); pp. 499-502.
Martin, Linda. 1992. AGA, phone conversation on 2/10/92.
Novak, Brad. 1992. Johnson Matthey; phone conversations in June 1992.
Oman Holdings International Co. LLC. and Sealweld Corporation. 1991. "Valve Maintenance
Campaign of the Government Gas Transmission System for Petroleum Development -
Oman, Contract No: C 95508," Muscat, Sultanate of Oman and Calgary, Canada.
2-56
-------
PG&E (Pacific Gas and Electric). 1986. Methods to Reduce Natural Gas Control Bleed Rates,
TECC Group, Inc., Littleton, CO.
PG&E (Pacific Gas and Electric). 1990. Unaccounted for Gas Project Summary Volume,
PG&E Research and Development; San Ramon, CA; GRI-90/0067.1.
Parr, C.H., C.J. Kuhlman, S. Roy, K. Pagalthivarthi, D.R. Stephens, T.J. Kilinski, R.B. Francini,
and G. Newaz. 1993. Long-Term Reliability of Gas Pipeline Repairs by Reinforced
Composites. Southwest Research Institute, San Antonio, TX; Battelle Memorial
Institute, Columbus, OH; and Gas Research Institute, Chicago IL. March 1993.
Pees, N.C. and B. Cook. 1992. "Applicability of Oklahoma's Air Toxic Rule to Natural Gas
dehydrator Units," Air Quality Service, Oklahoma State Department of Health in
Proceedings - 1992 Glycol Dehydrator Air Emissions Conference, Gas Research
Institute, July 20-22, 1992.
Radian. 1992a. Estimate of U.S. Methane Emissions - Production Segment (Draft Peer Review
Report), Radian; Austin, TX.
Radian. 1992b. U.S. Natural Gas Industry Methane Emissions Mitigation and Cost Benefit
Analysis, Radian, Austin, TX.
Radian. 1992c. "Venting and Flaring Emissions from Production, Processing, and Storage in
the U.S. Natural Gas Industry," Updated Draft Report prepared for the U.S. EPA and
the Gas Research Institute
Shaw, Howard C. 1981. "Reciprocating versus Centrifugal Compressors," Pipeline Industry
(May 1981), pp. 39-43.
SOCAL (Southern California Gas Company). 1992. Unaccounted for Gas Project Summary
Volume (in preparation), SOCAL Research and Development; Los Angeles, CA.
Starrett, Tracy L. 1992. 'Toxic Air Emissions from Louisiana Glycol Dehydrators," Louisiana
Department of Environmental Quality , Air Quality Division in Proceedings - 1992 Glycol
Dehydrator Air Emissions Conference, Gas Research Institute, July 20-22, 1992.
Tilkicioglu, B.H. and D.R. Winters. 1989. Annual Methane Emissions Estimates of the Natural
Gas and Petroleum Systems in the U.S., Pipeline Systems, Inc.
Tilkicioglu, B.H. 1990. Annual Methane Emissions Estimates of the Natural Gas Systems in
the U.S. - Phase II, Pipeline Systems, Inc.
Unnasch, S. and C.B. Moyer. 1989. "Comparing the Impact of Different Transportation Fuels
on the Greenhouse Effect," California Energy Commission, March 1989, pp. 232-261.
USEPA (U.S. Environmental Protection Agency). 1983. Equipment Leaks of VOC in Natural
Gas Production Industry, USEPA; Research Triangle Park, NC.
USEPA (U.S. Environmental Protection Agency). 1993. Anthropogenic Methane Emissions in
the United States, Report to the Congress, prepared by the Global Change Division,
Office of Air and Radiation, EPA, Washington, D.C.
2-57
-------
Watts, Jim (editor). 1989. Brown's Directory of North American and International Gas
Companies, 103rd Edition, Jim Donnelly, Dallas TX.
Watts, Jim (editor). 1990. "25th Distribution Piping Report," Pipeline and Gas Journal
(December 1990); pp. 14-15.
Watts, Jim (editor). 1991. The 11th P&GJ 500 Report," Pipeline and Gas Journal (September
1991); pp. 12-48.
Webb, Mike. 1992. Star Environmental; phone conversation - 5/8/92.
White, Gerald W. 1992. 'Technology Application Summary of Magion Plated Seals that
Reduce Fugitive Emissions," White Engineering Corporation, Dallas, TX.
2-58
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CHAPTER 3
OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM COAL MINING
Coal Mine Methane Emissions Reductions
Share of U.S.
Emissions Reductions
ID
8
6
e . -7
6 5_
, a
Pro-f I tab I e
Reciuct i ons
Rema i n i ng
Em 1 ss I ons
Low H i gin
199O
Low H ! g h
2OOO
Low H I gtn
2O1O
Coal Mine Methane Emissions (Tg)
Year Baseline Emissions*
1990
2000
2010
a Source: USEPA (1993)
period examined.
3.6 - 5.7
3.7 - 6.5
5.0 - 8.7
. Baseline emissions
Emissions with Technically
Feasible Reductions
-
2.4 - 4.1
3.1 - 5.3
reflect methane recovery of 0.25 Tg
Emissions with
Profitable Reductions
~
3.0 - 4.6
3.6 - 5.9
per year throughout the
CHAPTER SUMMARY
Many coal mines simultaneously could reduce
their methane emissions and generate a profit.
The economic model developed for this Chapter
and the present experience of several coal mine
methane recovery projects confirm that the
economics of coalbed methane recovery are
quite favorable. Significantly, this analysis dem-
onstrates that a considerable number of other
large and gassy coal mines have the potential to
recover methane for a profit if the most constrain-
ing legal, regulatory, and institutional barriers are
removed. Development of recovery and utilization
projects at these mines would result in substantial
reductions in the quantity of methane released
into the atmosphere each year from coal mining
activities. Although the precise prospects for
coalbed methane recovery projects are depen-
dent upon such factors as future economic
conditions and the amount of coal mined from
large and gassy mines, this analysis concludes
that a core group of mines should be able to
recover methane profitably even under the most
pessimistic of assumptions.
Technologically Feasible Reductions
It should be technologically feasible to recover
about 60 percent of methane released during
mining at most large and gassy underground
mines. For purposes of this report, large and
gassy underground mines are defined as those
that have annual coal production greater than 0.5
3-1
-------
Chapter Summary
million tons and methane emissions per ton
greater than 500 cubic feet per ton. Methane
recovery is not considered to be technologically
feasible at surface mines or at small, less gassy
underground coal mines at this time. In 1988, the
latest year for which detailed data are available
on coal production and emissions at under-
ground mines, over 60 mines could be classified
as large and gassy. The amount of methane
released by these mines during 1988 is estimated
to have been between 1.5 and 2.1 Tg,1 which
accounted for 85 to 90 percent of all methane
released from U.S. underground coal mines
during that year and about 65 to 70 percent of
total methane released from all coal mining
activities in the U.S. By 2000, technologically
feasible emissions reductions that could be
achieved at large and gassy mines are projected
to be in the range of 1.6 to 2.7 Tg of methane,
which would represent between 50 and 55 per-
cent of projected emissions from underground
mines. Similarly, by 2010, large and gassy mines
should be able to recover from 2.2 to 3.7 Tg.
Profitable Reductions
Methane emissions from coal mines can be
reduced cost-effectively by an estimated 1.0 to
2.2 Tg in 2000 and by 1.7 to 3.1 Tg in 2010. This
corresponds to a reduction of 32 to 44 percent of
projected emissions from U.S. coal mines in 2000
and 40 to 45 percent in 2010. The estimated
emissions reduction and the associated number
of mines that would develop coalbed methane
projects are shown in Exhibit 3-1.
The emissions reduction that could be achieved
by the development of recovery projects at coal
mines would make a substantial contribution
towards reducing annual emissions of green-
house gases in the United States. For example,
in terms of the global warming potential, the
emissions reductions cited for the year 2000
would be the equivalent of the CO2 output from
approximately 4 to 9 million cars. Furthermore,
the annual energy savings of utilizing this other-
wise wasted resource is the equivalent of 2 to 5
million tons of bituminous coal.
In addition to the environmental and energy
benefits that would result from the development
of coalbed methane recovery and utilization
projects, coal mines are expected to receive
significant economic benefits. For example, the
net present value of developing recovery and
utilization projects at the largest and gassiest
mines may exceed $30 million dollars per project
under some conditions. In addition, the mines
receive benefits associated with increased pro-
ductivity, lower ventilation requirements and
costs, and improved mine safety.
The profitability of a recovery and utilization
project for an individual mine and the total num-
ber of mines that will find it profitable to recover
methane will vary based on several key economic
factors affecting coalbed methane recovery
projects. These factors include the wellhead gas
price, the portion of released methane that is
recoverable, capital costs for recovery and utiliza-
tion, and disposal costs for water produced from
vertical wells. The results shown in Exhibit 3-1
reflect a 'base case" scenario, which assumes
average or slightly conservative values for these
key economic factors.
This analysis also examines the impact on the
overall potential for methane recovery under
different assumptions for these key factors. For
example, the wellhead gas prices assumed in the
base case are $2.25/mcf (thousand cubic feet) in
2000 and $3.00/mcf in 2010. Exhibit 3-2 shows
the impact on overall recovery when the wellhead
gas price is decreased by 75 cents (to $1.50 in
2000 and to $2.25 in 2010) and when it is in-
creased by 75 cents (to $3.00 in 2000 and to
$3.75 in 2010).
The emissions reduction potential increases
significantly when higher gas prices are assumed
-- by 0.3 Tg in 2000 and by 0.1 Tg in 2010.
Similarly, when a lower gas price is assumed, the
potential emissions reduction decreases by 0.5
Tg in 2000 and 0.3 Tg in 2010. While there is a
significant decrease in the emissions reduction
when a lower wellhead gas price is assumed, the
potential for significant emissions reductions
remains robust, because a core group of the
gassiest mines continues to show a strong
potential to recover for a profit. Additionally,
these low wellhead gas prices ($1.50 in 2000 and
$2.25 in 2010) are conservative in terms of cur-
rent wellhead gas price projections. Accordingly,
1 This amount includes 0.25 Tg that was recovered and utilized rather than emitted to the atmosphere.
3-2
-------
Chapter Summary
Exhibit 3-1
Projected Emissions and Potential Profitable Emission Reductions
For Underground Mines
Methane Released from Underground Mines (Tg)a
Profitable Emissions Reductions (Tg)b
Percent Reduction of Methane Released
Number of Mines Recovering
Low
3.2
1.0
32%
16
2000
Mid
3.9
1.4
36%
19
High
5.0
2.2
4-1%
25
a Methane released is the total amount of methane that would be emitted assuming
were in place. In 1988, six coal mines recovered 0.25 Tg for pipeline sales, and this
least this amount of methane would be recovered in the future.
Low
4.3
1.7
40%
25
2010
Mid
5.2
2.2
43%
27
High
6.8
3.1
45%
29
that no recovery projects
report assumes that at
b The low, mid, and high estimated potential emissions reductions correspond to the low and
emissions scenarios developed in USEPA (1993). See methodology section for more detailed
high projected
explanation.
Exhibit 3-2
Impact of Wellhead
Base Case Gas Price
Lower Gas Price
Higher Gas Price
Wellhead Gas
Price
($/mcf)
$2.25
$1.50
$3.00
Gas Price
2000
Methane
Recovered
(Tg)
1.4
0.9
1.7
on Projected
Emission
Wellhead Gas
No. of Mines Price
Recovering ($/mcf)
19
10
26
$3.00
$2.25
$3.75
Reductions
2010
Methane
Recovered
(Tg)
2.2
2.0
2.3
No. of Mines
Recovering
27
22
30
the corresponding amount of methane recovered
is likely to represent the low range of potential
emissions reductions.
Regional Impacts
Projected emissions and the potential for meth-
ane emissions reductions varied significantly
among the five major underground coal produc-
ing areas examined in this report ~ the Central
Appalachian basin, the Northern Appalachian
basin, the Warrior basin, the western basins, and
the Illinois Basin. Exhibit 3-3 presents the results
from individual basins. The large and gassy
mines of the Central Appalachian basin are
projected to account for an estimated 29 percent
of the potential cost-effective emissions reduc-
tions in 2000 and 23 percent in 2010 - approxi-
mately 0.4 Tg in 2000 and 0.5 Tg in 2010. Most
Central Appalachian basin mines are projected to
have a strong potential to recover, even in cases
in which costs for developing recovery projects
may be high. For example, 5 out of the 7 mines
projected to recover under base case assump-
tions are also projected to recover when higher
capital costs are assumed.
The potential for the development of profitable
emissions reduction projects in the Northern
3-3
-------
Chapter Summary
Exhibit 3-3
Regional Impacts
2000
Methane EmitTed and Recovet ed
Not thern Cential «ai i lor
Appalachian Appalachian
• Methane Recovei ed E
•estern
I Methane Emitted
111inols
and Other
Year 2010
Methane Emitted and Recovered (Tgi
Northern Central Hairier
Appalachian Appalachian
• Methane Recovered |
•e-stern 111.no.-i
and Other
|Methane Emitted
Appalachian basin is also very good; the estimat-
ed number of mines able to recover profitably is
5 in 2000 and 10 in 2010. These mines would
reduce emissions by approximately 0.3 Tg in
2000 and 0.7 Tg in 2010. However, unlike a
majority of the Central Appalachian basin mines,
some Northern Appalachian basin mines may not
be able to recover when faced with higher than
average costs for developing projects.
Though the Warrior Basin has the fewest under-
ground mines of any of the basins, its mines are
the gassiest At least 5 Warrior basin mines in
2000 and in 2010 are expected to be able to
recover for a profit. The projected emissions
reduction from mines recovering in the Warrior
basin is approximately 0.4 Tg in 2000 and 0.6 Tg
in 2010, which would reduce total methane
emissions from underground coal mines in the
U.S. by approximately 31 percent in 2000 and 27
percent in 2010.
The potential emissions reduction from Western
basin mines is approximately 0.2 Tg in 2000.
This reduction is associated with recovery pro-
jects at an estimated 3 mines and represents
approximately 40 percent of projected under-
ground emissions from all Western basin mines.
Due to the impact of acid rain legislation, coal
production in low sulfur western mines is expect-
ed to increase by 180 percent between 1988 and
2010 - the largest projected increase for any
region. Accordingly, the number of large and
gassy mines in western basins with the potential
to recover and utilize methane is also projected to
increase. The potential emissions reduction is
projected to double between 2000 and 2010; an
estimated 0.4 Tg could be recovered in 2010.
The Illinois basin is projected to account for only
9 percent of total methane emissions from under-
ground mines in 2000 and 11 percent in 2010.
Of the five major underground coal basins, the
Illinois basin mines are the least gassy. Unless
future production from this basin comes from
gassier coal seams, profitable emissions reduc-
tions do not appear to be achievable in the Illinois
basin.
Effective Methane Reduction Strategies
Several effective methane recovery and utilization
options are currently available for coal mines.
Potential recovery methods examined in this
analysis include vertical wells drilled two, five, and
ten years in advance of mining, and gob wells
drilled just prior to or during mining. The two
primary utilization options examined in the analy-
3-4
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Chapter Summary
sis are selling recovered methane to a pipeline or
using it to generate electricity for on-site use or
off-site sale to a utility.
Drilling vertical wells ten years in advance of
mining is the preferred recovery method in terms
of achieving the highest methane emissions
reduction. By employing this method, individual
mines can recover from 50 to over 70 percent of
the methane that would otherwise be released
during mining.2 Furthermore, this analysis shows
that drilling vertical wells ten years prior to mining
will lead to the highest profits for individual mines.
Accordingly, in comparing the potential recovery
methods, this method maximizes the number of
mines showing the potential to recover methane
for a profit.
Exhibit 3-4 compares the estimated number of
mines that are likely to recover methane for a
profit if they were to use vertical wells or gob
wells and were to sell the recovered methane to
a pipeline. As shown in this exhibit, compared to
other vertical well options, drilling ten years in
advance of mining shows a larger number of
mines recovering -19 mines in 2000 compared
to 17 for five year vertical wells and 7 for two year
vertical wells. Moreover, degasification ten years
in advance of mining shows a much higher
estimated emissions reduction -- 1.4 Tg in 2000
compared to 1.0 Tg for five year degasification
and only 0.3 Tg for two year degasification.
Gob wells can also be an effective recovery
method for pipeline injection, assuming that the
gob gas would not need to be enriched to pipe-
line quality. As shown in Exhibit 3-4, when en-
richment is not required, in terms of the projected
number of mines that could recover for a profit,
the gob well recovery method produces results
identical to the ten year vertical well method.
However, in terms of overall emissions reductions,
assuming all coal mines selected gob well recov-
ery, they collectively would recover slightly less
methane than when five year vertical wells are the
assumed recovery method.
Although several mines in the Black Warrior and
Central Appalachian basins are currently produc-
ing pipeline quality gas from gob wells without
enrichment, recovery of high quality methane
from gob wells may not be technically feasible for
all mines. In such cases the gob gas would need
to be enriched to pipeline quality. Because
enrichment technologies have not yet been used
for coal mine methane on a commercial basis, the
costs for this process are highly uncertain.
However, assuming that gob gas could be en-
riched at a cost of $1/mcf of gas produced, only
an estimated 5 mines in 2000 and 16 in 2010
could profitably recover methane for pipeline
sales. If the costs of enrichment are in the range
of $2/mcf, moreover, the number of profitable
projects falls to 0 for both 2000 and 2010.
The results in Exhibit 3-4 assume that mines will
sell methane recovered from vertical or gob wells
to pipeline companies. Results are shown for
pipeline injection because, for most mines, this
option is likely to be more profitable than using
the methane to generate power for on-site use or
sale to utilities. For example, for many of the
largest and gassiest mines, the net present value
of a pipeline injection project will be from 5 to 10
times greater than the net present value of a
power generation project. However, power
generation can also be an economically attractive
option for some mines. Power generation may be
the most cost-effective utilization strategy for
mines that: 1) were not within a feasible distance
to a pipeline; 2) were able to receive a high price
for electricity relative to the price received for gas
sold to pipelines; or, 3) were unable to recover
pipeline quality methane from their gob wells.
Impact of Including Environmental Benefits
From the perspective of social benefits, the value
of coal mine methane projects is underestimated
because the revenue estimates (from selling gas
or electricity) do not include the environmental
benefits that result from utilizing rather than
emitting the methane released from mines. By
omitting these benefits, profitability decisions
made by individuals do not reflect the full value of
the project.
Including the environmental benefit to society of
emissions reductions would lead to a significant
increase in the amount of methane recovered.
Even at a low value of $5 per ton of carbon emis-
The range of potential recovery is based on estimates discussed in USEPA (1990) and USEPA (1991).
3-5
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Chapter Summary
Exhibit 3-4
Estimated Potential Profitable Emissions Reductions: Comparison of Results for
Different Recovery Methods for Pipeline Projects
Recovery Method
Vertical Wells: 10 Year (Base Case)
Vertical Wells: 5 Year
Vertical Wells: 2 Year
Gob Wells: Enrichment Not Required
Gob Wells: Low Enrichment Costs ($1/mcf)
Gob Wells: High Enrichment Costs ($2/mcf)
Recovery
Percentage
(Per Mine)
60%
45%
24%
40%
40%
40%
Year 2000
Tg No. of Mines
Recovered Recovering
1.4 19
1.0 17
0.3 7
0.9 19
0.3 5
0 0
Year 2010
No. of
Tg Mines
Recovered Recovering
2.2 27
1.7 27
0.6 15
1.5 27
1.1 16
0 0
sions reduced ($0.57 per mcf methane),3 an addi-
tional 0.2 Tg of methane could be recovered in
2000 and in 2010. At a value of $20 per ton, the
incremental emissions reduction would be 0.4 Tg
in 2000 and 2010. Finally, at a value of $100 per
ton, all technologically feasible emissions reduc-
tions could be achieved. The emissions reduc-
tions would be about 2 Tg in 2000 and 2.8 Tg in
2010 -- about 0.6 Tg higher than if no financial
subsidy were place. With a value of $100 per
ton, nearly 70 mines in 2000 and 2010 would find
it profitable to develop methane recovery pro-
jects.
Current Recovery and Utilization Projects
U.S. experience demonstrates that selling recov-
ered methane to a pipeline can be profitable for
mining companies. Eleven mines (5 in Alabama,
5 in Virginia, and 1 in Utah) currently sell meth-
ane from their degasification systems to local
pipeline companies. These mines not only
generate revenue from the sale of recovered gas,
but also realize significant energy savings due to
a reduced need for air to ventilate the mines.
Current pipeline projects are summarized in
Exhibit 3-5.
Barriers to Methane Recovery
While a number of U.S. coal mines are already
profitably recovering methane for sale to natural
gas pipelines, many coal mines face economic,
institutional, and technological barriers that distort
the economics of developing methane recovery
and utilization projects. In many cases, the
barriers are legal or institutional and could be
addressed through regulatory or legislative action
at the federal or state level. Production tax
credits and other incentives that consider the
environmental benefits of methane recovery could
encourage mines to recover additional methane
while research support could reduce or eliminate
technological barriers.
Unresolved legal issues concerning the owner-
ship of coalbed methane resources have consti-
tuted one of the most significant barriers to
coalbed methane recovery, particularly in the
Appalachian states. Ambiguity in certain state
legal systems provides a disincentive for invest-
ment in coalbed methane projects because of the
uncertainties as to which parties may demand
compensation for development of resources.
Potentially, ownership could rest with the holder
of the coal rights, the owner of the oil and gas
The estimate of the value of avoiding methane emissions is calculated using the GWP for methane of 22, and the
ratio of the weight of carbon to the weight of carbon dioxide (12/44).
3-6
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Chapter Summary
Current Coal
Mining Company
Jim Walter Resources
U.S. Steel Mining
Consolidation Coal
Island Creek Coal
Soldier Creek Coal
Exhibit 3-5
Mine Methane Pipeline
No. of Mines
4
1
1
4
1
Projects
State
Alabama
Alabama
Virginia
Virginia
Utah
rights, the surface rights owner, or some combi-
nation of the three. As part of the Energy Policy
Act of 1992 (Public Law 102-486), states will be
required to develop a mechanism to address
ownership issues.4 One option, enacted by
Virginia, is to force pooling of all potential inter-
ests in the resource. Under forced pooling, until
such time as ownership is decided, payment of
costs or proceeds attributable to the conflicting
interests are paid into an escrow account. This
legislative effort has contributed to the rapid
development of coalbed methane projects in
Virginia.
Even where ownership issues have been re-
solved, certain conditions and characteristics of
the coal mining industry may still prevent invest-
ment in methane recovery projects. Market
uncertainty, preferences for investments in coal
mine productivity, and the relative newness of the
concept of utilizing methane from coal mines are
factors that may deter methane recovery and
utilization in conjunction with coal mining opera-
tions. This barrier partially could be addressed
by disseminating information on successful coal
mine methane recovery projects at all levels of
government.
While not necessary to make coalbed methane
production economical, a financial incentive
would reduce the financial risks associated with
initiating coalbed methane production, particularly
in new coal basins. Also, as mentioned previous-
ly, it may be desirable to develop some type of
financial incentive that would reflect the environ-
mental benefits of reducing methane emissions.
Since 1979, producers of unconventional gas
resources, including coalbed methane, have been
eligible to receive the "Section 29" (I.R.S. Code
Section 29) production tax credit. In regions
where ownership issues have not been a critical
barrier, this tax credit has spurred the developed
of coalbed methane production projects. The
eligibility of coalbed methane production under
the Section 29 tax credit expired in 1992, howev-
er, and gas produced from coalbed methane
wells is now only eligible for the credit if the wells
were drilled prior to the expiration date.5 There-
fore, there are no existing financial incentives that
will encourage future methane recovery at coal
mines.
For most mines, selling recovered methane to a
pipelines is likely to be more advantageous than
using the methane to generate power. One of
the most significant barriers to pipeline sales,
however, is that new gas producers may be
unable to gain access to existing pipelines due to
limited capacity. Though this barrier is not
unique to coal mine methane pipeline projects,
pipeline capacity is severely limited in the major
underground coal producing Appalachian region,
due to the large amount of gas being transported
from major gas producing areas in the southern
U.S. to the northeastern demand centers. These
constraints may make it difficult for coalbed
Those states determined by the Secretary of Interior to lack statutory or regulatory procedures for addressing
ownership concerns will have three years to enact such a program. If the state does not act, the Secretary of Interior
will impose a forced pooling mechanism similar to that enacted in Virginia.
5 Under the Energy Policy Act of 1992, the Section 29 tax credit was extended for other types of unconventional gas
production, but coalbed methane is no longer eligible for the production incentive.
3-7
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Chapter Summary
methane producers to gain firm access to pipe-
lines or may necessitate the construction of long
gathering systems to move gas from production
areas to pipelines with capacity. Accordingly, it
may be desirable to consider legislative means of
encouraging and/or expediting new pipeline
construction.
Another impediment to the development of pipe-
line projects is that some mines may be unable to
recover high quality methane from gob wells.
Funding of research and development efforts is
needed to find ways of lowering the cost of
technologies for gas purification, which may be
required to enrich gob gas to pipeline quality.
Such research efforts could be carried out at the
federal level by EPA or DOE, at the state level, or
by other organizations, such as the Gas Re-
search Institute. The Energy Policy Act of 1992
mandates the establishment of a coalbed meth-
ane recovery demonstration and commercial
application program that will emphasize the
development of advanced coalbed methane
utilization technologies. The program is to ad-
dress technologies for gas enrichment, technolo-
gies to use mine ventilation air in nearby power
generation facilities, and technologies for co-firing
coalbed methane together with coal in conven-
tional or clean coal technology boilers. The
demonstration and commercial application pro-
gram is an important first step toward encourag-
ing the development of advanced coalbed meth-
ane utilization technologies, and it is important
that this program be adequately funded and fully
implemented.
As with pipeline projects, coal mine power pro-
jects face a host of non-technological barriers,
some of which are common to most producers of
alternative energy and others that are more
unique to coal mine methane recovery projects.
Coal mines interested in generating power for on-
srte use will encounter impediments similar to
those faced by co-generators, including the fact
that utilities may discourage such projects due to
their concern over losing a large customer. This
problem may be particularly significant for coal
mines, given that utilities are likely to be the
largest purchaser of their coal.
A current potential barrier to the sale of electricity
to utilities is that coal mine methane projects may
not be granted qualifying facility status by the
Federal Energy Regulatory Commission (FERC).
Under the Public Utilities Regulatory Policies Act
of 1978 (PURPA), alternative energy producers
meeting certain size, ownership, and fuel use
requirements are designated as qualifying facili-
ties (QFs). As specified in PURPA, electric utili-
ties must purchase power from QFs at rates
equal to their "avoided cost" of generating elec-
tricity. QF status for coal mine projects, however,
is dependent upon whether the FERC classifies
coal mine methane as "waste gas." Ensuring that
coal mine methane power generation projects are
granted QF status will enable coal mines to sell
electric power at avoided cost rates.
While granting QF status to coal mine methane
projects is one step to overcoming obstacles to
generating power, other barriers that are faced by
most producers of alternative energy may also
prevent project development at coal mines. The
most significant barrier is low utility buy-back
rates. Electric utilities in many coal producing
regions have excess capacity and low generating
costs. They therefore have little incentive to
purchase power generated from coal mine meth-
ane for use in their systems or for transmission to
another utility. Under the Energy Policy Act of
1992, QFs that produce electricity from renewable
energy sources are eligible for a subsidy of one
cent per kWh of electricity produced. Electricity
generated from coal mine methane, however, is
not considered eligible for this incentive. A
change in the eligibility requirements for this
subsidy should be considered in order to spur
methane power generation projects.
In conclusion, although this analysis shows that
a large portion of methane emissions from coal
mining can be recovered profitably, effective
strategies must be implemented to address the
barriers discussed in this section.
3.1 BACKGROUND
The economics of coalbed methane recovery dictate that the more methane a mine
emits, the more likely it will be able to recover methane profitably. The amount of methane a
particular mine releases to the atmosphere is a product of the mine's annual coal production
3-8
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tonnage and the methane emissions per ton of coal mined. Emissions per ton is perhaps the
single most important factor in determining whether a mine can recover methane for a profit.
Emissions per ton depends on the depth of the coal and on the gassiness of the type of coal
being mined; deeper coals and coals with a higher carbon content are typically accompanied
by increased methane levels. Because of the significant fixed costs associated with mining in
deep seams, deep mines also tend to be fairly large in terms of annual coal production.
These large and gassy mines, located primarily in the Central Appalachian, Northern
Appalachian, and Warrior basins, are the most significant emitters of methane and are strong
candidates for the application of methane recovery and utilization techniques.
3.1.1 Factors Influencing Methane Emissions from Coal Mining
Methane and coal are formed together during coalification, a process in which swamp
vegetation is converted by geological and biological forces into coal. Methane is stored in
large quantities within coal seams and also within the rock strata surrounding the seams.
Two of the most important factors determining the amount of methane that will be stored in a
coal seam and the surrounding strata are the rank and the depth of the coal. Coal is ranked
by its carbon content; coals of a higher rank have a higher carbon content and generally a
higher methane content.6 Pressure, which increases with depth, tends to keep methane in
coal seams and surrounding strata from migrating to the surface. Thus, within a given coal
rank, deep coal seams tend to have a higher methane content than shallow ones.
Because methane concentrations increase with depth, underground mines tend to
release significantly higher quantities of methane per ton of coal mined than do surface
mines. In fact, as shown in Exhibit 3-6, while only 40 percent of U.S. coal is produced in
underground mines, these mines account for over 70 percent of estimated methane
emissions from coal mining.7
In underground mines, the mining method used has an impact on the amount of
methane that will be released during mining. Two methods are used in the U.S. - longwall
and room-and-pillar.8 The longwall technique tends to cause a more extensive collapse of
the methane-charged strata above the coal seam. Consequently, longwall mines tend to emit
more methane per ton of coal extracted than do room-and-pillar mines. Room-and-pillar
mining is the more common method; however, the number of longwall mines is growing. The
longwall technique is common in some of the largest and gassiest underground mines in the
U.S. -- those with the greatest potential for profitable recovery.
3.1.2 Candidate Mines for Profitable Methane Recovery
The low methane content of surface mined coals virtually eliminates the potential for
profitable recovery and use of methane released during mining. Therefore, options for
recovering and utilizing methane were evaluated for underground mines only.
6 In descending order, the ranks of coal are: Graphite, Anthracite, Bituminous, Subbituminous, and Lignite.
Most U.S. production is Bituminous or Subbituminous.
7 More information on methane emissions from U.S. surface and underground coal mines is available in
USEPA (1993).
8 More information on these mining techniques is available in USEPA (1990).
3-9
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Exhibit 3-6
1988 Coal Production and Estimated Methane Emissions -
Surface and Underground Mines
Mining Method
Coal Production
(thousand short tons)
Estimated
Methane Emissions
(teragrams)
Surface
Underground
Post-mining Emissions8
Total U.S. Emissions
Methane recovered
584,929
392,618
977,547
0.5 - 0.7
2.6 - 3.7
0.5 - 0.8
3.5 - 5.4
0.25
Sources: Methane Emissions (USEPA 1993); Coal Production (USDOE/EIA 1989)
a Though most methane is emitted during mining, extracted coal continues to emit
methane during transport, processing, and storage.
Most underground mining occurs in the eastern United States in the Northern and
Central Appalachian Basins (primarily Pennsylvania, West Virginia, Kentucky, Tennessee and
Virginia), the Warrior Basin (Alabama), and the Illinois Basin (Illinois and western Kentucky).
Underground mines are also located in the western states of Utah, Colorado, and New
Mexico.
Methane emissions per ton of coal mined is one of the most important factors in
determining the potential for a coal mine to recover methane for a profit. The methane
content of underground mined coals varies significantly by basin due to the types of coals
being mined, the depths of the mined seams, and other geologic factors. For example, in the
Illinois Basin, the average depth for underground mines is 500 to 1,000 feet and the average
methane emissions per ton of coal mined is approximately 160 to 190 cf/ton. In contrast, the
average depths for underground mines of the Warrior Basin is 1,000 to 2,000 feet and the
average methane emissions per ton of coal mined is approximately 2,500 cf/ton (USEPA
1993).
Exhibit 3-7 shows the number of large underground mines (those with annual coal
production exceeding 0.5 million tons) in each basin that have high methane emissions per
ton of coal mined. The Northern Appalachian has the greatest number of mines (25) with
methane emissions per ton of at least 500 cf/ton, however, the Central Appalachian basin has
the greatest number of mines (8) with emissions per ton of over 2000 cf/ton. Illinois basin
mines are the least gassy; while 8 mines in this basin have emissions per ton greater than
500 cf/ton, no mines have emissions per ton greater than 1000 cf/ton. In contrast, most of
the mines in the Western and Warrior basins that exceed 500 cf/ton also exceed 2000 cf/ton.
Another important factor determining a mine's potential for profitable methane recovery
is annual coal production. Annual coal production indicates the total amount of methane that
could be recovered each year, as well as a number of other factors such as the potential for
a mine to finance the large capital investments required for a methane recovery and utilization
3-10
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project. As shown in Exhibit 3-7, all of the five major coal basins contain a number of large
and gassy mines. In the U.S., due to the significant costs associated with mining in deep
seams, deep and gassy mines also tend to be fairly large in terms of annual coal production.
These largest and gassiest mines will have the greatest potential to recover methane
for a profit. Accordingly, as shown in Exhibit 3-7, several mines in the Northern and Central
Appalachian basins, the Warrior Basin, and the western basins show a strong potential for
profitable recovery. In addition to annual coal production and methane emissions per ton of
coal mined, several key economic factors such as proximity to a commercial pipeline are also
important indicators of the potential attractiveness of the application of recovery and utilization
techniques and, moreover, of the techniques that will be most economic for each mine.
Exhibit 3-7
Estimated Number of Large Mines in 1 988a with High
Methane Emissions per Ton of Coal Mined5
Basin
Central Appalachia
Northern Appalachia
Illinois
Warrior
Western Basins
TOTAL
Estimated Number of Mines
cf/ton > 500 of/ton > 1000 cf/ton > 2000
14 11 8
25 11 3
800
875
855
63 34 21
a Large mines are those with annual coal production exceeding 0.5 million
tons. Annual coal production is based on Keystone (1988).
b Gassiness level for each mine is based on average of high and low
emissions estimates for individual mines as described in USEPA (1993).
3.2 OVERVIEW OF METHANE RECOVERY AND UTILIZATION METHODS
Several well demonstrated methods are available for recovering methane from
underground coal mines. In some cases, these methods are currently used to control
methane hazards in underground mines. The methane recovered using these techniques is
often a high quality fuel that can be used as an energy source. The two principal options for
utilizing the methane recovered from coal mines are to sell it as pipeline-quality natural gas or
to use it to generate electricity at the mine.
3.2.1 Recovery Methods
In underground mines, methane poses a serious safety hazard for miners because it is
explosive even in low concentrations. By law, methane concentrations may not exceed one
3-11
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percent in mine working areas and two percent in all other locations. In some underground
mines, methane emissions can be controlled using ventilation systems alone. In particularly
gassy mines, however, the ventilation system must be supplemented with at least one other
degasification system. Degasification systems reduce the quantity of methane in the working
areas by recovering the gas before, during, or after mining, depending on mining needs. In
1988, emissions from degasification systems were estimated to account for one-fourth to
nearly one-half of the total methane emissions from underground coal mining (USEPA 1993).
While degasification systems are currently used primarily for economic and safety
reasons to ensure that methane concentration remain below acceptable levels, these systems
can recover methane that can be utilized as an energy source. The quantity and quality of
the methane recovered will vary according to the method used. The quality of the recovered
methane is measured by its heating value. Pure methane has a heating value of about 1000
BTU/cf (British Thermal Units per cubic foot), while a mixture of 50 percent methane and 50
percent air has a heating value of approximately 500 BTU/cf. Degasification methods include
vertical wells, gob wells, and horizontal and cross-measure boreholes. The preferred recovery
method will depend, in part, on how the methane will be utilized. In some cases, an
integrated approach using a combination of one or more of these methods will lead to the
highest recovery of methane. The key features of the methane recovery methods are
summarized in Exhibit 3-8 and are discussed in more detail below. Additionally, a diagram of
the recovery methods is shown in Exhibit 3-9.
Exhibit 3-8
Summary of Methods for Recovering Methane from Underground Mines
Method
Vertical Wells
Gob Wells
Horizontal
Boreholes
Cross-
measure
Boreholes
Description
Drilled from surface
to coal seam
several years in
advance of mining.
Drilled from surface
to a few feet above
coal seam just prior
to mining.
Drilled from inside
the mine to degasify
the coal seam.
Drilled from inside
the mine to degasify
surrounding rock
strata.
Methane Quality
Recovers nearly
pure methane.
Recovers methane
that is sometimes
contaminated with
mine air.
Recovers nearly
pure methane.
Recovers methane
that is sometimes
contaminated with
mine air.
Recovery
Efficiency8
up to 70%
up to 50%
up to 20%
up to 20%
Current Use in
U.S. Coal Mines
Used by at least 3
U.S. mining
companies in
about 10 mines.
Used by over 30
mines.
Used by over 10
mines.
Not widely used in
the U.S.
Sources: USEPA 1990; USEPA 1991; Northwest Fuel 1990.
a Percent of methane recovered that would otherwise be emitted.
3-12
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Exhibit 3-9
Diagram of Methods for Recovering Methane from Underground Coal Mines
Mined Area Unmln«d Ar««
Vertical Gob Well
Vertical Degaslflcation Well
F1U«r Flam* Arr*»t«r
Cross Measure and
Horizontal Boreholes
Surface Equipment
Vertical Wells
The optimal method for recovering high quality methane is to pre-drain the methane
from the coal and surrounding strata before mining operations begin. Pre-drainage ensures
that the recovered methane will not be contaminated with ventilation air from mine working
areas. Similar in design to conventional oil and gas wells, vertical wells can be drilled into the
coal seam several years in advance of mining, and usually require hydraulic fracturing of the
coal seam to activate the flow of methane. Vertical wells typically produce gas of over 90
percent purity. However, these wells may produce large quantities of water and small
volumes of methane during the first several months they are in operation. As this water is
removed and the pressure in the coal seam is lowered, methane production increases.
The total amount of methane recovered using vertical pre-drainage will depend on the
number of years the wells are drilled prior to the start of mining. Recovery of from 50 to over
70 percent of the methane that would otherwise be emitted during mining operations is likely
3-13
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for operations drilling vertical degasification wells more than 10 years in advance of mining.9
Although not widely used in the coal mining industry, vertical wells are used by numerous
stand-alone10 operations that produce methane from coal seams for sale to natural gas
pipelines. In some very low permeability coal seams, vertical wells may not be a cost-
effective technology due to limited methane flow. Furthermore, there is some concern that in
certain geologic conditions the hydraulic fracturing may cause damage to the roof rock,
which would hinder mining operations. However, vertical wells are likely to be a viable
recovery technology for most underground mines.
Gob Wells
The fractured zone caused by the collapse of the strata surrounding the coal seam in
longwall and room-and-pillar mining is known as a "gob" area, and it is a significant source of
methane. Gob wells are drilled from the surface to a point 2 to 15 meters above the target
seam prior to mining. As mining advances under the well, the methane-charged coal and
strata around the well fractures. The methane emitted from this fractured strata flows into the
gob well and up to the surface. Vacuums are frequently used in gob wells to prevent
methane from entering mine working areas.
Initially, gob wells produce nearly pure methane. Over time, however, additional
amounts of mine air can flow into the gob area and dilute the methane. The heating value of
"gob gas" normally ranges between 300 and 800 BTU/cf. In some cases, it is possible to
maintain nearly pure methane production from gob wells through careful monitoring and
management. For example, the Jim Walter Resources mines in Alabama have been able to
sell methane recovered from their gob wells to pipeline companies. Methane production
rates from gob wells can be very high, especially immediately following the fracturing of the
strata as mining advances under the well. Jim Walter Resources reports that gob wells
initially produce at rates in excess of 56,000 cubic meters per day (2 million cubic feet per
day). Over time, production rates typically decline until a relatively stable rate is achieved,
typically in the range of 2,800 cubic meters per day (100,000 cubic feet per day) (USEPA
1990). Depending on the number and spacing of the wells, gob wells can recover an
estimated 30 to over 50 percent of methane emissions per ton of coal mined (USEPA 1990).
Surface gob wells are currently used by over 30 U.S. underground mines to reduce
methane levels in mine working areas (USEPA 1993). In most mines, methane recovered
from gob wells is released into the atmosphere.
Horizontal Boreholes
Horizontal boreholes are drilled inside the mine (as opposed to from the surface) and
they drain methane from the unmined areas of the coal seam or blocked out longwall panels
shortly before mining. These boreholes are typically tens to hundreds of meters in length.
Several hundred boreholes may be drilled within a single mine and connected to an in-mine
vacuum piping system, which transports the methane out of the mine and to the surface.
Most often, horizontal boreholes are used for short-term methane emissions relief during
9 The range of potential recovery is based on estimates in USEPA 1990 and USEPA 1991.
10 The term "stand-alone" refers to coalbed methane operations that recover methane for its own economic
value. In most cases, these operations recover methane from deep and gassy coal seams that are not likely to be
mined in the near future.
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mining. Because methane drainage only occurs from the mined coal seam (and not from the
surrounding strata), the recovery efficiency of this technique is low - approximately 10 to 18
percent of methane that would otherwise be emitted (USEPA 1990). However, this methane
typically can have a heating value of up to 950 BTU/cf (USEPA 1991). Currently, over 10 U.S.
underground mines use this technique to reduce the quantity of methane in mine working
areas (Northwest Fuel 1990). Additionally, the Soldier Canyon mine in Utah uses longhole
horizontal boreholes to recover methane for sale to pipeline companies.
Cross-Measure Boreholes
While horizontal boreholes recover methane from the target coal seam, cross-measure
boreholes degasify the overlying and underlying rock strata. These boreholes are also drilled
from within the mine and they recover methane with a heating value similar to that of gob
wells. Cross-measure boreholes have been used extensively in Europe but are not widely
used in the United States where surface gob wells are preferred.
3.2.2 Utilization Methods
Recovered methane can be an economic resource for a coal mine because it can be
sold to natural gas pipelines or used to generate power. The ability of a mine to produce
pipeline quality methane and the mine's proximity to existing pipelines are key factors in
determining the technical and economic feasibility of recovering methane for pipeline
injection. The quality of the recovered methane, the capital and operating costs of electricity
generation, and the cost of the mine's purchased electricity are among the main technical
and economic considerations for a power generation project. The main utilization options are
summarized in Exhibit 3-10.
Pipeline Injection
Methane is the primary component of natural gas, and methane from coal seams can
be sold to pipeline companies and injected into natural gas pipelines. The key issues that
will determine project feasibility are: 1) whether the recovered gas can meet pipeline quality
standards; and, 2) whether the costs of production, processing, compression and
transportation are competitive with other gas sources.
U.S. experience demonstrates that selling recovered methane to a pipeline can be
profitable for mining companies. Eleven mines (5 in Alabama, 5 in Virginia, and 1 in Utah)
currently sell methane from their degasification systems to local pipeline companies. These
mines not only generate revenue from the sale of recovered gas, but also realize significant
energy savings due to a reduced need for air to ventilate the mines. Current coal mine
methane pipeline projects are summarized in Exhibit 3-11.
Technical Feasibility
The primary technical consideration involved in pipeline injection is that the recovered
methane must meet the standards for "pipeline quality" gas. First, it must have a methane
concentration of at least 97 percent and contain no more than a 2 percent concentration of
gases that do not burn (i.e., carbon dioxide, nitrogen, helium). Additionally, any non-methane
hydrocarbons (e.g., propane and butane) are usually removed from the gas stream for other
uses. Hydrogen sulfide (which mixes with water to make sulfuric acid) and hydrogen (which
makes pipes brittle) must also be removed before the gas is introduced into the pipeline
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Exhibit 3-10
Utilization Options for Coalbed Methane
Recovery Method
Vertical Degas Wells
Gob Wells
In-Mine Boreholes
Ventilation Air
Range of BTU
Quality
(BTU/cf)
> 950
300 to 950
up to 950
10 to 20
Utilization Options
Pipeline Injection
Power Generation
Pipeline Injection (requires (1) maintaining pipeline quality or (2) gas
enrichment)
Power Generation
Pipeline Injection
Power Generation
Use as combustion air in coal-fired boiler or gas turbine (needs
technical demonstration)
Source: USEPA 1990 and USEPA 1991
Current Coal
Mining Company
Jim Walter Resources
U.S. Steel Mining
Consolidation Coal
Island Creek Coal
Soldier Creek Coal
Exhibit 3-11
Mine Methane Pipeline Projects
No. of Mines
4
1
1
4
1
State
Alabama
Alabama
Virginia
Virginia
Utah
system. Finally, any water or sand produced with the gas must be removed to prevent
damage to the system.
With proper recovery and treatment, coalbed methane can meet the requirements for
pipeline quality gas. While coalbed methane requires water removal, it is often free of
hydrogen sulfide and several other impurities typically found in natural gas. Regardless of the
recovery technique used, methane must be processed and treated to ensure that is of the
requisite quality prior to pipeline injection. Processing includes the removal of water
produced with the methane. Compressors are used to propel the gas through a gathering
line to a pipeline and to compress the gas to the appropriate pressure for injection.
Gathering lines are used to transport methane from several production wells to a central
compressor, and from the compressor to a main commercial pipeline.
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Vertical degas wells are the preferred recovery method for producing pipeline quality
methane from coal seams because pre-mining drainage ensures that the recovered methane
is not contaminated with ventilation air from the working areas of the mine. Gob wells, in
contrast, generally do not produce pipeline quality gas as the methane is frequently mixed
with ventilation air. In certain cases, however, it is possible to maintain a higher and more
consistent gas quality through careful monitoring and adjustment of the vacuum pressure in
gob wells. For example, Jim Walter Resources, Inc. has successfully used gob wells to
recover methane for pipeline injection at its Alabama mines for several years.11
It is also possible to enrich gob gas to pipeline quality using technologies that
separate methane molecules from carbon dioxide, oxygen, and/or nitrogen. Several
technologies for separating methane are under development and may prove to be
economically attractive and technically feasible with additional research.12 A more remote
possibility is the use of these technologies for separating low concentration methane from air
emitted through the ventilation system.
Horizontal boreholes can produce pipeline quality gas when the integrity of the in-mine
piping system is closely monitored. However, the amount of methane produced from these
methods is generally not large enough to warrant investments in the necessary surface
facilities. In cases in which mines are developing utilization strategies for larger amounts of
gas recovered from vertical or gob wells, it may also be possible to use the gas recovered
from in-mine boreholes to supplement production.
Profitability
The overall profitability of recovering methane for pipeline injection will depend on a
number of factors, including the amount and quality of methane recovered and the capital
and operating costs for wells, water disposal, compression and gathering systems. Estimates
of the costs of these items are shown in Appendix A.
Drilling and maintaining vertical or gob wells involves significant expenditures.
However, in gassy mines, gob wells may be required to supplement the ventilation systems
regardless of whether the methane recovered is later utilized. Over 30 U.S. mines, for
example, currently use gob wells, but less than ten use any of the recovered gas (USEPA
1993). Gob wells and vertical degas wells reduce the need for ventilation air by reducing the
quantity of methane emitted into the working areas. Thus, it is important to determine what
portion of the costs of drilling wells is specifically associated with pipeline injection (as
opposed to costs associated with the mining operation) and to take into account the potential
electricity savings from recovering methane that would otherwise need to be diluted with
ventilation air.
The costs for disposal of production water from vertical wells may be a significant
factor in determining the economic viability of a project. Production water often contains high
levels of salt and other minerals and must be disposed of in an environmentally safe manner.
Water disposal costs will vary for individual mines depending on geologic conditions and
state or local environmental regulations. Production water is drained prior to mining activities
11 See, for example, Dixon (1989).
12 More information is available in USEPA 1990.
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regardless of the recovery methods used, though the water table may recharge somewhat if
vertical wells are drilled many years in advance of mining. In some states, however,
environmental regulations applied to water discharged as a result of mining operations may
differ from those applied to water produced from methane recovery operations, and water
produced from coalbed methane recovery operations may require more expensive methods
of disposal.
Because costs for laying gathering lines are high, proximity to existing commercial
pipelines is a significant factor in determining the economic viability of a coalbed methane
project. Costs for laying gathering lines vary widely depending, in part, on terrain. The hilly
and mountainous terrain in many mining areas increases the difficulty, and thus the costs, of
installing gathering lines.
The U.S. has a large network of major natural gas pipelines connecting the natural gas
supply regions of the Southwest, Rocky Mountains, and Allegheny Mountains to the market
areas of the East and West Coasts and the Upper Midwest. In addition to these major natural
gas transmissions lines, there is a vast network of smaller pipelines. Most coal mines are
located within 20 miles of a commercial pipeline (ICF Resources 1990a). However, in some
cases, existing pipelines may have limited capacity for transporting additional gas supplies.
Another determinant of the overall profitability of a pipeline injection project is a mine's
ability to find a pipeline company to purchase its recovered gas. A coal mine would need to
demonstrate to a pipeline company that its recovered methane is of the requisite quality and
that there are sufficient reserves to warrant an investment in infrastructure. A coal mine might
also be required to find a final buyer for the gas.
Power Generation
Coalbed methane may also be used as a fuel for power generation. Unlike pipeline
injection, power generation does not require pipeline quality methane. Gas turbines can
generate electricity from methane with concentrations of only 35 percent. Mines can use
electricity generated from recovered methane to meet their own on-site electricity
requirements and can sell electricity generated in excess of on-site needs to utilities. While
the use of coalbed methane for power generation has not been practiced on a commercial
basis in the U.S., several power generation projects are operating at coal mines in China,
Australia, England, and Germany (Sturgill 1991).
Technical Feasibility
A methane/air mixture with a heating value of at least 350 BTU/cf is a suitable gaseous
fuel for electricity generation. Accordingly, vertical degas wells, gob wells, and in-mine
boreholes are acceptable methods of recovering methane for generating power. Gas
turbines, internal combustion (1C) engines, and boiler/steam turbines can all be adapted to
generate electricity from coalbed methane. However, the most likely choice of a generator for
a coalbed methane project would be a gas turbine. Boiler/steam turbines are generally not
cost effective in small sizes (e.g., below 30 MW), and 1C engines are more sensitive to
variations in fuel heating values than are gas turbines. Furthermore, gas turbines are smaller
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and lighter than 1C engines and historically have had lower operation and maintenance
costs.^3
While maintaining pipeline quality methane output from gob wells can be difficult, the
heating value of gob gas is generally compatible with the combustion needs for gas turbines.
In fact, gases with even lower heating values (100 to 250 BTU/cf) have been used
successfully in some generators. One potential problem with using gob gas is that gob wells
generally are not predictable with respect to length of production, methane concentration,
and rate of flow; wide variations in the BTU content of the fuel may create operating
difficulties. Equipment for blending the air and methane may be needed to ensure that
variations in heat content remain within an acceptable range - approximately ten percent
allowable variability for gas turbines.
A potential advantage of using vertical wells as the recovery method for power
generation is that the amount and quantity of methane produced is more consistent than that
of gob wells. Thus, problems stemming from variations in the BTU content of the fuel would
be minimized where vertical wells are employed. Horizontal boreholes also can produce
methane of consistently high quality, however, the limited quantity of gas produced by this
method would likely need to be supplemented by larger quantities of methane from vertical or
gob wells.
The level of electric capacity that may be generated depends on the amount of
methane recovered and the "heat rate" (i.e., BTU to kWh conversion) of the generator. For
example, simple cycle gas turbines typically have heat rates in the range of 10,000 BTU/kWh,
while combined cycle gas turbines could have heat rates of 8,000 BTU/kWh. Assuming a
heat rate of 10,000 BTU/kWh, and assuming that mines could recover 40 percent of total daily
emissions, the level of electric capacity that could potentially be generated by the top 20
methane emitting mines in the U.S. would be in the range of 3 to over 30 MW per mine.
Profitability: Power Generation for On-Site Use
Given their large energy requirements, coal mines may realize significant economic
savings by generating power from recovered methane. Nearly every piece of equipment in an
underground mine operates on electricity, including mining machines, conveyor belts,
ventilation fans, and elevators for workers. Much of the equipment at typical mines is
operated 250 days a year, two shifts per day. Ventilation systems, however, must run 24
hours a day, 365 days a year, and they demand a considerable amount of electricity - up to
60 percent of the mine's total needs (USBM 1992).
Total electricity needs of a mine can exceed 30 kWh per ton of coal mined (Sturgill,
1990). Since the largest mines in the U.S. produce between 1 and 4 million tons of coal
annually, they can require up to 20 MW of capacity and can purchase over 100 million kWh of
electricity annually. At average industrial electricity rates of five cents per kWh, a mine's
electricity bill can exceed several million dollars a year.
13 IC engines are likely to be more cost effective than gas turbines for sizes below 3 MW, however the results
of this analysis show that the total capacity needed for a profitable coalbed methane power generation project is
above 3 MW.
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Coal preparation plants, which are frequently located near and associated with large
mines, also consume a great deal of energy. Preparation involves crushing, cleaning, and
drying the coal before its final sale. Coal drying operations require thermal energy, which
could be generated by a turbine or engine in a cogeneration cycle. Coal preparation
generally requires an additional 6 kWh per ton of coal (ICF Resources 1990c).
Among the main factors in determining the economic viability of generating power for
on-site use are the total amount and flow of the methane recovered, the capital costs of the
generator, the expected lifetime of the project, and the price the mine pays for the electricity it
uses. A mine would need to be fairly large to recover an amount of methane that would
justify the capital expenditures for a generator and other equipment needed for utilizing power
on-site. Moreover, because the per kiloWatt capital cost of a generator is relatively high in
terms of the overall economics of a coalbed methane power project, the mine would need to
generate power for several years in order to make the purchase of the generator a profitable
investment. A final economic consideration is the cost of back-up power, which is typically
supplied by a utility and is essential for mining operations given their safety considerations.
Capital and operating costs for generators and industrial electricity prices are shown in
Appendix A.
Profitability: Off-Site Sale to a Utility
Large and gassy coal mines may be able to generate electric power from coalbed
methane in excess of their own power requirements. In such cases, a mine may be able to
profit from selling power to a nearby utility. The economic feasibility of selling power off-site
would depend on the amount of electricity that could be generated in excess of on-site
needs, the incremental costs of selling power off-site, and the price received for the electricity.
If a mine is generating power to meet its own electricity needs, the incremental costs
of selling excess power off-site are relatively low. Normally, a coal mine already has a large
transmission line running from a main transmission line to the mine substation. In most
cases, this same line could be used to transmit power from the mine back to the utility. For
some mines, an interconnection facility or line upgrades may be needed to feed this
additional power into the main line. Estimates for the incremental costs of selling power off-
site are shown in Appendix A.
The Public Utility Regulatory Policies Act of 1978 (PURPA) encourages utilities to
purchase electric power from small power producers and cogenerators.14 Enacted in 1978,
PURPA was designed to promote conservation of energy and energy security. PURPA
guarantees a market, under certain conditions, for power producers that meet its
requirements. Facilities that meet PURPA requirements are known as qualifying facilities
(QFs) and include cogeneration facilities (because of their greater efficiency) and facilities that
employ waste or renewable fuels (because of the public policy interest in energy diversity).
To date, at least one mining company has been granted QF status to sell power generated
from coalbed methane. In that case, the Federal Energy Regulatory Commission (FERC)
allowed gob gas to be classified as a waste fuel.15
14 For a more detailed description of PURPA and its applicability to coalbed methane projects, see section 6 of
this chapter.
15 Island Creek Corporation Application to FERC for Certification of Qualifying Status, 1987. Although the
project received QF status, it did not proceed for other technical and economic reasons.
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Under PURPA, utilities are required by law to purchase power from and sell back-up
power to QFs at "nondiscriminatory" rates. State Public Utilities Commissions (PUCs) are
responsible for determining such rates, which are defined as the utility's "avoided cost" of
producing the power that will be supplied by a QF. QFs that can provide a constant supply
of electricity generally receive the highest avoided cost "price," as this power can be used to
offset a utility's base-load power requirements. In contrast, QFs that can only provide
intermittent power tend to receive lower avoided cost payments because they are a less
reliable source of power. Coalbed methane recovered from gob and/or vertical wells may be
viewed as a somewhat unreliable source of power, given the potential variability in fuel supply
and a mine's need for a certain supply of power on a priority basis.
In many U.S. coal mining regions, local utilities may have low avoided costs or excess
capacity, or may otherwise be unable or unwilling to purchase power from small power
producers. In such cases, selling power to neighboring utilities may be an attractive option
for coal mines that can generate power in excess of their on-site energy needs. Electricity
can be "wheeled" or transmitted by the local utility through the power grid for sale to other
utilities. For example, coal mines in Appalachia could sell power to utilities in the Northeast
or eastern Virginia. However, in reality, a number of problems may preclude wheeling as an
option. The decision to permit wheeling is made at the discretion of the local utility that
transmits the electricity. A utility may not wish to facilitate wheeling due to limited
transmission capacity or competition between the utility and the mine to sell power to
neighboring regions.
Utilization of Ventilation Air
As mentioned previously, large amounts of methane are emitted at concentrations of
less than one percent in mine ventilation air. One potential economic use for this methane is
as the combustion air in a gas turbine or coal-fired boiler. Even though the ventilation air
contains only a small percentage of methane, such air can supply sufficient heat for use in a
combustion device when the device is used to combust other fossil fuels. Aside from
utilization as combustion air, there do not currently appear to be other economic uses for the
dilute methane in ventilation air.
Technical Feasibility
The use of ventilation air in combustion processes has not been demonstrated, but
appears to be technically feasible; the combustion air requirements of coal-fired boilers and
gas turbines are compatible with ventilation air flows from many underground coal mines.
Furthermore, adapting a system to incorporate ventilation air should not require major
modifications. However, using ventilation air as combustion air has not yet been
demonstrated technically. The amount of energy supplied by ventilation air would be
dependent on the concentration of methane in the air. Assuming that all combustion air
needs are met by ventilation air, air containing 0.5 percent methane can supply approximately
7 percent of the energy needs of a coal-fired boiler and 15 percent of that required by a gas
turbine (Energy Systems Associates 1991).
Profitability
The economics of utilizing ventilation air will depend on the percentage of the
generator's energy needs supplied by the methane in the ventilation air and the capital and
operating costs for transporting the air from the ventilation shafts to the generator. The per
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mile cost of installing ducts is relatively high in terms of the overall economics of the project.
Thus, supply distances over a few miles are likely to be uneconomic for most mines. When
the distance between the ventilation shaft and the generator is greater than one mile, fans will
also be needed to move the ventilation air through the ducts. These fans would need to be
moved whenever new ventilation shafts were drilled. Operating costs are limited to the
energy costs of running these fans; energy costs of moving the ventilation air must remain
low in order for the project to be economic. Capital and operating costs for utilization of
ventilation air are shown in Appendix A. There are two scenarios in which it may be profitable
for a mine to utilize ventilation air as the combustion air for a generator.
• Sale to Mine-mouth Generators. Some coal-fired power plants are located within a
few miles of the mine that supplies their coal. Since the supply distance is limited, mine
ventilation air could be transported by ducts to the power plant for use as the combustion air
in a boiler. Coal-fired mine-mouth power plants typically are large enough to utilize all or
most of the ventilation air produced from a mine. For example, ventilation air flows from the
largest coal mines would be compatible with coal-fired boilers in the 400 to 500 MW range.
In the U.S., there are currently 6 coal-fired power plants located within 5 miles of a gassy
underground coal mine. Capacity at these plants ranges from under 200 to over 2000 MW
(Energy Systems Associates 1991). In general, however, the potential to achieve significant
emissions reductions through utilizing ventilation air at mine-mouth generators appears to be
limited due to the small number of mines that are within a few miles of a power plant and the
high costs of transporting ventilation air to a boiler.
• Use in Mine-owned Generators. A second possibility for the use of ventilation air
would be as the combustion air for a mine-owned gas turbine fueled by methane recovered
from gob and/or vertical wells. Ventilation air would be transported by ducts from the
ventilation shaft to the on-site generator. The amount of ventilation air utilized would depend
on the level of electric capacity. Gas turbines typically require 350 cubic feet of air per kWh
generated (Energy Systems Associates 1991). When large amounts of ventilation air can be
utilized and when the costs of transporting ventilation air are low, ventilation air utilization can
enhance the economic attractiveness of an on-site power generation project.
3.3 METHODOLOGY
To evaluate strategies for reducing the methane emitted by coal mines, the approach
taken was a "discounted cash flow analysis" that looks at the income stream of a recovery
and utilization project over its lifetime and determines the net present value of the project to
the private mine operator. A number of variables related to the physical characteristics of
mines, the cost of recovery and utilization equipment, and economic conditions influence the
analysis. While the discounted cash flow analysis is designed to approximate how an actual
coal mine might evaluate the financial value of a recovery and utilization investment, the
analysis was performed for representative or prototypical mines and relies on aggregate data
describing geologic characteristics, cost relationships, and expected revenues.
The section first describes what is being evaluated by establishing the categories of
representative mines used in the analysis and by delineating the available methane recovery
and utilization strategies. Next, the methods used to determine the material and financial
inputs required for the various recovery and utilization strategies are explained. The
profitability of these strategies is highly dependent upon values assumed for key economic
factors affecting coalbed methane projects. The third part of this section describes the
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various scenarios - each of which incorporates different values for these key economic
factors -- that were developed to evaluate the potential for mines to develop profitable
recovery projects. The final part of this section describes the method that was used to
determine the number of existing and future mines that would meet the minimum annual coal
production and gassiness requirements to profitably recover under each of the various
economic scenarios.
3.3.1 The Subjects of the Analysis:
Strategies
Mine Profiles and Recovery/Utilization
The analysis examines representative mines and the strategies that could be
employed to recover and utilize methane from such mines. The following subsections
describe the subjects of the analysis in more detail.
Mine Profiles
The economic viability of the various
recovery and utilization methods was
evaluated in terms of the potential for a wide
variety of gassy underground coal mines to
realize a positive net present value from
developing coalbed methane projects.
Therefore, a series of "mine profiles" was
developed to represent conditions at
different types of mines.16 For the
purposes of this analysis, a "mine profile" is
a hypothetical mine that is defined by a set
of specific characteristics, including: coal
basin, annual coal production, emissions
per ton of coal mined, mining method, and
distance to pipeline.
The f inans&i analysis was based on
prototypical mine prof iles that represent
key <^»aorerl^lcs of actual frttm with
respect to project feasibility. The
are: i •
•• Coat Basin •
* Annual
* Emissions Per Tort sfCoaf Mfoe
* Current Mining Method ;
* Current Recovery and Utilization
* Distance to
The mine profile characteristics were
selected because they are the most significant factors in evaluating a mine's potential to
recover and utilize methane. While the defining characteristics were based on data from real
mines, no single profile was intended to represent an actual coal mine. Instead, the analysis
was designed to reflect overall results for gassy underground coal mines in the U.S. For an
actual project assessment, a great deal of detailed, site-specific information would need to be
evaluated.
• Coal Basin. Geologic and economic conditions often vary significantly, depending
on the region in which a coal mine is located. Therefore, geographic location is one of the
defining characteristics of each mine profile. In this analysis, geographic regions are the
major coal basins: Central Appalachian, Northern Appalachian, Warrior, Illinois, and "Western."
The "Western" basin includes the Piceance, San Juan, and Raton Mesa basins in Colorado,
New Mexico, and Utah.
16 Mine profiles represent large and gassy underground mines (i.e. mines with emissions per ton greater than
500 cf/ton and annual coal production greater than .5 million tons). Smaller, less gassy underground mines are not
likely to be able to recover methane for a profit, and were not evaluated in this analysis.
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• Annual Coal Production. The size of a coal mine, determined by annual coal
production, is an indicator of the total amount of methane that could be recovered, the mine's
total electricity needs, and a number of other factors, such as the potential for a mine to
finance the large capital investments required for a methane recovery and utilization project.
The analysis assumed that a mine would need to have a minimum annual coal production of
0.5 million tons to consider a methane recovery and utilization project. In 1988, over 100 U.S.
underground mines had coal production exceeding 0.5 million tons (Keystone 1989). A mine
profile's annual coal production characteristic may be one of seven different levels, ranging
from 0.5 to 3.5 million tons.
• Emissions Per Ton of Coal Mined. Along with size, the relative gassiness of a mine
is an important factor in determining the amount of methane that could be recovered and
utilized. In this analysis, the gassiness of a mine profile was measured by the "status quo
emissions per ton of coal mined." This term refers to the total amount of methane that would
be emitted to the atmosphere, assuming no recovery or utilization methods were employed.
These emissions would include any methane contained in the coal seam itself or in the strata
above and below the coal seam that was released during mining. A mine profile's status quo
emissions may be one of eight different levels ranging from 500 to 4000 cubic feet per ton. In
1988, over 100 mines had methane emissions of more than 500 cubic feet per ton of coal
mined.17
• Current Mining Method. Mining method is a factor in determining the economic
feasibility of recovering and utilizing methane. For example, as mentioned earlier, longwall
mines tend to result in a more extensive collapse of methane charged strata surrounding the
coal seam. Mine profiles were assumed to employ either the longwall or room-and-pillar
technique. In the U.S., over 50 large and gassy mines use the longwall mining method (Coal
1989).
• Current Recovery and Utilization. This analysis evaluates only those factors that are
specific to the recovery of methane for pipeline injection or power generation. In other words,
only incremental costs incurred, revenues generated, or savings realized from new recovery
and utilization investments are included in the net present value analysis. Incremental
differences vary depending on whether a mine has already invested in recovery wells or
utilization equipment. For example, over 30 U.S. mines already use gob wells to reduce
methane levels in mine working areas, even though the methane recovered will be emitted to
the atmosphere rather than sold to a pipeline or used to generate power (USEPA 1993). In
such cases, the capital costs for gob wells would not be included in the incremental net
present value analysis. However, for the scenarios discussed in this analysis, all recovery
and utilization costs were assumed to be incremental to developing a coalbed methane
project.
• Distance to Pipeline. Per mile costs of laying gathering lines are substantial.
Therefore, proximity to a commercial pipeline is an important factor in determining a mine's
potential to sell methane to a pipeline company. A mine profile's proximity to a pipeline can
range from 2 to 30 miles, based on estimates of distances to pipelines for actual mines (ICF
Resources 1990a).
17 The number of mines with emissions greater than 500 cubic feet per ton was calculated by dividing total
methane emissions for each mine listed in USBM (1988) by annual coal production for each mine from Keystone
(1989).
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Each mine profile was formed from a unique combination of these characteristics. As
explained in the discussion on the number of actual mines matching each profile, many
profiles did not contain any actual mines, while other profiles contained several mines.
Recovery and Utilization Strategies
Recovery and utilization methods were
evaluated for each mine profile in terms of
their oost*effec£veness and their potential
for reducing methane emissions.
Methods
Five Year Vertical Wefts
For each mine profile, a number of
potential recovery and utilization methods
were evaluated in terms of their cost-
effectiveness and their potential for reducing
methane emissions.
Recovery Methods
The potential recovery methods
evaluated are vertical wells drilled two, five,
and ten years in advance of mining, and
gob wells. Gob wells, which are typically
drilled just prior to mining of a coal seam,
are assumed to recover methane for one
year. Vertical wells are assumed to recover
methane until the coal seam into which they
have been drilled is mined through. Vertical
well pre-mining drainage is set at a maximum of ten years for two reasons. First, and most
importantly, gas production rates decline rapidly after the first few years of production; by the
tenth year the amount of gas recovered is rather limited. Second, it likely would be difficult
for a mine to plan degasification strategies more than ten years in advance of mining.
The potential for methane recovery from horizontal and cross-measure boreholes was
not evaluated in this analysis. While in-mine boreholes can produce methane with a high
energy value, the amount of methane recovered by these methods is limited and would
typically need to be supplemented by methane recovered from vertical and/or gob wells.
Utilization Methods
Pipeline injection and power generation are the two utilization options evaluated. The
power generation option consists of six unique variations based on the utilization of
ventilation air and methane recovered in excess of on-site electricity needs. Any methane
recovered in excess of on-site power needs may be: 1) used to generate power for sale to a
utility; 2) sold to a pipeline; or, 3) vented to the atmosphere. Each of these three variations
were combined with the option of using ventilation air as combustion air in an on-site
generator, resulting in 6 unique options for power generation.
18
The combination of four recovery methods with seven utilization methods yields 28
unique recovery and utilization strategies. For each of the mine profiles, every recovery and
utilization strategy was evaluated.
18
The potential for coal mines to sell ventilation air to mine-mouth coal fired boilers is not specifically
addressed in this analysis.
3-25
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3.3.2 Financial Analysis of Recovery and Utilization Investments for Sample Mine
Profiles
The financial analysis of the mine profiles and their associated methane strategies was
conducted in three steps. First, material or "physical" calculations were made for the recovery
and utilization strategies, including estimates of the number of wells needed, the amount of
methane recovered, and of the capacity of equipment needed. Second, annual cash flows for
the recovery and utilization investments were determined over the projected lifetime of the
project. These cash flows were determined from estimates for the capital and operating
costs, revenue generated, and operating savings realized. Finally, based on the physical and
financial calculations, a net present value and internal rate of return were calculated for each
recovery and utilization project, along with an estimate for the reduction in methane
emissions. Mine profile results for the recovery and utilization methods were then used to
estimate the emissions reduction potential for the full population of underground mines in the
U.S. A methodology flow-chart is shown in Exhibit 3-12.
Exhibit 3-12
Methodology Flow-Chart
Mine Prof i Ies
CUnit of Analysis])
Recovery and
Ut i I izat ion
Opt i ons
Eva Iuated
Phys icaI
CaIcuI at ions
- Number of We IIs Needed
- Methane Recovered
- Equipment Needed
- Gas and Electricity
Produced
F i nanc iaI
Caleu I at ions
- Capital Costs
- Operat i ng Costs
- Revenue Generated
- Sav i ngs ReaIi zed
Results
- Fi nanc i a I
- Emissions Avoided
3-26
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Physical Calculations
The first step in evaluating the recovery and utilization strategies was to estimate the
quantity and quality of methane that could be recovered, the capacity of the equipment that
would be needed, and the gas and/or electricity produced. For each of these material or
"physical" calculations, a range of values rather than a single estimate was used to reflect
possible conditions at a wide variety of mines. The range of values used is shown in
Appendix A, along with a detailed description of the methodology for the calculations. Once
these physical production and capacity calculations were completed, financial estimates could
be made.
• Number of Wells Drilled. The number of vertical or gob wells needed for each
profile was determined by examining literature on optimal well spacing. For vertical wells, this
data is typically presented in terms of an acres per well ratio. For gob wells, the number of
wells needed per longwall panel is typically cited. However, because mine profiles are not
defined in terms of acreage or number of longwall panels mined, these vertical and gob well
ratios were converted to tonnage per well ratios, and annual coal production was used as an
estimate for the number of wells that would need to be drilled each year.
• Methane Recovered. The potential amount of methane that could be recovered for
each mine profile was determined from annual coal production and methane emissions per
ton of coal mined. Each recovery method was assumed to be able to capture a certain
percentage of methane that would otherwise be emitted. The total amount of methane
recovered depends on the recovery method, the number of wells drilled each year, and the
total years of drilling.
• Quality of Methane Recovered. Methane recovered from vertical wells was assumed
to be at least 95 percent pure (pipeline quality). For gob wells, two hypotheses were
examined: 1) gob wells recover methane that contains 50 percent methane and 50 percent air
(implying that the methane will need to be enriched for pipeline injection); and 2) gob wells
recover pipeline quality methane. Under the first scenario, significant expenditures would be
required in order to enrich the methane; however, even recovery of pipeline quality methane
(as postulated in the second scenario) would require some additional capital expenditures in
order to maintain the quality of the methane.
• Water Produced from Vertical Wells. Because water disposal costs can be
substantial, the amount of water produced from vertical wells was an important factor in the
analysis. Water production, like gas production, typically follows an exponential decline
curve. Therefore, water production was estimated by using a gas production (cubic feet) to
water production (barrels) ratio. These gas to water ratios were developed from data on gas
and water production at stand-alone coalbed methane operations.
• Capacity of Equipment Required. For pipeline injection, the required equipment
includes gathering lines, compressor(s), a water disposal system (for vertical well recovery
only), and equipment for enrichment (gob wells only), processing, and treatment. The
capacity of the pipeline equipment needed was based on the maximum daily methane
produced. For power generation, the required equipment includes a generator, gathering
lines (from the wells to a generator), a water disposal system (for vertical well recovery only),
and an interconnection facility (for off-site power sales). The capacity of the generator was
calculated from the maximum hourly gas production and the assumed heat rate. For the
ventilation air utilization option, ducts and fans are required to transport the air from the
3-27
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ventilation shaft to an on-site generator. The capacity of the ducts and fans was based on
estimated ventilation air flows and the distance from the shaft to the generator.
• Gas and Electricity Produced. For the pipeline utilization option, a small portion (i.e.,
less than 10 percent) of the methane recovered was assumed to be used to fuel the
compressors. Otherwise, the analysis assumed that all methane recovered could be sold to a
pipeline. For the power generation option, the amount of electricity generated was calculated
from the methane recovered and from the assumed heat rate of the generator. Electricity was
assumed to be used first to meet on-site electricity needs (estimated by a kWh to tons of coal
mined ratio). Methane produced in excess of the quantity needed to generate electricity for
on-site needs could be sold to a pipeline, used to generate power for sale to a utility, or
vented to the atmosphere. For ventilation air utilization, methane in ventilation air was
assumed to contribute additional heat to the combustion process; the energy supplied was
calculated from the capacity and combustion air needs of the generator and from the
assumed concentration of methane in the ventilation air.
Financial Calculations
Flrvane&f (^cuteflons were \
«ach recovery and utilization method.
These catenations included;
Capita* and
• TaxUabiHty
* Net Present Val«e
* internal Rate of ftefctm
In order to perform a discounted
cash flow analysis for the potential recovery
and utilization investments, annual cash
inflows and outflows were calculated.
Estimates for capital and operating costs,
revenue generated and savings realized
were based on the physical calculations for
gas, water and electricity produced and
equipment needed. Additionally, estimates
were made for inflation rates, discount rates,
and other relevant financial factors. As with
all other inputs, a range of values rather
than a single estimate was used to reflect
possible conditions at a wide variety of
mines. Exhibit 3-13 summarizes the financial factors used in the analysis. A detailed
description of the data and sources used for these financial factors is shown in Appendix A.
• Capital Costs. The required capital investments were calculated for each recovery
and utilization strategy. For the net present value (NPV) analysis, both the timing of the
required capital outlay and the total cost were estimated. The timing of the capital outlays
was discussed in terms of initial investments required at the start of the project and in terms
of subsequent annual investments -- primarily new wells drilled each year. Mines were
assumed to pay cash for all capital investments/"
19
• Operating Costs. Annual operating costs were estimated over the projected lifetime
of the project. These operating costs can vary significantly each year depending on the
number of wells in operation and on annual gas, water, and electricity production. Operating
costs for recovery wells were assumed to have a fixed maintenance cost, which includes all
labor and other costs of maintaining a producing well. Annual operating costs for
19 ,
Using all equity financing may be viewed as a conservative assumption -- in cases in which a mine would
finance a portion of the capital costs through debt, annual interest payments on the loan would be tax deductible.
3-28
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ExhibitS-IS
Summary of Financial Factors
Financing of Capital Investments
Depreciation Method
Taxes
Inflation
Discount Rate
1 00 percent equity financing was assumed.
Straight-line depreciation is used. The period of
depreciation is assumed to equal ten years except in the
case of recovery wells where it is assumed to equal the
lifetime of the well.
A marginal tax rate of 40 percent is assumed.
An inflation rate of 4 percent is assumed.
A nominal discount rate of 1 0 percent is assumed. With a 4
percent inflation rate, this corresponds to a real discount
rate of 6 percent.
utilization equipment (e.g., compressors, generators, water disposal system) were based on
annual production estimates.
• Operating Revenue. A mine profile could generate revenue by either selling
methane to a pipeline or selling electricity to a utility. In the case of power generation, it was
assumed that a mine would first use all electricity generated to meet on-site needs. Any
excess electricity could then be considered for sale to a utility. Forecasts for the wellhead
gas price ($/mcf) were used to estimate potential revenue from pipeline sales. Similarly,
projections for avoided costs (cents/kWh) were used to estimate revenue from electricity
sales. For both pipeline and power sales, it was assumed that the mine could sell all gas
recovered and/or all electricity produced in excess of on-site needs.
• Operating Savings. Operating savings may be realized by generating power to meet
on-site electricity needs and/or by reducing ventilation air requirements (and, accordingly, the
electricity needed to run the ventilation system). For both cases, the energy savings were
calculated in terms of the reduction in electricity purchased from a utility multiplied by the
industrial electricity cost (cents/kWh).
• Depreciation and Taxes. To calculate the annual tax liability, the assumed tax rate
was first applied to the annual income, then "avoided taxes" were calculated by computing
the depreciation tax shield.
• Discounted Cash Flow Analysis. Annual cash flows were calculated over the lifetime
of the project; these cash flows were then discounted at the private mine operator's assumed
discount rate to determine the net present value of the recovery and utilization investment.20
Additionally, the internal rate of return of the investment was calculated. Only the incremental
cash flows -- the cash flows specifically related to the coalbed methane project - were
included in the net present value analysis.
A real discount rate of 6 percent is assumed. This discount rate is based on an examination of the riskiness
of the coal industry and the assumption that coalbed methane projects may be slightly more risky than the
underlying coal business.
3-29
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Results
.For eaefc mine profile, several
categories of results lor methane
recovery weie evaluated, deluding:
' 4 Financial Benefits
f Emissions Avoided
> Energy Savfags
These mine profile results were used to
mafce predictions lor actual mines.
Three primary sets of results were
computed for each unique recovery and
utilization strategy for each mine profile: 1)
financial results, including the net present
value and internal rate of return; 2) methane
emissions avoided; and 3) methane sold to
a pipeline and/or electricity generated. For
each mine profile, the recovery and
utilization strategy showing the highest NPV
was assumed to be the preferred strategy.
For the majority of mine profiles, the
preferred strategy had a positive NPV.
Therefore, it was assumed that the mine
profile would employ the preferred strategy
to recover and utilize methane and that methane emissions would be reduced accordingly.
For a few of the mine profiles, all potential recovery and utilization strategies (including the
preferred strategy) had a negative NPV. In such cases, it was assumed that the mine profile
would not develop a recovery and utilization project and thus would continue to emit methane
at present levels.
The estimated number of mine profiles that could profitably recover and utilize
methane varied, depending on the values assumed for key factors such as the projected
wellhead gas price. In order to estimate the range of potential results for future emissions
reductions, the analysis evaluated a number of different economic scenarios.
3.3.3 Economic Scenarios
This section describes several scenarios that assume different values for each of the
key economic factors influencing the profitability of methane recovery and utilization projects.
These factors include the wellhead gas price, the capital costs for drilling gob or vertical
wells, the amount of methane that is potentially recoverable, and the costs for disposal of
water produced from vertical wells. One scenario, the "base case," represents EPA's best
estimate of the future value of the key variables informing the discounted cash flow analysis.
Accordingly, the results of the base case scenario represent EPA's best estimate of the
number of mines that could recover methane for a profit. The results of this scenario were
employed as a bench mark to measure the results of other scenarios, which are dependent
on different assumptions for the underlying variables.
Base Case Scenario
In general, the base case
incorporates average or median values for
all the variables used in the net present
value analysis. For example, all "medium"
values were used in estimating the variables
used for the tangible or "physical"
calculations, such as the number of wells
drilled each year and the amount of
methane recovered, and in estimating the
The base case represents EPA's best
es&mate of <&e future vaktes of the key
variables informing the discounted cash
flow analysis of a recovery and
uUHzaliori pr ojeet • '•
3-30
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variables used for the financial calculations, such as capital and operating costs. Key base
case assumptions are shown in Exhibit 3-14.
Exhibit
Key Base Case
Factor
Wellhead Gas Price8
Capital and Operating Costs
Utilization Method
Recovery Method
Portion of Methane Recoverable (per mine recovering)
Water Disposal Costs
a Source: Gas Research Institute (19S2); American Gas /
3-14
Assumptions
Value
$2.25 per mcf in 2000
$3.00 per mcf in 2010
Average of reported values
Pipeline Injection
Vertical Wells drilled ten years in advance of mining
60 percent of methane emitted
Average of reported values
Association (1992); USDOE/EIA (1992).
The base case also incorporates the assumption that each mine profile will drill
recovery wells for ten years. This assumption implies that methane will be recovered from an
amount of coal equivalent to ten years of annual coal production. For example, a mine profile
that is characterized as having an annual production of 2 million tons would recover methane
from 20 million tons of coal over the lifetime of the project.
Another assumption of the base case is that all costs for drilling vertical and/or gob
wells are treated as an additional or "incremental" cost of a methane recovery and utilization
project. Given that most large and gassy mines already use these wells as a necessary
supplement to their ventilation systems, this assumption is quite conservative. Furthermore,
the base case also incorporates conservative assumptions with respect to mines that do not
already use these degasification systems. Mines that would drill recovery wells solely as part
of a recovery and utilization project would greatly reduce their energy costs for mine
ventilation. However, these benefits were not taken into account in the financial analysis for
the base case.
Finally, the base case does not take into account a number of legal, regulatory, and
institutional barriers that are discussed in section 6 of this chapter. These barriers can
significantly distort the economics of coalbed methane projects. The recommendations in
sections 6 and 7 suggest possible approaches for removing or reducing some of the most
critical of these barriers.
Other Economic Scenarios
The results of five other economic scenarios are also presented in this analysis: 1)
lower future wellhead gas prices; 2) higher future wellhead gas prices; 3) lower recovery
percentages; 4) higher capital costs; and 5) higher water disposal costs. The estimated
number of mines that could profitably recover under each of these scenarios and the
associated emissions reduction that could be achieved is shown for each of these scenarios
3-31
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and is compared to the base case results. Additionally, results are presented for scenarios
evaluating the potential for mines to make a profit using recovery methods other than ten year
vertical wells and for power generation as opposed to pipeline injection.
For each economic scenario, a different number of mine profiles showed the potential
to recover and utilize methane for a profit. The next and final step in the analysis was to
estimate the number of mines that can be "mapped" to each mine profile.
3.3.4 Number of Mines with the Potential to Recover Methane for a Profit
While the mine profile is the unit of analysis for evaluating the recovery and utilization
strategies, the ultimate goal of the analysis is to estimate the number of existing and future
mines that could employ these strategies for a profit, as well as to estimate the associated
reduction in methane emissions. To accomplish this goal, actual mines were "mapped" to the
mine profiles. This mapping process matched data on existing gassy underground mines to
the characteristics of mine profiles to determine the number of actual mines that fit each
profile. In order to perform this mapping, a database of information on current mines was
developed. To identify the future reduction potential, predicted "future mines" were mapped
to the profiles. The database of existing mines and coal production forecasts for each basin
were used to approximate the total number of mines that would match each profile in the
future. It should be noted that the mapping was not a precise exercise, due to uncertainties
regarding conditions at actual mines. However, the analysis was designed to reflect general
conditions for the full population of mines rather than to be valid on a mine-specific basis.
Current Mines
The primary source for data used to map existing mines into mine profiles was a
USBM database of U.S. coal mines that emitted more than 0.1 million cf/day of methane from
their ventilation systems in 1988 (USBM 1988). To use the USBM database, methane
emissions for each mine in the database were estimated using the emissions assumptions in
USEPA (1993). Annual emissions from ventilation systems were taken as the emissions
measurements reported by the Mine Safety and Health Administration (MSHA). Additionally,
for mines in the Central Appalachian, Warrior, and Western basins that had degasification
systems in place in 1988, methane emissions from degasification systems were assumed to
be 40 percent of total ventilation and degasification emissions as a low estimate and 65
percent of total emissions as a high estimate. For the Northern Appalachian and Illinois
Basins, the low estimate for degasification system emissions was assumed to be 30 percent
of total emissions, while the high estimate was assumed to be 60 percent of total emissions.
Regardless of the high or low scenario, at certain mines in the Warrior Basin that were known
to have sold methane to pipelines in 1988, methane recovered from degasification systems
was estimated to constitute 35 percent of their total emissions. Finally, for one Western mine
that recovered methane for pipeline injection, methane recovered by its degasification system
was estimated to account for 50 percent of total emissions.
The mapping process was performed as follows:
1. Mines in the USBM database were sorted according to the coal basin in which
they are located (Central Appalachian, Northern Appalachian, Illinois, Warrior,
or "Western").
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2. Within each basin, mines were sorted according to annual coal production and
methane emissions per ton of coal mined. Annual coal production estimates
were rounded to the nearest 0.5 million tons, and estimates for emissions per
ton were rounded to the nearest 500 cf/ton.
3. Once the mines were sorted, they were mapped onto profiles that were defined
by these three primary characteristics (basin, coal production, and emissions
per ton).
For example, a mine that is located in the Northern Appalachian Basin (NAPP) and has
annual coal production of 2.2 million tons and methane emissions per ton of approximately
1400 cf/ton would be mapped into the following profile:
MAPPING __][
Profile I
BASIN
NAPP
PRODUCTION
2 million tons
j METHANE/TON
I 1500 cf/ton
Similarly, a mine that is also located in the Northern Appalachian basin and that has annual
coal production of 1.9 million tons and methane emissions per ton of 1600 cf/ton would also
be mapped into the same profile. In contrast, a mine located in the Illinois basin that has
annual coal production of 3.2 million tons and methane emissions per ton of 600 cf/ton would
be mapped as follows:
MAPPING | BASIN
Profile I IL
I PRODUCTION
I 3 million tons
METHANE/TON
500 cf
Information from the database of existing mines was then used to estimate the number
of mine profiles that have longwall or room-and-pillar mining methods, the number of profiles
that currently employ degasification systems, and the number of profiles that are located
within close proximity to a pipeline. Specifically, mine profiles were characterized as being
located within a range of 5 to 30 miles of a. commercial pipeline; as having a current mining
method of longwall or room-and-pillar; and as having either: 1) no current recovery; or
2) some type of degasification system in place.
Future Mines
To identify the future emissions
reduction potential, "future mines" were
mapped to the mine profiles. The number
of mines matching the profiles were
estimated for the years 2000 and 2010. In
order to approximate the number of mines
matching each profile, it was necessary to
estimate the potential distribution of
projected coal production among large and
gassy mines in each basin. Due to the high
degree of uncertainty regarding the
Due to 1h« large degree of aneertainty
in pr$#N#if*f^
£000 and 2010, three different scenarios
mid; ^d tt|gh;^ecteir:^^^1;; "
emissions from underground ownes.
3-33
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probable distribution of coal among large and gassy mines in the future, three unique
distributions were developed:
1) Low Case emissions scenario;
2) Mid Case emissions scenario;
3) High Case emissions scenario.
Each distribution corresponds to a different projected level of methane emissions from
underground coal mines in 2000 and 2010. The low and high scenarios are based on
projected emissions described in USEPA (1993). The low emissions scenario uses a lower
estimate for the portion of methane emitted from degasification systems21 and lower
projected coal production levels22 than does the high scenario. The mid case scenario
represents the average of these two scenarios. The coal production and emissions levels
assumed for each basin in the low, mid, and high scenarios are shown in Exhibit 3-15.
To estimate the number of large and gassy coal mines in 2000 and 2010, the
production increase factors were applied to the database of 1988 mines. To map mines to
mine profiles it was assumed that due to the finite size of coal seams, there is a reasonable
upper limit on mine size. Upper limits for annual coal production were set for each basin by
only allowing a slight increase over the size of the largest mine in the database of 1988
mines. Based on the original percentages of coal production, excess production resulting
from the application of this limit was reapplied to smaller mines not yet exceeding the
established limits. This process was repeated until all additional coal production had been
distributed and no single mine exceeded the coal production limit.
Once a unique distribution of mines in terms of annual coal production and methane
emissions per ton had been developed corresponding to the low, mid, and, high future
emissions projections levels, "future" mines could be mapped to the established mine profiles
(following the mapping process described in the preceding discussion of current mines). The
following section shows the results of the estimated number of mines that could recover given
base case economic conditions for the low, mid, and high projected emissions scenarios in
2000 and 2010.
21 Assumptions used for degasification emissions in USEPA (1993) are described in the preceding section on
mapping for current mines.
Two different forecasts of underground coal production levels in 2000 and 2010 for each basin were used to
derive low and high percentage increases over 1988 levels. Both scenarios were developed after passage of the
1990 Clean Air Act Amendments and reflect the expected impacts of that legislation on the coal industry. However,
the low case scenario assumes that energy efficiency improvements, continued low gas prices and the 1990 Clean
Air Act Amendments will result in lower coal production in the future than is anticipated under the high case
scenario. The low production scenario is based on DOE's Supporting Analysis for the National Energy Strategy
(USDOE/EIA 1990). The high coal production forecast is based on the Energy Information Administration's Annual
Energy Outlook, 1992 (USDOE/EIA 1992).
3-34
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ExhibitS-IS
Coal Production and Degasification Emissions Levels used to Project Emissions and
to Estimate the Number of Large and Gassy Mines in 2000 and 201 0
Basin
C. App.
N. App.
Illinois
Warrior
Western
Low Case
Degas % Chan9e in Coa|b
% from 1988 to
Per
Mine8 2000 2010
40% -3% 13%
30% 12% 44%
30% 44% 135%
40% 1% 44%
40% 83% 161%
Mid Case
Degas % Chan9e in Coa|b
0^ from 1988 to
Per
Mine3 2000 2010
52.5% 3% 21%
47.5% 19% 55%
47.5% 52% 152%
52.5% 6% 54%
52.5% 93% 180%
High Case
Deaas % Char)9e in Coa|b
<£ from 1988 to
Per
Mine3 2000 2010
65% 8% 30%
65% 25% 65%
65% 60% 168%
65% 12% 64%
65% 103% 199%
a Degas percent per mine is the portion of total emissions released from degasification systems. Low and high
case degas emissions are based on low and high projected emissions scenarios in USEPA (1993). For five
mines in the Warrior basin that sold methane recovered from degasification systems to pipeline companies,
degasification emissions were assumed to be 35 percent for all three cases. Additionally, for one Western basin
mine that sold methane to a pipeline, degasification emissions were assumed to be 50 percent for all scenarios.
b Low and high case coal production forecasts for each basin are from USEPA (1993). Mid case coal
production projections are the average of the low and high case forecasts.
3.4 PROFITABLE EMISSIONS REDUCTIONS
Profitable options exist for reducing methane emissions from coal mining. Currently,
eleven mines in three states -- Alabama, Utah, and Virginia -- are already making a profit from
selling recovered methane to pipelines. This analysis shows that other large and gassy coal
mines also have the potential to recover methane for a profit. Moreover, development of
recovery and utilization projects at these mines would result in significant reductions in the
quantity of methane released into the atmosphere each year from coal mining activities. The
extent of profitable emissions reductions in the future will depend on 1) the amount of coal
that will be produced from large and gassy mines; 2) several key economic factors affecting
coalbed methane recovery projects; and 3) the extent to which a number of current legal,
regulatory, and institutional barriers to coalbed methane projects can be removed or reduced.
Estimating the future amount of coal that will be produced from large and gassy mines
is the first step in assessing the percentage of projected methane emissions that could be
recovered for a profit. As described in the methodology section, a unique distribution of
mines in terms of annual coal production and emissions per ton was developed
corresponding to the low, mid, and high case emissions projections for 2000 and 2010.
Determining the assumed distribution of coal production among large and gassy mines is
essential because the minimum required levels of annual coal production and methane
emissions per ton necessary for profitable recovery vary based on assumed future economic
conditions (i.e., the minimum cut-off levels increase as the values assumed for key economic
factors become more conservative).
3-35
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The following subsections present estimates for the number of mines that could
recover methane for a profit under several different scenarios and estimates for the
associated emissions reductions. The regional prospects for coalbed methane projects are
also examined. Additionally, other environmental and energy benefits and expected financial
benefits to private mine operators are discussed, along with potential policy options for
encouraging the development of coalbed methane projects.
It is important to note that the results shown in this section do not take into account
several extant legal, regulatory, and institutional barriers that currently constrain the wider
development of coalbed methane projects. A number of these barriers must be addressed in
order to enable a greater number of mines to develop methane recovery and utilization
projects. The barriers that are unique to the coal industry are discussed in section 6 of this
chapter, along with options for overcoming them. Some additional, more general barriers are
discussed in Chapter 7 of this report.
3.4.1 Technologically Feasible Emissions Reductions
At most large and gassy underground mines, it should be technologically feasible to
recover about 60 percent of the methane released from mining activities. For purposes of this
report, large and gassy underground mines are defined at those that have annual coal
production greater than 0.5 million tons and methane emissions per ton greater than 500
cubic feet per ton. In 1988, the latest year for which detailed data is available on coal
production and emissions at underground mines, over 60 mines could be classified as large
and gassy. The amount of methane released by these mines during 1988 is estimated to
have been between 1.5 and 2.1 Tg,23 which accounted for 85 to 90 percent of all methane
released from U.S. underground coal mines during that year, and about 65 to 70 percent of
total methane released from all coal mining activities in the U.S. By 2000, technologically
feasible emissions reductions that could be achieved at large and gassy mines are projected
to be in the range of 1.6 to 2.7 Tg of methane, which would represent between 50 and 55
percent of projected emissions from underground mines. Similarly, by 2010, it should be
technologically feasible for large and gassy mines to recover an estimated 2.2 to 3.7 Tg.
3.4.2 Profitable Emissions Reductions
This analysis shows that methane
emissions from underground coal mines can
be reduced substantially through the use of
cost-effective recovery and utilization
methods; by the year 2000, approximately
32 to 44 percent (1.0 to 2.2 Tg) of methane
released during underground mining could
be captured and used rather than released
to the atmosphere. This reduction would be
associated with recovery projects at from 16
to 25 large and gassy coal mines.
Methane emissions from coal mines
•can foe reduced; o^t^ffectiv^ly foy 1,0
tq2£Tgjn2QG0and 1,7 to 3.1 Tg in
S010>; fh& corresponds lo a reduction
of 32 to 44 percent of total projected
'•'!Mri$Uj9from^nd^grotirid minss in
1 the l£S; in 2000 am* 40 to 4S. percent:in
' ''
23
This amount includes 0.25 Tg that was recovered and utilized rather than emitted to the atmosphere.
3-36
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By the year 2010, 25 to 29 mines are likely to be able to recover methane for a profit.
Projects at these mines would reduce methane emissions to the atmosphere by 1.7 to 3.1 Tg
- 40 to 45 percent of projected emissions from underground mines.
When comparing the potential for profitable recovery to the total projected
underground emissions it is important to note that the technically feasible portion of methane
that could be recovered is likely to be no greater than 60 to 70 percent of all emissions. This
technically feasible amount is based on the assumption that individual mines are likely to be
able to recover a maximum of 60 to 70 percent of emissions using a combination of methane
recovery approaches, including pre-mine degasification, in-mine recovery and gob wells.
Accordingly, the projected profitable emissions reductions represents approximately 60
percent of the technically feasible emissions reductions in 2000 and approximately 70 percent
in 2010.
The emissions reduction that could be achieved by the development of recovery
projects at coal mines would make a substantial contribution towards reducing annual
emissions of greenhouse gases in the United States. For example, the emissions reductions
cited for the year 2000 would be the equivalent of the CO2 output from approximately 4 to 9
million cars. Furthermore, the annual energy savings of utilizing this otherwise wasted
resource is the equivalent of about 2 to 5 million tons of bituminous coal or about 8 to 19
million barrels of imported oil.
As shown in Exhibit 3-16, the range in the potential number of mines recovering for a
profit in 2000 and 2010 and the associated emissions reduction corresponds to low, mid, and
high projections for methane emissions for coal mines. For 2000 and 2010, the low
emissions case shows the lowest percentage reduction in terms of total projected emissions
(32 percent in 2000 and 40 percent in 2010). The differences in the portion of methane
recovered are primarily due to the 1988 degasification system emissions assumed for each
scenario. Because the high scenario assumes the highest percentage of emissions for those
mines employing degasification systems, a larger number of mines than in the mid or low
scenarios meet the minimum gassiness requirements for profitable recovery. Throughout the
remainder of this section, the results of the analysis will be discussed in terms of the mid
case projected emissions level.
The minimum annual coal production and methane emissions per ton of coal mined
used to determine the number of mines that could recover methane for a profit was based on
a specific set of "Base Case" assumptions for the key economic factors affecting coalbed
methane recovery projects. These assumptions, which are fully described in the Methodology
section, include a $2.25 per mcf wellhead gas price in 2000 and a $3.00 wellhead gas price in
2010.
The base case represents the best estimate of potential emissions reductions that
could be achieved in the future. However, it is also useful to examine the potential emissions
reductions that could be achieved assuming a different set of values for the most important
economic factors impacting the profitability of coalbed methane projects. These factors
include the wellhead gas price, the portion of released methane that is recoverable, capital
costs for recovery and utilization, and disposal costs for water produced from vertical wells.
This analysis shows that even when more conservative values are assumed for these critical
economic factors, the potential for significant emissions reductions remains robust, because a
small number of the gassiest mines continue to show a strong potential to recover methane
profitably.
3-37
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Exhibit 3-1 6
Projected Emissions and Potential Profitable Emissions Reductions
Methane Released from Underground
Mines (Tg)a
Profitable Emissions Reductions (Tg)b
Percent Reduction of Total Emissions
Number of Mines Recovering for Profit
2000
Low
3.2
1.0
32%
16
Mid
3.9
1.4
36%
19
High
5.0
2.2
44%
25
2010
Low
4.3
1.7
40%
25
Mid
5.2
2.2
43%
27
High
6.8
3.1
45%
29
a Methane released is the total amount of methane that would be emitted assuming that no recovery projects
were in place. In 1988, six coal mines recovered 0.25 Tg for pipeline sales, and Ihis report assumes that at
least this amount of methane would be recovered in the future.
b The low, mid, and high estimated potential emissions reductions correspond to the low and high projected
emissions scenarios developed in USEPA (1993). See methodology section for more detailed explanation.
Assumed Wellhead Gas Prices
Base Case
Low Price
High Price
2000
$2.25
$1.50
$3.00
2010
$3.00
$2.25
$3.75
• Wellhead Gas Price
The estimated number of mines that can recover
methane for a profit varies significantly based on the assumed
wellhead gas price. As shown in Exhibit 3-17, 19 mines in
2000 and 27 mines in 2010 are projected to recover methane
for a profit under the base case, which assumes a $2.25/mcf
produced wellhead gas price in 2000 and $3.00/mcf in 2010.
Holding all other values constant, increasing the wellhead gas
price by $0.75 to $3.00/mcf in 2000 and to $3.75/mcf in 2010
results in an additional 7 mines that could recover methane for
a profit in 2000 and an additional 3 mines in 2010. The
additional emissions eduction associated with the increased number of mines recovering is
0.3 Tg in 2000 and 0.1 Tg in 2010.
Decreasing the wellhead gas price by $0.75 to $1.50/mcf in 2000 and to $2.25 in 2010
results in a more significant change in the estimated number of mines recovering than does
increasing it as described previously. Exhibit 3-17 shows that the projected number of mines
that could recover for a profit decreases by 9 in 2000 and by 5 in 2010. More importantly, the
reduction in the number of mines recovering increases the amount of methane emitted by 0.5
Tg in 2000 and 0.2 Tg in 2010. It should be noted, however, that these low wellhead gas
prices are very conservative given current forecasts for future wellhead gas prices in 2000
and 2010.
• Methane Recovered
The base case assumes that coal mines will be able to recover 60 percent of the
methane that would otherwise be emitted to the atmosphere during mining. This recovery
percentage is based on ten years of methane recovery prior to mining of the coal seam. The
3-38
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assumed portion of methane that is potentially recoverable is a very important factor both in
terms of the number of mines that can recover and in terms of the overall achievable
emissions reduction. As shown by the results in Exhibit 3-17, reducing the amount of
methane recovered at each mine from 60 to 50 percent decreases the number of mines
assumed to recover methane to 17 in 2000 and to 27 in 2010. More importantly however, the
overall predicted emissions reduction decreases substantially - to 1.1 Tg in 2000 and 1.9 Tg
in 2010.
Exhibit 3-1 7
Estimated Potential Profitable Emissions Reductions: Comparison of
Results for Different Economic Scenarios Mid Case Emissions
Scenario
BASE CASE
Higher Gas Price
Lower Gas Price
Lower Recovery
Higher Capital Costs
Higher Water Disposal Costs
Year 2000
Total Projected Mid Case
Underground Emissions:
3.9 Tg
Tg No. of Mines
Recovered Recovering
1.4 19
1.7 26
0.9 10
1.1 17
0.9 11
0.9 11
Year 2010
Total Projected Mid Case
Underground Emissions:
5.2 Tg
Tg No. of Mines
Recovered Recovering
2.2 27
2.3 30
2.0 22
1.9 27
1.9 19
2.1 23
The importance of the assumed per mine recovery percentage is highlighted when
comparing the results of the low recovery scenario to the results of the lower wellhead gas
price scenario. Under the lower wellhead gas price scenario, fewer mines are expected to
recover than in the low gas recovery scenario (7 less mine in 2000 and 5 less in 2010).
However, the overall emissions reduction under the lower wellhead gas price scenario is only
0.2 less than the low gas recovery scenario in 2000 and slightly higher in 2010.
• Capital Costs for Recovery and Utilization
When higher capital costs are assumed for developing a recovery and utilization
project, the number of mines able to recover and utilize methane for a profit decreases
substantially from the number of mines recovering in the base case - only 11 recover in 2000
and 19 in 2010. Though the number of mines recovering is lower, the estimated emissions
reduction in this scenario is identical to the low gas recovery scenario in 2010 (1.9 Tg) and
slightly less in 2000 (0.9 Tg as compared to 1.1 Tg for the lower recovery scenario).
The high capital cost case is the most conservative estimate of all of the scenarios.
The number of mines recovering decreases substantially from the number recovering in the
base case - a 42 percent decrease in 2000 and 30 percent in 2010. Moreover, the reduction
in emissions drops by 36 percent from the base case in 2000 and by 14 percent in 2010.
However, even when these significantly higher than average costs are assumed, profitable
3-39
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methane recovery projects would still reduce methane emissions from underground mines by
23 percent in 2000 and 36 percent in 2010.
• Costs for Water Disposal
Costs for disposal of water produced from vertical wells may be a critical factor in
determining whether some mines can recover methane for a profit. Costs for water disposal
can vary tremendously depending on local geologic conditions and environmental
regulations. The base case assumptions incorporate average values for the range of
potential water disposal costs. The high water disposal cost scenario assumes that deep well
injection - one of the more costly water disposal methods - would be required and that large
amounts of water would be produced. When this assumption is used, 11 and 23 mines
recover in 2000 and 2010 respectively. Furthermore, the estimated reduction in emissions
decreases to 0.9 Tg in 2000 and 2.1 Tg in 2010.
For many of the scenarios shown in Exhibit 3-17, the percentage decrease in the
number of mines recovering is much greater than the percentage decrease in the estimated
emissions reduction. This result is due to the fact that a core group of the largest and
gassiest mines show the potential to recover methane for a profit even under conservative
assumptions. Moreover, this relatively small group of mines accounts for a very large portion
of total emissions. Therefore, the development of projects that recover a high portion of
methane at a few of the largest and gassiest mines may have an equal impact on reducing
overall emissions as would developing less effective projects at a greater number of mines.
3.4.3 Regional Impacts
and glassy mines irt the Northern
and CerrtraJJAppaJachian basins
account for jat?oui s$'pe?eeflt of the
potential cost-effective methane
reductions torn ooal raining. The
Warrior basin accounts for about 25
wfcBewestew mines! aocotatf
Projected emissions and the
potential for emissions reduction varied
significantly among the five major
underground coal producing areas
examined in this report. Over half of the
estimated potential for profitable emissions
reductions would come from large and
gassy mines in the Central and Northern
Appalachian basins - approximately 0.7 Tg
in 2000 and 1.2 Tg in 2010. The emissions
reduction potential for the Warrior basin
(Alabama) mines is also projected to be
large - 0.4 Tg in 2000 and 0.6 Tg in 2010. The potential for profitable methane recovery
projects in the western U.S. is expected to increase significantly over the next 20 years; in
2000 western mines are expected to recover 0.2 Tg, while in 2010, they will recover an
estimated 0.4 Tg. The projected emissions and potential for profitable emissions reductions
in each basin is shown in Exhibit 3-18.
Central Appalachian Basin
The Central Appalachian basin is projected to have a large number of mines with a
strong potential to recover methane for a profit - an estimated 6 mines in 2000 and 7 in 2010.
These mines would account for an estimated 29 percent of the nationwide potential cost-
effective emissions reductions in 2000 and 23 percent in 2010. The slightly lower percentage
of total emissions reductions in 2010 as compared to 2000 is primarily due to the assumption
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that Central Appalachian basin mines will account for a lower percentage of underground
production in 2010 than in 2000.
Even under conservative economic conditions, Central Appalachian basin mines are
expected to continue to have cost-effective project opportunities. As shown in the Central
Appalachian basin table, 5 out of the 6 mines showing the potential to recover under base
case assumptions also recover when higher capital costs are assumed. Similarly, in 2010, 5
out of the 7 mines projected to recover under the base case also recover under the higher
capital costs scenario. Moreover, the estimated emissions reduction in the high capital cost
case is only 0.03 Tg less than in the base case.
Five Central Appalachian mines have developed projects to sell recovered methane to
a pipeline. Though owned by two separate mining companies, these mines have jointly
constructed an estimated 40 miles of gathering lines in order to deliver methane recovered
from gob and vertical wells to a main commercial pipeline. During the last seven months of
1992, these mines recovered over 4 billion cubic feet (0.08 Tg) of methane for sale to
pipelines (Virginia Department of Mines, 1993) and are expected to recover a much larger
amount in 1993.
ExhibitS-IS
Projected Emissions and Potential Emissions Reduction by Basin
"reai 2000
Methane Emitted and Recover ed ( Tg )
Year 20 10
Methane Emitted and Recover ed ( Tg 1
Not them Ontt af wai
Appalachian Appalachian
H .Methane Recovei ed
Western iIiinois
and OT net
j Methane Emitted
INJOI thei n Central Wai
Appalachian Appalachian
H Methane Reoovei ed
westei n I i i i no is
and Other
^Methane Emitted
While these five mines have already demonstrated that utilization of recovered
methane appears to be profitable for mines in the Central Appalachian basin, costs for the
development of such projects may be slightly higher for mines in this basin than for those in
other basins. Building a gathering line that connects to a major commercial pipeline is likely
to be one of the most significant costs. Per mile costs of laying pipeline could be high for
this basin due to the rugged, mountainous terrain. Water disposal costs are also likely to be
a major factor for those mines using vertical wells for pre-mining degasification. Deep well
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injection or off-site commercial disposal,
which are among the more expensive
methods, may be required.
Despite the potential for Central
Appalachian mines to face slightly higher
costs than other basins, a large portion of
the potential future cost-effective emissions
reductions will likely come from this basin
due to the large number of gassy mines
showing a strong potential to recover for a
profit.
Northern Appalachian Basin
The potential for the development of
profitable emissions reduction projects in
the Northern Appalachian basin is very
good; the estimated number of mines able
to recover profitably is 5 in 2000 and 10 in
2010, which would reduce emissions by
approximately 0.3 Tg in 2000 and 0.7 Tg in
2010.
Central Appalachian Basin
Emissions Reduction and Mines Recovering
Scenario
Base Case
High Cost
2000
Tg
0.4
0.4
Mines
6
5
2010
L T9
0.5
0.5
Mines
7
5
Northern Appalachian Basin
Emissions Reduction and Mines Recovering
Scenario
Base Case
High Cost
2000
Tg
0.3
0.0
Mines
5
0
2010
Tg
0.7
0.4
Mines
10
5
The Northern Appalachian Basin is
projected to account for over 32 percent of
total emissions in 2000 and over 31 percent in 2010 - the highest percentage of any of the
basins. However, compared to the Central Appalachian basin, a smaller portion of the
Northern Appalachian basin's coal production is projected to come from large and gassy
mines. Accordingly, the volume of emissions that are projected to be recoverable (27
percent) is smaller for the Northern Appalachian basin than for the Central Appalachian basin
(44 percent).
Currently, no Northern Appalachian basin mines have developed commercial methane
utilization projects. Legal concerns related to ownership of the coalbed methane resource
and other barriers have delayed some projects. Additionally, the gassiest Northern
Appalachian basin mines are not as gassy as the Central Appalachian and Warrior basin
mines that are already selling methane to pipeline companies. As discussed earlier in this
analysis, gassiness - defined as methane emissions per ton of coal mined ~ is one of the
principal determinants of a mine's ability to recover for a profit. However, while the Northern
Appalachian basin does not have mines with extremely high methane emissions per ton, it
does have a large number of slightly less gassy mines, which are likely to have a good
potential to recover methane for a profit.
While they may not be as gassy as mines in the Warrior or Central Appalachian
basins, Northern Appalachian mines may face lower costs for developing pipeline injection
projects than mines in these basins and in the Western basins for two reasons. First, the
average distance between a mine and a main commercial pipeline is likely to be lower for
Northern Appalachian mines. In general, the terrain in the Northern Appalachian Basin is less
mountainous than for the Central Appalachian and Warrior basins and for some Western
mines. However, water disposal costs may be similar to those in the Central Appalachian
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Basin; the more expensive disposal practices of deep well injection or off-site commercial
disposal may be required.
Warrior Basin
Though the Warrior Basin has the
fewest underground mines of any of the
basins, its mines are the gassiest. However,
Warrior Basin mines account for a relatively
small portion of current U.S. methane
emissions since five of the largest and
gassiest mines are already recovering
methane for pipeline sales.
Warrior Basin
Emissions Reduction and Mines Recovering
Scenario
Base Case
High Cost
2000
Tg
0.4
0.4
Mines
5
4
2010
Tg
0.6
0.6
Mines
5
5
At least 5 Warrior basin mines in
2000 and 2010 are expected to be able to
recover for a profit. The projected emissions reduction from mines recovering in the Warrior
basin is approximately 0.4 Tg in 2000 and 0.6 Tg in 2010, which will reduce total methane
emissions from underground coal mines in the U.S. by approximately 31 percent in 2000 and
27 percent in 2010. Furthermore, the methane recovered by Warrior basin mines is likely to
represent over half of all methane released from underground mines in this basin. Moreover,
even when higher capital costs are assumed for developing coalbed methane projects,
almost all of the future Warrior basin mines still show the potential to recover methane for a
profit.
Warrior basin mines are likely to face about average costs for developing recovery and
utilization projects as compared to other basins. While costs for drilling vertical and gob wells
may be somewhat higher for Warrior basin mines as compared to mines in other basins (due
to deeper seams), costs for building gathering lines to a main commercial pipeline may be
about average or lower due to relatively close proximity to pipelines and less rugged terrain
than in Central Appalachia or some areas of the West.
Overall, Warrior basin mines are likely to continue to substantially reduce methane
emissions through cost-effective recovery and utilization projects.
Western Basins24
The total number of large and gassy mines located in western basins is small -- only
12 of the 200 mines with the highest methane emissions in 1988 were located in the western
U.S. (USBM 1988). However, there are a few very gassy mines in the western basins, and
these mines have a strong potential for recovering methane profitably. In fact, one mine in
Utah is already recovering methane for sale to a pipeline company.
The potential emissions reduction from Western basin mines is approximately 0.2 Tg in
2000. This reduction is associated with recovery projects at an estimated 3 mines and
24 In this analysis, the term "Western basins" refers to the Piceance, San Juan, and Raton Mesa basins located
in Colorado, Utah, and New Mexico. See section on Other Regions for discussion of coal production and
emissions from the Northwest.
3-43
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Western Basins
Emissions Reduction and Mines Recovering
Scenario
Base Case
High Cost
2000
Tg
0.2
0.2
Mines
3
2
2010
Tg
0.4
0.4
Mines
5
4
represents approximately 40 percent of
projected underground emissions from all
Western basin mines.
Due to the impact of acid rain
legislation, coal production in low sulfur
western mines is expected to increase by
180 percent between 1988 and 2010 - the
largest projected increase for any region.
Accordingly, the number of large and gassy
mines in western basins with the potential to
recover and utilize methane is also projected to increase. The potential emissions reduction
is projected to double between 2000 and 2010; an estimated 0.4 Tg will be recovered in
2010.
Proximity to pipelines will be an especially important factor for western mines, because
the average distance to a pipeline is much greater for western mines than for mines in other
regions. Furthermore, some western mines are located in mountainous territory, which would
increase the per mile cost of laying gathering lines. Costs for disposal of water produced
from vertical wells may also pose a problem for some western mines; stand-alone coalbed
methane operators in the San Juan basin have typically used deep well injection, surface
evaporation, or off-site commercial disposal, all of which can be expensive methods of
disposal.
While some western mines could face higher costs for developing recovery projects
than other areas, the emissions reduction potential in this region is likely to continue to grow
in importance.
Illinois and Other Basins
The Illinois basin is projected to account for only 9 percent of total methane emissions
from underground mines in 2000 and 11 percent in 2010. Of the five major underground coal
basins, the Illinois basin mines are the least gassy. In fact, unless average per mine
gassiness in this basin increases, the gassiest mines in the Illinois basin mines are not
projected to have emissions per ton greater than 1000 cf/ton, which in many cases is the
minimum gassiness level required for profitable recovery. Accordingly, profitable emissions
reductions do not appear to be achievable in the Illinois basin.
Several other regions in the U.S. - the Western Interior, the Northern Great Plains, and
the Northwest - are projected to have very low levels of coal production (less than 10 million
tons collectively in 2000) and will likely account for only 1 percent of underground methane
emissions. Methane emissions per ton of coal mined at underground mines in these regions
are projected to be low - 160 to 180 cf/ton (USEPA 1993). Accordingly, these mines were
assumed not to have the potential to recover methane for a profit.
3.4.4 Effective Methane Reduction Strategies
Several effective methane recovery and utilization options are currently available for
coal mines. Potential recovery methods examined in this analysis include vertical wells drilled
two, five, and ten years in advance of mining and gob wells drilled just prior to or during
mining. The two primary utilization options examined in the analysis involve either selling
3-44
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recovered methane to a pipeline or using it to generate electricity for on-site use or off-site
sale to a utility.
Recovery Methods
Drifting vertical wells ten years in
advance of mfafag & the preferred
recovery method in terms of generating
financial b$RS$$ for incfividuaJ mines
and reducing Imethane emissions to the
atmosphere, i -.-•••
Drilling vertical wells ten years in
advance of mining is the preferred recovery
method in terms of achieving the highest
methane emissions reductions. By
employing this method, individual mines can
recover from 50 to over 70 percent of
methane that would otherwise be released
during mining.25 Furthermore, this
analysis shows that drilling vertical wells ten
years prior to mining will lead to the highest
profits for individual mines. Accordingly, in comparing the potential recovery methods, this
method maximizes the number of mines showing the potential to recover methane for a profit.
Exhibit 3-19 compares the estimated number of mines that are likely to recover
methane for a profit if they were to use vertical wells or gob wells and were to sell the
recovered methane to a pipeline. As shown in this exhibit, compared to other vertical well
options, drilling ten years in advance of mining shows a larger number of mines recovering -
19 mines in 2000 compared to 17 for five year vertical wells and 7 for two year vertical wells.
Moreover, degasification ten years in advance of mining shows a much higher estimated
emissions reduction - 1.4 Tg in 2000 compared to 1.0 Tg for five year degasification and only
0.3 Tg for two year degasification.
In addition to the vertical wells, gob wells may also be a profitable recovery method for
pipeline injection, assuming that a mine is able to recover pipeline quality methane. This
analysis evaluates three scenarios for the gob well recovery method. First, it is assumed that
mines could use gob wells to recover pipeline quality methane. Recovering high quality
methane from gobs requires careful monitoring and management, and, for technical reasons,
may not be possible at all mines. The second scenario assumes that enrichment would be
required for gob gas, and that these costs would be on the order of $1 per mcf of methane
produced. The final scenario assumes that enrichment would be required and would cost
approximately $2 per mcf of methane produced. Currently, the costs for enrichment of gob
gas are highly uncertain because this process has not been applied on a commercial basis at
coal mines. Accordingly, the assumed low cost of $1 per mcf and high cost of $2 per mcf
are rough estimates.
Assuming that a majority of large and gassy coal mines are able to recover pipeline
quality methane from gob wells, the projected number of mines that could recover for a profit
is identical to the ten year vertical well method. However, in terms of overall emissions
reductions, assuming coal mines selected gob well recovery, they collectively would recover
significantly less methane than when ten year vertical wells are assumed and slightly less
methane than when five year vertical wells are the assumed recovery method due to the gob
wells' lower per-mine recovery percentage. This result highlights the importance of ensuring
that the largest and gassiest mines recover as much methane as possible (i.e., through the
25 See discussion in USEPA 1990 and USEPA 1991.
3-45
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use of vertical wells). Even though an identical number of mines shows the potential to
recover methane for a profit using gob wells or ten year vertical wells, the overall emissions
reduction is lower by 35 percent.
Enrichment does not appear to be an economically feasible option for most mines at
this time. Even when a low cost of $1/mcf is assumed, only an estimated 5 mines could
recover in 2000 and 16 in 2010. When the higher estimate of $2/mcf is assumed, the
estimated number of profitable recovery projects falls to 0 for both the years 2000 and 2010.
This result emphasizes the need for research on lowering the costs of dilute methane
enrichment technologies.
The results in Exhibit 3-19 assume that mines will sell methane recovered from vertical
or gob wells to pipeline companies. Results are shown for pipeline injection because, for
most mines, this option is likely to be more profitable than using the methane to generate
power for on-site use or sale to utilities. For some mines, however, power generation may be
more profitable than pipeline injection. Both gob wells and vertical wells could be used to
recover methane for power generation. However, for most mines, the results of this analysis
show that gob wells are likely to be the most cost-effective recovery method for several
reasons. First, unlike pipeline injection, low BTU gob gas is suitable for power generation.
Accordingly, mines would not need to install equipment to ensure the production of high
quality methane. Second, because gob wells do not require hydraulic fracturing or water
disposal, they tend to be less costly to install and operate than vertical wells. Finally, gob
wells recover large amounts of methane in a very short time after the well has been mined
through. However, though gob wells are likely to be a more cost-effective technique for
power generation, the total amount of methane recovered from each mine would be
significantly lower than if ten year vertical wells were used.
Exhibit 3-1 9
Estimated Potential Profitable Emissions Reductions: Comparison of Results for
Different Recovery Methods for Pipeline Projects
Recovery
Method
Vertical Wells: Ten Year
(Base Case)
Vertical Wells: Five Year
Vertical Wells: Two Year
Gob Wells: Enrichment Not
Required
Gob Wells: Low Enrichment
Costs Required ($1/mcf)
Gob Wells: High Enrichment
Costs Required ($2/mcf)
Recovery
Percentage
(Per Mine)
60%
45%
24%
40%
40%
40%
Year 2000
Mid Case Underground
Emissions: 3.9 Tg
Tg
Recovered
1.4
1.0
0.3
0.9
0.3
0
No. of Mines
Recovering
19
17
7
19
5
0
Year 2010
Mid Case Underground
Emissions: 5.2 Tg
Tg
Recovered
2.2
1.7
0.6
1.5
1.1
0
No. of Mines
Recovering
27
27
15
27
16
0
3-46
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Utilization Methods
Of the two principal utilization
options, the net present value (NPV) of
pipeline projects will be significantly higher
than for power generation projects for a
majority of mines. For example, for many of
For most mines, pipeline injection Is the
most cost-effective utilization strategy.
For some mfn^s power geflemSon may
be ^profitable alternative, :
the largest and gassiest mines, the NPV of a
pipeline injection project will be from 5 to 10
times greater than the NPV of a power
generation project. Among other reasons, pipeline projects will tend to be the preferred
option because pipeline projects often have higher annual operating margins and lower initial
capital costs, provided that the mine is within a feasible distance to a commercial pipeline.
An individual mine that developed a pipeline injection project would likely sell
approximately 1 to 7 billion cubic feet of methane per year to a pipeline company. Assuming
that, as shown in Exhibit 3-19 for the ten year vertical well case, 19 large and gassy coal
mines developed pipeline projects in the year 2000, the estimated emissions reduction would
correspond to annual gas sales of approximately 73 billion cubic feet. By comparison, U.S.
natural gas production in 2000 is projected to be in the range of 20 trillion cubic feet
(USDOE/EIA1991).
Though a majority of mines is likely to make higher profits from pipeline injection,
power generation may be more economically attractive for some mines. For example, one of
the primary factors determining whether a pipeline project will be economically feasible is a
mine's proximity to a commercial pipeline. In some cases, mining companies with mines in
remote areas have been able to join together to build gathering lines connecting their wells to
large commercial pipelines. For example, Island Creek Coal and Consolidation Coal jointly
constructed 40 miles of pipeline to link five of their mines to a commercial pipeline. However,
for those mines that are not within a feasible distance to a pipeline and cannot share the
costs of developing a connecting pipeline with other neighboring mines, power generation
may be the only economically viable option.
A mine may also prefer power generation over pipeline injection if the value of the
electricity generated is greater than the price the mine would receive for selling gas to a
pipeline. The value to a coal mine of generating electricity is determined by 1) the savings
realized by generating electricity to meet on-site needs, and 2) the price a mine could receive
by selling power to a utility. In theory, mines would first use the electricity generated from
recovered methane to meet their own on-site needs and then sell any excess methane to
utilities. However, for safety reasons, mines also need to ensure that they have a reliable
source of electricity to keep their ventilation fans running at all times. Accordingly, mines will
need to purchase back-up power from the utilities, which can be quite expensive. Therefore,
some mines may actually continue purchasing electricity from a utility while at the same time
selling back to the utility power generated from recovered methane. In any case, this analysis
showed that for mines located within a feasible distance to a pipeline, only in scenarios in
which a very low wellhead gas price is assumed along with high electricity prices, is the net
present value of a power generation project likely to be higher than that of a pipeline injection
project.
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Finally, power generation may be the only economically viable option for mines that
can neither drill vertical wells several years in advance of mining nor recover pipeline quality
methane from their gob wells.
The results of this analysis show that approximately 14 coal mines in 2000 and 2010
would have the potential to generate power from recovered methane for a profit. Assuming
that these mines use the gob well recovery method, the estimated emissions reduction would
be 0.7 Tg in 2000 and 0.9 Tg in 2010.
Individual mines that would develop coalbed methane power generation are likely to
have an electric capacity in the range of 5 to over 40 MW. In general coal mines would be
considered small power producers. For example, under PURPA requirements, a small power
producer is defined as having production capacity of up to 30 MW, or no more than 80 MW
in the case of biomass or geothermal fuel.
Mines that would select power generation over pipeline injection also have the option
of utilizing ventilation air as combustion air. When ventilation air is used as combustion air for
a generator, the low concentrations of methane can add heat to the combustion process.
However, the energy savings from using ventilation air must be substantial enough to
outweigh the capital costs for ducts to transport the air from the ventilation shaft to the
generator and the energy costs of operating any fans required to move the air. In general,
utilizing ventilation air will only be economic for those mines with a capacity exceeding 30
MW.26 Generators in this size range will require enough combustion air to warrant the
investment in ducts and fans to transport the ventilation air. However, while ventilation air
utilization can improve the economics of a power generation project for very large and gassy
mines, the incremental benefit is not large enough to encourage the development of a power
generation project that otherwise would not be profitable.
The incremental reduction in emissions achieved by utilization of ventilation air can be
significant. For example, a mine that could recover 3.5 billion cubic feet of methane a year
from its gob wells is likely to be able to have a generating capacity of close to 30 MW. If
ventilation air was continuously used as combustion air and the generator were run at
capacity, an additional emissions reduction of 0.2 billion cubic feet a year (or about 0.004 Tg)
could be achieved for this mine.
3.4.5 Benefits to Coal Mines
Large and gassy mines can realize
significant economic benefits from
developing recovery and utilization projects.
As this analysts shows, the direct financial
benefits that can be achieved through
recovering methane for pipeline sales or
electricity generation can be substantial. In
addition, those mines not already employing
degasification systems as part of their
normal mining practices also receive
Many large mines eoulrf realize
economic benefits as a result of developing
recovery projects, in addition to the
financial benefits; of producing gas or
elecifiel^, fficovsry projects can jncrease
productivity, bwer ventilation costs,=and
26
1 The results of this analysis indicate that of the estimated 14 mines in 2000 with the potential to generate
power for a profit, about 6 could have an electric capacity exceeding 30 MW.
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benefits associated with increased productivity, lower ventilation requirements, and improved
mine safety.
This analysis shows that mines can generate significant profits from selling recovered
methane to pipelines. Estimated net present values for such projects range from a few million
dollars for relatively smaller projects (e.g. recovering less than 2 billion cubic feet a year) to in
excess of $20 million dollars for the largest projects. While estimated net present values
varied significantly, a core group of the largest and gassiest mines showed a profit under all
but the most pessimistic scenarios. This analysis also showed that, in some cases,
generating power for on-site electricity needs and for off-site sale to a utility could be very
profitable for mines. Potential net present values for power generation projects at large and
gassy mines would likely be in the range of $1 to $5 million dollars. The estimated range of
net present values for pipeline and power generation projects is shown in Exhibit 3-20.
Exhibit 3-20
Estimated Range of Net Present Values for Coal Mine Methane Projects
Net Present Value
of Project
$0 to $5 million
$5 to $10 million
$10 to $15 million
> $15 million
Total
Number
Base Case/
Pipeline
4
8
3
4
19
of Mines in 2000
Power
Generation
14
0
0
0
14
Number of
Base Case/
Pipeline
5
6
1
15
27
Mines in 2010
Power
Generation
14
0
0
0
14
In evaluating the potential for a mine to generate a profit from a methane recovery and
utilization project, one important factor is whether a mine already employs degasification
wells; most large and gassy mines with the potential for profitable recovery must use
degasification systems as a supplement to their ventilation systems. An estimated 35 mines,
for example, currently use such systems, which include in-mine boreholes or gob wells
(USEPA 1993). For these mines, the costs for drilling recovery wells would not be
incremental to a recovery and utilization project. Accordingly, overall capital costs specifically
associated with the utilization project would be lowered substantially - depending on costs
for surface rights and drilling depth, costs can exceed $200,000 per well.
Though most mines with the potential to recover methane for a profit already use
some type of degasification system as a necessary supplement to their ventilation systems,
this analysis assumes that all costs for degasification systems would constitute an additional
or incremental cost of the project. Therefore, for those mines already employing these
systems, this analysis over-estimates the costs of developing a project because these mines
would drill recovery wells regardless of whether the recovered methane was utilized. When
27 See, for example, Baker et al. (1988).
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costs for recovery wells are not included as an incremental cost of the utilization project, the
profitability of a project can increase by several million dollars.
For those mines not already employing degasification systems as part of their normal
mining practices (or for mines that would drill more wells than otherwise planned),
degasification systems installed as part of a recovery and utilization project will provide the
additional benefit of reducing costs for mine ventilation. Because recovery wells substantially
reduce the quantity of methane released into mine working areas, the quantity of air needed
to ventilate the mine is greatly reduced. Running ventilation fans are a major cost for gassy
coal mines. For example, Jim Walter Resources reports that electricity costs for ventilation at
one of their mines can run between $3500 and $4800 a day (Schlick and Stevenson 1990).
This analysis shows that, over a ten year period, the savings resulting from reduced electricity
costs for ventilation could improve the NPV of a project by several million dollars.
Furthermore, drilling recovery wells may also reduce the number of ventilation shafts that
would be required at a mine. Jim Walter Resources reports that, at one of its mines, if gob
degasification programs were not in effect, three additional ventilation shafts would be
required at a cost of $5 million per shaft (Dixon 1989). Though mines can substantially
reduce their ventilation costs, these savings are not included in the base case analysis shown
in this report.
Increased productivity is another important benefit that results from using
degasification wells to reduce methane levels in mine working areas. When methane
concentrations exceed acceptable levels, all production must cease until enough air can be
pumped into the mine to achieve safe levels again. Any disruption to the production
schedule can be extremely costly for a mine. Experience at many mines has shown that
extensive mine degasification can reduce the number of times a mine must slow or halt coal
production due to high methane levels. Due to the difficulty in quantifying likely "down-time"
for mines, however, this benefit was not incorporated with the analysis.
Finally, one of the most important benefits of degasification systems - especially pre-
mine drainage - is that the reduced methane levels will provide a safer environment for
miners by lowering the risks of fires and explosions. In recent years, there have been several
explosions in North American mines, including the December 1992 explosion where eight
miners died in a southwestern Virginia coal mine. That mine was located less than 20 miles
from the site of a 1983 coal mine explosion, which claimed the lives of seven miners
(Washington Post 1992).
3.4.6 Impact of Including Environmental Benefits
From the perspective of social benefits, the value of coal mine methane projects is
underestimated because the revenue estimates (from selling gas or electricity) do not include
the environmental benefits that result from utilizing, rather than emitting, the methane released
from mines. By omitting these benefits, profitability decisions made by individuals do not
reflect the full value of the project.
To assess the implications of including these benefits, the sensitivity of the results to a
range of values per mcf of methane recovered for pipeline sale was assessed. The proper
value to assign to avoided methane emissions has yet to be determined. These costs have
been estimated in the range of $5 to $20 per ton of carbon contained in carbon dioxide, with
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some estimates as high as $100 per ton.28 This range of costs for avoiding carbon dioxide
build up translates into a value of about $0.57 to $2.30 per mcf for avoiding methane
emissions from coal mines, with a value potentially as high as $11.50 per mcf.29
Including the environmental benefit to society of emissions reductions would lead to a
significant increase in the amount of methane recovered, as shown in Exhibit 3-21. Even at a
low value of $5 per ton of carbon emissions reduced ($0.57 per mcf methane), an additional
0.2 Tg of methane could be recovered in 2000 and 0.1 Tg in 2010. At a value of $20 per ton,
the incremental emissions reduction would be 0.4 Tg in 2000 and 2010. Finally, at a value of
$100 per ton, all technologically feasible emissions reductions could be achieved. The total
emissions reductions would be about 2 Tg in 2000 and 2.8 Tg in 2010 - about 0.6 Tg higher
than if no financial subsidy were in place. With a value of $100 per ton, nearly 70 mines in
2000 and 2010 would find it profitable to develop methane recovery projects.
Exhibit 3-21
Impact of Including Environmental Benefits
Value of Subsidy
$/ton C
($/mcf CHj)
Reference Case
$0 ($0)
$5 ($.57)
$20 ($2.30)
$100 ($11 .50)
Methane
Recovered
(Tg)
1.4
1.6
1.8
2.0
2000
Mines
Recovering
19
25
36
66
Methane
Recovered
(Tg)
2.2
2.3
2.6
2.8
2010
Mines
Recovering
27
30
47
69
3.5 BARRIERS TO THE RECOVERY AND USE OF METHANE FROM COAL MINES
Investments in the recovery and utilization of coalbed methane have the potential to
be profitable for a number of coal mining operations. However, this analysis has not taken
into account certain institutional and technological impediments that may reduce the
profitability of methane recovery projects or preclude such investments altogether. Currently,
a number of problems and disincentives exist that distort the economics of coalbed methane
recovery projects, with the result that many potentially profitable investments are not being
28
See, for example, Moulton and Richards (1990) and Nordhaus (1990).
29
Assuming a mass-based global warming potential (GWP) for methane of 22, the computation for $5/mt of
mtCOt 19.16 g//
carbon is the following:
$5
12 mt Caibon
22
1,000 ft*lmcfCH4 = $0.57/mcf
1 mt Caibon 44 mt CO, mt CH4 10* g/ mt
Similar computations yield $2.30 mcf for $20/ton carbon and $11.50/mcf for $100Aon carbon.
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undertaken. Some of the more significant problems are unique to coalbed methane and the
coal mining industry. These include unresolved issues of coalbed methane ownership,
uncertain qualifying facility status for electric power projects, economic conditions in the coal
mining industry, and some remaining technical challenges. Barriers that are specific to
coalbed methane are discussed in this section. Other problems are not unique to coalbed
methane, but are commonly faced by small or new producers of gas or electricity. These
common difficulties reflect more general conditions in the electric utility, gas and pipeline
industries. Chapter 7 of this report addresses how these general conditions impact coalbed
methane and other methane recovery projects (i.e., methane recovered from landfills and
animal waste lagoons).
Identifying the obstacles to the recovery and utilization of methane from coal mines
leads to the consideration of specific options that can address these impediments. There are
a number of concrete actions that could be taken on both the federal and state level to
remove the barriers to project development and to further encourage the recovery and use of
methane from coal mines. The Energy Policy Act of 1992 includes several provisions that will
help to alleviate some of these barriers; however, additional measures are needed. Options
for addressing barriers specific to coalbed methane are outlined in the following section.
3.5.1 Ownership of Coalbed Methane
Unresolved legal issues concerning the ownership of coalbed methane resources
have constituted one of the most significant barriers to coalbed methane recovery. Ambiguity
in federal and certain state legal systems provides a disincentive for investment in coalbed
methane projects because of the uncertainties as to which parties may demand
compensation for development of the resource. Recent coalbed methane industry forums
have identified ownership issues as serious obstacles to methane recovery, particularly in the
Appalachian region (USEPA 1992a). As interest in coalbed methane recovery increases, and
profitable exploitation of this resource becomes generally recognized, disputes over
ownership may be expected to increase.
Coalbed methane ownership is a complicated issue by virtue of the nature of the
resource itself. Conventional gas and oil resources are found in different, usually deeper,
strata than the strata containing coal reserves. Thus, rights to mineral reserves of the same
tract of land may be easily separated, according to strata, between the owner of the coal
rights and the owner of the gas and oil rights. However, a clear geological separation does
not exist for coalbed methane. Coalbed methane is a gas resource located in the same
strata as coal reserves, making separation of ownership problematic. In addition, coalbed
methane traditionally was not considered a potentially profitable resource worthy of attention
during the leasing process. Thus, it is usually not clear under older leases whether the owner
of the cbatrights is" also the owner of the associated coalbed methane resources. Potentially,
ownership could rest with the holder of the coal rights, the owner of oil and gas rights, the
surface owner, or some combination of the three. The situation may be further complicated
by the fact that there may bre more than a single owner of the-gas and oil rights, the coal
rights, and the surface rights. The multiplicity of owners tends to be particularly severe in the
Appalachian region. «
Virginia has been among the most active states in attempting to address the question
of coalbed methane ownership. Virginia originally tried to legislate ownership with passage of
the Migratory Gas Act of 1977. This legislation determined that, in leases entered into after
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1977, ownership of coalbed methane rested with the surface property owner, unless
otherwise provided for by law. However, industry concerns and questions of constitutionality
led to the repeal of this act in 1990. Instead of attempting to legislate ownership, Virginia has
recently adopted an approach that allows for coalbed methane projects to proceed in
instances when ownership is still undecided. As the culmination of a series of revisions to its
Gas and Coal Act, in 1990 Virginia adopted an amendment allowing for development of
coalbed methane in cases in which ownership remains uncertain or in dispute. In such
situations, the Virginia Gas and Oil Board may enact "forced pooling" of all potential interests
in the coalbed methane. Until such time as ownership is decided, costs or proceeds
attributable to the conflicting interests are paid into an escrow account. This legislation is
important as development of coalbed methane need no longer wait for final determination of
ownership - a determination that can take many years.
The legislative efforts in Virginia provide a useful example of the steps that state
governments may take to resolve the issue of uncertain ownership of coalbed methane
resources. Virginia's approach has received the general backing of the coalbed methane
industry and led to a substantial increase in coalbed methane recovery in that state. Since
passage of the forced pooling legislation in 1990, more than 200 coalbed methane wells have
been drilled and five coal mines have developed methane recovery projects.
Recognizing the importance of finding a solution to the ownership issue, the U.S.
Congress recently passed coalbed methane ownership legislation as part of the Energy
Policy Act of 1992. Under this act, those states determined by the Secretary of Interior as
lacking statutory or regulatory procedures for addressing ownership concerns will have three
years to enact such a program. If the state does not act, the Secretary of Interior will impose
a forced pooling mechanism similar to that enacted in Virginia. The provisions in the Energy
Policy Act are a necessary first step to resolving ownership issues and should help to
expedite the development of coalbed methane projects. However, it still may be necessary
for federal and/or state agencies to assist in negotiations between coal and gas industries to
resolve disputes to ensure that states adopt an approach that will enable projects to progress
without delay.
In addition to the provisions of the Energy Policy Act, recent court decisions seem to
indicate that a consensus may be emerging concerning coalbed methane ownership rights.
Several state and federal courts have ruled that coalbed methane rights belong to owners of
coal extraction rights as opposed to owners of gas extraction rights. However, these
decisions have been based upon different rationales and may not form the basis for a stable
allocation of rights to coalbed methane.
• In United States Steel Corp. v. Hoge, the Pennsylvania Supreme Court held as a matter
of law that the owner of coal rights also held title to the coalbed methane rights.31
The court based its determination on the legal principle that "subterranean gas is
owned by whoever has title to the property in which the gas is resting" and on the fact
that coalbed methane is contained within coal.32 However, the court indicated that
30 Since July 1990, 220 coalbed methane permits have been issued. Prior to 1990, only 52 permits had been
issued. Source: VA Dept. of Mines, Minerals and Energy, Division of Gas and Oil Permit Listing.
31 United States Steel Corp. v. Hoqe, 468 A.2d 1380 (Pa. 1983).
32ld. at 1383.
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coalbed methane that escaped outside of the control of the owner of the coal (e.g.,
into gob zones) would not belong to the coal owner.
Rayburn v. USX Corp. interpreted a deed to include the rights to coalbed methane
within its grant of mineral rights.33 This decision has little precedential value,
because it rests on the specific terms of the particular deed at issue.
• Pinnacle Petroleum Co. v. Jim Walter Resources, Inc. held that the coal owner held
title to the coalbed methane at issue as a matter of law.34 The court did not further
explain its reasoning.
• In Carbon County, et al. v. Baird, et a/. ,35 the court ruled that the conveyance of coal
rights included the right to coalbed methane contained within the coal. The court
adopted the reasoning of the Pennsylvania Supreme Court in Hoge and further held
that, because it is essential to vent coalbed methane in order to mine coal, the grant
of coal rights must include the right to recapture coalbed methane.
• The court in West, et al. v. NCNB Texas National Bank, et al. also followed Hoge and
ruled that coalbed methane belongs to the owner of the coal.36 However, the ruling
differed from Hoge in that the court held that even coalbed methane escaping outside
of the coal seam belonged to the coal owner, as long as it was recovered
contemporaneously with the mining of the coal.
These court opinions thus indicate that coalbed methane normally will be found to belong to
owners of coal rights; however, ownership of coalbed methane that has escaped into gob
areas may continue to be disputed.
On federal lands, ownership of coalbed methane remains in dispute. In 1981, the
Office of the Solicitor of the Department of Interior determined that, under the provisions of
the Federal Mineral Leasing Act, rights to coalbed methane are included within leases of oil
and gas rights and are not included within leases of coal rights.37 However, the coal
operator may ventilate coalbed methane liberated in association with mining operations. This
ruling could impede coal mine projects on federal lands that seek to utilize coalbed methane
as an economic resource. The significance of this federal, policy is limited in terms of
prospects to reduce methane emissions from coal mines, however, because there are
currently few deep, gassy mines on federal lands. Additionally, the federal government's
policy relating to ownership of coalbed methane on Indian lands is the subject of a legal suit
^Rayburn v. USX Corp., No. 85-G-2661-W, 1987 U.S. Dist. LEXIS 6920 (N.D. Ala. 1987), aff'd, 844 F.2d 796
(11th Cir. 1988) (memorandum).
•^Pinnacle Petroleum Co. v. Jim Walter Resources, Inc., No. CV-87-3012 (Cir. Ct. Mobile County, Ala. 1989).
35Carbon County, et al. v. Baird. et al., No. CV 90-120 (13th Jud. Dist. Ct. Dec. 12, 1992).
36West, et al. v. NCNB Texas National Bank, et al., No. 91-000443.51 (Cir. Ct. Mobile County, Ala. Dec. 31,
1992).
37M-36935, 88 Interior Dec. 538 (1981). This determination was reaffirmed in 1990. See M-36970, 98 Interior
Dec. 59 (1990).
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brought against Amoco, et al., by the Southern Ute Indian Tribe, initiated in December
3.5.2 Coal Mining Industry Conditions and Characteristics
The attractiveness of projects to recover and use methane from coal mines must be
considered in the greater context of the coal mining industry itself. Certain conditions and
characteristics in the coal mining industry may limit investment in methane recovery projects.
Market uncertainty, preferences for investments in coal mine productivity, and the relatively
new concept of utilizing methane from coal mines are factors that may deter methane
recovery and utilization in conjunction with coal mining operations.
Coal markets have been depressed in recent years. The period of 1987 to 1990
witnessed a decline in both nominal and real producer prices for coal. Real coal prices fell
slightly in 1991, and this trend is expected to continue in 1992. Production levels have
increased marginally since 1987, though the number of mines and the number of workers has
declined steadily over the past decade. Environmental concerns, embodied in the Clean Air
Act Amendments, are expected to depress the market for high sulfur coal, produced primarily
in eastern coal basins. As a result of industry-wide conditions, most coal companies are
experiencing declining or marginal returns.
Conditions in the coal mining industry may adversely affect the industry's
consideration of methane recovery projects for a number of reasons:
• Capital Constraints. Methane recovery and utilization projects require relatively large
capital investment. Given declining profits, attracting this level of investment may be difficult.
• Emphasis on Productivity, Since the early 1980s, most coal companies have placed
highest priority on investments in increased coal productivity. This preference, combined with
a shortage of investment capital, could make it more difficult for companies to consider
systems for methane recovery and utilization. For mines where high gas emissions pose a
safety hazard, however, these projects can enhance productivity.
• Future Uncertainty. Given adverse industry conditions, many coal companies are
uncertain about their future level of operation. Unless coal companies are confident that they
will be operating in the long-run, they may be hesitant to invest in methane recovery projects
with lifetimes of 10 years or more.
• Cautiousness. As with any new technology, decision makers unfamiliar with
methane recovery and utilization may be hesitant to commit to such projects because of the
possibility of unforeseen problems, and because they are unconvinced that methane recovery
can become a profit center. The successful experiences of several U.S. coal mines should
help to overcome these concerns, however.
While the conditions and characteristics of the coal mining industry noted above may
limit methane recovery projects, the importance of most of these factors may diminish in time
as methane becomes widely recognized as a potentially profitable resource for coal mines.
^Southern Ute Indian Tribe v. Amoco Prod. Co., No. 91-B-2273 (D. Col. filed Dec. 31, 1991).
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The possible formation of partnerships between coal companies and other companies that
may possess fewer investment constraints and/or more experience in coalbed methane
recovery will tend to lessen these limitations as well. Moreover, if returns from conventional
mining activity remain depressed, this may encourage more examination of new types of
projects, such as methane recovery, that could offer greater rates of return. The increasing
interest in natural gas engendered by the Clean Air Act Amendments of 1990, for example,
may encourage coal companies to develop their coalbed methane resources.
State and federal agencies can influence the coal mining industry's consideration of
methane recovery by funding or encouraging key studies related to methane recovery at coal
mines. Such studies could include examination of coalbed methane's effect on employment
and profitability, and comparisons of the potential return on different types of investments
available to coal mining companies. State and federal agencies can also encourage
demonstrations of proven technologies and disseminate information on methane recovery
methods and utilization options, while highlighting instances of successful methane recovery
projects at coal mines. Local agencies may also find a role in identifying and attracting
investors in coalbed methane projects, and facilitating linkages between local coal companies
and potential partners.
A number of different types of financial incentives - such as direct subsidies, tax
credits, or low interest loans - would help to reduce initial project risk. Currently, there are
no existing financial incentives that will encourage future methane recovery at coal mines,
even though such incentives exist for other types of unconventional fuels. Since 1979,
producers of unconventional gas resources, including coalbed methane, have been eligible to
receive the "Section 29" (I.R.S. Code Section 29) production tax credit. In regions where
ownership had not been a critical barrier, this tax credit spurred the development of coalbed
methane projects. The eligibility of coalbed methane under the Section 29 tax credit expired
at the end of 1992, however, and gas produced from coalbed methane wells are only eligible
for the credit if drilled prior to the expiration date. Under the Energy Policy Act of 1992, the
Section 29 tax credit was extended for other types of unconventional gas production, but
coalbed methane is no longer eligible for the production incentive. Furthermore, under the
Energy Policy Act, facilities that produce electricity from renewable energy sources are eligible
for a subsidy of $0.01 per kWh of electricity produced. Facilities that would generate
electricity from coal mine methane, however, would not be eligible for this incentive.
Accordingly, federal and state agencies could consider the development of financial
incentives designed specifically to stimulate the recovery of methane emissions from coal
mines.
3.5.3 Qualifying Facility Status
The Public Utilities Regulatory Policies Act (PURPA) of 1978 guarantees a market for
certain types of small power producers and cogenerators that are considered as "Qualifying
Facilities" (QFs). According to rules implemented by the FERC, to be considered a QF and
qualify for the benefits of PURPA, a power producer must be either a cogeneration facility or a
small power facility. A cogenerator, often a commercial or industrial entity, sequentially
produces steam and electricity. A small power facility produces electricity using biomass,
waste or other renewable sources, such as hydro, solar or geothermal power, and has a
power production capacity of up to 80 MW. Utilities are required by law to purchase power
from QFs and to sell back-up power to QFs at non-discriminatory rates. The state public
utility commissions set the electric power purchase rates at the "avoided cost" of the utility.
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Coal mining companies may be able to sell excess power that they generate from
recovered methane to utilities under PURPA if they qualify as QFs, which depends on whether
FERC classifies coalbed methane as "waste gas." The classification of coalbed methane has
been questioned because of its similarity to conventional gas. For example, under the
current definition of waste gas it is conceivable that FERC could decide that high quality
coalbed methane should be treated as conventional natural gas, which would prevent a
mining operation from achieving QF status and qualifying for the benefits of PURPA. This
uncertainty about the applicability of QF status increases project risk and imposes an
additional hurdle for project developers.
In at least one instance, however, methane recovered from a coal mine was classified
as "waste gas" by FERC. To encourage future projects, FERC should be encouraged to
develop a clear definition of waste gas that includes methane recovered from coal mining
when it is demonstrated that venting is the alternative to using the gas.
3.5.4 Production Characteristics of Coalbed Methane Wells
Coalbed methane degasification wells have production characteristics that differ from
conventional gas wells in a variety of respects. One important difference is the amount of
control the developer has in terms of the gas flow. A conventional gas well can be developed
and the gas flow controlled, or completely halted, at the discretion of the operator. This
provides the operator of a conventional gas well with flexibility as to when the gas is sold.
Unlike conventional gas wells, coalbed methane degasification wells are not subject to the
same control. For safety reasons, methane that is in the process of release from the coal
seam and surrounding strata cannot be turned on and off by the operator.
This production characteristic of coalbed methane wells presents difficulties in the
context of the natural gas and pipeline industries. Much of the consumer demand for natural
gas is seasonal in nature. In addition, in situations of limited pipeline capacity, local pipelines
may not be able to accept the gas supplied from coalbed methane projects on a continuous,
uninterrupted basis. To counteract this difficulty, regulators at the state and federal levels
could require pipelines to give priority access to gas supplies from coal mines where the
alternative is venting the gas to the atmosphere. Actions taken to expand pipeline and gas
storage capacity in key regions, such as Appalachia, would also be expected to help alleviate
this barrier.
3.5.5 Technical Issues
For the most part, the recovery and utilization options that could be used at coal
mines rely on proven technologies. In a few cases, however, there may be technical
limitations for which additional research and development is needed. Areas of emphasis
should include gob gas enrichment, the use of ventilation air for combustion, and water
disposal.
Gob Gas
Techniques for producing high-quality gas from gob wells are well known and are
being used successfully by Jim Walter Resources in Alabama. These techniques are not
difficult, but they do require close coordination of mining and methane recovery operations.
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At some mines, however, it may be impossible to produce pipeline quality methane from gob
wells, which means that the gas must either be used for power generation or enriched before
injection into a pipeline. Using the gas for power generation is technically feasible, and
requires a more limited monitoring of gas quality to ensure that the variation in energy content
is not too large for the turbine to handle. Enriching the gas for pipeline injection is currently
more difficult and expensive and additional research and development into the enrichment
technologies is warranted. To date there are no enrichment facilities separating gob gas from
air at U.S. coal mines, although coal companies have expressed strong interest in such
projects.
Combustion of Ventilation Air
The potential use of ventilation air for power generation has not yet been
demonstrated in the U.S., although technical feasibility studies have been conducted and
designs for the modifications necessary have been outlined.39 In particular, the
effectiveness of more unique design elements, such as for the safe introduction of methane-
enriched air into the boiler, remains to be demonstrated. The earlier analysis of coalbed
methane profitability examined cases that both included and excluded the use of ventilation
air for combustion. While the utilization of ventilation air for combustion purposes served to
increase returns for a project, this was not a significant factor in overall project profitability.
Water Disposal
A third area in which technical challenges may arise is water disposal. Vertical
coalbed methane wells will produce water from the coalbed seam and surrounding strata.
Water is also produced during conventional mining operations, but some states have adopted
separate regulations for water produced in association with coalbed methane operations and
for water produced as a result of mining operations. For mines located near fresh water
bodies or other vulnerable areas, surface water disposal may not be environmentally
acceptable. Several alternative disposal and treatment methods are in use or under
development, including deep well injection and other surface treatment approaches. These
treatments may have higher costs associated with them, and in some cases additional
research is necessary to address technical issues.
Research Efforts
The federal government, states and industry organizations can help to address the
technical challenges facing methane recovery and utilization projects at coal mines by
encouraging and supporting appropriate research and development efforts. The most
important needs in terms of reducing methane emissions from mining include developing
cost-effective gas enrichment methods, developing additional economic uses for medium
quality gas, and developing uses for methane released in ventilation air. The Energy Policy
Act of 1992 mandates the establishment of a demonstration and commercial application
program for advanced coalbed methane utilization technologies. Under the Act, the Secretary
of Energy, in consultation with the Administrator of the Environmental Protection Agency and
the Secretary of the Interior, are required to establish a coalbed methane recovery
39 See, for example, Opportunities for the Utilization of Mine Ventilation Air (Energy Systems Associates 1991)
and Utilization of Coal Mine Methane at Lingan Generating Station (Granatstein et al. 1991). Additionally, a new
study is underway on the potential to use methane released in ventilation air at coal mines in Germany.
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demonstration and commercial application program. The program is to address gas
enrichment technologies, technologies to use mine ventilation air in nearby power generation
facilities, technologies for co-firing methane recovered from mines, and other technologies for
producing and using methane from coal mines. To complement federal actions, it is essential
that state governments, industry organizations such as the Gas Research Institute, state
universities, and other organizations with an interest in the issue also be involved in research
and demonstration projects.
3.5.6 Summary of Problems and Available Options
The preceding discussion has presented a number of unique problems facing
methane recovery projects at coal mines. Though some of the problems represent significant
obstacles to investments in coalbed methane recovery, the discussion has also made clear
that there are options available to federal and state governments that may overcome or help
alleviate these problems. In evaluating the validity of undertaking these options, societal
costs will need to be weighed against societal benefits. For the options presented in this
chapter, the benefits include energy conservation and mitigation of global warming as well as
the financial interest of the coal industry. Exhibit 3-22 summarizes these barriers and some of
the available solutions.
3.6 STEPS TO REMOVING BARRIERS
The following actions on the part of the federal and/or state and local governments
would facilitate the development of coal mine methane projects. Most of the actions
described here involve the removal of current impediments that constrain the wider
development of methane recovery and utilization projects. Accordingly, while the
environmental benefits would be substantial, many of these actions would not require
significant additional expenditures. Some additional actions are also discussed in Chapter 7,
which addresses the more general barriers to methane recovery projects.
3.6.1 Address Ownership Questions
Unresolved legal issues concerning ownership of coalbed methane have delayed or
prevented project development in several states, particularly in the Appalachia region.
Provisions in the Energy Policy Act of 1992 that require states to adopt mechanisms to
resolve ownership issues should help to alleviate this barrier in the future. However, the
following measures may need to be taken to ensure that the goals of the Act are achieved:
• All states with gassy underground mines must develop mechanisms for
resolving ownership disputes, even if this issue has not yet been contested in
the state.
• If necessary, Congress, federal agencies or other entities could assist in
negotiations between coal and gas industries to resolve disputes to ensure that
states adopt an approach that will enable projects to progress without delay.
3-59
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Exhibit 3-22
Barriers, and Related Options Facing Methane Recovery at Coal Mines
Barrier
Ownership
Uncertain rights to gas,
coupled with lengthy
legal process to decide
ownership.
Industry Conditions
Coal industry prefers
investments in
productivity
Coal industry has capital
constraints
Methane recovery and
utilization are considered
to be a high risk
because they are new
and untried at many
mines.
QF Status
Uncertain QF status
under PURPA
Gas Production
Gas production from
wells not controllable
Technical Issues
Technologies for gas
purification and utilization
of ventilation air are not
commercially viable
Solution
Clear legal determination
of gas ownership (which
will be case specific), or
mechanism to allow
projects to proceed
Demonstrate profitability
of gas recovery
Encourage partnerships
with other investors
Reduce uncertainty by
demonstrating key
technologies
Reduce uncertainty by
providing financial
incentives for methane
recovery
Clear determination of QF
status
Assure continuous
access to pipeline
Expand gas pipeline and
storage capacity
Review adequacy of gas
storage and determine if
policy reforms are
needed to increase
storage in key regions
Develop cost-effective
technologies
Possible
Federal Actions
Resolve ownership
issues on federal lands.
Assist states in enacting
policies to address
ownership.
Fund key studies on
profitability;
Provide info on
successful examples
Energy Policy Act
includes provisions for
R&D on several important
technologies
Enact a financial
incentive targeted at coal
mine methane recovery
projects.
Encourage FERC to
classify coalbed methane
as "waste gas"
Encourage FERC to
grant coal mine gas
priority access
Energy Policy Act
mandates research on
several advanced
coalbed methane
utilization technologies.
Possible State Actions
Under the Energy Policy
Act of 1992, states with
this barrier have 3 years
to enact policies to
address ownership
issues or they are
mandated to implement
forced pooling.
Provide info on
successful local
examples
Help identify and attract
investors
Fund research and
development on
important technologies.
Provide financial
incentives.
Fund state and local
R&D, and sponsor
demonstration projects
at local mines.
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3.6.2 Develop Mechanisms that Will Reduce Initial Project Risk and Uncertainty
Recovery of methane released during mining is still a relatively new concept for the
coal mining industry. Accordingly, recovery and utilization projects may not be developed at
coal mines either due to lack of information about successful projects or concern over the
risks of developing a new project. A number of measures can be developed that will reduce
initial project risk and uncertainty, including information dissemination, project demonstration,
and the provision of financial incentives.
• Federal agencies should fund and/or encourage key studies related to
methane recovery at coal mines, including examinations of the effect of the
utilization of coalbed methane on regional employment and mine profitability
and comparisons of the potential return on different types of investments
available to coal mining companies.
• Federal and state agencies should encourage demonstrations of proven
technologies and disseminate information on methane recovery methods and
utilization options, while highlighting instances of successful methane recovery
projects at coal mines.
• Local agencies should also identify and attract investors in coalbed methane
projects and facilitate linkages between local coal companies and potential
partners.
• A number of different types of financial incentives - such as direct subsidies,
tax credits, or low interest loans - would help to reduce initial project risk.
Currently, there are no existing financial incentives that will encourage future
methane recovery at coal mines, even though such incentives exist for other
types of unconventional fuels. Accordingly, federal and state agencies should
consider the development of financial incentives designed specifically to
stimulate the recovery of methane emissions from coal mines.
3.6.3 Develop New Technologies for Methane Recovery and Use
Federal, state, and local agencies can have a positive influence on the coal mining
industry's consideration of methane recovery projects by supporting the development and
commercialization of additional options for methane recovery and use. Programs should
include both research and development and information dissemination. While the Energy
Policy Act of 1992 mandates the establishment of a demonstration and commercial
application program for advanced coalbed methane utilization technologies, the following
additional measures are needed:
• First, it is important to ensure that the demonstration and commercial
application program required under the Energy Policy Act be adequately
funded and fully implemented.
• State governments, industry organizations, state universities, and other
interested parties could contribute to research efforts at the federal level. For
example, such organizations could conduct research as to the types of
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advanced technologies that would be most appropriate for coal mines in
particular regions.
3.6.4 Reduce Barriers to Electricity Sale
Coal mines interested in generating electricity from recovered methane face several
impediments to selling power to utilities. The following actions would facilitate the
development of such projects.
• Methane recovery projects at coal mines that involve on-site power generation
and sales of power off-site should be designated as "Qualifying Facilities" under
the Public Utilities Regulatory Policies Act (PURPA), thus allowing the coal
mines to sell electric power under the PURPA mechanism at avoided cost
rates. FERC should be encouraged to develop a clear definition of waste gas
that includes methane recovered from coal mining when it is demonstrated that
venting is the alternative to using the gas.
• Coal mines and electric utilities share a tightly linked relationship - coal mines
are large consumers of electricity and electric utilities are the primary
purchasers of the coal produced by the mines. Accordingly, utilities have a
significant amount of leverage over their coal customers. States may need to
evaluate the need for actions to ensure that utilities do not inappropriately
discourage coal mines from generating power for on-site use.
3.6.5 Reduce Barriers to Pipeline Sale
Though several U.S. mines have demonstrated that recovering methane for sale to
pipeline companies is profitable, a number of existing barriers constrain the wider
development of pipeline injection projects. The following actions would reduce barriers to
pipeline sale.
• Because production rates from coalbed methane projects at coal mines are not
subject to the same control as conventional gas wells, this methane could be
given preferential access to natural gas pipelines. Federal and state regulators
could encourage pipeline companies to purchase methane from coal mines
where that gas would otherwise be wasted.
• Pipeline capacity in the Appalachian region is severely limited, due to the large
amount of gas being transported from major gas producing regions in the
southern U.S. to the northeastern demand centers. Incentives should be
investigated to help overcome the restrictions on coalbed methane recovery
projects imposed by limited pipeline capacity. The federal government should
examine the possibility of extending incentives or subsidies for pipeline
upgrades, new pipeline construction and extended gathering lines where these
are necessary for the recovery and utilization of significant amounts of methane
from coal mines.
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3.6.6 Encourage Development in the Appalachian Basins
When necessary due to limitations in funding or geographical scope, efforts to
encourage the recovery and use of methane from coal mines should be focused on the
Northern and Central Appalachian Basins. The Northern and Central Appalachian Basins
contain many of the nation's largest, deepest and gassiest underground coal mines, and
projects in these regions may have the greatest potential in terms of profitability and
environmental impact.
While offering the greatest potential for methane recovery, the Northern and Central
Appalachian Basins also tend to face greater problems in terms of ownership, limited pipeline
capacity and limited power transmission capacity. This further highlights the need to focus
efforts on alleviating such problems in these basins.
In summary, resolving the coalbed methane resource ownership question, providing
financial incentives targeted to coal mine methane development, and reducing barriers to
electricity and pipeline sales would enable many coal mines, which otherwise would not
develop projects, to recover and utilize methane for a profit. The first steps to addressing
many of these problems are included in the Energy Policy Act of 1992. It is important to
ensure that the provisions of this Act are fully implemented, however, and that states and the
federal government take appropriate action to address any remaining issues.
3.7 LIMITATIONS OF THE ANALYSIS
There are two primary limitations of the methodology used to evaluate the various
recovery and utilization methods: 1) prototypical mine profiles rather than actual mines were
used to evaluate the recovery and utilization options; and, 2) many of the current barriers to
coalbed methane projects discussed in Section 6 were not taken into account in estimating
the number of mines with the potential to recover methane and the corresponding reduction
in methane emissions.
3.7.1 Lack of Mine-Specific Data
In this analysis, prototypical mine profiles were used to assess the potential for a wide
variety of underground coal mines to employ the recovery and utilization methods. These
profiles were defined by a set of specific characteristics reflecting conditions at actual mines.
Ideally, actual mines would have been used to evaluate the potential recovery and utilization
methods. However, it was not possible to design a realistic analysis for the full population of
individual mines, since data on many important geologic and economic factors are not
available on a mine-specific basis.
As with any financial analysis of a new project, many uncertainties exist as to the true
costs and benefits of the project. Difficulties in estimating costs and benefits of coalbed
methane projects were compounded by the fact that conditions for individual mines vary
widely. To address these uncertainties, ranges, rather than single estimates, were used for all
important geologic and economic parameters. Ranges were developed from actual data
reported by real mines.
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Numerous scenarios were evaluated by assuming different combinations of low,
medium, and high values for all price, cost, and production variables shown in Appendix A.
Recovery and utilization options were then analyzed in terms of the overall results of these
scenarios for the full population of mines. An evaluation of the different scenarios reveals that
the analysis is robust - different combinations of the variables produce only a limited variation
in the overall results.
3.7.2 Current Barriers to Coalbed Methane Projects
A second limitation is that the analysis does not take into account several of the extant
barriers to coalbed methane projects. For example, the estimates for the reduction in
methane emissions shown in Section 5 assume that mines would be able to sell all methane
recovered to a pipeline or all electricity generated to a utility. In reality, many coal mines
currently may not be able to find a buyer for their methane or electricity or may be prevented
from gaining access to gas and electricity markets because of a lack of excess capacity in
pipelines or transmission lines. However, the analysis was designed to evaluate the potential
of individual mines to develop cost-effective coalbed methane projects; the primary focus was
to determine whether U.S. mines could produce enough methane from the coal they mine to
sustain a recovery and utilization project, given current estimates for likely costs and
revenues.
The results of the analysis showed that, in the absence of external barriers, a majority
of large and gassy coal mines are capable of generating a profit and achieving a substantial
reduction in methane emissions. However, in reality only a few U.S. mines have developed
coalbed methane projects. Thus, the analysis reveals that these barriers are a critical factor
constraining the wider development of coalbed methane projects. Furthermore, the results of
the analysis emphasize the need for the removal of the most critical of these legal, regulatory,
and institutional barriers in order to reduce methane emissions from coal mining.
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Coal Magazine. 1989. Annual Longwall Survey.
Coal Magazine. 1991. "Longwall Productivity Down in 1989" February 1991.
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Gas/Energy Technologies Meeting. September 1991.
GRI (Gas Research Institute). 1989. The Coalbed Methane Resource and the Mechanisms of
Gas Production" Topical Report prepared by ICF Resources Inc. for Gas Research
Institute. Contract Number 5984-214-1066. November 1989.
GRI. 1992. Baseline Projection Data Book. 1992 Edition of the GRI Baseline Projection of U.S.
Energy Supply and Demand to 2010.
Hartman, H.L., J.M. Mutmansky, and Y.J. Wang. 19xx. Mine Ventilation and Air Conditioning.
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Hunt, A.M. and D.J. Steele. 1991. Coalbed Methane Technology Development in the
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ICF Resources. 1990b. A Technical and Economic Assessment of Methane Recovery from
Coal Seams. Prepared by ICF Resources Incorporated for U.S. Environmental
Protection Agency, Office of Air and Radiation. September 1990.
ICF Resources. 1990c. Opportunities for Power Generation from Methane Recovered During
Coal Mining Draft Report prepared by ICF Resources for U.S. Environmental
Protection Agency. September 30, 1990.
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Keystone. 1989-1990. Keystone Coal Industry Manual. Years 1989 and 1990. Chicago,
Illinois: Maclean Hunter Publishing Co.
Kim, J. and J.M. Mutmansky. 1990. "Comparative Analysis of Ventilation Systems for a Large-
Scale Longwall Mining Operation in Coal Seams with High Methane Content" Journal
of Mining Research and Engineering. Volume 3 No. 2. pp. 99-117.
Kline R.J., LP. Mokwa, and P.W. Blankenship (Island Creek Corporation). 1987. "Island Creek
Corporation's Experience with Methane Degasification" Proceedings of the 1987
Coalbed Methane Symposium. Tuscaloosa, Alabama. November, 1987.
Kuuskraa and Zuber. 1990. Optimizing Well Spacing and Hydraulic-Fracture Design for
Economic Recovery of Coalbed Methane. SPE Formation Evaluation.
Lambert and Graves. 1989. "Production Strategy Developed" Oil & Gas Journal. November
20, 1989.
Meyers, W. "Electricity Needs in Coal Mining" in Crickmer and Zegeer Elements of Practical
Coal Mining 2nd Edition. Society of Mining Engineers.
Mills, R.A. and J.W. Stevenson (Jim Walter Resources, Inc.). 1991. "History of Methane
Drainage at Jim Walter Resources, Inc." Proceedings of the 1991 Coalbed Methane
Symposium. The University of Alabama/Tuscaloosa. May 1991.
Moulton, R.J. and K.R. Richards. 1990. Cosf of Sequestering Carbon Through Tree Planting
and Forest Management in the United States. U.S. Department of Agriculture Forest
Service. General Technical Report WO-58. December 1990.
Morgan, Jill. M. and Elizabeth A. McClanahan, "Competing Ownership Claims to Coalbed
Methane in the Appalachian Basin," The Landman, July/August 1990.
Nordhaus, William D. 1990. 'To Slow or Not to Slow: The Economics of the Greenhouse
Effect" Yale University, New Haven. February 1990.
Northwest Fuel. 1990. Survey of U.S. Coal Mine Degasification Processes. Prepared by
Northwest Fuel Development, Inc. Portland, Oregon, for U.S. Environmental Protection
Agency, Office of Air and Radiation.
Ortiz, I. 1992. "Environmental Issues Affecting Coalbed Methane Gas Development in the
Appalachian Basin" United Energy Development Consultants, Inc. Pittsburgh, PA.
Schlick, D.P. and J.W. Stevenson. 1990. Methane Degasification Experience at Jim Walter's.
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Sykes. W.W. 1989. "Gathering Systems Concepts-Planning, Design and Construction" in
Proceedings of the 1989 Coalbed Methane Symposium. The University of Alabama at
Tuscaloosa. April 17-20, 1989.
Trevits, M.A., G.L. Finfinger, and J.C. Lascola. 1991. "Evaluation of U.S. Coal Mine Emissions"
Proceedings of the Fifth U.S. Mine Ventilation Symposium. Morgantown, West Virginia.
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Littleton, Colorado.
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million cubic feet per day.
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APPENDIX 3A
CALCULATIONS AND DATA TABLES
This appendix describes the calculations that were made and assumptions that were
used to develop the net present value analysis for evaluating the various recovery and
utilization options at individual mine profiles. The appendix is divided into three sections: 1)
Physical Calculations for Recovery; 2) Physical Calculations for Utilization; and, 3) Financial
Calculations.
PHYSICAL CALCULATIONS FOR RECOVERY
Physical calculations for recovery include calculations for the number of wells drilled,
the quantity and quality of methane recovered over the lifetime of a project, and the amount
of water produced from vertical wells.
Number of Wells Drilled
Research on optimal spacing for vertical wells is often presented in terms of acre to
well ratios, while information for gob wells is often described in terms of number of wells per
longwall panel. However, the characteristics of the mine profiles do not contain information
on acreage or number of longwall panels mined. Therefore, the acres to well and wells to
longwall panel ratios are converted to a tonnage to well ratio, and the number of wells drilled
each year is calculated from annual coal production. A different ratio is used for gob wells
and for vertical wells.
The total number of wells drilled will depend on the size of the project and on the
tonnage to well ratio. Under the base case assumptions used in this analysis, the size of a
project (in terms of tons of coal produced) is ten times annual coal production. An example
of how tonnage to well ratios are used to determine the number of wells drilled is shown in
Exhibit 3A-1. The actual ratios used for gob wells and vertical wells are shown in Exhibit 3A-2
and 3A-3 respectively.
Exhibit 3A-1
Sample Calculation for Determining Number of Wells Drilled for a Mine Profile
Example:
Annual Coal Production = 2 million tons;
Size of Project (tons of coal) = 10 x annual coal production.
Tonnage per Vertical Well Ratio = 500,000 tons per 1 vertical well.
Total number of wells drilled each year: 2 million tons/500,000 tons per well = 4 wells
4 wells x 10 wells per year = 40 wells total.
3A-1
-------
Gob Wells
Basin
All Basins
Low
250,000
Medium
350,000
High
500,000
Exhibit 3A-2
Tonnage per well Ratios for Gob Wells
Assumptions: For gob wells, low, medium and high tonnage per well ratios were developed by assuming that
two, three, or four gob wells would be needed for each longwall panel. Furthermore, it was assumed that an
average longwall panel contains approximately 1,000,000 tons of coal. The average size of a longwall panel is
based on Coa) Magazine (1991). This article showed that the average size for a longwall panel in 1989 was:
cutting height, 6 feet; length 5,406 feet; width, 703 feet. Using these estimates and assuming a density of 1850
tons of coal to an acre-foot, an average longwall panel would be approximately 87 acres and would contain
approximately 970,000 tons of coal. Tonnage per well ratios were calculated by assuming that two, three, or
four gob wells would be needed for each longwall panel. These numbers were then rounded.
Sources used for well spacing: 1) USEPA (1990); 2) Baker el al. (1988)
Vertical Wells
Exhibit 3A-3
Tonnage per Well Ratios for Vertical Wells
Region
Eastern Basins
Western Basins
Low
250,000
500,000
Medium
500,000
1,000,000
High
1,000,000
2,000,000
Assumptions: For eastern basins, tonnage per well ratios were calculated by assuming well spacing of 20, 40,
and 80 acres (low, medium, and high). Furthermore, it was assumed that on average, 80 acres would be
roughly equivalent to 1 million tons of coal (see calculations for gob well assumptions using average longwall
panel size in tons and acres). For western basins, tonnage per well ratios were assumed to be higher -
equivalent to well spacing of 40, 80, and 160 acres.
Sources for Well Spacing: 1) Kuuskraa and Zuber (1990); 2) Bise and Sheetz (1989); 3) Ammonite Resources
(1991); 4) USEPA (1990).
3A-2
-------
Quantity of Methane Recovered
Methane Emissions from Annual Coal Production (Assuming No Recovery)
A mine profile's potential
annual methane production is
determined primarily by calculating
annual "status quo" emissions - the
level of emissions assuming no
recovery and utilization techniques
are employed. Status quo emissions
are calculated by multiplying annual
coal production for each mine profile
by its emissions per ton of coal
mined. This equation yields the total potential methane that could be recovered from one
year's worth of coal production.
Calculation:
Annual Production
x
Emissions per Ton
Status Quo Emissions
Example:
2 million tons
x
2000 cf/ton
4000 mmcf
Annual Emissions.
Methane Recovered from Annual Coal Production
The amount of methane
recovered from one year's worth of
coal production is calculated by
assuming that each unique recovery
strategy can capture a percentage of
the status quo emissions. For
example, gob wells are assumed to
recover from 30 to 50 percent of the
methane that would otherwise be
emitted, while ten year vertical wells
are assumed to recover from 50 to 70
percent of such methane. The recovery
Exhibit 3A-4.
Calculation:
Status Quo Emissions
x
Recovery Percentage
For Each
Recovery Method
Methane Recovered
Example:
4000 mmcf
x
50% recovery
percentage for 10 yr.
Vertical Well
2000 mmcf
Methane Recovered
percentages for each recovery method are shown in
Exhibit 3A-5 shows the percentage of emissions that would be recovered each year
over the lifetime of a vertical well. For gob wells, it is assumed that all methane would be
produced within one year after a well is drilled. For vertical wells, the amount of methane
recovered each year varies depending on the age of the well. Gas production rates from
individual vertical wells tend to follow an exponential decline curve - the amount of gas
produced in the early years is much greater than the amount produced in later years.
Accordingly, the amount of methane recovered within the first year after a well is drilled is
assumed to be higher than the second year and the second year higher than the third, etc.
3A-3
-------
Exhibit 3A-4
Recovery Percentages for Vertical and Gob Wells
Gob Wells
Ten Year Vertical Wells
Five Year Vertical Wells1
Two Year Vertical Wells
Low
30%
50%
Medium
40%
60%
High
50%
70%
Overall range for five year well is 35 to 55%
Overall range for two year well is 25 to 45%.
1 Production for two and five year vertical wells are determined from the assumed recovery percentage for a
ten year well and gas production decline curves.
Sources used for recovery percentages for ten year vertical wells and gob wells: 1) USEPA (1990); 2) USEPA
(1991). Sources used for production decline curves for vertical wells include: 1) Lambert and Graves (1989);
2) Zebrowitz and Thomas (1989).
Exhibit 3A- 5
Methane Recovery from Vertical Weils Drilled Ten Years in Advance of Mining For a Sample Mine Profile
Methane Recovered from
Annual Coal Production
Annual Coal Production: 2.000.000
Methane Emissions per ton
of coal mined (cubic feet): 2,000
Recovery Percentage of Methane Emitted
Ten Year Vertical Degas Recovery Method: 60%
Total Recovered from Annual Production:
(in thousand cubic feet of methane) 2.400.000
Percent of Methane
Recovered Over Ten Years
Percent Mcf
Year of Total Recovered
1
2
3
4
5
6
7
8
9
10
Total
22%
18%
14%
11%
10%
7%
6%
5%
4%
3%
100%
528.000
432.000
336.000
264,000
240,000
168.000
144,000
120.000
96.000
72.000
2,400,000
3A-4
-------
Methane Recovered Over Lifetime of A Project
Methane recovered during each year of the project depends on the number of wells in
operation and the stage in the project lifetime. The number of wells in operation is calculated
from the number of wells drilled each year, the expected lifetime of those wells, and the total
years of drilling. The analysis assumes that an equal number of wells are drilled each year.
As discussed earlier, the number of wells drilled each year is based on a mine profile's
assumed annual coal production. The expected lifetime of the well depends on the recovery
method selected. In this analysis, gob wells are assumed to produce methane for one year,
while vertical wells are assumed to produce methane from the time they are drilled until the
coal seam into which they have been drilled is mined through.1 The years of drilling varies
under different scenarios. For the base case and conservative scenarios, it is assumed that
wells are drilled over a period of ten years. The stage of the project lifetime is also important
in determining the amount of methane recovered because the age of the wells in operation at
any given time varies over the lifetime of the project.
Exhibit 3A- 6 illustrates how the total amount of gas recovered each year for a sample
mine profile using two year vertical wells and a ten year drilling period would be calculated.
Exhibit 3A-7 illustrates the amount of methane recovered each year for a ten year vertical well
recovery method and ten years of drilling. Exhibit 3A-7 shows that during the first year of the
project, methane is recovered only from those wells drilled in the first block of coal. During
the second year, two sets of wells are in operation. During the third year, three sets of wells
are in operation, and so on. By the tenth year, the maximum amount of methane recovered
and the maximum number of wells in operation has been reached.
Exhibit 3A-6
Methane Recovered over Lifetime of a Project for a Sample Mine Profile Two
Year Vertical Well Recovery Method
Went Wads Wells WeHi WeM
Drilled In Dfilledln Dirtied In DflMedta Drifted In
Y»«r Year i Yen 2 Year 3 Year 4 Year 5
1 528000
2 432 000 528 000
3 MINE 432.000 528000
4 MINE 432.000 528.000
5 MINE 432.000 528000
6 MINE 432 000
7 MINE
8
9
10
11
Total
MCF 960000 960.000 960.000 960.000 960.000
went Welt Went WeHi Wefts
Dewed In Dfftedtn DrWedln DtWedln DrMedln
Year 6 Year 7 Year B Year 9 Year 10
528000
432.000 528.000
MINE 432.000 528.000
MINE 432.000 528.000
MINE 432.000 528.000
MINE 432.000
MINE
960.000 960.000 960.000 960.000 960.000
Tout
Recovered
(Mcf)
528.000
960.000
960.000
960.000
960.000
960.000
960.000
960.000
960.000
960.000
432.000
9.600.000
1 Vertical wells can be drilled two, five, or ten years in advance of mining.
3A-5
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Quality of Methane Recovered
Vertical wells are assumed to recover methane that is over 95 percent pure. For gob
wells, two scenarios are examined. In the first scenario, gob wells are assumed to produce
medium heating value gas that would need to be enriched to pipeline quality, and the costs
per mcf of methane are taken into account. In the second scenario, gob wells are assumed
to recover pipeline quality methane.2
Water Production from Vertical Wells
Vertical wells often produce large quantities of water and small volumes of methane
during the first several months they are in operation. Water production from vertical wells is
estimated by using a gas production (cubic feet) to water production (barrels) ratio. The
ratios used in this analysis were developed from an examination of data on water and gas
production from stand-alone coalbed methane wells during the first two years of production.
For simplifying purposes in this analysis, water production was assumed to remain constant
over the lifetime of the well. However, because water production usually decreases
significantly (compared to gas production) after the first few years, the use of a constant gas
to water production ratio over the lifetime of a well is a conservative assumption. Exhibit 3A-8
shows the gas production to water production ratios.
Exhibit 3A-8
Gas Production to Water Production Ratios
(mcf gas to bbl water)
Ratios used for all basins
Low
2
Medium
1
High
0.5
Sources used to develop ranges: A number of sources showing gas and water production data for verticals
were examined including Lambert and Graves (1989) and Zebrowitz and Thomas (1989). Actual gas to water
ratios varied significantly for individual wells. However, the ranges used in this analysis were designed to be
conservative (i.e. they were designed to over-estimate rather than under-estimate the quantity of water that
would be produced from a vertical well).
PHYSICAL CALCULATIONS FOR UTILIZATION
Equipment Needed
For pipeline injection, equipment includes gathering lines (from individual wells to a
central compression point), compressor(s), a water disposal system (vertical wells only),
equipment for processing, treatment and enrichment (gob wells only), and a pipeline from a
central compressor at the mine to a main commercial pipeline. The equipment required for
power generation includes gathering lines from the wells to the generator, water disposal
equipment (vertical wells only), and a generator. Additionally, in some cases in which power
is sold to a utility, an interconnection facility may be needed. The equipment required for
2 In essence, it is assumed that a mine will be able to maintain pipeline quality methane from gob wells as has
been done at the Jim Walter Resources mines in Alabama.
3A-7
-------
each recovery and utilization method is shown in Exhibit 3A-9. A discussion of the cost of
these items is shown in the Financial Calculations section.
Exhibit 3A-9
Equipment Needed for the Potential Recovery and Utilization Methods
Equipment
Gathering Lines from
Individual Wells to Central
Compressor or to Generator
Gathering Lines from Central
Compressor to Main
Commercial Pipeline
Water Disposal
Central Compressor
Processing/
Treatment
Enrichment1
Generator
Interconnection Facility or
Line Upgrades
Vertical/
Pipeline
X
X
X
X
X
Gob/
Pipeline
X
X
X
X
X
Vertical/
Power
X
X
X
X
Gob/
Power
X
X
X
1 Enrichment is not always required for gob gas to be utilized for pipeline injection. In some cases, it is
possible to maintain pipeline quality methane from gob wells. This analysis examines both scenarios.
Gas Produced for Pipeline Injection
The amount of gas sold each year depends on the annual amount of methane
recovered and on the amount of methane required to fuel the compressor (compression
loss). Compression loss is assumed to range from 5 to 10 percent of production and varies
according to the distance to a commercial pipeline.
Electricity Produced
Electricity production is calculated from methane recovered and the assumed heat rate
of the generator (Exhibit 3A-10). The capacity needed for the generator is calculated by first
determining the maximum hourly gas production and then applying the heat rate. Mine
profiles with daily production less than 1 mmcfd (approximately 3 to 5 MW) are assumed to
install an 1C engine, while those above 1 mmcfd are assumed to install a gas turbine. As
mentioned earlier in the report, gas turbines are likely to be preferred over 1C engines as 1C
engines are more sensitive to fuel heat variations. However, gas turbines are typically
uneconomic below 3 to 4 MW. Therefore, the analysis assumed that mines with methane
production less than 1.0 mmcfd would select an 1C engine and mines with production greater
than 1.0 mmcfd would select a gas turbine.
3A-8
-------
Exhibit 3A-10
Generator Heat Rates (Btu/kWh)
Gas Turbine
(Used for production
above 1 mmcfd)
1C Engine
(Used for production
below 1 mmcfd)
Low
8,000
9,000
Medium
11,000
12,000
High
14,000
15,000
Sources used to develop ranges: 1) Sturgill (1991); 2) IGF Resources (1990c); 3) Wolfe and Maxwell (1990);
4) Personal Communication with Allison Gas Turbines.
Utilization of Ventilation Air in an On-Site Turbine
Ventilation air can be used as the combustion air in a generator. Methane in
ventilation air contributes heat to the combustion process. As mentioned in the overview of
recovery and utilization methods, there are two possible scenarios for the use of ventilation
air: 1) use in a coalbed methane fueled gas turbine, or 2) use in a mine-mouth coal fired
boiler. The second possibility is not addressed in this analysis due to the limited number of
large and gassy mines that are located within a few miles of a mine-mouth power plant.
Under the first scenario, the primary fuel for the generator would be methane
recovered from gob and/or vertical wells, but ventilation air would be used as the combustion
air. Gas turbines require approximately 350 cubic feet of combustion air for each kWh. Thus,
the capacity of the generator and the amount of electricity produced determine the total
amount of ventilation air that can be utilized. The formulas used to calculate the energy
contribution from ventilation air are shown in Exhibit 3A-11. The concentration of methane in
ventilation air is determined from the air to methane ratios used to calculate savings from a
reduced need for ventilation air shown in Exhibit 3A-13. The energy needed for fans to
transport the air from the ventilation shaft to an on-site generator is also calculated according
to the air power formula shown in Exhibit 3A-13.
On-S'rte Energy Needs (Capacity and Total)
The calculation of on-site electricity needs is important for two reasons: 1) to
determine the potential savings to a mine from generating its own electricity; and, 2) to
determine the amount of power generated in excess of on-site needs that could be sold to a
utility. Total annual on-site electricity needs are calculated by a kWh per ton of coal mined
ratio; these ratios are shown in Exhibit 3A-12.
3A-9
-------
Exhibit 3A-11
Calculations for Incremental Electric Capacity from Ventilation Air Utilization
Utilization of ventilation air leads to a slight increase in the capacity of a generator.
Assume capacity without ventilation air to be C kw and assume that the use of ventilation air increases the
capacity by a factor of r. With an unlimited supply of ventilation air, the final capacity with the use of ventilation
air is given by the following infinite series:
Ventilation air = C + Cr + Cr2 . . . .
= C/ (1-r) kw
r can be calculated as follows:
[Heat content/heat rate] x scfh air required for generator x methane concentration in ventilation air
Where:
Heat content = 1000 Btus for each cf pure methane
Heat rate = for example, 11,000 btus per kWh.
Air required for generator = 350 scfh.
Methane concentration = for example, .002
Sources used for air requirements of a generator: Energy Systems Associates (1991)
kWh per ton of
mined
Note: The high
per ton of coal
coal
Exhibit 3A-12
On-site Electricity Needs (kWh per ton of coal mined)
Low Medium High
13 22 30
range assumes that a coal preparation plant, located on-site, would require an additional 6 kWh
mined.
Sources used to develop ranges: 1) Sturgill (1990); 2) Meyers (1981); 3) ICF Resources (1990c).
The peak capacity required by the mine is calculated from the total annual kWh
needed and by assuming an electricity demand pattern. The electricity demand pattern
establishes the maximum power production capacity required during each day. To determine
the electricity demand pattern, it is assumed that the mine would be in full operation 220 days
a year for 20 hours a day, while the ventilation air system would need to be run continuously
throughout the year. Running fans to move ventilation air is assumed to account for
approximately 20% of a mine's total electricity demand, even when recovery methods were
used to reduce the quantity of methane in mine working areas (USBM personnel estimate that
40 to 60 percent of mine energy needs can be attributable to electricity required for ventilation
assuming that no degasification systems are used).3
3 The formula used to calculate on-site capacity is: [E*(.80)/(220*15)] + [E*(.20)/(365*24)] where E is total
- annual kWhs (see table above).
3A-10
-------
Exhibit 3A-13
Calculations for Determining Energy Savings from a Reduction in Ventilation Air Needs
Calculations
The analysis assumes that the quantity of
methane that would have been emitted into
working areas is reduced by the amount of
methane recovered by vertical or gob wells.
However, it is also assumed that the
ventilation air needs could only be reduced
by a percentage of the methane reduction.
The reduction in ventilation air needs used in
the analysis are 40, 60, or 80 percent.
A ratio of ventilation air needed to methane
emitted into mine working areas is
calculated. Low, medium, and high air to
methane ratios used are: 250, 500, 750 (cf
air to cf methane).
Calculate electricity savings by assuming a
ratio of kw/cfm of ventilation air.
Air power (hp) = 5.2HQ/33,000
Where Q = cfm air, H inches of head for the
fan, and 1.34HP = KW.
Assuming low, medium, and high values for
H of 4, 7, and 10 the following ratios of KW
to cfm of air were determined: Low .00047;
Medium .00082; High .001175.
Assume that without recovery a given coal
mine would have emissions of 8 mmcfd.
Further assume that a vertical well will
remove 60 percent of methane that would
otherwise be emitted into the mine.
However, ventilation air needs will only be
reduced by 80 percent of this amount.
Thus, the reduction in ventilation air needed
would be 60 percent x 80 percent = 48
percent.
Assume that 500 cf of air would be needed
to dilute each cf of methane emitted into the
mine working area. As stated above, without
recovery, methane emissions would be 8
mmcfd. Thus, the ventilation air needed
would be 500 x 8 mmcfd or 4,000 mmcfd
(approximately 2.8 million cf per minute).
Applying the formula for air power needed,
the total electric capacity needed to ventilate
the mine would be 2,296 kws (2.8 x medium
value for air power of .00082). Thus,
assuming the ventilation system is run
continuously, annual electricity needs would
be over 20 million kWh. The 48 percent
reduction is then applied and the industrial
electricity price (see Exhibit 3A-26) is used to
determine the total $ savings.
Sources: Air to Methane Ratios were developed from USBM (1973). Energy needed for ventilation air (air
power formula) is shown in numerous mining textbooks (e.g. Hartman et al.). Ranges for H were developed
from communications with USBM personnel and J. Mutmansky, Professor of Mining at Pennsylvania State
University in Pittsburgh.
Energy Savings from Reduction in Ventilation Air Needs
While a minimum flow rate of ventilation air is always required in a mine, the amount of
ventilation air needed above this minimum is primarily determined by the level of methane
emissions in the working areas. Since recovering methane through the use of gob or vertical
wells reduces the amount of methane emitted into mine working areas, a mine can realize
significant electricity savings from a reduced need for ventilation air. Though energy savings
from a reduction in ventilation air needs was examined in this analysis, the scenarios
presented in the main text of the chapter do not include these savings. Therefore, these
scenarios under-estimate the true net present value to a coal mine of developing a methane
recovery and utilization project. Exhibit 3A-13 shows calculations for determining energy
savings.
3A-11
-------
FINANCIAL CALCULATIONS
The methodology for evaluating the various recovery and utilization options is a
discounted cash flow analysis. In order to perform this analysis, annual cash inflows and
outflows are estimated. These annual cash flows are based on estimates for capital and
operating costs, operating revenue and savings, and other financial factors.
Capital Costs
The required capital investments are calculated for each recovery and utilization
strategy. Except for recovery wells, all capital outlays are assumed to occur at the start of the
project. For recovery wells, capital outlays are assumed to occur at the start of each year
during which wells are drilled (see explanation of staggered drilling in physical calculations
section). For all capital investments, all equity financing is assumed.
Capital Costs for Recovery Wells
Capita! costs for vertical and gob wells are estimated on a per well basis. The number
of wells drilled each year depends on a mine profile's assumed annual production (see
discussion in Physical Calculations section). Due to the need for hydraulic fracture treatment
and water pumping equipment, vertical wells tend to have higher capital costs than gob wells.
However, gob wells sometimes require powerful exhausters to provide the suction needed for
methane flow.
Capital costs for vertical and gob wells vary by basin. For vertical wells, eastern basin
wells require less expensive methods/materials for drilling, pumping and completion. In
general, compared to western basins, eastern basins are usually shallow, water-saturated, low
in reservoir pressure, and have low formation permeability. For both vertical and gob wells,
variations between and within basins are attributable to differences in well depths (drilling
costs), equipment costs and costs for surface rights (which can vary significantly on a site
specific basis depending on terrain and other land use in the area). Capital costs for gob
wells and vertical wells are shown in Exhibits 3A-14 and 3A-15, respectively.
Exhibit 3A-14
Capital Costs for Gob Wells
(per well costs)
Basin
Central Appalachian
Northern Appalachian
Illinois
Warrior
Western
Low
$80,000
$60,000
$50,000
$90,000
$100,000
Medium
$130,000
$110,000
$100,000
$140,00
$150,000
High
$190,000
$170,000
$160,000
$200,000
$210,000
Note: Capital costs for gob wells include all costs for surface drilling rights, site development and preparation,
and costs for drilling, completing and equipping the wells.
Sources used to develop ranges: 1) USEPA (1990); 2) IGF Resources (1990b); 3) Baker et al. (1988).
3A-12
-------
Exhibit 3A-15
Capital Costs for Vertical Wells
(per well costs)
Basin
Central Appalachian
Northern Appalachian
Illinois
Warrior
Western
Low
$60,000
$50,000
$45,000
$90,000
$320,000
Medium
$140,000
$125,000
$115,000
$190,000
$450,000
High
$225,000
$205,000
$195,000
$290,000
$580,000
Note: Capital costs for vertical wells include all costs for surface drilling rights, site development and
preparation, drilling, completing and equipping the wells and hydraulic fracture treatment.
Sources used to develop ranges: 1) USEPA (1990); 2) ICF Resources (1990b); 3) GRI (1989); 4) Ammonite
Resources (1991); 5) Hunt and Steele (1991); 6) Spears and Associates (1991).
Capital Costs for Water Disposal System
Vertical wells typically produce significant quantities of water during the first months of
operation. Production water often contains high levels of salt and other minerals and must be
disposed of in an environmentally safe manner. Water disposal costs will vary for individual
mines depending on geologic conditions and state or local environmental regulations.
Disposal methods include direct land application, stream or river discharge, evaporation pits,
deep injection disposal wells, and off-site commercial disposal.
For direct land application, water is transported through a pipeline and distributed by a
sprinkler system. Frequently, water must be treated or diluted before it is land applied.
Stream or river discharge can be used when the produced water does not contain high levels
of dissolved solids. However, the water quality of the river or stream must be continuously
monitored. Evaporation pits are typically used in western basins. For this disposal method,
water is transported through a pipeline or trucked to the pit. Finally, disposal wells may be
used when no other method is available. Water is transported to the well and reinjected into
selected formations. Capital costs for water disposal systems are shown in Exhibit 3A-16.
For the costs shown below, it is important to note that the overall costs for water
disposal are dependent upon both the capital and operating cost component. For example,
disposal wells (deep well injection) will have high capital costs, but, depending on the
situation, may have lower operating costs compared to some methods. In contrast,
commercial off-site disposal will have low, if any, capital costs, but high operating costs. The
high water disposal cost scenario presented in the report assumed that deep well injection
would be needed (high capital costs, medium operating costs).
3A-13
-------
Exhibit 3A-16
Capital Costs for Water Disposal (Vertical Wells Only)
$/barrel x maximum barrels produced per year
Basin
All basins
Low
$.30
Medium
$.90
High
$3.30
Notes: Low costs for the Warrior basin imply that stream discharge is available and that little treatment would
be needed, which is sometimes practiced in the Warrior Basin. Also, for all basins, low capital costs would
also be associated with commercial off-site disposal. Medium costs imply that stream discharge (with
treatment), or land application (with treatment) would be required (practiced in the Warrior basin). High costs
imply that a disposal well or evaporation (Western basins only) would be required.
Sources used to develop ranges: 1) ICF Resources (1990b); 2) Evans et al. (1991); 3) Ortiz (1992).
Capital Costs for Pipeline Injection
Equipment for pipeline utilization includes gathering lines from individual wells to a
central compression point, compressor(s), equipment for processing and treatment (e.g.
chemical dehydrator), equipment for enrichment (gob wells only), and a main gathering line
from a central compression point at the mine to a commercial pipeline. Costs for the main
gathering lines are calculated on a dollar per mile basis and are shown in Exhibit 3A-18. All
other pipeline utilization costs are shown in Exhibit 3A-17.
Exhibit 3A-17
Capital Costs for Pipeline Injection: All Equipment Needed Between the Wellhead
and a Central Compressor
Equipment
Gathering lines between
wellhead and Central
Compressor
Compressor(s)
ProcessingnVeatment
Low
$10,000 per well
$180 per mcf/day
$10 per mcf/day
Medium
$45,000 per well
$190 per mcf/day
$20 per mcf/day
High
$100,000 per well
$200 per mcf/day
$30 per mcf/day
Note: Capital costs for compressor and processing/treatment are based on maximum gas production per day.
Equipment costs for enrichment of gob gas are included in the total $/mcf operating costs.
Sources used to develop ranges: 1) USEPA (1990); 2) ICF Resources (1990a); 3) ICF Resources (1990b), 4)
Sykes (1989); 5) True (1990).
Capital costs for gathering lines between a central compression point at a mine and a
main commercial pipeline are calculated by first estimating the distance from a mine profile to
a commercial pipeline, and then multiplying that distance by a dollar per mile cost. A range
of different distances was evaluated for each mine profile - from 5 to 30 miles. This range of
3A-14
-------
distances was based on the estimated distance to a pipeline for actual large and gassy
mines.4
Exhibit 3A-18
Capital Costs for Pipeline Injection: Gathering Lines to Main Commercial Pipeline
Basin
Central Appalachian
Northern Appalachian
Illinois
Warrior
Western
Dollars per Mile
Low
$650,000
$450,000
$200,000
$500,000
$650,000
Medium
$750,000
$550,000
$300,000
$600,000
$800,000
High
$850,000
$650,000
$400,000
$700,000
$950,000
Sources used to develop ranges: 1) ICF Resources (1990a); 2) True (1990)
Note on Sources: Distance to pipeline is one of the defining characteristics of the mine profiles evaluated in
this analysis. The "Pipeline Economics" article was used to develop overall cost ranges for pipeline
construction. Information on terrain in the ICF Resources report was used to develop the ranges for costs
within each basin since costs were assumed to vary primarily according to terrain.
Per mile costs for laying gathering lines were assumed to vary by basin primarily
according to terrain. Terrain varies significantly between and within basins. Descriptions of
terrain at actual coal mines were used to develop overall estimates of the costs for laying
gathering lines within each basin.5
Capital Costs for Power Generation
Equipment required for on-site power generation includes a generator and the
gathering lines between the wellhead and the generator. For off-site sale of power to a utility,
transmission line upgrades or an interconnection facility may be needed to feed power
generated at the mine into the main transmission line. Capital costs for power generation are
shown in Exhibit 3A-19.
Utilization of ventilation air as combustion air in a generator is also an option
examined in this analysis. The additional capital costs required for this option are the ducts
and fans needed to transport the air from a ventilation shaft to the generator.
The estimated distance to a pipeline is shown for large and gassy mines in the Exhibits contained in the
report The Potential Recovery of Methane from Coal Mining for Use in the U.S. Natural Gas Systems (ICF
Resources, 1990a).
5 A description of terrain at actual coal mines is contained in the exhibits of ICF Resources (1990a).
3A-15
-------
Exhibit 3A-19
Capital Costs for Power Generation
Equipment
Gathering lines between
wellhead and generator
Gas Turbine1
Off-site Transmission2
Ducts for Utilization of
Ventilation Air
Low
$10,000 per well
$800 per kw installed
$100,000 per project
$400,000 per project
Medium
$25,000 per well
$1 ,000 per kw installed
$300,000 per project
$500,000 per project
High
$40,000 per well
$1 ,200 per kw installed
$500,000 per project
$600,000 per project
1 Both 1C engines and gas turbines were examined in the analysis. However, for sizes above 4 MW, it was
assumed that a mine would prefer a gas turbine. Since projects less than 4 MW were not shown to be
profitable, 1C engine costs are not included here.
2 Off-site transmission costs are for costs of an interconnection facility and/or line up-grades. The low costs
assume that an interconnection facility would not be needed and that line up-grades would be minimal.
Sources used to develop ranges: 1) Sturgill (1991); 2) ICF Resources (1990c); 3) Wolfe and Maxwell (1990); 4)
Personal Communication with Allison Gas Turbines; 5) Energy Systems Associates (1991).
Operating Costs
Annual operating costs are estimated over the projected lifetime of the project. These
operating costs can vary significantly depending on the number of wells in operation and on
annual gas, water, and electricity production. Recovery wells are assumed to have a fixed
annual operating cost. Annual operating costs for utilization equipment (e.g. compressors,
generators, water disposal system) are based on annual production estimates.
Operating Costs for Recovery Wells
Per well operating costs are those costs associated with recovering - but not utilizing
- methane. Recovery costs include all manpower, materials, and power costs for the
operation, maintenance, and administration of producing wells. This annual operating cost is
assumed to remain fixed over the lifetime of the well regardless of the amount of methane
recovered. Operating costs for vertical and gob wells are shown in Exhibit 3A-20.
Exhibit 3A-20
Operating Costs for Recovery Wells
Vertical and Gob Wells
Low
$4,000 per well
Medium
$6,000 per well
High
$8,000 per well
Sources used to develop ranges: 1) USEPA (1990); 2) ICF Resources (1990b); 3) Baker et al. (1988).
3A-16
-------
Operating Costs for Water Disposal from Vertical Wells
As with capital costs for water disposal, operating costs can vary significantly
depending on the disposal method used. Generally, the stream or river discharge disposal
method has the lowest operating costs. Evaporation pits, surface application and stream or
river discharge with treatment, deep well injection, and commercial off-site disposal have
higher operating costs. The section on capital costs for water disposal contains a more
detailed description of the methods. Operating costs for water disposal are shown in Exhibit
3A-21.
Exhibit 3A-21
Operating Costs for Water Disposal From Vertical Wells
$ per Barrel
Warrior basin
Other basins
Low
$.02
$.40
Medium
$.40
$.40
High
$1.00
$1.00
Notes: For the Warrior basin, low costs imply that stream discharge is available and that little treatment would
be needed. For all basins, medium costs imply that stream discharge (with treatment), land application (with
treatment), or lower cost deep well injection would be available. High costs imply that a higher cost disposal
well, evaporation (Western basins only) or off-site disposal would be required.
Sources used to develop ranges: 1) ICF Resources (1990b); 2) Evans et al. (1991); 3) Ortiz (1992); 4) Personal
communication between Alabama Oil and Gas Board and Raven Ridge Resources.
Operating Costs for Pipeline Injection
Operating costs for pipeline injection include costs for compression, processing and
treatment, and enrichment (for gob wells only). All operating costs are based on annual gas
production. These costs are shown in Exhibit 3A-22.
Exhibit 3A-22
Operating Costs for Pipeline Injection: All Equipment Needed Between the Wellhead
and a Central Compressor
Equipment
Compressor(s)
Processing/Treatment
Enrichment
Low
$.06 per mcf
$.02 per mcf
$1.00 per mcf
Medium
$.07 per mcf
$.03 per mcf
$1 .50 per mcf
High
$.08 per mcf
$.04 per mcf
$2.00 per mcf
Sources used to develop ranges: 1) ICF Resources (1990); 2) True (1990); 3) USEPA (1992b).
Note: Costs for enrichment are still highly uncertain since this technology is not yet being used on a
commercial basis.
3A-17
-------
Operating Costs for Power Generation
Operating costs for power generation are calculated on a cents per kWh produced
basis. These costs are shown in Exhibit 3A-23.
Exhibit 3A-23
Operating Costs for Power Generation
Equipment
Gas Turbine
Ducts for Utilization of
Ventilation Air
Low
$.01 per kWh
Medium
$.015 per kWh
High
$.02 per kWh
Operating Costs are calculated in terms of energy requirements (power produced
by on-site turbine that is used to transport ventilation air - see Physical
Calculations Section of Appendix)
Sources used to develop ranges: 1) ICF Resources (1990c); 2) Wolfe and Maxwell (1990); 3) Energy Systems
Associates (1991).
Revenue Generated
A mine profile can generate revenue either from selling methane to a pipeline or from
selling electricity to a utility.
Revenue from Pipeline Sales
Revenue for pipeline injection is calculated by multiplying the annual amount of gas
produced each year by the projected wellhead gas price. Projections for the wellhead gas
price in 2000 and 2010 are shown in Exhibit 3A-24.
Exhibit 3A-24
Wellhead Gas Price (1990 $/mcf)
Year
2000
2010
Low
$1.50
$2.25
Medium
$2.25
$3.00
High
$3.00
$3.75
Note: Though wellhead gas prices vary by region, national averages were used for all basins.
Source: Gas Research Institute (1992); American Gas Association (1992); DOE/EIA (1992).
Revenue from Electricity Sales
For power generation, it is assumed that a mine would first use all electricity generated
to meet on-site energy needs. Any excess electricity could then be considered for sale to a
utility. Projections for avoided costs are used to estimate the annual revenue that could be
generated by selling power to a utility. Projections for avoided costs in 2000 and 2010 are
shown in Exhibit 3A-25.
3A-18
-------
Exhibit 3A-25
Avoided Cost (1990 dollars)
Year
2000
2010
Low
$.03 per kWh
$.03 per kWh
Medium
$.04 per kWh
$.04 per kWh
High
$.05 per kWh
$.05 per kWh
Note: Though avoided costs vary by region, national averages were used for all basins.
Sources used to develop ranges included: USEPA (1991b), the Avoided Cost Quarterly, and Cogeneration
and IPP Power Sales.
Energy Operating Savings
Energy operating savings can be realized by generating power to meet on-site
electricity needs and/or by reducing ventilation air requirements (and, thus, the electricity
needed to run the ventilation system).6 For both cases, the energy savings is calculated in
terms of cents per kWh avoided, which is estimated from forecasts for industrial electricity
prices. Because the analysis only takes into account the incremental financial changes of
adopting a methane recovery and utilization strategy, only the difference in required electricity
purchases is calculated. The values used to estimate a mine's electricity purchase price are
shown in Exhibit 3A-26.
Exhibit 3A-26
Projected Electricity Price Paid by Mine
Year
2000
2010
Low
$.04 per kWh
$.04 per kWh
Medium
$.05 per kWh
$.05 per kWh
High
$.06 per kWh
$.06 per kWh
Sources used to develop ranges: 1) DOE/EIA Projections for Industrial Electricity Prices; 2) DRI Forecasts for
Electricity Prices.
Other Financial Factors
In order to perform a net present value analysis of the recovery and utilization
investments, values were assumed for several key financial factors. These factors include:
• Financing of Capital Investments. All equity financing was assumed for capital
investments.
As noted previously, though examined in this analysis, the energy savings realized from reducing ventilation
air requirements are not incorporated in the financial scenarios presented in the main body of the chapter.
3A-19
-------
Depreciation Method. Straight-line depreciation is used for all capital items. The
depreciation period is assumed to be the same as the loan period ~ for recovery
wells, the depreciation period is equal to the lifetime of the well, for other capital
items, the depreciation period is assumed to be 10 years.
Taxes. A mine profile's marginal tax rate is assumed to be 40 percent. Calculating
the annual tax liability consists of two parts. First, the assumed tax rate is applied
to the annual income. Second, "avoided taxes" are calculated by computing the
depreciation tax shield.
Inflation Rate. An annual inflation rate of 4 percent is assumed.
Discount Rate. A nominal discount rate of 10 percent is assumed. With a 4
percent inflation rate, this corresponds to a real discount rate of 6 percent.
3A-20
-------
CHAPTER 4
OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM LANDFILLS
Landfill Methane Emissions Reductions
Share of U.S.
Emissions Reductions
. .-1 3 . .-4
.9..5
Pr-or i tab I e
Reductions
Rema I n I ng
Em IssIons
Low HIgh
-I39O
Low HIgn
2OOO
Low HI
2O-IO
Landfill Methane Emissions (Tg)
Year Baseline Emissions8 Emissions with Technically Emissions with Profitable
Year Baseline Emissions Feas|ble Reductjonsb Reductions
1990
2000
2010
8.1-11.8
8.8-12.7
9.5-13.4
1.5-2.1
1.6-2.2
5.2-6.6°
(2.6-5.6)d (8.8-10.6)6
4.2-6.0c
(1.8-4.8)d (9.5-11.3)*
a Source: USEPA (1993a). Baseline emissions reflect methane recovery of 1.5 Tg per year throughout the
period examined.
b Technically feasible emissions reduction estimated at 85 percent of emissions in the absence of any
recovery projects.
c Range of estimates based on an electricity sales price of $0.05 per kWh.
d Range of estimates based on an electricity sales price of $0.06 per kWh.
e Range of estimates based on an electricity sales price of $0.04 per kWh.
CHAPTER SUMMARY
Landfills are the largest anthropogenic source of
methane emissions in the United States. In 1990
landfills emitted an estimated 8.1 to 11.8 Tg to
the atmosphere (USEPA 1993a). These emis-
sions represent a substantial amount of energy
and are equivalent to about 5,000 to 7,500 MW of
electricity generating capacity. In the absence of
efforts to reduce emissions, landfill methane
emissions are expected to grow to between 9.5
and 13.4 Tg per year by 2010 (USEPA 1993a).
The current and future baseline emissions esti-
mates include the recovery of 1.5 Tg of methane
4-1
-------
Chapter Summary
from landfills per year. In the absence of
thisrecovery, emissions would be about 1.35 Tg
peryear higher.1
It is technically feasible to recover up to 85 per-
cent of the methane produced by landfills by
drilling wells into the landfills and withdrawing the
landfill gas. The estimate of 85 percent is higher
than the average landfill gas collection efficiency
estimated for existing recovery projects (75 per-
cent) but is achievable with current technology.
The extent of reduction that is technically feasible
varies among landfills and depends on site-
specific design and waste factors. Technically
feasible emission reductions may range from 50
percent for old landfills to nearly 100 percent for
new landfills. Newer landfills are expected to
have more complete recovery systems because
they will be built to comply with the revised
Subtitle D requirements for municipal solid waste
landfills.2 The 85 percent estimate represents an
average across many old and new landfills.
At an electricity price of $
-------
Chapter Summary
other utilization options are more profitable, this
analysis may understate profitable reductions.
The profitability of landfill gas recovery projects is
very sensitive to the price at which the project
can sell the electricity it generates. This price de-
pends on the terms negotiated with individual
utilities, which may be influenced by rules estab-
lished by state public utility commissions. Often
the rates involve payments for installed capacity
and a schedule of rates that depends on the time
of day, the season, or both. Electricity prices
currently received by landfills fall in a range be-
tween $0.02 and $0.10 per kiloWatt hour (kWh)
with an average near $0.06 per kiloWatt hour.
However, the electricity prices that newer landfill
projects receive are generally in the range of
$0.03/kWh to $0.04/kWh (GAA 1991).
Federal tax credits for non-traditional energy
development increase the value of the gas for
many landfills. With the recent extension of the
Section 29 tax credit for non-conventional energy
production and the increased attention given to
environmental externalities in utility planning
decisions, an average rate of $0.05/kWh in 2000
is reasonable. At an electricity price of
$0.05/kWh, this report estimates that about 750
landfills can profitably recover 6.7 Tg of methane
in 2000 and produce about 4,000 MW of electric
generating capacity. For the broader range of
electricity prices, the analysis shows the following
profitable reductions can be achieved in 2000:
$0.04 per kWh: About 60 landfills could profitably
recover 1.5 Tg of methane and produce about
800 MW of electric generating capacity.
$0,06 per kWh: About 1,400 landfills could profit-
ably recover 8.2 Tg of methane and produce
about 5,000 MW of electric generating capacity.
Because there is uncertainty in the costs of col-
lecting landfill gas and producing electricity, the
estimates of the emissions reductions are also
uncertain. Uncertainty ranges for the emission
reductions were estimated by identifying the most
and least favorable conditions for profitable gas
recovery that are likely to occur. The most and
least favorable conditions were identified statisti-
cally based on the uncertainty ranges for each of
the key factors affecting the landfill gas recovery
profitability. Exhibit 4-1 summarizes the emis-
sions reduction estimates and shows that the
impact of the uncertainty on the estimates is
small relative to the sensitivity of the estimates to
electricity prices.
Relative to the 1.5 Tg of landfill methane recov-
ered in 1990, the analysis indicates that there is
considerable potential for additional recovery at
electricity prices above $0.04 per kWh. The
outlook for recovery and utilization projects will
likely improve in the future for several reasons.
First, to reduce air pollution from landfills the U.S.
EPA will soon require that large landfills collect
and combust (flare) landfill gas.3 Because large
landfills account for most emissions, the EPA
requirement will significantly reduce methane
emissions. Based on the analysis presented in
this chapter, once the gas is collected (as will be
required under the rule), in many cases it may be
economically justified to produce and sell electric-
ity rather than to simply flare the gas. Conse-
quently, the cost of the proposed rule will be
decreased by the income earned by generating
and selling electricity.
Second, as the average landfill size increases in
the future, landfill gas recovery and utilization
should become more profitable. As described in
the report, there are expected to be fewer and
generally larger landfills operated in the U.S.
Because gas recovery and utilization projects are
most profitable at large and gassy landfills, gas
recovery and utilization projects should become
more profitable.
Implications of Including
Environmental Benefits
The analysis of profitable recovery projects does
not include the value of the environmental bene-
fits of recovering methane from landfills. These
3 The proposed rule is the Standards of Performance for New Stationary Sources and Guidelines for Control of Existing
Sources: Municipal Solid Waste Landfills (USEPA 1991 a). The purpose of the proposed rule is reduce air pollution
and other hazards associated with landfill air emissions, including: volatile organic compounds; toxic and potentially
hazardous compounds; explosion potential; and odor nuisance (USEPA 1991c). While the proposed rule is not
specifically designed to reduce methane emissions, it will have the effect of significantly reducing methane emissions
from landfills.
4-3
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Chapter Summary
environmental benefits include not only the reduc-
tion in methane emissions, but also reductions in
air pollution from landfills (including non-methane
organic compound (NMOC) emissions), better
landfill gas migration control, and a reduction in
carbon dioxide (CO2) and other emissions from
displacing fossil fuel. Adding the value of these
benefits to the analysis improves the profitability
of landfill gas recovery significantly.
Tfte most effective
strategy far re-
to
and combust or otherwise
For example, the cost of reducing carbon dioxide
(CO2) build up in the atmosphere has been esti-
mated in the range of $5 to $20 per ton of carbon
contained in CO2. With this range, the environ-
mental benefit of preventing methane emissions
from landfills translates into a value of about
$0.0069 to $0.0276 per kWh for avoiding methane
emissions from landfills.4 In addition, assuming
that producing electricity at landfills displaces
fossil fuel produced CO2 at the rate of 1.5 Ib CO2
per kWh,5 then an additional benefit of $0.009 to
$0.0037 per kWh can be realized.6 Combining
these two benefits, the total value of recovering
methane from landfills ranges between
$0.0078/kWh to $0.0313/kWh. This value may be
as high as $0.1566 if the benefit of reducing CO2
emissions is as high as $100 per ton of carbon
contained in CO2.
These values take into account the global warm-
ing impact of methane but do not include the
benefits associated with improving local air
quality and improving landfill gas migration
control. Nevertheless, using these values as a
range, the addition of the value of the environ
mental benefits would indicate that landfill gas
recovery should be promoted at virtually all large
landfills.
Methane Reduction Strategies
The most effective strategy for reducing methane
emissions from landfills is to recover and utilize
the landfill gas. This approach is the only meth-
od available for reducing emissions from existing
landfills and from landfills that will contain degrad-
able waste in the future. Modifying waste man-
agement practices or promoting measures to
reduce the quantity of waste produced will also
reduce methane emissions from landfills. By
diverting waste away from landfill disposal and
toward other waste disposal methods such as
recycling, less waste will be in landfills to produce
methane in the future. Simultaneously, the
quantity of waste produced could be reduced
through waste minimization. The implications of
these efforts are incorporated into the baseline
landfill methane emissions estimates in this
analysis (see USEPA 1993a). Therefore, this
report focuses on landfill gas recovery as the
most effective strategy for significantly reducing
methane emissions.
Recovering Landfill Gas
Most gas collection systems have a similar de-
sign. After the landfill is capped, vertical wells
consisting of perforated pipe casing are drilled
into the landfill. These wells are back filled with
permeable material such as gravel around the
casing and are sealed at the surface with an
impermeable material to prevent the inflow of air.
The wells are connected by horizontal piping to
a central point where a motor/blower provides a
vacuum to remove the gas from the landfill. In a
well designed and constructed system, methane
recovery rates in excess of 85 percent can be
achieved (Maxwell 1990). Recovery systems
usually are operated as part of an overall landfill
gas control system. Other portions of the system
may include perimeter monitoring and methods
4 The calculation is based on the global warming potential (GWP) of methane, the efficiency of converting landfill gas
into electricity, and the value of reducing carbon dioxide emissions.
5 The figure of 1.5 Ib CO^kWh is an average national emission factor based on total CO2 emissions from generating
electricity divided by the total amount of electricity produced.
e
The calculation is based on the amount of CO2 emissions that landfill generated electricity displaces and the value
of reducing carbon dioxide emissions.
4-5
-------
Chapter Summary
to prevent off-site migration of landfill gas. Once
collected, the gas can be used to generate elec-
tricity; to sell as a medium-BTU fuel to fire indus-
trial boilers, chillers, or similar equipment; or to
produce liquid fuels and industrial chemicals. In
cases were it may not be economic to use the
gas, the best alternative is to flare it. These
options are described in the following two sec-
tions. By far the most commonly used options
are to generate electricity, to sell the gas as
medium-BTU fuel, or to flare the gas.
Electric Power Generation
Electric power generation is the
ttfost common gas uUlzstfon
method for landfill gas recovery
Electric power generation is the most common
gas utilization method for landfill gas recovery
projects. According to the Methane Recovery
From Landfill Yearbook, 1990-91, compiled by
Government Advisory Associates (GAA), Inc., over
two-thirds of the gas-to-energy projects generate
or plan to generate electricity. Some of the
options for producing electricity are as follows.
Internal Combustion (1C), Reciprocating Engines
are similar to automobile engines and can be
used to turn a generator that produces electricity.
The advantages of 1C engines include: cost
effectiveness, availability of a wide :ange of power
capacities, and power generating efficiency.
Newer engines use low pressure fuel injection
which significantly reduces parasitic drag and
down time due to less complicated compression
and pretreatment systems (Pacey 1993). The
primary disadvantages of 1C engines are their
susceptibility to corrosion from contaminants in
the landfill gas and their relatively high NOX
emissions. However, corrosion problems have
been addressed by installing corrosion resistant
parts and by frequently checking and changing
the engine oil. NOX emissions have been re-
duced by using newer "lean-burn" engines.
Turbines. Gas turbines are similar to jet engines
and can turn a generator that produces electrici-
ty. The advantages of turbines are low operating
and maintenance costs and lower NOX emissions.
The disadvantage of turbines is that they require
large gas flows to make them economic and so
are suitable only for the largest landfills.
Other Utilization Options
Sale as a Medium-BTU Fuel. If the landfill is
located near suitable industrial facilities the gas
can be transported via pipeline and sold as a
"medium-BTU" fuel.7 An ideal medium-BTU gas
customer would be located near the landfill and
would have a nearly continuous demand for
gaseous fuel. Landfill gas customers may use
the gas to fuel a cogeneration system, to fire
boilers or chillers, or to provide space heating.
Fuel Cells. Fuel cells are not currently practical
but hold promise for the future. A fuel cell con-
verts the chemical energy of the methane directly
into usable energy as electricity and heat. The
advantages of fuel cells include: high energy effi-
ciency; low by-product emissions; limited noise
production; minimal labor requirements; and
modularity. The disadvantage of fuels cells is
their high cost. However, the cost of fuel cells is
expected to decrease enough to be competitive
with other methods of generating electricity. If
fuel cells can be successfully demonstrated using
landfill gas, then fuel cells may hold great prom-
ise as an option for utilizing landfill gas. The
Electric Power Research Institute (EPRI) and the
USEPA Air and Energy Research Laboratory
(AEERL) are undertaking projects to demonstrate
fuel cells at existing landfills (Resource Manage-
ment International, Inc. 1992; Thorneloe 1992a).
Production of Liquid Fuels and Industrial Chemi-
cals. Recent developments in alternative fuels
have led to the improvement of a process that
converts landfill gas into diesel, naphtha, and
high grade industrial waxes. The advantage of
producing these products is that the economic
benefits do not depend on the local electric
power system or on proximity to a suitable indus-
trial customer. The disadvantage of producing
these products is that their high cost prevents
7 The energy content of a medium-BTU fuel is 400-600 BTU/ft3. The energy content of a high-BTU fuel, such as natural
gas, is 1,000 BTU/ft3.
4-6
-------
Chapter Summary
them from being competitive with conventional
liquid fuels.
Flaring. Flaring is the simplest way to eliminate
landfill gas. The advantage of flaring is that the
capital cost is small compared to energy recovery
systems. The disadvantage is that flaring produc-
es no income for the landfill.
Current Recovery and Utilization Projects
In 1991 there were just over 100 landfill gas
recovery and utilization projects operating in the
U.S. Seventy-one of these projects generated
electricity and twenty-five sold the gas as a medi-
um-BTU fuel. Three landfills both produce elec-
tricity and sell the gas as a medium-BTU fuel. Of
the seventy-four landfills that produced electricity,
most have an electrical generating capacity be-
tween 0.5 and 4 megaWatts. Exhibit 4-2 shows
the distribution of the seventy-four electricity
generating projects by their generating capacity.
Barriers to Methane Recovery
Under favorable pricing conditions profitable
opportunities exist for methane recovery from
landfills. However, while there are many landfills
at which methane recovery is apparently viable,
methane recovery and utilization projects are
often not undertaken because of various barriers.
Many of these barriers are common to most
alternative energy sources while other are specific
to landfill projects.
Barriers common to other alternative energy
sources such as cogeneration, biomass, solar,
and wind are discussed in Chapter 7 of this
report. In particular these barriers involve elec-
tricity pricing and sales agreements with electric
power utilities. Other barriers are specific to
landfill gas recovery projects and must be ad-
dressed before significant reductions in landfill
methane emissions can be realized. These
include the following.
Perception of High Risk. Most "alternative" energy
production technologies tend to be viewed as
unproven or risky. As a result, such projects
must earn high returns in order to attract financ-
ing. The dissemination of information on the 100
existing projects could help reduce the perceived
technological risk of these ventures.
Lack of Information. Over 86 percent of landfills
are owned by municipalities or other local govern-
ments (USEPA1988) whose primary responsibility
is to collect and dispose of municipal solid waste.
These landfill owners and operators may be
unaware of opportunities for profitably recovering
and utilizing landfill gas.
Siting and Permitting. Landfill gas recovery
projects must comply with local, state, and feder-
al regulatory and permitting requirements. The
majority of these requirements address environ-
mental, safety, and zoning concerns. The costs
of complying with these rules can be substantial,
and are not considered in the financial analysis
presented above. Reducing or overcoming this
barrier is necessary to fully realize the profitable
methane reductions estimated in this chapter.
Key requirements that must be addressed include
air and water emissions. In some areas, the
siting of new combustion sources is difficult due
to requirements to reduce emissions of NOX or
other combustion products. This is particularly
true for designated ozone "non-attainment" areas
where the NOX emission limits tor new sources
are relatively stringent. Witnin these non-
attainment areas, landfill energy recovery pro-
jects, and possibly flares, may have difficulty
meeting these stringent standards without incur-
ring additional cost. This additional cost may
cause apparently profitable projects to become
less economically attractive. The availability of
low-emission engine technology may help to
overcome this barrier, although at a cost. When
they become more widely available, fuel cells may
also help to overcome this barrier.
Water emission issues center around leachate
control. Landfills are required to monitor ground-
water quality and prevent off-site migration of
contaminants in the groundwater. In the process
of collecting landfill gas, water condenses in the
collection system. This condensate can be
hazardous and must be handled and disposed of
properly, within the context of the landfill's con-
densate and/or leachate control program.
Liability. Liability concerns have increased the
difficulty of obtaining financing for landfill gas
recovery projects because lenders are concerned
about the costs of cleaning up landfills under
CERLCA (Comprehensive Environmental
4-7
-------
Chapter Summary
Exhibit 4-2
Electricity Generating Capacity of Existing Landfill Projects
EIectr i c Generali ng Capac i ty
I - -KI 10 - 20
Based on GAA (1991).
Response, Compensation, and Liability Act).
Under CERCLA, entities that owned or operated
a landfill or placed waste at the landfill (as a
waste generator or waste hauler) may become a
potentially responsible party for the landfill.
Potentially responsible parties are strictly and
severally liable for the costs of investigating and
remediating hazardous waste sites. This means
that a single responsible party can be held
responsible for the entire cost of cleaning up a
site. This potential liability can arise at a munic-
ipal waste landfill if the landfill accepted hazard-
ous waste in the past or if the landfill exhibits
hazardous characteristics.
Given the potential liability involved, investors and
lenders are hesitant to provide financing for a
project that involves a landfill. If the landfill turns
out to have a hazardous waste problem, the
landfill gas recovery project owner and/or opera-
tor could become a potentially responsible party.
As a result of the cost of cleaning up the landfill,
the landfill gas recovery project may no longer be
profitable and the loan may not be repaid. In this
instance, the lending institution would not want to
seize the assets of the project because the
assets may include liability for cleaning up the
landfill. CERCLA liability issues primarily limit
landfill projects that require external financing.
CERCLA liability issues for landfill projects are of
less importance for municipally owned projects or
for projects that do not require external financing.
Technology Development. Promising technolo-
gies such as fuel cells could offer additional
options for using landfill gas. However, the high
cost of research has hindered the development of
this and other promising technologies.
Options are available for overcoming these barri-
ers. In particular, the perception of high risk for
can be overcome by disseminating information on
the reliability of the existing landfill gas recovery
projects. Both landfill gas extraction and engine
technology have improved to increase the reliabil-
ity of these systems. Some of the permitting and
siting concerns can be addressed by providing
information on the standard techniques for miti-
gating water and air releases.
To address the liability issue, a method is needed
for structuring the financing of the projects in a
way that insulates the lender from potential
CERCLA liability. Insurance or other related
options should be investigated. Alternatively,
legislative relief may be needed. Finally, funding
research and development projects will enable
quicker implementation of new utilization technol-
ogies.
4-8
-------
4.1 BACKGROUND
Because landfill gas is about 40 to 60 percent methane, it can be used as a fuel.
During the period of rapidly increasing energy prices in the 1970s, interest developed in
recovering and using landfill gas as a fuel. This interest led to the installation of recovery and
utilization systems at a number of landfills in the late 1970s and 1980s. Currently there are
about 100 landfill gas recovery and utilization projects in operation in the U.S., and several
additional projects are under development (GAA 1991). These projects have established a
decade-long track record, showing that it is possible to design, construct, and operate a
landfill gas recovery and utilization project at a profit.
4.1.1 Methane Emissions from Landfills
Sanitary landfills have been routinely used since the early 1970s. Although landfills
eliminated many of the problems associated with earlier waste disposal methods such as
dumps, some problems persist. A properly designed and operated landfill can produce large
quantities of methane gas as the organic matter in the refuse decomposes. Regardless of
concerns over global warming, the methane poses a potential hazard to the landfill and
neighboring community. Other problems with landfills may include ground water
contamination and air pollution.
Methane Production in Landfills
Methane is produced in landfills
because the organic matter in the refuse is
decomposed by bacteria under anaerobic
conditions (an environment free of molecular
oxygen). Methane production typically
begins one or two years after waste
placement and may last for decades. The
decomposition process occurs in five stages
that can occur simultaneously within the
landfill: aerobic, hydrolytic, acid forming,
methanogenic and stabilization.
The first three stages primarily occur over one or two years. Aerobic bacteria
consume the available oxygen and break down the complex organic matter in the waste into
simple organic acids. Anaerobic bacteria8 consume the simple organic acids and produce
methane, carbon dioxide, water, heat, and stabilized organic material.9 The methanogenic,
or methane forming, stage can last for 10 to 60 years or longer.
Site-Specific Factors Affecting Methane Production
Methane production may vary significantly from landfill to landfill and from area to area
within an individual landfill. This variability is due to the importance of site-specific factors
such as waste quantity and composition, moisture, temperature, and pH.
Q
Anaerobic bacteria can only survive in an oxygen-free environment; aerobic bacteria can only survive in an
oxygen environment; facultative bacteria can survive in either an oxygen or oxygen-free environment.
9 Stabilized organic material is material that is not broken-down or decomposed further.
4-9
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Waste quantity and composition affect methane production for several reasons. First,
because the refuse is the substrate for the bacteria that decompose the refuse, larger
quantities of organic matter increase the methane producing capacity of a landfill. Second,
the greater the energy content and degradability of the waste, the greater the methane
producing capacity. Third, nutrient availability affects bacterial growth and deficiency in
nutrients such as nitrogen, phosphorus, sulfur, potassium, sodium, or calcium inhibits
bacterial growth and methane formation. Finally, the density and consistency of the waste
affect the activity of bacteria. Smaller particle sizes increase the surface area on which
reactions may occur, promoting greater methane production.
Moisture is essential for anaerobic decomposition (Loehr 1984) since water is
necessary for bacterial cell growth, for metabolism, and to transport nutrients and bacteria to
other areas within the landfill. Temperature affects the growth rate of the bacteria responsible
for methane formation. Methane production in the landfill increases with rising temperature.
Methane formation occurs within a pH range of 6.5 to 8.0; beyond this range production
ceases. Methanogens are most productive when the pH is between 6.8 and 7.2. The pH of
most landfills is in this range.
Estimated Landfill Methane Emissions
Because about 70 percent of the waste placed in landfills is organic material that is
contained in yard waste, household garbage, food waste, and paper, the potential for
methane production is great.10 As shown in Exhibit 4-3, U.S. landfill methane emissions in
1990 are estimated to range from about 8.1 to 11.8 Tg/yr, or about 37 percent of total U.S.
methane emissions. Although an estimated 6,000 landfills emit methane in the U.S., about
1,300 account for nearly all the methane emitted. Of these, about 900 landfills account for 85
percent of the waste in landfills and 75 percent of the methane emitted. The nineteen largest
landfills account for about 25 percent of the waste in landfills and 20 percent of the total
methane generated.
The amount of methane produced by U.S. landfills is expected to increase over the
next two decades. Although the amount of waste landfilled annually is not expected to
increase, the amount of methane-producing waste accumulated in landfills will increase.
However, an EPA landfill rule has been proposed that may significantly reduce emissions,
depending on which standards are adopted.11 Without considering the possible impact of
the proposed landfill rule, emissions in the years 2000 and 2010 are estimated to be about 9
to 13 Tg/yr (USEPA 1993a).
Trends in Waste Management Practices
Estimates of future methane emissions from landfills take into account a number of
changes in waste management practices in the U.S. In the last decade, increased public
awareness of the hazards of waste disposal has made it more difficult to construct and
operate landfills. In addition, both the Clean Air Act (CAA) Amendments and the
reauthorization of the Resource
10 The remaining 30% may not be completely inorganic. EPA's Office of Research and Development is
conducting research on the relative gas potential of various biodegradable waste streams.
11 The proposed rule is the Standards of Performance for New Stationary Sources and Guidelines for Control
of Existing Sources: Municipal Solid Waste Landfills (USEPA 1991 a).
4-10
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Exhibit 4-3
National Emission Estimates for 1990a
Landfill Size Distribution by Waste in Place
Size
Class
1 (Closed)
2
3
4
5
6
7
Total0
a Emission
b Totals do
Range
Low (Mg)
0
0
500,000
1,000,000
5,000,000
10,000,000
20,000,000
estimates from
High (Mg)
500,000
500,000
1 ,000,000
5,000,000
10,000,000
20,000,000
200,000,000
USEPA (1993a)
Number
Landfills
3,000
4,744
425
712
106
27
19
6,034
; landfill
Waste in
Plarp
(106 Mg)
negligible
494
312
1,581
709
411
1,194
4,700
Percent of Total
Waste
<0.5%
10.5%
6.6%
33.6%
15.1%
8.8%
25.4%
Methane Generation
Minus Recovery
Plus Industrial
Minus Oxidation
Net Emissions for 1990
National Emissions
(Tg/Yr)
Low
1.01
0.63
3.59
1.35
0.69
1.78
9.80
1.50
0.69
0.90
6.09
High
1.66
1.05
6.15
1.85
0.98
2.73
13.60
1.50
0.95
1.31
11.75
size distribution information based on USEPA (1987).
not include size class 1 .
Conservation and Recovery Act (RCRA) are expected to increase the cost of landfill waste
disposal. Some major implications of these expected changes are:
Increased Recycling. Recycling will become an increasingly cost-effective
method of reducing the total waste stream. In 1991, approximately 14 percent
of U.S. waste was recycled. State percentages ranged from 3 percent in
Mississippi to 34 percent in Washington. Exhibit 4-4 provides information on
each state's recycling, composting and deposit/return laws. Most states now
have recycling goals of 20 - 50 percent, often as part of mandatory programs
(Biocycle 1992b).
• Increased Use of Alternative Disposal Methods. Alternative methods of waste
disposal such as composting and incineration will continue to grow, reducing
the portion of waste that is managed in landfills. The USEPA Office of Solid
Waste (USEPA 1992a) projects that the percentage of municipal solid waste
composted will increase from 2 percent in 1990 to 5.3 percent in 1995 and
7 percent in 2000. This trend is largely due to bans on landfilling of yard
wastes in many states. The percentage of municipal solid waste combusted is
projected to rise from 16 percent in 1990 to almost 21 percent in 2000.
The Construction of Fewer Landfills. The difficulty of constructing and
operating new landfills along with increasing regulatory compliance costs may
lead to fewer and generally larger landfills than exist today.
4-11
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• Increased Closures of Landfills. Due to the increasing regulatory compliance
costs, many less efficient landfills may be forced to close, further decreasing
the number of landfills.
These changes will affect methane production by landfills. Future landfill methane
production will be driven by the following factors:
The quantity of waste generated and placed in landfills. While recycling,
composting, and combustion will remove more municipal solid waste from the
waste stream before it reaches landfills, the quantity of municipal solid waste
generated is still expected to increase.
• The composition of the waste. The organic content of landfill waste is
expected to increase despite the increased recovery rates discussed above.
This is due to the increase in paper, wood, and other organic components of
municipal solid wastes.
Because of the changing regulatory climate and expected growth of recycling,
projecting future waste quantities and composition is very difficult. After reviewing a range of
scenarios of future landfilling, USEPA (1993a) adopted a mid-range estimate of 190 million Mg
per year placed in landfills between 1990 and 2010. This assumption implies that increased
generation of solid waste offsets the gains in recycling, composting, and other methods.
Therefore, the quantity of waste landfilled remains constant each year through 2000 and
2010.
The organic composition of the waste is also expected to remain near current levels.
Because recycling and recovery affect both organic and non-organic materials, recycling will
not significantly affect the organic fraction of landfill waste. In 1990 the organic content of
municipal solid waste after recovery was about 69 percent. By 2000 this percentage is
expected to decrease only slightly, to about 66 percent (USEPA 1993a).
Despite the efforts underway to divert waste from landfills, changes in waste disposal
practices will not significantly reduce methane emissions over the next 20 years. Based on
the analyses in USEPA (1993a), although
Despite efforts underway to divert waste
from JandfiBs, changes in waste
reduce methane emissions over the
the rate of waste disposal in landfills is
expected to remain fairly constant over the
next 20 years, the amount of waste in
landfills that can produce methane is
expected to increase from about 4,700
million megagrams (106 Mg) in 1990 to
5,300 million Mg by 2000 and 5,700
million Mg in 2010. Consequently, even
after considering changes in waste disposal practices, methane emissions from landfills may
increase from current levels over the next 20 years.
4.1.2 Other Major Actions Affecting Future Methane Emissions
Unless the gas created by the landfill is trapped by a collection system, it will migrate
through the waste following the path of least resistance and may eventually diffuse through
the soil cover and into the atmosphere. If upward movement is obstructed, the gas will
migrate laterally along subsurface routes of least resistance until a vertical path is found
4-12
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Exhibit 4-4
State Source Reduction Efforts (1991)
State Pet. Recycled
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
D.C.
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Mass.
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hamp.
New Jersey
New Mexico
New York
N. Carolina
N. Dakota
Ohio
Oklahoma
Oregon
Penn.
Rhode Is.
S. Carolina
S. Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
W. Virginia
Wisconsin
Wyoming
Nat'l Avg
KEY B= mercury
VB= vehicle
8
6
5
5
17
16
15
8
7
21
5
4
8
12
8
10
5
10
10
17
10
29
25
31
8
10
6
10
10
5
30
5
14
17
10
3
10
21
10
15
5
10
2
10
10
20
10
34
10
17
3
14
Disposal Bans
VB, T
VB, T, Y
B
VB, T, Y, M
VB
VB
VB, T
VB, T, Y
VB, T, Y, M
T
VB, T
Y
T
VB, T, Y
VB, Y
B, VB, T, Y, M
VB
VB, T, Y, M
VB
VB, Y
VB
VB, T, Y, M
VB, M
VB, T, Y
VB, T, M
VB, Y
VB
VB, T, Y, M
VB, T
VB, T, Y
VB, T, M
VB
B, VB, T, M
VB
VB, M
VB, T, Y
VB, T, Y, M
This average is
Waste (USEPA
oxide or other batteries
batteries
Sources: Biocvcle 1992a and
1992b.
Deposit/Return Law Num. of Composting Programs
VB, C
VB
C, B
C
VB
VB
C
T
VB
C
C
C, VB
VB
VB
VB
T
VB
C, VB
VB
VB
C, VB
VB
VB
VB
VB
VB
C
VB
VB
VB
slightly lower than the figure reported by the
1993a).
C= beverage containers M= motor oil
Y=yard waste
9
0
0
5
21
3
79
2
1
20
1
1
6
106
10
30
30
6
2
13
5
180
200
331
11
37
2
15
1
65
270
2
170
43
10
20
5
20
169
11
0
3
0
8
2
9
36
12
4
213
2
Office of Solid
T=tires
4-13
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through which it can escape. Because methane is combustible in concentrations as low as 5
percent, migration of methane into enclosed structures presents a hazard. To date there
have been numerous reported cases where methane produced in a sanitary landfill has
migrated into adjacent property and created explosive conditions. Where explosions have
occurred, property damage has been substantial, and in some cases the explosions have
resulted in personal injury and death.
In response to the potential danger methane poses, the EPA currently regulates
methane gas emissions under 40 CFR Parts 257 and 258. These regulations require certain
performance standards designed to protect human health from the hazards of explosive
gases generated by landfills. In general, these regulations mandate the use of collection
systems or perimeter vent systems where there is significant landfill gas generation. In most
cases the landfill gas is vented to prevent explosive conditions from developing. Gas
combustion is not currently required.
The USEPA has recently proposed a rule that would indirectly control methane
emissions by regulating air pollution emissions from landfills. The purpose of the rule is to
limit air pollution from new and modified MSW landfills by requiring them to install gas
collection systems and combust the captured landfill gas (with or without energy utilization) if
their air pollution emissions exceed a specified cutoff level.
The proposed rule requires any facility with maximum design capacity of 100,000 Mg
(111,000 tons) or more to calculate periodically its annual non-methane organic compound
(NMOC) emission rate. Each facility where the calculated emission rate is found to exceed
the proposed cutoff will be required to install a "well designed gas collection system and one
of several effective control devices to either recover or destroy the collected landfill
emissions." The control device will have to be capable of reducing NMOCs in the collected
gas by 98% by weight, thereby meeting EPA's Best Demonstrated Technology (BDT)
standards. In selecting regulatory alternatives, a preliminary evaluation of different NMOC
emission rate cutoffs between 25 Mg/yr and 500 Mg/yr was performed (USEPA 1991 a). When
finalized, this rule making should have a significant impact on landfill gas emissions.
4.2 OVERVIEW OF OPTIONS FOR REDUCING EMISSIONS
There are two general approaches for reducing methane emissions from landfills. One
approach involves modifying waste management practices to reduce the amount of waste
landfilled. Another approach is to recover the methane and to use it as an energy source or
to flare it. Utilizing or flaring the methane is the only method currently available for reducing
emissions from existing landfills and from landfills that will contain degradable waste in the
future.
4.2.1 Landfill Gas Recovery and Utilization
The methods used to recover landfill gas are described below followed by a
description of the options available for utilizing the gas, including: electric power generation,
sale as gas, and other uses.
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Recovery Options
Most landfill gas recovery systems use similar designs. The most common design
uses vertical wells to extract the gas and an above-ground system of collection headers to
gather it to a point where it is utilized. After the landfill is capped, wells are drilled into cells
within the landfill. A well consists of perforated pipe casing (usually polyvinyl chloride) placed
in holes drilled in the waste. These holes are back filled with a permeable material such as
gravel around the casing and then sealed at the surface with an impermeable material to
prevent the inflow of air. Well spacing varies depending on site-specific variables such as
methane production per unit of waste, but generally well spacing is on the order of 150 to
300 feet (Pacey 1993).
Horizontal trenches may be used instead of, or in addition to, vertical wells. Trenches
are particularly useful in control of gas emissions in the active work area and when additional
refuse will be placed vertically above the area from which the gas is to be recovered.
Because these trenches will be covered by additional refuse, they are susceptible to refuse
settlement and pipe breakage. The useful life of horizontal trenches is about half that of
vertical wells. Trench spacing varies depending on site specific variables, but trenches are
generally placed 75 to 150 feet apart laterally and between 30 and 50 feet apart vertically
(Pacey 1993).
All of the wells (or trenches) are connected by horizontal piping and a vacuum is
applied to remove the gas from the waste. The horizontal piping, known as the collection
header system, can be placed either above the surface of the landfill or below the surface if
necessary. As with horizontal wells, sub-surface header systems may break when the waste
settles and are difficult to repair. A motor/blower unit is usually the source of the vacuum and
collects the gas to a central point. The motor/blower and individual well valves must be
carefully regulated to prevent the vacuum from becoming too strong and drawing air into the
landfill. This would reduce methanogenesis and decrease recovery rates.
As an additional benefit, the gas collection system also helps control landfill leachate
as water condenses in the wells and header pipes. In a well-designed system the
condensate is collected at various points and can then be either returned to the landfill or
disposed of by another means, depending upon its characteristics and applicable laws. If the
condensate is not removed, it can block the passage of gas at low points in the system.
With a favorable landfill configuration and a properly constructed collection system,
recovery rates approaching 85 percent can be achieved with little difficulty (Maxwell 1990).
Recovery systems usually are operated as part of an overall landfill gas control system. Other
portions of the system may include perimeter monitoring and methods to prevent off-site
migration of landfill gas.
Once the gas has been collected by a recovery system, it can be utilized in a variety
of ways, including:
electric power generation;
gas delivery systems; and
emerging uses, such as fuels cells or the production of liquid fuels.
4-15
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Electric Power Generation
For landfills that generate large amounts of landfill gas, electric power generation is
usually the most cost-effective method of utilization. According to the Methane Recovery
From Landfill Yearbook, 1990-91, compiled by Government Advisory Associates (GAA), Inc.,
over two-thirds of the gas-to-energy projects generate or plan to generate electricity. Several
options for producing electric power are as follows.
Internal Combustion, Reciprocating Engines. An internal combustion (1C),
reciprocating engine generator can be used to produce electricity. These engines have
proven to be cost effective with cogeneration applications. In cases where small sizes are
necessary, 1C engines are the only available, proven option.
The engine is tuned to operate with the medium-BTU characteristics of landfill gas.
In some cases, 1C engines can be designed to operate on various fuels by equipping them
with multiple carburetors. A reciprocating internal combustion engine works by burning a
mixture of fuel and air. 1C engines generally require a fuel value input of 11,000 to 14,000
BTU per kWh produced (USEPA 1992c). This translates into an efficiency of approximately 25
to 30 percent. If the heat from the cooling system, exhaust, turbocharger, and lubricating oil
can be recovered, higher overall efficiencies may be achieved.
The primary disadvantage of 1C engines is their susceptibility to corrosion from
contaminants in the landfill gas. For example, corrosion occurs from industrial degreasing
and dry cleaning solvents that have been placed in landfills (liquid solvents may no longer be
placed in landfills). This problem has been addressed by installing corrosion resistant parts
(e.g., chrome valve stems and modified piston rings) and by frequent checking and changing
of the engine oil. The three primary manufacturers of these engines have modified the design
and the operating procedures to make the engines "landfill-gas-adapted" (USEPA 1992c).
Nitric oxide (NOX) emissions from 1C engines can be a problem. In some areas,
including ozone "non-attainment" areas, the siting of new combustion sources is difficult due
to requirements to reduce emissions of NOX or other combustion products. 1C engines
generally have higher NOX emissions than other electricity generation methods such as
turbines and fuel cells. Newer lean-burn12 1C engines, however, produce less NOX than
previous engines (Thorneloe 1992a).
Turbines. Gas turbines are similar to jet engines. At the front of the engine a large fan
draws air into a compressor. The compressor raises the pressure of the air, which then flows
to the combustion chambers. In the combustion chamber the fuel is ignited, causing the fuel-
air mixture to expand. The hot, high pressure gases rush toward the exhaust, where it turns
turbines which drive the fan, the compressors, and an electric generator.
Combustion turbines are slightly more expensive per kWh than 1C engines and
generally have an electrical efficiency in the range of 25 to 35 percent. However, the relatively
new steam-injected gas turbine (STIG), which injects high pressure steam in the combustion
"Lean Burn" technologies are developments that alter the air fuel mixture in the chamber. Less fuel and more
air enters the chamber, making the combustion process more thorough. Generally speaking, this decreases fuel
consumption and emissions of pollutants, but at a slightly higher cost.
4-16
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chamber, could potentially raise efficiency levels over 10 percent, while significantly
decreasing NOX emissions as well (Williams and Larson 1989).
Gas turbines generally are used at landfills that generate large amounts of methane
gas. Their power output per turbine is usually in the 3-4 MW range, depending upon the
source of gas. If gas flows are higher, a number of turbines may be used simultaneously.
They require a gas flow of approximately 2,000,000 scf/day at reliable levels to be feasible.
Although they require higher gas flows and operate at lower rates of efficiency, gas turbines
do have some advantages over internal combustion engines. Because of the large quantities
of excess air, NOX emissions are considerably lower than in 1C engines. This allows the use
of turbines in areas where 1C engines would have a very difficult time meeting air quality
standards. Also, the high temperature alloys used to operate at these high temperatures tend
to be more resistant to corrosion from impurities within the gas supply. If properly set-up, gas
turbines can operate over a range of fuel quality. Gas with heating values ranging from 450
to 700 BTU/ft3 can often be used without equipment modifications. This is especially
important at some locations where the purity of the gas supply may vary on a weekly basis.
Rankine Cycle (Steam) Turbines. In rare cases where gas flow rates are extremely
high, a rankine cycle turbine may be used. Rankine cycle turbines, otherwise known as
steam turbines, are the most common technology used for generating electricity in the United
States. The fuel (in this case, landfill gas) is combusted, creating heat which is used to make
steam. The steam is utilized by a heat recovery steam generator (HRSG), which uses the
steam to turn a turbine which supplies mechanical energy to a generator. In most cases the
steam then passes through a condenser and is returned to the boiler. If the scale of the
operation will support a rankine cycle turbine, electrical efficiencies similar to other methods
of power generation can be achieved (thirty to forty percent), generally with lower emissions
of air pollutants and lower costs per kWh of output. They also offer large amounts of high
temperature water which can be easily utilized for thermal co-generation activities.
Due to their large scale, rankine cycle turbines are only feasible at sites that generate
large amounts of landfill gas. The smallest facilities usually generate 8-9 MW of power.
Currently, rankine cycle turbines are only used at a handful of landfills in the United States,
the largest being a 47 MW facility at Puente Hills, California.
Another option is essentially a hybrid of the previous two technologies. Combined-
cycle combustion turbines utilize a combustion turbine to generate electricity like a normal
turbine. However, with combined-cycle operations, the high temperature exhaust of the
combustion turbine is used to produce steam in a HRSG. The HRSG produces additional
electricity, increasing the overall electrical efficiency of the system to nearly 50 percent.
Although combined-cycle technology has been used in a number of other applications, it has
only been used at one landfill gas recovery facility in the United States. Combined-cycle
facilities generally offer the highest net power for a given landfill, but the increased complexity
and cost of the system often outweighs the value of the additional power.
Gas Delivery Systems
Gas processing and delivery systems process landfill gas so it can be sold as a
gaseous fuel. Pipelines are used to deliver the fuel directly to a customer, or to the natural
gas system network. If medium-BTU fuel can be sold to a customer that is in close proximity
to the landfill, then only minimal gas processing may be required. In this case, a pipeline
dedicated to delivering the landfill gas to the customer is required. Alternatively, landfill gas
4-17
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can be upgraded to a high-BTU fuel and injected into the natural gas pipeline distribution
system. Upgrading to a high-BTU fuel is costly, however.
Sale as a Medium-BTU Fuel. In areas where industry is located near the landfill,
medium-BTU gas can be economically transported via pipelines to one or more industrial
facilities. An ideal medium-BTU gas customer should be located near the landfill (3-5 miles
maximum).
Landfill gas customers may use the gas to fuel a cogeneration system, to fire boilers
or chillers, or to provide space heating. As extracted, landfill gas has an approximate heating
value of 450-550 BTU/ft3. This medium-BTU gas often must be processed to meet the
requirements of the facility utilizing the gas. Usually water and hydrogen sulfide are the
primary components removed during purification. This may vary considerably, depending
upon the end-use of the gas. Some facilities may be able to utilize the raw gas without
purification.
Sale as a High-BTU Fuel. If the landfill gas is processed to pipeline specifications, it
can be sold directly to natural gas companies, where it is injected directly into the utilities
distribution system. The cost to upgrade the gas to high-BTU standards is generally very
high. Sale as a high-BTU fuel to a pipeline also usually requires that a natural gas pipeline be
located within close proximity of the site. However, in this case the landfill is not required to
identify specific customers to use the gas.
Upgrading the gas to pipeline quality specification requires the removal of water,
carbon dioxide (CO2), hydrogen sulfide (H2S), hydrocarbons, and on some occasions,
nitrogen. As contrasted to the use of landfill gas as a medium-BTU fuel, the costly part of this
process is the removal of CO2 and trace contaminants. Several processes can be employed
to remove the CO2, the most common of which is the absorption process.
The absorption process uses a solvent to absorb gases without any chemical
reactions. The gas is passed through the solvent, which absorbs the water, CO2, H2S, and
benzene. Because most contaminates have higher solubilities than methane, the absorption
process can be selectively controlled to eliminate most of the contaminates without absorbing
the methane. Nearly pure methane can be produced.
The absorption process which has been used most frequently is the SELEXOL®
process, which is currently in use at the Fresh Kills Landfill in Staten Island, New York. The
KRYOSOL® process is currently in use at landfills in Atlanta, Georgia and Birmingham,
Alabama. This method removes the non-CO2 contaminants cryogenically, and then produces
high-quality CO2 in the absorption step. The cryogenic purification step allows food-grade
CO2 to be produced by the absorption process.
A third method that has been commercially used is an adsorption process known as
the GEMINI®-5 PSA system. This system uses a thermal swing adsorption process to
pretreat the gas, removing water and most other impurities within the gas, and then a
4-18
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pressure swing adsorption process to remove the CO2 from the methane. Additional
adsorption processes that use a variety of solvents have also been investigated.13
Membrane separators have also been developed to remove CO2 from landfill gas.
The landfill gas passes through a series (usually two stages) of membranes under high
pressure, separating the methane from CO2. To date membrane separators have not been
economic for use with landfill gas because:
• the membranes are costly to replace;
• the raw landfill gas must be processed to remove any condensates prior to
entering the membrane separator, otherwise the condensates will plug the
membranes, shortening their life; and
• high pressures are required, leading to considerable energy requirements for
operation.
Emerging Utilization Options
Other less conventional utilization options are available or may become available.
Some of these options such as fuel cells are being demonstrated at a number of landfills to
determine their operational and economic viability. Other options such as the production of
mobile diesel fuel are promising technically but may not be economically justifiable at this
time.
Fuel Cells. A fuel cell is a device that converts the chemical energy of a fuel directly
into usable energy as electricity and heat. The fuel cell technology is currently under
development and holds great promise as a future option for utilizing landfill gas. In a fuel cell,
hydrogen (H2) gas is passed along the surface of an anode, and oxygen (O2) is passed
across the cathode. The hydrogen atoms release their electrons, and thereby produce
electrolytes. Landfill gas can be used as a source of hydrogen for such a system.
The Electric Power Research Institute (EPRI) and the USEPA Air and Energy
Engineering Research Laboratory (AEERL) are currently undertaking projects to demonstrate
fuel cells at existing landfills. EPRI is operating a 2 to 100 kW modular carbonate fuel cell test
facility and is planning a 20 kW fuel cell demonstration test at a Minnesota landfill (Resource
Management International, Inc. 1992). AEERL initiated a project in 1991 to demonstrate a
commercially available 200 kW phosphoric acid fuel cell. A ono year full-scale demonstration
test is scheduled to begin in 1993 (Thornelde 1992a).
Fuel cells have a number of advantages over technologies currently in use today such
as internal combustion engines and turbines. These advantages include:
13 The advanced amine guard process uses the solvents aqueous triethanolamine (TEA) and aqueous
diethanolamine (DEA) to remove the CO2. First compressed pretreated landfill gas is contacted with aqueous TEA
for bulk removal of CO2. Then aqueous DEA is used for removal of the remaining CO2. The Benfield and Binax
processes both work like the other solvent methods, but the Benfield process uses a solution of mostly potassium
carbonate in water as the solvent, while the Binax process uses water to absorb the CO2 from the landfill gas. The
Benfield system can be used (without losses in methane recovery) at much lower pressures than the other
systems.
4-19
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higher energy efficiencies;
lower by-product emissions;
minimal noise production;
• minimal labor requirements; and
modularity, better design for small landfills.
While fuel cells remain to be demonstrated at landfills, the high costs have hindered their
acceptance. Although several technical issues remain to be resolved, technological advances
and streamlined manufacturing are expected to bring fuel cell costs down to competitive
levels.
Production of Liquid Fuels and Industrial Chemicals. Recent developments in
alternative fuels have led to the improvement of a process that converts landfill gas into
diesel, naphtha, and high grade industrial waxes. The diesel fuel produced in this process
has been extensively tested by Detroit Diesel Corp.; Environmental Testing Corp., Aurora,
Colorado; and the California Air Resources Board, El Monte, California. The other products
of the process also have special qualities which should make them very marketable. The
naphtha produced is nearly odorless, and a grade of industrial wax is produced that was
previously available only from South Africa.
The greatest drawback of the process is high cost. Using cheap landfill gas as
feedstock, the end product is still somewhat more expensive than conventional diesel.
However, there may be certain applications in which a premium for the cleaner burning diesel
fuel produced by this process is justified. For example, cities classified as non-attainment
areas that have large numbers of diesel fueled vehicles may require use of cleaner burning
fuels to meet emission requirements.
Flaring
Flaring is the least costly method to safely eliminate landfill gas. In some cases flaring
may be the only option consistent with local environmental and air quality requirements.
However, while the capital cost is small compared to energy recovery systems, flaring does
not produce income.
There are essentially two types of flares used today, open flame combustors (candle
or pipe flares) and enclosed combustors. Open flame combustors are the simplest type,
basically consisting of a pipe with some form of pilot to keep it ignited. The gas flow to this
system may be controlled, but because it is burned in the open, air flow cannot be controlled.
It is effective at destroying over 98 percent of the total hydrocarbons provided a stable flame
exists. The greatest shortcoming of this system is the inability to accurately monitor
emissions. In areas where regulatory agencies require emission sampling or testing, this
method cannot be used.
Enclosed combustors have a number of advantages over open flame combustors.
First, they do allow the accurate sampling or testing of emissions. Second, they allow the
flame to be hidden, which for aesthetic reasons is required in many areas. Third, the
combustion process can be better controlled, improving destruction of hazardous
constituents. This is done by controlling both the flow of gas, and the flow of air. The landfill
gas is "pushed" through the burner tips by a blower, while the stack pulls or drafts air through
dampers and around the burner tips.
4-20
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4.2.2 Examples of Recovery and Utilization Projects
In 1991 there were just over 100
landfill gas recovery and utilization projects
operating in the U.S. Seventy-one of these
projects generated electricity and twenty-five
There were about 100 landfill gas
recovery and utilization projects in
operation in tfce U.S, in 1990,
sold the gas as a medium-BTU fuel. Three
landfills both produce electricity and sell the
gas as a medium-BTU fuel. Of the seventy-
four landfills that produced electricity, most have an electrical generating capacity between
0.5 and 4 megaWatts. Exhibit 4-5 shows the distribution of the seventy-four electricity
generating projects by their generating capacity.
The following are examples of some of these projects covering the major utilization
options discussed above.
Reciprocating Engine - Marina, CA. The Marina Landfill is located in Marina, California.
The landfill has been receiving waste since 1966, and currently receives about 4,800 tons of
waste per week. The 490 acre site contains about 4 million tons of waste. Approximately 0.9
MMscf/d (million standard cubic feet per day) of landfill gas is recovered from 12 vertical wells
and 7 horizontal trenches. Each of the facility's two generator sets are powered by a
Waukesha 12-cylinder engine, for a total of 1.2 MW (USEPA 1992c; USEPA 1992d).
The project was initiated in December 1983 and is one of the first landfill gas recovery
and utilization projects in the United States. The total cost of the system (not including
extraction costs) was about $1.3 million. Annual operating and maintenance costs of the
facility are about $100,000, while annual revenues are about $360,000. Electricity is sold to
Pacific Gas & Electric at a variable price ranging from $0.028 to $0.034 per kWh. The system
is currently owned and operated by the Monterey Regional Waste Management District
(USEPA 1992c).
Combustion Turbine - San Diego, CA. The Sycamore Canyon Landfill is located near
San Diego, California. The landfill has received waste since 1962 and currently has nearly
9 million tons of waste in place. The landfill covers an area of 530 acres, and has 50 vertical
recovery wells which recover approximately 1.2 MMscf/d of gas. The facility houses two Solar
Saturn recuperated gas turbines, each rated at 933 kW, that together generate about 1.7 MW
(USEPA 1992c; Thorneloe 1992a).
The turbine generating systems began to operate in 1989. The total capital costs of
the project were about $4 million. Annual operating and maintenance costs of the facility and
of the gas recovery system are about $450,000, while annual revenues from the system are
about $1,000,000 (Huitric 1993). Electricity is sold to San Diego Gas and Electric (USEPA
1992c).
4-21
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Exhibit 4-5
Electricity Generating Capacity of Existing Landfill Projects
20
19 -
18 -
17 -
in 16-
— 15 -
% "-
C 12 -
B r
10 -
b !:
| ;;
3 -
2 -
1 -
0
12 12
1
m_
Electric Generating Capacity
I - 10 10 - 20 20*
Based on GAA (1991).
Rankine Cycle Turbine - Puente Hills, CA. The Puente Hill Energy Recovery from Gas
Facility (PERG) is located in Whittier, California. The landfill currently receives 72,000 tons per
week and has over 45 million tons of waste in place. The entire fill covers an area of 1,365
acres, with an active area of approximately 550 acres, and a maximum depth of about 500
feet. Due to its tremendous size and extensive gas collection system, roughly 34.6 MMcf/d of
landfill gas is collected and burned on site, producing 46 MW in total power, making it the
largest landfill gas-to-energy project in the country. The average heating value of the gas is
420 BTU/scf.
The project began in 1981, when a gas collection system was installed to control
odors and subsurface migration. The gas collection system consists of vertical wells and
horizontal trenches. There are currently over 400 wells on the landfill. The wells are
monitored on a biweekly basis for temperature and methane content. The trench system is
constructed on the operating portion of the landfill, with collection pipes roughly every 260
feet. There are currently over 18 miles of landfill gas piping in the system.
Operation of the PERG facility began in November 1986. The choice of rankine cycle
turbines was made after a study of all suitable technologies. It was decided that such a
system offered the best combination of low air emissions, high net production power, ease of
operation, flexibility with landfill gas content, and low construction costs. The capital costs of
the entire project, including design, construction, and interest during construction, were
approximately $33 million for the facility, for a unit cost of about $650 per kilowatt of installed
capacity. Project revenues are generated from the sale of electricity to Southern California
Edison. Under the current agreement, the PERG facility receives annual lease payments from
Southern California Edison of $8,712,000 while total annual operating costs have been
roughly $3,600,000. In addition to the rankine cycle boiler, two combustion turbines are also
operational at the site. These are used on a gas available basis.
4-22
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Gas Fueled Boiler System - Raleigh, NC. Wilder's Grove Landfill is located in Raleigh,
North Carolina. The landfill has been open since 1972, has an estimated 3.3 million tons of
waste in place, and occupies 125 acres. Approximately 1.3 MMscf/d of gas is recovered from
a vertical well recovery system and then piped one mile to a pharmaceutical plant for use as
boiler fuel. The Cleaver-Brooks boiler, rated at 26,800 pounds per hour of steam on natural
gas, produces nearly 24,000 pounds of steam per hour for use at the pharmaceutical plant
(USEPA 1992c; Thorneloe 1992a).
The project began in December 1989, and involved five entities that owned and/or
operated the landfill, landfill gas system, pipeline, and boiler facility. Initial capital costs for
the pipeline, pumping station, and boiler were about $900,000. Annual operation and
maintenance costs for the gas system are approximately $42,000. Annual revenues from
steam sales range from about $450,000 to $500,000. Tax credits are estimated to exceed
$150,000 per year (USEPA 1992c).
4.3 NATIONAL ASSESSMENT OF PROFITABLE METHANE REDUCTIONS
In 1990 approximately 6,000 landfills in the U.S. emitted between 8.1 and 11.8 Tg of
methane to the atmosphere (USEPA 1993a). Most of these emissions are concentrated in
about 2,000 large landfills where it is technically feasible to recover about 85 percent of the
methane produced. Depending on the value of the recovered gas, it is profitable to recover
and utilize the methane from a subset of these large landfills. The amount of methane that
can be mitigated at a profit depends primarily on the price at which electricity produced from
the recovered gas can be sold.
This analysis estimates the total amount of methane that can be profitably mitigated
from landfills in the United States. Only methane recovery and utilization for electric power
production are considered as options for reducing emissions. The methodology includes the
following three main steps: (1) financial analysis at the individual landfill level to assess the
profitability of recovery and utilization; (2) assessment of the profitable options nationally; and
(3) estimation of the amount of methane that will be mitigated nationally by the adoption of
the recovery projects. Each step is described below.
4.3.1 Landfill-Level Financial Analysis
This portion of the analysis assesses the economic viability of methane recovery and
utilization at the landfill level. A discounted cash flow analysis was performed to identify
those conditions under which the projects have a positive net present value. The costs and
revenues for the analysis are largely influenced by the amount of gas that can be recovered
from the landfill. First, the method used to estimate the amount of landfill gas that could be
recovered is described. Then, the costs of
the recovery and utilization systems and the
revenue from selling electricity are
presented. Finally, the manner in which the
discounted cash flow analysis is performed
is described, including the manner in which
the requirements of the proposed rule
requiring landfill gas collection are
considered.
under which landfill gas recovery is
by fee value
4-23
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Landfill Gas Production and Recovery
One approach for estimating the amount of landfill gas that can be recovered from a
landfill is to conduct on-site measurements from test wells. However, such an approach is
not practical for the thousands of landfills that are candidates for recovery and utilization
projects. As an alternative, a model was used to predict the potential to recover landfill gas
based on the amount of waste in the landfill. Although the model does not consider all the
site-specific factors that affect landfill gas production, it is appropriate to use it to assess
landfill gas production at the population of landfills in the U.S.14
As described in USEPA (1993a), a statistical model was developed from data that
establishes the relationship between the quantity of waste in place and methane production in
the landfill. The analysis builds upon analyses performed by the USEPA Air and Energy
Engineering Research Laboratory (AEERL) which indicate that a relatively simple model can
be used to estimate methane generation rates in the United States. For 21 landfills, AEERL
conducted site visits and examined in detail the relationships among methane recovery and
(1) waste quantity; (2) waste characteristics (such as moisture content, temperature, and pH);
and (3) landfill characteristics (such as age, depth, volume, and surface area). Although
many of these factors were found to be correlated with observed gas recovery rates, AEERL
chose waste quantity as the preferred variable for explaining variation in the observed gas
data (USEPA 1992b) because it explains much of the variation and is fairly readily available
information.
The model developed in USEPA (1993a) is based on information from 85 landfills that
are representative of the population of U.S. landfills and vary in terms of depth, age, regional
distribution, and other factors. For landfills with over one million megagrams (10 Mg) of
waste, the following statistical model was estimated:
CH4 (m3/min) = 8.22 + 5.54 W (106 Mg) - 2.09 D-W (4.1)
2.6 10.2 4.0
R2 = 0.67 n = 85 Range: 1,215,600 Mg <; W s 45,360,000 Mg
The variable W is the amount of waste at the landfill, measured in 106 Mg. A "Dummy"
variable, D, indicates whether the landfill is in an arid region.15 The model predicts the
amount of methane produced at the landfill, in units of cubic meters per minute (m3/min).
The figures below the coefficients estimates are the t-statistics for the 95 percent confidence
interval for the null hypothesis that the true coefficient value is zero. For this model, the
coefficients are significantly different from zero at the 95 percent confidence level.
In this study, insufficient information is available to assign reliably the arid/non-arid
dummy variable to each landfill in the population of landfills being analyzed. Consequently,
the model was simplified further by estimating a single coefficient for waste in place (W) that
reflects the national distribution of waste in place in arid and non-arid landfills. USEPA
14 Because of variability in the model, it is not adequately precise to evaluate an individual landfill. However,
the variability in the total result is reduced when applied to a population of landfills, as is done in this analysis.
15 The "Dummy" variable is set to 1 whe
less than 25 inches of precipitation annually.
15 The "Dummy" variable is set to 1 when the landfill is in an arid region, and 0 otherwise. Arid is defined as
4-24
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(1993a) estimates that 13 percent of the waste in place is in arid landfills, so that equation 4.1
becomes:
CH4(m3/min)= 8.22 + 5.27W(106Mg) (4.2)
A separate model was developed in USEPA (1993a) to estimate methane production from
smaller landfills (those with less than 106 Mg of waste in place) because Model 4.2 over-
estimated methane production at landfills with less than 106 Mg of waste in place.
CH4 (m3/min) = 7.43 W (106 Mg) (4.3)
This model is used for the smaller landfills and for large landfills during the period of time
when their waste in place is less than 106 Mg.16
To implement Models 4.2 and 4.3, the waste in place for the landfill is estimated based
on its acceptance rate over time. As discussed in USEPA (1993a), one of the assumptions
underlying Models 4.2 and 4.3 is that waste only produces methane for 30 years after it is
disposed. Consequently, to apply Models 4.2 and 4.3 for a given year, the sum of the waste
accepted at a landfill for the previous 30 years is taken as the waste in place for the
calculation. Waste that was disposed more than 30 years prior would be excluded from the
calculation.17 While this exclusion may be conservative (i.e., may under-estimate total
landfill methane production), insufficient data are currently available to incorporate the older
waste into the analysis.
While Models 4.2 and 4.3 estimate methane production as a function of waste in
place, only a portion of the methane produced in the landfill would be emitted to the
atmosphere. Even in the absence of a gas recovery system, a portion of the methane
produced in the landfill would be oxidized. Precise estimates of the rate of methane oxidation
are not available, and a 10 percent oxidation factor is used (USEPA 1993a). Consequently, in
the absence of a landfill gas recovery system, only 90 percent of the methane estimated
using Models 4.2 and 4.3 would be emitted to the atmosphere.
It is also the case that only a portion of the methane can be collected by the recovery
system. Based on discussions with owners and operators of landfill gas recovery projects,
gas collection efficiency (i.e., the portion of the gas produced that is collected) can vary
substantially, from 50 to 95 percent. A variety of site-specific factors influence the collection
efficiency, and precise estimates are difficult to ascertain (USEPA 1993a). For this analysis, a
collection efficiency of 85 percent is adopted, so that the gas recovery system only collects
85 percent of the gas estimated to be produced using Models 4.2 and 4.3.18 Of the gas
16 For example, if a landfill has only been open for a few years, it may have a small amount of waste. Model
4.3 is applied when the landfill has over 40,000 Mg and less than 1,000,000 (106) Mg of waste in place. When the
waste in place exceeds 106 Mg, M
production is assumed to be zero.
waste in place exceeds 106 Mg, Model 4.2 is applied. When the waste in place is less than 40,000 Mg, gas
In most cases today, all the waste in a landfill was disposed during the previous 30 years. Once a landfill is
closed, the value of the waste variable for Models 4.2 and 4.3 will decline as the waste in the landfill exceeds 30
years in age.
1A
Among existing recovery projects, the average collection efficiency is believed to be about 75 percent
(USEPA 1993). Future recovery projects are expected to have collection efficiencies of over 85 percent.
4-25
-------
not collected by the recovery system, 90 percent is estimated to be emitted to the
atmosphere (10 percent is assumed to be oxidized).
Exhibit 4-6 presents estimates of methane production, recovery, and emissions from
landfills of various sizes. These estimates were developed from Models 4.2 and 4.3, and are
expressed in units of m3/min of methane. Because landfill gas is only about 50 percent
methane, the amount of landfill gas produced would be about twice the amount indicated in
the exhibit.
Gas Recovery System Costs
The cost estimates for landfill gas recovery systems include the following system
components:
• cost of designing, obtaining and installing the collection system equipment,
including extraction wells, gas collection and handling equipment, and leachate
collection and handling equipment;
• cost of operating and maintaining the collection system equipment, including
labor, materials, insurance, overhead, and administration;
cost of installing a flare system to flare recovered gas; and
cost of operating and maintaining the flare system equipment, including labor,
materials, insurance, overhead, and administration.
The cost estimates were developed from data on existing recovery projects from USEPA
(1991b), USEPA (1991c), USEPA (1992c) and through discussions with experts who design
and build landfill gas recovery projects. All estimates are converted to 1990 dollars.
Although a variety of site-specific factors will influence the cost of the recovery system,
the amount of waste in place or gas recovered is a good indicator of the expected cost.
Consequently, these costs are estimated as a function of the methane recovered.
Collection System. The collection system includes the extraction wells, lateral well
connections, header system, gas mover system, and condensate handling system. The
capital cost of this system, including installation, is estimated as follows:
Collection System Capital Cost = W°-8 $470,000 (4.4)
where: W = waste in place in 106 Mg.
The annual operating and maintenance costs (O&M) for the collection system are
principally comprised of labor costs of 2 to 3 person-years and indirect costs (overhead,
insurance, administration). The non-labor costs of insurance and administration are estimated
as 4 percent of the capital cost estimated using Equation 4.4. Exhibit 4-7 summarizes
recovery system costs for a variety of landfill sizes. Equation 4.4 does not include the cost of
replacing components of the collection system that may need to be replaced over the course
of the project. However, these replacement costs are expected to be small relative to the
overall cost of the collection system and the overall cost of the recovery and utilization
system.
4-26
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Exhibit 4-6
Methane Production, Recovery, and Emissions from Representative Landfills
Landfill Size
(106 Mg)
0.25
0.50
1.0
5.0
10.0
20.0
Landfill Methane
Production3
(m3/min)
1.9
3.7
13.5
34.6
60.9
113.6
Methane Emissions:
No Recovery
System6
(m3/min)
1.7
3.3
12.1
31.1
54.8
102.3
With a Recovery System
Methane
Recovered0
(m3/min)
1.6
3.2
11.5
29.4
51.8
96.6
Methane Emittedd
(m3/min)
0.25
0.50
1.82
4.67
8.22
15.34
a Estimates using Models 4.3 (less than 106 Mg) and 4.2 (greater than or equal to 106 Mg).
b Estimated at 90 percent of the methane produced in the landfill.
c Estimated at 85 percent of the methane produced in the landfill.
d Estimated at 90 percent of the 15 percent of the methane produced in the landfill that is not collected by the
recovery system.
Flare System. The flare system is used to burn the collected landfill gas. The costs
for the flare system are included in this analysis even when gas utilization equipment is used
because excess gas may need to be flared at any time. The capital cost and O&M costs of
the flare system, including installation, are estimated as follows:
Rare System Capital Cost = (CH4 • $2,200) + $65,000
Rare System Annual O&M Cost = Flare System Capital Cost
(4.5)
(4.6)
where: CH4 = the methane recovered using the collection system (m3/min)
The annual O&M costs are estimated at 10 percent of the capital cost. Of this 10 percent, 6
percent is for direct costs such as labor and materials. The additional 4 percent is for indirect
costs such as administration and insurance. Exhibit 4-7 summarizes flare system costs for a
variety of landfill sizes.
Because the gas flow rate changes over time at a landfill, the one-time maximum gas
flow rate estimated for a 20 year period is used in these cost calculations. At an open landfill
where the gas flow rate is increasing, the capital and operating costs are estimated using the
maximum gas flow rate expected in 20 years. At a closed landfill, where the gas flow rate is
declining, the maximum is also used (which is the current gas flow rate because the rate is
declining). By using the maximum gas flow rate this method considers the maximum
expenditure required for the collection and flare system.
4-27
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Exhibit 4-7
Representative Landfill Energy Recovery System Costs: Capital & Annual O&M
Landfill Max Gas Engine
Size Flow8 Capacity15
(106Mg) (m3/min) (MW)
0.25 1.6 0.3
0.50 3.2 0.6
1 6.3 1.1
5 29.4 5.2
10 51.8 9.1
20 96.6 17.1
Collection System
(000 dollars)
Annual
Capital o&M
155 55
269 60
468 68
1,698 117
2,956 167
5,146 255
Flare System
(000 dollars)
Annual
Capital o&M
68 4
72 4
79 4
130 7
180 10
280 15
Generator System
(000 dollars)
Annual
Capital0 O&Md
374 37
719 73
1,379 147
6,227 682
10,974 1,202
20,467 2,241
Total
(000 dollars)
Annual
Capital o&M
$597 $96
$1,060 $137
$1,927 $219
$8,055 $806
$14,109 $1,379
$25,892 $2,51 1
a Estimated using Models 4.2 or 4.3 (depending on landfill size) and an 85 percent collection efficiency.
b Estimated using Equation 4.7
c Estimated using Equation 4.8.
d Estimated using Equation 4.9 with an O&M rate of $0.015/kWh of installed capacity.
Gas Utilization Costs
While a variety of gas utilization options is available, only the option of producing
electricity using internal combustion reciprocating engines is analyzed. This option is
expected to be preferred at many landfills because: the technology is well established; it can
be used at both large and small landfills; and landfills are almost always in reasonable
proximity to electric power lines. Because alternative utilization options may be preferred in
some cases due to lower costs or higher benefits, this analysis may over-estimate gas
utilization costs. For example, at the largest landfill projects, turbines are likely to be more
cost effective than reciprocating engines for producing electricity.
Rather than estimate each component of the capital and O&M costs for the utilization
equipment, aggregate parameters were adopted to estimate costs as a function of electricity
generating capacity and electricity produced. Capital costs, including obtaining and installing
all necessary engine generator equipment, are estimated at $1,200 per kiloWatt (kW) of
capacity. This cost includes all site acquisition and preparation costs as well as connections
to the utility grid. Site-specific factors that may cause these costs to be higher or lower are
not considered.
The gas flow rate is used to estimate the engine generator capacity desired. As
discussed above, the gas flow rate changes over time at a landfill. Therefore, the maximum
sustainable gas flow rate expected over a 20 year period is used to size the engine generator
to estimate costs. The following equation is used:
Engine Generator (MW) = MAX (CW4)/n3/min
60 mtolhr • 35.3 ft3//n3 • Jg? gff
12,000 BTUIkWh
(4.7)
1,OOOkWIMW
where MAX (CH4) is the maximum methane flow rate over 20 years (in m3/hr). Based on the
result of Equation 4.7, the capital cost of the engine generator is estimated as follows:
Engine Generator Capital Cost = (Engine Generator MW) • $1,200,000/MW (4.8)
4-28
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Estimating this cost based on the maximum gas flow rate is conservative because several
smaller engine generators could be obtained and brought on line as the gas flow rate
increased. Similarly, the smaller engines could be used elsewhere (or sold) as the gas flow
rate decreased. By estimating the costs for the engine generator as a single unit, the costs
may be over-estimated.
O&M costs are estimated using a range of 1.5 to 2.0 cents per kWh of electricity
produced. This range encompasses most of the reported experience of existing projects, and
includes labor as well as other direct costs and indirect costs such as insurance and
administration. The O&M costs are also estimated using the maximum gas flow rate, as
follows:
Engine Generator O&M Cost - O&M Rate ($ / KWh) - Engine Generator (MW). 8.760 hrlyr (4.9)
1,000 Kwwf Mrr
where the O&M rate is $0.015 to $0.020 per kWh. Using the maximum gas flow rate to
estimate these costs is also conservative because the engine generator is not running at
maximum output most of the time. For the projects evaluated in this analysis, the engine
generators run on average at 80 to 95 percent of their maximum capacity. Exhibit 4-7
summarizes the estimates of the capital and O&M costs for electricity generation for a range
of maximum gas flow rates. As shown in the exhibit, the capital costs are mostly in the
millions to tens of millions of dollars. The annual O&M costs are roughly 11 to 15 percent of
the capital costs.
Over the course of the project's lifetime, by far the largest costs are for the engine
generators and the engine generator O&M. For a 1 MW gas recovery project, the engine
generator capital and O&M each account for about 35 percent of the project's lifetime cost.
The collection system capital and O&M account for about 25 percent of the lifetime cost and
the flare system capital and O&M account for the remaining 5 percent of the lifetime cost.
Exhibit 4-8 summarizes the lifetime costs for a range of representative landfill sizes.
The estimates for capital and O&M costs for the collection, flare, and utilization
systems were compared to estimates published in GAA (1991) for 14 landfills that reported all
these data elements. Overall, the comparison shows that the estimating equations over-
estimate the capital costs per MW slightly, and substantially over-estimate O&M costs per MW
for smaller landfills. The correlations between the estimated and published values are 0.95 for
the capital cost estimates and 0.92 for the O&M cost estimates.
Value of Electricity Production
The value of the electricity produced is estimated as the amount of electricity
produced (in kWh) times a single rate per kWh ($/kWh). The rate at which landfills can sell
electricity will vary depending on the terms negotiated with individual utilities and the rules
established by state public utility commissions. Often, the rates involve payments for installed
capacity as well as a schedule of rates that depends on the time of day and/or season in
which the power is produced. For this analysis it is assumed that the landfill gas will be
collected continuously, and that the electric generation equipment will operate continuously,
except for scheduled maintenance periods. Landfill gas storage and power generation
strategies that take advantage of higher peak power rates are not considered.
The electricity generated is estimated from the amount of gas produced each year. In
most cases the gas produced is less than the maximum capacity of the engine generator
4-29
-------
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because the engine generator was sized based on the maximum gas flow rate over a 20 year
period. A heat rate of 12,000 BTU/kWh is used to convert landfill gas to electricity. Landfill
gas is assumed to have 500 BTU per ft3, or 1000 BTU per ft3 of methane.
Discounted Cash Flow Analysis
A discounted cash flow analysis was used to estimate the net present value of the
landfill recovery projects at the landfill level. The following factors were used for the analysis:
All installation costs are incurred as a lump sum in year 1.
Capital costs are depreciated using straight line depreciation over 10 years with
no salvage value.
• Taxes are computed assuming a marginal tax rate of 40 percent.
After-tax cash flows are discounted at a real rate of 8 percent, with sensitivity
cases of 6 and 10 percent also presented. The discount rate used in this
analysis reflects the private (i.e., landfill industry) perspective and is not a social
discount rate.19
Investment tax credits or other tax incentives for producing power from renewable resources
are not considered in the analysis.
The recovery and utilization project with the highest net present value (NPV) is
selected as the most attractive project for the landfill. If the NPV of the most attractive project
is greater than zero, the project is considered to be profitable. If the NPV is less than or
equal to zero, the project is considered to be not profitable. To identify the most attractive
recovery and utilization project, the following analysis is performed for each landfill:
• Compute Landfill Methane Over Time. The expected methane production is
estimated for each year from 1990 to 2050. The waste in place that contributes
to methane production is estimated based on the waste in place in 1990 and
the landfill acceptance rate.20 When the landfill's design capacity is reached
the landfill stops accepting waste.21 The estimate of landfill methane
production over time is used to estimate the amount of methane that can be
recovered from the landfill each year during the period. As discussed above,
an 85 percent collection efficiency is used in the analysis.
19 Discount rates in the range of 6 to 10 percent are appropriate for the solid waste disposal industry. Other
discount rates would be appropriate for other industries and other types of methane mitigation projects.
20 If the landfill is simulated to open after 1990, the analysis begins with the year it opens.
21 The total waste in place at the landfill is used to assess whether the landfill has reached its design capacity.
If the landfill has been open for over 30 years, the waste that contributes to methane production will be less than
the total waste in place at the landfill.
4-31
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• Compute NPVs for Each Option for Each Year.22 For each year from 1990 to
2010, four options are evaluated:
one internal combustion (1C) engine generator operating for 20 years;
two internal combustion (1C) engine generators operating sequentially
for 20 years each (for a total project length of 40 years);
pO
a collection and flare system that collects and flares the gas; and
do nothing.
For example, at an existing landfill that was open in 1990, the NPV for each of
these four options is computed 20 times: once for each year in which the
project may begin (1990, 1991, 1992, 1993, etc.). As a result, 20 NPVs are
estimated for the 20 year 1C engine generator option, one for each year in
which the project can begin. Of these 20 values, the highest NPV indicates the
year in which it is best to begin a 20 year 1C engine generator project at this
landfill. Similarly, 20 values each are computed for the 40 year 1C engine
generator option and the collect and flare option. The NPV of the "do nothing"
option is always zero.
Select the Preferred Option. Using the 80 NPVs computed (20 each for 4
options), the option with the highest NPV is identified. Because the collect and
flare option only entails costs and no revenue, it always has a negative NPV.
Consequently, "do nothing" is preferred to the collect and flare option. If one of
the 1C engine generator options has a positive NPV, it is preferred to the "do
nothing" option.
Using this method, the preferred option and the best year to initiate the preferred option are
identified for the landfill.
In the absence of any regulatory requirements to collect and flare landfill gas, the
above analysis will choose either an 1C engine generator project or "do nothing." However,
collecting and flaring landfill gas may be required in the future. To analyze the implications of
EPA's proposed rule requiring landfill gas collection and combustion, the impact of requiring
gas collection and combustion at landfills was evaluated.
The following additional analysis was performed to evaluate the implications of
requiring gas collection and combustion at each of the existing landfills:
Identify Whether and When "Collect and Flare" are Required. For each landfill,
a decision is required as to whether and when a collection and flare system
must be installed. This evaluation would normally be based on estimates of
NMOC emissions relative to the NMOC trigger level adopted in the landfill air
22 Because a real discount rate of 8 percent is used in the analysis, the internal rate of return (IRR) for any
project with a positive NPV will be greater than 8 percent. Assuming an average rate of inflation of 4 percent over
the period of analysis, a real IRR of 8 percent corresponds to a nominal IRR of 12 percent.
23 For purposes of this analysis the collect and flare option is assumed to continue for 20 years.
4-32
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pollution control rule. Because the NMOC emission cutoff has not yet been
selected, this analysis examines the implications of requiring collection and
flare systems at all the existing large landfills in 1990. It is expected that the
actual rule will be less stringent, so that only a portion (probably less than half)
of the landfills will be subject te the requirement.
Select the Preferred Option. The best option is selected using the NPVs
calculated above, subject to the constraint that either an engine project or a
collect and flare project must be implemented.24 Given this constraint, "do
nothing" cannot be selected. The implications of the requirement may be one
of the following:
No Impact: The requirement will have no impact on the landfill if the
preferred option in the absence of the requirement is one of the engine
projects starting in 1990. In this case, the engine project begins in its
best year and is unaffected by the rule.
Require a Non-Profitable Option be Implemented: In the absence of the
requirement, the preferred option for the landfill in the trigger year may
have been to "do nothing." With the requirement, the landfill must
initiate a project that is not profitable. The option with the highest NPV
will be selected (1C engine generator (20 or 40 years) or collect and
flare).
Change the Timing of a Profitable Project: In the absence of the
requirement, the preferred option for the landfill may have been to
implement an 1C engine generator project in a year later than 1990.
With the requirement, the landfill must initiate a project in 1990. The
result of selecting the option with the highest NPV may be to move the
timing of the profitable project from its preferred year to 1990. As a
result of moving the timing of the initiation of the project, the NPV for
the project must decline.
As a result of imposing the requirement, a non-profitable option may be undertaken, or the
timing of a profitable option may be changed so that its NPV declines. Complex strategies,
such as flaring gas for several years starting in 1990, and then initiating an 1C engine
generator project are not considered. Consequently, the results of the analysis are
conservative in that they may under-state the extent to which profitable opportunities exist to
reduce methane emissions.
Once the preferred option is identified, the emissions from the landfill are estimated. If
an 1C engine generator or collect and flare project is initiated, the amount of methane
collected and combusted is equal to 85 percent of the methane produced. The emissions in
this case are 15 percent of the methane produced, minus 10 percent for oxidation.
The engine projects will combust the gas adequately to comply with the rule.
25 The NPV for the project must decline because if the earlier year had a higher NPV, it would have been
selected as the preferred option initially.
4-33
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4.3.2 Assessment of Profitable Options Nationally
The profitability of gas recovery and utilization was assessed nationally by repeating
the landfill-level financial analysis for landfills around the country. For each landfill, the
analysis was performed to identify the preferred project based on NPV. The results from each
landfill were summed to estimate national results.
Because detailed data on every landfill in the U.S. are not readily available, the survey
conducted by the USEPA Office of Solid Waste (USEPAOSW) was used to characterize the
population of existing landfills. The USEPAOSW Survey collected information from about
1,000 landfills across the United States. The survey results were extrapolated by USEPAOSW
to represent the approximately 6,000 operational landfills in the U.S. In particular, the survey
includes information on waste in place and acceptance rate (USEPA 1988). This information
was used as follows:
• For each landfill in the data set, the amount of waste in place contributing to
methane production was estimated for the period 1990 through 2010 using the
following information: open date; waste in place in 1986; acceptance rate; and
planned closure date.26
Those landfills that do not accumulate 500,000 Mg of waste were excluded
from the analysis. A total of 597 landfills that responded to the survey
(representing about 4,155 landfills) were excluded in this step.27 These
landfills excluded from the analysis accounted for about 0.7 Tg of methane
emissions in 1990. These landfills will not likely be affected under the
proposed rule and, with only a few exceptions, will not find engine generators
profitable.
The 416 landfills remaining in the data set represent 2,034 landfills nationally. They represent
over 90 percent of the emissions in 1990, and consequently are the main focus of
opportunities to reduce methane emissions profitably.
The landfill-level analysis described above was conducted for each of the 416 landfills
in the data set. The results for each landfill were multiplied by the appropriate sampling
weight for the landfill and summed to estimate the national totals.
In addition to analyzing existing landfills, new landfills were simulated to replace
existing landfills that close. For each existing landfill that is simulated to close before 2010, a
new landfill is opened in the following year with the same acceptance rate. By using the
same acceptance rate, the total quantity of waste disposed remains constant, as expected
(USEPA 1993a). As with existing landfills, the new landfills that accumulate less than
500,000 Mg of waste are excluded from the analysis.
26 The acceptance rates were adjusted to reflect the total national acceptance rate estimated in USEPA
(1993a). As described in USEPA (1993a), the relative distribution of acceptance rates across landfill sizes was also
adjusted to reflect an increasing reliance on large.landfills.
27 The OSW survey was designed so that each respondent represents more than one landfill nationally. Each
landfill's weight in the national population was reported in the OSW data set, and generally falls in the range of 2
to 7.
4-34
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The total national results are the sum of the estimates for new and existing landfills.
To the extent that new landfills have different characteristics than existing landfills, that portion
of the analysis may be biased. For example, if landfills are larger than expected in the future,
the average size of future landfills may be under-estimated. Such an under-estimate could
lead to an under-estimate of the profitable opportunities to reduce emissions because
profitability improves at larger landfills.
4.3.3 Methane Emissions Mitigated
Methane emissions mitigated are equal to the emissions that would have resulted had
landfills not implemented the profitable recovery and utilization projects. Methane emissions
mitigated are 90 percent of the methane gas recovered because 10 percent of the recovered
gas would have been oxidized as it was emitted from the landfill.
The total methane emissions mitigated is estimated by summing the results from the
individual landfill analyses. Currently, about 1.5 Tg of methane is recovered from landfills and
combusted (USEPA 1993a). Most of this methane is recovered and used to produce
electricity. As described below, additional methane mitigation is possible under favorable
economic conditions and/or as the result of the proposed air pollution control rule for landfills.
4.4 PROFITABLE EMISSION REDUCTIONS FROM LANDFILLS
Methane emissions from landfills can be reduced at a profit under favorable electricity
pricing conditions. The extent to which methane recovery projects are profitable, and the
overall amount of methane mitigation that can be achieved at a profit, are very sensitive to the
price at which the electricity produced by the project can be sold. Relatively modest
increases in the price of electricity result in large increases in the number of projects that are
expected to be profitable.
First, the extent to which emissions can be reduced profitably is assessed for a range
of electricity prices. Then, the implications of energy projects for the costs of the proposed
landfill air pollution control rule are described. Finally, the sensitivity of the analyses to key
assumptions is evaluated.
4.4.1 Profitability for a Range of Electricity Prices
Three electricity rates were analyzed: $0.04, $0.05, and $0.06 per kWh. These rates
were multiplied by the amount of electricity produced to estimate the revenue earned by the
project. These rates can be considered as average rates that reflect the more complex utility
purchase agreements which often include seasonal rate differences and separate capacity
payments.
Utility purchase agreements generally are based on estimates of a utility's "avoided
costs" of generating electricity. The avoided cost for non-firm power (i.e., power that cannot
be reliably produced at any given time, such as during periods of peak demand), is low for
most utilities, in the range of $0.02 to $0.03 per kWh. These rates reflect only the utility's
variable costs of producing power. Power generation from landfill gas recovery projects are
expected to operate continuously (except for scheduled maintenance). Therefore, the
purchase price can also include a payment for capacity. Including the capacity factor can
increase the purchase price to about $0.04 per kWh.
4-35
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Methane emissions from lapdlitls can foe
/reduced at a profit under favorable
electricity prtyng conditions, Relatively
• modest increases in:1fte price d
etectric% result in terge increases in the
number $ profitable projects.
In addition to the revenue from the
sale of electricity, Federal tax credits are
also available. The Energy Policy Act of
1992 extends the Section 29 Production Tax
Credit through the year 2008. Section 29
provides an after-tax credit for producing
fuel from non-conventional sources,
including landfills. Although the value of the
credit depends on a number of factors,
including the domestic oil price and the
inflation rate, at current oil prices the credit is approximately equivalent to $0.01 per kWh of
the electricity sold.
Based on these factors, a value of $0.05 per kWh of electricity sold is appropriate for
assessing the profitability of landfill gas recovery projects. Because purchase agreements are
negotiated individually, terms will vary among projects. The range of $0.04 to $0.06 per kWh
is expected to encompass the majority of likely purchase rates and tax benefit situations for
landfill electricity generation projects.
Below an average rate of $0.04, few projects are profitable at a real discount rate of 8
percent.28 Above an average rate of $0.06, most of the large landfills considered in this
analysis can collect and utilize landfill gas profitably. Exhibit 4-9 summarizes the baseline
emissions, number of profitable landfill projects and the emissions that can be mitigated
profitably at the three prices for existing landfills. Exhibit 4-9 shows that at:
$0.06/kWh: in 2000 emissions from large landfills can be reduced by about
8.2 Tg. This represents an 80 percent decrease from what emissions would
have been from the large existing landfills in the absence of any landfill
recovery projects.29
• $0.05/kWh: in 2000 emissions from large landfills can be reduced by about
6.7 Tg. This represents a 65 percent decrease from what emissions would
have been from large existing landfills in the absence of any landfill recovery
projects.
$0.04/kWh: in 2000 emissions from large landfills can be reduced by about
1.5 Tg. This represents a 14 percent decrease from what emissions would
have been from large existing landfills in the absence of any landfill recovery
projects.
28
All the results in this sub-section are based on an 8 percent real discount rate. The sensitivity of the results
to lower and higher discount rates is presented below in Section 4.5.3.
29 The emissions in the absence of any recovery projects estimated are within about 10 percent of the
estimates in USEPA (1993a), after removing the adjustments for emissions from industrial landfills and emissions
avoided by existing landfill gas recovery projects included in USEPA (1993a). In 1990 the baseline emissions in
this analysis are about 6 percent lower than USEPA (I993a), and in 2000 and 2010 the estimates are about 10
percent higher due to a higher estimate of future total refuse implied by the landfill data used in this analysis.
4-36
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Currently, about 1.5 Tg of methane is recovered from landfills, preventing about 1.35 Tg of
emissions annually.30 These results indicate that at a price of $0.05/kWh or greater,
considerably more methane can be collected and used profitably than is currently the case.
As shown in the exhibit, baseline emissions from the small landfills are less than
1.0 Tg/yr throughout the period analyzed. Based on the assumptions used in this analysis,
landfill gas cannot be collected and used profitably at the small landfills. However, there are
several landfill gas recovery and utilization projects operated at small landfills (GAA 1991).
This implies that the assumptions used in this analysis may be conservative and that
profitable opportunities to recover and utilize methane at some small landfills are available.
Exhibit 4-10 presents similar estimates for simulated new landfills. By 2010, a total of
1,365 new landfills are simulated to open in place of the large existing landfills that close. As
with the existing landfills, emissions from the large landfills account for most of the emissions.
Also, emissions from the new landfills are smaller than the emissions from the existing landfills
during the period analyzed (through 2010). Gas recovery projects are profitable at up to 602
new landfills by 2010, mitigating up to 2.6 Tg of emissions per year by that year.
By 2010, a total of about 900 MW, 5,700 MW, and 7,000 MW of electricity generation
capacity is estimated to be installed at the three prices ($0.04/kWh, $0.05/kWh, and
$0.06/kWh, respectively). At $0.04/kWh, most profitable electricity generating projects would
be large and would have generating capacities between 4 and 5 MW. However, at
$0.06/kWh, profitable electricity generating projects could be much smaller and could range
between 0.5 and 5 MW. Exhibit 4-11 shows the distribution of electrical generating capacity
for the three electricity prices in the year 2000. The revenues minus the costs of the projects,
adjusted for taxes and discounted to 1990 at an 8 percent real rate, equal $0.1 billion, $1.6
billion, and $4.7 billion for the three electricity prices.
4.4.2 The Proposed Landfill Air Pollution Control Rule
By requiring that landfill gas be collected and combusted at many landfills, the
proposed landfill air pollution control rule will reduce methane emissions. The costs of the
rule will depend on the number of landfills affected and the attractiveness of producing and
selling electricity. For example, if all the landfills that must comply with the rule would have
found it profitable to collect the gas and produce electricity in any case, then the rule itself
imposes no additional costs.
The impact of energy production opportunities on the costs of the rule was analyzed
for the three electricity prices assuming that the rule would require all large landfills to collect
and combust gas. At $0.06/kWh, an estimated 1,368 landfills would find it profitable to
produce electricity right away. Of these, 984 would have started producing electricity
immediately in any case, and the remainder would have started by 2000. An additional 574
landfills (over and above the 1,368) would find it less costly to produce electricity than to
collect and flare the gas. For these landfills, the costs are reduced by nearly 60 percent from
the costs of collect and flare only. These 1,942 landfills would have 5,500 MW of electricity
producing capacity. Finally, 92 landfills would find it least costly to collect and flare only.
30 The emissions prevented equal about 90 percent of the methane recovered because about 10 percent of the
recovered methane would have been oxidized prior to being emitted from the landfill.
4-38
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and existing landfills in the year 2000.
4-40
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At $0.05/kWh, fewer landfills (about 661) find it profitable to produce electricity
immediately. However, for 1,127 landfills, it is 55 percent less costly to produce electricity
than to collect and flare only. These 1,788 landfills would have 5,100 MW of electricity
producing capacity. At $0.04/kWh, an estimated 54 landfills find it profitable to produce
electricity immediately. However, for 1,064 landfills, it is 45 percent less costly to produce
electricity than to collect and flare only. These 1,118 landfills would have 3,700 MW of
electricity producing capacity. These results are summarized in Exhibit 4-12. As shown in the
exhibit, this analysis indicates that considering the opportunities to produce electricity
substantially reduces the cost of requiring collection and flare systems at the electricity prices
examined. If the rule were to affect 1,000 or fewer landfills, gas recovery opportunities would
reduce the costs of the rule by about half for the affected landfills.
4.4.3 Sensitivity Analysis
The estimates are sensitive to a variety of factors and assumptions used in the
analysis. Several key factors analyzed are as follows.
The
influence on the assessment of
Discount Rate. The discount rate
used to estimate the NPVs for the projects
has a strong influence on the assessment of
profitability. When using a higher discount
rate, the projects must have higher returns
in order to be considered profitable. If a
lower discount rate is used, projects may be
considered profitable at lower rates of
return. Two discount rate sensitivities were performed, 6 percent and 10 percent. Assuming
an average inflation rate of 4 percent over the period of analysis, these discount rate
sensitivities are equivalent to requiring profitable projects to have an internal rate of return
(IRR) greater than 10 or 14 percent, respectively.
As expected, with a 10 percent discount rate fewer projects are profitable. For
example, at $0.04/kWh, no projects are profitable at existing landfills by 2010, as opposed to
65 at an 8 percent discount rate. At the 6 percent discount rate the number of projects
increases. At $0.04/kWh the number of profitable projects increases to over 200 at existing
landfills by 2010, and the emissions mitigated increases to 41 percent for 2010. At the $0.05
and $0.06 prices, the estimates of emissions mitigated are not overly sensitive to the discount
rate used: the estimates differ by about 1.5 Tg or less. Similar results are seen for new
landfills. Exhibits 4-13 and 4-14 summarize these sensitivity analysis results.
Other Sensitivities. The sensitivity of the results to a variety of other factors was
explored using the $0.05/kWh price as a reference case. The estimates of the number of
profitable projects and the methane emissions mitigation in the year 2000 are used to assess
the sensitivities.
High Engine Generator Capital Costs. Increasing the capital costs for engine
generators by 20 percent to $1,440 per kW reduces the number of profitable
projects by 35 percent, and reduces the emissions mitigated by 19 percent.
Overall, baseline emissions are reduced by 47 percent.
Low Engine Generator Capital Costs. Reducing the capital costs for engine
generators by 20 percent to $960 per kW increases the number of profitable
4-41
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projects by 40 percent, and increases the emissions mitigated by 14 percent.
Overall, baseline emissions are reduced by 66 percent.
• High Engine Generator O&M. Increasing the O&M costs for engine generators
by 33 percent to $0.02 per kWh reduces the number of profitable projects by
49 percent, and reduces the emissions mitigated by 30 percent. Overall,
baseline emissions are reduced by 40 percent.
No Tax Effects. Removing the consideration of taxes on the profits generated
from the discounted cash flow analysis increases the number of profitable
projects by 45 percent, and increases the emissions mitigated by 15 percent.
Overall, baseline emissions are reduced by 67 percent.
• Low Collection Efficiency. Reducing the collection efficiency from 85 percent to
75 percent reduces the number of profitable projects by 9 percent, and
reduces the emissions mitigated by 16 percent. Overall, baseline emissions
are reduced by 49 percent.
High Methane Flow Rate. Increasing the methane flow rate from landfills by 20
percent increases the number of profitable projects by 21 percent, and
increases the emissions mitigated by 27 percent. Overall, baseline emissions
are reduced by 61 percent.
Low Methane Flow Rate. Reducing the methane flow rate from landfills by 20
percent reduces the number of profitable projects by 19 percent, and reduces
the emissions mitigated by 26 percent. Overall, baseline emissions are
reduced by 53 percent.
High Siting and Permitting Cost. Including a siting and permitting cost of
$100,000 incurred at the start of the project reduces the number of profitable
projects in 2000 by 4 percent and reduces methane mitigation by 1 percent.
Overall, baseline emissions are reduced by 43 percent.
• Very High Siting and Permitting Cost. Including a siting and permitting cost of
$500,000 incurred at the start of the project reduces the number of profitable
projects in 2000 by 27 percent and reduces methane mitigation by 10 percent.
Overall, baseline emissions are reduced by 48 percent.
The results for these sensitivities are summarized in Exhibit 4-15.
Uncertainly. The combined impact of the uncertainty in the various factors affecting
the profitability of landfill gas recovery was evaluated by performing the analysis with a
stochastic model. The following uncertainty ranges were simulated independently:
Engine generator costs: A normal distribution was simulated using a standard
deviation of 10 percent of the mean estimate of $1,200 per kW.
Engine generator O&M: A normal distribution was simulated using a standard
deviation of 15 percent of the mean estimate of $0.015 per kWh.
4-45
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Exhibit 4-15
Sensitivity Analysis Results
Number of Methane Mitigation
Case Profitable Projects in 2000
in 2000 (Tg/yr)
Reference Case8 763 6.69
High Engine Generator Capital Costs5 496 (65%)k 5.39 (81%)
Low Engine Generator Capital Costs6 1,067(140%) 7.61(114%)
High Engine Generator O&M Costsd 387 (51%) 4.66 (70%)
No Tax Effects6 1 , 1 06 (1 45%) 7.68 (1 1 5%)
Low Collection Efficiency* 691 (91%) 5.61 (84%)
High Methane Flow Rate^ 921 (121%) 8.47 (127%)
Low Methane Flow Rateh 620 (81%) 4.93 (74%)
High Siting and Permitting Cost' 729 (96%) 6.60 (99%)
Very High Siting and Permitting Costj 555 (73%) 6.02 (90%)
Methane Emissions
in 2000
(percent of baseline)'
42%
53%
34%
60%
34%
51%
39%
47%
43%
48%
a Assumptions for all cases, unless otherwise noted, include: 8 percent real discount rate; $0.015/kWh for
engine generator O&M; 40 percent marginal tax rate; 85% collection efficiency; electricity price of $0.05/kWh.
Estimates for large landfills only, see text. Estimates include both existing landfills and new landfills simulated
to open in the future.
b Engine generator capital costs increased by 20 percent to $1 ,440 per kW.
c Engine generator capital costs decreased by 20 percent to $960 per kW.
d Engine generator O&M costs increased by 33 percent to $0.02 per kWh.
e Tax effects eliminated by setting the marginal tax rate to 0%.
f Collection efficiency reduced to 75%.
g Methane flow rate increased by 20 percent.
h Methane flow rate reduced by 20 percent.
i Siting and permitting cost of $100,000.
j Siting and permitting cost of $500,000.
k Percent of Reference Case estimate.
I Baseline emissions in 2000 for the high methane flow rate case are 13.9 Tg and for the low methane flow rale
case are 9.2 Tg. Baseline emissions in 2000 for all other cases are 1 1 .6 Tg.
Methane Flow Rate: The uncertainty in the methane flow rate was estimated
using the parameter uncertainty quantified during the process of statistical
estimation of the methane flow rate (see USEPA 1993a). The uncertainty range
varies depending on the flow rate estimate, with the largest uncertainties
associated with the highest and lowest values.
• Collection System Costs: For collection system capital costs a normal
distribution was simulated using a standard deviation of 10 percent of the
mean cost estimate. For collection system O&M a normal distribution was
simulated using a standard deviation of 15 percent of the mean O&M cost
estimate.
• Collection Efficiency: A uniform distribution of 80 to 90 percent was simulated.
The results of this combined assessment of uncertainty indicates that the uncertainty is much
greater at lower electricity prices than at higher electricity prices and that the uncertainty is
asymmetric about the central estimate. The 95 percent confidence intervals for the simulated
values (based on 100 iterations of each case) are as follows.
4-46
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At an electricity price of $0.05/kWh, the estimated methane mitigated is as
follows:
2000: 5.0 Tg to 7.4 Tg, compared to the central estimate of 6.7 Tg.
2010: 6.7 Tg to 8.8 Tg, compared to the central estimate of 8.1 Tg.
At an electricity price of $0.04/kWh, the estimated methane mitigated is as
follows:
2000: 0.3 Tg to 4.1 Tg compared to the central estimate of 1.5 Tg.
2010: 0.3 Tg to 5.0 Tg compared to the central estimate of 1.5 Tg.
• At an electricity price of $0.06/kWh, the estimated methane mitigated is as
follows:
2000: 7.5 to 8.5 Tg compared to the central estimate of 8.2 Tg.
2010: 9.1 to 10.0 Tg compared to the central estimate of 9.8 Tg.
At the $0.04 electricity price, the results are very sensitive to the uncertainty in the parameters
that were simulated. For purposes of this analysis, a minimum mitigation of 1.35 Tg is used
for the $0.04/kWh case to be consistent with the baseline emissions estimate reported in
USEPA (1993a).31 The uncertainty analysis shows that, overall, the results are more
sensitive to the electricity price than they are to the uncertainties in the parameter values.
4.4.4 Impact of Including Environmental Benefits
From the perspective of social benefits, the value of landfill gas recovery projects is
underestimated because the revenue estimates from selling electricity do not include the
value of the environmental benefits of recovering methane from landfills. These environmental
benefits include not only the reduction in methane emissions, but also reductions in air
pollution from landfills (including non-methane organic compound (NMOC) emissions), better
landfill gas migration control, and a reduction in carbon dioxide (CO2) and other emissions
from displacing fossil fuel produced electricity. By omitting these benefits, profitability
decisions made by individuals do not reflect the full social value of the project.
For example, the cost of reducing carbon dioxide (CO2) build up in the atmosphere
has been estimated in the range of $5 to $20 per ton of carbon contained in C(X>. With this
range, the environmental benefit of reducing methane emissions to the atmosphere from
landfills translates into a value of about $0.0069 to $0.0276 per kWh.32 In addition,
31 USEPA (1993a) assumes landfill gas recovery of 1.5 Tg per year through 2010 as part of the baseline
emissions estimate. This recovery rate implies an emissions mitigation of 1.35 Tg (10 percent of the recovered
methane (0.15 Tg) would have been oxidized prior to being emitted). The uncertainty analysis indicates that the
baseline level of future recovery assumed in USEPA (1993a) may not be profitable if a $0.04/kWh electricity rate
prevails and unfavorable combinations of other model parameters occur.
QO
If the benefit of reducing carbon dioxide emissions is $5 per metric ton of carbon contained in CO- and a
mass-based global warming potential (GWP) for CH4 of 22 is assumed, then the value of recovering landfill gas
can be computed as follows:
4-47
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assuming that producing electricity at landfills displaces fossil fuel produced CO2 at the rate
of 1.5 Ib per kWh,33 an additional benefit of $0.009/kWh to $0.037/kWh can be realized 34
Combining these two benefits, the total value of recovering methane from landfills ranges
between $0.0078/kWh and $0.0313/kWh. This value may be as high as $0.1566/kWh if the
benefit of reducing carbon dioxide emissions is as high as $100 per ton of carbon contained
in CO2.
These values take into account the global warming impact of methane but do not
include the benefits associated with improving local air quality and improving landfill gas
migration control. Nevertheless, the estimates of profitable emissions reductions are very
sensitive to emissions reduction values of this magnitude. Even the low values of this range,
e.g., $0.0078 to $0.0313 per kWh, would have a significant impact on the profitability of landfill
gas recovery projects. If the value of avoiding methane emissions is in this range, landfill gas
recovery should be promoted at all large landfills.
4.5 BARRIERS
As discussed above, under favorable pricing conditions profitable opportunities exist
for reducing methane emissions from landfills. Proven technologies are available to recover
and utilize the methane to produce electricity. About 100 landfills across the country are
successfully utilizing these technologies today.
While there are many landfills at which methane recovery is apparently viable, methane
recovery and utilization projects are often not implemented because of various barriers.
Economic and regulatory barriers are common to virtually all "alternative" energy sources
(e.g., cogeneration, biomass, solar, and wind) and are discussed more fully in Chapter 7. In
particular, issues involving electricity pricing and sales agreements with utilities are important
barriers for landfill projects. As discussed above, profitability is very sensitive to the price at
which electricity can be sold.
$5 . 12mtC .22 WtCOg 19.16 g / ft* CH4 12.000 BTU/kWh -$ooo690/kWh
1mtC 44mtC02 mtCH4 10»g/mt 1,000 BTU/tt3 CH4
Similar computations yield $0.0276/kWh for $20/ton carbon and $0.1380/kWh for $100/ton carbon.
33 The CO2 emission factor of 1.5 Ib COg/kWh is based on values used by the USEPA Green Lights Program
to estimate pollution prevention (USEPA 1993b). The factor is calculated by dividing total COg emissions from all
electrical power generation in the U.S. (including independent power producers) -- 3.952-10 Ibs C02 -- by total
electricity sales of 2,582-109 kWh (USDOE 1992). The factor therefore represents a national average emission
factor for generating electricity from all fuel sources (e.g., coal, oil, hydroelectric, nuclear) and does not necessarily
reflect the marginal reduction in CO2 emissions associated with generating one fewer kiloWatt hour of electrical
power. Using the factor of 1,5lb COg/kWh likely underestimates the actual fossil fuel C02 emissions reduction
because the landfill generated power likely will offset power that would be generated by CO2 producing fossil fuels
such as coal or oil and likely would not offset hydroelectric or nuclear power that would produce no fossil fuel CO2.
34 If the benefit of reducing carbon dioxide emissions is $5 per metric ton of carbon contained in CO2 and
assuming that landfill produced electricity displaces fossil fuel produced CO2 at the rate of 1.5 Ib per kWh, then the
value of reducing net CO2 emissions by generating electricity with landfill gas can be computed as follows:
1-5lbc°2 . 1 kg . 1 mt . 12mtC $5 . tonog,,<«/>.
1 kWh 2.2046 to 1,000kg 44 mt CO2 1 mt C *"'w '
Similar computations yield $0.0037/kWh for $20/ton carbon and $0.0186/kWh for $100/ton carbon.
4-48
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There are, however, additional barriers specific to landfills that need to be addressed.
These include the following:
Perception of High Risk. Most "alternative" energy production technologies tend to be
viewed as unproven or risky. As a result, such projects must earn high returns in order to
attract financing. The dissemination of information on the 100 existing projects could help
reduce the perceived technological risk of these ventures.
Lack of Information. An estimated 86 percent of municipal solid waste landfills are
owned by municipalities or other local governmental bodies (USEPA 1988) whose primary
responsibility is to collect and dispose of municipal solid waste. These landfill owners and
operators may not be completely aware of the opportunities for profitably recovering landfill
gas. In addition, because most municipalities or waste disposal companies may only own a
few landfills, it is difficult for an individual municipality or company to develop the expertise
and experience necessary to successfully design and operate a landfill energy recovery
project. This barrier can be overcome by developing an out-reach program to provide
information and technical assistance to the landfill owners and operators so that they can
evaluate the feasibility of landfill gas recovery from their landfills.
Siting and Permitting. Landfill gas recovery projects must comply with local, state, and
federal regulatory and permitting requirements. The majority of these requirements address
environmental, safety, and zoning concerns. The costs of complying with these rules can be
substantial, and are not considered in the financial analysis presented above.
Key requirements that must be addressed include air and water emissions. In some
areas, the siting of new combustion sources is difficult due to requirements to reduce
emissions of NOX or other combustion products in non-attainment areas. The availability of
low-emissions engine technology helps to overcome this barrier, although at a cost. When
they become more widely available, fuel cells may also help to overcome this barrier.
Water emission issues center around leachate control. Landfills are currently required
to monitor groundwater quality and prevent off-site migration of contaminants in the
groundwater. In the process of collecting landfill gas, leachate will condense in the collection
system. This leachate can exhibit hazardous characteristics and must be handled and
disposed properly, within the context of the landfill's leachate control program.
Liability. Liability concerns have increased the difficulty of obtaining financing for
landfill gas recovery projects because lenders are concerned about the costs of cleaning up
landfills under CERCLA. 5 Under CERCLA, an entity that owned or operated a landfill or
placed waste at the landfill (as a waste generator or waste hauler) may become a potentially
responsible party for the landfill. Potentially responsible parties are strictly and severally liable
for the costs of investigating and remediating hazardous waste sites. This means that a
single responsible party can be held responsible for the entire cost of cleaning up a site.
This potential liability can arise at a municipal waste landfill if the landfill accepted hazardous
waste in the past or if the landfill exhibits hazardous characteristics.
35
Comprehensive Environmental Response, Compensation, and Liability Act (42 United States Code Section
9607).
4-49
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Given the potential liability involved, an outside lender may be hesitant to finance a
project that involves a landfill. If the landfill turns out to have a hazardous waste problem, the
landfill gas recovery project owner and/or operator could become a potentially responsible
party. As a result of the cost of cleaning up the landfill, the landfill gas recovery project may
no longer be profitable and the loan may not be repaid. In this instance, the lending
institution would not want to seize the assets of the project because the assets may include
liability for cleaning up the landfill.
Technology Development. Several emerging technologies -- including fuel cells and
processes that could convert gas into diesel, naphtha, and high grade industrial waxes -
could provide additional options for utilizing landfill gas. For example, fuel cells are efficient
and have low by-product emissions, limited noise production, and minimal labor
requirements. However, additional research and demonstrations are necessary in order to
show that fuel cells can be economically used with landfill gas. The high cost of research
has hindered the development of this promising technology.
Options are available for overcoming these barriers. In particular, the perception of
high risk for the technology can be overcome by disseminating information on the reliability of
the existing landfill gas recovery projects, Both landfill gas extraction and engine technology
have improved to increase the reliability of these systems. Some of the permitting and siting
concerns can be addressed by providing information on the standard techniques for
mitigating water and air releases. To address the liability issue, a method is needed for
structuring the financing of the projects in a way that insulates the lender from potential
CERCLA liability. Insurance or other related options should be investigated. Alternatively,
legislative relief may be needed. Exhibit 4-16 summarizes these barriers and potential
solutions for overcoming them.
4.6 LIMITATIONS
This analysis is limited by a variety of factors. Most importantly, there are a variety of
site-specific factors that influence the cost and feasibility of recovering methane from landfills
and producing electricity. While this analysis uses representative cost estimates, some
landfills will find that projects will be more or less costly than the estimates used here. The
implications of the diversity of site-specific situations are not considered.
The prediction equations for gas flow rates and gas recovery as a function of waste in
place produce "average" estimates and are themselves uncertain (USEPA 1992a). Actual
methane production and recovery rates vary substantially across landfills. Unfortunately, the
characterization of landfills is not adequate to consider the variability of gas flow rates.
Finally, this analysis does not consider several of the institutional and physical barriers
that prevent the implementation of landfill gas recovery projects. Barriers to successful
implementation include low utility buy-back rates, inadequate financing, and inadequate
information on proper system designs and operating practices.
4-50
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Exhibit 4-16
Barriers Limiting Implementation of Landfill Methane Recovery Projects
Possible
Barrier Solution Governmental Actions
Perception of High Risk
Alternative energy production technologies are
often considered "high risk."
Disseminate
information on 100
existing projects.
Outreach program to
provide information on
successful projects.
Lack of Information on Profitable
Opportunities
Many landfills are owned by municipalities
whose primary concern is to collect and dispose
of municipal waste. These municipalities may be
unaware of opportunities for profitable landfill
gas recovery.
Outreach program to
educate and provide
technical assistance
to the owners of
prospective projects.
Outreach program to
provide technical
information and
assistance.
Low Utility Buy Back Rates
Landfill gas recovery projects receive low
"avoided cost" prices for the electric power they
sell back to electric utilities.
Encourage Public
Utility Commissions
(PUCs) to allow higher
buy back rates for
environmentally
beneficial projects.
Siting and Permitting
Landfill gas recovery projects must comply with
regulatory requirements. The cost of complying
with these requirements may make gas recovery
uneconomical.
Develop low
emissions engine
technologies and fuel
cells.
Permit waivers.
Government/private
research program.
Special permitting
program for environ-
mentally beneficial
projects.
Liability
Under CERCLA3, landfill gas system investors
and lending institutions could be held liable for
the costs of investigating and remediating any
hazardous waste found in the landfills.
Develop method to
insulate investors
and lenders from
potential CERCLA
liability.
Congressional action
may be necessary to
reduce the potential
CERCLA liability issue.
High Cost of New Technology Development
The high cost of research and development has
hindered the development of promising landfill
gas utilization technologies such as fuel cells.
Fund government
and/or private
research programs
a Comprehensive Environmental Response, Compensation, and Liability Act (42 United States Code Section 9607).
4-51
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4.7 REFERENCES
Anderson, Charles, E. 1993. Letter to Cindy Jacobs, USEPA. July 23, 1993.
Biocycle 1992a. "1992 Nationwide Survey: The State of Garbage in America." April 1992.
Biocycle 1992b. "Solid Waste Legislation: The State of Garbage in America." May 1992.
GAA (Governmental Advisory Associates, Inc.) 1991. 1991-92 Methane Recovery From Landfill
Yearbook, Governmental Advisory Associates, Inc., New York, 1991.
Huitric, Ray. 1993. Letter to Cindy Jacobs, USEPA. September 3, 1993.
Loehr, B.C. 1984. Pollution Control for Agriculture. Second Edition. Academic Press, Inc.
Orlando, Florida. 1984.
Maxwell, G. 1990. "Will Gas-To-Energy Work at Your Landfill?" in So//of Waste and Power,
September 17, 1990.
Pacey, John G. 1993. Letter to Cindy Jacobs, USEPA. July 23, 1993.
Resource Management International, Inc. 1992. "Survey of Landfill Gas Generation Potential 2-
MW Molten Carbonate Fuel Cell," Interim Report, TR-101068 Research Project 1677-21,
Prepared for Electric Power Research Institute, September 1992.
Thorneloe, Susan A. 1992a. "Landfill Gas Recovery/Utilization - Options and Economics,"
prepared by the Global Emissions and Control Division, Air and Energy Engineering
Research Laboratory, US EPA, Research Triangle Park, NC 27711, March 5, 1992.
Thorneloe, Susan A. 1992b. "Landfill Gas Utilization - Options, Benefits, and Barriers."
Presented at The Second United States Conference on Municipal Solid Waste
Management. June 3-5, 1992.
USDOE (United States Department of Energy) 1992. Electric Power Annual 1990. January
1992.
USEPA (United States Environmental Protection Agency) 1987. National Survey of Solid Waste
Municipal Landfills. Database supplied by DPRA, Inc. September 1987.
USEPA (United States Environmental Protection Agency) 1988. National Survey of Solid Waste
(Municipal) Landfill Facilities. Washington D.C. September 1988.
USEPA (United States Environmental Protection Agency) 1991 a. "Standards of Performance
for New Stationary Sources and Guidelines for Control of Existing Sources: Municipal
Solid Waste Landfills," Federal Register, Vol 56, No. 104 May 30, 1991, pp. 24467-
24528.
USEPA (United States Environmental Protection Agency) 1991b. EPA Docket Number A-88-09
Document Number ll-B-45, Memorandum from Kathleen Hogan, Chief, Methane
Programs, to Alice Chow, Office of Air Quality Planning and Standards, "Analysis of
Profits and Cost from Regulating Municipal Solid Waste Landfills," March 28, 1991.
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USEPA (United States Environmental Protection Agency) 1991 c. "Air Emissions from
Municipal Solid Waste Landfills - Background Information for Proposed Standards and
Guidelines," prepared by the Emissions Standards Division, Office of Air Quality
Planning and Standards, US EPA, Research Triangle Park, NC 27711,
EPA-450/3-90-011.
USEPA (United States Environmental Protection Agency) 1992a. "Characterization of
Municipal Solid Waste in the United States: 1992 Update." EPA Office of Solid Waste
and Emergency Response, Washington, D.C. EPA/530-R-019, July 1992.
USEPA (United States Environmental Protection Agency) 1992b. "Development of an Empirical
Model of Methane Emissions from Landfills." Air and Energy Engineering Research
Laboratory, Research Triangle Park, NC EPA 600/R-92-037, March 1992.
USEPA (United States Environmental Protection Agency) 1992c. "Landfill Gas Energy
Utilization: Technology Options and Case Studies," prepared by the Air and Energy
Engineering Research Laboratory, US EPA, Research Triangle Park, NC 27711, EPA-
600/R-92-116, June 1992.
USEPA (United States Environmental Protection Agency) 1993a. "Anthropogenic Methane
Emissions in the United States - Report to Congress," prepared by Global Change
Division, Office of Air and Radiation, US EPA, Washington, DC.
USEPA (United States Environmental Protection Agency) 1993b. "Green Lights Update." Air
and Radiation 6202J, US EPA, Washington, D.C. July 1993.
Williams, R.A. and E. Larson. 1989. "Expanding Roles for Gas Turbines in Power
Generation," in Electricity: Efficient End-Use and New Generation Technologies, and
Their Planning Implications. Lund University Press, Sweden.
4-53
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CHAPTER 5
OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM LIVESTOCK
Livestock Methane Emissions Reductions
Share of U.S
Emissions Reductions
ID
S -•
n 6
& . 9
^ Pr-o-F I tab I e
J Reduct Ions
Rema i n i ng
Em i ssIons
Low High
-I99O
Low High
20OQ
Low High
2O1O
Methane Emissions from U.S. Livestock (Tg)
Year
1990
2000
2010
Baseline
Low
4.6
5.0
4.8
Emissions3
High
6.9
7.9
8.2
a Emissions estimate from USEPA (1993). The emissions scenarios
future domestic consumption and export of animal products.
Emissions with Profitable
Reductions
Low High
3.9-4.4 6.2-6.9
3.6-4.0 6.3-7.0
reflect a range of assumptions regarding
CHAPTER SUMMARY
Technically feasible and cost-effective strategies
exist to reduce methane emissions per unit of
milk and meat produced in the U.S. By reducing
emissions per unit of product produced, overall
national emissions from livestock will be reduced
from levels that would otherwise occur. Total
national emissions could decline from current
levels because emissions reductions per unit
product may exceed increases in future pro-
duction.
Specific results are as follows:
In 2000, methane emissions can be reduced by
about 12 to 22 percent, or about 0.6 to 1.7 Tg
from rates that would otherwise occur. Relative
to 1990, emissions can be reduced by 0.2 to
0.7 Tg and 0.0 to 0.7 Tg in the low and high
emissions scenarios respectively.
In 2010, methane emissions can be reduced by
about 15 to 25 percent, or about 0.8 to 1.9 Tg
from rates that would otherwise occur. Relative
to 1990, emissions can be reduced by 0.6 to
5-1
-------
Chapter Summary
1.0 Tg and -0.1 to 0.6 Tg in the low and high
emissions scenarios respectively.
These estimates are sensitive to the effectiveness
of the emissions reduction techniques, the extent
to which they are adopted, and the growth in
production. Relative to 1990 emissions rates,
emissions can be reduced most if production
does not grow substantially, and if the emissions
reduction techniques are widely adopted and
effective.
Baseline Emissions
Methane emissions from domesticated livestock
in the U.S. in 1990 are estimated at 4.6 to 6.9 Tg,
with a central estimate of 5.8 Tg. Dairy and beef
cattle account for 95 percent of these emissions.
A foundation of scientific measurements and
understanding of methane formation and emis-
sion supports these estimates. The principal
uncertainties in the estimates of current emissions
are associated with the large diversity of animal
management practices found in the U.S., all of
which cannot be characterized and evaluated
precisely. The uncertainty estimate is subjective,
based on the sensitivity of the results to various
assumptions.
Improving livestock productivity sothat
product &#n? most promising and cost
effective technique lor reducing emis-
sions In Hie U.S, Opportunities for
productivity improvement axJat for $8
sectors of the UJ& cattle indjastry.
Emissions are estimated to increase to a range of
5.0 to 7.9 Tg/yr by 2000 and 4.8 to 8.2 Tg/yr by
2010. The high estimates in these ranges as-
sume substantial increases in milk production for
export and a small increase in beef production
associated with beef maintaining its domestic
market share of red meat consumption. The low
estimates assume that beef production declines
by 2010 and that dairy production increases at
the rate of domestic consumption only. These
emissions estimates include an uncertainty of
about ±20 percent, based on the uncertainty of
the factors that form the basis of the 1990 emis-
sions estimate.
Emissions Reductions
Improving livestock productivity so that less
methane is emitted per unit of product is the
most promising and cost effective technique for
reducing emissions in the U.S. While U.S. live-
stock production is among the most productive in
the world, opportunities for improvement exist for
all sectors of the cattle industry that can reduce
methane emissions substantially. In many cases
these options can be profitable because they
reduce costs per unit of product produced.
However, no single set of practices can define
what is best economically for the large diversity of
livestock producers in the U.S. Exhibit 5-1 sum-
marizes the emissions reductions that are esti-
mated over time for the major industry segments:
dairy and beef cattle. As shown in the exhibit,
emissions can be reduced by about 0.6 to 1.9 Tg
from expected future levels, or about 12 to 25
percent. Relative to 1990 emissions, future
emissions may be reduced by up to 1.0 Tg.
Specific strategies for reducing methane emis-
sions per unit product have been identified and
evaluated for each sector of the beef and dairy
cattle industry. Throughout the industry, proper
veterinary care, sanitation, ventilation (for en-
closed animals), nutrition, and animal comfort
provide the foundation for improving livestock
productivity. For many producers, focusing on
these basics provides the best opportunity for
improving productivity. Within this context, a
variety of techniques can help improve animal
productivity and reduce methane emissions per
unit of product.
Dairy industry. Significant improvements in milk
production per cow are anticipated in the dairy
industry as the result of continued improvements
in management and genetics. Additionally,
production-enhancing technologies, such as bST,
are ready for deployment that accelerate the rate
of productivity improvement. By increasing milk
production per cow, methane emissions per unit
of milk produced declines.
Dairy industry emissions can also be reduced by
refinements in the milk pricing system. By elimi-
nating reliance on fat as the method of pricing
milk, and moving toward a more balanced pricing
system that includes the protein or other non-fat
solids components of rnilk, methane emissions
can be reduced as the result of changes in dairy
5-2
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Chapter Summary
Exhibit 5-1
Methane Emissions from U.S. Livestock and Profitable Emissions Reductions
Year
Industry Segment
1990
Dairy Industry
Beef Industry
Other"
Total0
2000
Dairy Industry
Beef Industry
Other
Total
2010
Dairy Industry
Beef Industry
Other
Total
Baseline Emissions8
(Tg)
Low
1.2
3.2
0.2
4.6
1.4
3.4
0.2
5.0
1.4
3.1
0.2
4.8
High
1.8
4.8
0.4
6.9
2.0
5.5
0.4
7.9
2.4
5.4
0.4
8.2
Profitable Emissions
Reductions (Tg)
Low
-
0.2-0.3
0.4-0.8
0.0d
0.6-1.1
0.3-0.4
0.4-0.7
0.0
0.8-1.2
High
-
0.3-0.5
0.7-1.2
0.0
1 .0-1 .7
0.5-0.7
0.7-1.2
0.0
1.2-1.9
Profitable Emissions
Reductions (%)
Low
-
14-21%
12-24%
0%
12-22%
21-30%
13-23%
0%
17-25%
High
-
15-25%
13-22%
0%
13-22%
21-30%
13-22%
0%
15-23%
a Baseline emissions estimate from USEPA (1993).
b Other includes goats, sheep, pigs and horses.
o Totals may not add due to rounding.
d Options for reducing emissions were not examined for other livestock.
cow rations and genetics. There is already a
trend to reduce reliance on fat in the pricing of
milk. To realize methane emissions reductions
from this trend, the effectiveness of alternative
ration formulations on protein synthesis must be
better characterized.
Beef Industry. The main options for reducing
methane emissions from the beef industry are the
refinements to the marketing system and im-
proved cow-calf sector performance. The refine-
ments to the marketing system are needed to
promote efficiency (which will reduce methane
emissions by eliminating unnecessary feeding)
and shift production toward less methane emis-
sions intensive methods. To be successful, the
refinements to the marketing system require that
the information flow within the beef industry be
improved substantially. Techniques are required
to relate beef quality to objective carcass charac-
teristics. Additionally, the carcass data must be
collected and used as a basis for purchasing
cattle so that proper price incentives are given to
improve cattle quality and reduce unnecessary fat
accretion.
The beef industry has several programs under
way to achieve these objectives. Carcass data
collection programs have been initiated that
provide detailed data on carcass quality to partici-
pating producers. Also, a major initiative is
ongoing to educate retailers regarding the cost-
effectiveness of purchasing more closely trimmed
beef (less trimmable fat). As these programs
become more widely adopted, the information
needed to provide the necessary price incentives
to producers will become available.
Improving productivity within the cow-calf sector
requires additional education and training. The
importance and value of better nutritional man-
agement and supplementation must be communi-
cated. Byers (1992a) recommends that energy,
protein, and mineral supplementation programs
tailored for specific regions and conditions be
developed to improve the implementation of
these techniques. The special needs of small
producers must also be identified and addressed.
Exhibit 5-2 summarizes the major techniques for
reducing methane emissions for the beef and
5-3
-------
Chapter Summary
Exhibit 5-2
Summary of Livestock Methane Emissions Reduction Options
Option
Description
Dairy &Kh«try V
Improve Dairy Cow
Productivity
Refine milk pricing system
Continue the trend in productivity improvement through better
management and genetics
Once approved, use bST to improve production per cow
Reduce emphasis on fat synthesis, allowing rations to be
adjusted in a manner that reduces methane emissions
Beef industry . ..-.!,,. ."' ;
Improve beef production
productivity
Refine beef marketing
system
Improve cow-calf sector reproductive performance through
better nutritional management
Improve cow-calf sector feed efficiency by using ionophores
Improve growth rate and feed efficiency by expanding the use
of growth-promoting implants where appropriate
Provide information so that market incentives lead to a
reduction in the accretion of excess trimmable fat
Provide information so that market incentives lead to an
increase in the portion of calves that move directly from cow-
calf producers into feedlots
% of Total
Reductions
! 33%
10-15%
3-7%
10-20
66%
20-30%
5-15%
<1%
4-6%
20-30%
dairy industries. About one-third of the emissions
reduction per unit product are estimated to be
from the dairy industry, while two-thirds are from
the beef industry. Within the dairy industry,
refining the milk pricing system and continuing
the trend in improvement in cow productivity are
the main sources of the emissions reductions.
Within the beef industry, improving cow-calf
reproductive performance and refining the beef
marketing system to increase the portion of
calves that move directly from cow-calf producers
into feedlots are the two main sources of emis-
sions reductions. These four options account for
about 65 to 85 percent of the total emissions
reductions estimated.
Limitations and Uncertainties
The emissions reduction estimates presented in
this analysis are based on the best information
currently available. The analysis is limited by the
lack of quantitative information needed to link
more closely the changes in the beef and dairy
marketing and pricing systems to the changes in
production practices. Because the changes in
production practices can lead to significant
reductions in methane emissions per unit of
product produced, better data and more com-
plete analysis are needed. The extent to which
these practices will be adopted is uncertain,
making the overall emissions estimates uncertain.
The estimates also do not consider the impact
that changing production practices could have on
demand. For example, improvements in beef
production could lead to increased demand and
increased production, which would offset partially
or completely the reductions achieved in emis-
sions per unit product. Such interactions among
production practices, emissions, and demand are
not considered.
5-4
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5.1 BACKGROUND
In 1990 the U.S. livestock industry marketed about $90 billion worth of meat, milk, and
fiber (Hoffman 1991). As a by-product of this production, livestock emitted about 4.6 to
6.9 Tg of methane in 1990. Methane is produced as part of the normal digestive processes
of animals. Referred to as "enteric fermentation," emissions from these processes account for
a significant portion of the global methane budget, about 65 to 100 Tg annually (IPCC 1992).
Of domesticated animals, ruminant animals (cattle, buffalo, sheep, goats and camels) are the
major source of methane emissions.
Cattle are the primary source of methane emissions from enteric fermentation in the
U.S.: dairy and beef cattle account for about 27 percent and 68 percent of U.S. emissions
respectively. For this reason, only options for reducing emissions from cattle are considered
in this chapter.
5.1.1 Livestock Methane Emissions
Ruminant animals are characterized by a large "fore-stomach" or rumen. Within the
rumen, microbial fermentation breaks down the feed consumed into products such as volatile
fatty acids (VFAs) that can be utilized by the animal. The microbial fermentation that occurs
in the rumen enables ruminant animals to digest coarse plant material which monogastric
animals, including humans, cannot digest.
Methane is produced in the rumen by bacteria as a byproduct of the fermentation
process. This methane is exhaled or eructated by the animal. Non-ruminant herbivores such
as horses, mules, rabbits, pigs, and guinea pigs do not support this pre-gastric fermentation.
Some microbial fermentation does occur in the large intestines or ceca of these animals, but
the methane produced in this manner is quite small compared to the amount produced by
ruminant animals.
litratufe
melhariei
A significant scientific literature exists
that describes the quantity of methane
produced by individual ruminant animals,
particularly cattle. This literature results
from decades of research evaluating feeding
practices for cattle and other ruminants.
Over the past 30 years, hundreds of
methane measurements have been
performed on a wide variety of cattle diets
typically used in the U.S. The USDA
Ruminant Nutrition Laboratory has been the
primary focus of dairy animal evaluations,
and the Colorado State University Department of Animal Science has been the primary focus
of beef animal evaluations. The main purpose of these measurements was the development
of scientifically-based feeding standards for dairy and beef animals in the U.S. The standards
1 Although non-ruminant animals produce only a small quantity of methane from enteric fermentation as
compared with ruminant animals, emissions from non-ruminant animal manure, especially swine manure, may be
significant. Opportunities for reducing methane emissions from livestock manure are discussed in Chapter 6 of this
report.
5-5
-------
are presented in a series of National Research Council publications (e.g., NRC 1989; NRC
1984) and are used routinely for determining feeding strategies.
While the methane measurements data for cattle are substantial, it should be noted
that the measurement technique used is somewhat intrusive in that it requires animals to be
held in confinement.2 Consequently, emissions measurements from grazing animals
generally are not available. Nevertheless, experience indicates that the data collected from
the measurement experiments predict well the performance of animals under field conditions.
Consequently, although less intrusive measurement techniques are desired both for
measuring emissions and for evaluating feeding strategies, confidence in the available data is
high.
At the same time that the experimental data on whole animals were being developed,
significant progress was made in understanding the microbiological processes involved in
ruminant digestion and animal growth. Detailed assessments of rumen fermentation at the
microbiological level had been performed and continue to be refined. A mechanistic
understanding of ruminant digestion and physiology has evolved that allows quantitative
models to be developed.
The understanding of ruminant digestion and physiology continues to evolve, so that
feeding efficiency and animal productivity continue to improve. Commercial products are
available that improve production by manipulating rumen digestion processes directly.
Increasingly sophisticated manipulations of digestion and other physiologic processes are
expected in the future. Nevertheless, there is currently a firm basis of scientific measurements
and mechanistic understanding for estimating methane emissions from ruminant animals in
the U.S.
Current Emissions
USEPA (1993) presents a detailed estimate of methane emissions from livestock in the
U.S. For cattle the estimates are further divided into segments of the beef and dairy industry.
The beef industry is the largest source of livestock emissions in the U.S. and the dairy
industry is the second largest.
The beef industry can be divided into three main segments: the cow-calf sector, the
backgrounding or "stocker" phase, and the feedlot sector. As a whole, the cow-calf sector is
the largest source of livestock methane emissions in the U.S., accounting for about 2.9 Tg of
methane emissions, or 50 percent of the U.S. livestock total. The cow-calf sector is
comprised of the following:
• Beef Cows. In 1990 there was estimated to be about 33 million mature beef
cows in the cow-calf segment of the U.S. beef industry. The principal function
of these cows is to produce offspring. Most of the offspring enter the
backgrounding and feedlot sector (see below).
2 Calorimetry is the laboratory technique currently used to perform in-depth evaluations of alternative feeding
practices. This technique involves placing an animal in a climate-controlled confinement chamber for a period of
several days, and measuring the levels of inputs to (feed, oxygen, carbon dioxide) and outputs from the chamber
(feces, urine, milk, carbon dioxide, oxygen and methane). Because methane is produced as part of the normal
digestive process of cattle, methane is measured as part of this feed evaluation technique.
5-6
-------
• Replacements. A portion of the offspring are retained to replace mature cows
that die or are removed from the herd (culled) each year. Those that are
retained are termed "replacements." In 1990 there were about 11 million calves
and yearlings under the age of 24 months being retained for replacements
(about 5.5 million calves and 5.5 million yearlings).
• Bulls. Bulls are used in beef cow-calf operations. Nationally there are an
estimated 2.2 million bulls.
The backgrounding or stocker phase is the second major segment of the beef
industry. Cattle move through this phase in a wide variety of ways, and as a consequence
the segment is relatively ill defined (Cornett 1993). Recently, with increasing weaning weights
and relatively high calf prices, the trend has been toward shorter backgrounding periods.
Nevertheless, the stocker phase continues to help spread out cattle marketings throughout
the year, and allows calves to add frame and muscle relatively cheaply. Examples of stocker
programs include the following:
Fall-weaned calves with high weaning weights (e.g., 550 pounds) require a
short backgrounding period. These calves may overwinter on wheat pasture
and enter a feedlot in the spring. The calves will be pulled off the wheat
pasture at various times, depending on market and weather conditions (Cornett
1993). Some calves will be pulled off pasture as the wheat goes into its winter
dormancy. Others will remain and be pulled off in early spring before the grain
starts to form. Most will graze until late spring as the wheat matures. Wheat
pasture grazing is typical in the Texas Panhandle and throughout the high
plains.
Spring-weaned calves and fall-weaned calves that do not go to feedlots in the
spring may graze during the summer on the Midwest prairies. The duration of
the grazing will depend on forage quality and the market for livestock.
• The corn-belt states support stocker operations year round, often using a
combination of grass during the fall and spring and home-grown corn during
the winter. The cool season grasses in this region are ready for fall-weaned
cattle before the grain crops are fully available for feedlot feeding.
Throughout the country cattle are held over the winter using home-grown hay
and stockpiled grasses, yielding relatively low growth rates (e.g., 1 pound per
day). In the spring they are turned out on grass, and gain weight more rapidly
(e.g., 2 pounds per day) prior to being sent to a feedlot in the late summer or
fall. This practice is reportedly typical of parts of Nebraska (Cornett 1993) as
well as the Southeast.
Some of the larger calves skip the stocker phase completely and enter a
confined feeding program. During this program these calves are fed a diet with
an increasing amount of grain to prepare them for feedlot rations.
A variety of factors influence how cattle move through the stocker phase, with cattle
prices and forage quality and availability being among the important determinants. For
example, some cow-calf operators like to graze their weaned cattle themselves during years
when forage quality is good. This strategy may be preferred to increasing the cow-herd size
5-7
-------
to take advantage of the good forage, because the forage in the following year may not
support the larger herd size. Also, the availability of wheat pasture and the strategy for using
wheat pasture for grazing depends, in part, on the US Department of Agriculture wheat
acreage program and the markets for grain and livestock.
The feedlot sector is the third major segment of the beef industry. Feedlots are
confined feeding programs in which cattle are fed diets very high in grain. These programs
typically last about 120 to 150 days, depending on the cattle characteristics, rates of weight
gain, and the market for livestock. In 1990, about 26.3 million feedlot fed cattle were
marketed.
USEPA (1993) estimated the methane emissions from the cattle that move through the
backgrounding and feedlot sectors at about 1.1 Tg in 1990, or about 19 percent of total U.S.
livestock emissions. To estimate these emissions, USEPA (1993) used two combined
backgounding-feedlot programs to represent the large diversity of programs that are used.3
One program, referred to here as the "Weanling System," moves calves directly from weaning
to confined feeding programs. This system represents a very fast movement of cattle through
to marketing. The second program, referred to here as the "Yearling System," includes a
wintering over, followed by a summer of grazing on pasture. This system represents a
relatively slow progression to marketing. Whereas the Weanling System cattle are marketed
at about 420 days of age (14 months), the Yearling System cattle are marketed at 565 days of
age (18.8 months).
For 1990, USEPA (1993) estimated that the beef industry can be represented by
assuming that about 20 percent of the cattle move through the Weanling System and 80
percent move through the Yearling System, for an average age at marketing of under 18
months. Of the total emissions estimated for these segments of the industry, the Yearling
System cattle account for about 90 percent (0.99 Tg in 1990) because the emissions per
head marketed are substantially higher for the Yearling System than for the Weanling System.
Since 1990, the shift toward shorter backgrounding periods would likely reduce emissions
relative to the estimates for 1990.
The dairy industry is comprised primarily of mature dairy cows and replacements for
the mature cows that die or are removed from the herd annually. In 1990 there were about
10 million dairy cows in the U.S., which are used almost exclusively for producing milk.
Calves produced from the best dairy cows are retained as replacements. Bull calves and
heifer calves not needed as replacements generally enter the feedlot sector of beef
production (emissions from these animals are counted in the beef sector in this analysis).
The mature dairy cows and dairy cow replacements account for about 1.5 Tg of methane
emissions, or about 27 percent of total U.S. livestock emissions.
Exhibit 5-3 summarizes the emissions estimates for the dairy and beef industries. As
shown in the exhibit, cattle in the beef and dairy industry account for about 5.5 Tg of methane
emissions, or about 95 percent of the total emissions from U.S. livestock. The remaining
species, sheep, goats, pigs, and horses account for the remaining 0.3 Tg of emissions, which
is about 5 percent of total U.S. livestock emissions. These emissions estimates have a
reported uncertainty range of about ±20 percent. This range is also shown in Exhibit 5-3.
3 The time that the calves spend with the mother cows in the cow-calf sector is also included. However, calf
emissions are assumed to be zero pre-weaning.
5-8
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Exhibit 5-3
1990 U.S. Methane Emissions from Livestock
Animal
Population
(000 head)
Emissions
(Tg/yr)
'B^dt^ary ' ' -v^Mr; v ;;;,;, •;.; : . ...
0-12 month old replacements
12-24 month old replacements
Mature dairy cows
Dairy Industry Total
4,205
4,205
10,130
-
0.08
0.25
1.16
1.49
B«*f indtistty
Cow-Caff sector
0-12 month old replacements
12-24 month old replacements
Mature beef cows
Bulls
Cow-Calf Sector Subtotal
5,535
5,535
33,478
2,200
-
0.12
0.36
2.23
0.22
2.93
Backgrounding and Feed/of Sector
Weanling System feedlot fed cattle
Yearling System feedlot fed cattle
Backgrounding and Feedlot Sector Subtotal
Beef Industry Total
5,260a
21,040a
-
-
0.12
0.99
1.11
4.04
&iter Spe&w f "'"" ''''. ' •'•'•-- -I y. +
Sheep
Goat
Pigs
Horses
Other Species Total
Total U.S. Livestock Emissions
11,364
1,900
53,852
5,215
-
-
0.09
0.01
0.08
0.09
0.27
5.80
(4.6 to 6.9) b
a Yearling and Weanling System feedlot fed cattle populations listed in terms of
cattle marketed annually. Because the cattle are marketed at 422 to 565 days of
age, the average annual total population alive at one time exceeds the number
marketed annually.
b Uncertainty range of ±20 percent.
Source: USEPA (1993).
5-9
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Future Emissions
Future methane emissions from cattle and other animals in the U.S. will be driven by
future levels of production and the production methods used. Future levels of milk and meat
production will be driven principally by domestic demand. However, the ability of U.S.
suppliers to compete with other producers in both the domestic market and foreign markets
may also play a role. Because international trade in agricultural commodities is highly
influenced by national and international trade policies and agreements, future U.S. production,
and hence future U.S. emissions, will be influenced by potential changes in these policies.
metfcane; emissions from oattte
and other anfmals in the U;Sv wflf be
by futureltevefes of produ<3tion
and Hie production methods used.
Future tevete of pmdt*etk>n wi &e inv-
ert principally b^ilirnesfic demand.
Over the past 15 years strong trends
have been evident in the domestic
production and consumption of milk and
meat products. Domestic per capita meat
consumption has increased by about 0.9
percent per year during the period 1975 to
1990. During this period, the market share
of the various meats has changed
substantially, with the per capita
consumption of beef, veal, lamb, and
mutton decreasing nearly 25 percent. Because the total U.S. population has increased, U.S.
beef production has remained fairly flat during this period.
Domestic milk production and consumption increased substantially during the 1975 to
1989 period. Production and domestic consumption rose by about 25 percent, while per
capita consumption rose by about 8.4 percent. Net milk imports are small compared to
domestic production and consumption, and consequently have not affected these trends.
In the absence of significant changes in international trade agreements, future
production and consumption of milk and meat products in the U.S. are anticipated to
continue along these trends. There are, however, possible changes in international trade
policies that would cause U.S. production of milk products to increase at a rate greater than
the recent trend. Additionally, efforts are underway in the beef industry to stop the loss of
beef's market share of total meat consumption in the U.S. These factors could lead to
increases in U.S. beef and milk production relative to past trends.
Considering the recent trends in milk and meat production, and a range of possible
future trade policies, USEPA (1993) presents a range of future methane emissions estimates
assuming that production practices and productivity remain unchanged. As shown in
Exhibit 5-4, methane emissions from the beef industry could remain fairly flat for the period
1990 through 2010 if the decline in per capital consumption of beef continues (Low Scenario).
Alternatively, emissions from the beef industry could increase if the trend is reversed (High
Scenario).
Emissions from the dairy industry are expected to increase in both the Low and High
Scenarios in Exhibit 5-4. The substantial increase in emissions by 2010 in the High Scenario
(33 percent relative to 1990) is driven by increases in exports of dairy products that could
result from liberalization of international trade for these commodities.
These scenarios of future emissions are used as the baseline against which emissions
reductions are estimated in this chapter. This baseline reflects current production practices
5-10
-------
and a range of future domestic and export demand for beef and milk products. This analysis
focuses on opportunities for reducing emissions within this context of a given overall demand
for cattle-based products.
Exhibit 5-4
Scenarios of Future Livestock Methane Emissions
(Tg/year)
Animal
Type
1990
Emissions
2000 Emissions
Low8
Highc
2010 Emissions
Low3
Highc
Beef Industry
Cow-Calf Sector
Backgrounding/Feedlot Sector
2.9
1.1
3.0
1.2
3.3
1.3
2.8
1.1
3.3
1.2
Dairy Industry
1.5
1.7
1.7
1.8
2.0
Others0
0.3
0.3
0.3
0.3
0.3
Total0
5.8
6.2
6.6
6.0
6.8
Range6
4.6-6.9
5.0-7.4 5.3-7.9 4.8-7.2
5.4-8.2
a Low scenario includes a continuation of the decline of beef consumption per capita, and
no increase in milk exports.
b High scenario includes a slight increase in beef consumption per capita, reversing recent
trends, and an increase in milk exports.
c Emissions from pigs assumed to change with pork production. Emissions from sheep
and goats assumed to change with beef production. Emissions from horses assumed to
remain constant.
d Total may not add due to rounding.
e A range of ±20 percent is used.
Source: USEPA (1993).
5.1.2 Approaches for Reducing Emissions from Cattle
There are several main approaches for reducing methane emissions from cattle.
Improving livestock productivity so that less methane is emitted per unit of product is the
most promising and cost effective technique for reducing emissions in the U.S. Other
approaches involve modifying the rumen bacterial population to reduce the rate of methane
production while maintaining proper digestion.
Improve Livestock Productivity
Continuing to improve livestock productivity is the most promising avenue for reducing
emissions from livestock in the U.S. During the past 40 years, significant improvements in
livestock productivity, in both the U.S. dairy and beef industries, have been achieved through
5-11
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the use of better management practices,
breeding, and the application of scientific
feeding principles. Over the past 20 years,
milk production per dairy cow has increased
by about 2 percent per year (Exhibit 5-5)
and beef production per cow has increased
by about 1.25 percent per year (Exhibit 5-6).
Continued improvements in productivity will
reduce methane emissions per unit of prod-
uct (milk, meat) produced.
There are two primary mechanisms by which improvements in livestock productivity
can reduce methane emissions per unit of product produced:
• reducing the maintenance requirement per unit product; and
• improving feed conversion efficiency for production (above maintenance).
Reducing the maintenance requirement per unit product can be achieved by increasing the
production levels of individual animals. Maintenance is the feed intake necessary to support
the basic metabolic requirements of the animal. Simply put, feed intake for maintenance is
needed to "keep the animal alive," but does not provide energy for the production of a
product, such as the synthesis of milk, the accretion of tissue (i.e., meat), or the development
of a fetus. By increasing the production rate per animal (e.g., increasing milk production per
dairy cow or increasing weaned calf weight per beef cow), the emissions associated with
maintenance can be spread out over a larger level of production, resulting in a reduction in
emissions per unit of product. Similarly, reducing the time it takes for steers and heifers to
grow to slaughter weight reduces maintenance requirements per unit of product (in this case
beef) produced.
Exhibit 5-5
Trend in Dairy Cow Productivity
r\ 15,000-
0) r, 12,500-
Q
0 g 10,000 -,
|k 7'500'
0&
L > 5,000-
ff o
* 2,500-
~ X
j L
0 197
^-^
0 1974 1978 1982 1986 1990
Year
Sources: USDA (1990); MIF (1991).
Exhibit 5-6
Trend in Beef Production per Cow
^
c -
0 <-<
u S
II
II
Source:
600-
500-
400-
300-
200-
100-
0
19
_^^=^=
KZZ^ZZZ**
^s=^s^ ^~-r
70 1974 1978 1982 1986 1990
Year
CF Resources (1991).
5-12
-------
Reducing maintenance requirements per unit product is a promising avenue for
reducing emissions because: (1) improving production rates can be profitable for the
producer, and is consistent with current industry trends; and (2) a substantial portion of the
feed consumed by cattle in the U.S. is associated with animal maintenance. Based on the
analyses performed in USEPA (1993), approximately 40 and 60 percent of the methane
emissions from dairy and beef cattle respectively in the U.S. are associated with the feed
intake required for animal maintenance. Additionally, the feed intake associated with the
growth of replacement heifers and the maintenance of bulls can be considered part of the
maintenance requirement for the herd, which increases the overall maintenance portions to
about 50 and 70 percent respectively for the U.S. dairy and beef industries (see Exhibit 5-7)4
Exhibit 5-7
Methane Emissions Associated with Maintenance and Production in the Dairy and
Beef Industries
Beef Industry Dairy Industry
Steers & Heifers Mature Cows
Bui is
^Mature Cows
flepIacaments
Replacements ^^"""""itature Cows
Mature Cows
fI Production 31* | | Production: 50*
lH Haintenace 69* [HI Uaintenace. 50*
Source: Developed from data presented in USEPA (1993). Maintenance energy requirements estimated as net
energy for maintenance based on NRC (1984) for beef cattle and NRC (1989) for dairy cattle. The net energy
for maintenance content of the diet was estimated using the metabolizable energy content of the diet and the
conversion equation in NRC (1984). The ratio of net energy for maintenance to metabolizable energy was
estimated to be about 65 percent for the diets examined.
While a substantial portion of the feed consumed by cattle in the U.S. is associated
with maintenance, the portion is lower in the U.S. cattle industry than in most other countries
because relative to most other countries, the level of animal productivity achieved in the U.S.
is extremely high. Consequently, methane emissions per unit of product produced is
generally much lower in the U.S. than in other countries. Nevertheless, opportunities for
4 The 70 percent estimate of feed intake associated with maintenance for the U.S. beef industry compares well
with an independent estimate of 71 percent developed at Colorado State University (Field, 1993).
5-13
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further improvement exist. As an example, using these figures, a 20 percent improvement in
production rates per animal would reduce emissions by about 8 percent and 12 percent per
unit product for dairy and beef production respectively.
Improving feed efficiency for production also improves livestock productivity because
less feed input is required per unit of product produced. If the rate of conversion of feed
energy to methane by the animal remains unchanged, improvements in feed efficiency reduce
methane emissions per unit of product because feed intake per unit of product is reduced.
Several products are currently available for improving feed efficiency. Generally, these
products do not affect the rate of conversion of feed energy to methane, although, as
discussed below, ionophores reduce the rate of methanogenesis, at least temporarily.
Increased use of these products within the applicable segments of the cattle industry can
contribute to emissions reductions.
The manner in which beef and milk are marketed affects methane emissions. The
marketing and pricing systems provide the framework within which products are produced,
processed, and eventually sold to consumers. Both beef and dairy products are subject to
strict federal grading and safety inspection requirements. Additionally, milk price and
composition are heavily influenced by federal and state milk programs. Refining the pricing
and marketing systems to improve the links between production incentives and consumer
demands is expected to promote efficiency. Particularly in the U.S. beef industry, there is
currently a strong incentive to refine the marketing system to improve the ability of the
industry to respond to consumer demands. As a side benefit, the refinements that are
currently under discussion would reduce methane emissions.
Modify the Rumen Microbe Population
The rumen microbe population can be modified directly with chemical agents that
inhibit the growth of selected bacteria or protozoa. Chemical agents that inhibit the growth of
methanogens in the rumen were investigated during the 1950s through the 1970s because it
was believed that reducing methanogenesis would improve feed efficiency (Chalupa 1977).
During this time it became clear that reducing methanogenesis in and of itself did not improve
productivity because inhibiting or eliminating methanogens does not automatically increase
the feed energy accessible to the animal. Consequently, although a variety of anti-
methanogenic agents have been identified (e.g., Phillips and Tadman 1984), the realization of
feed efficiency gains solely as the result of this mechanism has been elusive.
While eliminating methanogens from the rumen has not been successful in improving
feed efficiency, feed efficiency improvements in growing beef cattle and beef cows have been
achieved using agents that shift the mix of rumen microbes so that, inter alia, the VFA
propionate is produced preferentially to the other major VFAs, acetate and butyrate, in the
rumen (Dinius et al. 1976; Richardson et al. 1976). Through their mode of action, these
agents, referred to as ionophores, also inhibit methanogenesis in the rumen, at least for a
brief period following initial administration. Ionophores are the only commercially available
product that reduces methanogenesis by altering the rumen microbe population, although the
reduction appears to be temporary.
Leng has proposed that removing protozoa from the rumen will also reduce methane
excretion, particularly among cattle consuming poor quality tropical feeds (Leng 1991 a and
1991 b). Leng indicates that protozoa account for the turnover of a large portion of the
bacterial pool in the rumen and also increase the degradation of dietary protein in the rumen.
5-14
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Removing protozoa from the rumen would therefore increase microbial cell outflow from the
rumen and reduce methanogenesis per unit of carbohydrate fermented. The improved
protein to energy ratio in the rumen fermentation products would also improve feed utilization
efficiency. Bird et al. (1989) report feeding trial data in support of this view, and indicate that
eliminating protozoa would be particularly beneficial for livestock production systems on low
protein, fibrous feeds, and especially in warm climates which reduce the animal's ability to
dissipate metabolic heat.
Using indirect calorimetry techniques, Whitelaw et al. (1984) measured the impacts of
removing protozoa from cattle on a restricted barley-based concentrate diet. The results of
the study showed that removing the ciliate protozoa reduced methane excretion by a
statistically significant 42 percent. Additionally, metabolized energy in the protozoa-free cattle
was improved by approximately the same amount by which the methane production was
depressed, about 4.8 percent of gross energy intake. The principal mechanism for the
methane effect seen in the study was the shifting of the rumen fermentation pattern toward
propionate. The methane measurements were consistent with the stoichiometric predictions
made by the authors based on the VFA proportions in the rumen fluid.
While the improved energy retention reported by Whitelaw et al. supports Leng's
proposed mechanism regarding the expected impacts of removing protozoa from the rumen,
the barley-concentrate diet examined is not typical of most cattle diets. Additional analyses
are required to verify the effectiveness of removing protozoa for reducing methane emissions
and enhancing production, particularly for forage-based diets and mixed diets commonly
found in the U.S. Additionally, commercial products that safely and effectively remove
protozoa from the rumen remain to be developed. Leng (1991b) indicates that a promising
natural forage has been identified that may prove effective in removing protozoa.
Over the long term the rumen ecosystem could potentially be managed using genetic
engineering techniques to reduce the role of methanogens and reduce methane production
and emissions (Hespell 1987). Considerable basic and applied research is needed before
this approach can yield emissions reductions. Hespell (1987) presents a research strategy
for approaching the problem of modifying rumen microbes.
While various avenues for modifying rumen microbes to reduce methane emissions
appear promising, only ionophores are currently available for implementation. Additional
research is needed to verify and commercialize protozoa removal techniques and
commercially-useful modification of rumen microbes using biotechnology is many years away.
Consequently, only ionophores, which also improve livestock productivity, are analyzed
further as a means of reducing emissions by modifying the rumen microbe population.
5.2 OVERVIEW OF OPPORTUNITIES FOR EMISSIONS REDUCTIONS
Opportunities exist for reducing methane emissions per unit product produced from
dairy and beef cattle by increasing animal productivity. These options can be profitable
because they reduce costs per unit of product produced. Methane emissions per unit
product are reduced because maintenance feed requirements are spread out over a larger
amount of production and/or because feed conversion efficiency is improved. Using these
profitable techniques, total methane emissions will be reduced for a given level of production.
5-15
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Currently available techniques are
first presented in two parts: (1) productivity
enhancing agents and practices; and
(2) marketing and pricing system
refinements. Then, future techniques that
have yet to be fully developed are
Options lor reducing methane ©mis-
sions from dairy and beef cattle are
profitable principally because they re-
duce costs per unit of product pro-
duced* :
discussed. Exhibit 5-8 summarizes the
options and the industry sectors to which
they apply. As shown in the exhibit,
productivity enhancement options are available for all sectors of both the beef and dairy
industries. Marketing and pricing system refinements will primarily reduce methane emissions
from mature dairy cows and the backgrounding/feedlot sector of the beef industry.
5.2.1 Productivity Enhancing Agents and Practices
A wide variety of products and livestock management practices have been developed
to improve productivity and reduce costs of production. This section discusses the main
approaches that can be used more extensively to help reduce methane emissions.
It is well recognized that there is a wide range of levels of productivity of dairy and
beef operations throughout the U.S., and consequently there is considerable opportunity for
improving productivity in many areas. Proper veterinary care, sanitation, ventilation (for
enclosed animals), nutrition, and animal comfort all promote efficient growth, reproduction,
and lactation. These fundamental principles of livestock management provide the foundation
for improving livestock productivity.
Of particular relevance to reducing methane emissions in the near term is improved
nutitional management. Throughout both the beef and dairy industries computerized feed
ration balancing tools have become available that help producers get the most from their
animals by matching feed characteristics to the animal's nutritional requirements for
maintenance, growth, pregnancy, and lactation. Periodic feed testing in conjunction with the
use of computerized ration balancing tools helps producers improve productivity and increase
profitability. For many producers, focusing on nutrition and the other basic principles of
livestock management provides the best opportunity for improving productivity and reducing
emissions per unit of product produced. Within this context, a variety of techniques can help
improve animal productivity and reduce methane emissions per unit of product.
Bovine Somatotropin (bST) in the Dairy Industry
Because of its ability to increase milk production in dairy cows, bovine somatotropin
(bST) is being developed for use in the dairy industry.5 At current and expected future milk
prices, bST can be profitably produced and marketed to dairy producers. At current prices,
dairy producers may earn $2 for each $1 spent on bST treatment (Fallert et al. 1987). The
profitability of bST use is not sensitive to key assumptions, such as increases in feed costs,
increases in veterinary costs, or reductions in the effectiveness of the drug (Fallert et
al. 1987). Consequently, assuming that bST is approved for commercial use, and
5 In the future, bST may be considered for use in beef cattle production to promote feed efficiency and lean
tissue production (see discussion under section 5.2.3).
5-16
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assuming that its use is accepted by consumers, there will be a strong financial incentive for
producers to use bST.
bST is a naturally occurring growth hormone found in cattle. Growth hormones are
proteins, secreted by the pituitary gland in all animals, vital for the regulation of growth in
young animals and for lactation in mature animals. Growth hormones are species-specific,
and the hormone occurring in cows is known variously as "bovine growth hormone" (BGH) or
"bovine somatotropin" (bST).
Until the 1980s, bST was costly and the supply was limited because its only source
was from the pituitary glands of slaughtered cattle. However, using recombinant DMA
techniques, the gene responsible for bST production has been isolated and transferred to
ordinary bacteria cells (Miller et al. 1980). Using standard fermentation techniques, the
altered bacteria can be reproduced on a large scale, and the resulting bST (produced by the
bacteria) can be isolated, purified and made available for commercial use in large quantities
(Kalter et al. 1985). bST produced in this manner is sometimes referred to as recombinant
bST, or rbST or rBGH. In this discussion, the term bST is used to include rbST.
A significant scientific literature has demonstrated that injections of natural or recombi-
nant bST increase milk production in lactating dairy cows (Kenney and Fallert 1987). Fallert
et al. (1987) report a consensus estimate of an increase of 2,400 pounds of milk per cow per
year for the expected commercial bST dose. This is an increase of 11.2 pounds per cow per
day during a treatment period of 215 days per cow per year. In their analysis of the impacts
of bST use on the U.S. dairy industry, Fallert et al. (1987) assume that under field conditions
the yield response would be reduced by about 25 percent to 1,800 pounds per cow per year.
This average yield response expected under field conditions is about a 12.2 percent increase
in milk production per cow at 1990 U.S. production rates.
Experiments have demonstrated that good yield responses are expected from cows
with a wide range of genetic capacity to produce milk. Additionally, no special expertise or
equipment is needed to administer bST in the forms expected to be made available.
Consequently, bST could be used to improve the yields of all dairy cows on all farms in the
U.S., not just the most productive cows or the cows on the most capital intensive, largest, or
technically sophisticated operations. To realize the benefits of bST treatments, however,
additional nutritional inputs must be provided to the bST-treated cows to keep pace with the
increased amounts of milk produced. Failure to adjust the diet appropriately can result in
little or no yield response from the bST treatment.6
By increasing milk production per cow, bST reduces methane emissions per unit of
milk produced. Because bST does not change the efficiency with which feed energy is used
for maintenance or milk synthesis (Eisemann et al. 1986b and Tyrrell et al. 1982), methane
emissions are reduced solely by spreading out the maintenance requirement across a larger
production level. Using the estimates in USEPA (1993), about 50 percent of the dairy industry
emissions are associated with feed intake for dairy cow maintenance and pregnancy and
raising replacements. A 12.2 percent increase in milk production per cow (the average on-
g
The process of formulating diets to meet the nutritional requirements of bST-treated dairy cows is no different
that the process of formulating diets to meet the varying nutritional requirements of daiiy cows with a range of
genetic potential to produce milk. Dairy producers routinely formulate diets to reflect changing forage
characteristics (e.g., with the seasons) and varying levels of production within the herd.
5-18
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farm response expected from bST use) would therefore reduce methane emissions per unit of
milk produced by about 5 to 6 percent assuming that feed characteristics remain unchanged.
To handle the higher milk production rates, feeds with higher energy content may be
required, which will also tend to reduce methane emissions somewhat. The combined impact
of both the increase in production and the change in feed characteristics would reduce
emissions by about 9 percent (Johnson et al. 1992).
There are a variety of obstacles to the approval and widespread adoption of bST in
the U.S. dairy industry. Concern over the use of a drug derived from recombinant DMA
techniques has prompted extensive study and review of potential health effects for both
humans and cows. Currently, the scientific consensus overwhelmingly supports the safety
and effectiveness of bST. The Food and Drug Administration (FDA) has found the
consumption of milk from bST-treated cows to be safe for humans; the FDA is currently
considering the impacts of bST use on the health and safety of the animals and on the
environment. bST has been approved for commercial use in at least 8 countries: Brazil,
Mexico, Namibia, Zimbabwe, South Africa, Bulgaria, Czechoslovakia, and the Soviet Union.
The potential impacts of bST use on the profitability and structure of the dairy industry
has also been a concern. The most comprehensive studies of industry impacts indicate that
widespread use of bST would reinforce underlying trends toward fewer and larger dairy farms
throughout the U.S. (Fallert et al. 1987 and Kalter et al. 1985). Under the range of future
possible milk support price scenarios examined by Fallert et al. (1987), the decline in cow
numbers and dairy farm numbers is generally expected to accelerate as the result of bST use,
unless price supports and government purchases increase from current levels (which is
unlikely, with or without bST). Some have also questioned the need to improve dairy cow
productivity with bST given the relatively high levels of productivity already achieved in the
U.S.
The combined effect of concerns about safety, cow health, and adverse industry
impacts has made bST approval and use a controversial topic. Even if bST is approved for
commercial use by FDA, consumer fears regarding the consumption of milk from bST treated
cows could inhibit its use. Also, some groups are opposed to the introduction of
recombinantly-derived products in the food industry. For these groups, the approval and use
of bST would be an important precedent that may allow additional recombinantly-derived
products to be used in the U.S. Additionally, those who are concerned about the impacts of
increased production rates on dairy farmers may work to limit its acceptance.
In response to the controversial nature of bST approval and use, the Budget
Reconciliation Act of 1993 (the 1993 Budget Bill) imposed a 90 day moratorium on bST sales
that will begin following FDA approval. Assuming that bST is approved for commercial use,
these various concerns would be balanced by producers against the production cost
advantage that bST provides. Despite the cost advantage of using bST, the industry is
unlikely to use bST if consumers consider the milk from bST-treated cows to be undesirable.
Anabolic Steroid Implants in the Beef Industry
Anabolic steroids have been demonstrated to be effective in increasing the rate of
weight gain and improving feed conversion efficiency among beef cattle. These effects are
achieved by redirecting the energy used to deposit fat in the animal to the deposition of
protein. As a consequence, the animal adds protein more quickly and efficiently.
Additionally, the use of anabolic steroids results in a leaner beef product at slaughter.
5-19
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Several steroids have been approved for use in food producing cattle including the
following:
progesterone, used in steers and intact males grown for beef;
• testosterone, used in heifers and in some cases steers;
zeranol, used in heifers and steers;
trenbolone, used in heifers and steers; and
• estradiol benzoate, used in combination with testosterone, progesterone, or
trenbolone in heifers and steers.
The preferred method for introducing the steroids into the animal is by placing or "implanting"
a small pellet under the skin of the animal's ear, hence the use of the term "implants." The
pellet releases a defined dose of steroid into the animal's bloodstream. Via the bloodstream,
the steroid reaches its appropriate and effective sites throughout the body. Implanting is
preferred to previously used injection methods of delivery because the dose can be con-
trolled carefully, thereby preventing concentrations of the steroid from building up in tissues
used for human consumption.
The implants will typically increase daily rates of gain by 10 to 15 percent and improve
feed efficiency by 5 to 10 percent (Ensminger 1987). Implants are not used in milk producing
animals, replacement heifers ready for breeding, or beef cows. Implants are extremely cost
effective for growing beef animals. The value of the increased rate of weight gain and the
feed efficiency exceeds the cost of the implant and the cost of administering it to the animal.
The average cost of an implant is about $1.00 per head each time it is administered. A single
steer could receive three doses during its lifetime if the steer were implanted continuously
post weaning. More typically, steers in the U.S. are only implanted during the feedlot feeding
phase.
Implants are widely available in the U.S. and can be obtained commercially for use in
producing beef animals. However, steroid implants have recently been banned from human
food production in the European Community (EC) due to concerns about residues from
improper administration of hormones through injection. Injection is no longer used to
administer homones, and some view the EC ban as a trade barrier to U.S. produced beef
because food that was produced with implants also cannot be imported into the EC.
Implants reduce methane emissions from beef cattle production by increasing the rate
of weight gain and improving the feed conversion efficiency in growing heifers and steers.
Increasing the rate of weight gain reduces the time it takes for cattle to reach slaughter
weight, or increases the retail product produced within a specified growing period. Improving
feed efficiency reduces the feed intake required per unit of weight gain, further reducing
methane emissions per unit of product produced.
In 1987 the U.S. Department of Agriculture (USDA) published a comprehensive
evaluation of the impacts of implant use on U.S. beef production (USDA 1987). This analysis
summarized the effects that implants have on beef cattle growth, feed efficiency, and costs of
production. Using the growth model for steers presented in the report, the use of implants
from weaning through feedlot feeding has the following effect relative to the case in which no
implants are used:
retail product produced per steer is increased by 14 percent; and
5-20
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• feed intake per pound of retail product produced is reduced by 10 percent7
By increasing the retail product per steer, implants reduce the emissions per unit product by
spreading the emissions from the beef cows, bulls, and replacement heifers over a larger level
of production. The improved feed efficiency reduces emissions by reducing methane
emissions from the steer itself as it grows.8 The combined impact of these two effects is to
reduce emissions by about 12 percent relative to the no implants case. Exhibit 5-9
summarizes these estimates.
Exhibit 5-9
Impacts of Implant Use in Beef Production
(Estimates Relative to No Implant Use)
Retail Product Per Steer
Feed Intake Per Retail Product
(Steer Only)
Methane Emissions Per Retail
Product
Extent of Implant Use
Feedlot Only
+ 10%
-5%
-8%
Feedlot and
Background
+ 13%
-9%
-11%
Feedlot,
Background,
and Calf
+14%
-10%
-12%
Estimates based on the steer growth model presented in USDA (1987). Estimates are relative to the case in
which no implants are used. All steers are assumed to enter the background or stocker phase and feedlot at
the same weights. All steers are fed to the same end point to grade choice with a yield grade of 3.0. Impacts
on emissions are estimated based on the estimate that 70 percent of the emissions from the beef industry are
associated with the beef cows, replacement heifers, and bulls.
lonophore Feed Additives in the Beef Industry
In the 1970s, ionophore feed additives gained widespread attention for their ability to
improve feed efficiency in ruminant animals. Since then, two ionophore feed additives have
7 These estimates are based on the assumption that both the implanted steers and the non-implanted steers
enter the feedlot at the same weight, and are fed to the same endpoint to finish choice and have a yield grade of
3.0. Similar estimates are produced under varying assumptions, such as holding constant the age at which steers
enter the feedlot or holding constant the age or weight at which steers are slaughtered. Of note is that recently
approved combinations of implants (e.g., estradiol plus trenbolone) have been reported to have a larger impact
than the implants evaluated by USDA in 1987. Consequently, the emissions reductions for implants estimated in
this study are likely to be conservative.
8 Because the implants do not modify the rumen environment, the reduction in methane emissions for the steer
itself would be approximately equal to its reduction in feed intake. Feed intake is reduced as a result of the feed
efficiency improvement and the faster growth rate.
5-21
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been approved for use in cattle feeding in the U.S.: monensin (produced by Elanco) and
lasalocid (produced by Hoffman LaRoche).9
lonophores are polyether antibiotics produced by naturally-occurring soil microorgan-
isms. The ionophore is fed to cattle by mixing it with the feed at the appropriate dosage, or
providing it as a component of a multi-mineral or multi-nutrient "block lick" that the cattle
consume on an ad lib basis. A ruminal delivery device has also been developed, although it
has not been used in the U.S.10 Appropriate doses cost $0.01 to $0.02 per head per day,
so that for a 140 day feedlot feeding period, costs per head would generally be under $3.00
(Ensminger 1987).
Extensive studies have demonstrated that at recommended doses ionophores improve
feed efficiency in cattle by about 5 to 10 percent in both high grain feedlot-type diets and
forage diets (Ensminger 1987; Garrett 1982; Potter et al, 1976; Raun et al. 1976). Additionally,
ionophores have been demonstrated to improve rate of gain by up to about 8 percent in
some circumstances. This improved feed efficiency makes ionophores very cost effective
under conditions where the ionophore can easily be made available to the cattle, and
consequently these additives are commonly used in the feedlot phase of beef production.
lonophores are not approved for use in feeding dairy cows, although they can be used with
replacement heifers (Goings and Bernett 1993).
Several mechanisms appear to contribute to the ability of ionophores to improve feed
efficiency (Bergen and Bates 1984):
• Energy metabolism in the rumen is improved due to the shift in VFA production
toward propionate and away from acetate and butyrate.
• Nitrogen (protein) metabolism is improved, possibly due to reduced protein
digestion in the rumen.
• The incidence of acidosis and bloat in high grain feedlot-type feeding situations
is reduced.
Of these, the shift toward propionate has the potential to reduce methane production in the
rumen (Richardson et al. 1976). Measurements in vitro and in vivo show at least a temporary
reduction in rumen methane production when ionophores are fed. Recent whole-animal
calorimetry analyses indicate that within a period as short as two weeks following the initial
introduction of the ionophores, methane production in the rumen returns to the levels seen in
non-treated controls (Johnson 1992). This result is consistent with in vitro experiments
showing that methane inhibition by ionophores is temporary (Chen and Wolin 1979; Dellinger
and Ferry 1984). Consequently, for this analysis ionophores are assumed to reduce methane
emissions principally through their feed efficiency effect, and the methane suppression
component within the rumen is not quantified.
9 A third ionophore, salinomycin, has been approved for use in poultry production.
The rumen delivery device is an orally-administered bolus containing monensin blended with a water soluble
copolymer. Following administration, the bolus remains in the rumen and the copolymer slowly dissolves, releasing
monensin at the recommended dose for about 150 days. This method of delivery may be appropriate in cases
where mixing with feeds is not possible, such as in pasture or range situations.
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As with implants, the improved feed efficiency of ionophores reduces methane
emissions by reducing the feed intake required for maintenance and growth. For example, a
10 percent improvement in feed efficiency during feedlot feeding would reduce methane
emissions from that phase of production by an equivalent 10 percent. An additional reduction
(not quantified here) would be achieved due to the temporary suppression of methane
production in the rumen.
As a companion feed additive for heifers in feedlots, melengestrol acetate (MGA) can
be used to improve feed efficiency and increase rate of gain. MGA keeps heifers out of heat
(prevents estrus). Rate of gain is improved by about 10 percent and feed efficiency is
improved by 6.5 percent. The improved feed efficiency and rate of gain reduces methane
emissions by reducing the feed intake required for maintenance and growth.
Improved Cow-Calf Sector Productivity
The cow-calf sector has a large influence on the overall productivity of the U.S. beef
industry. The approximately 33 million beef cows are the principal source for the 26 million
feedlot fed cattle marketed annually. As described above, this sector accounts for about 50
percent of total U.S. livestock emissions. Consequently, improvements in cow-calf
productivity can have a significant influence on methane emissions per unit of product
produced.
The cow-calf sector is comprised of a diverse set of operations, varying in size,
technological sophistication, and resource base. Generally, U.S. cow-calf operations graze
their cows on pasture or rangelands, at least seasonally. In some cases owners have
infrequent contact with their cows because the cows are dispersed over very large areas. In
other cases the cows are in fenced pastures or corrals, and can be managed more closely.
Management practices vary regionally, with
larger grazing areas generally used in the
western states.
Despite their diversity, the goal of
virtually all cow-calf operations is the same:
Improvements in £
-------
These productivity measures are also important indicators of the methane emissions
per unit product for the cow-calf sector. Reliable first calving at 24 months and a high
weaning percentage means that the production of calves per cow is high. Assuming that the
calves are healthy, can grow well, and be marketed efficiently, the emissions from the cows
per unit of product produced is minimized when these productivity measures are high.
Given this view, maintaining and enhancing the productivity of the cow-calf sector is
one approach for reducing methane emissions per unit product in the beef industry. In many
cases, improving productivity is also profitable. For example, there is generally a positive
relationship between return on assets and weaning percentage (see Exhibit 5-10). However,
as with any enterprise, the cost of improving productivity must be justified by the increased
revenue caused by the improvement. The most profitable set of practices is not always the
set that yields the highest level of biological productivity (Odde and Gutierrez 1993). Each
producer should adopt the set of practices that matches his available resources and costs,
including forage resources, labor inputs, and supplemental feed costs. Consequently, no
single set of practices can define what is best economically for all cow-calf producers.
Exhibit 5-10
Return on Assets is Positively Correlated with Weaning Percentage
Weaning Percentage vs ROA
Weaning Percentage
Weaning percentage is the ratio of the number of calves weaned to the number of cows 'exposed* to mating.
Source: Odde and Gutierrez (1993).
While there are a large number of factors that influence the productivity and
profitability of cow-calf operations, Byers (1992a and 1992b) identified several key practices
that hold promise for reducing methane emissions per unit product in the beef industry. In
particular, Byers emphasized the role of nutrition in maintaining the productivity of beef cows
(see also Blasi and Corah 1993), and concluded that a variety of nutrient-related problems
contribute low pregnancy rates (and hence low weaning percentages) and difficulty in getting
5-24
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heifers to calve at 24 months. It was recommended that in forage-based production
programs producers should improve their nutritional management by:
• collecting soil samples to determine the correct fertilization plan for their
forages;
taking forage samples to determine what nutrients are available in specific
quantities to their animals; and
• eliminating toxic plants that could have an impact on the animal's productivity
(Byers 1992b).
Using these techniques, nutrient deficiencies can be identified and corrected using
feed supplements of various types or forage improvement techniques. For example, protein
supplements can be (and often are) used to improve the availability of protein during winter
months. In some regions, key macro or trace minerals are lacking or are improperly
balanced, so that mineral supplements are advised. Byers (1992a) found that supplements
are not used adequately or are not properly designed to correct for local nutritional
deficiencies in some areas. These nutritional deficiencies appear to be one important factor
contributing to depressed rates of productivity in these areas. Among smaller operations in
particular, productivity was hampered by nutritional deficiencies which are cost effective to
correct.
Generally, supplementation is cost effective for most producers. However, inadequate
supplementation results due to: lack of knowledge regarding the value of proper nutrition for
animal performance; lack of adequate production statistics to demonstrate the value of
supplementation for individual producers; and inadequate characterization of nutritional
deficiencies, which vary seasonally.
As a companion to improved nutrition, Byers (1992b) also recommended conducting
pregnancy checks to identify cows that are not carrying their calves to term. Improved
pregnancy checking can improve culling decisions and reduce the number of unproductive
cows in the herd.
Improving the rate of calving at 24 months and increasing the weaning percentage can
have a large impact on methane emissions from the cow-calf sector. For example, typical
values for the Southeast U.S. are a weaning percentage of 70 percent and a 24 month heifer
calving rate of 50 percent (Byers 1992a). These are relatively low levels of productivity for
U.S. operations. By increasing the productivity levels to typical industry goals of a weaning
percentage of 85 percent and a 24 month heifer calving rate of 75 percent (Field 1993), the
number of cows needed is reduced by about 25 percent (see Exhibit 5-11), and emissions
per unit product produced are reduced by about 25 to 30 percent.11
In addition to nutritional supplements and pregnancy checking, a variety of techniques
can be used to improve the productivity of cow-calf operations in specific situations. For
11 The emissions reduction estimate is based on the following assumptions: half the open heifers and cows
are culled each year; non-culled open heifers and cows have a 50 percent chance of weaning a calf the following
year; cows live to be 12 years old; and culled cows have a discounted value (10 to 50 percent) in terms of product
"produced. The estimate of emissions per unit product considers the value of the culled heifers and cows.
5-25
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example, if the cows are relatively accessible, estrus synchronization and/or artificial insemina-
tion (Al) can be effective in maintaining high pregnancy rates in a cost effective manner.
Alternatively, annual fertility checks for bulls, performed before the breeding season, would
help eliminate infertile bulls and reduce the number of bulls required for a successful breeding
program. Proper veterinary care, including vaccinations, deworming, and other standard
practices also help reduce losses due to morbidity and mortality.
Exhibit 5-11
Cows Required Per 100 Calves Weaned for a Range of Weaning Percentages and
Heifer Calving Rates
TD
Q)
to
in
OJ
3
CD
O
QJ
Q.
(1)
L.
cr
O)
cr
o
o
180
so
Current Conditions in
"Southeast U . S
He. i fee.. .Ca.l.v J.nQ.. Rate.
Typical Industry Goal
sax as*
Wean i ng Percentaae
3 OX
95*
Estimates assume that one half of open heifers and cows are culled.
Other Productivity Enhancing Practices in the Beef and Dairy Industries
A variety of other practices and products can help to improve the productivity of dairy
and beef cattle in a cost effective manner. As mentioned above, the first step to assuring
productivity of livestock is to provide proper veterinary care, sanitation, ventilation (for
enclosed animals), nutrition, and animal comfort. For many producers, focusing on these
basics provides the best opportunity for improving productivity. Once the foundation of good
practices is built, several tools are available to further improve productivity in a manner that
will reduce methane emissions per unit product produced. Two nutrition-related approaches
that are currently available include:
• Probiotic Feed Additives. Probiotic feed additives are currently available that
improve feed efficiency.
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Arnino Acid Feed Additives. Feed additives that provide key amino acids
(methionine and lysine) to dairy cows in a form that is not digested within the
rumen have been shown to improve milk production rates.
While these products have not been approved as drugs (which would require proof of their
performance enhancing effects), they have gained acceptance in some segments of the
industry.
5.2.2 Marketing and Pricing System Refinements
The marketing and pricing systems for milk and beef products have a significant
impact on the structure and efficiency of the industry. The highly regulated dairy pricing
system has a strong impact on the relative quantity of the fat and non-fat components in milk
that is produced. Refinements to the pricing system to better match production incentives
with consumer demand can not only improve efficiency and reduce costs, they can also
reduce methane emissions as a side benefit.
Efforts are currently underway in the beef industry to promote efficiency by changing
the way that live cattle and beef are bought and sold within the beef marketing system. In
particular, steps are being taken to provide market information to cattle breeders and feeders
that will enable them to produce more efficiently. This initiative, referred to as "Value-Based
Marketing" within the industry, provides an opportunity to reduce substantially the methane
emissions per unit of product produced by the industry.
Milk Pricing in the Dairy Industry
Milk pricing in the U.S. is primarily influenced by two related programs: the milk price
support program and the marketing orders program. These programs protect farmers from
price fluctuations caused by imbalances in milk supply and demand, protect consumers from
seasonal supply imbalances (shortages), and help to assure an orderly market. The need for
these programs has been justified by the unusual vulnerability of dairy farmers to marketplace
forces. Historically, dairy farmers were perceived to be at a considerable disadvantage in
negotiating a price for their product because milk is a perishable commodity that must be
produced and shipped daily, whether prices are favorable or not. Consequently, farmers
could not bargain effectively and could not obtain fair prices for their milk. Additionally,
farmers usually found it difficult to consistently meet consumer demand without falling into
periods of costly overproduction (Becker 1984).
The milk price support program is a federal program authorized by the Agricultural Act
of 1949, as amended by the Food Security Act of 1985. Under the program, the U.S.
Department of Agriculture (USDA), through the Commodity Credit Corporation (CCC), agrees
to purchase all the butter, cheese, and nonfat dry milk, at predetermined prices, that
processors are unable to sell on the open market (Becker and Carr 1990). The CCC butter,
cheese, and nonfat dry milk prices are set so that farmers will receive at least a minimum
support price for their milk. Historically, the support price has been set legislatively. Under
the Food Security Act of 1985, the support price is adjusted periodically by formula
depending on the level of purchases by the CCC: low levels of purchases result in an
increase in the support price, and high levels of purchases result in a decrease in the support
price. By purchasing butter, cheese, and nonfat dry milk at predetermined prices, the milk
price support program establishes a floor for milk prices.
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The price that most farmers receive for milk is also governed by a complex system of
more than 40 regional Federal and state milk marketing orders (Becker and Carr 1990).
Marketing orders are authorized by the 1935 amendments to the Agricultural Adjustment Act
of 1933 and by the Marketing Agreement Act of 1937, as amended by the Food Security Act
of 1985.
Marketing orders set the minimum prices that milk processors must pay dairy farmers
for milk. The price depends on how the milk is used: milk sold for fluid products (primarily
fluid milk purchased in supermarkets) gets a higher price than milk sold for manufactured
products (such as ice cream, yogurt, cheese, butter, and milk powder). Individual farmers
actually receive a "blend price" determined by the weighted average price for all milk
marketed in the market order area.
The marketing order prices for manufactured product uses are generally uniform
throughout the country, and are based on the prices currently being paid by dairy product
manufacturers in the Minnesota-Wisconsin (M-W) area. By establishing the floor with these
M-W prices, the milk support program influences the prices received by dairy farmers under
the milk marketing orders. In times of milk surplus, when CCC purchases are setting the
market price for butter, cheese, and nonfat dry milk, changes in the support price will directly
influence the M-W price series, and hence the prices received by farmers through the
marketing orders.
The marketing order prices for fluid milk use varies from area to area. A "differential"
for each marketing order area is added to the price for manufactured product uses. The
differential generally rises with the geographical distance from the Upper Midwest, which has
traditionally been a milk surplus area due to its low milk production costs. By adding a
differential for fluid milk use, the incentive for dairy producers to ship fluid milk products from
milk surplus areas to other areas is reduced or eliminated. The resulting effect of the
differential system is to encourage local milk production to serve most or all of local fluid milk
demand, while allowing milk surplus regions (i.e., those areas with the lowest costs of
production) to produce milk for the manufactured products market. In other words, the
system enables dairy farmers in high-cost production areas (e.g., Florida) to produce milk to
satisfy local fluid milk demand, but provides no incentive for high-cost producers to produce
milk for manufactured product uses (such as cheese, butter, and nonfat dry milk).
During the mid-1970s congressionally-mandated increases in the support price
encouraged such large production increases that chronic, rather than seasonal, surpluses
resulted (Chite 1990). CCC purchases for dairy products peaked in 1982/83 with outlays
exceeding $2.5 billion. The milk pricing system came under criticism for causing the surplus,
maintaining artificially high prices, and leading to large federal budget expenditures for CCC
purchases. Since the late 1980s the purchases by the CCC have been more modest, as
overall milk production and demand have been relatively well balanced.
The design and implementation of the milk pricing system affects the incomes of U.S.
dairy farmers and the prices of all U.S. milk products. Due to the regional nature of the U.S.
dairy industry, the program also has impacts on the regional distribution of income: five
states account for about 50 percent of milk produced in the U.S. (Wisconsin, California, New
York, Minnesota, and Pennsylvania), and 10 states account for about two-thirds (USDA 1990).
Eight states surrounding the Great Lakes account for nearly 50 percent of U.S. production
(Indiana, Illinois, Michigan, Minnesota, New York, Ohio, Pennsylvania, and Wisconsin) (USDA
1990).
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The milk pricing system affects methane emissions by influencing the quantity of milk
produced. Chronic surplus production, such as occurred from the late 1970s through the
middle 1980s, contributes to excess methane emissions. To limit methane emissions from
this sector, the supply-demand balance must be maintained over the long term. Because
milk production per cow continues to increase, and could increase more rapidly in the future
as the result of efforts to improve productivity (e.g., using bST and other techniques), dairy
cow numbers and dairy farm numbers must continue to decline to maintain the supply-
demand balance in the U.S.
While overall supply and demand have been relatively well balanced in recent years,
data indicate that there is currently an imbalance in the supply and demand for milk compo-
nents (Chite 1990). As consumers have shifted away from whole milk to low fat and nonfat
milk and to low fat and nonfat milk products, the relative demand for the fat and nonfat
components of milk12 has changed, so that there is currently a chronic over-supply of milk
fat. This surplus manifests itself in terms of CCC purchase prices, which show a continuing
decline in butter prices and increases in nonfat milk prices. 3
Assuming consumers continue to demand low fat products, this excess production of
fat can persist because under the marketing order framework dairy farmers are paid for their
milk on the basis of its fat content.14 Historically, consumer demand for the fat and nonfat
components of milk coincided well with the proportion of each in the raw milk produced by
farmers. Consequently, the fat-based pricing system did not cause a distortion. However,
with the recent shift in consumer preferences away from fat, the pricing system improperly
gives dairy farmers the incentive to increase their production of fat, without providing any
incentive to increase the relative production of nonfat milk components.
This imbalance is starting to be recognized, and steps are being taken in some
marketing orders to remove the incentive to over-produce fat. While maintaining overall
support prices and incomes for dairy farmers through the existing programs, several
marketing orders are shifting to a "component pricing" formula that pays farmers for the
nonfat component of milk as well as the fat component.15 For example, starting in 1992,
the Arizona marketing order prices the fat and protein components of the milk separately. At
1992 prices, the fat price was only about one third the protein price ($0.87 per pound as
contrasted with $2.73 per pound). Under this pricing system, the price for raw milk with 3.6
percent fat and 3.3 percent protein would be $12.14 per 100 pounds of milk. Nearly 75
percent of this price is accounted for by the value of the protein. Consequently, it is more
The nonfat component of raw milk is protein and other solids, principally lactose.
13 Butter is principally made from the fat component of raw milk, and consequently is an indicator of the value
of the fat component of the milk. Cheese is made from the whole milk, including the fat and nonfat solids. The
protein content of the milk (which is a fraction of the nonfat solids) is important in determining the yield of the
cheese production process (increased protein improves yield). Nonfat dry milk powder is made from the nonfat
solids portion of the raw milk, and is consequently an indicator of the value of the nonfat solids portion of the milk.
14 Historically, raw milk from farmers was purchased on the basis of its fat content because it was easy to test
for fat and because it eliminated any incentive for farmers to increase their apparent milk volume by adding water.
Currently, fast and accurate methods are routinely used to test for the protein and nonfat solids contents of raw
milk as well as for the fat content.
15 Raw cow's milk in the U.S. is typically about 3.6 percent fat, 3.3 percent protein, 4.6 percent lactose, 87.7
percent water, and 0.8 percent other.
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valuable for dairy farmers to increase protein production than fat production under the new
pricing system.
This trend toward component pricing could have an important impact on methane
emissions from the U.S. dairy industry. Reduced emphasis on fat production and increased
incentives for nonfat solids production will lead to changes in dairy cow rations and genetics.
In particular, increased feeding of highly digestible grains improves protein production at the
expense of fat production. The grain diets shift rumen fermentation patterns toward
propionate production and away from acetate and butyrate production, which reduces
methane emissions per unit of carbohydrate fermented. Additionally, the fermented feed
energy intake necessary per unit of milk synthesized by the cow will decline slightly as the
result of the changing ratio of fat to protein in the raw milk because fat is more energy
intensive than protein.
The change in pricing will also affect dairy cow breeding. Sires are evaluated for both
fat and protein, and the sires with demonstrated higher protein production genetics will
increase in value.16 Assuming that the trend in the relative demand for protein and fat
continues, and the pricing system responds to this demand with the implementation of
component pricing, the genetic make up of the dairy cows will shift slowly toward higher
protein producers.
While genetic characteristics for fat and protein production appear to be related, there
is opportunity for protein production to be improved relative to fat production. For example,
among the 209 highest rated Al bulls in the U.S., the correlation between predicted
transmitting ability (PTA) for fat and protein is only about 0.15.17 As shown in Exhibit 5-12,
there is a wide range of protein PTAs for any given fat PTA. Considering that protein has not
been an important factor driving genetic selection to date, it would appear that the existing
diversity in the available genetic characteristics could support improvement in protein PTA
relative to fat PTA. Additional analysis of this issue is warranted, however.
The combined impact of the change in ration and the change in milk composition on
methane emissions per unit of milk produced could be significant. The increased use of grain
in the ration could reduce the portion of feed energy going to methane from about 6 to 7
percent to 5 to 6 percent, for a reduction in methane emissions of about 10 to 20 percent.
Larger reductions could be achieved if more grain were fed: 40 to 50 percent reductions in
methane excretion per unit of feed intake have been measured for the high grain diets
commonly used in feedlots. More modest reductions are expected because the dairy cow
rations would not include as much grain as the rations used in feedlots. In particular, grain
feeding would be limited by the need to maintain forage intakes to protect against acidosis
and related rumen conditions. Nevertheless, relative to rations used in most dairy herds,
there is opportunity to increase grain feeding in response to changes in milk pricing.
16 Sire rankings are starting to incorporate the importance of the higher value of milk protein, e.g., see Ewing
(1993).
17 This correlation coefficient was estimated for the 209 highest rated bulls listed in Hoard's (1993). These
bulls represent the top 30 percent of active Al bulls in terms of the dollar value of their fat, milk, and protein PTAs.
PTA refers to the additional pounds of fat or protein that the daughter of the bull would produce relative to the
daughter of a bull with a PTA of zero. The genetic base was established by setting to zero the weighted average
PTAs of all cows born in 1985.
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Due to the differences in the energy required to synthesize fat and nonfat components
of milk, the energy density of the milk would also decline if protein production were
emphasized over fat production. This change in energy requirements would lead to an
additional reduction in methane emissions per unit of milk produced, because feed intake per
unit of milk produced would be reduced. The impact on methane emissions from this effect
has not been quantified, but it is likely to be small (less than a 5 percent reduction in
emissions per unit of product produced) assuming that the relative production of fat is only
reduced by about 10 percent or less. Larger reductions in the relative production of fat could
yield larger methane emissions reductions.
Exhibit 5-12
PTAs for Protein and Fat for the Top Active Al Bulls in the U.S.
O> t- 60
(fl O
ia in
1- T5
^ c 4D
"O O
si a
u
CD
i
Predicted Transmitting Ability:
Pounds of Fat
This figure shows that there is variability in the PTAs for fat and protein among the top
209 active Al bulls in the U.S. The correlation between the fat and protein PTAs is 0.15.
Source for the data: Hoard's (1993).
Beef Marketing
Unlike the dairy industry, there are no direct government interventions in the pricing of
live cattle or beef for purposes of supporting producer incomes or maintaining an orderly
market. Live cattle are managed in cow-calf operations, background or "stocker" operations,
and feedlots, prior to sale to meat packers. Cattle may be bought and sold several times
prior to sale to a packer. Alternatively, some producers may retain ownership of their cattle
through all phases of production prior to sale to a packer.
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While nationally there are nearly a million cattle operations in all phases of the beef
cattle industry, the feedlots control the marketing of the cattle to packers. Among the
feedlots, a relatively small number account for a large fraction of total marketings. In 1990
about 200 large feedlots marketed about 45 percent of the feedlot fed cattle in the U.S. An
additional 800 feedlots accounted for about 30 percent of the marketed cattle. Over 42,000
smaller feedlots accounted for the remaining 25 percent of the feedlot fed cattle marketed.
The packer industry is similarly concentrated. While there are 50 to 100 local and
regional packers with packing plant capacities of 200 or more head per day, the market share
of four major firms has grown over the past 20 years to about 70 percent of the feedlot fed
cattle slaughtered annually. Typically, cattle are purchased by the packers from the feedlots.
Price information is readily disseminated, and consequently the bidding is generally described
as competitive, although the increased concentration in the packing industry has concerned
some producers.
Over the past five years it has become generally recognized within the beef industry
that the existing marketing system does not provide incentives for producers to respond
adequately to consumer preferences. Several factors contribute to this problem:
• The existing beef grading system is an inadequate measure of product
characteristics. In particular, the grading system does not adequately identify
tender and palatable low fat beef. As a consequence, the system promotes
unnecessary fat accretion during feedlot feeding (solely for purposes of
grading), which increases costs to producers and consumers.
The system used to buy and sell cattle does not transmit information to
producers (cow-calf operators, stockers, and feedlot operators) regarding the
final value of the beef produced from the cattle. Consequently, the market
does not provide the information needed for producers to improve cattle
characteristics. As a result, producers do not invest adequately in cattle
genetics (breeding programs) and management practices that improve the
value of the beef produced.
The beef industry has begun a "Value Based
Marketing" initiative to correct these
problems in the beef marketing system.
This initiative includes developing
The beef industry's "Value Biased Mar-
keting" initiative wl help reduce meth-
ane emissions from U.S. beef cattfe.
recommendations for modifying the grading
system to eliminate incentives for excess fat
accretion, working with packers to develop
programs to collect and provide information on carcass characteristics, and working with
retailers to quantify the value of purchasing beef with reduced quantities of fat.
The implications of these refinements to the beef marketing system for methane
emissions could be substantial. The industry estimates that about 2 billion pounds of excess
fat is produced each year which is trimmed from the meat before it reaches consumers
(Cross et al. 1990). This fat costs producers about $2 billion annually in feeding costs, and
does not contribute to the production of retail beef product. Eliminating this fat will reduce
feed intake and methane emissions.
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A steer requires about 14.2 Meal of gross energy feed intake to accrete a pound of
fat.18 Assuming that 4 percent of this gross energy intake would be converted to methane
under feedlot feeding conditions, the feed intake associated with the 2 billion pounds of
excess trimmable fat translates into about 85,000 metric tons of methane emissions.
Eliminating this excess fat would involve reducing the feeding time for the cattle as well. A
reduction of about 25 days of feeding time reduces methane emissions by about 35,000
metric tons.19 The total methane emissions associated with the 2 billion pounds of excess
trimmable fat is therefore about 120,000 metric tons per year, or 0.12 Tg.
The industry initiative also recognizes that the marketing system penalizes the most
efficient class of cattle grown: calves that are placed on feed immediately post-weaning
(Cross et al. 1990). USEPA (1993) estimates that the per head lifetime methane emissions
from these "weanling system" cattle are only about one-half the lifetime methane emissions
from "yearling system" cattle that move through a stocker program prior to being fed in the
feedlot.
Modifications to the marketing system currently under discussion (see, e.g., Kester
1993), would likely increase the use of the weanling system by providing a premium for
younger cattle with a "small" level of marbling. EPA (1993) estimated that in 1990 a large
majority of feedlot-fed cattle were managed as yearlings (about 80 percent). Currently, the
trend is toward shorter backgrounding periods and use of a weanling type approach to
feeding. Refinements to the marketing system are expected to reinforce and possibly
accelerate this trend so that the 20:80 split between weanling and yearling could change.20
If 80 percent of cattle were managed using the weanling system and 20 percent as yearlings,
methane emissions from this portion of the beef industry would be reduced by about 380,000
metric tons per year, or about 0.38 Tg.
5.2.3 Future Options for Reducing Emissions
Significant research and development is ongoing that will lead to further improvements
in livestock productivity and reductions in methane emissions per unit product produced.
The impact of these techniques on future U.S. methane emissions from livestock has not yet
been quantified. These techniques, and the impact they will have on emissions is as follows.
18 The caloric value of fat is about 9.4 kcal per gram (NRC, 1984). This translates into a need of 4,264 kcal of
net energy for growth (NE ) intake per pound of fat accreted. At a 17%:83% forage:concentrate ration (typical for
feedlots), the ratio of NE to metabolizable energy (ME) is 0.458, the ratio of ME to digestible energy (DE) is about
0.82 and the ratio of DE to gross energy (GE) is about 0.8. Therefore, the gross energy intake required per pound
of fat accreted is about: 4,264 •=• (0.458 x 0.82 x 0.80) = 14,192 kcal = 14.2 Meal.
19 The reduced feeding time of 25 days is reported in Cross et al. (1990). This estimate is consistent with the
2 billion pounds of excess trimmable fat being associated with 26 million marketed fed cattle annually, which gain
weight at 3 pounds per day near the end of their feedlot feeding: 2 billion Ibs +• (26 million x 3 Ibs/d) = 25.6 days.
Gross energy feed intake per day is estimated based on the maintenance net energy (NEm) intake requirement of
8,140 kcal per day, a NEm to ME ratio of 0.677, an ME to DE ratio of 0.82 and a DE to GE ratio of 0.8. A methane
conversion rate of 4 percent is used to estimate the methane emissions.
20 In conjunction with the shortening of the feeding time, genetic characteristics must be selected properly so
that product tenderness and payability do not suffer. In particular, with less excess fat accretion, the marketing
system must develop a means of measuring and communicating reliable information on tenderness.
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Twinning. Twinning could redue the number of cows required to produce a given
number of calves. Because beef cows account for a significant portion of total U.S. methane
emissions from livestock, emissions reductions can be sizable as a result of twinning.
To date, selection for natural twinning has not held much promise because the
heritability of twinning is low (Ensminger 1987). Additionally, under current management
conditions twinning has not been a desired characteristic among beef cows because:
• heifers born twin with a male calf are often sterile;
• twin calves are generally lighter than single-birth calves; and
• cows that produce twins are more difficult to re-breed the following season.
Strategies for improving the productivity of twin births are being developed. Techniques to
inhibit the hormones that suppress twinning have been developed, enabling twinning to be
promoted or prevented as appropriate. For example, if excellent pasture conditions are
expected in the coming season, twinning may be promoted because adequate nutrition is
available. If poor pasture conditions are expected, single births would be preferred. Better
predictions of future forage conditions than are currently available would be essential for this
approach to be successful.
Options for improving the nutrition of cows carrying twins and of the twin calves are
also being developed to reduce the rate of stillbirths associated with twinning and to help
ensure the calves grow and mature quickly. At this time, twinning is not practical for
commercial operations. Cost-effective commercialized techniques for twinning are likely to be
available in the future. The techniques will likely be applicable to commercial beef production
situations in which there is reasonably good contact with the animals and for which
conditions are not too harsh.
Embryo transfer. Embryo transfer involves non-surgically removing a number of
embryos from a super-ovulated donor cow and transferring them to recipient cows for
gestation. This technique has grown rapidly in the dairy industry in the 1970s and 1980s
(Seidel and Elsden 1989), but has yet to become commonplace. To date, this technology
has not been used extensively in the beef industry.
Used by itself or in conjunction with embryo splitting (dividing a single embryo into
two so that two calves can be produced), the technique may enable the genetic material from
superior producing cows to be made available more widely. As such, the rate of genetic
improvement in dairy or beef cows could increase substantially. Before its use becomes
widespread, the cost of this technique must be reduced and its effectiveness improved so
that it can be commercially beneficial.
Defaunation. Defaunation (removal of rumen protozoa) may increase microbial cell
outflow from the rumen by 25-50 percent among animals on poor-quality forage-based diets.
Such an increase may reduce methane emissions per unit of carbohydrate fermented by
approximately 25 percent. Additionally, defaunation will improve the protein to energy ratio in
nutrients available to the animal and increase productive efficiency.
Anti-protozoal properties have been discovered in at least one type of natural forage.
Preliminary trials indicate that small amounts of this forage can successfully defaunate the
5-34
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rumen (Leng 1991b). Additional research is needed to demonstrate the safety and effective-
ness of defaunation agents.
Bioengineer rumen microbes. The efficiency of feed utilization and methane produc-
tion is principally controlled by the microbes in the rumen. Over the long term, it may be
possible to select or bioengineer specific microbes that improve feed utilization (thereby
reducing methane production indirectly) or suppress methanogenesis directly.
Significant research remains to be done so that microbes can be developed that will
enhance feed efficiency and reduce methane production directly or indirectly. For example,
to reduce methane production directly, research is needed in several areas, including:
determination of the key methanogenic species in animals on different diets;
correlation of methanogenic species and other rumen environmental factors
with levels of methane production; and
• identification of techniques to inhibit specifically-targeted methanogens without
adversely affecting animal performance.21
Given that genetic research on rumen microbes has only recently begun, there is
considerable potential for successful development of useful products. At this time, however, it
is premature to assess the costs and emissions reduction potential of this strategy.
Production enhancing agents. Additional production enhancing agents are being
developed that are expected to have commercially-valuable effects on growth, feed efficiency,
and carcass characteristics. Examples of compounds under investigation include
isoproterenol, and cimaterol (Muir 1988). To date these compounds, and similar related
compounds, have been demonstrated to improve growth rates and feed efficiency by up to
20 percent. Additionally, carcass characteristics are improved, including increases in protein
and decreases in fat.
The use of bST in growing beef cattle is also being investigated (Eisemann et al.
1986a and 1986b). Indications are that bST improves feed efficiency, growth rate, and lean
tissue accretion, all of which would help reduce methane emissions.
Other mechanisms are also being investigated to improve animal productivity. For
example, it has been determined that somatostatin (SS) inhibits somatotropin (ST) release. If
the inhibitory effects of SS could be prevented, additional growth could be achieved using the
animal's own supply of ST. One mechanism being explored is the development of a vaccine
that would cause antibody binding to SS, thereby reducing its inhibitory effect on ST release.
Considerable research remains to be done in this area.
Jransgenic manipulation. In the long term, transgenic manipulation, the transfer of
genetic material from one species to another, holds promise as a method for dramatically
improving the productivity of domestic livestock, including large ruminant animals.
21 A variety of pathways for inhibiting methanogens could be examined, including developing hydrogen-using
microbes that can out-compete the methanogens or developing microbes that produce an antibiotic that selectively
inhibits the growth of methanogens.
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Transgenesis research is largely aimed at developing new genomes through the manipulation
of genetic material using recombinant DNA, embryo manipulation, and embryo transfer
techniques (Leng 1991 a).
To date, emphasis has been placed on developing techniques for introducing DNA
that will promote the expression of growth hormone. Growth has already been accelerated in
transgenic mice carrying genes that lead to the production of growth hormone or the
expression of growth hormone releasing factor (Allen 1988). These characteristics have been
shown to be transmittable to subsequent generations. Considerable research remains,
however, before transgenic manipulation is used commercially in food producing animals.
While these and possibly other strategies are investigated for improving livestock
productivity and reducing methane emissions, the safety and wholesomeness of food
production will also be protected. As is the case with the current debate on the use and bST,
consumer acceptance will be one important factor affecting the adoption of new technologies
in the dairy and beef industries.
5.3 NATIONAL ASSESSMENT OF PROFITABLE METHANE REDUCTION
This analysis estimates the emissions reductions that can be achieved in the dairy and
beef industry using cost-effective techniques. The emissions reductions are estimated relative
to the baseline emissions estimates from USEPA (1993), which are based on a continuation
of current practices with current rates of productivity. For each option, the following analysis
was performed:
• A range of emissions reductions associated with implementing the option was
estimated in percentage terms based on the option's productivity or feed
efficiency effect.
The extent to which the option is currently used was quantified.
The extent to which the use of the option could be increased was estimated.
The emissions reduction was estimated based on the estimated incremental
implementation of the option, the emissions reduction in percentage terms from
using the option, and the baseline emissions estimate.
To estimate the total emissions reduction achieved with several options, the joint impacts of
the options were considered, so that the total emissions reduction is less than the sum of the
individual emissions reductions that could be achieved by each option.
One of the limitations of this analysis is that it does not consider the impact of
changing prices on demand. As the productivity of milk and beef production improve, the
relative price of these products may decline, thereby leading to increases in demand and
production. This effect is not expected to be significant, however, because the U.S. per
capita consumption of milk and beef are both relatively high already. Additionally, potential
changes in future per capita consumption and export are already considered in the baseline
assumptions.
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5.3.1 Dairy Industry
The major options for reducing methane emissions per unit of product from the dairy
industry are the use of bST and refinements to the milk pricing system. Additionally, the
continuation of increased production per cow will continue to contribute to reductions in
emissions. By 2010 these options can reduce methane emissions per unit product by 21 to
30 percent from 1990 levels. Because U.S. milk production is expected to increase by about
this same rate by 2010 (USEPA 1993), these options would maintain total methane emissions
from the dairy industry at 1990 levels.
Increased Production Per Cow. Continued genetic and management improvements
and the approval and use of bST will increase the average milk production per cow in the
U.S. If fully adopted, bST would increase average production per cow by about 1,800
pounds per year (about 12.2 percent of 1990 production levels). Adoption is not likely to be
complete, however. Fallert et al. (1987) estimate a range of adoption of 45 to 70 percent
within 6 years of introduction, depending on the support price for milk. This range is used
here to estimate adoption by the year 2000, which implies increases in production of about
810 to 1,260 pounds per cow per year. By 2010, the adoption rate is assumed to increase to
75 to 95 percent, which implies increases of 1,350 to 1,710 pounds per cow per year.
From 1970 to 1990, milk production per cow increased by about 240 pounds per year,
or at a constant rate of about 2 percent per year. This rate of increase is expected to
continue without the use of bST. Assuming a linear increase at 240 pounds per year, milk
production per cow would increase by 2,400 pounds per cow by 2000, and 4,800 pounds per
cow by 2010. Assuming that the growth continues at 2 percent per year compounded, milk
production per cow would increase by 3,230 pounds per cow by 2000, and 7,170 pounds per
cow by 2010. Exhibit 5-13 summarizes the estimates of future increases in milk production
per cow.
The increases in milk production per cow shown in the exhibit are reasonable when
compared with the increase in performance over the past 20 years and the performance
currently achieved at some dairies. The high estimate for 2010, with an increase in
production of 8,880 pounds per cow per year, implies a production level of 23,630 pounds
per cow per year. Some dairies already achieve average production rates well in excess of
this figure, and the best dairies are approaching 30,000 pounds per year per cow. In 1990,
33 percent of U.S. dairy cows were enrolled in programs to track and report production rates.
These 3.3 million cows had average production approaching 18,000 pounds per cow per
year, and had increased their production rate by about 285 pounds per year from 1975 to
1989 (USDA 1990). The performance of these cows show that the genetics and management
tools are available for the higher levels of productivity estimated for 2000 and 2010.
The estimated future increases in milk production allow the methane emissions
associated with maintenance feed intake to be spread over an increased level of production.
No reductions in the emissions associated with milk synthesis are estimated as part of these
increases in productivity, however. Because emissions associated with maintenance are
about 50 percent of total emissions (see Exhibit 5-7 above, and associated text), a 22 percent
5-37
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22
increase in production per cow reduces emissions by about 9 percent. The higher
increases in productivity produce larger emissions reductions per unit of product, up to 19
percent by 2010. Exhibit 5-13 summarizes the estimates.
ExhibitS-IS
Increases in Annual Milk Production Per Cow and Reductions in Methane Emissions
Per Unit Product: 2000 and 2010
(pounds per cow)
Increase due to bST Use
Adoption Rate (% of cows)
Increase in milk production (lbs/cow/yr)a
Increase due to improved genetics/management
(lbs/cow/yr)b
Total increase in milk production (Ibs/cow/yr)
(% increase from 1 990)
Annual milk production per cow (pounds)0
Reduction in methane emissions per unit productd
2000
Low
45%
810
2,400
3,210
(22%)
1 7,960
9%
High
70%
1,260
3,230
4,490
(30%)
19,240
11%
2010
Low
75%
1,350
4,800
6,150
(42%)
20,900
15%
High
95%
1,710
7,170
8,880
(60%)
23,630
19%
a Estimated as the adoption rate times 1,800 pounds per cow per year expected from using bST.
b Estimated as the continuation of the trend from 1970 to 1990. The low estimate assumes a linear increase
over time at 240 pounds per year. The high estimate assumes an exponential increase at 2 percent per year.
c Estimated using the 1990 production rate of 14,750 pounds per cow per year.
d Estimated by spreading emissions associated with maintenance intake over the larger production level. In
1990, emissions associated with maintenance were estimated to be 50% of total emissions.
Refinements to the Milk Pricing System. Modifying the milk pricing system to provide
incentives for protein production as contrasted with fat can reduce emissions by 10 to 20
percent as the result of changes in ration formulations. This refinement to the pricing system
has begun, and could be completed by 2000 if given priority. Consequently, this level of
emissions reduction is achievable nationally. These reductions apply only to the emissions
from the dairy cows during lactation, however, which account for about 70 percent of the
The emissions reduction is estimated based only on the dilution of maintenance feed intake across a larger
level of production. The implications of changing rations in order to achieve the higher milk production rates are
not included here because ration changes are evaluated separately in response to refinements to the pricing
system. Therefore, the emissions reduction is estimated using the following formula:
1 - (maintenance emit % + production emit % x (1 + production increase %)) / (1 + production increase %).
Using a 22 percent increase in production per cow, with 50 percent of emissions due to maintenance, results in the
following estimate:
1 - (0.5 + 0.5 x (1 + 0.22)) / (1 + 0.22) = 0.09 = 9 percent reduction in emissions per unit product.
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emissions from the dairy industry. Consequently, the emissions reductions are on the order
of 7 to 14 percent of total industry emissions.
The emissions reductions from refining the pricing system only apply to the emissions
that remain following the increase in production per cow. Consequently, the total possible
emissions reduction is not simply the sum of the percentage reductions from the refinements
to the pricing system and the increased rates of production per cow. Exhibit 5-14
summarizes the range of emissions reductions achievable by the combination of the methods.
As shown in the exhibit, a 15 to 23 percent emissions reduction per unit of product is
achievable by 2000, and a 21 to 30 percent reduction is achievable by 2010. When the low
and high estimates of the emissions reductions are both applied to the low and high
estimates of future emissions, the resulting estimates of future emissions are at or below the
estimate for 1990 emissions. Consequently, although milk production in the baseline is
estimated to increase by 20 to 32 percent by 2010, total methane emissions from the dairy
industry can be maintained at or below current levels, if total national milk production grows
more slowly than projected, methane emissions can be reduced in absolute terms.
Exhibit 5-14
Emissions Reductions in the Dairy Industry
1990
Low
High
2000
Low
High
2010
Low
High
Reduction in Methane Emissions Per Unit Product (%)
Increased Production Per Cow
9%
11%
15%
19%
Refinements to the Milk Pricing System
7%
14%
7%
14%
Total8
15%
23%
21%
30%
Estimated Future Methane Emissions from the Dairy Industry (Tg)
Baseline Emissions
1.2
1.8
1.4
2.0
1.4
2.4
Emissions Reduction0
0.2-0.3
0.3-0.5
0.3-0.4
0.5-0.7
Reduced Emissions'^
1.2
1.8
1.1-1.2
1.5-1.7
1.0-1.1
1.7-1.9
a The total emissions reduction is estimated as follows: [1 - (1 - P) x (1 - M)], where P = the emissions
reduction associated with increased production per cow, and M = the emissions reduction associated with
refinements to the pricing system.
b Baseline emissions are estimated in USEPA (1993) based on a continuation of current practices. The
baseline includes expected increases in milk production due to increased domestic consumption and
increased exports. Increased production is estimated at 12 to 14 percent by 2000 and 20 to 32 percent by
2010
c Emissions reduction calculated as the total emissions reduction in percent times the baseline emissions.
d Reduced emissions calculated as the baseline emissions minus the emissions reduction.
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5.3.2 Beef Industry
The major methods for reducing methane emissions from the beef industry are to
refine the marketing system, improve cow-calf productivity, increase the use of ionophores
where appropriate, and increase the use of implants where appropriate. By 2010, the
combined use of these options can reduce emissions per unit product by about 15 to 25
percent from 1990 levels. If total U.S. beef production remains fairly constant over this time
period, total methane emissions from the beef industry can be reduced from 1990 levels by
as much as 0.6 to 1.0 Tg.
Refinements to the Beef Marketing System. Refinements to the beef marketing system
will enable excess trimmable fat to be eliminated and will allow the weanling system for
feedlot fed cattle to be used more extensively. As estimated above, the excess trimmable fat
is associated with about 0.12 Tg of methane emissions, or about 11 percent of emissions
from the feedlot fed cattle. It is unlikely that all of the excess trimmable fat can be eliminated.
One industry recommendation has been to eliminate 20 percent of the excess trimmable fat
by 1995 (Cross et al. 1990). For purposes of this analysis, a range of 50 to 75 percent
reduction in excess trimmable fat is used for both 2000 and 2010. Using this range, emis-
sions from feedlot fed cattle would be reduced by about 5 to 8 percent per unit of
product.23 Additional analysis of the most profitable level of fat elimination is warranted. In
light of expected improvements in genetic selection for tenderness, greater elimination of
excess trimmable fat may be feasible.
The extent to which the backgrounding period continues to decline depends on how
the rapidly-fed cattle perform on the carcass characteristic measures that are developed to
implement Value Based Marketing and the relative values for several key costs: feedlot feeds
(grains), grazing land, and interest payments. Assuming that the rapidly-fed cattle perform
well in terms of carcass characteristics, relatively low grain prices will tend to promote larger
increases in the use of weanling system. When grazing land costs are low, longer
backgrounding programs may be favored. High interest rates increase the value of moving
the cattle to market faster, which favors using the weanling system.
It is expected that it would not be profitable to switch completely to the weanling
system. Given the types of changes to the marketing system that are likely, the current
20%:80% mix of weanling:yearling production is estimated to shift to a range of 50%:50%
(low) to 80%:20% (high). A shift to 50 percent weanling and 50 percent yearling would
reduce feedlot fed cattle emissions per unit product by about 17percent, and a shift to 80
percent weanling would reduce emissions by about 34 percent. The age at marketing
would therefore be shifting from the 1990 estimate of just under 18 months to about 15 to 16
months. This shift seems plausible given the current trend toward shorter backgrounding
periods.
23 The emissions reduction estimate is computed as: 50% x 11% = 5.5% (low estimate of 5%) and
75% x 11% = 8.25% (high estimate of 8%).
24 The emissions reductions are based on the emissions factors for the weanling and yearling systems
reported in USEPA (1993), of 23.5 kg and 47.6 kg per head respectively. With 20 percent of the feedlot fed cattle
produced using the weanling system the average emissions factor is 42.8 kg per head. The shift to 50 percent
using the weanling system yields an emissions factor of 35.6 kg per head, or a 17 percent reduction. The shift to
80 percent using the weanling system yields an emissions factor of 28.3 kg per head, or a 34 percent reduction.
5-40
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Increased Use of lonophores and Implants Among Feedlot Fed Cattle, lonophores and
implants are currently routinely used in nearly all the large feedlots. Byers (1992a) reports
that over 90 percent of cattle in feedlots receive ionophores and implants. The effects of
these technologies on emissions are already considered in the baseline emissions estimates
(USEPA 1993). Consequently, additional emissions reductions are not expected.
However, the use of implants in cattle prior to reaching the feedlot could be increased.
Byers (1992a) reports that implants are only used in about 30 to 40 percent of calves that will
be feedlot fed and in about 50 to 60 percent of the stocker cattle that will be feedlot fed. As
presented above in Exhibit 5-9, expanding the use of implants to include both the calf and
stocker phases of production would reduce emissions by an additional 4 percent per unit
product over using implants only in the feedlot phase. Because implants are already used to
some extent, the emissions reduction is estimated here as 0 to 2 percent per unit of product,
with the lower bound (0 percent) implying no additional use of implants in cow-calf and
stocker operations.
Increased Use of lonophores in Cow-Calf Operations, lonophores are seldom used in
cow-calf operations. Byers (1992a) reports that only 5 to 10 percent of cattle in cow-calf
operations receive ionophores. The 5 to 10 percent feed efficiency gain from ionophores
would reduce emissions by a like amount from the cow-calf sector if ionophores were used
routinely. However, the cost of delivering the ionophores to the cattle will limit the implemen-
tation of this technique. A ruminal release device would make ionophores more widely cost
effective for use in cow-calf operation. For this analysis, 50 percent of the potential of this
technique is adopted for the estimates, implying a 2.5 to 5 percent reduction in emissions per
unit product.
Improved Cow-Calf Productivity. In most regions of the U.S., cow-calf sector productiv-
ity is reasonably high, conforming to general industry performance goals. Byers' (1992a)
summary of the productivity of the sector by region shows that the Southeast, which
accounts for about 27 percent of the mature beef cows, has a relatively low level of productiv-
ity in terms of calves weaned and heifers that calve at 24 months (see Exhibit 5-15). The
relatively low productivity level leads to higher than average methane emissions per unit of
product produced by this sector.
Byers' data show that regional cow-calf sector productivity is correlated with the extent
of energy, protein and mineral supplementation (correlation coefficients are 0.71 and 0.69 for
percent of cows weaning a calf and percent of heifers calving at 24 months, respectively). No
correlation was found with farm size in terms of number of head. The Southeast has the
lowest reported utilization of energy, protein, and mineral supplementation in the country for
all farm sizes (see Exhibit 5-15). Consequently, Byers (1992a) concludes that the lack of
energy, protein, and mineral supplementation in the Southeast is the likely cause of the
relatively low level of cow-calf sector productivity.
Based on Byers' recommendation, improved nutritional management in the cow-calf
sector in the Southeast should improve performance. Use of these techniques is expected to
be profitable for most producers. The industry's Value Based Marketing initiative will
strengthen incentives for cow-calf producers to improve productivity and performance. As a
25 The Southeast region is defined in Byers (1992a) as: Virginia; West Virginia; North Carolina; South Carolina;
Georgia; Florida; Alabama; Tennessee; Kentucky; and Mississippi.
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companion, education and outreach are recommended for improving management in this
region. Specific education and outreach tools are needed that are suited to the special
needs of the producers in this region, many of which are relatively small.
Exhibit 5-15
Regional Cow-Calf Productivity
Region
Southeast
Other Regions
U.S. Total
Beef Cows in
Region
(% of U.S.)
27%
73%
100%
% of Cows that
Wean a Calf
Annually
69%
83%
79%
% of Heifers
that Calve at 24
Months
50%
82%
74%
% of
Cows/Heifers
that Receive
Protein/Energy
Supplements
44%
71%
64%
% of
Cows/Heifers
that Receive
Mineral Sup-
plements
72%
94%
88%
Source: Byers (1992a).
As shown above in Exhibit 5-11, improving cow-calf productivity from the level found in
the Southeast to typical industry goals of 85 percent of cows weaning a calf and 75 percent
of heifers calving at 24 months reduces the number of cows needed to produce a given
number of calves. Methane emissions per unit product are reduced by about 25 to 35
percent by improving productivity from the average level in the Southeast to typical industry
goals. Given that the Southeast has 27 percent of the beef cows in the cow-calf sector in the
U.S. (Exhibit 5-15), total emissions from the cow-calf sector in the U.S. could be reduced by
about 7 to 9 percent if steps to improve cow-calf sector productivity in the Southeast are
successful.
Exhibit 5-16 summarizes the methane emissions reductions that can be achieved in
the beef industry by the combination of these techniques. Relative to the baseline emissions
estimates, emissions from the backgrounding/feedlot sector can be reduced. Relative to
1990, emissions can be held constant or reduced in absolute terms. These emissions
reductions are driven principally by the changes in beef marketing that lead to reductions in
fat accretion and the increased use of weanling production as contrasted with yearling
production.
Similar results are shown for the cow-calf sector. Relative to 1990, emissions can be
held constant or reduced in absolute terms. These emissions reductions are derived principal-
ly from improved reproductive performance achieved through better nutritional management,
specifically in the Southeast region.
5.3.3 Total Methane Emissions Mitigated
The combined impact of the emissions reduction techniques prevents methane
emissions from cattle from increasing in the future and may lead to emissions reductions from
1990 levels. Exhibit 5-17 summarizes the estimates of future emissions. If emissions
reductions achieved are on the low end of what is estimated, emissions may be reduced by
5-42
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Exhibit 5-16
Emissions Reductions in the Beef Industry
1990
Low
High
2000
Low
High
2010
Low
High
Backgrounding/Feedlot Sector: Reduction in Methane Emissions Per Unit Product (%)
Beef Marketing:
Eliminate Excess Trimmable Fat
Increased Use of Weanling System
Beef Marketing Subtotal3
Increased Use of lonophores
Increased use of Implants (as calf and during •
backgrounding)
Total6
-
--
--
-
-
—
--
--
5%
17%
21%
0%
0%
21%
8%
34%
39%
0%
2%
40%
5%
17%
21%
0%
0%
21%
8%
34%
39%
0%
2%
40%
Backgrounding/Feedlot Sector: Estimated Future Methane Emissions (Tg)
Baseline Emissions0
Emissions Reduction1*
Reduced Emissions6
0.9
—
0.9
1.3
--
1.3
0.9
0.2-0.4
0.5-0.7
1.5
0.3-0.6
0.9-1.2
0.9
0.2-0.4
0.5-0.7
1.5
0.3-0.6
0.9-1.2
Cow-Calf Sector: Reduction in Methane Emissions Per Unit Product (%)
Increased Use of lonophores
Improved Reproductive Performance
Total*
-
—
-
-
—
--
2.5%
7%
9%
7.5%
9%
16%
2.5%
7%
9%
7.5%
9%
16%
Cow-Calf Sector: Estimated Future Methane Emissions (Tg)
Baseline Emissions0
Emissions Reduction01
Reduced Emissions6
2.3
—
2.3
3.5
—
3.5
2.5
0.2-0.4
2.1-2.3
4.0
0.4-0.6
3.4-3.6
2.2
0.2-0.3
1.9-2.0
3.9
0.4-0.6
3.3-3.5
a Emissions reduction for beef marketing is estimated as follows: [1 - (1 - F) x (1 - W)], where F = the
emissions reduction associated with eliminating excess trimmable fat and W = the emissions reduction
associated with increased use of the weanling system.
b Emissions reduction for feedlot-fed cattle is estimated as follows: [1 - (1 - M) x (1 - 1) x (1-P)], where M =
the emissions reduction associated with beef market ng changes, I = the emissions reduction associated with
increased use of ionophores; and P = the emissions reduction associated with increased use of the implants.
c Baseline emissions are estimated in USEPA (1993) based on a continuation of current practices. The
baseline includes a range of potential changes in beef production.
d Emissions reduction calculated as the range in total emissions reduction in percent times the baseline
emissions.
e Reduced emissions calculated as the baseline emissions minus the emissions reduction.
f Emissions reduction for the cow-calf sector is estimated as follows: [1 - (1 - 1) x (1 - R)], where I = the
emissions reduction associated with increased use of ionophores and R = the emissions reduction associated
with improved reproductive performance.
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Exhibit 5-1 7
Total National Livestock Emissions Reductions
1990
Low
High
2000
Low
High
2010
Low
High
Baseline Emissions (Tg)
Beef Industry
Backgrounding/Feedlot Sector
Cow-Calf Sector
Dairy Industry
Others
Total3
0.9
2.3
1.2
0.2
4.6
1.3
3.5
1.8
0.4
6.9
0.9
2.5
1.4
0.2
5.0
1.5
4.0
2.0
0.4
7.9
0.9
2.2
1.4
0.2
4.8
1.5
3.9
2.4
0.4
8.2
Estimated Future Methane Emissions With Emissions Reduction Techniques (Tg)b
Beef Industry
Backgrounding/Feedlot Sector
Cow-Calf Sector
Dairy Industry
Others
Total
0.9
2.3
1.2
0.2
4.6
1.3
3.5
' 1.8
0.4
6.9
Total Emissions Reduction (Tg)
Total Emissions Red'n Relative to 1 990 (Tg)
(% Reduction Relative to 1 990)
0.5-0.7
2.1-2.3
1.1-1.2
0.2
3.9-4.4
0.6-1.1
12-22%
0.2-0.7
4-15%
0.9-1.2
3.4-3.6
1.5-1.7
0.4
6.2-6.9
1.0-1.7
13-22%
0.0-0.7
0-10%
0.5-0.7
1.9-2.0
1.0-1.1
0.2
3.6-4.0
0.8-1.2
17-25%
0.6-1.0
12-22%
0.9-1.2
3.3-3.5
1.7-1.9
0.4
6.3-7.0
1.2-1.9
15-23%
(0.1)-0.6
(1)-9%
a Totals may not add due to rounding.
b The ranges of emissions estimates for 2000 and 2010 are estimated by applying the low and high estimates
of emissions reductions (in percent) to the low and high baseline emissions estimates.
Baseline estimate from USEPA (1993).
up to 0.7 Tg. If the high end of the emissions reduction potential is achieved, emissions will
be reduced from 1990 levels by about 0.6 to 1.0 Tg. Overall, emissions can be reduced by
about 12 to 25 percent from baseline levels.
5.4 BARRIERS
There are a variety of informational, institutional, and other barriers that must be
overcome to achieve the emissions reductions estimated above. Most of these barriers can
be overcome with research and outreach to key producers.
5-44
-------
Dairy Industry
The main options for reducing methane emissions from the dairy industry are to
increase the milk production per cow and to refine the pricing system. The majority of the
increase in milk production per cow is anticipated as a result of the continuation of the trend
observed over the past 20 years. Continued improvement in management and genetics are
required in order to achieve this goal. These improvements are likely.
The use of bST is also estimated to contribute to improved productivity and reduced
methane emissions. In addition to FDA approval, which is required before bST can be used
in the U.S., consumer acceptance of its use is also required. Currently, some groups are
advocating that bST not be used, and intend to limit the adoption of bST. Education and
outreach programs could be conducted to inform consumers about the safety and
effectiveness of bST. These steps could help ensure that bST can be used by those
producers that find it profitable.
Changes to the milk pricing system must be approved under individual milk marketing
orders. Movement toward this approach has started. Information exchange among regions
and focused analyses of the effects of changes in the regions that have modified their pricing
system may help accelerate the trend. To be fully effective, these pricing system changes
must also be reflected in the manner that dairy cooperatives pay their members for the milk
they produce. Based on discussions with cooperative representatives, it is likely that
changes in the pricing system will be reflected by cooperatives in a timely manner.
To realize fully the emissions reduction associated with the change in the pricing
system, data are required that demonstrate how ration adjustments improve milk protein
synthesis, and these data must be integrated into ration formulation software. As a priority,
available data on the impacts of ration formulation on protein synthesis should be reviewed,
and summarized. Gaps in data needed for formulating protein-enhancing rations in key dairy
regions should be identified. Most importantly, these data must be added to the software
used by nutritionists to formulate dairy rations. The current software is based exclusively on
maximizing profit based on milk quantity and fat pricing. Protein pricing requires that the
response of protein synthesis to various ration formulations be quantified.
Beet Industry
The main options for reducing methane emissions from the beef industry are the
refinements to the marketing system and improved cow-calf sector performance. The
refinements to the marketing system require that the information flow within the beef industry
be improved substantially. Better grading measures are required to relate beef quality to
objective carcass characteristics. Additionally, the improved carcass data must be collected
and used as a basis for purchasing the cattle so that the proper price incentives are given to
improve cattle quality and reduce unnecessary fat accretion.
The beef industry has several programs under way to achieve these objectives. With
the cooperation of the major meat packers, the cattle producers have initiated carcass data
collection programs that provide detailed data on carcass quality to participating producers.
With the involvement of 7 state universities, data on over 20,000 head of cattle were collected
during the first 9 months of the program in 1992 and 1993. These data will help producers
develop feeding and breeding programs to enhance the value of their cattle.
5-45
-------
Also, a major initiative is ongoing to educate retailers regarding the cost-effectiveness
of purchasing more closely trimmed beef (less trimmable fat). As these programs become
more widely adopted, the information needed to provide the necessary price incentives to
producers will become available. A modified grading system that is consistent with the new
information could also be useful, although it is not essential for the success of the Value
Based Marketing system. Recently, a revised grading system was rejected by one of the
major industry groups (Kester 1993). The process of resolving the objections to the revised
grading system could help unify producers and consumers behind appropriate measures of
carcass characteristics.
The principal barrier to improved productivity within the cow-calf sector is education
and training. The importance and value of better nutritional management and
supplementation must be communicated. Byers (1992a) recommends that energy, protein,
and mineral supplementation programs tailored for specific regions and conditions be
developed to improve the implementation of these techniques. The special needs of small
producers must also be identified and addressed. In particular, systems for delivering the
supplements that require less time and equipment would be valuable. For example, a ruminal
delivery device for ionophores and mineral supplements would make it easier for many cow-
calf producers to use these techniques. Similarly, programs for analyzing forage seasonally
would provide a basis for better matching supplementation decisions to nutritional needs.
5.5 LIMITATIONS
The principal limitation of this analysis is the lack of quantitative information needed to
link more closely the changes in the beef and dairy marketing systems to the changes in
production practices that are expected. The changes in production practices discussed
above can lead to significant reductions in methane emissions per unit of product produced.
The extent to which these practices will be adopted is uncertain. Detailed financial analyses
of key representative producers are needed to verify and improve the estimates.
The estimates also do not consider the impact that changing production practices
could have on demand. For example, improvements in beef production could lead to
increased demand and increased,production, which would offset partially or completely the
reductions achieved in emissions per unit product. Such interactions among production
practices, emissions, and demand are not considered.
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Bergen, W.G. and D.B. Bates. 1984. "lonophores: Their effect on production efficiency and
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the 7th International Symposium on Ruminant Physiology, Hakone, Japan, Japan
Scientific Press, Tokyo.
Blasi, D.A. and LR. Corah. 1993. "Make the Best Use Of Your Resources," Beef, , Vol. 29,
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Global Change Division, Office of Air and Radiation, U.S. EPA, August 24, 1992.
Byers, P.M. 1992b. Interim Report of: Analysis of Targeted Options to Enhance Efficiency
and Limit Methane/Unit Retail Product in Specific Beef Enterprises, Texas A&M
University, College Station, Texas, prepared for the Global Change Division, Office of
Air and Radiation, U.S. EPA, June 1, 1992.
CF Resources. 1991. 1991 CF Resources Cattle Industry Reference Guide, CF Resources
Inc., Englewood, Colorado.
Chalupa, W. 1977. "Manipulating Rumen Fermentation," Journal of Animal Science, Vol. 46,
pp. 585-599.
Chen, M. and M.J. Wolin. 1979. "Effect of Monensin and Lasalocid-Sodium on the Growth of
Methanogenic and Rumen Saccharolytic Bacteria," Applied and Environmental
Microbiology, Vol. 38, pp. 72-77.
Chite, R. 1990. The 1990 Farm Bill: Dairy Policy Issues, CRS Issue Brief, Congressional
Research Service, The Library of Congress, Washington, D.C., August 13, 1990.
Cornett, S. 1993. "Stockers Are Here To Stay," Beef, Vol. 30, No. 1, pp. 33-34.
Cross, H.R. et al. 1990. The War on Fat, A Report From The Value Based Marketing Task
Force, sponsored by the National Cattlemen's Association, the Beef Industry Council,
and the Beef Promotion and Research Board, August 1990.
Dellinger, C.A. and J.G. Ferry. 1984. "Effect of Monensin on Growth and Methanogenesis of
Methanobacterium Formicicum," Applied and Environmental Microbiology, Vol. 48,
pp. 680-682.
Dinius, D.A., M.E. Simpson, and P.B. Marsh. 1976. "Effect of Monensin Fed with Forage on
Digestion and the Ruminal Ecosystem of Steers," Journal of Animal Science, Vol. 42,
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Eisemann, J.H., A.C. Hammond, D.E. Bauman, P.J. Reynolds, S.N. McCutcheon, H.F. Tyrrell
and G.L. Haaland. 1986a. "Effect of Bovine Growth Hormone Administration on
Metabolism of Growing Hereford Heifers: Protein and Lipid Metabolism and Plasma
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Concentrations of Metabolites and Hormones," Journal of Nutrition, Vol. 116,
pp. 2504-2515.
Eisemann, J.H., H.F. Tyrrell, A.C. Hammond, P.J. Reynolds, D.E. Bauman, G.L. Haaland, J.P.
McMurtry, and G.A. Varga. 1986b. "Effect of Bovine Growth Hormone Administration
on Metabolism of Growing Hereford Heifers: Dietary Digestibility, Energy and Nitrogen
Balance," Journal of Nutrition, Vol. 116, pp. 157-163.
Ensminger, M.E. 1987. Beef Cattle Science, Interstate Printers & Publishers, Inc., Danville,
Illinois.
Ewing, M. 1993. "January 1993 Bull Proofs," Dairyman, Vol. 74, No. 3, pp. 17-20.
Failed, R., T. McGuckin, C. Betts, and G. Bruner. 1987. bST and the Dairy Industry: A
National, Regional and Farm-Level Analysis, Agricultural Economic Report Number 579,
Economic Research Service, U.S. Department of Agriculture, Washington, D.C.
Field, T. 1993. "Look For The Ail-Around Performer," Beef, Vol. 29, No. 7A, pp. 20-27.
Garrett, W.N. 1982. "The Influence of Monensin on the Efficiency of Energy Utilization by
Cattle," In: Energy Metabolism: Proceedings of the Ninth Symposium on Energy
Metabolism, Butterworths Publishers, London, p. 104-107.
Goings, R. and R. Bernett. 1993. "Feeding Yearling Dairy Heifers," The Dairyman, Vol. 74,
No. 4, pp. 15-19.
Hespell, R.B. 1987. "Biotechnology and modifications of the rumen microbial ecosystem,"
Proceedings of the Nutrition Society, Vol 46, pp. 407-413.
Hoard's. 1993. 'The Hoard's Dairyman Bull List, the top active A.I. bulls," Hoard's Dairyman,
Vol. 138, No. 14, pp. 605-610.
Hoffman, Mark S. 1991. The World Almanac and Book of Facts 1992. Pharos Books. New
York.
IPCC (Intergovernmental Panel on Climate Change). 1992. Climate Change 1992: The
Supplementary Report to the IPCC Scientific Assessment. Report prepared for
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Johnson, D.E., G.W. Ward, and J. Torrent. 1992. 'The Enviornmental Impact of Bovine
Somatotropin Use in Dairy Cattle," Journal of Environmental Quality, Vol. 21, No. 2,
pp. 157-162.
Johnson, D.E. 1992. Personal communication with Dr. Donald E. Johnson, Colorado State
University, Fort Collins, Colorado.
Kalter R.J. et al. 1985. Biotechnology and the Dairy Industry: Production Costs and Commer-
cial Potential, and the Economic Impact of the Bovine Growth Hormone. Prepared for
the Cornell University Center for Biotechnology, Committee for Economic Develop-
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Kenney, J.M. and R.F. Failed. 1987. Bovine Somatotropin. A Bibliography with Selected
Annotations. Commodity Economics Division, Economic Research Service, United
States Department of Agriculture. Washington, D.C. October 1987.
Kester, W. 1993. "Grading Resolution Scuttled," Beef, Vol. 29, No. 7, pp. 14-16.
Leng, R.A. 1991 a. Application of biotechnology to nutrition of animals in developing coun-
tries. FAO Animal Production and Health Paper 90, Food and Agriculture Organization
of the United Nations, Rome, Italy.
Leng, R.A. 1991 b. Improving Ruminant Production and Reducing Methane Emissions From
Ruminants by Strategic Supplementation. Office of Air and Radiation, U.S. Environmen-
tal Protection Agency, EPA/400/1-91/004, June 1991.
MIF (Milk Industry Foundation). 1991. Milk Facts. Milk Industry Foundation, Washington,
D.C.
V
Miller, W.L, J.A. Martial and J.D. Blaxter. 1980. "Molecular Cloning of DMA Complementary
to Bovine Growth Hormone," Journal of Biological Chemistry. Vol. 255, p. 7521.
Muir, Larry A. 1988. "Effects of Beta-Adrenergic Agonists on Growth and Carcass Character-
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Press, Washington, D.C., pp. 184-193.
NRC (National Research Council). 1984. Nutrient Requirements of Beef Cattle. National
Academy Press, Washington, D.C.
NRC (National Research Council). 1989. Nutrient Requirements of Dairy Cattle. National
Academy Press, Washington, D.C.
Odde, K. and P. Gutierrez. 1993. "High Level of Production Not Sole Profit Key," Beef,
Vol. 29, No. 7A, pp. 17-19.
Phillips, D.J., and J.M. Tadman. 1984. (Trichloromethyl)Pyridine Compounds Useful for
Promoting Growth and lor Improving Feed Utilization Efficiency in Ruminants. U.S.
Patent, No. 4,474,789, October 2, 1984.
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Monensin on Performance of Cattle Fed Forage," Journal of Animal Science, Vol. 43,
pp. 665-669.
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Monensin on Feed Efficiency of Feedlot Cattle," Journal of Animal Science, Vol. 43,
pp. 670-677.
Richardson, L.F., A.P. Raun, E.L. Potter, C.O. Cooley, and R.P. Rathmacher. 1976. "Effect of
Monensin on Rumen Fermentation in vitro and in vivo," Journal of Animal Science,
Vol. 43, pp. 657-664.
Seidel, G.E. and R.P Elsden. 1989. Embryo Transfer in Dairy Cattle, W.D. Hoard and Sons
Company, Milwaukee, Wisconsin.
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Tyrrell, H.F. et al. 1982. "Effect of growth hormone on utilization of energy by lactating
Holstein cows," Proceedings of the 9— Symposium on Energy Metabolism, Lillehammer,
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USDA (U.S. Department of Agriculture). 1990. Agriculture Statistics 1990, USDA, Washington,
D.C.
USEPA (U.S. Environmental Protection Agency). 1993. Anthropogenic Methane Emissions in
the United States, Report to the Congress, prepared by the Global Change Division,
Office of Air and Radiation, EPA, Washington, D.C.
Whitelaw, F.G., J. M. Eadie, LA. Bruce and W.J. Shand. 1984. "Methane Formation in
Faunated and Ciliate-Free Cattle and Its Relationship with Rumen Volatile Fatty Acid
Proportions," British Journal of Nutrition, Vol. 52, pp. 261 -275.
5-50
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CHAPTER 6
OPPORTUNITIES TO REDUCE METHANE EMISSIONS FROM UVESTOCK MANURE
Livestock Manure Methane Emissions Reductions
Share of U S
Emissions Reductions
7
6
5
4
)
3
2
1
O
-
- .1 . , -7
•
;
-3- -6
•*
3 . 1
S7B
'"
f
5 6
4 ". $
''
: ' • * *
3 2
'"2"<"Si
..:
-
•
f.
6 . 0
. 5-, 13
'-' -Ys
' i
f
}
s
^> j
Low H i gh
1990
Low H i gh
2OOO
Low H i gh
2O10
Prof i tab I e
Reduct. i ons
Rema. i n i ng
Emiss i ons
Livestock Manure Methane Emissions (Tg)
Year
1990
2000
2010
Baseline Emissions9
1.7-3.6
3.1 - 5.6
3.2 - 6.0
a Source: USEPA (1993). Emissions scenario
of liquid-based manure management systems
Technically Feasible
Emission Reductions
1 .7 - 4.4
1.7-4.7
Profitable Emission
Reductions
0.5 - 0.8
0.6-1.0
reflects continuation of the trend toward increased use
in the future.
CHAPTER SUMMARY
Methane is produced during the anaerobic
decomposition1 of the organic material in live-
stock and poultry manure. In 1990 livestock and
poultry manure in the U.S. emitted between 1.7
and 3.6 Tg of methane to the atmosphere, with a
central estimate of 2.3 Tg (USEPA 1993). Liquid
based livestock manure systems such as anaero-
bic lagoons produce about 80 percent of the
total. If, as expected, the use of liquid manure
management systems increases, then methane
emissions from livestock and poultry manure
could increase significantly in the next decade.
Methane recovery systems can collect the meth-
ane produced by liquid manure management
systems so that the methane can be used as a
fuel. With methane recovery systems it is techni-
cally feasible to reduce total methane emissions
from livestock manure by 80 percent to between
0.3 Tg and 0.7 Tg. Although technically feasible
for virtually all farms using liquid based manure
management systems, methane recovery systems
1 Anaerobic decomposition (fermentation) of animal waste is a micro-biological process that occurs in an oxygen free
environment.
6-1
-------
Chapter Summary
are only profitable for large farms in warm cli-
mates. At these farms, it is profitable to collect
the methane and use it to meet a portion of the
farm's energy requirements.
Methane recovery systems such
as covered anaerobic lagoons can
reduce total methane emissions
from livestock manure by 80 per*
cent, The recovered methane can
be used to produce electricity or :
to fuel gas-fired equipment such
as boilers or chHters. :
The technically feasible and cost-effective tech-
nologies for recovering methane include the
following:
Covered Anaerobic Lagoon: Anaerobic lagoons
are among the simplest manure storage and
treatment systems in current use. Methane is
produced in the lagoon by the biological process
that stabilizes the manure. By covering the
lagoon, the methane is recovered and can be
used as an on-farm energy source.
Plug Flow and Complete Mix Digesters:
Digesters have been used for many years in the
U.S. and other countries to produce energy from
livestock manure. Commonly, the digesters are
built as tanks (complete mix) or trenches (plug
flow). As the manure decomposes in the di-
gester, the methane is recovered and used for
fuel.
The recovered methane can be used to produce
electricity or can fuel gas-fired equipment such as
boilers or chillers. In addition to providing an
energy source, methane recovery systems are
consistent with environmental controls placed on
manure management facilities to protect ground
and surface water and to control odor.
Profitable Reductions
Profitable strategies to reduce methane emissions
generally involve collecting the methane and
using it as an on-farm energy source. The profit-
ability of these systems depends on the amount
of methane recovered, its value, and the cost of
installing the recovery system:
Methane Recovered. The amount of methane
recovered depends primarily on: the system
used to recover the methane (e.g., covered
lagoons versus digesters); the quantity and type
of manure being managed (e.g., dairy manure
versus swine manure); and the climate (warm
versus cold).
Value. The value of the methane depends on
how it is used. If the methane is used as an on-
farm energy source, the value of the methane is
the energy costs avoided by the farmer.
Cost of the Recovery System. The cost of install-
ing the recovery system depends on the design
of the existing manure management system and
other farm specific characteristics. In most cases
the cost of installing recovery systems will be
least for farms that already utilize liquid manure
management systems. In addition, covered
lagoons generally are more cost effective than
complete mix or plug flow digester systems.
swine ;farms al-
ready rise aftaeroblc lagoons to
manage manure and contain run-
off. Coverts these anaerobic
lagoons is potentially profitable for
about 4,W large dairy aw* hog
Because liquid manure systems are common on
dairy and swine farms (Safley et al. 1992), this
analysis focuses on profitable emission reduc-
tions on dairy and swine farms. In addition, dairy
and swine farms are increasingly using liquid-
based manure management systems, such as
lagoons, to comply with environmental regulations
under the Federal Clean Water Act (CWA). In
particular, because manure generally can be
easily and efficiently controlled and stored as a
liquid, many confined livestock operations such
as dairies and swine farms are complying with
the CWA regulations by utilizing anaerobic la-
goons to contain runoff and manage their ma-
nure.
6-2
-------
Chapter Summary
Covered lagoons are potentially profitable for
about 4,000 large dairy and hog production
facilities. Facilities with the following characteris-
tics are the best candidates for profitability: over
500 dairy cows or over 1,500 hogs; currently use
liquid or slurry manure management systems;
located in a relatively warm climate; and currently
pay relatively expensive energy prices. Specific
results are as follows:
In 2000 methane emissions can be reduced at a
profit to the farmer by 0.5 to 0.8 Tg.
In 2010 methane emissions can be reduced at a
profit to the farmer by 0.6 to 1.0 Tg.
Exhibit 6-1 summarizes these results.
These estimates are particularly sensitive to the
value of the recovered methane. In this analysis
the value of the recovered methane is based on
state-average residential electricity prices. Rela-
tively modest increases in the value of energy
result in large increases in the number of projects
that are expected to be profitable. For example,
an increase in electricity prices of $0.02 per
kiloWatt-hour (kWh) doubles the expected profit-
able methane reductions.
Regional Impacts
The number of dairy and hog farms with the
potential to recover methane for a profit varies
significantly from state to state. This regional
pattern is determined by three main factors:
Farm Size: Larger farms (in terms of number of
animals) find methane recovery more profitable.
The distribution of farm sizes varies significantly
by region.
Methane Production: Warmer climates lead to
more gas production in lagoons.
Energy Prices: Higher energy prices make
methane recovery more profitable.
While many states have the climate conditions
and energy prices that are conducive to profitable
methane recovery projects, relatively few states
have significant numbers of large farms. As a
result, a few states account for the majority of the
profitable emissions reductions.
At current prices for electricity most dairies re-
quire at least 500 head of milking cows to justify
the investment in a methane recovery system.
In the northern U.S., most dairy production
comes from relatively small farms, and cold
winters reduce methane production. Conse-
quently, although the northern U.S. accounts for
a significant portion of U.S. dairy production,
methane emissions reductions are not profitable
in this region. ' , contrast, large dairies are
common in sunbelt states such as California,
Texas, Arizona, and Florida. These states also
have favorable climates for methane production.
Methane recovery projects are profitable in
southern states, and are most profitable at Cali-
fornia and Arizona dairies.
At current prices for electricity most hog farms
require at least 2,000 head to justify the invest-
ment in a methane recovery system.3 Based on
the 1987 agriculture census, few states have a
significant number of hog farms with at least
2,000 head. Swine farms are primarily located in
the 'corn belt' states of Iowa, Illinois, Indiana, and
Missouri. In addition, the hog population in North
Carolina has grown substantially in the last
twenty years. More recently, large hog farms
have been developed in Virginia, but these were
developed after the 1987 census.
Because of their concentration of large hog
farms, Illinois and North Carolina account for
about 70 percent of the profitable emission
mitigation potential from hog farms. Additionally,
methane recovery projects are more profitable in
these two states because of the relatively high
electricity prices in Illinois and the relatively warm
climate in North Carolina. Although Iowa contains
by far the most hogs of any state, the potential
for profitable emission mitigation is small because
most Iowa hog farms are relatively small.
impact of Including Environmental Benefits
The analysis of profitable recovery projects does
not include the value of the environmental bene-
fits of recovering methane from livestock manure.
2 Assumes an average weight of 1,400 Ibs. per milking cow.
3 Assumes an average weight of 138 Ibs per hog.
6-3
-------
Chapter Summary
Exhibit 6-1
Methane Emissions from U.S. Livestock Manure and Profitable Emissions
(Tg per Year)
Year
1990
2000
2010
Emissions Without Recovery8
Dairy
0.6- 1.0
1.1-1.7
1.2-2.0
Swine
0.8 - 1 .4
1.7-2.6
1.6-2.6
Total
1.7-3.6
3.1 - 5.6
3.2 - 6.0
Profitable
Dairy
-
0.1 - 0.4
0.1 - 0.5
Reductions
Emissions Reductions15
Swine
-
0.4
0.5
Total
-
0.5 - 0.8
0.6- 1.0
a Emissions estimate from USEPA (1993). The emissions scenario reflects continuation of the trend
toward increased use of liquid-based manure management systems in the future. Total emissions
include other livestock as well as dairy and swine.
b Emissions reduction from profitable covered lagoon methane recovery and utilization projects at dairy
and hog production facilities. The emissions reduction scenario reflects continuation of the trend
toward increased use of liquid-based manure management systems and increased concentration of
animals on large production facilities.
These environmental benefits include not only
the reduction in methane emissions, but also
reductions in ground and surface water pollution
and air pollution. Adding the value of these
benefits improves the profitability of methane
recovery from manure systems.
For example, the cost of reducing carbon dioxide
(CO2) build up in the atmosphere has been esti-
mated in the range of $5 to $20 per ton of carbon
contained in CO2. With this range, the environ-
mental benefit of preventing methane emissions
from livestock manure translates into a value of
about $0.0086 to $0.0345 per kWh.4 In addition,
assuming that producing electricity displaces
fossil fuel produced CO2 at the rate of 1.5 Ib CO2
per kWh,5 then an additional benefit of $0.009 to
$0.0037 per kWh can be realized.6
Combining these two benefits, the total value of
recovering methane from livestock manure ranges
between $0.0095/kWh to $0.0382/kWh. This
value may be as high as $0.1910 if the benefit of
reducing CO2 emissions is as high as $100 per
ton of carbon contained in CO2.
These values do not include the value of reduced
water and air pollution from livestock manure.
Nevertheless, using these values as a range, the
addition of the value of the environmental benefits
indicates that methane recovery projects should
be pursued at most large hog farms. Because
most large dairy farms already are profitable
without consideration of these environmental
benefits, including these benefits does not have
a great impact on emission reductions from large
dairy farms.
4 The calculation is based on the global warming potential (GWP) of methane, the efficiency of converting methane
into electricity, and the value of reducing carbon dioxide emissions.
5 The figure of 1.5 Ib CcykWh is an average national emission factor based on total CO2 emissions from generating
electricity divided by the total amount of electricity produced.
The calculation is based on the amount of CO2 emissions that electricity displaces and the value of reducing carbon
dioxide emissions.
6-4
-------
Chapter Summary
to addition to reducing methane
odor pfoblero& associated wfth
* f •. '.. •.'• .. ._._•_
Effective Methane Reduction Strategies
The most viable option for reducing U.S. methane
emissions from livestock manure is to recover the
methane and to utilize it as an on-farm energy
source.7 Methane can be recovered from la-
goons by putting a cover over the lagoon and
withdrawing the gas that collects under the cover.
Another option is to use plug flow or complete
mix digesters to treat the manure and produce
methane. These recovery systems have been
demonstrated and are operational in the United
States to a limited extent. Anaerobic lagoons are
used to store and treat manure. As the manure
decomposes in the lagoons it produces methane
which can be captured by placing a floating,
impermeable cover over the lagoon. The meth-
ane can then be collected and used.
Plug Flow Digesters consist of a long trough built
below ground level with an air tight expandable
cover. The manure is collected daily and added
at one end of the trough. Each day a new "plug"
of manure is added, slowly pushing the other ma-
nure down the trough. As the manure progress-
es through the trough it decomposes and pro-
duces methane which is trapped under the
expandable cover and collected.
Complete mix digesters consist of a large air-tight
digester vessel in which manure is continuously
added and mixed. As the manure decomposes,
methane is trapped under a fixed cover from
where it is collected. The manure mixture is often
heated to speed the decomposition process.
Current Recovery and Utilization Projects
Over 20 methane recovery and utilization systems
are currently operating on private and university
livestock facilities across the U.S. These recovery
systems demonstrate the operational and eco-
nomic feasibility of covered lagoons, plug flow
digesters, and complete mix digesters. These
recovery systems have been designed specifically
for each livestock operation based upon the type
of livestock, number of livestock, manure man-
agement system, energy requirements, and
climate.
goons, plug flow and coertpJete
Barriers to Methane Recovery
As discussed above, profitable opportunities exist
for reducing methane emissions from livestock
manure. While there are many livestock opera-
tions at which methane recovery is apparently
viable, digester systems are often not undertaken
because of various barriers. Significant informa-
tional, economic, and regulatory barriers some
Alternatively, methane emissions can be reduced by using solid manure management systems at farms that currently
use liquid systems. Methane production Is minimal in solid systems because solid systems do not promote the
anaerobic conditions that lead to methane production. However, because liquid systems are widely utilized on swine
and dairy operations, these farms would have to shift to a solid system to achieve a significant reduction in methane
emissions. However, a shift towards solid based systems is inconsistent with current practices and expected trends.
Environmental regulations require proper manure storage and disposal on livestock operations, and swine and dairy
operations are complying with these regulations by storing their manure in anaerobic lagoons or slurry tanks or pits.
A shift towards alternative solid based manure management systems on swine and dairy operations would therefore
contradict current trends in the industry and could affect their ability to meet environmental regulatory requirements.
6-5
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Chapter Summary
times prevent the successful implementation of
methane recovery systems at livestock opera-
tions. Although informational barriers are specific
to methane recovery from livestock manure,
economic and regulatory barriers are common to
virtually all alternative energy sources (e.g.,
cogeneration, biomass, solar, and wind) and are
discussed more fully in Chapter 7.
The most important barrier to developing meth-
ane recovery projects is lack of information.
Many of the digester projects built in the early
1970s failed because of poor designs, improper
maintenance, or low energy prices. Operational
failures were primarily due to mechanical prob-
lems with the digesters and utilization equipment
and biological problems that restricted the
amount of methane produced. These failures
gave digesters the reputation of being an expen-
sive and mechanically dubious technology. Most
of these problems which limited the success of
commercial-scale digesters have been solved and
digesters are now a cost-effective and reliable.
However, because of past failures, the systems
must be demonstrated to show that the problems
that plagued the early digester systems have
been resolved. In addition to informational barri-
ers, economic, financial, and regulatory barriers
limit the adoption of methane recovery systems.
Economic barriers include low utility "buy back"
rates that limit the value of the biogas produced.
Financial barriers limit the ability of farmers to
borrow to purchase a biogas recovery and utiliza-
tion system. Regulatory barriers include air
emission standards that may restrict the use of
energy recovery equipment and manure system
permit modifications that are required in some
areas to add a methane recovery system to an
existing manure management system.
Opportunities are available for overcoming these
barriers. In particular, lack of information can be
overcome by providing information on the reliabili-
ty of the existing methane recovery projects. Low
utility "buy back" rates can be overcome by
emphasizing on-farm energy use that offsets
energy purchases. Financial barriers can be
overcome by providing lenders with information
on the reliability and profitability of recovery
systems. Regulatory barriers can be overcome
by providing regulators with information on the
environmental benefits associated with recovery
systems.
6.1 BACKGROUND
In 1990 the U.S. livestock industry marketed about $90 billion worth of meat, milk, and
fiber (Hoffman 1991). As a by-product of this production, the livestock industry generated
over one billion metric tons of manure (fresh). The majority of the livestock manure is
produced by dairy cattle (22%), beef cattle (61%), and swine (10%) (Based on Safley et al.
1992). To protect the environment, manure management systems that safeguard ground
and surface waters are now required at large confined animal production facilities in many
locations. As a consequence, the larger production facilities are now storing and treating
livestock manure in anaerobic lagoons and pits as a means to comply with federal and state
environmental requirements which place limits on the legal discharge of manure into surface
waters. These lagoons and pits are conducive to producing methane, and present an oppor-
tunity for the more widespread recovery of methane for energy production.
6.1.1 Livestock Manure Management and Methane Emissions
Manure management systems are designed to handle and dispose of manure without
threatening the health of the animals, the producer, the public, or the environment. To
achieve these objectives many management systems must store the manure because it
cannot be applied to the land year-round. In particular, manure can not be applied when the
land is wet or frozen or when crops are being grown. Such storage often results in anaerobic
conditions and methane formation (Loehr 1984).
6-6
-------
Liquid based manure management systems generate the majority of methane
emissions (Safley et al. 1992). These management systems include:
Liquid/Slurry Handling: Water is added so the manure can be handled as a
semi-liquid slurry. As a slurry the manure can be pumped and stored in tanks
or pits. Periodically the slurry is spread on land using tankers or other meth-
ods. Swine manure is typically handled as a liquid slurry, as is dairy manure
from the milking parlor and/or feed apron.
Liquid Handling: Water is added so that the manure is a free flowing liquid.
These systems are often designed so that water is used to flush manure from
the production areas periodically, such as once every three hours. The
water/manure mixture then flows into a storage area, such as a lagoon. The
lagoon water may be spread on land periodically using irrigation equipment or
may be treated and recycled for on-farm use (Loehr 1984). Dairy manure from
the milking parlor is typically handled as a liquid, as is swine manure.
Overall, liquid based systems manage about one-third of dairy manure and seventy-five
percent of swine manure (see Exhibit 6-2).
Non-liquid based management systems produce much smaller amounts of methane.
These systems include:
• Solid Handling: The manure is handled dry (i.e., without the addition of water),
such as in drylots. Periodically the manure is collected and spread on land.
The frequency of the spreading varies from daily in some cases to as seldom
as once a year in others. Manure is typically handled as a solid at beef cattle
feedlots, poultry facilities, and the drylot portion of dairies.
• Pasture and range: Animal production systems such as the grazing of cattle,
sheep, and goats, generally do not use a manure management system per se.
In these cases manure is deposited on the ground where it decomposes,
returning nutrients and organic matter to the soil.
Overall, non-liquid based systems manage virtually all beef cattle manure and most poultry
manure (see Exhibit 6-2).
In 1990 livestock and poultry manure in the United States emitted an estimated
2.3 Tg/yr (1.7 - 3.6 Tg/yr) of methane to the atmosphere, or about 15 percent of the world's
total emissions of about 14 Tg/yr from livestock manure (EPA 1993). Of the total 2.3 Tg/yr,
liquid systems account for 1.9 Tg/yr or about 80 percent of the yearly total. These emissions
are divided between dairy and swine farms as follows:
• Swine produce 1.1 Tg/yr or about 50 percent of the U.S. total emissions.
Dairy cattle produce 0.7 Tg/yr or about 30 percent of the U.S. total emissions.
6-7
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Exhibit 6-2
Livestock Manure System Usage
Animal
Non-Dairy Cattle
Dairy
Poultry8
Sheep
Swine
Other Animals6
Liquid
Anaerobic
Lagoons
0%
10%
5%
0%
25%
0%
Systems
Liquid/Slurry
and Pit
Storage
1%
23%
4%
0%
50%
0%
Daily
Spread
0%
37%
0%
0%
0%
0%
for the U.S
Solid
Solid
Storage
& Drylot
14%
23%
0%
2%
18%
0%
.
Systems
Pasture,
Range &
Paddock
84%
0%
1%
88%
0%
92%
Litter,
Deep Pit
Stacks
and Other
1%
7%
90%
10%
6%
8%
a Includes chickens, turkeys, and ducks.
b Includes goats, horses, mules, and donkeys.
Totals may not add due to rounding.
Source: Safley et al. (1992).
Exhibit 6-3 summarizes the estimates of methane emissions from livestock manure in 1990.
Several key states account for the majority of emissions from dairy and hog produc-
tion facilities (Exhibit 6-4). Emissions from dairy facilities are highest in the states of Califor-
nia, Texas, Missouri, Washington, and Wisconsin. Together, these states account for about
50 percent of total U.S. emissions from dairy cattle. Emissions from California alone,
however, account for about 25 percent of total dairy emissions. For hogs, emissions are
highest in the states of Missouri, Iowa, Illinois, North Carolina, and Indiana. Emissions from
hog facilities in these states account for about 50 percent of total U.S. swine emissions. The
states shown in the Exhibit 6-4 account for a large portion of the total dairy and hog
emissions primarily because they use liquid manure management systems. Wisconsin
(dairies) and Iowa (hog facilities) have large emissions primarily because they have large
populations of animals.
In the U.S. the use of liquid manure management systems is expected to increase in
the coming decades. The increasing use of liquid manure management systems will lead to
an increase in methane emissions from livestock manure. The reasons for this expected
increased use of liquid management systems include larger herd sizes that make it practical
to use automated (generally liquid) manure management systems and increased concern
over the effect of improper manure management on the environment. Emissions are
expected to grow to 3.1 to 5.6 Tg/yr by 2000 and 3.2 to 6.0 Tg/yr by 2010 (see Exhibit 6-1).
6-8
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Exhibit 6-3
U.S. Methane Emissions from Livestock Manure -
- s lli/Jiflriitii ^ tMat^iUMan6fA S^trtani TTufvf\
By moiiuic. 4vuuHi|jj&rUiuut O^SMHIM ^HJfjF'j
Solid Systems
Pasture/Range
Drylot
Solid Storage
Other
Total Solid Systems
Liquid Systems
Liquid/Slurry
Pit Storage
Anaerobic Lagoons
Total Liquid Systems
Total
1 - . ByywstockTypepg^
Beef
Dairy
Swine
Poultry
Other
Total
Source: USEPA (1993).
1990
-
0.12
0.03
<0.01
0.26
0.41
0.21
0.23
1.42
1.87
2.28
— X ^ i. ,
0.17
0.73
1.12
0.23
0.02
2.28
Exhibit 6-4
Dairy and Hog Facility Methane Emissions in Key States (1990)
Dairy
State
California
Texas
Missouri
Washington
Wisconsin
Other States
Total
Source: Developed from
Facilities
Emissions (mt/yr)
174,978
63,708
54,522
44,031
22,335
374,062
733,637
Hog
State
Missouri
Iowa
Illinois
North Carolina
Indiana
Other States
Total
USEPA (1993).
Facilities
Emissions (mt/yr)
127,050
117,518
113,213
103,261
90,224
572,011
1,123,276
6-9
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6.1.2 Trends in Livestock Manure Management
Manure management practices in the livestock industry are being reshaped by
environmental concerns. In particular, proper management of livestock manure can generate
the following benefits:
Reduced Surface Water Pollution. Untreated or partially treated manures have
a high Biochemical Oxygen Demand (BOD) level which is indicative of biologi-
cally unstable organic materials. On entering surface waters through runoff,
manure contributes to the depletion of the oxygen in water and to the eutrophi-
cation of rivers, lakes, and wetlands (Loehr 1984).
• Decreased Ground Water Pollution. The nutrient content of manure, primarily
nitrogen and salts, can impair both ground and surface water quality. High
nitrate concentrations in drinking water can cause diseases in humans (in
particular, Methemoglobinemia in infants) and animals (Loehr 1984).
Reduced Air Pollution. Partially treated manure emits strong odors, particularly
when wet, due to the formation of volatile organic acids, ammonia, and hydro-
gen sulfide. Odors have prompted legal action and a decline in the property
values in affected areas (George et al., 1985).
• Improved Human Health. Pathogens in manure can pose health risks to
humans. For example, Salmonella organisms have been found in livestock
manure and runoff from animal confinement operations (Loehr 1984).
Regulations have been promulgated requiring proper manure management practices to avoid
the adverse impacts livestock manure can have on the environment. In particular these
regulations have focused on protecting the surface waters of the United States.
Manure management is regulated under the Federal Clean Water Act (CWA). Section
502 of the CWA defines concentrated animal feed operations (CAFOs) as point sources
subject to the National Pollution Discharge Elimination System (NPDES) permit program (40
CFR 122.23).8 The Effluent Guidelines promulgated under the CWA require that there be no
discharge of any pollutant from a point source except as provided by a permit issued under
section 402 of the CWA. CAFOs may discharge pollutants only when "rainfall events, either
chronic or catastrophic, cause an overflow of process wastewater from a facility designed,
8 An animal feeding operation is a concentrated animal feeding operation (CAFO) if more than the following
number of animals are confined: 1,000 beef cattle; 700 mature dairy cattle: 2,500 swine each weighing over 25 kg;
or 1,000 animal units (animal units can be calculated for any animal feeding operation by adding the number of
slaughter and feeder cattle multiplied by 1.0, plus the number of mature dairy cattle multiplied by 1.4, plus the
number of swine weighing over 25 kilograms multiplied by 0.4, plus the number of sheep multiplied by 0.1, plus the
number of horses multiplied by 2.0.). Alternatively, if the animal feeding operation discharges pollutants into
navigable waters through a man-made ditch, flushing system, or similar man-made device or pollutants are
discharged directly into waters which originate outside of and pass over, across, or through the facility, then a
facility is defined as a CAFO if more than the following number of animals are confined: 300 beef cattle; 200 mature
dairy cattle, 750 swine each weighing over 25 kg; or 300 animal units (40 CFR Part 122, App. B).
6-10
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constructed and operated to contain all process generated wastewaters plus the runoff from a
25-year, 24-hour rainfall event9 for the location of the point source." (40 CFR 412.13).
The Effluent Guidelines require zero discharge of liquid or solid manure or the water
that falls on or through the following: manure covered lot surfaces; manure storage areas; or
feed storage facilities. The CWA does not prescribe how a facility is to meet the zero
discharge requirements and does not require the installation of lagoons or tanks. However,
the practical affect of the zero discharge requirement is that a facility must have the capacity
to store runoff up to and including the 25 year, 24 hour storm. Because any discharge, even
from a treatment facility, would violate the NPDES requirements, land application generally is
the most practical method of disposal of the manure or wastewater (Shuyler and Meek 1989).
It should be noted that smaller animal operations can also cause water quality problems,
particularly when several are located in the same watershed. While these smaller operations
are not subject to NPDES requirements, they may be subject to state regulation if they are
located in coastal areas and are subject to state regulation under the Coastal Zone Act
Reauthorization Amendments of 1990 (CZARA).
As farmers respond to the zero discharge requirements, certain practices have
evolved, including (Shuyler and Meek 1989):
Diversion of drainage before it comes into contact with manure to minimize the
volume of wastewater that must be managed.
• Construction of manure storage systems (e.g., lagoons and tanks) to allow for
the spreading of the manure at times when it is most favorable. This replaced
the practice of daily spreading which can cause problems in the winter when
the ground is frozen. In addition, the storage structures allowed for better
control of runoff than when the manure was simply piled outside the facility.
• Removal of solids from the wastewater (e.g., with separators) before it reaches
the manure storage system to minimize the need to clean out the storage
system.
To help livestock operations meet these requirements, "Best Management Practices"
(BMPs) have been established. The BMPs are designed to reduce water usage, control water
flow, and contain wastewater on the livestock operation. BMPs include wastewater contain-
ment facilities such as anaerobic lagoons, holding ponds, and storage tanks.
Because manure generally can be easily and efficiently controlled and stored as a
liquid, many confined livestock operations are complying with the CWA regulations by utilizing
anaerobic lagoons to contain runoff and manage their manure. In addition to storing the
manure, anaerobic lagoons also can efficiently treat the manure. A properly designed and
operated lagoon system can treat the manure without producing disagreeable odors. Treated
lagoon water can be applied to crops or the water may be recycled within the livestock
operation, for example, to flush manure into the lagoon system.
The 25-year, 24-hour storm event is the rainfall event with a probable recurrence interval of once in 25 years,
with a duration of 24 hours, as defined by the National Weather Service in technical Paper Number 40, "Rainfall
Frequency Atlas of the United States", May 1961, and subsequent amendments.
6-11
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Anaerobic lagoons are becoming
increasingly utilized at confined livestock
operations because of their ability to meet
the above regulatory requirements. In par-
fhe use of anaerobic lagoons on dairy
and swine farms wilMikely increase in
response to
ticular, hog and dairy operations that al-
ready manage a portion of their manure with
liquid or slurry systems will likely increasing-
ly use lagoons to manage their manure. Alternatively, beef, poultry, and other livestock
operations will not likely switch to lagoon systems as readily because manure from these
operations is generally managed as a solid. These operations will need to ensure that runoff
from these solid based systems will not be discharged from the facility.
Anaerobic lagoon systems generally consist of several components including the
following (see Exhibit 6-5):
Manure Collection System. A system for moving the manure to the lagoon is needed.
"Flush" systems use water to cause the manure to drain into the lagoon. Manure can
also be added to the lagoon by scraping operations or other means.
Solids Separation. Solids separators are installed on dairy farms to reduce the
amount of non-degradable or slow-to-degrade solids, such as bedding material, that
would otherwise enter the lagoon. The manure first enters the solids separator prior
to being added to the lagoon. Solids removal from dairy flush waters reduces the
build-up of solids in the lagoon and reduces the need for frequent and costly lagoon
cleaning.
Lagoon. One or more lagoons can be used. A single lagoon may be designed with
the volume necessary to collect, store, and treat the expected quantity of influent.
Multiple lagoon systems are also common, in which the loading rate of the primary
lagoon is relatively high. One or more secondary lagoons are connected in series
through a spill pipe, and are used for storage during storm events and further treat-
ment of the wastewater from the primary lagoon.
Water Withdrawal System. A system for removing water from the lagoon is needed. In
many cases water is recirculated and used in the "flush" system. Pump systems are
also commonly used to irrigate fields with lagoon water. Lagoon systems with solids
separation generally require little maintenance. Depending on soil characteristics,
either clay or synthetic liners should line the lagoon to control seepage and to protect
the groundwater. In general, lagoon manure management systems are managed with
the following guidelines.
• Lagoons should be adequately sized to treat and stabilize the influent manure.
In order to lawfully (under the CWA) discharge during catastrophic or chronic
storm events, facilities should at a minimum construct lagoons to handle all
wastewater and storm runoff resulting from a rainfall event up to and including
the 25-year, 24-hour maximum storm event.
• Lagoons should be located at a low point so that runoff can be directed
through a series of berms and channels which lead into the lagoon.
6-12
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Exhibit 6-5
Schematic of an Anaerobic Lagoon System
Mi Ik i ng Par for
Free StaI I Barr
So I ids Spread
On Field
EffIuenx Spread
On Field
Source: Adapted from Safley et al. (1991).
In addition to storing manure and preventing contamination of surface and ground
waters, proper anaerobic treatment of manure greatly reduces the organic content of the
manure as measured by volatile solids (VS) content, the biological oxygen demand (BOD)
and the chemical oxygen demand (COD) of the manure (Loehr 1984). Anaerobic
treatment also helps to control the production and leaching of nitrates into ground waters by
converting a large fraction of the organic nitrogen in the manure into ammonia (NH^ (Loehr
1984).11 Although ammonia can leach or run off, in general it is quickly taken up by plants.
Because the rate of plant uptake of ammonia can be readily estimated, nitrogen loading can
be precisely matched with crop needs when spreading effluent on fields (given the current
understanding of how plants utilize the nitrogen in nitrogen containing compounds in the
soil). The fate and transport of ammonia produced in excess of the carrying capacity of
available cropland must also be addressed, however.
10 Volatile solids (VS) are defined as the organic fraction of the total solids (TS). BOD and COO are common
measures of the organic, or polluting capacity, of waste water.
11 Ammonia is a primary constituent of commercial fertilizers.
6-13
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These benefits are demonstrated by comprehensive measurements taken at a North
Carolina anaerobic dairy lagoon (Safley 1991). The measurements show that:
• On average, about 78 percent of the influent volatile solids was eliminated (See
Exhibit 6-6).
• On average, about 81 percent of the COD in the influent was eliminated (See
Exhibit 6-7).
On average, about 57 percent of the influent organic nitrogen was eliminated
(See Exhibit 6-8).
Anaerobic digestion, like aerobic processes, also eliminates many disagreeable odors
associated with livestock manure. Odor control results from the bacterial reduction of the
volatile organic acids in the manure. Anaerobic digester tanks or covered anaerobic lagoons
have the advantage of containing the odor-causing compounds until they are reduced to
odor-free compounds. Reduced odors will reduce the number of flies attracted to the manure
and will significantly reduce their breeding potential.
The liquid effluent from a lagoon can be applied directly to land as fertilizer. The
effluent from a lagoon contains most of the elements needed for plant growth and can supply
nutrients at a rate comparable to that needed by growing crops. The advantages of utilizing
lagoon effluent as a fertilizer are consistent with sustainable agricultural practices and include
the reduced dependance on costly and energy intensive manufactured fertilizers and the
reduced need for the application of nutrients (Loehr 1984). Additionally, it is easy and cost-
effective to use lagoon water for irrigation purposes. One drawback of lagoon systems is that
they dilute the manure considerably, making it costly to transport the treated effluent off site,
which would be necessary if the carrying capacity of the soil for nutrients is too low to allow
the use of all the lagoon water on site.
6.2 OVERVIEW OF OPTIONS FOR EMISSIONS REDUCTIONS
Profitable opportunities exist for reducing methane emissions from livestock manure.
Because methane emissions from livestock manure handled in solid manure management
systems are minimal, opportunities for reducing methane emissions exist primarily for
livestock operations that handle manure as a liquid. The primary option for reducing methane
emissions from livestock manure handled in liquid systems is through use of methane
recovery systems and on-farm energy use.
Emissions reductions can also be achieved if livestock operations that currently utilize
liquid manure management systems instead utilize solid systems. Emissions would be
reduced because methane production is minimal for livestock manure handled in solid
systems. As described below, this option is not believed to be feasible at this time.
6.2.1 Methane Recovery Systems
The most viable option for reducing U.S. methane emissions from livestock manure is
to recover the methane and to utilize it as an on-farm energy source. Methane can be
recovered from lagoons by putting a cover over the lagoon and withdrawing the gas that
6-14
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Exhibit 6-6
VS Reduction at a Covered Lagoon
VS Destruction in a Covered Lagoon
tn vox -
;n 40* -
c
re
I nf Iuent VS
Average VS Reduction 78 pence
Err Iuent VS
nt
Jan Mar May Jul Sep Nov
Month
VS = Volatile Solids
Source: Safley (1991).
Exhibit 6-7
COD Reduction at a Covered Lagoon
GOT
2 16 -
a,
a,
^^
a
o
0 12-
e
a>
s
i-t
•4-4
M-l
u 8 -
T3
C
re
»->
| 4-
rH
f5
M
) Destruction in a Covered Lagoon
A Influent COD
/\ A A /
t
Average Reduction 81 percent
Effluent COD 1
Jan Mar May Jul Sep Nov
Month
COD = Chemical Oxygen Demand Source: Safley (1991).
6-15
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Exhibit 6-8
Organic Nitrogen Reduction at a Covered Lagoon
c
o
O
<§
^Influent Organic Nitrogen
Average Reduction
67 Percent
Effluent Organic Nitrogen
i/n VVM
tin 4/90
i/so i
Source: Safley (1991).
collects under the cover. Alternatively, anaerobic digesters can be built and used to treat
manure and produce methane. Each of these recovery systems has been demonstrated and
is operational in the United States to a limited extent. These recovery systems collect
methane that can provide profitable on-farm electricity, heating, and cooling benefits.
In the United States methane recovery systems were first developed in the early 1970s
when alternative energy sources were being encouraged and energy prices were high.12
Federal and state governments funded many methane recovery projects on farms throughout
the United States. These projects primarily involved recovering methane to produce and sell
electricity to local utilities. Because methane recovery technology was in its initial stages of
development, many mechanical and biological problems existed with the systems. These
operational problems restricted the profitability of the recovery systems and affected consum-
er and investor confidence in the technology. As energy prices declined in the early 1980s,
the profitability of the methane recovery systems further decreased. The operational
problems with the recovery technology combined with the decline in energy prices led to a
sharp fall in demand for the recovery systems and resulted in fewer businesses designing,
building, and installing the recovery systems. Funding and support for the projects on the
Federal and state levels also were discontinued.
12
Small scale methane recovery systems (biogas digesters) have been common in developing countries for
much longer. There are about 2-2.5 million in operation worldwide, primarily in China and India (Safley et al. 1992).
6-16
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The recent trends in manure management in the livestock industry have prompted
renewed interest in developing and installing on-farm methane recovery systems. As livestock
operations respond to environmental controls on manure management and discharge,
options for reducing the costs of compliance are being explored. Because many of the
operational problems initially experienced with methane recovery systems have been
overcome during the past two decades through advances in the methane recovery industry,
methane recovery for energy production is again under consideration as a means of reducing
the cost of complying with manure management requirements.
The type of recovery system utilized on a given farm depends upon several factors
including farm size, number of animals, livestock production characteristics, manure manage-
ment system characteristics, climate, and on-farm energy requirements. Each of the three
main methane recovery systems is described below.
Covered Lagoons
Anaerobic lagoons are used to store
and treat manure. A properly designed and
operated lagoon system in which the hy-
draulic retention time exceeds sixty days will
produce significant quantities of methane.
The methane produced from anaerobic
lagoons can be captured by placing a
floating, impermeable cover over the lagoon (See Exhibit 6-9). The cover can be placed over
the entire lagoon or the portion of the lagoon that produces the most methane. The cover is
constructed of a rubber-like material (e.g., hypalon) which rests on solid floats laid on the
surface of the lagoon. The cover is held in position with ropes and anchored by a concrete
footing along the edge of the lagoon. Where the cover attaches to the edge of the lagoon,
an air-tight seal is constructed by placing a sheet of the impermeable cover material over the
lagoon bank and down several meters into the lagoon, and clamping the cover (with the
footing) onto the sealed bank. Seals are formed on the remaining edges using a two meter
deep "curtain" of material hanging vertically from the edge of the cover into the lagoon.
The size and location of the cover depends upon several factors. Selective sizing and
placement of the cover can greatly improve cost effectiveness by reducing capital costs
without reducing recovery efficiency. In most cases, the manure solids will be concentrated
near the flush-water inflow and will not be evenly distributed across the entire lagoon.
Methane production per unit area of the lagoon surface area will be higher where the solids
are concentrated, and often a significant proportion of the total methane production can be
recovered with a relatively small cover area. The design of the cover lends itself to easy
modular expansion. Sludge mapping or small biogas test units can determine the optimal
size and location of the cover on the lagoon.
When the cover is installed, the methane produced in the covered area of the lagoon
is trapped. A collection device, such as a long perforated pipe, is placed under the cover
along the sealed edge of the lagoon. Methane is removed by pulling a slight vacuum on the
collection pipe (e.g., by connecting a suction blower to the end of the pipe) which draws the
collected gas out from under the cover. The gas produced in this manner is a medium
6-17
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Exhibit 6-9
Schematic of a Covered Lagoon
Source: USEPA (1992).
BTU13 gas (e.g., 500 to 600 BTU per cubic foot), and is suitable for use in engine-genera-
tors, boilers, gas-fired chillers, or other equipment.
Because they are outdoors, anaerobic lagoons operate primarily in the psychrophilic
temperature range (less than 20°C). The rate of digestion and gas production will be greatest
in the summer and least during the winter. Excess gas produced during warm periods will
accumulate under the cover and may be stored there for long periods of time (e.g., months)
until needed. Finally, lagoons (covered or not) are impractical in areas with a high water table
13 British Thermal Unit is a measure of the heat content. One BTU is the amount of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
6-18
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because of potential groundwater contamination. If lagoons are built into highly permeable
soils, the lagoon should be adequately lined to prevent groundwater contamination.
Plug Flow Digesters
The basic plug flow digester design is a long trough, often built below ground level,
with an air tight expandable cover (Exhibit 6-10). The manure is collected daily and added at
one end of the trough. Each day a new "plug" of manure is added, slowly pushing the other
manure down the trough. The size of the system is determined by the size of the daily "plug"
and the retention time, which is the total time that manure spends inside the digester as it
flows from one end to the other. Retention times between 20 and 30 days are most common,
depending on the temperature at which the digester is maintained. The depth of the trough is
usually 2 to 5 meters while the length and width are designed in a 5:1 ratio. The trough is U-,
V-, or rectangular shaped.
An air tight cover prevents gas leaks and maintains anaerobic conditions inside the
trough. In order to protect the flexible cover and to maintain optimal temperatures, some plug
flow digesters are enclosed in simple greenhouses (frames covered in plastic sheeting) or
insulated with a fiberglass "blanket." As the manure progresses through the trough it
decomposes, producing methane which is trapped in the expandable cover. The gas is
collected through a perforated pipe supported above the surface of the manure and is
Exhibit 6-10
Schematic of a Plug Flow Digester
Manure Emranoa
Lagoon Storage
for
Agricultural Fandizar
Source: Koelsch et al. (1989).
6-19
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transported to various end use equipment. The amount of methane produced depends on
the quantity of manure and the average retention time in the trough.
The plug flow digester consists of several components in addition to the digester
trough. These components include the manure delivery system, mixing pit equipment
(holding/pre-heating tank), a removal and collection system for the effluent, and other design
features that improve the ease of operation and overall performance. The plug flow digester
systems generally use a gravity-feed design by building the pre-heating tank, digester, and
collection system on a gentle slope. If a gravity-feed design is not used, pumps are needed
to move the manure between the system areas.
An often vital component of a plug flow digester is the mixing pit. A mixing pit allows
the percent total solids of the manure to be easily adjusted by dilution with water. Many
systems use a mixing pit with a volume roughly equal to one day's manure output to store
manure before being added to the digester. The mixing tank is connected to the digester by
a pipe (usually underground) below the surface level of the manure. The pipe effectively
prevents air from flowing into the digester.
Plug flow digesters operate at either the mesophilic (20°C-45°C) or thermophilic (45°C-
60°C) temperatures. Lower temperatures will slow the rate of digestion, requiring a longer
retention time and consequently a larger, more expensive trough. Higher temperatures will
increase the rate of digestion, requiring a shorter retention time and a smaller less expensive
trough. The energy for heating the digester can be derived from the waste heat from the
cooling system of an internal combustion engine generator that is powered by the gas
produced in the digester. Hot water pipes from the engine coolant system run through the
containers, transferring heat to the manure.
As the digested manure reaches the end of the trough, it must be removed without
allowing air to enter the system. A trap mechanism is typically used to prevent air from
entering the system when removing manure from the digester. Manure in gravity-flow
systems is displaced as new manure is added. After the digested manure is removed, it is
stored before being spread on land as a fertilizer. As with covered lagoons, plug flow
digesters produce a medium BTU gas. If gas production does not match gas demand, a
facility for storing gas may be needed as well.
Complete Mix Digesters
Complete mix digesters typically handle manure with a lower solids content than plug
flow digesters and generally handle larger manure volumes. The basic system components
for a complete mix digester are similar to the components in a plug flow digester. As with
plug flow digesters, the manure is collected in a mixing pit where the percent total solids can
be diluted and the manure can be pre-heated (See Exhibit 6-11). The manure enters the
digester vessel from the mixing pit by either a gravity-flow or pump system. The digester
vessel is a large, vertical, poured concrete or steel circular container. The circular shape is the
strongest and most economical design for the digester vessel. Both the digester vessel and
mixing pit are heated with waste heat from the engine cooling system. Manure is deliberately
mixed within the digester vessel. The mixing process creates a homogeneous substrate,
preventing the formation of a surface crust and keeping solids in suspension. The mixing
process, however, also results in the lack of sequential processing (i.e., there is not a fixed
retention time). Although the average retention time can be controlled, the retention time of a
particular batch of solids will vary considerably. This potential inefficiency is generally
6-20
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balanced by the improved digestion efficiency of a complete mix system due to mixing,
heating, and other management techniques.
Complete mix digesters operate at either the mesophilic (20°C-45°C) or thermophilic
(45°C-60°C) temperatures. As with plug flow digesters, lower temperatures reduce the rate of
methane production and would consequently require a longer average retention time and
larger tank relative to a complete mix digester maintained at a higher temperature. Like the
plug flow digester, the digester can be heated using the waste heat from the gas utilization
system (e.g., engine coolant).
Complete mix digester volumes range considerably from about 100 cubic meters to
several thousand cubic meters. Improved digestion efficiency due to mixing and heating can
allow average retention times as low as 10 to 20 days. (Low retention times are important for
keeping the volume of the tank as small as possible.) These capacities therefore represent
daily capacities of about 1,500 gallons to 100,000 gallons per digester. Larger volumes are
usually handled in multiple digester systems.
Exhibit 6-11
Schematic of a Complete Mix Digester
BypMC
Mv«mEnfinc»
FteircuMng
Pump
ferAgrtauhnlFMIter
Source: Koelsch et al. (1989).
A fixed cover is placed over the digester vessel to maintain anaerobic conditions and
to trap the methane that is produced. The methane is removed from the digester, processed,
6-21
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and transported to the end use site. Adequate space must be maintained between the
surface of the manure and the cover for gas to collect.
Centralized Digesters
In areas where there are a large number of animals in a small geographical region, it
may be feasible to construct a large centrally located digester to manage the manure for a
large number of farms. Universal Synergetics Inc. (UNISYN) of Seattle, Washington, is
currently studying the feasibility of building a large anaerobic digester in Tillamook County,
Oregon. The digester will receive the manure from about 5,000 milk cows within a ten mile
radius of the facility. The manure will be transported by trucks. The digester will produce
biogas which will be used to generate electricity. The digester effluent will be packaged and
sold as fertilizer (UNISYN 1992).
If the Tillamook project is successful, it will demonstrate another important technology
for reducing methane emissions from livestock manure. At this time, however, it is too early
to evaluate how well this technology can be applied on a wide scale.
6.2.2 Alternative Manure Management Systems
Methane emissions can be reduced by utilizing solid manure management systems at
livestock operations that currently use liquid systems. In solid systems, methane production
is minimal because solid systems do not promote the anaerobic conditions that lead to
methane production. In liquid systems methane production is greater because manure is
kept in an oxygen-free environment that generally promotes methane production. Solid
based manure management systems that do not promote methane production include:
• Daily Spread. Manure is collected frequently and applied to nearby crop land.
Daily spread is a common dairy manure management practice in the U.S. (See
Exhibit 6-2). The amount of manure that can be land applied depends on crop
needs, climate and Federal, state, and local environmental regulations.
• Composting. Composting is an aerobic, biological process in which the
organic material in manure is converted into humus. Composting accom-
plished in open windows takes about three to eight weeks while composting in
enclosed units can be accomplished in five to seven days. The resulting
humus may be land applied or sold as a garden supplement (Loehr 1984).
Incineration. The manure is dried and burned in a high temperature incinera-
tor. The heat produced can be used to produce electricity. A 20 MW manure
fueled incinerator is operating in the Imperial Valley in California (Murphy 1989).
Because the manure must be dried, incineration is not practical in humid
climates. In many areas air quality regulations prohibit incineration. Also, the
resulting ash has no nutrient value and generally must be disposed in a landfill.
Because liquid systems are primarily utilized on swine and dairy operations, these
livestock operations would need to shift to one of these solid systems in order to achieve a
significant reduction in U.S. methane emissions from livestock manure. However, a shift
towards these solid based is inconsistent with current practices and expected trends.
Environmental regulations require proper manure storage and disposal on livestock
6-22
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operations, and swine and dairy operations
are complying with these regulations by Solid based manure Systems are not
storing their manure in anaerobic lagoons or practical on many dairy and-swine
slurry tanks or pits. A shift towards farms and are inconsistent with current
alternative solid based manure management = practices and trends.
systems on swine and dairy operations
would therefore contradict current trends in
the industry and could affect their ability to
meet environmental regulatory requirements.
In addition to possible regulatory concerns, a shift towards solid systems may not be
operationally or economically feasible. Increasingly, the livestock on swine and dairy
operations are kept in confinement and their manure is collected by flushing these areas with
large quantities of water. Because the manure is diluted and has a low total solids content,
managing the manure in a solid system is not operationally or economically feasible.
Therefore, because of their limited applicability for reducing emissions from the largest
methane source categories (i.e., liquid based systems on swine and dairy farms), a shift
toward solid manure management systems is not considered further in this report.
6.2.3 Methane Utilization
Because methane is a fuel, the methane gas recovered by any of the available
methods provides a renewable energy source. The methane gas can be used in a variety of
equipment including engine generators, boiler or space heaters, or in "gas-fired" refrigeration
equipment. These options are described below:
is commonly used
to gsnerats slectricrty. The etecirteity
can olfeet ele^k>%:jwfchased from a
local utility or could potentially be sold
10 the ICNsal :$eeuisiiy supply system.
Internal Combustion Engines.
Methane recovered from live-
stock manure is most com-
monly used to generate elec-
tricity with an internal com-
bustion engine. These en-
gines are reliable, available in
a variety of sizes, and can be
operated easily. Electricity
generated in this manner can be used to replace energy purchased from a
local utility or could potentially be sold to the local electricity supply system.
Additionally, waste heat from these engines can provide heating or warm water
for farm use or can be recycled into the methane recovery system.
Boiler and Space Heaters. Boilers and space heaters fired with methane can
produce heat for use in livestock operations. Although this is an efficient use
of the gas, it is generally not as versatile as electricity generation and most
farms do not require the amount of heating that can be generated.
Chillers. Gas-fired chillers are commercially available and can be used for milk
refrigeration on dairy operations. Because dairy farms use considerable
amounts of energy for refrigerating milk, chillers may provide a profitable
opportunity for on-farm methane utilization.
6-23
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• Pipeline Sales. Gas can be sold to a pipeline for distribution through the
existing natural gas pipeline network. Gas produced from livestock manure
would not typically be sold for distribution off site because it does not meet the
BTU requirements for such gas. Although the gas can be enriched by remov-
ing CO2, which makes up about 40 to 50 percent of the biogas produced, such
enrichment is generally costly. Therefore, selling gas to a pipeline is not
anticipated and is not discussed further in this report.
Before methane can be used in any of this equipment, the gas must be cleaned to
some degree (depending upon the specifications of the equipment). The cleaning process
typically involves the removal of water and moisture in a water trap and the removal of
particulates with a filter. The removal of trace corrosive chemicals (such as sulfur) may also
be desirable, depending on the manner in which the gas is used.
This use of the methane is valuable to the farmer because it can displace the
purchase of power from utilities. For example, if the gas is used to generate electricity, the
farmer can reduce the amount of electricity purchased. The benefit to the farmer depends on
the cost of the electricity he otherwise would have purchased, which in turn depends on the
pricing system of the local utility. For example, in Erath County, Texas, a major dairy
producing area of the country, the local electric utility has two electricity pricing classifications
for dairies:
• Residential: The residential pricing schedule applies to livestock operations
where peak demand does not exceed 50 kW. Under this pricing schedule
livestock operations pay a flat rate per kiloWatt-hour (kWh) of electricity used.
Commercial: The commercial pricing schedule applies to livestock operations
where peak demand is equal to or greater than 50 kW. Billing for this schedule
is based on a demand charge plus an energy charge:
Demand Charge is the peak kW demand during any quarter hour
interval multiplied by the demand charge rate.
Energy Charge is the energy charge rate times the total kWh of electrici-
ty used.
By using gas from manure to generate electricity, farmers reduce both the total amount of
electricity purchased, as well as their peak demand. Exhibit 6-12 shows how electricity
production reduces energy purchases. In the absence of electricity production, the farmer
purchases electricity as indicated by the graph. The load profile presents the peak electricity
demands for a typical 1,000 sow farrow-to-finish operation. As shown in the exhibit, the peak
electricity requirements on this hog facility occur when the ventilation equipment and the feed
conveyor are operating. Without a methane recovery system, the farmer must purchase from
the utility the total amount of electricity needed to satisfy the facility's electricity requirements,
which is the entire shaded area of the graph. Using a methane recovery system, however,
the farmer can reduce his electricity purchases from the utility by producing 50 kW of
electricity, which is the shaded bottom half of the graph. The resulting purchases from the
utility therefore are reduced to the lightly shaded quantities in the graph. In this example, the
total amount of energy purchased is reduced by 1,200 kWh per day (50 kW x 24 hours) and
the peak demand is reduced by 50 kW.
6-24
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Exhibit 6-12
Load Profile of a 1,000 Sow Farrow-to-Finish Operation
150 —
100 —
TI me of Day
Source: Adapted from Currence and Bohl (1988a).
If sufficient electricity is generated on-farm, "surplus" electricity may be available to sell
to the utility. This situation would result if the on-farm energy requirements were substantially
less than the energy that can be generated from the gas produced from the manure. The
price at which farmers can sell power to utilities is generally much less than the average price
that farmers pay for electricity. Consequently, producing power for sale is not considered in
this study. In the future, however, if electric power could be sold at favorable rates (e.g., at
rates equal to or greater than the average price of electricity faced by farmers), recovering
methane to generate electricity for sale could become a more economically viable enterprise.
6.2.4 Typical Methane Recovery and Utilization Systems
Over 20 methane recovery and utilization systems are currently operating on private
and university livestock operations across the United States. These recovery systems
demonstrate the operational and economic feasibility of covered lagoons, plug flow digesters,
and complete mix digesters. These recovery systems have been designed specifically for
each livestock operation based upon the type of livestock, number of livestock, manure
management system, energy requirements, and climate.
Exhibit 6-13 lists the recovery projects currently operating in the U.S. As shown in the
exhibit, covered lagoons, plug flow digesters, and complete mix digesters are in operation.
Several profitable projects have provided information regarding their costs and benefits,
including:
Randleigh Dairv: A covered lagoon system is currently operating in North Carolina on
a dairy with 150 cows. The system was installed in 1988 at a cost of $44,000.
6-25
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Manure is flushed daily with about 8,000 gallons of recycled water to a storage pit and
solids separator. The separated solids are spread on crop land, while the liquid flows
by gravity to a settling basin before being pumped to the lagoon. The lagoon is fully
covered. The collected methane fuels a 160,000 BTU/hr rated boiler to provide hot
water for the milking parlor. Because the dairy's demand for hot water fluctuates, hot
water is stored in an insulated 250 gallon tank. The system reduces annual energy
costs by $9,350 and has a 4.9 year payback period (Safley and Lusk 1991).
Lanaerwerf Dairy: A plug-flow digester is operating in Durham, California, on a dairy
with 350 to 500 cows. The $200,000 digester project was installed in 1982 and funded
through a commercial lender and a low-interest government loan from the California
Department of Food and Agriculture. Electricity is produced from the collected
methane using a Caterpillar 3306 engine. About 40 kW of electricity is produced daily,
satisfying all of the dairy's 35 kW electricity requirement. Any excess electricity is sold
to the utility. The dairy's on-farm electricity production has resulted in electricity
savings of $2,000 per month. The digester also enabled the dairy to forego monthly
lagoon cleanup and hot water heater expenses, saving the dairy $1,950 per month
(Treleven 1989).
Valley Pork: A complete mix digester was installed in 1986 and is currently operating
on a 1,500 sow farrow-to-finish farm in Pennsylvania. Although the digester was
originally installed for odor control, it also satisfies many on-farm energy requirements.
The methane collected from the digester is combusted in a reciprocating engine-
generator. Excess engine heat provides 70 percent of the heating need for the
building. The farm's reduced electricity demand and electricity savings are shown in
Exhibit 6-14. Monthly farm electricity and heating oil bills are reduced by about $5,000
to $6,000 during the digester's operation. The digested manure is spray irrigated on
to 300 acres of corn.
UNISYN (Universal Synergetics. Inc.): A centralized complete mix digester is operated
by UNISYN in Oahu, Hawaii. The facility processes the manure from a 1,200 head
dairy and also receives organic wastes from food processors and distributors. The
recovered methane fuels an electric generator that satisfies most of the facility's
energy requirements. The facility also recovers solid nutrients after digestion and
produces a granular fertilizer and a fibrous soil amendment product. Both fiber and
fertilizer products are sold to golf courses and nurseries in Hawaii. The facility
demonstrates that a centralized methane and resource recovery system can operate
economically by converting manure into electricity and marketable fertilizer and soil
amendment products (Nakano 1993).
These recovery systems illustrate the operational and economic feasibility of recover-
ing methane from livestock manure. Covered lagoon, plug-flow, and complete mix digesters
are operating on livestock operations across the United States. In addition to methane
recovery systems on individual farms, centralized recovery systems also provide an opportuni-
ty to process livestock manure from several farms. Centralized recovery systems are
potentially more profitable than on-farm systems due to the amount of manure that can be
processed and resulting economies of scale. Centralized recovery systems, however, also
demand increased labor and capital requirements.
6-26
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Exhibit 6-13
Typical Methane Recovery Systems Operating in the U.S.
Animal
Type
State
Site
Number of
Animals3 End Use of Recovered Methane
Dairy
Hog
Hog
NC Randleigh Dairy
CA Royal Farms
IA Monfort
150 On-farm heating6
up to 15,000 On farm electricityb'c
— Heating for processing plantc
Dairy Wl Crandon, Wl 100
Dairy ME U. of Maine Dairy Farm 160
Dairy NY Agway Farm Research Center 210
Dairy NY Cooperstown Holstein Corp. Farm 320
Dairy MN Lindstrom Farm 50
Dairy AZ Arizona Dairy Co. 4,800
Dairy Wl Fran Peoterman, Jr. 30
Dairy/Poultry HI Unisyn 1,200/—
Hog IA Harold McCabe 1,000
Poultry IA Hamilton Farms 320,000
Poultry NC Darrell Smith Farm 70,000
Hog PA Valley Pork 1,500
Veal Wl Poy Sippi, Wl 300
On-farm electricity generationbid
On-farm heatingd
On-farm electricity generation13'*
Sell recovered methane to infirmary*
On-farm electricity generation1
On-farm electricity generationd
On-farm electricity generationbld
On-farm electricity generation13'9
Flared6''
On-farm electricity generation6'6''
Sell generated electricity to utilityd''
On-farm electricity generationb'd
On-farm electricity generationb'd
Dairy
Dairy
Dairy
Dairy
Dairy
Dairy
Hog
Goat
Ml Fairgrove Farms
PA Frey Dairy
PA Oregon Dairy Farms
PA Mason Dixon Farms, Inc.
VT Foster Brothers Farm
CA Langerwerf Dairy
PA Gypsy Hill Farms
CA Cal Poly Sustainable Farm
600 On-farm electricity generationbld''
780 Sell generated electricity to utilityd'h
250 On-farm electricity generationbid
900 On-farm electricity generation •'
600 On-farm electricity generation6'6''
350-500 On-farm electricity generation6'6'1
11,250 On-farm electricity generation6'6
11 On-farm heating6
a Approximate farm size.
b Excess electricity sold to utility.
c Chandler et al. (1983).
d ICF (1992).
e Safley and Lusk (1991).
f Koelsch et al. (1989).
g Ledbetter (1991).
h RCM (1991d).
i Ashworth (1985).
6-27
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Exhibit 6-14
On-Farm Energy Savings at a Swine Operation
,ODD
8. 000 -
6,000 -
4,000 -
2,000 -
overage power cost without digester
I I i I I I I I I i I I I I I I I I I
BEFORE i START
DIG6ST6P
DIGESTER OPERATION
Source: ROM (1989).
6.3 NATIONAL ASSESSMENT OF PROFITABLE METHANE REDUCTION
This analysis estimates the total amount of methane that can be profitably mitigated
from farms in the United States. Three types of methane recovery systems were considered
in the analysis: covered lagoons, complete mix digesters, and plug flow digesters. Each of
these recovery systems was evaluated to determine their profitability on dairy and swine
farms. Only dairy cattle and swine were considered in the analysis since these two animal
types account for about 80 percent of total U.S. methane emissions from livestock manure.
Additionally, liquid manure management systems, which are most amenable to methane
recovery projects, are used most often on dairy and swine farms.
The methodology includes the following three steps: .(1) financial analysis at the
individual farm level to assess the profitability of the recovery options; (2) assessment of the
profitable options nationally; and (3) estimation of the amount of methane that will be
mitigated nationally by the adoption of the recovery projects. Each step is described below.
6-28
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6.3.1 Farm-Level Financial Analysis
This portion of the analysis assesses the economic viability of the methane recovery
options at the farm level. A discounted cash flow analysis identified the conditions under
which projects have a positive net present value. The costs and revenues for the analysis are
as follows.
Gas Recovery System Installation Costs
For each recovery option the cost of
materials, labor, and engineering services
were computed. These costs vary primarily
with the amount of manure handled, which
is essentially a function of the size of the
Tfce eost of a recovery system depends
on ihe amoum of manum Iwidisej, to*
depth of the water table, and local labor
and equipment costs.
farm (measured by the number of animals)
and the portion of the manure to be
managed within the gas recovery system.
Other local conditions also influence the costs, such as the depth of the water table and the
cost of local labor and equipment.
Based on case studies in Texas, California, North Carolina, Illinois, and Iowa (RCM
1990, RCM 1991a-c), representative average cost relationships were developed. Exhibits 6-15
through 6-17 summarize the costs for the three gas recovery systems for a range of hog and
dairy farm sizes. At dairies, covered lagoons and complete mix digesters can handle from 15
percent of the manure generated (i.e., the manure flushed from the milking parlor) to up to 55
percent of the manure generated (i.e., the 15 percent from the milking parlor plus 40 percent
from the feed apron). About 45 percent of the manure generated in dairies is generally
handled on drylots and would not be readily available for handling in these gas recovery
systems.
For plug flow digesters, the solids content of the manure washed from milking parlors
is too low to be used, so only the 40 percent of the manure found on the feed apron would
likely be managed with this recovery system. For hog farms, the solids content of the manure
is generally too low to utilize plug flow digesters and so plug flow digesters are not consid-
ered in this analysis for hog farms.14
As shown in Exhibit 6-15, the main cost of covered lagoon systems is the lagoon
cover. Depending on the farm size and animal type, the lagoon cover accounts for between
30 to 55 percent of the covered lagoon installation cost. Engineering and consulting services
account for between about 15 and 40 percent of the installation cost. In addition to the farm
size and animal type, engineering and consulting costs also will depend on the utilization
equipment installed. Gas transmission and gas handling costs are relatively small and will
depend on the physical layout of the farm and the quality and quantity of the gas produced.
The cost of the lagoon itself accounts for about 10 to 20 percent of the covered lagoon
installation cost. In addition to the digester size and animal type, the lagoon cost depends on
local labor rates, permit requirements and costs, and any required environmental tests.
14 This does not imply that plug flow digesters cannot be used on hog farms. One of the eight plug flow
digester projects listed in Exhibit 6-15 is installed on a hog farm.
6-29
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The main cost for the plug flow and complete mix digester systems is the digester
vessel (see Exhibits 6-16 and 6-17). Depending on the digester size, the digester vessel
accounts for about 45 to 65 percent of the total digester installation cost. In addition, the
mixing/settling basin accounts for between 15 and 25 percent of the cost; engineering and
consulting fees account for about 25 percent of the cost; and gas transmission accounts for
only about 1 to 4 percent of the cost. The actual gas transmission costs will depend on the
physical layout of the farm.
Exhibit 6-1 5
Farm Size3
(head)
Representative
Lagoon
Covered
Lagoon
Cover
Lagoon Installation Costs
Gas Trans-
mission
i D^^fBmwHhH^^^^^Mmw^
250
500
1,000
$4,700
$6,500
$10,100
$12,700
$19,900
$32,700
$4,200
$4,200
$4,200
Gas
Handling
ftemttetf
$2,800
$2,800
$2,800
Engineering
Consulting
$15,000
$15,000
$1 5,000
. • • . .. • *"'•••••
250
500
1,000
$8,500
$14,000
$25,200
$21 ,500
$34,700
$60,300
$4,200
$4,200
$4,200
$2,800
$2,800
$2,800
$15,000
$15,000
$18,100
Hog Farm with 10Q Pef<5e<# of tite Msuwm Hantftetf
500
1,000
5,000
a Refers
having
Source: Based
$5,000
$7,200
$24,600
$1 5,700
$23,600
$75,100
to the number of milking cows having
an average weight of 138 Ibs.
on ROM (1990) and RCM
(1991a-c).
$1 ,200
$1 ,200
$1 ,200
an average weight of
$3,200
$3,200
$3,200
1,400 Ibs. or the
$8,500
$1 1 ,600
$40,600
number of hogs
Gas Utilization Costs
Several options for using the recovered gas were analyzed. At dairy farms, farmers
require energy to heat wash water, cool milk, and run a variety of electrical equipment,
including milking equipment. Four alternatives were analyzed to identify the most cost-
effective opportunities for recovering and using gas at dairies:
• Option I: On-farm heating and cooling with parlor manure;
Option II: On-farm electricity generation with parlor manure;
6-30
-------
Exhibit 6-1 6
Representative Complete-Mix Digester Installation Costs
Farm Size3
(head)
Mixing/Settling
Basin
Digester
Gas Transmis-
sion
Engineering
Consulting
= - . i -^^i^mtrm with W teek^mifenum tfaraffetf . '•= , ! .
250
500
1,000
• ...-'-.... :'.
250
500
1,000
500
1,000
5,000
$16,100
$17,200
$1 8,900
:&^%i$y$h
$1 8,600
$21 ,300
$25,700
Hog Farm with
$16,400
$17,800
$24,900
$29,400
$38,400
$54,000
m$er$^ptih?4
$51 ,500
$77,300
$124,200
$2,600
$2,600
$2,600
^u^ M^'7l ..-.. 1
$2,600
$2,600
$2,600
$1 5,000
$17,900
$23,200
" V"': .''
$22,400
$31 ,500
$48,400
100 Percent of the Manure Handled
$32,400
$43,600
$115,000
a Refers to the number of milking cows having an average weight
an average weight of 138 Ibs.
Source: Based on ROM (1991a-c).
$2,600
$2,600
$2,600
of 1 ,400 Ibs. or the number
$16,700
$21 ,400
$53,900
of hogs having
Exhibit 6-1 7
Representative Plug-Flow Digester Installation Costs
Farm Size3
(head)
•'•'•:• •%fV;;— J
250
500
1,000
Mixing/Settling
Basin
: ;®^:jii^)^&
$17,800
$1 9,900
$23,400
Digester
Mtaran&oftfi^tfi
$39,600
$55,200
$82,300
Gas Transmis-
sion
in^$&sf^:.r;:
$2,600
$2,600
$2,600
Engineering
Consulting
:. ;... /";-;*:v '••:'':
$18,800
$24,700
$35,500
a Refers to the number of milking cows having an average weight of 1 ,400 Ibs.
Source: Based on ROM (1991a-c).
6-31
-------
Option III: On-farm heating and cooling with parlor and apron manure;
and
Option IV: On-farm electricity generation with parlor and apron manure.
The first two options are designed to recover gas from the milking parlor manure only. As
discussed above, this represents about 15 percent of the manure produced at most dairies.
The third and fourth options are designed to recover gas from the apron manure as well,
which accounts for about an additional 40 percent of the manure generated. Because the
third and fourth options handle more manure, they also produce more gas.
The two options considered for using the gas at dairies are: (1) to heat wash water
and fire chillers; and (2) to produce electricity. When used to heat wash water and fire
chillers, the gas is used directly in gas-fired equipment. Dairies generally do not have such
gas fired equipment, so new equipment is generally required in order to take advantage of
the gas that is produced. When used to produce electricity, the gas is used in a generator.
The electricity produced with the gas can then be used in existing equipment, such as
chillers, pumps, and other equipment.
For hog farms, only electricity generation from all of the manure is considered.
Heating and cooling requirements are relatively small on hog farms, so gas-fired equipment
was not analyzed. Electricity requirements on hog farms are often substantial, however,
including the need for electricity to operate ventilation fans, grain drying and feed handling
equipment, and water pumps.
The cost of the gas utilization equipment depends on its "size" or capacity: larger
chillers and generators cost more than smaller ones. The size of the gas utilization equip-
ment was selected based on the amount of gas produced and the on-farm energy demand.
The amount of gas produced was estimated based on a gas recovery rate per unit of manure
handled. For plug flow and complete mix digesters the rate of gas recovery is constant per
unit of manure handled because these systems are not as sensitive to local ambient tempera-
tures. Depending on how well the digesters are insulated, gas recovery rates in warm
climates will likely exceed the value assumed in the analysis and gas recovery rates in cold
climates will be less than the value assumed in the analysis.
Gas recovery rates for covered lagoons depend, in part, on ambient temperatures
throughout the year. Exhibit 6-18 summarizes the gas recovery rates used in the analysis for
the plug flow and complete mix digesters and for covered lagoons in representative locations
throughout the country. As expected, less gas is recovered from covered lagoons in cooler
locations.
Electricity and Cooling Demand for Dairies
The principal components of electricity demand on dairy farms include cooling
equipment, vacuum pumps, and water pumps. In some cases water heaters, lighting, and
feed processing may create significant demands as well (Currence and Bohl 1988b). The on-
farm demand for electricity on dairy farms was estimated as a function of the number of milk
cows as follows:
Less than 200 Milk Cows: kWh/day = 1.85 kWh/cow/day x (# Cows) (6.1)
6-32
-------
Exhibit 6-1 8
Average Gas Recovery Rates Per Unit of Manure Handled
(m3 of biogas per 1,000 kg of VS handled)
Recovery System
Complete Mix Digesters
Plug Flow Digesters
Covered Lagoons:
Erath County, Texas
Tulare County, California
San Bernadino County, California
Sampson County, North Carolina
Lancaster County, Pennsylvania
Henry County, Illinois
Delaware County, Iowa
Madison County, New York
Dane County, Wisconsin
Dairies
1 60-- 320
1 60-- 320
350
356
375
325
187
219
200
194
219
Hog Farms
304 - 608
304 - 608
493
481
512
462
312
287
268
256
262
Notes: Biogas is assumed to be 60 percent methane and 40 percent carbon dioxide.
Source: Complete mix and plug flow recovery rates based on Jewel et al. (1981). Covered
lagoon recovery rates based on RCM and ICF (1991).
More than 200 Milk Cows: kWh/day =150+1.1 kWh/cow/day x (# Cows) (6.2)
Equation 6.1 is based on a study of 26 small dairies in Wisconsin (Stanley 1987). Equation
6.2 is based on electricity demand at large California dairies (Chandler 1991).
The on-farm refrigeration needs for dairies were estimated as a function of the number
of head based on RCM (1990) as follows:
Cooling (tons) = 0.0165 ton x Number of milk cows (6.3)
Chillers were sized to meet the on-farm requirements. If the amount of gas produced could
not meet the entire refrigeration requirements, then the refrigeration option was not consid-
ered feasible for that farm. In most cases, the parlor manure produces enough gas to run a
dairy's chillers and heaters. The electricity produced using both the parlor and apron manure
can be used to provide for other on-farm electricity requirements in addition to chilling and
heating.
6-33
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Electricity Demand for Hog Farms
Many large hog farms use a variety of confinement facilities to house sows, to brood
and nurse pigs, and to finish animals to a market weight. Each facility requires different
amounts of energy depending on: the type of production system (e.g., farrowing, nursery,
and/or finishing); the characteristics of the production system (e.g., enclosed versus open
front housing); the degree of mechanization; and the climate. The principal components of
electricity demand on hog farms include: ventilation equipment; heat lamps; grain drying and
feed handling equipment; and water pumps. If electric heating equipment is used there can
be a significant winter demand as well. Depending on the specific practices used at
individual hog farms, the total energy demand can vary substantially between farms (Currence
and Bohl 1988b).
Little data are available to quantify electricity demand on hog farms. Exhibit 6-19
shows two estimates of on-farm electricity demand. One estimate is based on four farrow to
finish farms in Nebraska with an average of about 180 head. The other estimate is based on
energy consumption at five large farrow to finish operations operated by Smithfield-Carroll's
Farms in Virginia. As shown in the exhibit, there is a wide variation in the amount of electrici-
ty necessary per animal on hog farms.
For purposes of this analysis, it is assumed that hog farms can use all the energy
produced by the digesters. With this assumption and the gas production rates shown in
Exhibit 6-18, this implies a minimum energy consumption ranging from about 0.26
kWh/head/day (for Illinois) to about 0,40 kWh/head/day (for North Carolina). As shown in
Exhibit 6-19, these implied energy consumption values fall within the range of energy
consumption reported on hog farms.15
Using the calculated gas flows and on-farm energy requirements, the cost estimates
for gas utilization equipment for a range of gas utilization rates are shown in Exhibit 6-20.
The gas utilization costs are a function of the amount of gas to be utilized. The cost per ton
of cooling capacity for gas-fired chillers is about $700 to $1,000, depending on the model
selected and its efficiency. In addition to providing refrigeration, gas-fired chillers also
produce hot water as a by-product of the chilling process.
The cost for electric power generators depends on the capacity of the generator. The
amount of biogas to be used determines the capacity. The cost per kilowatt of generating
capacity is about $1,000 to $1,100, depending on the model selected and the capacity. In
addition, a small building to house the generator is required that is assumed to cost approxi-
mately $5,000.
The operating and maintenance costs of the utilization equipment is assumed to equal
$0.015 per kilowatt hour for generators and $0.015 per ton hour for gas-fired chillers (ROM
1991b).
15 In cases where on-farm energy consumption is less than the maximum produced by the covered lagoon,
the size of the digester or lagoon cover can be reduced to match actual on-farm energy needs. This will reduce
the cost of the digester or lagoon cover but may also reduce the amount of methane emissions that are mitigated.
These effects are not considered in the analysis.
6-34
-------
Exhibit 6-19
On-Farm Electric Demand on Hog Farms
1.4 -
1.2 -
10-
0.8
06-
0.2 -
Crop Drying A Handling
Electric Demand at Four Farrow to FinlshxFarms
X x x x
Electric Demand at Snltnf leid-Carrol I s Farms C.Avg=<
16}
Jao Feb tfar Apr Hay Jun Jul Aug Sep Oct Mov Dec
Uonth
Electric Demand at Four Farrow to Finish Farms: Based on four Nebraska farrow to finish
farms with an average population of about 180 head. All farms had confinement farrowing,
nursery, and finishing buildings and utilized grain drying and handling equipment. The
residential electric demand is also included (Stetson et al. 1984).
Electric Demand at Smithfieid-Carroll's Farms: Based on five hog farms operated by
Smithfield-Carroll's Farms with about 1.2 million pounds of total animal live weight. The
primary electric demands are ventilation fans, heat lamps, and lighting. Propane utilized for
other heating needs is not included. Data are only for January through July (Gettier 1993).
The banded area between 0.26 and 0.40 kWh/head/day represents the range of
energy consumption assumed in this analysis. This range assumes that the hog farms will
be able to utilize all the energy produced by the digesters. These values may overstate
actual on-farm energy consumption in some cases (e.g., at the Smithfield-Carroll Farms). In
these cases, the size of the digester or lagoon cover can be reduced to match actual on-
farm energy needs and to reduce the cost of the digester or lagoon cover.
6-35
-------
Exhibit 6-20
Gas Utilization Equipment Costs
Equipment Size
Gas-Fired Chillers for Dairies
7.5 ton
20 ton
Installed Costs
Comments
$9,600
$24,100
Approx. requirement for 250 head dairy on a cov-
ered lagoon
Approx. requirement for 1 ,000 head dairy on a
covered lagoon
Wash Water Heaters for Dairies
1.6 million BTU/day
5.8 million BTU/day
6.4 million BTU/day
23.3 million BTU/day
$4,000
$5,400
$5,600
$11,300
Boiler size required to utilize gas produced by
250 head dairy with 15% of the manure handled
on a covered lagoon
Boiler size required to utilize gas produced by
250 head dairy with 55% of the manure handled
on a covered lagoon
Boiler size required to utilize gas produced by
1,000 head dairy with 15% of the manure handled
on a covered lagoon
Boiler size required to utilize gas produced by
1 ,000 head dairy with 55% of the manure handled
on a covered lagoon
Electric Power Generators for Dairies
5kW
12 kW
18 kW
46 kW
$10,200
$17,600
$23,900
$53,300
Approx. requirement for 250 head dairy with 15%
of the manure handled on a covered lagoon
Approx. requirement for 250 head dairy with 55%
of the manure handled on a covered lagoon
Approx.. requirement for 1 ,000 head dairy with
15% of the manure handled on a covered lagoon
Approx. requirement for 1,000 head dairy with
55% of the manure handled on a covered lagoon
Electric Power Generators for Hog Farms
10 kW
95 kW
$15,400
$105,000
Approx. requirement for 500 head hog farm on a
covered lagoon
Approx. requirement for 5,000 head hog farm on
a covered lagoon
Notes: Number of head refers to the number of milking cows having an average weight of 1 ,400 Ibs. or the
number of hogs having an average weight of 138 Ibs. One million BTU is equivalent to 293 kWh. A ton of
cooling is equivalent to 288,000 BTU/day.
6-36
-------
Total Costs of Representative Projects
The total costs for gas recovery and utilization projects are estimated as the sum of
the above individual component costs. Exhibit 6-21 presents estimates for representative
projects of various sizes. For purposes of estimating the gas recovery rates the covered
lagoons are assumed to be in Erath County, Texas, for the dairy example and in Sampson
County, North Carolina, for the hog farm example. As shown in the exhibit, costs range from
about $49,000 for a 250 head dairy utilizing a covered lagoon to produce heating and cooling
with parlor manure only to $292,400 for a 5,000 head hog farms utilizing a complete mix
digester to produce electricity with all available manure. Annual operating and maintenance
costs for these cases range between $500 and $10,300. For other areas of the country,
these costs will differ depending on the climate and local labor and construction costs.
Value of On-Farm Energy Production
The value of on-farm energy production is estimated as the energy costs avoided by
the farmer. When electricity is produced, or when gas-fired chilling is produced, the value of
the energy is assumed to be the price of the electricity purchases avoided. State average
agriculture electricity rates are used in this analysis, which vary from 4.3 cents per kWh in
Washington State to 10.9 cents per kWh in New York State. Exhibit 6-22 lists the electricity
rates used. The value of gas fired heating for dairy wash water is conservatively estimated as
$8 per head per year (Koelsch 1982). In addition, digesters may provide space heating for
dairies and hog farms. Although these benefits can be substantial in cooler climates, they are
not included in this analysis.
Discounted Cash Flow Analysis
A discounted cash flow analysis was performed to estimate the net present value of
the projects at the farm level. The following parameters were used for the analysis:
All installation costs are incurred as a lump sum in year 1.
• Total project life is 10 years.
• Straight line depreciation of equipment costs over 10 years.
• Marginal tax rate of 40 percent for energy cost offsets and annual O&M costs.
• Salvage value of equipment at the end of the project is zero.
A real discount rate of 10 percent applied to the after tax cash flow. The
discount rate used in this analysis reflects the private (i.e. farmer's) perspective
and is not a social discount rate.16
16 Discount rates in the range of 8 to 12 percent are appropriate for the evaluating livestock manure recovery
projects. Different discount rates woulc be appropriate for other industries and other types of methane mitigation
projects.
6-37
-------
Exhibit 6-21
Total Costs of Representative Gas Recovery and Utilization Projects
Recovery Option
Utilization Option
Farm Size3
(head)
Installation Costs
Annual O&M Costs
Dafcrles: Pitrlor Manure Ontjr
Covered Lagoon
Complete Mix
Digester
DaM*« l>ypr-«fl
Covered Lagoon
Complete Mix
Digester
Plug Flow
Digester
(apron manure
only)
Heating and Cooling
Electricity Genera-
tion
Electricity Genera-
tion
HjApronmaBin'e
Heating and Cooling
Electricity Genera-
tion
Electricity Genera-
tion
Electricity Genera-
tion
250
500
1,000
250
500
1,000
250
500
1,000
250
500
1,000
250
500
1,000
250
500
1,000
250
500
1,000
$49,000
$60,800
$88,900
$49,600
$62,800
$88,700
$76,500
$92,900
$122,100
$500
$1,100
$2,200
$600
$1,200
$2,300
$400
$800
$1,700
$55,800
$68,000
$103,600
$69,500
$99,800
$163,800
$117,400
$168,200
$261,800
$97,800
$130,100
$190,300
$500
$1,100
$2,200
$2,100
$4,200
$8,500
$1,500
$3,100
$6,100
$1,100
$2,200
$4,400
Hog Farms •••-:••••;'! '".-'•&•'' '. \ '•'• '• '."••.••••'•'• "" '.A=' "• ' •..-••'• .... .. • •
Covered Lagoon
Complete Mix
Digester
Electricity Genera-
tion
Electricity Genera-
tion
500
1,000
5,000
500
1,000
5,000
$48,900
$71,700
$249,600
$86,000
$112,
-------
State
AL
AZ
AR
CA
CO
CT
DE
FL
GA
ID
IL
IN
IA
KS
KY
LA
ME
MD
MA
Ml
MN
MS
MO
MT
Exhibit 6-22
State-Average Electricity Prices
Rate
($/kWh)
$0.066
$0.088
$0.078
$0.094
$0.070
$0.096
$0.082
$0.077
$0.072
$0.048
$0.100
$0.069
$0.076
$0.077
$0.056
$0.073
$0.085
$0.069
$0.091
$0.076
$0.067
$0.068
$0.073
$0.054
State
NE
NV
NH
NJ
NM
NY
NC
ND
OH
OK
OR
PA
Rl
SC
SD
TN
TX
UT
VT
VA
WA
WV
Wl
WY
Rate
($/kWh)
$0.062
$0.057
$0.095
$0.101
$0.090
$0.109
$0.077
$0.061
$0.078
$0.068
$0.048
$0.089
$0.090
$0.072
$0.068
$0.057
$0.070
$0.074
$0.089
$0.069
$0.043
$0.059
$0.067
$0.060
Source: DOE (1991).
The project with the highest net present value is the most attractive to the farmer.
Those projects with a positive net present value are profitable from the farmer's perspective.
Across a wide range of farm sizes, covered lagoons were nearly always preferred to plug flow
and complete mix digesters. Exhibit 6-23 summarizes a comparison of the different options.
Note that for the covered lagoon options in Exhibit 6-23, the total costs do not include
the cost of the lagoon. This assumes that the farmer either already has a lagoon or would
install a lagoon regardless of whether a methane recovery system was utilized. This assump-
tion is used for all the covered lagoon options analyzed in the National Assessment section.
6-39
-------
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-------
Compared with the costs and benefits observed at operating digesters in the U.S., the
net present values listed in Exhibit 6-23 are conservative. In particular, the benefits are likely
understated because conservative biogas production rates were assumed. In addition, the
electricity rates used to calculate the benefits in Exhibit 6-23 are low compared with many
parts of the country. There are several examples of digesters that operate very profitably
although the analysis in this chapter would predict that they would not be profitable.
6.3.2 Assessment of Profitable Options Nationally
The profitability of gas recovery and utilization was assessed nationally by repeating
the farm-level economic analysis for locations around the country. For each location, the
analysis was performed to estimate the farm level "Breakeven Animal Population," which is the
number of head necessary to make each of the gas recovery and utilization options profitable
(i.e., have a net present value of zero). The following location-specific data were used in this
analysis:
Climate Data: The National Climatic Data Center (NCDC) Historical Climatolo-
gy Data (HCD) for the United States was used to describe monthly average
temperatures. The HCD divides each state into up to 10 climate
divisions (there are a total of 345 dimate divisions in the contiguous 48 states).
The 30 year average monthly temperature within each climate division was
used in the analysis.
• Electricity Rates: The average state electricity prices (listed above in Exhib-
it 6-22) were used.
The result of this analysis is estimates of the Breakeven Animal Population for each
climate division for each of the four dairy utilization options and for hog farms. For example,
in Texas Climate Division 3 (North Central), which includes Erath County, Texas, the
Breakeven Animal Population for dairies using covered lagoons to handle parlor and apron
manure to generate electricity is 340 head.
The 1987 Census of Agriculture (Bureau of the Census, 1987) was used to estimate
the number of animals within each climate division that are on farms with animal populations
as large or larger than the estimated farm-level Breakeven Animal Population for the division.
First the county level data from the 1987 census were aggregated to the climate division
level. Then, the Breakeven Animal Population estimates were used to estimate the number of
animals within each division that were on farms with populations above the breakeven points.
The total national populations of dairy cows and hogs that are on farms that would
find the various recovery and utilization project profitable are estimated by summing the
results from each of the climate divisions. Additionally, the total number of farms, the total
gas recovered, and the total electricity produced are estimated by summing the results from
each climate division.
6-41
-------
6.3.3 Methane Emissions Mitigated
Methane emissions mitigated are equal to the emissions that would have resulted had
farms not implemented the profitable recovery and utilization projects. Methane emissions
mitigated need not be equal to methane gas recovered. In some cases, for example, the
recovery project may be a covered lagoon that manages 55 percent of a dairy farm's
manure.while in the absence of the project 15 percent of the manure would have been
handled in an (uncovered) lagoon and 85 percent would have been spread on fields
periodically. In
this case, the methane emissions mitigated are much less than the methane gas recovered
by the recovery project. In other cases, however, the methane emissions mitigated are more
than the methane gas recovered by the recovery project. This difference occurs because the
estimates of the amount of methane that can be recovered from a covered lagoon are
conservative (i.e., are probably underestimated). Conservative estimates are used to avoid
producing over-optimistic assessments of the profitability of the recovery projects.
Methane emissions mitigated were estimated at the state level using estimates of the
current proportion of manure handled by each manure management system within the state
by species (EPA 1993). It is assumed that only dairies and hog farms that currently handle
their manure in liquid manure management systems would undertake the recovery projects.
Consequently, the emissions mitigated are estimated as the emissions that would have
resulted from the liquid handling of manure in the state.
6.3.4 Comparison of Systems for Mitigating Methane Emissions
The preceding sections have described the technical feasibility and costs of alternative
technologies for mitigating methane emissions. The preferred system for reducing methane
emissions at a profit will be one that:
• reduces methane emissions from the largest source category (i.e., liquid based
systems on dairy and swine farms);
is technically feasible on the farms producing these emissions;
• is consistent with the manure management practices currently utilized or
expected to be utilized in the future; and
• can be operated at a profit.
Based on these criteria, covered lagoons
offer the best opportunity for significantly
reducing methane emissions at a profit.
The reasons for this are:
Covered lagoons can be
used to reduce emissions
from dairy and swine farms
which account for about 60
percent of total methane
emissions from livestock manure (Exhibits 6-3 and 6-4).
Jsest
reducing methane
6-42
-------
Covered lagoons are technically feasible in most parts of the country. Al-
though covered lagoons are not practical in northern tier states, most existing
dairy and swine lagoons are in southern and western states (Safley et
al. 1992).17
Covered lagoons are consistent with the trend towards increased liquid manure
storage and treatment systems (Shuyler and Meek 1989).
Covered lagoons generally require lower capital and operating costs relative to
other methane recovery systems and can be operated profitably over a wider
range of farm sizes.
Exhibit 6-24 summarizes this conclusion and compares covered lagoons with the other
methane recovery systems and other methane reduction systems (See Section 6.2.1 and
Section 6.2.2).
This conclusion is consistent with a report by Lusk (1991) that compared the profitabil-
ity of a covered lagoon system with a traditional mixed tank mesophilic digester. Lusk found
that "an earthen psychrophilic digester [covered lagoon] can have an economic advantage
over a mixed tank mesophilic digester because of lower capital costs and reduced operation
and maintenance expenses." (Lusk 1991). Although covered lagoons may be generally
preferred to plug-flow or mixed tank digesters, the plug-flow and mixed digester systems can
play an important role in areas where covered lagoons are not practical. This conclusion is
supported by a draft report prepared for the U.S. Department of Energy Western Regional
Biomass Energy Program which concludes that plug-flow digesters could be profitably
operated in thirteen western states (NEOS 1993).
The remainder of this report focuses on the profitable use of covered lagoons to
reduce methane emissions from dairy and swine manure. To the extent that the report does
not consider other mitigation systems (e.g., plug-flow and mixed tank digesters), and other
manure sources (e.g., feedlot, poultry), profitable emission reductions may be understated.
6.4 PROFITABLE EMISSION REDUCTIONS FROM LIVESTOCK MANURE
Methane emissions from livestock manure can be reduced at a profit. The extent to
which the methane recovery projects are profitable, and the overall amount of methane
mitigation that can be achieved at a profit are very sensitive to the value of the energy
produced by the projects. Relatively modest increases in the value of energy result in large
increases in the number of projects that are expected to be profitable.
Methane recovery projects are most
profitable where large numbers of animals
are managed in warm climates. In California
and Texas, the large dairy farms will find
methane recovery attractive. In North Caro-
lina the large hog farms will similarly benefit
in t^lfornla, Ts&fe,- atfti.
Carolina.
17 Lagoons (covered or not) generally are not practical in areas with a high water table because of potential
groundwater contamination.
6-43
-------
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from methane recovery. Small farms are generally less profitable than large farms because
the value of the amount of energy produced is too small to pay back the costs of the
recovery system. Overall, higher energy values make farms of all sizes and climates more
profitable.
First, the extent to which emissions can be reduced profitably by region is presented.
Then, the national estimates are described and their sensitivity to the value of energy is
examined. Finally, opportunities for profitable emission reduction in the future are presented.
6.4.1 Profitable Emissions Reductions
Using the method described in the previous section, the opportunities for profitable
methane recovery were estimated. The following results are reported: the amount of
methane emissions mitigated; the number of animals affected; the number of farms involved;
and where applicable, the amount of electricity generated. The specific results of the analysis
depended upon the type of farm, the manure collection method used, and the use that was
made of the methane.
Exhibit 6-25 displays the results for the four options analyzed for dairy farms. The
results indicate that collection of manure from both parlor and apron for use to generate
electricity (Option IV) is profitable for the greatest number of farms, and would likely mitigate
the greatest amount of methane. The results for each source/use option are as follows:
• Option I: On-farm heating and cooling with parlor manure: About 270 dairy
farms with about 250,000 dairy cows will find it profitable to utilize parlor
manure to generate heating and cooling. Option I would mitigate about 7,500
metric tons of methane per year.
• Option II: On-farm electricity generation with parlor manure: Nearly 400 dairy
farms with about 370,000 dairy cows will find it profitable to generate electricity
for on-farm use using only parlor manure. About 11,000 metric tons of meth-
ane would be mitigated and about 5 megawatts of electricity generation
capacity would be added, which would produce about 34,000 megaWatt-hours
of electricity each year.
Option III: On-farm heating and cooling with parlor and apron manure: Over
500 dairy farms with about 475,000 dairy cows will profit using parlor and feed
apron manure to produce heating and cooling. Methane mitigation will range
between 15,000 and 50,000 metric tons per year, depending on the manure
systems the covered lagoons replace.
Option IV: On-farm electricity generation with parlor and apron manure: Over
2,000 dairy farms with almost 1.2 million dairy cows would profit using parlor
and feed apron manure to generate electricity for on-farm use. Methane
mitigation will range between 35,000 and 130,000 metric tons per year depend-
ing on the manure systems the covered lagoons replace. The amount of
methane that potentially could be recovered from dairies is about 115,000
metric tons per year. About 59 megawatts of electricity generation capacity
would be added, which would produce about 400,000 megawatt-hours of
electricity each year.
6-45
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Exhibit 6-25
Estimated Profitable Methane Recovery Using Covered Lagoons in the U.S.
Option Manure Source End Use
Methane Mitigated
Animals3 Farms (mt/yr)b
(percent) (percent) (percent)
Dairy Farms
1 Parlor
II Parlor
Heat & Cool
On-Farm Electricity
251,159
2.6
368,163
3.7
267
0.1
399
0.2
7,581
1.0
11,113
1.5
Parlor & Apron Heat & Cool
473,287 506 14,291-52,413
4.8 0.3 2.0 - 7.2
IV Parlor & Apron On-Farm Electricity 1,175,703
11.9
2,199 35,488-132,419
1.1 4.9-18.1
Hog Farms
All Manure On-Farm Electricity 4,231,418 1,791 173,056
8.3 0.7 15.5
Refers to the number of milking cows having an average weight of 1,400 Ibs. or the number of hogs
having an average weight of 138 Ibs.
The methane mitigated will depend upon the manure management system that is replaced by the
covered lagoon. For dairy options I and III, it is assumed that the covered lagoon replaces a lagoon
receiving about 15 percent of total manure. For dairy options II and IV, it is assumed that the covered
lagoon replaces a lagoon receiving between 15 and 55 percent of total manure. For hogs, It is
assumed that the covered lagoon replaces a lagoon receiving all the hog manure.
The potential for profitable methane recovery for hog farms is more promising than for
dairies. Although less than 1 percent of hog farms (about 1,800) would find it profitable to
recover methane, about 170,000 metric tons of methane would be mitigated. Profitable
methane recovery projects would affect over 4 million hogs. About 67 megawatts of electrici-
ty generation capacity would be added, which would produce about 470,000 megawatt-hours
of electricity each year. More methane could be recovered by hog farms than by dairies
because most hog farms are already collecting all of their manure in a manner that generates
methane (i.e., through liquid systems).
The combined impact of Option IV for dairy and the emissions reductions from hog
farms would be about 4,000 methane recovery projects producing over 125 megawatts of
electric generating capacity. The electricity produced would have a value of about $70 million
annually. Total methane emissions avoided would be about 0.2 to 0.3 Tg per year, and the
6-46
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total capital investment required nationally
for all 4,000 projects would be on the order
of $400 to $500 million.
These results are somewhat
Profitable methanereductions ooufcl be
as Mgh as 0.2ito Q&1|j:pef year and
could proyide over 125 raegawatts of
electric cjefteratsig capacity.
conservative because favorable financing
may be available (e.g., from the Farmers
Home Administration) for a portion of the
costs of upgrading the manure handling system, thereby reducing total costs. Also,
accelerated depreciation methods are available that would make the projects more profitable.
The impact of favorable financing and accelerated depreciation methods on methane
mitigation is about equal to a one cent increase in electricity prices. The amount of methane
mitigated under the various electricity price scenarios therefore may be underestimated in
cases where favorable financing and accelerated depreciation methods are available.
6.4.2 Regional Pattern of Profitability
The number of dairy and hog farms with the potential to recover methane for a profit
varies significantly from state to state. This regional pattern is determined by three factors:
Farm Size: Larger farms (in terms of number of animals) find methane recovery
more profitable. The distribution of farm sizes varies significantly by region.
• Methane Production: Warmer climates lead to more gas production in la-
goons.
Energy Prices: Higher energy prices make methane recovery more profitable.
This analysis shows that while many states have the climate conditions and energy prices
that are conducive to profitable methane recovery projects, relatively few states have
significant numbers of large farms with herds larger than the breakeven herd size. As a
result, a few states account for the majority of the emission reduction potential.
Exhibit 6-26 shows that it is profitable to recover methane on dairy farms with at least
500 cows with parlor and feed apron manure in most of the country. In the areas shaded in
the exhibit, farms with at least 500 cows will earn a profit by recovering methane from a
covered lagoon at current electricity prices.
However, although milk is produced in virtually every part of the country, dairy farms in
most parts of the country are smaller than 500 cows. Therefore, at current prices for
electricity they are too small to justify the investment in recovery systems. In the northeastern
and midwestern parts of the country, most dairy production comes from relatively small farms
that do not produce enough manure to justify a recovery system. In addition, because of the
cold winters, methane production from the lagoons will be reduced. In contrast, large dairies
account for a large part of dairy production in sunbelt states such as California, Texas,
Arizona, and Florida. These states have favorable climates for methane production and large
numbers of animals concentrated on each dairy.
Exhibit 6-27 lists the states in which methane recovery opportunities are the greatest.
These states have the combination of climate, electricity prices, and animal populations that
make recovery profitable. For each state the following is reported for each of the four cases
6-47
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Exhibit 6-27
States with Greatest Potential for Profitable Methane Recovery from Covered Lagoons
(Dairy Farms)
Rank
State
Animals6
Farms
Methane
Mitigated
(mt/yr)b
I. Heating & Cooling with Parlor Manure
U.S. Total
CA
AZ
251,159
222,128
29,031
267
239
28
7,581
6,705
876
1
2
1
2
3
4
U.S. Total
CA
AZ
NM
NY
368,163
323,877
29,031
14,068
1,188
399
357
28
12
2
11,113
9,776
876
425
36
III, Heating & Cooling with Parlor and Apron Manure
U.S. Total
473,287
506
14,291 - 52,413
1
2
CA
AZ
444,257
29,031
478
28
13,410-49,169
876 - 3,213
IV. Electricity Generation wfth Parlor and Apron Manure
U.S. Total
1,175,703
2,199
35,488 - 132,419
1
2
3
4
5
6
7
8
9
10
CA
TX
AZ
FL
NY
NM
GA
LA
SC
AL
833,623
88,989
76,370
75,453
30,719
29,660
16,137
9,611
4,106
3,895
1,320
283
104
198
95
30
70
41
17
15
25,163
2,686
2,305
2,278
927-
895-
487-
290-
124
118
- 92,263
-9,849
- 8,452
- 8,351
3,400
5,372
1,786
1,064
-661
-431
a Refers to the number of milking cows having an average weight of 1,400 Ibs.
b The methane mitigated will depend upon the manure management system that is replaced by the
covered lagoon. For dairy options I and III, it is assumed that the covered lagoon replaces a lagoon
receiving about 15 percent of total manure. For dairy options II and IV, it is assumed that the covered
lagoon replaces a lagoon receiving between 15 and 55 percent of total manure.
6-49
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examined: the number of cows on farms that can recover methane profitably; the number of
farms that can recover methane profitably; and the amount of methane mitigated. California
and Arizona dominate the results because areas in these states have the large dairy farms
necessary for the recovery options to be profitable at current energy prices.
Exhibit 6-28 illustrates the parts of the country where it is profitable to recover methane
for on-site electricity use for hog farms with at least 2,000 head. Based on the 1987 agricul-
ture census, relatively few states have a significant number of hog farms of this size, however.
Swine farms are primarily located in the "corn belt" states of Iowa, Illinois, Indiana, and
Missouri. In addition, the hog population in North Carolina has grown substantially in the last
twenty years. More recently, large hog farms have been developed in Virginia, but these were
developed after the 1987 census.
Exhibit 6-29 lists the states in which methane recovery opportunities for hog farms are
the greatest. Together, the top two states of Illinois and North Carolina account for about 70
percent of the profitable emission mitigation potential. Although Iowa contains by far the
most hogs of any state, the profitable emission mitigation potential there is small because
most Iowa hog farms are relatively small.
6.4.3 Sensitivity Analysis
The estimates are sensitive to a variety of factors and assumptions used in the
analysis. Several key factors are as follows:
Sensitivity to Electricity Prices. The economic feasibility of recovering methane from
dairy and swine manure using covered lagoons is sensitive to the value of the energy
produced from the recovered methane. The sensitivity to energy prices was evaluated for
dairy farms Option IV (electricity generation with parlor and feed apron manure) and for hog
farms. Four electricity rate sensitivity scenarios were constructed by increasing base case
prices by one, two, and four cents and by decreasing current prices by one cent per kWh.
For dairy farms, decreasing the base case rates by one cent reduces by about 550 the
number of farms that likely would find it profitable to recover (Exhibit 6-30). Total methane
recovered would be reduced by about 13,500 metric tons per year, or nearly 12 percent.
Electricity generation capacity would decrease by about 7 megawatts. Increasing base case
electricity rates by one cent adds about 400 farms and 100,000 cows relative to the base
case. About 5 megawatts of electricity generation capacity are added, and methane
mitigation increases by about 10 percent.
Increases of two and four cents have even larger impacts. A two cent increase adds
nearly 1,000 farms and 200,000 cows, and methane mitigation increases by about 20 percent.
For the four cent estimate, methane mitigation increases by about 40 percent, and dairy farms
recovering methane would account for nearly 1.7 million dairy cows (approximately 17 percent
of the U.S. total), and the total electricity generation capacity would be about 81 megawatts.
The sensitivity of the estimates for hog farms is greater (Exhibit 6-30). With a one cent
increase in electricity prices, methane mitigation at hog farms increases by over 70 percent.
Methane mitigation more than doubles when an increase of two cents is assumed. At this
level, about one-third of methane emissions from hog farm manure would be eliminated by
the recovery projects, and approximately 7,000 recovery projects are estimated to be
profitable.
6-50
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Exhibit 6-29
States with Greatest Potential for Profitable Methane Recovery using Covered
Lagoons (Hog Farms)
Rank
1
2
3
4
5
6
7
8
9
10
State
On-Farm Electricity
U.S. Total
NC
IL
AR
GA
SC
KS
CA
AZ
PA
FL
Animals3 Farms
Generation with AH Manure
4.231,418 1,791
1,443,274 386
1,708,394 988
415,141 40
139,603 81
62,555 33
85,620 47
49,566 28
43,363 19
135,466 72
25,177 32
Methane
Mitigated
(mt/yr)b
173.056
74,670
47.667
22,397
7,554
3,570
3,230
2,931
2,565
1,631
1,456
a Refers to the number of hogs having an average weight of 138 Ibs.
b The methane mitigated will depend upon the manure management system that is replaced by the
covered lagoon. For hogs, it is assumed that the covered lagoon replaces a lagoon receiving all the
hog manure.
Similarly, decreases in the price of electricity have a large impact on the economic
viability of methane recovery from hog farms. A one cent decline in prices would reduce the
number of farms and animals by nearly 50 percent.
The sensitivity of the results to electricity prices is important for two reasons. First, the
base case analysis was performed using state average electricity prices. Prices vary within
states, so that some will be above and below the values used here. Second, the sensitivity of
the results to electricity prices demonstrates how much additional methane can be mitigated if
prices increase in the future or if preferential electricity rates are provided for these projects.
For example, using the estimates in Exhibit 6-30, a two cent increase in electricity prices
would reduce methane emissions by about 0.2 Tg beyond the base case estimates. If a two-
cent subsidy per kWh were used to achieve this reduction, the cost of the subsidy would be
about $40 million per year, or about $200 per metric ton of methane emissions avoided.
Uncertainty in Recovery Systems Costs. The costs of the recovery and utilization
system components (e.g., cover material, engine generator costs) are not known with
certainty and may vary from location to location. The combined impact of the uncertainty in
the various factors affecting the profitability of methane recovery projects was evaluated by
performing the analysis with a stochastic model. The following uncertainty ranges were
simulated independently:
• Engine generator costs: A normal distribution was simulated using a standard
deviation of 10 percent about the mean engine generator cost estimate.
6-52
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Exhibit 6-30
Profitable Methane Mitigation Under a Range of Electricity Prices
Methane Mitigated
Animals3 Farms (mt/yr)b
Electricity Price Scenario (percent) (percent) (percent)
Farms generating electricity for on-farm use with parlor and apron manure
Current rates minus $0.01 1 ,024,993 1 ,651 30,939 - 1 1 4,924
10.4 0.8 4.2 - 15.7
' .......................................... i","l75,703 .............. 2,199 ................... 35"488"-'l"3e"'
11.9 1.1 4.9-18.1
,278,910 2,602
13.0 1.3 5.3-19.8
3,122
14.2 1.6 5.8-21.6
i",678,986 .............. 4,590 ................... '56"686"-"l89"568"
17.1 2.3 6.9 - 26.0
Hog Farms generating electricity for on-farm use with all manure
Current rates minus $0.01 2,524,982 981 102,796
4.9 0.4 9.2
cTirfe^'7ates'(Base"case) 4"23i"418 T"79"i 173"656"
8.3 0.7 15.5
C^rrenFrates'pius"$61oi 8,360,595 4"477 307,286'
16.4 1.9 26.9
Currenfrates plus $0.02 TT,702,196 7,069 393,236""
22.9 2.9 35.1
Current "rates'pius"$0.04 ^9,224,599 13781 587,539
37.6 5.7 52.5
Refers to the number of milking cows having an average weight of 1,400 Ibs. or the number of hogs
having an average weight of 138 Ibs.
The methane mitigated will depend upon the manure management system that is replaced by the
covered lagoon. For dairy options I and III, it is assumed that the covered lagoon replaces a lagoon
receiving between 15 and 55 percent of total manure. For dairy options II and IV, it is assumed that the
covered lagoon replaces a lagoon receiving between 15 and 55 percent of total manure. For hogs, it is
assumed that the covered lagoon replaces a lagoon receiving all the hog manure.
Engine generator O&M: A uniform distribution was simulated using a range of
20 percent about the mean estimate of $0.015 per kWh.
Other costs: A uniform distribution was simulated using a range of 20 percent
about the mean estimate for all other cost components (e.g., cover material,
piping, excavation, labor).
The results of this combined assessment of uncertainty indicates that the uncertainty
in emission reduction varies by the utilization option and animal type and that the uncertainty
is asymmetric about the central estimates. In particular:
6-53
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For Dairy Option I (heating and cooling with parlor manure) 90 percent of the
stochastically determined emission reduction values fall within a range of minus
15 percent to plus 170 percent of the baseline value.
• For Dairy Option II (on-farm electricity production with parlor manure) 90
percent of the stochastically determined emission reduction values fall within a
range of minus 40 percent to plus 100 percent of the baseline value.
For Dairy Option III (heating and cooling the parlor and apron manure) 90
percent of the stochastically determined emission reduction values fall within a
range of minus 50 percent to plus 44 percent of the baseline value.
For Dairy Option IV (on-farm electricity production with parlor and apron
manure) 90 percent of the stochastically determined emission reduction values
fall within a range of minus 24 percent to plus 17 percent of the baseline value.
For Hogs (on-farm electricity production with all manure) 90 percent of the
stochastically determined emission reduction values fall within a range of minus
32 percent to plus 80 percent of the baseline value.
These results indicate that there is considerable up-side potential for methane recovery for
dairy options I and II, as well as for hog farms. Dairy option IV is least sensitive to the
uncertainties examined.
6.4.4 Impact of Including Environmental Benefits
From the perspective of social benefits the value of livestock manure methane
recovery projects is underestimated because the revenue estimates (by off-setting energy
purchases) do not include the value of the methane and other environmental benefits
achieved. By omitting these benefits, profitability decisions made by individual farmers do not
reflect the full value of the project to society.
For example, the cost of reducing carbon dioxide (CO2) build up in the atmosphere
has been estimated in the range of $5 to $20 per ton of carbon contained in CO2. With this
range, the environmental benefit of reducing methane emissions to the atmosphere from
livestock manure translates into a value of about $0.0086 to $0.0345 per kWh.18 In
addition, assuming that producing electricity displaces fossil fuel produced CO2 at the rate of
18 If the benefit of reducing carbon dioxide emissions is $5 per metric ton of carbon contained in CO2 and
assuming a mass-based global warming potential (GWP) for CH4 of 22, then value of recovering methane from
livestock manure can be computed as follows:
$5 . 12mtC . 22 ™t CO2 19.16 g / ft3 CH4 15.000 BTU/kWh = $00086/kwh
ImtC 44mtCO2 mtCH4 10* g/mt 1,000 BTU/ft3 CH4
Similar computations yield $0.0345 for $20/ton carbon and $0.1724/kWh for $100/ton carbon.
6-54
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1.5 Ib per kWh,19 then an additional benefit of $0.0009/kWh to $0.0037/kWh can be
realized.20 Combining these two benefits, the total value of recovering methane from
livestock manure ranges between $0.0095/kWh to $0.0382/kWh. This value may be as high
as $0.1910/kWh if the benefit of reducing carbon dioxide emissions is as high as $100 per ton
of carbon contained in CO2.
The estimates of emissions reductions that could be achieved profitably are sensitive
to emission reduction values in this range. In particular, the estimates of profitable methane
mitigation from hog farms is sensitive, as follows:
At $0.0095/kWh: Profitable emission reductions from hog farms increase by
about 50 percent. Profitable emission reductions from dairy farms (assuming
Option IV) increase by less than 10 percent.
At $0.0382/kWh: Profitable emission reductions from hog farms increase by
150 percent. Profitable emission reductions from dairy farms (assuming Option
IV) increase by almost 30 percent.
At $0.19/kWh, the estimates of profitable methane recovery for both hog farms and dairy
farms (option IV) would increase substantially, by about 350 and 170 percent respectively.
6.4.5 Future Emission Reduction Opportunities
The amount of methane mitigation
that can be achieved in the future depends
on: (1) the amount of methane emitted from
livestock manure in the future; and (2) the
portion of the emissions that can be mitigat-
ed profitably. Trends in dairy and hog pro-
duction and manure management are affect-
ing both of these factors.
projects eoulci potentially mitigate two
to three times f?e amissions lhat can be
mitigated; today; ;t ; ;
19 The CO2 emission factor of 1.5 Ib COg/kWh is based on values used by the USEPA Green Lights Program
to estimate pollution prevention (USEPA 1993b). The factor is calculated by dividing total CO- emissions from all
electrical power generation in the U.S. (including independent power producers) of 3.952-101* Ibs CO2 by total
electricity sales of 2,582-109 kWh (USDOE 1992). The factor therefore represents a national average emission
factor for generating electricity from all fuel sources (e.g., coal, oil, hydroelectric, nuclear) and does not necessarily
reflect the marginal reduction in CO2 emissions associated with generating one fewer kilowatt hour of electrical
power. Using the factor of 1.5 CO^kWh likely underestimates the actual fossil CO2 emissions reduction because
the landfill generated power likely will offset power that would be generated by CO2 producing fossil fuels such as
coal or oil and likely would not offset hydroelectric or nuclear power that would produce no fossil CO2.
20 If the benefit of reducing carbon dioxide emissions is $5 per metric ton of carbon contained in CO2 and
assuming that landfill produced electricity displaces fossil fuel produced CO2 at the rate of 1.5 Ib per kWh, then
value of reducing net C02 emissions by generating electricity with landfill gas can be computed as follows:
1.5lb CO,
1 mt
12mtC
1 kWh 2.2046 Ib 1.000kg 44 mt CO2 1 mt C
= $0.0009/kWh
Similar computations yield $0.037 for $20/ton carbon and $0.0186/kWh for $100/ton carbon.
6-55
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The amount of methane emitted in the future will be driven by trends in animal
production and the systems used to manage livestock manure. USEPA (1993) reports that
both dairy production may increase about 18 to 30 percent from 1990 to 2010, and pork
production may increase by zero to 14 percent. In the absence of changes in management
practices, methane emissions would be expected to increase by the same amounts.
However, producers are shifting toward the use of liquid management systems (EPA
1993). EPA (1993) estimates that methane emissions may increase by 45 to 80 percent from
dairy and hog farms as a result. If so, the use of covered lagoons to recover methane will
result in larger methane emissions reductions than estimated based on current practices.
The profitability of recovery in the future will be affected by the costs and benefits of
the recovery systems. If a significant number of projects are performed, one would expect
the cost per project to decline as experience is gained in the design and operation of the
systems. If materials costs or energy prices change, profitability will also be affected.
One key trend affecting profitability is that the average size of hog and dairy farms is
increasing (Exhibit 6-31). Since 1978, the portion of dairy cows on dairy farms with 500 or
more head has increased from 7 percent to about 12 percent nationally. A trend toward
increasing dairy farm size has also been seen in the key states of California, Arizona, and
Texas. Wisconsin, the state with the most dairy cows, has very few cows on large farms (with
over 500 head). Because recovery projects are more economically viable at larger dairy
farms, the increase in cows on large farms will increase the portion of cows that are on farms
that can recover methane profitably.
Similarly, the number of hogs on hog farms with 1,000 or more head has increased
(Exhibit 6-32). Since 1978, the portion of hogs on hog farms with 1,000 or more head has
increased from 23 percent to about 38 percent nationally. The trend is also seen in the key
states of Iowa, Illinois, and North Carolina. As with dairy farms, recovery projects are more
economically viable at larger hog farms.
Based on these trends, several scenarios of future methane mitigation were derived.
Current Practices. This scenario assumes that all factors affecting methane
generation and the profitability of methane recovery remain unchanged.
Methane emissions and mitigation change proportionately with changes in milk
and pork production.
• Increased Use of Liquid Manure Management Systems. This scenario reflects
the fact that dairies and hog farms are shifting to liquid based manure manage-
ment systems. Methane mitigated increases substantially.
• Increased Use of Liquid Manure Management Systems and Increased Farm
Sizes. In addition to the assumptions in Scenario 2, this scenario assumes that
a larger fraction of cows and hogs will be on farms that can recover methane
economically because of increases in farm size. Assumed increases in farm
sizes are as follows:
Dairy Farms: By 2000, 20 percent of dairy cows will be managed in
dairies with over 500 head, and by 2010, 25 percent of dairy cows will
6-56
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be managed in these large dairies. In 1987 about 12 percent of dairy
cows were in farms with at least 500 cows.
Hog Farms: By 2000, 45 percent of swine will be managed in farms
with at least 1,000 head, and that by 2010, 55 percent of hogs will be
managed in these large farms. In 1987 about 38 percent of hogs were
managed in farms with at least 1,000 head.
State
California
Texas
Arizona
Wisconsin
Nationally
Dairy Cows
Year
1978
1982
1987
1978
1982
1987
1978
1982
1987
1978
1982
1987
1978
1982
1987
a Assumes an average weight of 1,400
Source: Bureau of
the Census (1987).
Exhibit 6-31
on Large Farms Over Time
Number of Cows3
(OOOs)
837
946
1,070
307
323
356
70
82
86
1,700
1,853
1,743
10,221
10,850
1 0,085
Ibs. per milking cow.
Percentage of Cows
on Dairy Farms of
500 or More Head
47%
53%
63%
8%
8%
19%
61%
71%
80%
0%
0.2%
0.3%
7%
8%
12%
For dairy farms these scenarios are evaluated using Option IV where parlor and feed
apron manure is used to generate electricity. For swine farms these scenarios are evaluated
assuming that methane is recovered to generate electricity.
Exhibit 6-33 presents the estimates for methane mitigated under these various
scenarios. As shown in the exhibit, emissions mitigation may increase slightly as the result of
increases in production in the future. However, as a result of the trend toward the use of
liquid systems, opportunities for emissions mitigation could increase substantially. As more
farms switch to liquid manure handling systems, methane emissions could increase substan-
tially over the next 10 to 20 years (EPA, 1992). Profitable methane recovery projects could
help offset these increases in emissions.
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Exhibit 6-32
Hogs on Large Farms Over Time
State
North Carolina
Illinois
Iowa
Nationally
Year
1978
1982
1987
1978
1982
1987
1978
1982
1987
1978
1982
1987
Number of Hogs3
(OOOs)
1,901
2,047
2,547
6,206
5,989
5,643
14,695
14,333
12,983
57,697
55,366
52,271
Percentage of Hogs
on Farms of 1 ,000 or
More Head
47%
65%
79%
27%
36%
43%
21%
27%
32%
23%
31%
38%
a Assumes an average weight of 138 Ibs. per hog.
Source: Bureau of the Census (1987).
Finally, the increasing concentration of animals on large farms will increase the portion
of animals for which methane recovery projects are profitable. The continuation of current
trends may increase substantially the opportunity to mitigate methane emissions profitably.
By 2010, profitable methane recovery projects could potentially mitigate two to three times the
emissions that can be mitigated today.
6.5 BARRIERS
As discussed above, profitable opportunities exist for reducing methane emissions
from livestock manure. Proven technologies are available to recover and utilize the methane
to meet on-farm energy needs. Over twenty livestock operations across the country are
successfully utilizing these technologies today.
While there are many livestock operations in which methane recovery is apparently
viable, digester systems are often not undertaken because of various barriers. Informational
barriers specific to methane recovery systems from livestock manure are perhaps the most
important barrier. In addition, economic, financial, and regulatory barriers are common to
virtually all "alternative" energy sources (e.g., cogeneration, biomass, solar, and wind).21
21 The economic and financial barriers common to most alternative energy sources are discussed more fully
in Chapter 7 of this report.
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Exhibit 6-33
Emissions Reduction Potential for 2000 and 2010
Year
1990
2000
2010
Extend Out
Percentage Change in
Production8
Dairy Swine
12% 10%
25% 10%
?Qf& f» ISCfcSBS:
Estimated Methane
(mt/yr)
Dairy
35,488 - 132,419
39,750 - 148,300
44,350 - 165,500
".":-:•
Mitigated
Swine
173,056
190,360
190,360
Increased Use of Uquid Manure Management Systems !
a
b
c
d
Year
1990
2000
2010
Year
1990
2000
2010
Percentage Increase in
Emissions
Dairy Swine
75% 85%
90% 85%
Increase ir^Pef
-------
During their development in the early 1970s, the success of commercial-scale
anaerobic digesters was limited by two types of problems:
mechanical problems with the digesters and utilization equipment; and
• biological problems that limit the amount of methane produced.
The most common mechanical and biological problems with digester use were identified
through a study of the commercial-scale anaerobic digester industry in the U.S. (ICF 1992).
Operational data were gathered on digesters currently operating, not operating, or designed
and never built. Information was compiled from both source materials and conversations with
digester owners and operators, engineers who design and build digesters, and university
researchers. This information shows that the mechanical and biological barriers that have
limited the success of digester systems have been solved.
Mechanical Problems. During the 1970s and early 1980s mechanical problems
frequently caused either the temporary or complete shut down of the digester. The digester
operators were forced to spend considerable time and resources to keep the systems
running. The components of the digester systems that experienced the greatest difficulties
were the engine-generators used to produce electricity and the pumps used to transport
manure to and from the digester (ICF 1992).
Engine-generator problems were the most common trouble with the digester systems.
These problems were particularly expensive because of the high cost of repairs as well as the
lost electricity value of the unused biogas. Many of the engine-generators installed in
digesters required frequent overhaul or rebuilding long before their expected operational
lifetime expired. Many of the generators were not designed to operate continuously and
under varying load conditions. These stresses contributed to mechanical breakdowns.
However, by installing a generator with a capacity consistent with the gas flow, these stresses
can be greatly relieved (Ashworth 1985). In addition, generators are available that can
operate continuously without problem if properly maintained (RCM 1991d). An engine-
generator powered by methane from a covered lagoon treating hog manure at Royal Farms in
California has operated continuously for over ten years without significant trouble (ICF 1992).
In some cases the presence of hydrogen sulfide in the biogas contributes to the
breakdown of an engine-generator. The amount of hydrogen sulfide depends on the
characteristics of the manure. In most cases, this problem can be eliminated either by
removing the hydrogen sulfide before it reaches the engine-generator or by changing the
engine oil frequently (RCM 1991d).
Problems with the pumps used to transport manure to and from the digesters were the
next most common mechanical problem. These pumps were often clogged with debris
gathered during the collection of manure, especially if the manure was scraped and hauled to
the digester. In the case of mixed-tank digesters, the breakdown of these pumps could have
been dangerous if the digester had been left unattended. If the influent loading continued
while the pumps were clogged, the digester tank could fill to capacity and eventually lift itself
from its foundation (ICF 1992). However, pumps are now widely available that are not likely
to clog and so this problem has been greatly minimized.
The key factors for the successful mechanical operation of digesters are adequate
digester design and routine inspection and maintenance. By utilizing pumps that are not
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likely to clog and by changing the engine-generator oil frequently, digester systems will
operate trouble-free.
Biological Problems: Biological problems also limit the success of anaerobic digester
technology by reducing the amount of methane that is produced. Because the economic
feasibility of anaerobic digesters results from methane production, biological problems can
severely limit economic benefits. Problems which can limit biogas production include:
• variable manure characteristics;
• inadequate heat maintenance; and
• build-up of non-degradable materials in the tanks or lagoons.
The composition and quantity of the influent manure determines the maximum level of biogas
production that can be achieved. The composition and quantity of the manure depends on
the number and type of animals and their diet. In addition, the presence of antibiotics or
other foreign material in the manure can limit biogas production.
Heat maintenance is important for mixed-tank and plug-flow digesters. (Anaerobic
lagoon digesters operate at the ambient outdoor temperature.) In general, the greater the
temperature within the digester, the greater the biogas production. However, large tempera-
ture variations can severely limit biogas production. Many of the digesters built in the 1970s
were operated at too low a temperature because they lacked adequate systems for maintain-
ing heat. However, by providing adequate heating systems (e.g., using waste heat from the
utilization equipment) and insulation, mixed-tank and plug-flow digesters can be maintained at
proper temperatures.
Inorganic or non-degradable materials can accumulate in a digester or covered
lagoon. These materials reduce the effective volume of the digester or lagoon and the
amount of biogas that can be produced. In addition, these materials can clog the digester or
cause the mechanical equipment to become inoperative. In the case of lagoons, the
excessive build up of non-degradable material may require a costly lagoon cleaning. These
problems can be greatly alleviated by removing non-degradable materials prior to their
entering the digester. This is accomplished with either separators (for dairies), settling basins
or mixing pits. The lagoon digester operated at the Randleigh dairy uses a separator and has
not experienced problems with the build-up of non-degradable material (Safley 1991).
The key factors for the successful biological operation of digesters are to assure a
consistent quantity and composition of manure to the digester and to eliminate or reduce the
amount of inorganic and non-degradable material that enters the digester or lagoon.
Economic, Financial, and Regulatory Barriers
Many of the economic barriers that limit the adoption of methane recovery systems are
common to other biomass energy sources or to other independent power producers. These
problems include: low utility "buy back" rates that limit the value of the biogas produced; and
inadequate financing that limits the ability of farmers to purchase a biogas recovery and
utilization system. In the case of methane recovery from livestock manure, the low "buy back"
rate barrier is less of a problem because in most cases the energy produced (e.g., electricity)
can be used to displace the energy purchased by the farmer from the utility. Consequently,
the value to the farmer is driven by the rate paid and not the rate the utility would pay to
purchase the energy. If utilities were to lower their electricity rates in order to compete with
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these recovery projects, the economic viability of the projects would be reduced because
their economic viability is very sensitive to the rate that farmers pay for electricity.
Because of the perceived "high risk" and novelty of methane recovery projects, many
financial institutions and other lenders are unwilling to provide loans to farmers who would
like to install methane recovery systems. In other cases, government cost share loans for
constructing manure management systems may not include methane recovery systems.
Regulations exist that hinder the development of digester systems. In some cases
where livestock operations are near large metropolitan areas, energy recovery equipment
must meet air emission standards that do not consider that the equipment is being used to
mitigate other harmful emissions. Additionally, because manure management is being
increasingly regulated, adding a methane recovery system to an existing manure manage-
ment system may require permit modifications. The costs of applying for and obtaining
changes in operating permits have not been included in these cost estimates.
Opportunities for Overcoming Barriers
Opportunities are available for overcoming these informational, economic, financial
and regulatory barriers. Informational barriers can be overcome by publicizing the reliability
and profitability of the existing methane recovery projects to livestock industry leaders and to
the engineers who design and install livestock manure management systems. For instance,
decision support information can be provided to agricultural engineers who design and build
manure management systems so that the most profitable, environmentally responsible
manure management systems will be built.
Economic barriers can be overcome by emphasizing on-farm energy use that offsets
energy purchases and by recognizing the additional benefits provided by methane recovery
systems. These benefits include the nutrient value of the digested manure, reduced odors
and other air pollution problems, and reduced risk of ground and surface water contamina-
tion.
Financial barriers can be overcome by providing information to lenders on the
reliability of existing recovery projects or by allowing the inclusion of methane recovery
systems in government financed manure management systems. Other innovative financing
mechanisms might include financing through local electric cooperatives.
Regulatory barriers may be overcome by providing information on the environmental
benefits that result from methane recovery projects. As described above, these benefits
included reduced methane emissions, reduced odors and other air pollution problems, and
decreased risk of ground and surface water pollution.
Exhibit 6-34 summarizes the barriers limiting methane recovery from livestock manure
and the steps that can be undertaken to overcome these barriers. As the information about
these projects is disseminated, and as additional successful projects are undertaken, the
viability of these projects will become clear.
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Exhibit 6-34
Barriers Limiting Methane Recovery from Livestock Manure
Barrier
Solution
Possible
Governmental Actions
Lack of Information on Current Technologies
Many early methane recovery projects were
unsuccessful because of mechanical and
maintenance problems. These failures gave the
technology a bad reputation. Most of these
problems have been resolved and commercial-
scale methane recovery systems are reliable and
cost-effective.
Disseminate infor-
mation existing suc-
cessful methane
recovery tech-
nologies.
Develop voluntary
program to promote
key demon-strations
and more widespread
use of available
technologies.
Low Utility Buy Back Rates
Manure methane recovery projects receive low
"avoided cost" prices for the electric power if
farmers wish to sell power to electric utilities.
Increase buy-back
rates.
Emphasize on-farm
energy use which
displaces purchased
electricity.
Encourage Public Utility
Commissions (PUCs) to
allow higher buy back
rates for environ-
mentally beneficial
projects.
Siting and Permitting
Adding a methane recovery system to an existing
manure management system may require permit
modifications. In some cases these costs may
be substantial.
Do not require a
permit modification for
adding methane
recovery to an
existing manure
management system.
Develop voluntary
program to provide
information on the
environmental benefits
that results from
methane recovery
projects.
6.6 LIMITATIONS
This analysis is limited by a variety of factors. Most importantly, there are a variety of
site-specific factors that influence the cost and feasibility of managing manure in covered
lagoons and utilizing recovered methane. While this analysis uses cost estimates based on
case studies of dairies and hog farms in key areas of the U.S., some farms will find that
projects will be more or less costly than the estimates used here. The implications of the
diversity of site-specific situations is not considered.
Estimates of profitability are also limited by uncertainties in various estimates. Average
values for manure composition were used to estimate expected biogas production. Actual
composition varies depending on animal diets and the manner in which manure is handled.
Similarly, expected biogas generation rates from lagoons and digesters were estimated using
models of lagoon and digester performance. Additional empirical data are needed to improve
the basis for making these estimates. Conservative assumptions were used to avoid over-
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estimating methane recovery potentials, and consequently the economic viability and energy
production possibilities may be underestimated.
Estimates of the methane emissions mitigated are particularly uncertain because the
estimates depend, in part, on the manure management system that would have been used
had the covered lagoon or digester not been in place. If a solid manure management system
had been in place (e.g., a drylot or daily spread system), then methane mitigation would have
been quite low. If an uncovered lagoon had been in place, then methane mitigation would
have been quite high. Given the uncertainty in this portion of the assessment, the estimates
of the emissions mitigated are quite uncertain.
Finally, this analysis does not consider several of the institutional and technological
barriers that prevent the implementation of on-farm recovery systems. Barriers to the
successful implementation of on-farm recovery systems include low utility buy-back rates,
inadequate financing, and inadequate information on proper system designs and operating
practices.
6.7 REFERENCES
Ashworth, John H. 1985. "Problems with Installed Commercial Anaerobic Digesters in the
United States: Results of Site Visits." Report prepared by Associates in Rural Develop-
ment, Inc under contract to the Solar Energy Research Institute.
Bureau of the Census, 1987 Census of Agriculture. U.S. Department of Commerce. Washing-
ton, D.C. 1987.
Chandler, Jeffrey A., S. Jack Hermes, and Kenneth D. Smith. 1983. "A Low Cost 75 kW
Covered Lagoon Biogas System." Paper present at Energy from Biomass and Wastes
VII, Lake Buena Vista, FL January 25, 1983.
Chandler, Jeffrey 1990. Personal communication with Jeffrey Chandler, President of Jiff
Chandler + Associates, Elk Grove, CA.
Currence, H. David and Curtis A. Bohl. 1988a. "Computerized On-Farm Energy Analysis Part
II Information for Improving Electric Energy Use Efficiency and for Leveling Demand."
Department of Agricultural Engineering. University of Missouri. Columbia, Missouri.
June 1, 1988.
Currence, H. David and Curtis A. Bohl. 1988b. "Computerized On-Farm Energy Analysis Part
II Information for Improving Electric Energy Use Efficiency and for Leveling Demand."
Department of Agricultural Engineering. University of Missouri. Columbia, Missouri.
June 1, 1988.
DOE (U.S. Department of Energy). Energy Information Administration, Electric Sales &
Revenue 1989, Jan 1991.
George J.A., C.D. Fulhage, and S.W. Melvin, "A Summary of Midwest Livestock Odor Court
Actions", Agricultural Waste Utilization and Management, American Society of Agricul-
tural Engineers.
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Gettier, Dr. Stacy. 1993. Personal communication with Dr. Stacy Gettier, Agronomist,
Smithfield-Carroll's Farms. February 1993.
Hoffman, Mark S. 1991. The World Almanac and Book of Facts 1992. Pharos Books. New
York.
ICF 1992. "U.S. Anaerobic Farm Digester Study." Report prepared by ICF Incorporated under
contract to the U.S. Environmental Protection Agency.
Koelsch, R.K. 1982. "Water Heating Energy Conservation Practices for the Dairy." Depart-
ment of Agricultural Engineering, Cornell University. Unpublished manuscript.
Koelsch, R.K., E.E. Fabian, R.W. Guest, and J.K Campbell 1989. "Anaerobic Digesters for
Dairy Farms." Agricultural and Biological Engineering, Department of Agricultural and
Biological Engineering, New York State College of Agriculture and Life Sciences,
Ithaca, New York, Extension Bulletin 458.
Ledbetter, G. 1991. "Processing Animal Waste Profitably." From IPCC Workshop Findings,
December 1989.
Loehr, Raymond C. 1984. Pollution Control for Agriculture. Second Edition. Academic
Press, Inc. Orlando.
Lusk, Philip D. 1991. "Comparative Economic Analysis: Anaerobic Digester Case Study."
Bioresource Technology. 36:223-228.
Murphy, Con. 1989. Personal communication with Con Murphy, Plant Manager of Mesquite
Lake Project manure combustion power plant. September 1989.
Nakano, Hiroshi W. 1993. Personal communication with Hiroshi W. Nakano, UNISYN
Biowaste Technology. Seattle. March 15, 1993.
Nelson, Stanley. 1987. "Dairy Studies, Phase II." Dairyland Power Cooperative, LaCrosse,
Wisconsin.
NEOS. 1993. "Energy Conversion of Animal Manures in 13 Western States." Prepared by
NEOS Corporation for the U.S. Department of Energy Regional Biomass Energy
Program. Contract Number 65-90WA05637. NEOS Corporation. Lakewood, Colora-
do. Draft Report. March 1993.
RCM (Resource Conservation Management). 1989. Personal communication with Mark
Moser, President of RCM Digesters, Berkeley, CA. September 18, 1989.
RCM (Resource Conservation Management) 1990. "Estimating the Costs and Benefits of
Methane Recovery from New Texas Dairy Waste Lagoons to Mitigate New Methane
Sources." Draft report prepared by RCM Inc. for the U.S. Environmental Protection
Agency under sub-contract to ICF, Inc. December 1990.
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RCM (Resource Conservation Management). 1991 a. "Potential Methane Generation and
Mitigation Study of the South Valley of California." Draft report prepared by RCM Inc.
for the U.S. Environmental Protection Agency under sub-contract to ICF, Inc. July 27,
1991.
RCM (Resource Conservation Management). 1991b. "Potential Methane Generation and
Mitigation from Hog Waste Storages in the States of Iowa and Illinois." Draft report
prepared by RCM Inc. for the U.S. Environmental Protection Agency under sub-
contract to ICF, Inc.
RCM (Resource Conservation Management). 1991c. "Potential Methane Generation and
Mitigation from Hog Waste Storages in the State of North Carolina." Draft report
prepared by RCM Inc. for the U.S. Environmental Protection Agency under sub-
contract to ICF, Inc.
RCM (Resource Conservation Management). 1991d. Personal communication with Mark
Moser, President of RCM Digesters, Berkeley, CA.
RCM (Resource Conservation Management) and ICF 1991. "LAGMET: Animal Waste Lagoon
Methane Emissions Model." Draft report prepared by RCM, Inc. and ICF, Inc. under
contract to the U.S. Environmental Protection Agency.
Safley, LM. 1991. Personal Communication with Dr. Lawson Safley. Professor of Biological
and Agricultural Engineering. North Carolina State University. Raleigh, North Carolina.
January 1991.
Safley, L M., M.E. Casada, J.W. Woodbury, and K.F. Roos 1992. "Global Methane Emissions
from Livestock and Poultry Manure." EPA/400/1091/048. U.S. Environmental Protec-
tion Agency. Washington, D.C. February 1992.
Safley, L.M., Jr. and P.O. Lusk. 1991. Low Temperature Anaerobic Digester, Energy Division.
North Carolina Department of Economic and Community Development.
Shuyler, Lynn and James W. Meek. 1989. "EPA Guidelines Concerning Agricultural Manure
Management Practices." in Dairy Manure Management Proceedings from the Dairy
Manure Management Symposium, Syracuse, New York, February 22-24, 1989.
NRAES-31. Northeast Regional Agricultural Engineering Service, Ithaca, New York.
Stanley, Nelson. 1987. "Dairy Studies, Phase II." Dairyland Power Cooperative. La Crosse,
Wisconsin.
Stetson, L.E., G.L. Stark and K.L. Farrell. 1984. "Electric Demand Characteristics of Nebraska
Farmstead," Technical Paper Presented at the Annual Conference, National Food &
Energy Council, Inc. July 1984.
Treleven, M. 1989. "Black Gold." California Farmer, June 3, 1989, pp. 8-9, 27.
UNISYN (Universal Synergetics Inc.). 1992. Tillamook Anaerobic Digestion Facility Precon-
struction Study." Prepared for the Tillamook Mead Committee with Funding from the
Oregon Department of Energy. UNISYN. Seattle. March 1992.
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USEPA (U.S. Environmental Protection Agency) 1992. Technological Options for Reducing
Methane Emissions: Background Document of the Response Strategies Working
Group." Draft report prepared by the U.S./Japan Working Group on Methane, January
1992.
USEPA (U.S. Environmental Protection Agency) 1993. Anthropogenic Methane Emissions in
the United States. Report to the Congress, prepared by the Global Change Division,
Office of Air and Radiation, EPA, Washington, D.C.
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CHAPTER 7
BARRIERS TO METHANE RECOVERY PROJECTS
While opportunities to reduce methane emissions are technically feasible and
economically viable, methane mitigation projects are often not undertaken because of various
barriers. Economic and regulatory barriers are common to virtually all "alternative" energy
sources. This chapter describes the barriers that are common to all or several of the sources.
Barriers that are specific to a particular source or industry are described in the individual
chapters.
Recovery of methane and use as an energy source can be profitable for operators of
coal mines, landfills, and livestock manure systems. However, certain conditions in the
electric power and natural gas industries may prevent the development of such projects. In
the electric power industry, these barriers are related to general issues of small power
production and transmission access. In the natural gas industry, the barriers are related to
limited pipeline and storage capacity, as well as the difficulties confronted by small producers
finding buyers for their gas.
7.1 CONDITIONS IN THE ELECTRIC POWER INDUSTRY
As discussed in the previous chapters of this report, the methane recovered from coal
mines, landfills, and livestock manure systems can be used to generate electricity. Coal
mines can generate power for on-site needs or off-site sales. Power generated from methane
recovered from manure systems could be used for on-farm energy needs, while recovered
landfill methane would be used to generate power for off-site sales. Obstacles exist, however,
that limit the attractiveness of power generation. Though the discussion in this chapter refers
to coal mines, landfills, and livestock manure systems, the problems are not unique to
methane recovery projects. Other electric power producers that are new, relatively small or
utilizing environmentally beneficial fuels typically face these same challenges. The following
discussion is divided between issues relating to power generation for on-site use and issues
related to off-site sale of electricity.
7.1.1 Power Generation for On-Srte Use
Coal mines and farms with liquid or slurry livestock manure systems would need to
address several issues before on-site power generation could become a realistic option.
Power generated from recovered methane may be intermittent or on-site electricity needs may
exceed the capacity of the on-site generating station. Accordingly, both farms and coal
mines would need to continue to rely on local utilities for back-up power or for power to
supplement their on-site generating capacity. Therefore, it would be necessary for coal mines
or farms and local utilities to enter an agreement that would meet the unique needs of the
methane recovery project. Furthermore, because coal mines and large livestock facilities are
significant electricity consumers, price competition from utilities may become an issue for
operations wishing to generate power for their own use.
7-1
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7.1.2 Off-Site Sale of Electricity
Landfills and large and gassy coal mines may be able to generate enough power from
recovered methane to warrant the off-site sale of electricity. In such cases, the coal mine or
landfill operators may attempt to sell power to their local utility, or to a regional utility with the
local utility providing transmission, or "wheeling" services. The following discussion reviews a
number of challenges that face off-site sale of electricity generated by unconventional
producers, such as coal mines and landfills. These include price and competitiveness,
excess capacity in the power industry, limited transmission capacity at local utilities, and other
constraints to wheeling.
Price and Competition
Price and competition are important factors to all unconventional power producers,
including potential landfill and coal mine projects. If the power produced from alternative
energy sources is too costly, unconventional power producers will have a difficult time finding
a market for their electricity. Currently, there are two principal mechanisms for determining
the pricing of power generated from small producers: avoided cost pricing and competitive
bidding.
Under the Public Utilities Regulatory Policy Act (PURPA), the price that a Qualifying
Facility1 (QF) receives from a utility for selling power is called the avoided cost rate.
Determining these rates is complex, and they can vary depending on the utilities long and
short-run marginal costs, the time of day the power will be available, and the reliability of the
supplier. Projects at coal mines may be expected to confront low avoided costs because of
the over-capacity situation among utilities in coal mining regions. In addition, rates for coal
mines and landfills may be low because of concerns about reliability. If rates are too low
power generation is not likely to be economically attractive. To overcome this situation, one
option available to state public utility commissions is to incorporate environmental
externalities into the determination of the avoided cost rate, which would lead to the payment
of higher rates to environmentally beneficial producers, such as coal mines and landfills that
recover methane.
Competitive bidding is an accepted and now widely practiced alternative to avoided
cost pricing of power generated from QFs. In recent years, at least 34 states have adopted
competitive bidding systems to manage the development of new capacity from QFs and other
non-regulated power generators. Though systems vary between states, competitive bidding
systems generally select the lowest cost projects. However, non-price criteria such as
dispatchability, transmission requirements, development status, and other policy objectives
can be incorporated into the bid selection process. Non-price criteria notwithstanding, if the
costs of the bidded projects exceed the utility's avoided cost, the utility itself will build the
remaining necessary capacity. In many cases, the capacity bid is more than required, and
the price arrived at is typically lower than the utility's avoided cost.
1 Enacted in 1978, PURPA guarantees a market for certain types of small power producers and cogenerators
that are considered to be QFs. QFs include cogeneration facilities (because of their greater efficiency) and facilities
that employ waste or renewable fuels (because of the public policy interest in energy diversity). Landfills generally
meet QF requirements, however the status for coal mine methane projects is still unclear (see chapter 3).
7-2
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Coalbed and landfill methane recovery projects will need to compete with other power
sources in competitive bidding systems. Although the price offered by the project may be
below the utility's avoided cost, the methane recovery project may not necessarily enter the
lowest bid, and thus may not be selected. Under bidding systems that are not restricted to
QFs (allowing, for example, neighboring utilities to also bid), price competition can be very
severe. Bidding systems can be, and in some instances have been, established to
incorporate non-price criteria, such as environmental externalities. Such systems should be
employed to ensure that environmentally beneficial generation projects are developed.
Wheeling
In many parts of the United States, such as major coal producing regions, the electric
utility industry is characterized by excess power generation capacity. As mentioned above,
excess capacity may result in lower avoided cost rates paid to QFs and increased
competition in competitive bidding situations. Coal mines and landfills located in regions with
excess capacity and/or low avoided cost rates may have the option of "wheeling", or selling
their electricity to non-adjacent utilities. The decision to permit wheeling is made at the
discretion of the local utility that transmits the electricity. A utility may not wish to facilitate
wheeling for several reasons, including limited transmission capacity or competition between
the utility and the independent producer to sell power to neighboring regions.
Federal and state laws related to wheeling are somewhat ambiguous. At the federal
level, jurisdiction over the provision of wheeling services rests with FERC. FERC has not yet
emphasized open access to regulated utilities' transmission systems. At the level of individual
states, there are few policies or guidelines governing wheeling. Because of the barriers to
wheeling, in many regions companies with alternative fuel sources, such as methane from
coal mines and landfills, that wish to generate power will not be able to do so unless their
local utility is willing to buy the power. It may be possible for Federal and state agencies to
encourage wheeling by working with electric utilities.
7.2 CONDITIONS IN THE PIPELINE AND NATURAL GAS INDUSTRIES
The sale of methane to local pipelines is an extremely attractive utilization option for
many coal mines. Additionally, landfills could potentially sell recovered methane to pipeline in
situations in which the methane could be enriched to pipeline quality. Coal mines and landfills
seeking to sell recovered methane into the natural gas market will most likely encounter some
difficulties that are also common to other producers of natural gas, however. The most
significant of these problems are related to limited pipeline capacity and obstacles to sales
and delivery of gas to buyers other than the adjacent pipeline.
7.2.1 Pipeline Capacity
For all natural gas supply projects, feasibility is dependent, in part, on the existence of
a neighboring natural gas pipeline willing and able to accept this additional gas supply. In
many cases, the availability of pipeline capacity is not assured because the pipeline is already
operating at full capacity. In these cases, it may be necessary to upgrade the pipeline or
construct new lines, both of which can increase project costs.
Pipeline capacity is extremely limited in the Appalachian region, where excess pipeline
capacity is frequently available only during the summer. As a result, the potential coal mine
7-3
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and other methane recovery projects may be denied access, provided access only on an
interruptable basis, or be required to finance the pipeline upgrades needed to carry their gas.
If a neighboring pipeline is unwilling or unable to accept the coalbed methane and upgrading
is not feasible, longer gathering lines can be constructed to move the gas to more distant
pipelines with excess capacity. Obviously, costs increase as gathering lines are extended
longer distances and in some cases projects may not be pursued if the neighboring pipelines
cannot or will not accept the gas.2
Several aspects of the regulatory process may contribute to limited pipeline capacity.
First, receiving federal, state and local approval for new pipelines is complicated and time-
consuming and new pipelines cannot be constructed quickly. Interstate transmission
pipelines must be approved by FERC, which must grant a Certificate of Public Convenience
and Necessity based on an evaluation of factors such as economic rationality and
environmental impacts. In some cases, this process can take two to five years. In addition,
pipeline construction must also be approved by state and local authorities. These delays can
have important implications for projects at coal mines because, unlike conventional gas
development projects, methane from coal mines cannot be stored in the ground until the
proposed transmission lines are completed.
A second regulatory issue concerns the building of pipelines with excess capacity.
When new pipelines are constructed, FERC requires that they are sized in accordance with
current gas supplies. At present, FERC does not permit pipeline companies to build pipelines
with excess capacity because of cost-recovery issues. As a result, future gas supplies, such
as from coalbed and landfill methane, cannot be anticipated when laying new pipelines.
Pipeline capacity is limited from the time of construction and it is difficult to add new sources
of supply without building new lines or undertaking expensive system upgrades.
For a number of larger economic and policy reasons (aside from the methane
recovery projects issue), there has been significant interest in finding ways to address the
problems of pipeline capacity. Possible actions include encouraging new pipeline
construction or the construction of lines with excess capacity and streamlining the regulatory
procedures. Other options targeted at environmentally beneficial projects are also available.
These include providing incentives, or redistributing costs, for pipeline upgrades required for
environmentally beneficial gas recovery projects. All of these options could benefit landfill
methane and coal mine methane producers.
7.2.2 Third Party Sales
The potential buyers of the methane recovered from coal mines and landfills include
pipeline companies into whose transmission systems the methane is injected, and third
parties such as distribution companies, end users and marketers. Before 1985, new gas
producers could generally sell all of their gas to nearby pipeline companies. However, the
marketing situation for natural gas has become more complex in recent years and pipelines
have reduced their purchases of long-term gas supplies. As a result, coal mines and landfills
and other gas producers may need to sell to third-party buyers, while still relying upon the
2 Analysis of methane recovery profitability, presented earlier in this report, included distance to pipeline as one
variable. The analysis showed that larger, gassier mines may find it justifiable to construct pipelines of as much as
50 miles in length to deliver their gas. In one case in Virginia, five coal mines are currently constructing a pipeline
of over 100 miles in length.
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use of adjacent pipelines for transmission. For reasons of capacity, discussed above, or
because of dislike of competition, the pipeline company may discourage use of its
transmission lines to facilitate third party sales. As in the case of electricity wheeling, in cases
in which excess capacity is available, regulatory bodies such as FERC may be able to
encourage pipeline companies to accept and transmit the additional gas supplies to third
party buyers.
7.3 SUMMARY OF AVAILABLE OPTIONS
The issues raised in this chapter represent challenges arising from more general
conditions in the electric and natural gas industries, respectively. These problems are
commonly faced not only by methane recovery projects, but also by other gas or electricity
producers. Exhibit 7-1 summarizes some of the problems stemming from general conditions
in the electricity and natural gas industries and some possible options for overcoming the
problems. These options have primarily been discussed and developed in response to larger
policy interests rather than in response to the specific interests of coal mines, landfills, and
livestock facilities. However, in evaluating these options, the environmental benefits with
respect to encouraging the development of methane recovery projects should also be
considered.
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Exhibit 7-1
Barriers to Methane Recovery Projects and Related Options
Barrier
Solution
Possible
Federal Actions
Possible
State Actions
Electricity Industry
Low avoided cost rates
Competitive bidding on
cost basis only
Limited ability to "wheel"
Recognize environmental
benefits of landfill and
coal mine methane
recovery and use
Recognize environmental
benefits of landfill and
coal mine methane
recovery and use
Greater access to
transmission lines
Additional transmission
capacity
Grant preferential access
to lines for power from
environmentally beneficial
projects or projects using
otherwise wasted fuel.
Require utilities to
incorporate
environmental criteria in
determination of avoided
cost
Use environmental
criteria in bid selection
Require utilities to
provide transmission
access and wheeling to
QFs.
Pipeline/Gas Industry
Limited pipeline capacity
Limited pipeline access
Encourage pipeline
upgrades, extended
gathering lines and new
pipeline construction
Open access to pipelines
Expand Storage
Encourage construction
of additional lines
Provide incentives for
pipeline upgrades and
extended gathering lines
Encourage FERC to
allow preferential access
to pipelines for gas from
environmentally beneficial
projects or projects using
otherwise wasted fuel.
Encourage construction
of additional lines
Provide incentives for
pipeline upgrades and
extended gathering lines
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