EPA/600/R-08/049

March 2008 

Smart Energy Resources Guide
EPA/600/R-08/049 

March 2008 

Smart Energy Resources Guide 

Prepared By 

Jennifer Wang 

for 

Penny McDaniel, Superfund Project Manager 

Michael Gill, Hazardous Substance Technical Liaison 

Superfund Division 

Region 9 

U. S. Environmental Protection Agency 

San Francisco, CA 94105

Steven Rock 

Land Remediation and Pollution Control Division 

National Risk Management Research Laboratory

Office of Research and Development 

U.S. Environmental Protection Agency 

Cincinnati, Ohio 45268 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Foreword 

The U.S. Environmental Protection Agency (EPA) is charged by Congress with protecting the 

Nation's land, air, and water resources. Under a mandate of national environmental laws, the 

Agency strives to formulate and implement actions leading to a compatible balance between human 

activities and the ability of natural systems to support and nurture life. To meet this mandate, EPA's 

research program is providing data and technical support for solving environmental problems today 

and building a science knowledge base necessary to manage our ecological resources wisely, 

understand how pollutants affect our health, and prevent or reduce environmental risks in the future. 

The National Risk Management Research Laboratory (NRMRL) is the Agency's center for 

investigation of technological and management approaches for preventing and reducing risks from 

pollution that threaten human health and the environment. The focus of the Laboratory's research 

program is on methods and their cost-effectiveness for prevention and control of pollution to air, 

land, water, and subsurface resources; protection of water quality in public water systems; 

remediation of contaminated sites, sediments and ground water; prevention and control of indoor air 

pollution; and restoration of ecosystems. NRMRL collaborates with both public and private sector 

partners to foster technologies that reduce the cost of compliance and to anticipate emerging 

problems. NRMRL's research provides solutions to environmental problems by: developing and 

promoting technologies that protect and improve the environment; advancing scientific and 

engineering information to support regulatory and policy decisions; and providing the technical 

support and information transfer to ensure implementation of environmental regulations and 

strategies at the national, state, and community levels. 

This publication has been produced as part of the Laboratory's strategic long-term research plan. It 

is published and made available by EPA's Office of Research and Development to assist the user 

community and to link researchers with their clients. 

Sally Gutierrez, Director 

National Risk Management Research Laboratory 

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Notice 

This document was prepared by a Regional Applied Research Effort (RARE) grantee under the U.S. 

Environmental Protection Agency (EPA), Region 9. The EPA makes no warranties, expressed or 

implied, including without limitation, warranty for completeness, accuracy, or usefulness of the 

information, warranties as to the merchantability, or fitness for a particular purpose. Moreover, the 

listing of any technology, corporation, company, person, or facility in this report does not constitute 

endorsement, approval, or recommendation by the EPA. 

The report contains information attained from a wide variety of currently available sources, including 

reports, periodicals, internet websites, and personal communication with both academically and 

commercially employed sources. No attempts were made to independently confirm the resources 

used. It has been reproduced to help provide government (federal, state, and local), industry and 

other end users, with information on methods to reduce GHGs and diesel emissions at waste 

cleanup and redevelopment sites. 

All links in this document are active as of February 26, 2008. 

Acknowledgments 

This document was prepared under the Regional Applied Research Effort (RARE) program by 

Jennifer Wang. The RARE project was conceived and organized by Penny McDaniel, Mike Gill 

(Region 9) and Steve Rock (ORD), with support, advice, contributions, guidance, and review by: 

Elizabeth Adams, Dorothy Allen, Rich Bain, Richard Baldauf, Monica Beard-Raymond, Jen Blonn, 

Elaine Chan, S.J. Chern, Brendan Cox, Suzanne Davis, Ashley DeBoard, Joseph DeCarolis, Regan 

Deming, Jeff Dhont, Rebecca Dodder, Matt Domina, Charlotte Ely, Lauren Fondahl, Rachel 

Goldstein, Dennis Johnson, Ozge Kaplan, Kingsley Kuang, Jamie Liebman, Jerry Lai, Ben Machol, 

Andy Miller, Gary Miller, Heather Nifong, Carlos Pachon, Cara Peck, Kristin Riha, Nancy RivelandHar, Ray Saracino, Bobbye Smith, Susan Thorneloe, Maggie Witt and Martin Zeleznik. Thanks to 

the many to project managers who shared information on their sites. 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

About the Regional Applied Research Effort 

The Regional Applied Research Effort (RARE) Program promotes collaboration between the EPA 

regional offices and the EPA Office of Research and Development (ORD). The goals of the program 

are to: 

• Provide the regions with near-term research on high-priority, region-specific science needs, 

• Improve collaboration between regions and ORD laboratories and centers, and 

• Build a foundation for future scientific interaction. 

ORD provides $200,000 per year to each region to develop a research topic or topics, which are 

then submitted to a specific ORD laboratory or center as an extramural research proposal. Once 

approved, the research is conducted as a joint effort with ORD researchers and regional staff 

working together to meet region-specific needs. Each region’s Regional Science Liaison (RSL) 

coordinates RARE Program activities and is responsible for ensuring the research results are 

effectively communicated and utilized in the region. 

Past RARE research topics have touched upon all aspects of environmental sciences, from human 

health concerns to ecological effects of various pollutants. However, the RARE Program can be 

used as a tool to address any type of issue or problem that a region identifies as a high priority 

research need and for which ORD has the necessary expertise and capability to address. 

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Table of Contents 

Executive Summary _____________________________________________________________ 1

Chapter 1: Introduction_________________________________________________________ 2

1.1 Overview of the Smart Energy Resources Guide (SERG) __________________________ 2 

1.2 The Cleanup-Clean Air Initiative (CCA) _________________________________________ 3 

1.3 Incorporating Emissions Reductions Into Site Cleanups ____________________________ 4 

1.4 Importance of Reducing the Superfund Program Environmental Footprint______________ 4 

Chapter 2: Energy Basics, Energy Conservation and Efficiency, Renewable Energy

Introduction, Purchasing Clean Energy and Carbon Sequestration______________________ 6

2.1 Understanding Electrical Energy and Key Terms _________________________________ 6 

2.2 Understanding Energy in Fuels and Key Terms __________________________________ 8 

2.3 Energy Conservation and Energy Efficiency _____________________________________ 9 

2.4 Renewable Energy Introduction, Net Metering and Utility Bills ______________________ 10 

2.5 Purchasing Clean Electricity ________________________________________________ 11 

2.6 Carbon Sequestration _____________________________________________________ 12 

Chapter 3: Solar Power ________________________________________________________ 14

3.1 Solar Power Terminology___________________________________________________ 14 

3.2 Solar Power Technology Basics _____________________________________________ 15 

3.3 Assessing Solar Power Potential and Size of a PV System ________________________ 17 

3.4 Grid-Tied or Stand-Alone Systems ___________________________________________ 18 

3.5 Capital Cost, O&M, Installers and Warranties ___________________________________ 20 

3.6 Permits and Environmental Concerns _________________________________________ 22 

3.7 Success Stories __________________________________________________________ 22 

Chapter 4: Wind Power ________________________________________________________ 25

4.1 Wind Power Terminology___________________________________________________ 25 

4.2 Wind Power Technology Basics _____________________________________________ 27 

4.3 Assessing Wind Power Potential and Sizing a Wind Turbine _______________________ 29 

4.4 Grid-Tied or Stand-Alone Systems ___________________________________________ 32 

4.5 Capital Costs, O&M, Permits, Insurance and Environmental Concerns_______________ 32 

4.6 Finding Wind Turbine Vendors and Installers ___________________________________ 34 

4.7 Success Story ___________________________________________________________ 35 

Chapter 5: Landfill Gas-to-Energy _______________________________________________ 37

5.1 Landfill Gas-to-Energy Terminology __________________________________________ 37 

5.2 Landfill Gas-to-Energy Technology Basics _____________________________________ 38 

5.3 Assessing Landfill Gas-to-Energy Project Potential and System Components __________ 40 

5.4 How Much Energy Can a Landfill Produce? ____________________________________ 42 

5.5 Capital Cost and Possible Business Models ____________________________________ 42 

5.6 Landfill Gas Environmental and Safety Concerns and Permits ______________________ 43 

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5.7 Success Stories __________________________________________________________ 44 

Chapter 6: Anaerobic Digestion ________________________________________________ 47

6.1 Anaerobic Digester Terminology _____________________________________________ 47 

6.2 Anaerobic Digester Technology Basics ________________________________________ 48 

6.3 Basic Digester Components, Types of Digesters and Assessing Anaerobic Digester 

Potential ________________________________________________________________ 49 

6.4 Anaerobic Digester Energy Production ________________________________________ 53 

6.5 Capital Cost, O&M, Developers and Possible Business Models _____________________ 54 

6.6 Environmental Benefits and Concerns, Safety and Permits ________________________ 56 

6.7 Success Stories __________________________________________________________ 57 

Chapter 7: Biomass Gasification ________________________________________________ 61

7.1 Gasifier Terminology ______________________________________________________ 61 

7.2 Gasifier Technology Basics _________________________________________________ 62 

7.3 Gasifier System and Energy Generation _______________________________________ 63 

7.4 Assessing Biomass Gasifier Project Potential ___________________________________ 64 

7.5 Emissions Reductions, Capital Cost, Permits, Involved Parties and Partnerships _______ 65 

7.6 Success Story ___________________________________________________________ 66 

Chapter 8: Cleaner Diesel ______________________________________________________ 67

8.1 Importance of Reducing Diesel Emissions _____________________________________ 67 

8.2 Approaches to Reduce Diesel Emissions ______________________________________ 69 

8.3 Clean Diesel Sample Language and Relevant Laws and Regulations ________________ 78 

8.4 Success Stories __________________________________________________________ 79 

Chapter 9: Funding Resources and Opportunities _________________________________ 81

9.1 Resources for Finding Funding Opportunities and Funding Opportunities Chart ________ 81 

9.2 National Funding _________________________________________________________ 88 

9.3 Arizona Funding__________________________________________________________ 98 

9.4 California Funding ________________________________________________________ 99 

9.5 Hawaii Funding _________________________________________________________ 106 

9.6 Nevada Funding_________________________________________________________ 107 

Chapter 10: Tools ___________________________________________________________ 109

10.1 Energy Efficiency Calculators, Technical Assistance Resources, and Informational 

Resources ____________________________________________________________ 109 

10.2 Purchasing Clean Energy Informational Resources ____________________________ 110 

10.3 General Renewable Energy Economic Calculations ____________________________ 111 

10.4 General Renewable Energy Calculators, Technical Assistance, Informational Resources 

and Contractor Licensing Information _______________________________________ 112 

10.5 Solar Power Tools ______________________________________________________ 114 

10.6 Wind Power Tools ______________________________________________________ 115 

10.7 Landfill Gas-to-Energy Tools ______________________________________________ 117 

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10.8 Anaerobic Digestion Tools ________________________________________________ 118 

10.9 Biomass Gasifier Tools __________________________________________________ 119 

10.10 Clean Diesel Tools_____________________________________________________ 121 

Appendix I: ERRS and RAC Contract Language ___________________________________ 124

Appendix II: Federal Regulations and Goals ______________________________________ 126

Appendix III: Solar Power ______________________________________________________ 128

More Solar PV Terms and Definitions_____________________________________________ 128 

Solar PV Technology _________________________________________________________ 128 

More Questions to Ask Your Potential Solar Installer_________________________________ 133 

Concentrated Solar Power (CSP) ________________________________________________ 134 

Appendix IV: Wind Power ______________________________________________________ 135

Wind Technology ____________________________________________________________ 135 

Calculating Wind Turbine Output Power___________________________________________ 136 

Appendix V: Landfill Gas-to-Energy _____________________________________________ 137

Preliminary Evaluation Worksheet _______________________________________________ 137 

Combined Heat and Power (CHP) _______________________________________________ 138 

Electricity Generation _________________________________________________________ 138 

Appendix VI: Anaerobic Digestion_______________________________________________ 143

Preliminary Evaluation Checklist for Manure Feedstock_______________________________ 143 

Calculating Energy Potential in Dairy Manure ______________________________________ 144 

Digester Biology _____________________________________________________________ 145 

Sludge or Effluent ____________________________________________________________ 146 

Appendix VII: Biomass Gasification _____________________________________________ 147

How Does Gasification Work? __________________________________________________ 147 

Types of Gasifiers ____________________________________________________________ 147 

Appendix VIII: Cleaner Diesel___________________________________________________ 150

Verified Technologies _________________________________________________________ 150 

Engine Family Name__________________________________________________________ 152 

Estimating Emissions From On-Road Transport Trucks_______________________________ 152 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory __________ 154

Appendix X: Utility Rate Schedules______________________________________________ 172

Appendix XI: Green Pricing Programs ___________________________________________ 174

Appendix XII: Net Metering Programs ____________________________________________ 176

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Acronyms and Abbreviations 

AC Alternating current 

AFO Animal feeding operations 

AFV Alternative fuel vehicles 

AH Amp-hours 

ASTM American Society for Testing and Materials 

AWEA American Wind Energy Association 

BACT Best available control technologies 

bhp-hr Brake horsepower - hour 

BIPV Building-integrated photovoltaic 

BTU British thermal unit 

C Carbon 

CARB California Air Resources Board 

CCA Cleanup-Clean Air Initiative 

CEC California Energy Commission 

CERCLA Comprehensive Environmental Response, Compensation and Liability Act 

cf Cubic foot 

cfd Cubic foot per day 

CFDA Catalog of Federal Domestic Assistance 

cfm Cubic foot per minute 

CFR Code of Federal Regulations 

CH4 Methane 

CHP Combined heat and power 

CIG Conservation Innovation Grants 

CMAQ Congestion Mitigation and Air Quality 

CMP Carl Moyer Memorial Air Quality Standards Attainment Program 

CNG Compressed natural gas 

CO Carbon monoxide 

CO2 Carbon dioxide 

CPUC California Public Utilities Commission 

CREBs Clean Renewable Energy Bonds 

CSI California Solar Initiative 

CSP Concentrated solar power 

CT Combustion turbine 

DC Direct current 

DCA Dichloroethane 

DOC Diesel oxidation catalyst 

DOE U.S. Department of Energy 

DOT U.S. Department of Transportation 

DPF Diesel particulate filter 

EERE DOE Office of Energy Efficiency and Renewable Energy 

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EGR Exhaust gas recirculation 

EIA DOE Energy Information Administration 

EO Executive Order 

EPA U.S. Environmental Protection Agency 

EPAct Energy Policy Act 

EPBB Expected performance base buydown 

EQIP Environmental Quality Incentives Program 

ERP Emerging Renewables Program 

ERRS Emergency and Rapid Response Service 

FEMP Federal Energy Management Program 

FPPC Farm Pilot Project Coordination, Inc. 

FY Fiscal year 

GAC Granulated activated carbon 

GCW Groundwater circulation wells 

GHG Greenhouse gas 

GRO Greater Research Opportunities 

GSA General Services Administration 

GSFC Goddard Space Flight Center 

GW Gigawatt 

H2 Hydrogen 

HC Hydrocarbons 

hp Horsepower 

HRT Hydraulic retention time 

IC Internal combustion 

IEA International Energy Agency 

IRS Internal Revenue Service 

kg Kilogram 

kW Kilowatt 

kWh Kilowatt-hour 

kWh/m2 Kilowatt-hour per square meter 

lfg Landfill gas 

LFGE Landfill gas-to-energy 

LMOP Landfill Methane Outreach Program 

LNG Liquefied natural gas 

lsd Low-sulfur diesel 

μm Micrometer 

m Meter 

m2 Square meter 

m/s Meters per second 

MACRS Modified Accelerated Cost-Recovery System 

MSW Municipal solid waste 

mph Miles-per-hour 

MOA Memorandum of agreement 

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MPO Metropolitan planning organization 

MW Megawatt 

NASA National Aeronautics and Space Administration 

NCDC National Clean Diesel Campaign 

NEG Net excess generation 

NETL DOE National Energy Technology Laboratory 

NMOC Non-methane organic compounds 

NNEMS National Network for Environmental Management Studies 

NOx Nitrogen oxides 

NREL DOE National Renewable Energy Laboratory 

O&M Operations and maintenance 

OII Operating Industries Incorporated 

ORD EPA Office of Research and Development 

OTAQ U.S. EPA Office of Transportation and Air Quality 

P2 Pollution Prevention 

P&T Pump-and-treat 

PBI Performance based incentive 

PCE Perchloroethylene 

PG&E Pacific Gas and Electric Company 

pH Potential of hydrogen 

PIER Public Interest Energy Research 

PM Particulate matter 

PPA Power purchase agreement 

ppm Parts per million 

PRP Potentially responsible party 

psig Pounds-force per square inch gauge 

PV Photovoltaic 

RAC Response Action Contracts 

RARE Regional Applied Research Effort 

RCRA Resource Conservation and Recovery Act 

RD&D Research, development and demonstration 

RD/RA Remedial Design/Remedial Action 

REC Renewable energy credit/certificate 

REPC Renewable Electricity Production Tax Credit 

REPI Renewable Energy Production Incentive 

RFP Request for proposals 

RI/FS Remedial Investigation/Feasibility Study 

ROD Record of Decision 

RPM Remedial project manager 

RPM Revolutions per minute 

RSL Regional science liaison 

SARE Sustainable Agriculture Research and Education 

SCE Southern California Electric Company 

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scfm Standard cubic feet per minute 

SDG&E San Diego Gas and Electric Company 

SERG Smart Energy Resources Guide 

SGIP Self Generation Incentive Program 

SOW Statement of work 

SO2 Sulfur dioxide 

SOx Sulfur oxides 

SVE Soil vapor extraction 

TCA Trichloroethane 

TCE Trichloroethylene 

TOU Time-of-use 

ulsd Ultra-low-sulfur diesel 

USDA U.S. Department of Agriculture 

VOCs Volatile organic carbons 

W Watt 

W/m2 Watts per square meter 

WRAP Western Regional Air Partnership 

WURD Western United Resource Development Corporation 

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EXECUTIVE SUMMARY 

Remedial actions taken to clean up hazardous waste sites for environmental restoration and 

potential reuse are often sources of diesel and greenhouse gas (GHG) emissions. Many 

remediation systems, such as pump-and-treat (P&T), may operate for many years, demanding 

electricity from fossil-fuel powered utilities. Heavy-duty equipment used in construction during site 

remediation are usually diesel powered. Opportunities to lessen these emissions exist through 

innovative approaches and new technologies. The purpose of this guide is to provide information on 

available mechanisms to reduce these emissions at cleanup sites. 

Reducing GHG and diesel emissions are important challenges facing this country. Executive orders 

have been issued and federal and state laws passed to address both concerns. GHG emissions 

from human activities are directly linked to global climate change. Diesel emissions are known to 

cause premature deaths and a wide variety of respiratory illnesses. The Cleanup-Clean Air Initiative 

(CCA) was established by the U.S. Environmental Protection Agency (EPA) Region 9 Superfund and 

Air Divisions to encourage GHG and diesel emissions reductions at cleanup sites. Through these 

efforts, CCA staff have engaged in pilot projects and changed Emergency and Rapid Response 

Service and Response Action Contracts to include language on renewable energy and clean diesel. 

This document discusses many opportunities to reduce emissions due to energy use from 

remediation activities. Examples include energy efficiency upgrades, implementing on-site 

renewable energy projects, and carbon sequestration. An overview of renewable energy 

technologies is presented including costs, availability, applicability, estimated emissions reduction 

benefits, considerations, permitting, vendor information, funding resources and success stories. 

Renewable energy technologies covered in this guide are solar, wind, landfill gas, anaerobic 

digesters, and gasifiers. Additional methods for utilizing renewable energy are provided. Similar 

information is provided for diesel emissions reduction technologies and cleaner fuels. This 

document includes information on reducing diesel emissions through retrofitting diesel equipment, 

using cleaner and alternative fuels, and simple, low-cost practices such as idle reduction. Currently, 

there are approximately 15 EPA cleanup sites that are using cleaner diesel technologies and fuels or 

renewable energy to power their remediation systems. 

The Smart Energy Resources Guide (SERG) is a tool for project managers to help them assess and 

implement these technologies and practices on Superfund sites as well as other cleanup sites. With 

this information, project managers may be better prepared to discuss emissions reductions 

strategies with contractors and/or developers. While resources cited in this document focus on 

Region 9 territories, many are applicable in other parts of the nation. 

Executive Summary 1 
 

 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Chapter 1 Table of Contents 

1.1 Overview of the Smart Energy 

Resources Guide (SERG) 

1.2 The Cleanup-Clean Air Initiative (CCA) 

1.3 Incorporating Emissions Reductions Into 

Site Cleanups 

1.4 Importance of Reducing the Superfund 

Program Environmental Footprint 

•

•

•

•

•

•

CHAPTER 1: INTRODUCTION 

Remedial actions taken to clean up hazardous 

waste sites for environmental restoration and 

potential reuse at U.S. Environmental Protection 

Agency (EPA) Superfund Program sites are often 

also sources of harmful greenhouse gas (GHG) and 

diesel emissions. Region 9 Superfund’s Cleanup – 

Clean Air Initiative (CCA) aims to encourage and 

facilitate emissions reductions at cleanup sites. The 

Smart Energy Resources Guide (SERG) was 

created as part of the initiative to provide 

information on emissions reductions opportunities 

for remediation project managers. This information can be useful for ascertaining emissions 

reductions opportunities at cleanup sites and as background information to facilitate communication 

with contractors and/or developers about cleaner energy. 

1.1 OVERVIEW OF THE SMART ENERGY RESOURCES GUIDE (SERG) 

The SERG was created for CCA to provide technical information to Region 9 Superfund remedial 

project managers (RPMs) and to help them make economic decisions about reducing GHG and 

diesel emissions from energy use in 

remediation activities at Superfund 

sites. An optimal phase in which to 

start considering these actions is 

during the Remedial 

Investigation/Feasibility Study (RI/FS) 

phase of a cleanup. The technical 

information in this document may 

assist in designing a remediation 

system during the Remedial 

Design/Remedial Action (RD/RA) 

phase as well. Efforts to reduce 

emissions can also be applied during 

remedy system optimization and 

evaluation, 5-year reviews, and 

Record of Decision (ROD) 

amendments. While some 

information presented in this guide is 

Region 9-specific, much of the 

information is also applicable for 

other parts of the nation. RPM 

What the SERG Can Do for You 

The SERG provides information on practices and 

technologies that can reduce emissions from electricity 

and diesel use at cleanup sites. This information can be 

used to: 

Assess possibilities of cleaner electricity and diesel 

at cleanup sites. 

Share information with contractors. 

Provide background information in order to better 

communicate with contractors and/or developers on 

emissions reductions strategies. 

Provide a starting point for implementing cleaner 

electricity and/or diesel projects. 

Reference guide for funding opportunities. 

Reference guide for tools to help estimate costs of 

technologies and emissions reductions. 

Chapter 1: Introduction 2 
 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

counterparts, such as Resource Conservation and Recovery Act (RCRA) site and state project 

managers, may also find this guide useful. 

See Chapter 2 for overviews on energy, conservation and efficiency, general renewable energy, 

purchasing clean energy, and carbon sequestration. Review Chapter 3 through Chapter 7 for more 

in depth information on renewable energy technologies that may be applicable for cleanup sites. 

Chapter 8 provides information on diesel emissions reduction practices and technologies. See 

Chapter 9 for funding and incentives for energy efficiency efforts, renewable energy projects, and 

cleaner diesel technologies. Find tools such as calculators, technical resources, and sources of 

further information for energy efficiency, purchasing clean energy, renewable energy and cleaner 

diesel in Chapter 10. Calculators to measure emissions and emissions reductions are also included 

in Chapter 10. In addition, Chapter 10 provides resources to help select a properly licensed 

renewable energy contractor. Appendix I includes an excerpt of contract language that incorporates 

CCA principles. Appendix II lists relevant executive orders and federal goals related to emissions 

reductions. Appendices III-VIII provide supplemental information on renewable energy technologies 

and cleaner diesel. Find the Region 9 Superfund Electricity and Diesel Emissions Inventory in 

Appendix IX. Appendix X includes resources to find local utility rate schedules on-line. Appendix XI 

provides a list of Green Pricing Programs in Region 9 states and territories. Last, Appendix XII 

provides a summary of some net metering programs in Region 9 states and territories. 

The SERG focuses on cleaner energy and cleaner diesel technologies and practices. Although 

there are many other methods to reduce the environmental footprint of cleanup sites, those 

strategies extend beyond the scope of this guide. 

1.2 THE CLEANUP-CLEAN AIR INITIATIVE (CCA) 

The Cleanup – Clean Air Initiative is a cross-program partnership between the EPA Region 9 Air and 

Superfund Divisions. CCA aims to protect human health by reducing air pollution at Superfund sites 

during remedial action, construction and redevelopment. CCA seeks to encourage, facilitate and 

support implementation of diesel emissions and GHG reduction technologies and practices at 

Superfund cleanup and redevelopment sites. The use of cleaner fuels, retrofit technologies, and idle 

reduction practices on diesel equipment used at Superfund sites for purposes of construction is 

consistent with the Comprehensive Environmental Response, Compensation and Liability Act 

(CERCLA) section 121(b)(1). In addition, CCA seeks to reduce GHG emissions through better 

energy management practices, such as the use of renewable energy technologies and improved 

energy efficiency. 

To accomplish the emissions reductions goals, Cleanup – Clean Air: 

• Raises awareness of the potential for GHG and diesel emissions reductions at Superfund 

site cleanup and redevelopment; 

• Promotes Cleanup-Clean Air projects by providing coordination and facilitation support for 

potential projects that reduce diesel and GHG emissions; 

• Creates an open forum for information sharing, and works to leverage significant new 

resources to expand voluntary emissions reductions; and 

Chapter 1: Introduction 3 
 

 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

• Creates momentum for future GHG and diesel emission reduction efforts within the 

Superfund Program and elsewhere. 

Visit the CCA website at www.epa.gov/region9/cleanup-clean-air. 

1.3 INCORPORATING EMISSIONS REDUCTIONS INTO SITE CLEANUPS 

Some of Region 9 Superfund contracts now include language on cleaner diesel and electricity. The 

Emergency and Rapid Response Services Contract (ERRS) strongly encourages contractors to use 

clean technologies and/or fuels on all diesel equipment to the extent practicable and/or feasible. 

The Response Action Contract (RAC) requires contractors, when directed by EPA, to use cleaner 

engines, cleaner fuel and diesel emissions control technology on diesel powered equipment where 

feasible and to evaluate all reasonably feasible renewable energy sources. See Appendix I (page 

124) for the incorporated language. 

GHG and diesel emissions reductions from cleanup activities can also be achieved through the 

following mechanisms: 

• Modifying the Statement of Work under RAC (completed in Region 9) 

• Developing Stand Alone Contract or Interagency Agreements with the Army Corps Of 

Engineers 

o Request for proposals (RFP) to energy providers 

o General Services Administration schedule 

For fund-lead sites, RPMs have more control over which contractors are chosen. If it is lead by a 

potentially responsible party (PRP), it is best to encourage PRPs to make efforts to reduce diesel 

and GHG emissions and provide information on emissions reduction technologies and practices. 

1.4 IMPORTANCE OF REDUCING THE SUPERFUND PROGRAM 

ENVIRONMENTAL FOOTPRINT 

Reducing GHG and diesel emissions is a high priority for our nation. Presidential executive orders 

(EOs) and state and federal strategies have stressed the importance of GHG and diesel emissions 

reductions. For example, the EPA Administrator’s Action Plan includes goals to promote diesel 

emissions reductions and renewable energy development. For a listing of some of the policies, 

regulations and executive mandates that are driving efforts to reduce emissions, see Appendix II 

(page 126). 

Many remediation systems constructed for Superfund site cleanups operate for decades and/or have 

high energy consumption levels. Fossil fuel electricity generation is a major source of GHGs, (a 

primary cause of climate change) as well as other pollutants. Also, remediation activities often 

include the use of diesel equipment, which consumes fossil fuels and emits toxic diesel exhaust, 

potentially exposing site workers and surrounding communities. 

In the U.S., most electricity is generated from coal or natural gas combustion. Power generation 

from fossil fuels releases carbon dioxide (CO2), a GHG, as well as other air pollutants into the 

Chapter 1: Introduction 4 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

atmosphere. In 2005, more than 2.6 billion metric tons of CO2 were emitted from electricity 

production in the U.S.1 The U.S. population is about 300 million, so on average, the nation 

generated approximately 8.7 metric tons of CO2 per person due to electricity production in 2005. 

A survey conducted of half of Region 9 Superfund sites found that they will emit approximately 

428,174 tons of CO2 from remediation activities between 1990 and 2009 due to electricity 

consumption. This amount of CO2 is equivalent to that from 84,000 cars on the road for one year or 

powering about 50,000 single family homes for one year. From 1985 to 2009, an estimated 3,140 

tons of nitrogen oxides (NOx), 848 tons of carbon monoxide (CO), and 105 tons of particulate matter 

(PM) will result from diesel equipment use at these sites (DeBoard, EPA GRO Fellow, 2007). See 

Appendix IX (page 154) for the full report. 

CCA seeks to aid the Superfund Program to remediate sites in a manner that minimizes 

environmental impacts and to set positive examples for the public and other agencies. There are a 

variety of opportunities for Superfund to reduce GHG and diesel emissions including the following, 

which are discussed in this guide: 

• Energy Efficiency • Renewable Energy Technologies 

• Purchasing Clean Energy • Cleaner Diesel Technologies 

• Carbon Sequestration • Cleaner and Alternative Fuels 

At the time of writing, 15 EPA cleanup sites were identified that currently use renewable energy to 

power some or all of their remediation activities (Dellens, EPA NNEMS Fellow, 2007).2

 The majority 

of these sites are utilizing groundwater extraction and treatment systems, one uses soil vapor 

extraction (SVE), and others are using renewable energy for powering irrigation and data collection 

purposes. See the EPA publication Green Remediation and the Use of Renewable Energy Sources 

for Remediation Projects (http://cluin.org/s.focus/c/pub/i/1474/) for more details. 

Chapter 1: Introduction 5 
 

 

Chapter 2 Table of Contents 

2.1 Understanding Electrical Energy and 

Key Terms 

2.2 Understanding Energy in Fuels and Key 

Terms 

2.3 Energy Conservation and Energy 

Efficiency 

2.4 Renewable Energy Introduction, Net 

Metering and Utility Bills 

2.5 Purchasing Clean Energy 

2.6 Carbon Sequestration 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

CHAPTER 2: ENERGY BASICS, ENERGY CONSERVATION 

AND EFFICIENCY, RENEWABLE ENERGY INTRODUCTION, 

PURCHASING CLEAN ENERGY AND CARBON 

SEQUESTRATION 

This section begins with a refresher of electrical and 

fuel energy basics. It includes information on 

options to reduce electricity and fuel use and 

associated environmental impacts. Conservation 

and energy efficiency opportunities as well as 

renewable energy are discussed. Purchasing clean 

electricity is another strategy discussed in this 

chapter to reduce the unwanted impacts of site 

cleanups. The end of this chapter includes an 

overview of carbon sequestration on contaminated 

lands which may be considered to mitigate GHG 

emissions. 

2.1 UNDERSTANDING ELECTRICAL ENERGY AND KEY TERMS 

Think of a faucet with a hose to help understand amps, voltage, and watts. Electricity running 

through a wire is analogous to water running through a hose (Fig. 1). 

Figure 1 Electric circuit and hose. Image courtesy Solar On-Line and NDT3 

Voltage Voltage is the “pressure” that pushes electrons along in a wire. This “electrical pressure” is 

analogous to water pressure in a garden hose. The greater the pressure, the more energy each 

parcel of water in the hose has and the greater the force with which it is pushed along. Voltage is 

measured in volts, usually abbreviated “V.”4 

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Amperes (Amps) An ampere is a unit of measure of electrical current. An electrical current is the 

rate at which electrons flow past a given point in a wire. This electrical flow rate is analogous to 

a volume of water flowing per second. Amperes is usually abbreviated “amps” or “I.”5 

Power (Watts) The rate at which electricity is produced or consumed is referred to as power. It 

measures how much energy is needed to start a device or operate a piece of equipment per unit 

time. Using the water analogy, power is the combination of water pressure (voltage) and rate of 

flow (current) that allows work to be done (e.g., lighting a light bulb, water turning a turbine). 

This rate of energy use or production is measured in watts (W). It can also be measured in 

horsepower (hp). One hp is equivalent to 745.7 W. The power rating is usually found on the 

specifications of a piece of equipment. 

Power (watts) = voltage (volts) x current (amps) 

One can see the relationships among voltage, amperage and power by returning to the garden 

hose analogy. A high-pressure garden hose with a pinhole opening will shoot a tiny stream of 

water far into the air. The water has high energy, but there is very little water actually flowing 

(high voltage, low amperage). In contrast, consider a large pool of water slowly exiting a very 

large pipe. There is a large amount of water moving, but it has low energy (low voltage, high 

amperage). Most modern energy production systems generate both high voltage and high 

amperage electricity. 

Energy Usage The actual energy used is measured in watt-hours (Wh). A 60-watt light bulb needs 

60 watts of power to operate. If it operates for 3 hours, this light bulb will use 60 W x 3 hours = 

180 Wh of energy. 

Electrical Energy (Wh) = Power (W) x Time Operated (hours) 

You most often see kWh on an energy bill and it stands for kilowatt-hours. One kilowatt is 1,000 

watts, and so a kilowatt-hour is 1,000 watt-hours. A megawatt (MW) is 106 watts and a gigawatt 

(GW) is 109 watts. A typical 3 bedroom house will use about 600 kWh a month.6 Another energy 

unit, the British Thermal Unit (BTU), is usually used to describe the energy content in fuels like 

natural gas. One kWh is equivalent to 3,414 BTUs. 

Load A load is the general term for the power demanded by any device, equipment, or appliance 

that consumes electricity. 

Alternating and Direct Current Electricity needs a complete circuit to flow. Electricity flowing in one 

direction is referred to as direct current (DC) and is typically found in batteries and solar 

modules. Electricity that cyclically reverses direction is referred to as alternating current (AC). 

Most appliances and equipment use this type of power and utility companies provide power as 

AC. Some renewable energy sources such as solar power and small wind turbines generate 

electricity as DC and an inverter is used to convert it to usable AC power.7 

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2.2 UNDERSTANDING ENERGY IN FUELS AND KEY TERMS 

Different types of fuels are used to run construction equipment and vehicles, and to produce heat 

and electricity from renewable energy projects. Heavy-duty equipment like excavators, dozers, 

drills, and back hoes are used at cleanup sites during removals and construction. Most heavy-duty 

equipment runs on diesel fuel. Alternatively biogas or syngas fuels are used to generate electricity. 

Common energy terms associated with fuel include the following: 

Biogas Gas produced from the decomposition of organic matter which can be used for heating or 

electricity generation. Biogas is produced in a landfill or anaerobic digester. See Chapter 5 for 

information on landfill gas and Chapter 6 for information on anaerobic digesters. 

bhp-hr (Brake horsepower – hour) Net power after frictional power losses in the engine are 

subtracted from the maximum theoretical output power is the brake horsepower. Often seen as 

g/bhp-hr (grams per brake horsepower-hour) when assessing emissions. 

Emissions (g) = g x bhp x hours of operation 

bhp-hr 

BTU (British Thermal Unit) The amount of heat (energy) required to raise the temperature of one 

pound of water one degree Fahrenheit.8

 Usually refers to energy content in fuels. 3,414 BTU = 

1 kWh. 

Combined Heat and Power (CHP) Practice of generating electrical and thermal energy and utilizing 

both, also known as cogeneration. When generating electricity, excess heat is produced and 

this valuable energy is often wasted. Capturing the thermal energy for heating dramatically 

increases efficiency.9 

Energy content The amount of energy that can be released by burning a fuel. See “BTU.” 

Fuel efficiency/fuel economy Measure of how well chemical energy in a fuel is converted into kinetic 

energy to operate equipment. 

Heat rate Calculated as the fuel energy input divided by the electricity output of prime movers. It is 

closely related to the efficiency of the electricity generation system. Higher heat rates indicate 

lower efficiency. 

Horsepower (hp) Like watts, a measure of the power required to operate a device or piece of 

equipment. One hp is equivalent to 0.7457 kW. 

Prime Mover Devices that convert fuels to mechanical energy (e.g., gas turbines, reciprocating 

engines, steam turbines). Biogas or syngas can fuel prime movers to generate mechanical 

energy which in turn can drive a generator to produce electricity and heat.10 

Syngas Gas composed of CO and hydrogen (H2) produced by gasification technologies that can be 

used for heating and/or electricity generation. See Chapter 7 for information on gasifiers. 

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2.3 ENERGY CONSERVATION AND ENERGY EFFICIENCY 

Conserving energy and improving energy efficiency are the first steps to reducing electricity and fuel 

use. Energy efficiency efforts reduce pollution and demand on resources, and can save money in 

many cases. There are many opportunities to improve energy efficiency at cleanup and 

redevelopment sites. 

Conservation and Increasing Efficiency in Equipment 

While preserving the priority of remediating a contaminated site to cleanup levels specified in the 

ROD, energy conservation may be considered during remedy selection. In long-term remedial 

action, remediation equipment may operate for years and even decades. In order to reduce energy 

demand as well as wear, equipment should be purchased and maintained for maximum efficiency. 

Although a piece of equipment may be over-sized in order to compensate for infrequent unexpected 

loads, note that the piece of equipment may not run at its maximum efficiency for the majority of 

operation. For example, a 50-hp pump engine may be very inefficient running at 30 percent of its full 

power. Installing a 15-hp engine instead can reduce energy bills compared to running the 50-hp 

engine at low power.11 Properly sizing and maintaining pumps will prevent electricity and money 

from being wasted and will reduce pollution. Compare efficiency curves of pumps and purchase/rent 

a motor that is just powerful enough to meet what is required. 

See Introduction to Energy Conservation and Production at Waste Cleanup Sites 

(www.epa.gov/swertio1/tsp/download/epa542s04001.pdf), a May 2004 EPA Engineering Forum 

Issue Paper for details on opportunities to make your pumps more efficient. 

The same concept applies to diesel engines used during cleanup. Diesel fuel is wasted when 

oversized equipment is used to perform a job that a smaller piece of equipment is better suited to 

complete. 

Optimizing Electricity Use Schedules 

Utilities often resort to alternate, more expensive, polluting sources of energy during times of highdemand such as summer daytime hours. Time-of-use (TOU) rate schedules often categorize these 

times as ”on-peak” hours. Under TOU schedules, electricity prices during on-peak hours are often 

significantly higher than during mid-peak or off-peak hours. Reducing electricity use at your site 

during on-peak hours can help to minimize the need for utilities to operate beyond their base loads 

and can reduce your utility bill. If available, contact an account manager at your utility to help 

compare different rate schedules to see which one best suits the electricity demands of your site in 

order to reduce costs. See Appendix X (page 172) for a list of web pages where you can find rate 

schedules for many utilities providing service in Region 9 states and territories. 

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2.4 RENEWABLE ENERGY INTRODUCTION, NET METERING AND UTILITY 

BILLS 

Renewable energy is obtained from sources that are essentially inexhaustible (e.g., solar, wind, 

biomass). While fossil fuels are being depleted, renewable energy technologies provide a lasting 

source of energy. This document includes information on solar power, wind power, landfill gas-toenergy projects, anaerobic digestion and biomass gasification. Other renewable energy 

technologies such as hydropower, geothermal, tidal power, and biomass direct-combustion and 

pyrolysis are not covered in this guide. See Table 1 for a chart that summarizes applications and 

costs of some of these technologies. Cleanups may require a high electricity demand. Using 

renewable energy can avoid many of the pollutants emitted from fossil fuel use, including GHGs. 

Renewable energy use also reduces the demand to extract fossil fuels. Solar and wind power are 

widely available resources and the technologies are well established. Cleanup sites that are near 

landfills may consider capturing landfill gas if available. Sites that have potential biomass resources 

nearby may consider anaerobic digesters or gasifiers to produce electricity. Solar and wind options 

also require less maintenance and operational costs compared to digesters and gasifiers. 

Additionally, implementing a renewable energy project can reduce energy bills. Some utilities have 

net metering programs which can increase monetary savings. Net metering programs allow grid-tied 

utility customers who generate electricity in excess of their consumption to credit that amount for 

later use.12 For example, when a wind turbine produces more electricity than is consumed on-site, 

excess electricity is sent to the grid. For net metered systems, the utility acts like a giant battery. 

When wind power is unavailable, the site can use the energy credits from the utility. Some utilities 

may purchase excess power generated from renewable energy projects. Not all utilities have a net 

metering program. See Appendix XII (page 176) for net metering programs in Region 9 territory. 

Also, review the cleanup site’s energy bill to become familiar with how it is charged for electricity 

use. Commercial and agricultural customers are often charged per kWh (the electricity actually 

consumed), as well as per kW (the power the utility needs to have available). This kW charge is 

based on the highest level of power demanded during the month. This charge is often a large 

portion of the bill and may also be difficult to avoid. It may be worth sizing a renewable energy 

system for the purpose of reducing the demand charge. 

Table 1 Summary of Some Renewable Energy Applications and Costs13 

Energy Source Applications Cost 

(Generating 

Capacity) 

Cost (Use) U.S. Production 

Solar P&T, SVE, data collection, 

general energy production 

$8-$10 per watt $0.04-$0.07 per 

kWh 

120 MW (PV) 

Wind P&T, SVE, general energy 

production 

$2-$4 per watt $0.20-$0.30 per 

kWh 

11,961 MW 

Landfill gas General energy 

production 

$2-3 per watt $0.07-$0.09 per 

kWh 

1,195 MW 

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2.5 PURCHASING CLEAN ELECTRICITY 

While it may not be feasible for a cleanup and redevelopment site to produce its own renewable 

energy, there are other options for a site to offset its carbon emissions from energy use. Options 

include buying Renewable Energy Credits and participating in green pricing programs. To estimate 

emissions reductions from purchasing clean electricity, go to EPA’s Power Profiler listed in Chapter 

10 (page 112.) 

Renewable Energy Credits 

Renewable Energy Credits (RECs), also called Renewable Energy Certificates or Green Tags, 

represent the environmental benefit from producing energy from renewable resources separate from 

the actual electricity. A REC puts a dollar value on the environmental benefits of clean energy that 

can be traded and sold independently of any actual electricity. After the REC is sold, the clean 

energy producer sells renewable electricity at the market price for conventional electricity. For 

example, producers of renewable energy, such as wind farm owners, register the amount of 

electricity they produce and can receive RECs. They can in turn sell two different products, 

electricity and RECs, to two different customers. REC owners can claim that they have offset their 

emissions from fossil fuel electricity consumption with cleaner renewable energy. The EPA 

purchases RECs to offset 100 percent of its energy use in EPA facilities nationwide. For a list of 

REC retailers, go to www.eere.energy.gov/greenpower/markets/certificates.shtml?page=1. 

Green Pricing Programs 

Some utilities provide green pricing as an optional service. These options provide an opportunity for 

customers to support the utility company’s investment in renewable energy technologies. 

Participating customers pay a premium on their electric bills to cover the additional cost of renewable 

generation relative to conventional generation. More than 600 utilities in the nation, including 

investor-owned, municipal utilities, and cooperatives, offer a green pricing option. The price 

premiums charged in green pricing programs range from 0.7 cents per kWh to as much as 17.6 

cents per kWh. Contact your utility to see if they offer a green pricing program. See Appendix XI 

(page 174) for some green pricing opportunities in EPA Region 9 states and territories. 

Power Purchase Agreement 

Another option for using renewable energy is to enter into a power purchase agreement (PPA). A 

PPA is a long-term agreement to buy electricity from a power producer. A company that provides 

PPA services will use its own funds to install a renewable energy system on your site. The company 

will own the system and sell the produced power to provide the needed power for your remediation 

system. This type of agreement may be applicable for the renewable energy technologies discussed 

in this document. PPAs may also be considered if a renewable energy project on a cleanup site 

produces a surplus of energy that can be sold to another party. For more information, go to EPA’s 

Guide to Purchasing Green Power pages 22-23 

(www.epa.gov/greenpower/documents/purchasing_guide_for_web.pdf). 

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2.6 CARBON SEQUESTRATION 

Carbon sequestration is the process of removing CO2 from the atmosphere and storing it in another 

form. Carbon can be stored in plant-life, soils, and geologic formations. While CO2 can be 

sequestered in geologic formations such as oil and gas reservoirs, un-mineable coal seams, and 

deep saline reservoirs, this section focuses on carbon sequestration in plants. Restored lands may 

provide space for carbon sequestration in plant matter. Plants remove CO2 from the atmosphere 

and store it in biomass (Fig. 2).14 Plants store CO2 in their tissues and also release some CO2 back 

into the atmosphere. Soils also store and release CO2. Net sequestration results if the rate of 

removal is higher than the rate of release. Young, fast-growing trees in particular will remove more 

CO2 from the atmosphere than they will release.15 An informational and technical resource is the 

U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL) which is currently 

researching carbon sequestration on mined lands16 

(www.netl.doe.gov/technologies/carbon_seq/index.html). 

Carbon sequestration rates 

vary by tree species, soil 

type, regional climate, 

topography and 

management practice. In 

the U.S., fairly wellestablished values for 

carbon sequestration rates 

are available for most tree 

species. Soil carbon 

sequestration rates vary by 

soil type and cropping 

practice and are less-well 

documented but information 

in this area is growing.18 

Planting trees on lands 

previously not forested is called afforestation, which may be feasible for some cleanup sites. 

Afforestation can sequester about 0.6–2.6 metric tons of carbon per acre per year for approximately 

90-120 years.19 Carbon accumulation in vegetation and soils eventually reaches a saturation point. 

This happens, for example, when trees reach maturity, or when the organic matter in soils builds 

back up to original levels before losses occurred. Even after saturation, the trees or agricultural 

practices need to be sustained to maintain the accumulated carbon and prevent subsequent losses 

of carbon back to the atmosphere.20 

Use the following document to estimate the amount of carbon sequestered in trees at your site: 

Method for Calculating Carbon Sequestration by Trees in Urban and Suburban Settings by the 

DOE, Energy Information Administration (EIA) published in April 1998 

(ftp://ftp.eia.doe.gov/pub/oiaf/1605/cdrom/pdf/sequester.pdf). 

Figure 2 Carbon sequestration in plant-life. Image courtesy EPA17 

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For more information go to: 

□ EPA Carbon Sequestration Web Pages: General information on carbon sequestration in 

agriculture and forestry. www.epa.gov/sequestration 

□ DOE Carbon Sequestration Web Pages: Information on DOE carbon sequestration efforts. 

www.fossil.energy.gov/programs/sequestration 

□ NETL Carbon Sequestration Web Pages: Information on current carbon sequestration research. 

www.netl.doe.gov/technologies/carbon_seq 

□ The Contribution of Soils to Carbon Sequestration (Plains CO2 Reduction Partnership, August 

2005): Document detailing soil carbon sequestration. 

www.netl.doe.gov/technologies/carbon_seq/partnerships/phase1/pdfs/ContributionSoils.pdf 

□ West Coast Regional Carbon Sequestration Partnership: This partnership is a collaborative 

research project bringing together dedicated scientists and engineers at 70 public agencies, 

private companies, and nonprofits to identify and validate the best regional opportunities for 

keeping CO2 out of the atmosphere. www.westcarb.org/ 

Mary Jane Coombs 

Research Coordinator 

West Coast Regional Carbon Sequestration Partnership 

E-mail: maryjane.coombs@ucop.edu 

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Chapter 3 Table of Contents 

3.1 Solar Power Terminology 

3.2 Solar Power Technology Basics 

3.3 Assessing Solar Power Potential and 

Size of a PV System 

3.4 Grid-Tied or Stand-Alone Systems 

3.5 Capital Cost, O&M, Installers and 

Warranties 

3.6 Permits and Environmental Concerns 

3.7 Success Stories 

CHAPTER 3: SOLAR POWER 

Various technologies are available to capture 

energy from the sun. Photovoltaic (PV) technology 

converts solar energy directly to electrical energy. 

In addition, heat from the sun can be used in solar 

hot water heaters or in concentrated solar power 

modules (see Appendix III page 134). While other 

forms of solar power are available, this guide 

focuses on PV technology. The Pemaco Superfund 

site in southern California is currently augmenting 

some of its grid-power consumption with a 3-kW 

solar PV system (see Section 3.7). PV systems 

typically require little maintenance depending on the 

complexity of the system. 

3.1 SOLAR POWER TERMINOLOGY 

The following are some solar power terms and definitions. See Appendix III (page 128) for more 

terms. 

Photovoltaic (PV) Solar power technology that converts light energy into electrical energy.21 

PV Cell Smallest semiconductor element within a PV 

module to perform the immediate conversion of light into 

electrical energy. They are also referred to as solar cells 

(Fig. 3).23 

PV Module Individual PV cells wired together in a sealed 

unit is called a module. It is the smallest assembly of 

solar cells and additional parts, such as interconnections, 

intended to generate DC power.24 

PV Panel A group of modules wired together.25 

PV Array PV system component composed of one or more 

PV modules or panels wired together. The array is an 

interconnected system of PV modules that function as a single electricity-producing unit.26 

Battery A device that stores electricity for use when the PV system is not providing enough energy 

to meet the demand.27 Typical batteries for PV systems last for 5-10 years.28 See Appendix III 

(page 130). 

Charge Controller A device that prevents overcharging of the batteries and the batteries from overly 

discharging electricity.29 See Appendix III (page 132). 

Figure 3 Multi-crystalline solar cell. Image 

courtesy Lawton Ltd22 

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Inverter A device that changes direct current (DC) power to alternating current (AC). Electricity 

produced by the PV system is DC, and stored as DC if batteries are used, but appliances and 

equipment usually use AC power. The inverter converts DC electricity to AC either for standalone systems or to supply power to an electricity grid.30 See Appendix III (page 132). 

Balance of System Term used to describe PV system parts that include all hardware such as wiring 

and safety equipment that keep the system functional.31 

Net Metering Net metering programs allow grid-tied utility customers who generate electricity in 

excess of their consumption to credit that amount for later use.32 See Appendix XII (page 176) 

for some net metering programs in Region 9 states. 

3.2 SOLAR POWER TECHNOLOGY BASICS 

Sunlight hits PV cells and creates an electrical 

current. PV systems generate electricity without 

noise nor pollution (although production of PV 

systems results in some emissions, see Section 

3.6) and are widely available. PV systems have a 

useful life of at least 25 years until the unit 

produces power at 80 percent of its original power 

rating.35 PV technology can be installed in areas 

with sufficient space and solar resource. The 

core component of a solar panel is a PV cell. A 

PV module is made up of individual PV cells wired 

together in a sealed unit. An array is made up of 

interconnected modules (Fig. 4). 

Figure 4 PV cells are interconnected into a module, 

and modules are interconnected to form an array to 

increase power output. Image courtesy EERE33 

PV cells are composed of at least two layers of 

semiconductor material, commonly silicon. 

Sunlight hitting the cell causes electrons to flow 

in a single direction, generating DC electricity 

(Fig. 5). An inverter is then needed to convert 

the electricity to AC. See Appendix III (page 

128) for more information on PV technology. 

You can view a short video by DOE’s Office of 

Energy Efficiency and Renewable Energy 

(EERE) at the following link to see how a solar 

cell converts sunlight into electricity: 

www1.eere.energy.gov/solar/animations.html. 

Crystalline and Amorphous Modules 

Current cutting-edge PV technology can convert up to 40 percent of solar energy that hits a PV 

panel into electricity. Most readily available crystalline PV systems have solar cells with efficiencies 

Figure 5 Inside a solar PV cell. Image courtesy EERE34 

Chapter 3: Solar Power 15 
www.epa.gov/cleanenergy/powerprofiler.htm 

Estimating Solar Power Emissions Reductions 

Using FindSolar.com and EPA’s Power Profiler 

Consider the Pemaco Superfund site as an 

example. FindSolar.com estimates that a 3-kW 

solar system in southern California produces 

about 375 kWh per month. Then, go to the Power 

Profiler and enter the required information. Under 

“Make a Difference,” select “My Emissions.” Enter 

375 kWh into the “Average Monthly Use” option. 

The Profiler estimates that about 4,311 pounds of 

CO2 are released annually from producing 375 

kWh of conventional electricity each month. This 

means that the 3-kW PV system at Pemaco 

prevents an estimated 4,311 pounds of CO2 from 

being released into the atmosphere every year. 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

of around 10-15 percent. Amorphous PV cells, or 

thin-film technology, have maximum efficiencies of 

about 10 percent. They are ideal for buildingintegrated uses such as roof tiles or shingles (Fig. 

6).36 Advancing technologies show that they may 

soon produce electricity at rates almost as high as 

crystalline modules and may drastically bring down 

the cost of solar power.37 

Single-crystalline PV devices are made from a 

single large silicon crystal. Multi-crystalline 

modules are made from multiple crystals grown 

together and are slightly less efficient than singlecrystal modules. Amorphous modules are 

manufactured by depositing semi-conductor 

material onto a sheet of glass or plastic. 

Crystalline modules are delicate and need to 

be mounted on a rigid frame. Amorphous 

modules are flexible and their efficiency is not 

as affected as crystalline varieties by high 

temperatures, shading or cloudy days. While 

100 ft2

 of crystalline cells produce roughly 1 

kW, 100 ft2

 of amorphous cells will produce 

about 0.60 kW.39 

Tracking or Fixed Tilt 

Tracking units point the modules at the 

optimal angle to the sun throughout the day 

(Fig. 7). They can increase efficiency by 15 

percent in the winter and 40 percent in the 

summer and thus can reduce the size of the 

system but require significant additional costs. 

They may need more frequent maintenance 

due to moving parts. They are best used at 

sites with long hours of sunlight and with no 

shading. Fixed tilt units do not move; they are 

tilted at an angle equal to the degree of latitude

of the site to capture the greatest amount of 

energy over the year without using a tracking 

system.41 

Figure 6 Building integrated PV (BIPV) shingles. 

Image courtesy Kyocera38 

Figure 7 Solar tracking unit. Image courtesy Northern 

Arizona Wind and Sun40 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

3.3 ASSESSING SOLAR POWER POTENTIAL AND SIZE OF A PV SYSTEM 

Sites that receive direct sunlight without shading from 9 am to 3 pm have good solar power potential. 

The following DOE National Renewable Energy Laboratory (NREL) website provides maps of solar 

radiation (sunlight availability) based on location and solar mounting type (fixed tilt or tracking) (Fig. 

8): http://rredc.nrel.gov/solar/old_data/nsrdb/redbook/atlas/. Keep in mind that this website gives the 

actual total solar radiation hitting earth’s surface. Solar modules are 10-15 percent efficient at 

capturing this energy. 

Figure 8 Solar radiation map. Image courtesy NREL42 

PV panels can provide power to cleanup site remediation systems (1) that are off-grid; (2) that utilize 

low-flow pump systems; and (3) to augment grid-power for sites with high electricity demand. In 

general, PV systems will be most suitable for sites with an expected long-term need for power to 

operate equipment. 

Completely shading just one cell can reduce efficiency by 75 percent for crystalline systems.43 On 

moderately cloudy days, arrays can produce 80 percent of electricity compared to a bright sunny 

day, and on highly overcast days they can produce 20 percent.44 For sites in the northern 

hemisphere, PV panels should be south-facing for maximum sunlight exposure. East or west facing 

panels may also be acceptable.45 Panels can be mounted on roofs or poles or directly on the 

ground. 

Chapter 3: Solar Power 17 
 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

A PV system can be sized to meet all or a portion of your site’s energy consumption. The size of the 

PV system needed for a site depends on the energy demands of the remediation system and 

available solar energy at a particular site. PV modules have two efficiency ratings. One measure is 

the Standard Test Conditions Rating set by the manufacturer which represents the maximum power 

output in laboratory conditions. A more accurate efficiency rating is the PV-USA Test Conditions 

rating which reflects the output under day-to-day conditions. A PV system rated for 1-kW in Region 

9 sites will typically produce between 135 and 150 kWh per month. See EERE’s A Consumer’s 

Guide: Get Your Power from the Sun page 9 for a map of estimated site-specific annual solar energy 

production (www.nrel.gov/docs/fy04osti/35297.pdf). Rated kW is the maximum output capacity of 

the PV system. The actual energy produced depends on the solar resource at the site and efficiency 

of the PV equipment. Use the following 

equation (Box 1) to estimate the size of a 

PV system needed. To estimate your 

energy needs per month for a remediation 

system that is already operating, look at the 

site’s energy bill for the number of kWh 

used per month. See Section 10.5 (page 

114) for calculators to help size a solar PV 

system for the needs of your site. 

Box 1 Size Calculation for a Simple PV System 

S = E ÷ O 

S = PV System Rated Power Output (kW) 

E = Site Energy Needs per Month (kWh per month) 

O = Average PV Energy Output (kWh per kW per month); 

Estimate 135 kWh/kW/month 

3.4 GRID-TIED OR STAND-ALONE SYSTEMS 

As previously discussed, grid-tied systems are connected to a utility grid. Stand-alone systems are 

not connected to a grid and may need battery backup or another source of power (e.g., clean diesel 

generator or wind turbine hybrid system) if a constant source of energy is necessary. Batteries add 

a substantial cost to a PV system but may be economical considering the cost of extending power 

lines. Evaluate the available electricity infrastructure in addition to solar energy availability. 

Stand-Alone Day Use with DC Load 

These systems are the simplest and least expensive. This 

configuration is applicable for remote sites that do not 

require a steady supply of power, especially at night. 

Examples include solar powered remote water pumps and 

solar powered fans used to circulate air in the daytime. 

Remediation equipment, devices or appliances that 

operate on DC power can directly use the electricity 

produced from the solar panels (Fig. 9).47 

Stand-Alone DC Load with Batteries 

Figure 9 Day use DC load. “PV Array” 

image courtesy Solar On-Line46 

In many cases, electricity is needed in the day as well as at night and during cloudy weather. 

Excess energy produced during the day is stored in a battery to be used when the solar resource is 

not available. Battery power can also be used to provide high surge currents for short amounts of 

Chapter 3: Solar Power 18 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

time which may be useful to 

start large motors. To 

prevent the battery, or 

batteries, from being 

overcharged or overly 

discharged, a device called a 

charge controller must be 

installed (Fig. 10).49 See 

Appendix III (page 132) for 

more information on charge 

controllers. PV systems with 

batteries cost about $15,000-$20,000 per kW.50 

Stand-Alone AC Load with Battery 

When solar panels are used to power AC loads, an inverter is installed to convert solar DC power to 

AC power (Fig. 11). Though inverters add complexity and cost, their use usually cannot be avoided. 

AC appliances are mass produced and more reliable than DC appliances. To see if your load is AC 

or DC, check manufacturer specifications.51 

Figure 10 Stand-alone DC load with batteries. Separate images courtesy 

Solar On-Line except “DC Load”48 

Figure 11 Stand alone AC load with battery. Separate images courtesy Solar On-Line except “AC Load”52 

Grid-Tied AC Load 

Grid-tied systems are 

interconnected with the utility grid 

(Fig. 12). When energy 

consumption exceeds energy 

production, the grid provides the 

remaining electricity needed. At 

times when electricity production 

is greater than consumption, 

excess energy is sent to the utility 

grid. Utilities may have a netmetering program that gives 

credits for electricity sent to the 

grid. See Appendix XII (page 176) 

Figure 12 Grid-tied AC load without battery. Image courtesy Solar OnLine except for “AC Load”53 

Chapter 3: Solar Power 19 
 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

for net metering rules in your area. Also, without a battery, if the grid goes down, the site will not be 

able to get electricity from your solar PV system. They are disconnected at these times so utility 

employees are not at risk from an unexpected “live” wire.54 Contact the local utility for more 

information on connecting to the grid. 

Grid-Tied AC Load With Battery 

Grid-tied systems can still have battery backup to help reduce demand from the grid. Excess energy 

generated will charge the battery, or batteries. If there is more energy left over, it will run back to the 

grid. In case the PV and battery system cannot meet the demand, the grid will provide necessary 

electricity. Also, these systems can operate when grid electricity is unavailable. 

3.5 CAPITAL COST, O&M, INSTALLERS AND WARRANTIES 

Estimate Capital Cost 

The capital costs of a PV system with battery 

backup is $15,000-$20,000 per rated kW ($15­

$20 per watt). PV systems without batteries cost 

$8,000-$10,000 per rated kW ($8-$10 per watt) 

(Box 2).55 See Section 10.5 (page 114) for 

calculators to estimate initial costs, cash flow, 

and energy production. 

Operations and Maintenance 

Box 2 Capital Cost Calculation for a Simple PV System 

C = S ∗ P 

C = Capital Cost of PV System ($) 

S = PV System Rated Power Output (kW) 

P = Price per kW of PV System ($ per kW); Estimate 

$10,000/kW

Panels should be cleaned once a year if the cleanup site receives little rain and/or wind or has 

substantial bird populations. The PV equipment manual should provide more information on 

maintenance of the system and its components. Inverters should be stored in a cool and dry 

location out of direct sunlight if possible. Dust and cobwebs on the inverter unit inhibit it from cooling 

properly. Inverters usually need replacement after about 15 years of operation. Cost for inverter 

replacement is about $700 per rated kW.56 If your system has batteries, they need to be replaced 

every 5-10 years.57 It is important to allow air flow under and over the modules to remove heat and 

avoid high cell temperatures. A module will lose approximately 0.5 percent efficiency per degree 

centigrade temperature rise between 80 ̊C and 90 ̊C.58 The output of a PV module degrades by 

about 0.5 percent per year.59 Annual 

operations and maintenance costs are 

around 0.25-1.5 percent of the initial 

capital cost.60 Estimate total operations 

and maintenance costs for the life of 

the solar system with the equation in 

Box 3. 

Box 3 Lifecycle Operation and Maintenance Costs 

O&M = P ∗ C ∗ Y 

O&M = Total Lifecycle O&M Costs ($) 

P = 0.0025 for low estimate; 0.015 for high estimate 

C = Capital Cost of PV System ($) 

Y = Years of operation (years); Estimate 25 years 

Chapter 3: Solar Power 20 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Solar Installers 

Setting up a PV system on a cleanup site is usually done through a solar installer or contractor. 

They will design and size the PV system, and acquire and install the appropriate panels, inverters, 

wiring, batteries, mounting, and any other equipment for a full running system. Here are a few 

websites that provide information on solar installers: 

□ Findsolar.com: Pre-screened, customer reviewed installers. www.findsolar.com Select “Find a 

Solar Pro.” 

□ Solar Energy Industries Association Members: National solar trade association. www.seia.org 

□ General Services Administration Contracts Schedule: www.gsaelibrary.gsa.gov Search “206 3” 

for solar businesses. 

□ Source Guides: Renewable energy businesses and organizations directory. 

www.sourceguides.com 

Start with contractors local to the site since they would be familiar with the weather, sun availability, 

and permitting processes for the area. Make sure that they are licensed (Section 10.4 page 114). 

Research or interview the companies with some of the following questions. 61 For a more extensive 

list of questions for your potential installer, see Appendix III (page 133). 

• How many projects like yours have they completed in the past year? In the past three 

years? 

• Can they provide a list of references for those projects? 

• What PV training or certification do they have? 

• Do they offer adequate warranties? 

• Can you communicate effectively with the contractor? 

Warranties62 

More expensive solar panels may include a 20-25 year warranty. However, this warranty will not 

likely apply to all system components. The parts and labor warranty will usually cover two years, in 

addition to the regular manufacturer's warranty. Batteries typically have limited warranties ranging 

from 8-10 years. Inverters will usually have a two year warranty. 

Be sure of the following: 

• Is your warranty included in the cost of the bid, or do you know its cost? 

• Does the warranty cover all aspects of the removal, shipping, repair and reinstallation of 

components? 

• Who is responsible for all aspects of the system--is it the installer, the manufacturer, the 

dealer? 

Chapter 3: Solar Power 21 
 

 

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3.6 PERMITS AND ENVIRONMENTAL CONCERNS 

Permits 

Installers are usually responsible for garnering permits from city and/or county offices and will pass 

on these costs to the customer.63 Among these are building permits and electrical permits. Permit 

fees may cost up to $1,500 although some cities have eliminated the fee for solar installations.64 

Sometimes, additional drawings or calculations must be provided to the permitting agency. Be sure 

the permitting costs and responsibilities are addressed with your PV contractor before installation 

begins. 

Environmental Concerns 

The following addresses some PV system environmental concerns. 

How long does it take for a PV system to recover the energy that went into producing it? 

DOE estimates that today’s multi-crystalline silicon PV systems have about a four year energy 

payback period while it takes three years for current thin-film modules, two years for future multicrystalline modules, and one year for anticipated thin-film modules.65 

What happens to panels after their useful life? 

PV systems have about a 25-30 year useful life so there currently is little issue with its disposal. PV 

products are generally safe for landfills because PV materials are usually encased in glass or plastic, 

and many are insoluble. Some modules, however, may be classified as hazardous waste due to 

small amounts of lead solder, selenium and cadmium.66 This is prompting the PV industry to 

develop recycling processes for modules. Recycling processes may even allow some PV 

components to be recovered intact. This in turn would allow companies to produce recycled PV 

modules at a lower cost and with lower energy use.67 

3.7 SUCCESS STORIES 

The following are three success stories 

of Region 9 Superfund sites that are 

using solar PV systems. 

Pemaco Superfund Site, Maywood, 

CA, Region 9 

Pemaco is a fund-lead Superfund site 

located in southern California in the city 

of Maywood. It is a former chemical 

mixing plant and EPA determined that 

the soil and groundwater on site were 

contaminated with volatile organic 

Figure 13 3-kW solar PV system at Pemaco. 

Image courtesy Caraway68 

Chapter 3: Solar Power 22 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

compounds (VOCs) including perchloroethylene (PCE), trichloroethylene (TCE), trichloroethane 

(TCA), dichloroethane (DCA), and vinyl chloride. A 3-kW solar system was installed on the roof of 

the building that houses remediation equipment (Fig. 13). It will provide some of the electricity 

demanded for the site. The PV panels were installed and operational as of June 29, 2007, and 

power was being directed back into the utility grid. The PV system will produce an estimated 375 

kilowatt hours per month (4,506 kilowatt hours per year) and will avoid 4,311 pounds of CO2 per 

year, four pounds of NOx per year, and three pounds of sulfur dioxide (SO2) per year. 

Site Contact: 

Rose Marie Caraway 

RPM, EPA Region 9 

Phone: (415) 972-3158 

E-mail: caraway.rosemarie@epa.gov 

Apache Powder Company Superfund Site, St. David, AZ, Region 9 

The Apache Powder Company Superfund site is a former industrial chemicals and explosives 

manufacturing plant. Contaminants identified on-site include high concentrations of heavy metals in 

ponds, arsenic, fluoride and nitrate in perched groundwater, dinitrotoluene in a drum disposal area, 

and nitrate in shallow wells. The perched groundwater zone is pumped and treated by forced 

evaporation (brine concentrator). The shallow aquifer is pumped and treated with the use of 

constructed wetlands. The treated water is then pumped back into the aquifer. Solar power is used 

on site to power a pump that recirculates water through the wetlands when the water cannot be 

discharged to the aquifer (when water exceeds nitrate discharge limit of 30 parts per million [ppm]). 

The PV system consists of twelve PV panels with a 1,440 watt total capacity and one solar powered 

centrifugal pump. The system is capable of pumping five gallons per minute through 100 feet of two 

inch fire hose with an elevation rise of about 10 feet. The system is only used when sunlight is 

available. 

Site Contacts: 

Andria Benner 

RPM, EPA Region 9 

Phone: (415) 972-3189 

E-mail: benner.andria@epa.gov 

Greg Hall 

Apache Nitrogen Products, Inc. 

E-mail: ghall@apachenitro.com 

Lawrence Livermore National Laboratory Site 300 Superfund Site, Eastern Altamont Hills near 

Livermore, CA, Region 9 

The Lawrence Livermore National Laboratory Site 300 is an 11 square mile facility operated by the 

University of California System for DOE as a high explosives and materials testing site for nuclear 

weapons research, established in 1955. Groundwater contaminants released from various on-site 

activities include solvents, VOCs, tritium, uranium-238, highly explosive compounds, nitrate, and 

perchlorate. Sources of contamination include spills, leaking pipes, leaching from underground 

landfills and pits, high explosives testing and disposal of waste liquids in lagoons and dry wells. A 

Chapter 3: Solar Power 23 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

groundwater P&T system is operating to treat contaminated groundwater at four locations. Solar 

power is used to pump water through four granulated activated carbon (GAC) systems. The 

systems were installed between June 1999 and September 2005. The low flow systems pump 

groundwater at about 5 gallons per minute from depths of 75-100 feet. Each system has a capacity 

of 800 watts (for a total of 3.2 kW) and costs about $2,000. These systems are not grid connected 

but they are equipped with batteries to store excess power to allow for some operation during nondaylight hours. 

Site Contacts: 

Kathy Setian 

RPM, EPA Region 9 

Phone: (415) 972-3180 

E-mail: setian.kathy@epa.gov 

Ed Folsom 

Lawrence Livermore National Laboratory 

Phone: (510) 422-0389 

E-mail: folsom1@llnl.gov 

Chapter 3: Solar Power 24 
 

 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Chapter 4 Table of Contents 

4.1 Wind Power Terminology 

4.2 Wind Power Technology Basics 

4.3 Assessing Wind Power Potential and 

Sizing a Wind Turbine 

4.4 Grid-Tied or Stand-Alone Systems 

4.5 Capital Costs, O&M, Permits, Insurance 

and Environmental Concerns 

4.6 Finding Wind Turbine Vendors and 

Installers 

4.7 Success Story 

CHAPTER 4: WIND POWER 

Wind is a renewable energy resource that can be 

captured to produce electricity. Wind turbines 

convert kinetic energy from wind into mechanical 

energy (Fig. 15). Generators then convert this 

mechanical energy into electrical energy that can be 

used anywhere, including on a cleanup site. An 

average wind speed of at least 10 miles-per-hour 

(mph) at 33 feet above the ground is typically 

necessary to run a wind turbine. An example of a 

Superfund site utilizing wind power is the Nebraska 

Ordnance Plant Superfund Site. It currently has a 

10-kW wind turbine powering its groundwater 

circulation wells (see Section 4.7). 

4.1 WIND POWER TERMINOLOGY69 

The following are some wind power terms and definitions (Fig. 14). 

Anemometer Device on a wind turbine that measures wind speed and transmits wind speed data to 

the controller. 

Blades Most turbines have either two or three blades. Wind blowing over the blades causes the 

blades to "lift" and rotate. 

Controller Component of a wind 

turbine that starts up the rotor 

in 8-16 mph wind and shuts it 

off when wind speeds exceed 

about 65 mph. Usually, 

turbines cannot operate in 

such high wind speeds 

because their generators 

could overheat. 

Cut-in Speed Minimum wind 

speed needed to turn a wind 

turbine and produce electricity. 

Varies from turbine to turbine. 

Figure 14 Parts of a wind turbine. Image courtesy DOE, EERE70 

Chapter 4: Wind Power 25 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Cut-out Speed Maximum wind speed that a turbine can 

handle. Turbines automatically stop spinning at winds 

speeds greater than the cut-out speed to prevent 

damage to the turbine. Varies from turbine to turbine. 

Generator Device that converts mechanical energy into 

electrical energy. 

High-speed Shafts Drive the generator at 1,000-1,800 

revolutions per minute (rpm). 

Inverter Small wind turbines (20 W–100 kW) usually 

produce DC power. Inverters convert DC power to AC 

power so it can be used to power AC equipment. 72 See 

Appendix III (page 132) for more details. 

Low-speed Shafts Drive the generator at 30-60 rpm. 

Nacelle The nacelle sits atop the tower and encloses the 

gear box, low- and high-speed shafts, generator, 

controller, and brake. A cover protects the components 

inside the nacelle. Some nacelles are large enough for a 

technician to stand inside while working. 

Power Curve Graph showing the power output of a wind 

turbine at various wind speeds. 

Swept Area Space that turbine blades travel through. Larger swept areas capture more wind 

energy.73 Swept Area = π x r2 (r = length of one blade; π ≈ 3.14) 

Tower Vertical structure made from tubular steel or steel lattice. Because wind speed increases 

with height, taller towers enable turbines to capture more energy and generate more electricity 

than turbines mounted on shorter towers. See Appendix IV (page 135). 

Wind Power Class NREL wind speed and corresponding wind power classification system (Table 2). 

Wind Power Density Available power usually measured in watts per square meter (Table 2). 

Wind Direction Figure 14 illustrates an "upwind turbine”, so-called because it operates with the 

blades facing into the wind. Other turbines are designed to run downwind, with the blades facing 

away from the wind. 

Wind Map Map showing average annual wind speeds at a specified elevation (Fig. 20 page 30). 

Wind Vane Component of a turbine that measures wind direction and communicates with the yaw 

drive to orient the turbine properly with respect to the wind. Also known as the tail. 

Yaw Drive Component of a turbine that keeps the rotor facing into the wind as wind direction 

changes. 

Figure 15 A 5-kW wind turbine. 

Image courtesy ISET71 

Chapter 4: Wind Power 26 
 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

4.2 WIND POWER TECHNOLOGY BASICS 

Kinetic energy in wind can be captured by wind 

turbines and converted to mechanical energy. 

Generators produce electricity from the 

mechanical energy. Simply, wind turbines work 

like a fan operating backwards. Instead of 

electricity making the blades turn to blow wind 

from a fan, wind turns the blades in a turbine to 

create electricity (Fig. 16). Remediation systems 

used to pump groundwater may consider 

windmills that directly draw water, rather than 

turbines for producing electricity. Windmills are 

commonly used on farms and have been utilized 

for hundreds of years.76 

Wind turbines range in size from a few hundred 

Figure 16 Main parts of a wind turbine. 

Image courtesy EERE74 

watts to as large as several megawatts (Fig. 

17).77 The amount of power produced from a wind turbine 

depends on the length of the blades and the speed of the wind. 

The faster the wind speed, the more kinetic energy it has. See 

Appendix IV (page 135) for more information on energy in wind. 

There is a cubic relationship between wind speed and power 

which means that a small change in wind speed will have a 

large effect on the power produced. Wind speeds vary with 

height and are generally weaker near the ground due to friction 

between earth’s surface and air flow. To reduce turbulence and 

capture a greater amount of wind energy, turbines are mounted 

on towers (Appendix IV page 135). A common tower height is 

about 150 feet though it will depend on the length of the blades. 

A 10-kW turbine is usually mounted on a tower of 80-120 feet.78 

NREL divides wind speeds into wind power classes designated 

Figure 17 3.6 MW turbine. Image 

courtesy EERE75 

Class 1 (lowest) through Class 7 (highest) (Table 2). Class 2 and above wind speeds (at least 10 

mph at 33 feet above ground) can provide sufficient energy to drive a small wind turbine. Utility 

sized turbines usually need at least Class 3 wind conditions to operate. 

Chapter 4: Wind Power 27 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Estimating Wind Power Emissions 

Reductions Using EPA’s Power Profiler 

www.epa.gov/cleanenergy/powerprofiler.htm 

Consider the 10-kW wind turbine at the 

Nebraska Ordnance Plant Superfund site. It is 

estimated to produce about 817 kWh per 

month. Go to the Power Profiler and enter the 

required information. Under “Make a 

Difference,” select “My Emissions.” Enter 817 

kWh into the “Average Monthly Use” option. 

The Profiler estimates that about 19,000 

pounds of CO2 are released annually from 

producing 817 kWh of conventional energy 

each month. This means that the 10-kW wind 

turbine prevents approximately 19,000 pounds 

of CO2 from being released into the atmosphere 

every year. 

Table 2 Wind Power Classes at 10 m (33 ft) Elevation∗79 

Power Class Wind Speed 

mph 

Wind Speed 

m/s 

Power Density 

W/m2 

1 0-9.8 0-4.4 0-100 

2 9.8-11.5 4.4-5.1 100-150 

3 11.5-12.5 5.1-5.6 150-200 

4 12.5-13.4 5.6-6.0 200-250 

5 13.4-14.3 6.0-6.4 250-300 

6 14.3-15.7 6.4-7.0 300-400 

7 15.7-21.1 7.0-9.4 400-1,000 

Figure 18 Darrieus style wind 

turbine. Image courtesy 

Solcomhouse80 

There are two basic groups of wind turbines. Horizontal axis turbines (propeller style) have two 

blades that face downwind or three blades that face upwind. Vertical axis turbines, such as the 

eggbeater-style Darrieus model, are less commonly used (Fig. 18). Blades for both types of turbines 

are made from fiberglass, carbon fiber, hybrid composites, or wood and will not interfere with 

television or radio waves.81 

Wind turbines can be used in a wide variety of applications, from charging batteries to pumping 

water to powering a significant portion of a site. Large turbines are considered to be those rated 

greater than 100 kW and small turbines are considered to be 100 kW or less.82 Turbines produce 

DC or AC power, depending on the generator.83 

Small turbines usually generate DC power.84 

Generators that produce DC power need an inverter 

to change the power to AC for use in most 

equipment. See Appendix III (page 132) for 

information on inverters. While variable speed 

turbines do not produce electricity at the voltage and 

frequency used in most equipment, these turbines 

are usually equipped with features to produce 

∗

 1 meter per second (m/s) = 2.237 miles per hour (mph) 

Chapter 4: Wind Power 28 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

correct voltage and constant frequency compatible with the loads.85 

Wind power will present an advantage for locations that are not easily accessible to local utility 

lines.86 The expected wind turbine lifetime is about 20–30 years.87 See Appendix IV (page 136) for 

a calculation of power output. 

Wind Turbine Power Curve 

A wind turbine power curve shows the power output of a turbine at corresponding wind speeds. 

Power curves are specific to different wind turbines. A wind turbine with the power curve shown in 

Figure 19 may be rated for a maximum output of 500 kW. What may not be stated upfront is that 

wind speeds of 14-24 m/s are necessary to reach a 500 kW output. Be sure to determine the power 

output of a turbine for wind speeds specific to your site. Wind turbine developers can properly install 

a turbine that is well-suited for each site. Higher altitudes usually have faster wind speeds because 

winds are more turbulent closer to the ground. Though it is more expensive to install a taller tower, it 

is often a good investment because of the greater return in energy production. 

4.3 ASSESSING WIND POWER POTENTIAL AND SIZING A WIND TURBINE 

Does My Site Have Wind Power Potential? 

There is a space minimum as well as 

wind speed minimum for a wind power 

project to be feasible for your site. The 

potential site should be located on or 

near at least one acre of open, rural 

land. More importantly, it is necessary 

to have consistent wind at speeds of at 

least 10 mph (4.5 m/s) at an elevation 

of 33 feet (10 m) (Fig. 20). A common 

height for wind turbines is about 150 

feet (45.7 m), where wind speeds are 

approximately 25 percent greater than 

at 30 feet. 

The turbine manufacturer can provide 

the expected annual energy output of a 

turbine as a function of annual average wind speed. A wind energy system, including rotor, 

transmission, generator, storage and other devices, will deliver approximately 10-30 percent of the 

energy available in the wind, depending on the manufacturer.89 A 1.5-kW wind turbine will produce 

about 300 kWh per month in a location with a 14 mile-per-hour (mph) or 6.26 meters-per-second 

(m/s) annual average wind speed. A 10-kW turbine typically has a blade diameter of about 20-25 

feet and would typically be mounted on a tower roughly 100 feet tall. If placed at a site with wind 

speeds of 10–15 mph, it will produce between 10,000 and 18,000 kWh per year.90 

Figure 19 Sample wind Turbine Power Curve. Courtesy De 

Montfort University88 

Chapter 4: Wind Power 29 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Wind speeds at a site can vary based on local topography and structural interference. Localized 

areas of good wind power potential such as a ridge-top may not show up on a wind map, so sitespecific evaluations should be conducted to determine wind availability. Wind turbines should be 

sited in an area where obstructions or future obstructions, such as new buildings, will have minimal 

effect on the wind resource. Keep in mind that, depending on the manufacturer and/or model, some 

turbines run more efficiently at lower wind speeds and others are more efficient at higher speeds. 

Consult vendors to determine which turbines will operate efficiently with wind speeds available at 

your site. 

To view average wind speed maps, visit: 

□ EERE: Provides annual average wind speed maps for individual states. 

www.eere.energy.gov/windandhydro/windpoweringamerica/wind_maps.asp 

□ NREL: Provides annual average and seasonal wind speed maps for individual states and U.S. 

territories. http://rredc.nrel.gov/wind/pubs/atlas/maps.html 

□ Bergey Windpower: Provides wind maps for individual states and U.S. territories. 

www.bergey.com/wind_maps.htm 

Figure 20 Wind resource map. NREL provides national wind maps and state-by-state maps.91 

Location-specific wind speed data can be obtained using a recording anemometer, which generally 

costs $500-$1,500. Your local utility may provide services that lend assessment tools for renewable 

energy projects (See Section 10.6 page 115). The most accurate readings are taken at "hub height" 

Chapter 4: Wind Power 30 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

(i.e., the elevation at the top of a potential wind turbine tower). This requires placing the 

anemometer high enough to avoid turbulence created by trees, buildings, and other obstructions. 

Determining Size of Wind Power System 

While solar panels are rated at an industry 

standard, there are no standards that apply 

to wind turbines. The electricity produced 

by a wind turbine depends on the following 

factors: 

• Average wind speed of your site 

• Length of blades (corresponds to 

swept area) 

• Tower height 

• Efficiency of system components 

Use the equation in Box 4 for a rough 

estimate of the turbine size, in terms of 

rated power output (kW), needed to 

completely or partially provide electricity for 

your site. 

Consider a site that has an average wind 

speed of 7 m/s (15.6 mph) and consumes 

87,000 kWh a year. Enter 87,000 kWh into 

the equation to find that your site would 

need about a 40-kW turbine to meet all the 

site’s electricity needs, based on average 

electricity demand. You would need a wind 

turbine that outputs about 40 kW at 7 m/s 

wind speeds. To get a rough estimate of 

Box 4 Estimate Turbine Rated Power Output (kW)92 

P = E ÷ CF ÷ 8,760 

P = Turbine Rated Power Output (kW)

E = Site Energy Needs per Year (kWh) 

CF = Capacity Factor; Small Turbine Estimate ~0.25; Large

Turbine Estimate ~0.30 

8,760 = Hours in One Year 

Box 5 Estimate Turbine Energy Production 

G = P ∗ CF ∗ 8,760 

G = Annual Energy Production (kWh) 

P = Turbine Rated Power Output (kW)

CF = Capacity Factor; Small Turbine Estimate ~0.25; Large

Turbine Estimate ~0.30 

8,760 = Hours in One Year 

Box 6 Estimate Length of Blades93 

AEO = 0.01328 x D2 x V3 

AEO = Annual Energy Output (kWh per year)

D = Diameter of rotors (feet) 

V = Average wind speed (mph)

how much energy would be produced by this turbine at a certain speed, use the equation in Box 5. 

You can also use the equation in Box 6 to estimate the lengths of the blades your turbine would 

need to meet your site’s energy demand. 

These equations help to provide very rough estimates. Wind turbine manufacturers can help you 

more precisely size your system based a cleanup site’s electricity needs and the specifics of local 

wind patterns.94 They can factor in the particular wind turbine power curve, the average annual wind 

speed at the site, the height of the tower that you plan to use, and the frequency distribution of the 

wind (i.e., estimated number of hours that the wind will blow at each speed during an average year). 

They may also adjust this calculation for the elevation of your site. 

Chapter 4: Wind Power 31 
 

 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

4.4 GRID-TIED OR STAND-ALONE SYSTEMS 

Grid-tied systems have access to 

electricity supplied by a utility. Sites 

that are interconnected can receive 

energy both from the utility and from a 

local wind turbine (Fig. 21). When the 

turbine produces more electricity than 

is consumed, excess electricity is sent 

to the grid. Net metering programs 

allow grid-tied utility customers who 

generate electricity in excess of their 

consumption to credit that amount for 

later use.97 When wind power is 

 Figure 21 Grid-connected wind turbine. Image courtesy EERE95 

unavailable, the site can use the 

energy credits from the utility. Some 

utilities may purchase excess power 

generated from wind turbines. For 

more information on utilities that have 

net metering programs, see Appendix 

XII (page 176). 

Wind power will be an even better 

investment if your site is not easily 

accessible to local utility lines.98 The 

cost of extending utility lines to a 

remote location can cost as much as 

$20,000-$30,000 per quarter mile.99 

Stand-alone sites do not have access 

to grid-electricity. They must 

completely rely on wind power or a hybrid system with another renewable energy technology and/or 

a clean diesel generator (Fig. 22). If it is important to have a reliable, constant source of electricity, 

battery backup may be necessary. Battery systems can store power for use when the wind is not 

blowing. See Appendix III (page 130) for more information on batteries. Grid-tied systems can also 

consider a hybrid system to further reduce dependence on the grid. 

4.5 CAPITAL COSTS, O&M, PERMITS, INSURANCE AND ENVIRONMENTAL 

CONCERNS 

This section includes information on estimating wind turbine capital costs and payback times. It also 

discusses O&M costs and labor. Information on potential permit and zoning issues are also 

included. This section also addresses some insurance and environmental concerns. 

Figure 22 Stand-alone hybrid system of wind power, solar power, 

battery backup and clean diesel generator. Image courtesy EERE96 

Chapter 4: Wind Power 32 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Capital Costs 

The Windfarmers Network estimates that the capital cost for a wind turbine is about $1,000 per kW 

of generation capacity, usually for utility-size turbines.100 The American Wind Energy Association 

estimates that capital costs range from $3,000 to $5,000 per kW for smaller systems.101 Costs may 

vary from project to project depending upon the size of the turbine(s), interconnection costs, 

permitting costs, installation and transportation costs, generator model, the type of tower and other 

components in your system such as batteries, inverters, and controllers. According to the American 

Wind Energy Association, a typical 10-kW wind turbine system will cost $25,000-$35,000. A 3-kW 

turbine mounted on a 60-80-ft tower costs about $15,000, including accessory components and 

batteries. Systems smaller than 1-kW are often used in stand-alone applications, or as part of a 

hybrid system with solar PV cells. A 400-watt system can be installed for $1,500.102 

Used turbines will be much less expensive but should undergo remanufacturing by a qualified 

mechanic. Many parts should be replaced even if they are still functioning.103 

Well-sited small wind turbines usually have a simple payback time of 15 years, about half of their 

serviceable lifetimes, if federal and state incentives are applied.105 Installing a wind turbine is usually 

cost effective if electricity rates are more than 10-15 cents per kWh and there are sufficient wind 

resources. See Section 10.3 (page 111) for economic analysis calculations and Section 10.6 (page 

115) for wind power calculators. 

Operation and Maintenance 

Annual operating and maintenance costs for a wind 

turbine are estimated to be about one percent of 

the capital cost. Alternator bearings need 

replacement after several years of operation. The 

same is true for yaw bearings given their significant 

loading. Check that bolts remain tight. Dust, 

debris, and insects will eventually erode the most 

durable blade materials, and leading edge tapes. 

Paint coatings, subjected to sunlight, moisture, and 

temperature extremes will eventually deteriorate. 

Also, the lubricant in the gear box, like oil in a car 

engine, will degrade over time. Maintain the 

turbine as recommended by the manufacturer to 

ensure that it will continue to operate properly for 

many years (Fig. 23).106 

Permits 

Permitting requirements, procedures, and fees for wind turbines vary by county. Consider zoning 

issues in advance since local zoning codes or covenants may not allow wind turbines. You can find 

out about the zoning restrictions in your area by calling the local building inspector, board of 

 Figure 23 Repairing a wind turbine. Image 

courtesy Argonne National Lab104 

Chapter 4: Wind Power 33 
 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

supervisors, or planning board. They should be able to tell you if you will need to obtain a building 

permit and provide you with a list of requirements.107 

Costs for building permits, zoning permits, and use permits may range from $100 to $1,600. Contact 

your county permitting agency or planning department for information on permitting issues. Find out 

if small wind energy systems (under 100 kW) are addressed by your local ordinance. Review the 

applicable standards and restrictions. They may include minimum land size, tower height 

restrictions, minimum distance from the edge of the property, and maximum noise levels. The 

turbine must comply with the Uniform Building Code and National Electric Code. Federal Aviation 

Administration approval may be necessary if your site is within 20,000 feet of a runway and your 

tower is taller than 200 feet. Wind turbines may be subject to local restrictions if they are near 

coastal regions, scenic highways or other specially designated areas.108 In many cases, a building 

permit for a wind turbine tower will require that the zoning board grant you a conditional use permit 

or a variance from the existing code.109 Also consult neighbors before installing a turbine on your 

site. This is recommended and sometimes required by county planners. You may need to appear at 

a public hearing for a conditional use permit or variance. For grid-tied systems, contact your local 

utility for more information on interconnection requirements and net metering programs if 

applicable.110 Consultants can also help with permitting issues. 

Contact the local municipality for more information on permitting requirements. For more information 

on permitting issues, go to www.awea.org/smallwind/toolbox/INSTALL/building_permits.asp. 

Insurance 

For grid-tied systems, some utilities require small wind turbine owners to maintain liability insurance 

in amounts of $1 million or more. Laws or regulatory authorities in some states, including California 

and Nevada, prohibit utilities from imposing any insurance requirements on small wind turbines that 

qualify for net metering.111 

Environmental Concerns 

There has been concern over the risk that wind turbines pose to birds and bats. While wind turbines 

may pose a danger to wildlife if not carefully sited, fatalities from turbines are minimal compared to 

deaths due to buildings, windows, power lines and radio towers. Tower design changes and careful 

siting of the turbine will mitigate this problem.112 Consideration of migration patterns is an important 

step in the process. Look into legal and environmental limitations for your site’s city and county and 

contact your local Audubon Society. 

4.6 FINDING WIND TURBINE VENDORS AND INSTALLERS 

Wind power companies may provide services from designing a wind energy system to acquiring 

equipment to system installation. Check the following websites for databases of wind energy 

professionals. 

□ American Wind Energy Association: Searchable member directory provides list of wind energy 

professionals. www.awea.org, http://web.memberclicks.com/mc/page.do?orgId=awea 

Chapter 4: Wind Power 34 
 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

□ General Services Administration Contracts Schedule: www.gsaelibrary.gsa.gov Search “206 3” 

for wind power businesses. 

□ California Energy Commission (CEC): California registered wind turbine retailers. 

www.consumerenergycenter.org/erprebate/database/index.html 

□ Source Guides: Worldwide renewable energy directory. www.energy.sourceguides.com 

Tips to choose among wind turbine manufacturers and installers113 

• Obtain and review the product literature from several manufacturers. 

• Ask the turbine manufacturer to suggest turbines that run most efficiently at speeds 

comparable to wind speeds at your site. 

• Ask for references of past customers with installations similar to the one you are considering. 

• Ask current system owners about performance, reliability, and maintenance and repair 

requirements, and whether the system is meeting their expectations. 

• Find out how long the warranty lasts and what it includes. 

• Find out if the installer is a licensed electrician (Section 10.4 page 114). 

• A credible installer will help with permitting issues. 

• Consider contacting the Better Business Bureau (www.bbb.org) to check the company’s 

integrity. 

4.7 SUCCESS STORY 

Nebraska Ordnance Plant Superfund Site, near Mead, NE, 

Region 7 

The Nebraska Army Ordnance Plant operated from 1942 to 

1956 as a munitions production plant. The groundwater is 

contaminated with VOCs and explosives and soils are 

contaminated with polychlorinated biphenyls. P&T technology 

is utilized to address groundwater cleanup. A grid-tied 10-kW 

wind turbine powers a single relatively low energy groundwater 

circulation well (GCW), operating at a flow rate of 50 gallons 

per minute (Fig. 24). The GCW is equipped with air strippers 

used to treat TCE contaminated groundwater. The site has an 

average wind speed of 14.3 mph (6.4 m/s). The average 

monthly electricity demand by principal components of the 

GCW is 767 kWh. On average, the wind turbine generates 

817 kWh each month; the excess electricity is sent to the grid. 

Over the initial five months of the project, the system treated 

more than 4 million gallons of water and an estimated 63 

kilograms (kg) of TCE were removed from groundwater. This 

Figure 24 Installation of 10-kW turbine 

at Nebraska Ordnance Plant Dec 2003. 

Image courtesy EPA114 

Chapter 4: Wind Power 35 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

project was funded by the EPA’s Office of Solid Waste and Emergency Response through a grant 

program of the Innovation Work Group, with additional support from University of Missouri-Rolla, the 

Kansas City District Corps of Engineers, Bergey Wind Systems, and Ohio Semitronics. Researchers 

estimate that the use of wind power, coupled with a well designed climate control system, may result 

in a present-worth energy cost savings of more than $40,000 over the 20 years of groundwater 

treatment anticipated at this site. Similarly-sized off-grid wind turbine systems, including installation, 

cost approximately $45,000. The wind turbine saved an estimated total of 17,882 pounds of CO2 

emissions over a period of 19 months. 

For details, see www.clu-in.org/products/newsltrs/tnandt/view.cfm?issue=0904.cfm and 

www.epa.gov/oswer/docs/iwg/groundwaterFactSheet_final.pdf. 

Site Contacts: 

Scott Marquess 

RPM, EPA Region 7 

Phone: (913) 551-7131 

E-mail: marquess.scott@epa.gov 

Dave Drake 

RPM, EPA Region 7 

E-mail: drake.dave@epa.gov 

Curt Elmore, Ph.D., P.E., 

Assistant Professor of Geological Engineering, University of Missouri-Rolla 

Phone: (573) 341-6784 

E-mail: elmoreac@umr.edu 

Chapter 4: Wind Power 36 
 

 

Chapter 5 Table of Contents 

5.1 Landfill Gas-to-Energy Terminology 

5.2 Landfill Gas-to-Energy Technology 

Basics 

5.3 Assessing Landfill Gas-to-Energy 

Project Potential and System 

Components 

5.4 How Much Energy Can a Landfill 

Produce? 

5.5 Capital Cost and Possible Business 

Models 

5.6 Landfill Gas Environmental and Safety 

Concerns and Permits 

5.7 Success Stories 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

CHAPTER 5: LANDFILL GAS-TO-ENERGY

Municipal solid waste (MSW) landfills can provide a 

source of energy. MSW landfills consist of 

everyday garbage generated from residences, 

businesses, and institutions. The decomposition of 

MSW creates landfill gas (LFG). This gas is 

primarily composed of CO2 and methane (CH4). 

CH4, a GHG with high energy content, can be 

captured to produce electricity through the use of 

microturbines, boilers, or engines. As an example, 

Operations Industries Inc. Landfill Superfund Site in 

Southern California is currently powering about 80 

percent of its operations buildings with landfill gas 

(See Section 5.7). 

5.1 LANDFILL GAS-TO-ENERGY TERMINOLOGY 

The following are some landfill gas-to-energy terms and definitions. 

Boiler / Steam Turbine A boiler produces thermal energy from burning LFG. This heat is used in a 

steam turbine and generator to produce electricity. This configuration is best suited for landfills 

with gas production of greater than five million cubic feet per day.115 It is the least used among 

LFG projects because it is more expensive than other gas power conversion technologies for the 

typical size of landfill projects.116 See Appendix V (page 142). 

Co-disposal landfill Landfill that may contain MSW as well as some hazardous wastes. 

Collection Wells Wells strategically dug into a landfill to collect LFG. Gas collection system 

transports the gas to be treated and used to generate electricity or as a direct fuel. 

Combustion (Gas) Turbine (CT) Energy generation equipment typically used in medium to large 

LFG projects, where LFG production is approximately two million cubic feet per day. This 

technology is competitive in larger LFG electric generation projects because of significant 

economies of scale. The electricity generation efficiency generally improves as size 

increases.117 See Appendix V (page 139). 

Compressor A device that changes the density of LFG to be compatible for use in an internal 

combustion engine, combustion turbine, or microturbine to generate electricity. 

Condensate Liquid formed from water and/or other vapors in the LFG that condense as the gas 

travels through the collection pipes. Proper disposal of condensate is necessary. 

Chapter 5: Landfill Gas-to-Energy 37 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Internal Combustion (IC) Engine / Reciprocating Engine Engine in which the combustion of fuel and 

air in a chamber produce expanding gas that can run a electricity generator. IC engines are the 

most widely used electricity generation technology for LFG.118 They are typically used for 

generation projects greater than 800 kW.119 See Appendix V (page 138). 

Landfill gas (LFG) Gas generated when landfill waste decomposes. It is approximately 50 percent 

CO2 and 50 percent CH4. 

Methane (CH4) Highly combustible GHG that makes up about 50 percent of gas produced from a 

landfill. This gas can be used directly to generate heat or as a fuel to produce electricity. 

Methane makes up more than 90 percent of typical natural gas. 

Microturbine Small combustion turbine with rated power outputs that range from 30-250 kW and can 

be combined with each other. They are better-suited to landfills where gas production is low (low 

concentrations of CH4 and/or low flow) to economically use a larger engine and for sites with onsite energy use. Microturbine heat rates are generally 14,000-16,000 BTU per kWh. The total 

installed cost for a LFG microturbine project is estimated to be $4,000-$5,000 per kW for smaller 

systems (30 kW), decreasing to $2,000-$2,500 per kW for larger systems (200 kW and above). 

Operation and maintenance costs are about 1.5-2 cents per kWh.121 The addition of a heat 

recovery system adds $75-$350 per 

kW.122 The CA Energy Commission 

estimates annual maintenance costs 

to be 0.5-1.6 cents per kWh, which 

would be comparable to costs for 

small reciprocating engine 

systems.123 

Municipal Solid Waste (MSW) Everyday 

garbage generated from residences 

and institutions. 

5.2 LANDFILL GAS-TO-ENERGY 

TECHNOLOGY BASICS 

Landfill gas is composed of about 50 

percent CO2, 50 percent CH4, and traces 

of non-methane organic compounds 

(NMOC). In the U.S., landfills are one of 

the largest sources of anthropogenic 

(human-made) CH4 released into the 

atmosphere.124 One kilogram of CH4 

gas in the atmosphere creates 23 times 

the global warming effect as one 

kilogram of CO2 over a 100 year 

period.125 For more information on GHG 

Figure 25 LFGE processes. 

Image courtesy Oregon Department of Energy120 

Chapter 5: Landfill Gas-to-Energy 38 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Estimating Emissions Reductions from a 

LFGE Project Using LMOP’s LFGE 

Benefits Calculator 

www.epa.gov/lmop/res/calc.htm 

The Benefits Calculator estimates methane 

and CO2 emissions reductions from a LFGE 

project. For example, a 3-MW LFGE project 

reduces about 6 tons of methane emissions 

per year and avoids 17 tons of CO2 

emissions due to fossil fuel energy generation 

per year. A project this size could power 

about 2,000 homes. 

global warming potentials, go to www.eia.doe.gov/oiaf/1605/gwp.html. Methane is a high energy 

gas that is used to provide energy for homes, businesses and industries. Instead of wasting a 

valuable energy source by flaring LFG, it can be collected from landfills and used directly for heating 

and/or to generate electricity by implementing a landfill gas-to-energy (LFGE) project (Fig. 25). A 

series of wells drilled into the landfill can collect the gas and transport it through a system of pipes to 

be cleaned (Fig. 26) and then (a) used directly as a boiler fuel to produce hot water or steam to run a 

steam turbine or for other processes; (b) used as a fuel to power internal combustion engines or 

turbines to generate electricity; or (c) treated to become pipeline quality gas.126 Landfill gas may 

also be sold as pipeline quality gas for direct use in heating applications such as for greenhouses, 

dryers, boilers, and many other industrial purposes. 

Co-disposal landfills usually 

produce less CH4 because they 

are generally older and the 

LFG has already escaped to 

the atmosphere. They may 

also have more inert materials 

buried that do not produce CH4. 

Co-disposal landfills tend to 

produce higher concentrations 

of NMOC and air toxics than 

MSW landfills and may be less 

suitable for renewable energy 

generation without engineering 

and waste disposal practices 

and controls. To help evaluate potential emissions 

from hazardous waste landfills, use EPA’s Guidance 

for Evaluating Landfill Gas Emissions From Closed or 

Abandoned Facilities

(www.epa.gov/nrmrl/pubs/600r05123/600r05123.pdf). 

While burning LFG also generates CO2, using LFG is 

considered to contribute a net zero effect to climate 

change because the gas came from recently living

organisms that would have released the same amount 

of CO2 from naturally decomposing.128 However, note 

that all combustion devices, including LFGE systems, 

generate some NOx emissions which are attributed to ground-level ozone and smog formation. 

Overall, the environmental benefit from landfill gas electricity generation projects is significant 

because of the large reductions in CH4 emissions, hazardous air pollutants, and use of limited 

nonrenewable resources such as coal and oil.129 Go to Section 10.7 (page 117) for the LFGE 

Benefits Calculator by EPA’s Landfill Methane Outreach Program (LMOP). 

Figure 26 Landfill gas wells and collection piping. Image courtesy LMOP127 

Chapter 5: Landfill Gas-to-Energy 39 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

5.3 ASSESSING LANDFILL GAS-TO-ENERGY PROJECT POTENTIAL AND 

SYSTEM COMPONENTS130 

This section details the factors to consider when determining whether a landfill gas-to-energy system 

is appropriate for your site. Information on the components of a LFGE system is also included. 

Assessing LFGE Project Potential 

LMOP created a database of landfills in the country that have potential for LFGE projects 

(http://epa.gov/lmop/proj/index.htm). Arizona has 13 potential candidates, California has 40, Hawaii 

has eight, and Nevada has 5. LMOP can also help locate landfills within 20-25 miles of your site 

using their Locator Tool. Contact LMOP (www.epa.gov/lmop/contact) for assistance. 

As a guide, 432,000 ft3

 of LFG is produced per day for every million tons of MSW in a landfill.131 

This is equivalent to 800 kW of power that could be generated. See Section 10.7 (page 117) to 

calculate LFG production. Site measurements are highly recommended, especially for co-disposal 

landfills, to more accurately quantify CH4 flow rates. A flare may be installed to assess LFG flow 

before sizing energy recovery equipment.132 

There are many factors to consider that effect the amount of gas produced at each landfill. Some of 

the most important factors are:133 

Depth of landfill—a depth of at least 40 feet best-suits anaerobic conditions for producing LFG. 

However, LFGE projects have been successfully implemented in shallower landfills. 

Amount of waste—a landfill with at least one million tons of MSW is optimal, although smaller 

ones may be applicable as well. Small landfills are good candidates if the gas will be used onsite or near by. 

Type of waste—organic wastes such as paper and food scraps produce the most LFG. Landfills 

with a lot of construction and demolition, industrial, or hazardous wastes, such as co-disposal 

landfills, may not be as productive. 

Age of landfill—as a landfill ages, the rate of CH4 production decreases. Landfills that are still 

open or have recently closed have the best potential for a LFGE project. 

Rainfall—the bacteria that break down the waste and produce LFG thrive best in moisture. An 

optimal site will have at least 25 inches of rainfall a year. Landfills in arid climates may have 

lower rates of LFG flow but are expected to produce LFG for a longer period of time. 

For a LFGE project preliminary evaluation worksheet, go to Appendix V (page 137). 

Chapter 5: Landfill Gas-to-Energy 40 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

LFGE System Components 

The following are components of a landfill gas-to-energy system. 

1. Gas Collection and Backup Flare: 

Gas collection typically begins after a portion of a landfill (called a cell) is closed. A collection well is 

drilled into the landfill to collect the gas. Each LFG wellhead is connected to lateral piping, which 

transports the gas to a main collection header. An aqueous condensate forms when warm gas from 

the landfill cools as it travels through the collection system. If the condensate is not removed, it can 

block the pipes and disrupt the energy recovery process. Sloping pipes and headers in the field 

collection system are used to drain condensate into collecting ("knockout") tanks or traps. 

Condensate could be recirculated to the landfill, treated on-site, or discharged to the public sewer 

system. Most landfills with energy recovery systems have a flare for combusting excess gas and for 

use during equipment downtimes (Fig. 27). 

2. Gas Treatment: 

The collected LFG must be treated to remove any condensate that is not captured in the knockout 

tanks. NMOC and air toxics must be properly treated. Removal of particles and other impurities 

depend on the end-use application. For example, minimal treatment is required for direct use of gas 

in boilers, while extensive treatment is necessary to remove CO2 and other trace organic compounds 

for injection into a natural gas pipeline. Electricity production systems typically include a series of 

filters to remove impurities that could damage engine components and reduce system efficiency. 

3. Energy Recovery: 

Prime movers such as internal 

combustion (IC) engines, 

combustion turbines (CT), and 

boiler/steam turbines combined 

with generator systems can 

convert energy in LFG into 

electricity. The IC engine is the 

most commonly used 

conversion technology in LFG 

applications. IC engine projects 

typically have higher rates of 

NOx emissions than other 

conversion technologies which may cause a permitting issue. NOx controls can usually be installed 

to meet local requirements. CTs are typically used in medium to large landfill gas projects, where 

landfill gas volumes are sufficient to generate a minimum of 3-4 MW. One of the primary 

disadvantages of CTs is that they require high gas compression levels. More energy is required to 

run the compression system, as compared to other generator options. However, CTs are much 

more resistant to corrosion damage than IC engines and have lower NOx emission rates. They are 

also relatively compact and have low operations and maintenance costs in comparison to IC 

Figure 27 LFGE treatment/blower/flare station. Image courtesy LMOP134 

Chapter 5: Landfill Gas-to-Energy 41 
 

 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

engines. The boiler/steam turbine configuration is less often used as a LFG conversion technology 

compared to IC or CT. It is applicable mainly in very large landfill gas projects, where LFG flow rates 

support systems of at least 8-9 MW. The boiler/steam turbine consists of a conventional gas or 

liquid fuel boiler, and a steam turbine generator to produce electricity. This technology usually 

requires a complete water treatment and cooling cycle, plus an ample source of process and cooling 

water. Other technologies include microturbines and fuel cells. See Appendix V (pages 138-142) 

for details on electricity generation technologies. Use combined heat and power (CHP) applications 

along with these prime movers (heat engine135) to capture the thermal energy output which will 

improve energy efficiency. Go to Appendix V (page 138) for CHP resources. Lastly, note that LFG 

may be corrosive to LFG collection and electricity generation parts and equipment so proper 

maintenance is necessary to keep the system running safely and efficiently. 

5.4 HOW MUCH ENERGY CAN A LANDFILL PRODUCE?136 

Use the following equation to estimate the potential energy production from a landfill each year with 

more site specific information (Box 7). Keep in mind this is a rough estimate that does not account 

for losses in gas capture and transport 

and any efficiency losses from 

conversion to electricity. 

See LMOP’s A Landfill Gas to Energy 

Project Development Handbook, 

Section 2.2.1 “Methods for Estimating 

Gas Flow” 

(www.epa.gov/lmop/res/pdf/handbook 

.pdf) for more precise methods of 

estimating landfill gas production. 

Consider the following example: 

Landfill gas typically contains about 

500 BTUs per cubic foot. This can be 

Box 7 Estimating Landfill Energy Production 

G = F ∗ EC ∗ 365 

G = Potential energy production from a landfill in one year (BTU 

per year) 

F = LFG Flow per day (cfd); 1 million tons MSW ≈ 432,000 cfd 

LFG 

EC = Energy content in LFG (BTU per cf); Estimate 500 BTU/cf 

365 = Days in one year 

. . . 

BTU = British Thermal Unity (1 kWh = 3,414 BTU) 

cfd = cubic feet per day 

BTU/cf = energy content per cubic foot of gas 

used as a default if the BTU value of landfill gas at a specific site is not known. For a 5 million ton 

landfill with a gas flow of about 3 million cubic feet per day, the energy content would therefore be 

calculated as follows: 

548 billion BTU per year = 3 million cfd x 500 BTU per cf x 365 days per year 

5.5 CAPITAL COST AND POSSIBLE BUSINESS MODELS 

Estimating Cost 

Cost of a LFGE project varies depending on a variety of factors including size of the landfill, type of 

electricity generation technology, and site specific characteristics. Site preparation and installation 

costs vary significantly among locations though in general, electric generation equipment accounts 

Chapter 5: Landfill Gas-to-Energy 42 
 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

for about 30-70 percent of the capital cost. Total capital includes the engine, auxiliary equipment, 

interconnections, gas compressor, construction, and engineering. Some landfills may already have 

a gas collection system in place.137 

The California Energy Commission (CEC) estimated the following costs for LFGE projects in 

California in a report published in 2002 (Table 3). 

Table 3 Estimated LFGE Project Costs138 

LFG Collection 

System 

Blower / Flare 

Station 

Reciprocating 

Engine 

Combustion 

Turbine 

Boiler / Steam 

Turbine 

Construction 

Cost 

$10,000 - $20,000 

per acre of landfill 

$350 - $450 

per scfm* 

$1,100 - $1,300 

per kW 

(> 800 kW) 

$1,000 - $1,200 

per kW 

(> 3.5 MW) 

$2,500 - $1,500 

per kW 

(> 10 MW) 

O & M $400 - $900 per 

acre per year 

$20 - $30 per 

scfm per year 

1.6¢ - 2.0¢ 

per kWh 

1.4¢ - 1.8¢ 

per kWh 

1.0¢ - 1.4¢ 

per kWh 

*

Scfm: standard cubic feet per minute 

In a 2005 draft document, the California Climate Action Team estimated total installed costs to range 

between $1,100 and $4,000 per kW of generating capacity.139 Use software and documents listed in 

Section 10.7 (page 117) to estimate LFG production and costs for a MSW landfill gas project. 

Possible Business Models 

The following are examples of business models that outline LFGE operations and maintenance 

roles: 

• Landfill owner owns and manages all LFGE equipment and sells electricity to the utility or 

directly to an end user. 

• Landfill owner owns LFG collection system. Electricity generation equipment owned and 

operated by utility; the utility purchases LFG from landfill owner. 

• Landfill owner provides LFG. Third party owns and operates LFG collection system and 

electricity generation equipment 

Review LMOP’s A Landfill Gas to Energy Project Development Handbook, Section 7 “Selecting a 

Project Development Partner” (www.epa.gov/lmop/res/pdf/handbook.pdf) for more information. 

Though the target audience of this document is the landfill owner, it may provide some insight on 

partnering with other stakeholders. Find a list potential clean energy investors at 

www.nrel.gov/technologytransfer/entrepreneurs/directory.html. 

5.6 LANDFILL GAS ENVIRONMENTAL AND SAFETY CONCERNS AND 

PERMITS140 

This section provides information on LFGE environmental and safety concerns and potential permits 

required for developing a LFGE project. 

Chapter 5: Landfill Gas-to-Energy 43 
 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Environmental and Safety Concerns 

Dioxins and furans are a group of toxic chemical compounds known as persistent organic pollutants. 

Combustion processes, such as incinerating municipal waste, burning fuels (e.g., wood, coal, or oil), 

and some industrial processes, can release dioxins and furans into the atmosphere. Relative to 

many of these combustion processes, landfill gas combustion is less conducive to dioxin/furan 

formation. 

Batteries, fluorescent light bulbs, electrical switches, thermometers and paints are some sources of 

mercury in a MSW landfill. Mercury may be present in landfill gas but combusting the gas converts 

the organic mercury compounds to less toxic inorganic compounds. 

LFG is potentially explosive, may pose an asphyxiation hazard, and may cause headaches and 

nausea due to odors. LFG collection systems minimize exposure. Always take precautions when 

handling LFG. For more information, see the following document by the Agency for Toxic 

Substances and Disease Registry: Landfill Gas Primer: An Overview for Environmental Health 

Professionals (www.atsdr.cdc.gov/HAC/landfill/html/toc.html). 

LFGE Permits 

LFGE projects must follow federal regulations related to both the control of LFG and air emissions 

from the electricity generation equipment. Emissions need to comply with the federal Clean Air Act 

and Resource Conservation and Recovery Act. States may have more stringent requirements. 

Permits can take more than a year to attain. No construction should begin until permitting issues are 

resolved since permits may affect the design of the project. Permits in the following areas may be 

required: 

• Air Quality • Wastewater 

• Building Permit • Condensate 

• Land use Permit • Water 

• Noise • Stack height 

See LMOP’s A Landfill Gas to Energy Project Development Handbook, Section 9 “Securing Project 

Permits and Approvals” for details (www.epa.gov/lmop/res/pdf/handbook.pdf). Contact LMOP for 

more information on permitting issues. 

5.7 SUCCESS STORIES 

Three examples of successful LFGE projects are presented below. Go to LMOP’s website for more 

success stories (www.epa.gov/lmop/res/index.htm#4). 

Operating Industries Inc.141 (OII) Superfund Site, Monterey Park, CA, Region 9 

OII is a Superfund site located in southern California. It was a 190-acre landfill that operated from 

1948 to 1984. It accepted 38 million cubic yards of MSW and 330 million gallons of liquid industrial 

waste. Methane production at this landfill is about 2,500 ft3

 per minute. A LFGE project was 

constructed in 2002 (Fig. 28). The construction of the project cost $1.05 million and utility 

Chapter 5: Landfill Gas-to-Energy 44 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

connection cost $105,000. It produces electricity from microturbines to save an estimated $400,000 

annually by providing 80 percent of electricity needs for the operations and maintenance of the site. 

For RPMs who are considering a LFGE project, OII project managers recommend briefing 

stakeholders early in the planning process, including local utilities, land use contacts, and federal, 

state and local environmental agencies. It is important to obtain a “power interconnection” 

application from the utility in the early stages of 

planning to sell power back to the grid. If using 

microturbines, ensure that the microturbine 

system can accept the LFG specific to your site. 

Research the microturbine vendor for experience 

and support for a LFGE project. An ideal 

situation would be to contract a turnkey system 

which provides a completely operational product 

upon delivery. It is also recommended to get a 

service contract for the microturbine system that 

includes details of the costs and time frame for 

implementation of the system. 

Figure 28 LFG flares at OII. Image courtesy Chern142 

Site Contacts: 

S.J. Chern 

RPM, EPA Region 9 

Phone: (415) 972-3268 

E-mail: chern.shiann-jang@epa.gov

Pankaj Arora 

RPM, EPA Region 9 

Phone: (415) 972-3040 

E-mail: arora.pankaj@epa.gov 

National Aeronautics and Space Administration (NASA)'s Goddard Space Flight Center 

(GSFC), Greenbelt, MD143 

GSFC in Maryland is the first federal facility in the country to implement a LFGE project. Two of the 

five boilers at GSFC were modified in 2003 to run on LFG, and can use natural gas or fuel oil as 

backup. The LFG is supplied from the nearby county-owned Sandy Hill Landfill and fuels boilers to 

make steam that heats 31 GSFC buildings. The project illustrates a successful public-private 

partnership between Prince George's County, MD., Waste Management, Toro Energy, NASA and 

LMOP in pursuing the economic and environmental benefits of landfill gas energy. LMOP worked 

with NASA to assess the technical and economic feasibility of using gas from the Sandy Hill Landfill 

to fuel boilers at GSFC. This LFGE project will reduce 160,000 metric tons of CO2 equivalents from 

being emitted over ten years. These emissions reductions are equivalent to taking 35,000 cars off 

the road per year or planting 47,000 acres of trees. NASA will save taxpayers more than $3.5 

million over the next decade in fuel costs. Landfill gas provides 95 percent of all of the center's 

Chapter 5: Landfill Gas-to-Energy 45 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

heating needs, with natural gas serving as the backup. Go to 

www.nasa.gov/centers/goddard/news/topstory/2003/0508landfill.html for details. 

BMW, Green, South Carolina144 

The BMW plant in Greer, South Carolina has a landfill cogeneration project. Landfill gas is 

transported through a 9.5-mile pipeline and provides 53 percent of the plant’s energy needs by 

generating electricity with the use of gas turbines and direct use in heating water. The landfill is 

expected to be able to provide LFG for at least 20 years. For more information, go to 

www.bmwusfactory.com//community/environment/gastoenergy.asp. 

Chapter 5: Landfill Gas-to-Energy 46 
 

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Chapter 6 Table of Contents 

6.1 Anaerobic Digester Terminology 

6.2 Anaerobic Digester Technology Basics 

6.2 Basic Digester Components, Types of 

Digesters and Assessing Anaerobic 

Digester Potential 

6.3 Anaerobic Digester Energy Production 

6.5 Capital Cost, O&M, Developers and 

Possible Business Models 

6.6 Environmental Benefits and Concerns, 

Safety and Permits 

6.7 Success Stories 

CHAPTER 6: ANAEROBIC DIGESTION 

Anaerobic digestion is the natural process of 

decomposing organic materials by bacteria in an 

oxygen-free environment. Anaerobic digestion 

produces biogas, which is mainly CO2 and CH4. It 

can be used to produce heat and/or electricity. 

Anaerobic digestion can be manipulated in a 

controlled environment, such as inside an anaerobic 

digester, where biogas can be collected and 

utilized.145 Digesters may be designed as plastic or 

rubber covered lagoons, troughs, or as steel or 

concrete tanks.146 Organic material such as manure, 

wastewater treatment sewage sludge, agricultural 

wastes or food processing wastes are appropriate 

feedstock for anaerobic digesters. Regular 

maintenance is required to restock biomass as well as dispose of digester byproducts, which may be 

used as fertilizers. Cleanup sites that have biomass sources nearby may consider using an 

anaerobic digester to generate electricity and gas. 

6.1 ANAEROBIC DIGESTER TERMINOLOGY147 

The following are some anaerobic digester terms and definitions. 

Anaerobic Absence of oxygen. 

Anaerobic Digester Sealed container in which anaerobic bacteria break down organic matter and 

create biogas. 

Biogas The gas produced from decomposition of organic matter in anaerobic conditions consisting 

of 60-80 percent CH4, 30-40 percent CO2, and other trace gases such as hydrogen sulfide, 

ammonia and H2. 

Effluent Organic liquid and solid material leaving a digester. 

Hydraulic Retention Time (HRT) The average length of time the influent remains in the digester for 

decomposition. 

Influent, or Feedstock Liquid and solid material fed to the digester. 

Methane (CH4) A combustible gas produced by anaerobic digestion and also the principle 

component of natural gas. 

Mesophilic Range Temperature range between 95°F and 105°F in which certain methane-producing 

microbes thrive. 

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Thermophilic Range Temperature range between 125°F and 135°F where certain methaneproducing bacteria are most active. In digesters, the greatest pathogen destruction occurs in this 

temperature range. 

Slurry The mixture of biomass and water processed in the digester. 

6.2 ANAEROBIC DIGESTER TECHNOLOGY BASICS 

Anaerobic digestion is the 

natural process of 

decomposing organic 

materials by bacteria in an 

oxygen-free environment. 

One of the products of 

anaerobic digestion is biogas, 

which consists of 60-80 

percent CH4, 30-40 percent 

CO2, and trace amounts of 

other gases. It typically has 

an energy value of about 

600-800 BTU/ft3

.

149 This 

natural process can be 

manipulated in a controlled environment, such as in an anaerobic digester, where the biogas can be 

collected and used for heating and/or electricity production (Fig. 29).150 

Organic material such as manure, wastewater treatment sewage sludge, agricultural wastes or food 

processing wastes are used in anaerobic digesters to produce biogas. Cleanup sites that have 

these sources nearby may consider using an anaerobic digester to generate electricity. Digesters 

are designed as plastic or rubber covered lagoons, troughs, or as steel or concrete tanks.151 

Carefully controlled nutrient feed, moisture, temperature, and pH in the digester make a habitable 

environment for the anaerobic bacteria, which are naturally occurring in manure (Fig. 30). 

Digesters work best with biomass that is greater than 85 percent moisture by mass. Digesters 

operate at two ideal temperature ranges: mesophilic temperatures (95 ̊F-105 ̊F) which best host 

mesophile bacteria, and thermophilic temperatures (125 ̊F-135 ̊F) which best host thermophile 

bacteria.152 See Appendix VI (page 145) for more information on digester biology. Thermophilic 

conditions decrease the hydraulic retention time, reducing the size of the digester needed compared 

to digesters operating under mesophilic temperatures.153 However, thermophilic bacteria are also 

much more sensitive to changes in their environment, so digester conditions must be closely 

monitored and maintained. Digesters operating at thermophilic temperatures also need more energy 

to heat them. Excess heat from operating the electricity generators or direct combustion of the 

produced biogas may be able to provide enough thermal output to heat the digester. There is little 

change in the volume of the organic matter after it goes through the digester. The digested solids 

and liquids can be used as high-quality fertilizer (See Appendix VI page 146). The effluent can be 

spread on fields as a liquid fertilizer or liquids and solids can be separated to be sold individually. 

Figure 29 Plug-flow digester. Image courtesy Penn State University148 

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The fiber in digested dairy manure can be used on farms as bedding or recovered for sale as a highquality potting soil ingredient or mulch. Because anaerobic digestion reduces ammonia losses, 

digested manure contain more valuable nitrogen for crop production. The nutrient content of 

digested manure is the same as in raw manure. Some liquid content can be re-fed into the digester 

in the case that the moisture content needs to be increased. 

Benefits of an anaerobic 

digester include: 

• Green energy

production. 

• In the case of manure 

digesters, reduced 

odor compared to 

conventionally stored 

liquid manure, 

reducing potential 

nuisance complaints. 

• Digested material can 

be pumped long 

Figure 30 Bacterial processes within an anaerobic digester. 

Image courtesy Penn State University154 

distances for use as fertilizer. 

• Reduction of pathogens and weed seeds in digested material. 

• Reduced fly propagation. 

• Use of digested material as fertilizer, potting soil, or mulch. 

6.3 BASIC DIGESTER COMPONENTS, TYPES OF DIGESTERS AND ASSESSING 

ANAEROBIC DIGESTER POTENTIAL 

There are many types of digesters but all share similar components. This section discusses the 

various components of a digester system and various anaerobic digester types. Information on 

assessing the potential of a digester project for a site is also provided. 

Basic Components of All Digesters155 

The following are descriptions of the components of an anaerobic digester biogas recovery system. 

The digester system components include (Fig. 31): 

Nutrient Source Organic material including animal manure, wastewater treatment sewage sludge, 

food waste, food processing wastes. It is possible to combine different sources of organic matter 

to feed into the digester. 

Chapter 6: Anaerobic Digester 49 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

 Figure 31 Components of an digester biogas recovery system. Image courtesy AgStar156 

Transport System Most digesters are constructed on-site near the nutrient source. The organic 

matter must be collected and fed into the digester. 

Pre-treatment Tank A pre-treatment tank is sometimes recommended. This tank is used to preheat 

the influent as well as settle out sand, grit, and other contaminants from the organic feedstock 

before transporting into the digester. 

Digester Choose a digester that suits your site-specific characteristics. 

Gas Handling System Biogas is collected and processed to remove moisture and contaminants to 

the degree necessary for end use. 

Electricity Generation System Reciprocating engines, boilers/steam engines, or microturbines and 

generators can produce electricity from the biogas. See Appendix V (pages 138-142). The 

waste heat can be captured and recycled to heat the digester. 

Flare or Heat Source Excess CH4 is flared. Methane can also be used directly for heating the 

digester or other processes. 

Effluent Storage Digested material is stored for later use. It can be spread on fields as a liquid 

fertilizer. Solids can also be separated for use as a solid fertilizer. 

Types of Digesters 

Choosing the most suitable digester depends on the moisture content of the influent and, in the case 

for covered lagoon, climate at the site. The digesters detailed below are conventional designs 

including complete-mix, plug-flow, and covered lagoon digesters. This section also includes 

information on where a digester project may be applicable. 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Complete-Mix Digester 

The complete-mix digester is a 

vertical concrete or steel circular 

container that can be installed 

above or below ground (Fig. 32). 

It can handle organic wastes 

with total solid concentration of 

3-10 percent, such as manure or 

food waste collected from a 

flush system. Complete-mix 

digesters can be operated at 

either the mesophilic or 

thermophilic temperature range 

with a HRT of 10-20 days. A 

mixer keeps the solids in 

suspension. For manure feedstock, cost estimates range from $200-$400 per 1,000 pounds of 

animal mass that contribute to the digester influent.158 

Plug-Flow Digester 

Figure 32 Schematic of a complete-mix digester. 

Image courtesy Ohio State University 157 

The basic plug-flow digester 

design is a rectangular trough, 

often built below ground level, 

with an impermeable, flexible 

cover (Fig. 29 page 48). Organic 

material is added to one end of 

the trough and decomposes as it 

moves through the digester. Each 

day a new "plug" of organic waste 

is added, pushing the feedstock 

down the trough (Fig. 33). Plugflow digesters are suitable for biomass with a solids concentration of 11-13 percent and have a HRT 

of about 20-30 days. Suspended heating pipes of hot water stir the slurry through convection. This 

type of digester has few moving parts and requires little maintenance. For manure feedstock, cost 

estimates range from $200-$400 per 1,000 pounds of animal mass that contribute to the digester 

influent.160 n

33 Schematic of a plug-flow digester. 

Image courtesy Ohio State University159 

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Covered Lagoon Digesters 

A covered lagoon digester is a 

lagoon fitted with a floating, 

impermeable cover that collects 

biogas as it is released from the 

organic wastes (Fig. 34). An 

anaerobic lagoon is best suited for 

liquid organic wastes with a total 

solid concentration of 0.5-3 percent. 

Covered lagoon digesters are 

generally not externally heated so 

they must be located in warmer 

climates for them to produce enough biogas for energy production. This type is the least expensive 

of the three mentioned here. For manure feedstocks, cost estimates range from $150-$400 per 

1,000 pounds of live animal mass that contribute to the digester influent.162 

Other digester designs include advanced integrated pond systems, up-flow solids reactors, fixed-film 

(Fig. 35), temperature-phased, and anaerobic filter reactors.163 

Siting Anaerobic Digesters 

A suitable location for anaerobic digester energy project should be close to an organic waste source. 

It may be possible to collect organic wastes from a community, such as local farms and food 

Figure 34 Covered lagoon digester. 

Image courtesy Ohio State University161 

processing facilities that have a need to dispose biomass. 

To consider a manure digester project for energy production, 

the manure influent supply should generally have at least 

300 head of dairy cows or steers, 2,000 swine in 

confinement, or 50,000 caged layers or broilers (types of 

fowl) from which manure is collected regularly.165 The 

influent source should be available year-round for a constant 

supply of biogas and energy production. Anaerobic 

digesters need material with high moisture content. The 

influent should be collected as a liquid, slurry, or semi-solid 

from a single point daily or every other day. Alternatively, 

water may be added after collection. Manure feedstock 

should have as little bedding materials as possible. It may 

be necessary to have at least one person who can manage 

the digester for daily and long-term maintenance. Consider 

uses for the digested material, both liquid and solid 

components, such as for fertilizers. See Appendix VI (page 

143) for a preliminary evaluation checklist for manure 

Figure 35 Fixed-film digester. Image 

courtesy University of Florida164 

feedstock. 

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6.4 ANAEROBIC DIGESTER ENERGY PRODUCTION 

Producing biogas is just one step to harnessing energy from organic wastes. Once the gas has 

been collected, engines or boilers coupled with generators are utilized to convert the energy 

contained in the biogas to heat and/or electricity to be used on the cleanup site. The term “prime 

mover” is often used to refer to heat engines which generate mechanical energy that can drive 

electricity generation equipment. See Appendix V (pages 138-142) for more details. 

Energy Generation Options 

Internal Combustion Engine / Reciprocating Engine An internal combustion engine is the most 

commonly used technology for utilizing biogas. Natural gas or propane engines can be modified 

to burn biogas. In general, a biogas-fueled engine generator is 18-25 percent efficient at 

converting energy in biogas to electricity.166 Optimize efficiency by using the co-generated heat 

energy for space heating, water heating, and/or heating the digester. When a reciprocating 

engine is used, the biogas must have condensate and particulates removed. 167 

Boiler / Steam Turbine A boiler can produce thermal energy from burning biogas. The heat is used 

in a steam turbine to generate electricity. This configuration is best suited for gas production that 

can generate 8-9 MW, which is very large for a digester project.168 At smaller scales, it is 

generally more expensive than other gas power conversion technologies. 

Combustion (Gas) Turbine Combustion turbines (CTs) are typically used in medium to large biogas 

projects rated from 3-4 MW. This technology is competitive in larger biogas electric generation 

projects because of significant economies of scale. The biogas must have most of the visible 

moisture and any particles removed and then must be compressed in order to be utilized in a 

gas turbine combustion chamber. 

Microturbines Microturbines range in power rating from 30-250 kW and can be combined with each 

other. They are better-suited for digester projects for which low CH4 concentrations or low flow 

rates prohibit the applicability of larger engines. Microturbines cost from $700 per kW to $1,100 

per kW of generation capacity. The addition of a heat recovery system, which captures the 

otherwise wasted heat, adds between $75 and $350 per kW.169 Microturbines require very clean 

biogas fuel, increasing the cost for biogas cleanup. 

Potential Energy Production 

The amount of energy a digester can produce depends upon the type of feedstock, type of digester, 

environment inside the digester, loading rate, and type of energy recovery technology. Table 4 

includes electricity production rates compiled by the California Energy Commission (CEC) which 

provides a general estimate of the energy production potential of different manure feedstocks. Other 

influent sources including cheese whey (about twice as much biogas production as manure), animal 

and vegetable fats and oils (about 20 times as much biogas production as manure), crop and green 

wastes, and food processing waste, yield even greater amounts of biogas. Different feedstocks can 

be combined to increase biogas production.170 If you are considering dairy manure as a feedstock 

for a digester, use the CEC Dairy Power Production Program’s worksheet for estimating energy 

production (Appendix VI page 144). The heat generated from the engine or turbine generator is also 

Chapter 6: Anaerobic Digester 53 
 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

a useful resource that can be harnessed instead of being released as waste heat. See Appendix V 

(page 138) for combined heat and power application information. 

Table 4 Energy Potential of Various Animal Manures171 

Anaerobic Digestion Feedstock Volatile Solids per animal per 

day (lbs/day) 

Energy Potential 

(kWh/animal/day) 

Dairy Cows 6.2 1.24 

Swine 1.64 0.328 

Layer Poultry 0.048 0.0096 

Broiler Poultry 0.034 0.0068 

Turkey 0.091 0.0182 

Sheep and Lamb 0.92 0.184 

6.5 CAPITAL COST, O&M, DEVELOPERS AND POSSIBLE BUSINESS MODELS 

This section includes information on estimating the capital cost for an anaerobic digester, associated 

operations and maintenance, resources to find digester developers and possible business models 

for an anaerobic digester project. 

Estimating Cost 

For a manure digester, the joint EPA, USDA, and DOE AgStar Program estimates the installed 

capital cost of a covered lagoon, complete mix, and plug flow digester to range between $200 and 

$450 per 1,000 pounds of animal mass that provide feedstock to the digester (Table 5). AgStar 

estimates a 3-7 year payback period when energy recovery is employed.172 Contact digester 

developers for cost estimates for other feedstocks. 

Table 5 Cost Estimates for Various Manure Management Options 

(per 1,000 pounds of animal mass that contribute feedstock)∗173 

Aerated lagoons with open storage ponds (for comparison)♣ $200-$450 

Covered lagoon digesters with open storage ponds $150-$400 

Heated digesters (e.g., complete mix and plug flow) with open storage tanks $200-$400 

Separate treatment lagoons and storage ponds (2-cell systems) $200-$400 

Combined treatment lagoons and storage ponds $200-$400 

Storage ponds and tanks $50-$500 

∗

 Cost estimates are from a 2002 publication. Cost ranges do not include annual operation and maintenance costs. ♣ Aerated lagoon energy requirements add an additional $35-50 per 1,000 live animal lbs/year. 

Download FarmWare from www.epa.gov/agstar/resources/handbook.html to get preliminary 

feasibility and economic analyses of manure digesters. 

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Operations and Maintenance 

Anaerobic digesters require daily maintenance checks and longer term maintenance. Daily 

maintenance includes checking proper digester and engine function (e.g., gas leaks in digester 

cover or piping, oil level in the engine, film buildup in the digester). Daily maintenance takes from 10 

minutes to one hour per day. Oil in the engine may need changing every few months. Digesters 

may need to be cleaned out after several years of operation. 

Finding a Developer 

The following links provide listings of anaerobic digester consultants, developers, and equipment 

suppliers. Select businesses based on their previous biogas project experience, successful project 

track record, and in-house resources such as engineering, financing, operations and experience with 

environmental permitting and community issues.174 

□ The AgSTAR Industry Directory: Listing of consultants, project developers, energy services, 

equipment manufacturers and distributors, and commodity organizations. 

www.epa.gov/agstar/tech/consultants.html 

□ The California Integrated Waste Management Board: Listing of anaerobic digester vendors. 

www.ciwmb.ca.gov/Organics/Conversion/Vendors 

□ Penn State Department of Agriculture and Biological Engineering: Listing of digester 

consultants, designers, and vendors. www.biogas.psu.edu/listdigandequip.html 

Partners and Possible Business Models 

Purchasing and operating an anaerobic digester may involve many different parties. Consider the 

following: 

• Appropriate level of involvement with the local utility if the digester is expected to produce a 

large excess amount of energy that can be net metered or sold to the utility. 

• The need for a formal agreement with feedstock provider(s). 

• Which party will own, operate and manage the digester. 

• County, community, union organization involvement. 

The following are possible business models that outline digester operations and maintenance roles: 

• Producer of organic matter owns and manages digester and electricity generation 

equipment. 

• Producer of organic matter owns and manages digester. Electricity generation equipment 

owned and operated by utility; the utility purchases the biogas from digester owner. 

• Producer of organic matter provides influent. Third party owns and operates digester and 

electricity generation equipment. 

Find a list potential clean energy investors at 

www.nrel.gov/technologytransfer/entrepreneurs/directory.html. 

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Estimating Digester Emissions Reductions with EPA’s 

Power Profiler 

www.epa.gov/cleanenergy/powerprofiler.htm 

Consider Gordondale Farms (Section 6.7) which has a 

digester fueled with manure from their 860 cows. Their 

digester system produces about one million kWh per year. 

Go to the Power Profiler and enter the required information. 

Under “Make a Difference,” select “My Emissions.” Enter 

83,000 kWh into the “Average Monthly Use” option. The 

Profiler estimates that about two million pounds of CO2 are

released from producing one million kWh of conventional 

electricity a year. This means that use of the digester gas 

prevents an estimated two million pounds of CO2 from 

being released into the atmosphere every year. 

6.6 ENVIRONMENTAL BENEFITS AND CONCERNS, SAFETY AND PERMITS 

This section includes information on the environmental benefits of a digester project, mainly 

emission reductions. It also highlights some environmental concerns and safety issues. Information 

on possible permit requirements is also included. 

Emissions Reductions175 

Use AgStar’s A Protocol for Quantifying 

and Reporting the Performance of 

Anaerobic Digestion Systems for Livestock 

Manures 

(www.epa.gov/agstar/pdf/protocol.pdf) to 

estimate GHG reductions from the use of a 

manure digester. Utilizing anaerobic 

digesters, rather than conventional manure 

management practices, can reduce CH4 

and nitrous oxide (N2O) emissions, two 

highly potent GHGs. CO2 emissions from 

livestock are not estimated because 

annual net CO2 emissions are assumed to 

be zero – the CO2 photosynthesized by plants is returned to the atmosphere as respired CO2. A 

portion of the carbon is emitted as CH4 and for this reason CH4 requires separate consideration.176 

Methane emission reductions should not be based on CH4 production from the digester. Methane 

generated from conventional manure practices often differ from the amount produced in an 

anaerobic digester. To estimate baseline emissions, calculate the CH4 emissions from a 

conventional manure management method, or the method that would have been in place if a 

digester was not installed. The methodology described in the EPA Climate Leaders “Draft Manure 

Offset Protocol” is found at 

www.epa.gov/stateply/documents/resources/ClimateLeaders_DraftManureOffsetProtocol.pdf. 

While CO2 emissions from manure management are usually not counted towards a carbon footprint 

as mentioned above, there is carbon savings if the biogas is used to produce electricity. Instead of 

using fossil fuel electricity, carbon is offset by using renewable biogas. 

FarmWare may be used to help estimate the emissions from anaerobic lagoons with secondary 

storage and combined storage and treatment lagoons 

(www.epa.gov/agstar/resources/handbook.html). 

Environmental and Safety Issues 

NOx emissions from combusting biogas may be of concern for a digester project. Naturally aspirated 

reciprocating internal combustion engines emit relatively high levels of NOx. Fuel injected lean-burn 

reciprocating internal combustion engines provide greater engine power output and lower NOx 

emissions compared to a naturally aspirated engine. Gas turbines emit even lower levels of NOx. 

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Sulfur oxides (SOx) may be produced from swine manure digesters and may necessitate the use of 

scrubbers. SOx emissions are generally not a concern for other types of influent. 

Since biogas is flammable and displaces breathable oxygen within the space it occupies, it is 

potentially dangerous and it is necessary to take safety precautions including, but not limited to, 

installing and monitoring gas detectors, eliminating ignition sources, posting warning signs and never 

entering an empty digester without extensive venting and a confined space entry permit in 

accordance with Occupational Safety and Health Administration regulations. Developers should 

train the owner to properly maintain and operate the system to ensure efficiency and safety. Go to 

http://www.biogas.psu.edu/Safety.html for more on digester safety. 

Permits 

It is essential to garner appropriate permits early in the digester design process as the design may 

need adjustment to comply with federal, state, and local rules. Anaerobic digester construction and 

operation may need permits in the following areas: 

• Land use • Wastewater 

• Confined Animal Facility Operation • Water 

Permit • Storm-water management 

• Noise • Air 

See AgStar Handbook, Chapter 8 “Permitting and Other Regulatory Issues” for more details 

(www.epa.gov/agstar/pdf/handbook/chapter8.pdf). 

6.7 SUCCESS STORIES 

Dairy Manure: Gordondale Farms, Nelsonville, WI177 

Gordondale Farms is a 3,200 acre dairy farm located in Nelsonville, Wisconsin with a milking herd of 

about 860 Holstein-Friesian cows. They use a two-stage modified plug-flow mesophilic digester with 

vertical gas mixing. The captured biogas is used to fuel a modified 150-kW engine generator set. 

While the farm owns the digester, the local utility, Alliant Energy, owns and operates the electricity 

generation equipment and owns the electricity generated. Alliant Energy pays Gordondale Farms at 

the rate of $0.015 per kWh delivered and all electricity used by Gordondale Farms is purchased from 

the utility at retail rates. Biogas production was estimated to be 93,501 ft3 per day with 860 cows. 

For each 1,000 ft3 of biogas utilized, about 30 kWh are generated. Liquid and solid residuals are 

separated. Liquids are used as fertilizer and the solid portion is used on-site and sold as bedding for 

dairy farms. Cost for design, materials, and construction was estimated to total $650,000 

(completed March 2002). The owners of this system partially constructed the digester themselves, 

reducing the capital cost. The installed cost of the engine-generator set was $198,000. The enginegenerator itself and interconnection fees totaled $160,000 while the remaining $38,000 was the cost 

of generator installation, including labor and materials. 

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Dairy Manure: California Dairy Power Production Program, various locations, CA 

The Dairy Power Production Program was funded by the CEC and contracted to the Western United 

Resource Development Corporation (WURD). The purpose of the Dairy Power Production Program 

was to encourage the development of biological-based anaerobic digestion and gasification 

electricity generation projects on California dairies. The overall goal of this effort was to develop 

commercially proven biogas electricity systems that can help California dairies offset the purchase of 

electricity, and may provide environmental benefits by potentially reducing air and ground water 

pollutants associated with storage and treatment of livestock wastes. Total funds allocated for this 

project was $9,640,000.178 All funds have been granted and future funding for this program is 

uncertain. The following is a summary of many of the projects that were completed through this 

program (Table 6). From the data below, a covered lagoon and generator set costs about $3,500 

per kW and plug-flow digesters and generator set costs an average of about $3,000 per kW of 

generating capacity. 

Table 6 California Dairy Power Production Program Digester Projects179 

Dairy Name Cows Type of System kW Total Cost 

Hilarides Dairy 6,000 heifers Covered Lagoon 250 $1,500,000 

Gallo Cattle 

Company 5081 Covered Lagoon 300 $1,289520 

Blakes Landing 

Dairy 237 Covered Lagoon 75 $135,800 

Castelanelli Bros. 

Dairy 1600 Covered Lagoon 160 $772,925 

Koetsier Dairy 1500 Plug Flow 260 $381,850 

Van Ommering 

Dairy 600 Plug Flow 130 $489,284 

Meadowbrook Dairy 1900 Plug Flow 160 $524,898 

CA Polytechnic 

State University 

Dairy 

175 Covered Lagoon 30 $75,000 

Lourenco Dairy 1258 Covered Lagoon 150 $229,557 

Inland Empire 

Utilities Agency 4700 Plug Flow 563 $1,546,350 

Eden-Vale Dairy 770 Plug Flow 150 $661,923 

See the CEC (www.energy.ca.gov/pier/renewable/biomass/anaerobic_digestion/projects.html) and 

WURD (www.wurdco.com/) websites for more information on the CA Dairy Power Production 

Program. 

Food Processing: Valley Fig Growers Biogas Project, Fresno, CA180 

Valley Fig Growers is a grower-owned marketing cooperative with 35 growers. They installed an 

anaerobic digester at their processing facilities in Fresno, California to help mitigate their wastewater 

Chapter 6: Anaerobic Digester 58 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

issues and to produce electricity. The digester and microturbine system began operations in May 

2005. 

The Fig Growers installed a covered lagoon and a 70-kW Ingersoll Rand microturbine. The lagoon 

is 26,500 ft2 (0.6 acres) with a 1.8 million gallon capacity. The retention time is 45 days with gas 

production of 2,000–2,500 ft3

 per hour. In 2002, the CEC Public Interest Energy Research (PIER) 

Program awarded the Valley Fig Growers $476,000. Biogas from the digested fig processing 

wastewater is used to generate electricity and heat. The Fig Growers use a total of 40,000 gallons 

of fresh water daily for processing, seven days a week. With high levels of organic matter in their 

wastewater, the Valley Fig Growers were charged $100,000 a year to discharge their wastewater 

into city sewers. 

Benefits 

The digester reduced biochemical oxygen demand and suspended solids by 70-80 percent. The 

estimated cost savings from this reduction is $115,000 per year. They save $90,000 each year from 

reduced wastewater discharge fees. Electricity produced from the digester saves the Fig Growers 

$25,000 each year in energy costs. 

Costs181 

The digester system cost a total of about $1.1 million. See the breakdown of the costs below. 

Digester 

Engineering and project management $478,000 

Earthwork $210,000 

Lagoon liner and cover $219,000 

Digester and aeration $229,000 

Gas collection, heating $270,000 

Microturbine 

70-kW microturbine $163,000 

Engineering and commissioning $13,000 

Freight and sales tax $8,000 

3-year maintenance contract $38,000 

Utility rebate ($70,000) 

Other Costs 

Road surface, fencing, landscaping $65,000 

Interest $65,000 

Total $1,676,000 

PIER grant and utility rebate ($546,000) 

Net total cost $1,142,000 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Permitting182 

• San Joaquin Valley Air Pollution Control District—permit to operate, emissions requirements 

• City of Fresno Building Permit—city inspectors may not be familiar with microturbines and 

may be unsure of the inspection process for microturbines 

• CA Regional Water Quality Control Board—submit groundwater monitoring network plan and 

waste discharge permit 

• CA State Water Resources Board—general permit to discharge storm water 

Valley Fig Recommendations183 

• Test biogas quality to ensure compatibility with engine/turbine. 

• Ensure that all correct O rings are used. 

• Ensure that gas line regulators are properly installed to prevent potential fires. 

• Negotiate equipment maintenance in the early stages of contracting. 

• For bacteria to start producing biogas quicker during early stages of digester use, find similar 

digester material from other digesters as seed material. 

• Contact local utilities early to resolve any interconnection issues and net metering rules. 

• Plan for alternative uses of excess biogas. 

• Investigate the underground characteristics of the planned digester site before construction. 

• Be warned that if the project receives a state grant of more than $1,000, prevailing wages 

must be paid, increasing construction costs. Be sure contractors are aware of these grants. 

• Utilize heat produced by the microturbine to heat the digester. 

• Look for simple solutions to minimize the complexity of operations and maintenance. Budget 

for automation only when needed. 

• Address water quality, air quality and other permitting issues early in design phase and 

negotiate annual fees ahead of time. 

• Find a project manager with experience in both construction and operation of anaerobic 

digesters. 

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Chapter 7 Table of Contents 

7.1 Gasifier Terminology 

7.2 Gasifier Technology Basics 

7.3 Gasifier System and Energy Generation 

7.4 Assessing Biomass Gasifier Project 

Potential 

7.5 Emissions Reductions, Capital Cost, 

Permits, Involved Parties and 

Partnerships 

7.6 Success Story 

CHAPTER 7: BIOMASS GASIFICATION 

Biomass such as manure, crop residue, and other 

agricultural wastes may be gasified to produce 

electricity. Instead of relying on biological 

processes as in anaerobic digestion, gasification is 

the process of heating material in a chamber at 

carefully controlled temperature, pressure, and 

moisture levels to produce high energy syngas. 

Syngas consists of CO and H2, which can be used 

to generate electricity. Cleanup sites that have 

access to biomass may consider gasification to 

provide power. Gasifier projects require high capital 

costs as well as regular maintenance to restock biomass and dispose byproducts. While biomass 

gasification is not strongly established, many companies are emerging to develop this technology. 

7.1 GASIFIER TERMINOLOGY185 

The following are some gasifier terms and definitions. 

Char A combustible residue of carbonaceous feedstock. 

Feedstock A raw material used in the manufacture of a 

product. In the case of gasification, biomass feedstock 

could include agricultural residues or manure. 

Gasification Conversion of low-value carboniferous 

feedstocks to higher-value gaseous fuels. 

Gasifier Main component of a gasification system, which 

converts a solid or liquid into a gas by means of heat and 

pressure in the presence of low levels of oxygen. 

Methane (CH4) The primary constituent of natural gas. 

Oxidation A chemical reaction in which oxygen is added to 

an element or compound. 

Slurry A liquid mixture of water and an insoluble solid, such 

Figure 36 Coaltec Energy USA’s smallscale gasifier. Image courtesy Coal 

Research Center184 

as coal. 

Syngas A gaseous fuel produced from gasification composed of CO and H2 gas. 

Town gas Coal-based syngas provided by municipalities for heating and lighting, primarily in the 

19th century. 

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Water - gas shift reaction An inorganic chemical reaction in which water and CO react to form CO2 

and H2 (water splitting). CO + Water (H2O) + catalyst + heat = CO2 + H2. 

7.2 GASIFIER TECHNOLOGY BASICS 

Gasifiers extract energy 

from biomass to generate 

electricity (Fig. 36). 

Although coal can be 

gasified to produce 

energy, only when 

biomass is used is it 

considered renewable 

energy. Gasification uses 

heat, pressure, and steam 

to convert carboniferous 

matter (i.e., biomass and 

coal) into synthesis gas 

(Fig. 37). Synthesis gas 

or “syngas” is composed 

primarily of CO and H2.

188 Figure 37 Gasification inputs and outputs. Adapted from image courtesy NETL186 

CO and H2 are colorless, 

odorless, and highly flammable gases 

that can be used to generate 

electricity. Gasification is not the 

same as combustion. Gasification 

utilizes only about one-third of the 

oxygen needed for efficient 

combustion. The syngas that is 

produced from gasification can be 

used to produce steam or to fuel gas 

turbines.189 Gasification can be 

applied to a wide variety of organic 

feedstocks including waste material 

from agriculture, forestry operations, 

food processing, and pulp and paper 

mills. (Fig. 38).190 Cleanup sites that 

have these sources nearby may 

consider using gasification to 

generate electricity. See Appendix 

VII (page 147) for more information 

on the gasification process. 

Figure 38 Gasifier fueled with poultry litter in West Virginia. Image 

courtesy Coaltec Energy USA187 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

While coal gasifier technology had been used in the early 1800’s to produce syngas for lighting and 

cooking, applications for biomass gasification for the purpose of full scale energy generation have 

not been fully established. Gasification is a complex technology and feasibility and applicability 

depend on many site-specific and feedstock variables. Some challenges with biomass gasification 

compared to coal gasification include its heterogeneous properties, low bulk density, and fibrous 

nature of herbaceous feedstock. These differences require specialized design and operation as 

compared to coal gasification. 191 

7.3 GASIFIER SYSTEM AND ENERGY GENERATION 

This section includes information on the components of a gasifier system and details electricity 

generation equipment that can utilize syngas. 

Gasifier System 

The following image depicts the different components of a gasifier system (Fig. 39): 

Figure 39 Biomass Combined Heat and Power Gasification Plant. Image courtesy “Gasification Guide”192 

Energy Generation193 

Different sources of feedstock have varied energy content. Lab tests are necessary to determine the 

potential energy content in a fuel. Discuss with your gasifier consultant the amount of energy a 

gasifier is expected to produce with the type and amount of biomass available at your site. 

Combustion (gas) turbines and steam turbine-generators can use syngas and waste heat to 

generate electricity (see Appendix V pages 139-142). To produce electricity, the syngas leaves the 

Chapter 7: Biomass Gasification 63 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

gasifier and first must be cleansed of impurities such as alkalis, ammonia, chlorides, sulfides and 

particulates with the use of scrubbers. The syngas is then ignited to drive a combustion turbine and 

create electrical power through the use of a generator. Waste heat from the turbine can be used to 

boil water and create steam to drive a steam turbine with its own generator set. This combined heat 

and power operation increases energy efficiency by 33 percent compared with using a combustion 

turbine alone (see Appendix V page 138). 

Alternatively, the CO and water in syngas may be converted to H2 and CO2 via a water-gas shift 

reaction. Hydrogen is a very clean burning fuel that can be used in fuel cells. Water may be added 

to the syngas prior to the water-gas shift reaction to increase the production of H2. The syngas may 

also be turned into a clean burning diesel-like fuel using the Fischer-Tropsch process (a catalyzed 

chemical reaction).194 Go to www.eere.energy.gov/afdc/pdfs/epa_fischer.pdf for an EPA factsheet 

on Fischer-Tropsch fuels. 

Gasifier 

850 ̊C 

~1/3 amount of air or O2 

needed for combustion 

Syngas 

Char & Ash Power Generation 

Biomass Air 

Figure 40 Small modular gasifier process (5 kW – 5 MW). Adapted from image courtesy EERE195 

7.4 ASSESSING BIOMASS GASIFIER PROJECT POTENTIAL 

Gasification can be done on a large utility scale or a smaller scale. Cleanup sites most likely can be 

powered with small scale gasification systems which are rated between 5 kW and 5 MW (Fig. 40).196 

If there is a large source of biomass in the surrounding area, you may consider a larger facility to 

supply electricity to remediation equipment and to the utility grid. See Appendix XII (page 176) for 

net metering programs available in Region 9 states. There should be a source of biomass nearby 

and transportation costs should be taken into consideration when planning a gasifier. 

After establishing that there is a potential source of biomass in the cleanup site area, you may need 

to consult the owner of the biomass resource for a potential partnership. You may then want to 

contact a biomass energy consultant for further assessment (see Section 10.9 page 119). Samples 

of biomass should be analyzed for energy, moisture, sulfur, and ash content to ensure compatibility 

with gasification. While each source of biomass may have different properties, there are a few 

databases that can provide a general sense of the composition of various types of biomass. See 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

NREL’s “Biomass Feedstock Composition and Property Database” 

(www1.eere.energy.gov/biomass/feedstock_databases.html). 

“Phyllis” (www.ecn.nl/phyllis/) is another database of energy content and composition of various 

feedstocks compiled by the Energy Research Center of the Netherlands that may provide general 

estimates. 

7.5 EMISSIONS REDUCTIONS, CAPITAL COST, PERMITS, INVOLVED PARTIES 

AND PARTNERSHIPS 

This section includes information on emissions and emissions reductions associated with gasifiers, 

estimating capital costs, potential permit needs, potential parties that are involved in a digester 

project, and resources to develop partnerships. 

Emissions Reductions197 

Gasification systems emit very low emissions of SO2, PM, and toxic compounds such as mercury, 

arsenic, selenium, and cadmium. The gasification process releases CO2 but for non-fossil fuel 

feedstock, the net emissions are considered to be zero because it came from recently living things 

including grasses, trees, and agricultural crops that are continually being renewed. In other words, if 

forest residue was used in a gasifier, the same amount of CO2 released from gasification should be 

taken up by new forest growth, assuming the biomass will be replanted. When syngas is then used 

to generate electricity, net emissions are negative since this offsets the emissions that otherwise 

would have been emitted from fossil fuel-powered utilities. Go to the EPA Power Profiler listed on 

page 112 to help determine emissions reductions from using syngas to generate electricity. 

Capital Cost 

According to the Bioenergy Feedstock Information Network, a large scale gasifier is estimated to 

cost about $1,000 per rated kW.198 A 2000 NREL “Small Modular Biopower Initiative” document 

estimated that 25 kW—5 MW gasifiers have capital costs between $1,600 and $3,000 per rated 

kW.199 At a per kWh basis, estimates range from 4.9-8.2 cents per kWh. 

Permits 

It is essential to garner appropriate permits early in the gasifier planning process as the design may 

need adjustment to comply with federal, state, and local rules. Gasifier construction and operation 

may need permits in the following areas: 

• Land use • Hazardous waste (ash) 

• Air • Water 

• Wastewater • Storm-water management 

Gasifier consultants should be able to help with permitting issues. 

Chapter 7: Biomass Gasification 65 
 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Involved Parties 

Many sectors may be involved in planning, designing, operating, and managing a gasification 

project. Involved parties may include: 

• Gasifier design companies • Permitting officers 

• Biomass suppliers • Local agriculture/farming association 

• Local utility or organization 

• US Department of Agriculture (USDA) • Investors 

Finding Gasifier Partners 

□ California Integrated Waste Management Board: List of gasifier vendors. 

www.ciwmb.ca.gov/organics/conversion/Vendors/ 

□ NREL: List of potential clean energy investors. 

www.nrel.gov/technologytransfer/entrepreneurs/directory.html 

7.6 SUCCESS STORY 

Mount Wachusett Community College, Gardner, Massachusetts200 

Mount Wachusett Community College partnered with Community Power Corporation, NREL, and 

USDA Forrest Service to install a $1.2 million 50-kW woody biomass gasifier. The gasifier is fed 1.5 

tons of wood chips per day and provides electricity to help power the school. Excess thermal energy 

is used for space heating and for cooling. 

For more information, go to www.mwcc.edu/renewable/BiomassGasificationatMWCC.htm and 

www.delaware-energy.com/Download/BIO-MASS-CONF/Rob%20Rizzo.pdf. 

Chapter 7: Biomass Gasification 66 
 

 

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Chapter 8 Table of Contents 

8.1 Importance of Reducing Diesel 

Emissions 

8.2 Approaches to Reduce Diesel Emissions 

8.3 Clean Diesel Sample Language and 

Relevant Laws and Regulations 

8.4 Success Stories 

CHAPTER 8: CLEANER DIESEL 

On cleanup and redevelopment sites, diesel 

engines are commonly used in soil removals and 

construction. Common construction equipment 

includes wheel loaders, skid steer loaders, wheel 

dozers, landfill compactors, excavators, backhoes, 

drill rigs, scrapers, and trucks. Diesel engines are 

highly durable and can last for about 30 years. 

While stringent diesel emissions rules are reducing 

emissions from newly manufactured engines, inuse older engines can continue to operate for 

many years. Diesel emissions, especially PM, are highly toxic, potentially exposing site workers and 

surrounding communities to increased health risks. Clean diesel technologies and alternative fuels 

can reduce harmful emissions from older, higher polluting engines. Clean diesel technologies 

include replacing, repowering, or retrofitting older engines with advanced emission control devices 

that significantly reduce harmful pollutants. The two most widely used retrofit technologies are 

diesel particulate filters (DPFs) and diesel oxidation catalysts (DOCs). Cleaner fuels like ultra-lowsulfur diesel (ULSD), and alternative fuels such as biodiesel, also reduce emissions. In addition, 

simple measures like idle reduction and engine maintenance can be practiced as fundamental 

components of reducing diesel pollution. 

8.1 IMPORTANCE OF REDUCING DIESEL EMISSIONS 

Reducing emissions 

from diesel engines is 

one of the most 

important air quality 

challenges facing the 

country. Diesel engines 

emit a complex mixture 

of air pollutants including 

both solid and gaseous 

materials that have 

serious human and 

environmental impacts 

(Table 7). EPA has 

deemed diesel exhaust as a “likely human carcinogen.”202 California has also classified over 40 

diesel exhaust pollutants as “toxic air contaminants.”203 Diesel activities occurring at cleanup sites 

may expose workers and surrounding communities to diesel pollution. The diesel pollutants that 

cause the most public health concerns are PM and NOx. 

Table 7 Human and Environmental Health Risks from Diesel Pollutants201 

Particulate Matter (PM) Nitrogen Oxides (NOx) 

• Irritation of airways 

• Coughing 

• Difficulty breathing 

• Aggravated asthma 

• Decreased lung function 

• Lung and heart disease 

• Acute and chronic bronchitis 

• Irregular heartbeat 

• Heart attacks 

• Acid Rain 

• Global warming 

• Water quality deterioration 

• Visibility impairments 

• Smog/precursor to ground-level 

ozone 

• Formation of toxic chemicals 

• Asthma in children 

• Increases lung susceptibility to 

toxins and microorganisms 

Chapter 8: Cleaner Diesel 67 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Diesel pollution is a serious public health problem facing our country. The following are a few 

statistics that show the nationwide impacts of diesel emissions. 

• In 2002, off-road diesel construction equipment emitted roughly 71,000 short tons of PM10. 

About 95 percent of it was PM 2.5.

204 

• PM causes about 15,000 premature deaths a year. This is comparable to the number of 

deaths from 2nd-hand smoke and traffic accidents in California.205 

• Diesel emissions result in approximately 6,000 children’s asthma-related emergency room 

visits every year.206 

• PM causes about 15,000 heart attacks per year.207 

• In 2002, off-road diesel construction vehicles emitted about 764,000 tons of NOx into our 

air.208 

• EPA estimates that every $1 invested in diesel emissions reductions generates up to $13 in 

health-related benefits.209 

For more information on EPA engine emissions standards, see the document Reducing Air Pollution 

from Non-Road Engines published in May 2003 by the EPA Office of Air and Radiation 

(www.epa.gov/OMS/cleaner-nonroad/f03011.pdf). 

Key Diesel Pollutants 

Particulate matter is the general term for a mixture of 

solid particles and liquid droplets found in the air.211 

Diesel engines emit particles smaller than 10 

micrometers (μm) (PM10) in diameter and nearly all 

are under 2.5 μm (PM2.5) (Fig. 41). Human exposure 

to PM2.5 is especially dangerous because these 

particles can penetrate deep into the lungs and cause 

serious problems including asthma, heart attacks, and 

even premature death.212 

Nitrogen oxides (NOx) is the term for a group of highly 

reactive gases that contain nitrogen and oxygen in 

varying amounts. NOx form when fuel is burned at 

high temperatures, such as in a diesel engine. NOx 

contribute to human health and environmental 

problems including asthma, smog, and acid rain (Table 7). 

CO and SOx pollutants are present in lower amounts in diesel exhaust compared to PM and NOx but 

may also pose a risk to human health. CO can cause fatigue in healthy people and chest pain in 

people with heart disease. Exposure to moderate concentrations may cause angina, impaired 

vision, and reduced brain function. Higher concentrations can cause headaches, dizziness, 

confusion, nausea, and even death. SOx can cause breathing problems for people with asthma. 

SOx can also aggravate heart disease and induce respiratory illness and is a major component of 

Figure 41 Size of diesel PM compared to a cross 

section of a human hair. Image courtesy EPA210 

Chapter 8: Cleaner Diesel 68 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

ambient PM. In addition, this pollutant is a major component in acid rain formation, which harms 

ecosystems and degrades buildings and statues. Hydrocarbons (HC) are a precursor to groundlevel ozone. 

Go to the American Lung Association of California’s website for more technical information on the 

health effects of diesel pollution (www.californialung.org/spotlight/cleanair03_research.html). 

8.2 APPROACHES TO REDUCE DIESEL EMISSIONS 

There are many technologies and practices that reduce diesel emissions. The following are some 

examples. More details on retrofits and cleaner fuels follow. See Section 10.10 (page 121) to 

calculate emissions and emissions reductions. 

Retrofit engines with EPA or California Air Resources Board (CARB) verified diesel emission control 

technologies. Alternatively, try to select contractors or rental companies that have retrofitted or 

newer engines. 

Maintain engines in accordance with engine manual (e.g., change air filters, check engine timing, 

fuel injectors and pumps) and keep engines well tuned. 

Refuel with biodiesel, other alternative fuels, or with cleaner fuels such as ULSD. See page 74. 

Modify Operations by reducing operating and idle time. A mid-sized off-road tractor may consume 

as much as one gallon of diesel fuel per hour of idling.213 Reducing just one hour of idling from a 

typical back hoe loader can avoid about 13 grams of PM emissions, 155 grams of NOx 

emissions, 65 grams of CO emissions, and 65 grams of CO2 emissions.214 For more details, go 

to www.epa.gov/otaq/smartway/idlingtechnologies.htm. 

Replace/Repower existing engines with new cleaner diesel engines, hybrid engines, or engines 

compatible with alternative fuels. 

See EPA’s March 2007 publication, Cleaner Diesels: Low Cost Ways to Reduce Emissions from 

Construction Equipment (www.epa.gov/sectors/pdf/emission_0307.pdf) for more information on 

methods of reducing diesel pollution. 

Diesel Engine Retrofits 

Engines can be retrofitted with many kinds of emissions control devices. This section describes the 

most widely used technologies (Table 8). See Appendix VIII (page 150) to see which verified retrofit 

technologies may be applicable for off-road equipment used at your site. 

Chapter 8: Cleaner Diesel 69 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Diesel Particulate Filters (DPFs) 

DPFs use ceramic filters to collect 

diesel PM from engine exhaust 

(Fig. 42, Fig. 43). Over time, PM 

builds up on the filters and they 

must be cleaned or 

“regenerated.”217 For some DPFs, 

high enough engine exhaust 

temperatures can clean the filters 

by oxidizing (breaking down) the 

PM into less harmful components 

of CO2 and water vapor.218 These 

DPFs are called passive DPFs. 

Active DPFs require more 

maintenance because they must 

be removed for regeneration. 

DPFs require ULSD since sulfur 

reduces the effectiveness of 

DPFs. 

Diesel Oxidation Catalysts 

(DOCs) 

DOCs have been installed in offroad engines for over 30 years to 

reduce PM emissions. DOCs 

usually consist of a stainless steel 

container that holds a 

honeycomb structure (Fig. 44, 

Fig. 45). The interior surfaces 

are coated with catalytic metals 

such as platinum or palladium. 

Chemical oxidation reactions 

convert exhaust gas pollutants 

into less harmful gases. While 

many older engines are not 

compatible with passive DPFs, 

DOCs are able to work with 

these higher polluting engines. 

Figure 42 Schematic of DPF. Image courtesy MECA215 

Figure 43 Dozer installed with DPF. Image courtesy EPA,216 

Figure 44 Schematic of DOC. Image courtesy MECA219 

Chapter 8: Cleaner Diesel 70 
Figure 45 Dozer with DOC retrofit. 

Image courtesy Schattanek220 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Selective Catalytic Reduction (SCR)221 

While DOCs and DPFs concentrate on 

reducing PM emissions, SCRs are best at 

reducing NOx emissions and reduce PM and 

HC as well. NOx are converted to molecular 

nitrogen and oxygen in the SCR. A stream 

of ammonia or urea added to the exhaust 

gases pass over an SCR catalyst and cause 

chemical reactions that reduce NOx 

emissions. SCRs greatly reduce odor 

caused by diesel engines and diesel smoke. 

SCR catalysts may also be combined with 

DOCs or DPFs for additional PM emissions 

reductions. 

Exhaust Gas Recirculation (EGR) 

Diesel engines may be equipped with EGR devices to lower NOx formation. Engine combustion 

chambers can reach temperatures greater than 2,500°F. At these temperatures, nitrogen and 

oxygen react to form NOX which contribute to smog. An EGR device recirculates exhaust into the air 

intake stream. These gases displace some of the normal intake, lowering the peak temperature of 

the combustion process by hundreds of degrees and reduce the amount of oxygen available to form 

NOx. 

222 However, EGR increases PM emissions and are not compatible with many verified DOCs 

and DPFs for off-road engines.223 

Chapter 8: Cleaner Diesel 71 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Table 8 Diesel Engine Retrofit Options 

Diesel Particulate Filter 

(DPF) 

Diesel Oxidation Catalyst 

(DOC) 

Selective Catalytic 

Reduction (SCR) 

Technology 

Description Wall-flow type filter installed in the 

exhaust system, much like a 

muffler, in which PM emissions are 

trapped. Active DPFs require 

regular maintenance to regenerate 

or burn off accumulated PM, when 

the engine is not in use. Passive 

DPFs regenerate during engine 

operation if exhaust temperature 

requirements are met. 

Canister-like device containing a 

honeycomb structure that is 

installed in the exhaust system. 

A catalyst oxidizes CO and HC 

as the exhaust flows through, 

which breaks them down into 

less harmful components. 

Device that injects urea, or 

some form of ammonia, into 

the exhaust stream and reacts 

over a catalyst to reduce NOx 

emissions. 

Cost per 

retrofit $7,000—$10,000224 $500—$2,000225 $12,000 with DOC 

$20,000 with DPF226 

Emissions 

Reductions PM reduced 60%-90%227 

HC reduced 60%-90%228 

CO reduced 60%-90%229 

PM reduced 40%-50%230 

SCR without DOC or DPF 

PM reduced 30%-50%231 

NOx reduced 75%-90% 

HC reduced 50%-90% 

Benefits Can be coupled with an exhaust 

gas recirculation system (page 

71) to further reduce NOx (up to 

40%) and PM (up to 85%) though 

may not be compatible with 

currently verified DPFs232 

Can also be coupled with a SCR to 

reduce NOx and PM 

Should not decrease fuel 

economy, shorten engine life, 

nor adversely affect drivability 

Less restrictive than DPF 

because DOCs are less 

affected by exhaust buildup in 

the filter 

Works well with older, higher 

emitting engines 

Use of ULSD increases 

efficiency 

Commonly used in stationary 

applications. 

Often used with a DOC or 

catalyzed DPF to achieve 

greater PM reductions 

Considerations Annual maintenance costs 

approximately $150-$310233 

Active DPFs require maintenance 

to keep filters clean. Passive 

DPFs oxidize PM via catalysts or 

high exhaust temperatures 

Off-road engines may require 

active DPFs 

Diesel equipment needs to meet 

minimum temperature 

requirements specific to 

individual filter technologies 

Slight fuel economy penalty from 

pressure buildup in the exhaust 

system, pressure and 

temperature monitors are 

necessary 

Requires ULSD 

1995 and older engines may 

overload passive filters but may 

be compatible with active 

regeneration systems 

May suffer thermal degradation 

when exposed to temperatures 

above 650 ̊C for prolonged 

periods of time but these are 

unlikely conditions during 

normal operation234 

Requires normal exhaust 

maintenance 

Requires periodic refilling of 

an ammonia or urea tank 

Requires low-sulfur diesel or 

ULSD 

Chapter 8: Cleaner Diesel 72 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Retrofitting a Fleet 

The following steps provide an approach to retrofitting a fleet. 

Step 1 

Inventory the fleet for each engine and determine the following: 

• Type of equipment (backhoe, generator, etc.) 

• Engine year, make, model, horsepower, displacement 

• Engine family name (See Appendix VIII page 152) 

• If a diesel emissions reduction device is already in place. New engines may have one 

installed. 

• Turbocharged or naturally aspirated 

• Mechanically or electrically controlled 

• If it employs exhaust gas recirculation (page 71) 

Step 2 

Visit the EPA (www.epa.gov/otaq/retrofit/verif-list.htm) and CARB 

(www.arb.ca.gov/diesel/verdev/vt/cvt.htm) verification websites to determine compatible retrofit 

devices. See Appendix VIII (page 150) for verified retrofit technologies for off-road mobile 

engines. 

Step 3 

Work with vendors to assess the compatibility of your diesel equipment with a retrofit. They may 

need additional information such as: location for mounting retrofit device (on the muffler or on the 

side of the vehicle), size of the exhaust system, and if any changes will be made to the exhaust 

system (sometimes the retrofit device does not replace the muffler). 

Step 4 

Typically, datalogging is required before installing a DPF to determine if the exhaust 

temperatures are sufficient for passive DPF systems. Passive filters require high exhaust 

temperatures to oxidize the soot that accumulates on the filter. Vendors will datalog temperature 

information for a few days on each engine to see if required temperature minimums are met. 

Datalogging may cost about $200-$300 for two to three days of monitoring. Active DPF systems 

do not require high exhaust temperatures but do require maintenance. 

Important Notes on Retrofitting 

• Equipment retrofitted with DPFs should always include a device to monitor the increased 

pressure buildup in the exhaust system. These devices, called back-pressure monitoring 

systems, may also be installed with DOCs. A warning light in the cab will notify the 

equipment operator if the pressure becomes too high and maintenance is necessary. 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

• Retrofits may take place on-site or at the dealership, depending on the contract with the 

dealer. 

• It is generally not recommended to remove a retrofit device from an engine for which it was 

designed and use it on another engine. Though this is possible if the engines are similar, it 

may not be in proper verified use, and may result in damage to the engine or retrofit device. 

• DPFs may take from 1.5 hours to a full day to install. DOCs usually take 1.5-4 hours to 

install. Installations cost from $170 to $500 for each engine for both DOCs and DPFs.235 

• SCRs require installation of a tank for ammonia (or other reagent), as well as the necessary 

catalyst and associated piping and controls. These retrofits can be much more involved 

compared to DPFs or DOCs. A dependable source of ammonia or urea supply is also 

required. 

Cleaner and Alternative Fuels 

Using cleaner and alternative fuels also helps to minimize diesel pollution. Most retrofit technologies 

require the use of low- or ultra-low-sulfur diesel. Many retrofits are also compatible with low blends 

of biodiesel. The following are commonly used cleaner and alternative fuels (Table 9). For 

information on where these fuels are available, go to www.eere.energy.gov/afdc/fuels/stations.html. 

Ultra-Low-Sulfur Diesel (ULSD) 

 EPA's Clean Air Highway Diesel rule, finalized in 2001, requires a 97 percent reduction in the sulfur 

content of highway diesel fuel, from 500 ppm in low-sulfur diesel (LSD), to 15 ppm in ULSD (Fig. 46). 

While on-road diesel vehicles are already required to fuel with ULSD, off-road equipment ULSD 

fueling requirements begin in 2010. Highway model year 2007 and later engines must use ULSD to 

function properly. California’s stricter rules already require ULSD in both off- and on-road 

engines.237 Use ULSD in both on-road and off-road equipment used in site cleanup and 

redevelopment activities to reduce PM emissions by about 13 percent compared to LSD.238 ULSD 

costs about 4-5 cents more per gallon to produce 

and distribute.239 Some diesel fuel may be 

colored red. The red dye is added to non-taxed 

off-road diesel to distinguish it from clear, or 

“white,” taxed on-road diesel.240 

Biodiesel 

Biodiesel is a renewable fuel made from 

agricultural products such as vegetable oils. 

While most biodiesel is made from soybean oil in 

the United States, biodiesel made with canola oil 

and sunflower oil are also available. Biodiesel 

can also be produced from recycled cooking oils 

and animal fats, which is less energy-intensive 

than biofuel made from virgin crops. Biodiesel is 

Figure 46 ULSD pump label. Image courtesy EPA236 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

not pure vegetable oil or animal fats. The oil must be refined through a process called esterification 

in which an industrial alcohol and a catalyst convert the oil into biodiesel.241 Use biodiesel that 

conforms to ASTM standards to ensure that it performs properly.* 

Biodiesel is often blended with conventional diesel in varying amounts. Biodiesel labeled “B20” is 

composed of 20 percent biodiesel and 80 percent conventional diesel and “B5” biodiesel is 5 percent 

biodiesel and 95 percent conventional diesel, etc. Biodiesel blends with ULSD will yield greater 

emission reductions. Most engines are compatible with biodiesel blends up to B20. Check with the 

manufacturer or rental company for recommendations and/or warranty issues. Biodiesel may 

release accumulated deposits from fuel tank walls and pipes, potentially causing clogs in the fuel 

filter. The fuel filter should be changed after the first tank of biodiesel. Some rubber fuel system 

components may also need to be replaced with biodiesel-compatible rubber, especially in older 

engines. 

Compared to petrodiesel, biodiesel reduces PM, GHGs, sulfates, and HC. Go to Section 10.10 

(page 121) to calculate your emissions reductions. Some DPFs may be compatible with biodiesel 

and may provide additional reductions compared with using ULSD.242 As a consideration, some 

studies have shown a slight increase in NOx while others show a slight decrease NOx emissions 

from using biodiesel compared with conventional diesel. Further investigation is planned to yield 

more conclusive results.243 Also, using B20 may result in a slight fuel economy loss of around one 

to two percent compared to fueling with petrodiesel.244 

Go to www.epa.gov/smartway/growandgo/documents/factsheet-biodiesel.htm for more information 

on benefits of biodiesel and how it is produced. 

Find biodiesel fueling stations at the National Biodiesel Board website 

(www.biodiesel.org/buyingbiodiesel/distributors/). 

Natural Gas 

Natural gas burns cleaner than gasoline or diesel but must be used in vehicles with speciallydesigned engines. It emits 90 percent less PM and CO compared to diesel. However, natural gas is 

mostly CH4, a GHG. Some studies show that there are no GHG reductions from using natural gas— 

the CO2 reductions are offset by escaping CH4.

245 It is important to ensure that there are no leaks in 

the tanks. Natural gas can be used in vehicles as compressed natural gas (CNG) or liquefied 

natural gas (LNG). CNG is natural gas pressurized to 3,600 pounds per square inch and LNG is 

natural gas condensed to its liquid state by cooling it to -260 ̊F.246 

A wide range of light-duty vehicles that run on CNG are available. While natural gas engines are not 

available for off-road heavy-duty equipment, there are natural gas options for hauling-trucks. Search 

*

 ASTM International is an international organization that develops standards for a wide variety of 

materials and products. Biodiesel should comply with ASTM D6751 standards. 

Chapter 8: Cleaner Diesel 75 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

for natural gas vehicles at the EERE Alternative Fuels and Advanced Vehicles Data Center website 

(www.eere.energy.gov/afdc/afv/afdc_vehicle_search.php). 

CNG is a cleaner burning fuel which reduces maintenance costs compared with conventional diesel 

engines.247 Note that CNG cylinders must be inspected every 36 months or 36,000 miles. Go to the 

Clean Vehicle Education Foundation website for more information on natural gas vehicles 

(www.cleanvehicle.org/technology/cylinder.shtml). 

Go to www.eere.energy.gov/afdc/fuels/natural_gas.html for more information on natural gas. 

Emulsified Diesel Fuel 

Emulsified diesel is a mixture of diesel fuel, water, and other additives which lowers combustion 

temperatures to reduce PM and NOx emissions.248 The water content in emulsified fuels is between 

5 and 30 percent. This fuel can be used in any diesel engine though some power and fuel economy 

losses may be expected. While emulsified diesel stays well mixed for a fairly long time, the water 

may settle out after a few months of dormancy. 249 

Find verified emulsified fuels at the following websites: 

□ EPA Verified Diesel Retrofit Technology www.epa.gov/otaq/retrofit/verif-list.htm 

□ CARB Verified Diesel Retrofit Technology www.arb.ca.gov/diesel/verdev/vt/cvt.htm 

Chapter 8: Cleaner Diesel 76 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Table 9 Cleaner and Alternative Fuels 

Ultra-Low-Sulfur 

Diesel Biodiesel Natural Gas Emulsified Fuel 

Fuel 

Description 

Ultra-low-sulfur 

diesel (ULSD) has 

less than 15 ppm 

sulfur content. Lowsulfur diesel (LSD) 

contains less than 

500 ppm sulfur 

content. 

Renewable fuel made 

from animal or 

vegetable fats. Can be 

blended with 

conventional diesel. 

Usually found in 2% 

(B2), 20% (B20), and 

100% (B100) blends. 

Gas consisting mainly 

of methane. In the 

forms of compressed 

natural gas and 

liquefied natural gas. 

Fuel that is mixed 

with water and 

additives to lower 

combustion 

temperatures which 

reduces NOx and PM. 

Refer to the CARB 

verified list for 

qualified emulsified 

fuels. 

Emissions 

Reductions 

(compared to 

low-sulfur 

diesel) 

PM 13%250 

NOx 3%251 

CO 6%252 

HC 13%253 

B20 

PM 10%254 

NOx* -2%255 

CO 10%256 

HC 21%257 

Sulfates 20%258 

CO2 15%259 

PM 90%260 

NOx 50%261 

CO 90%262 

HC 50 to 75%263 

CO2 25%264 

PM 16 to 58%265 

NOx 9 to 20%266 

CO 13%267 

HC -30 to -99%268 

Cost $0.04 -$0.05 more 

per gallon than 

low-sulfur 

diesel269 

As of July ‘07, B20 was 

the same price as 

conventional diesel270 

~15 to 40% less than 

gasoline per 

gallon271 

~$0.20 more per 

gallon than 

conventional 

diesel272 

Considerations Most verified retrofit 

technologies 

require the use of 

LSD or ULSD. In 

June 2006, 

CARB mandated 

the use of ULSD 

in both on- and 

off-road vehicles 

in California. 

Nationwide 

mandates for 

ULSD use in onroad engines 

came into effect 

in 2006 and 

mandates for 

LSD use in offroad vehicles 

came into effect 

in 2007. 

Biodiesel blends lower 

than B20 experience 

insignificant difference 

in torque, horsepower, 

and fuel economy 

compared to 

conventional diesel. 

Using higher biodiesel 

blends may require 

changing fuel filters 

and replacement of 

rubber compound fuel 

system components 

with compatible 

rubber. 

Use biodiesel that 

meets the ASTM 

D6751 standard. 

Monitor performance in 

cold weather 

operation and ensure 

proper additives are 

used to prevent 

gelling. 

Needs more frequent 

fueling. 

Natural gas vehicles 

cost about $3,500 

to $6,000 more than 

gasoline 

equivalents.273 

May affect 

horsepower in 

some applications. 

Can be used in any 

diesel engine. 

*NREL and EPA are conducting further evaluations to determine potential NOx increase. 

Chapter 8: Cleaner Diesel 77 
 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

8.3 CLEAN DIESEL SAMPLE LANGUAGE AND RELEVANT LAWS AND 

REGULATIONS274 

This section includes information on sample language used in contracts that may be useful when 

writing task orders. Some current state laws and regulations that address diesel emissions are also 

listed. 

Sample Cleaner Diesel Language 

Many areas of the country are placing clean diesel language in contracts, codes, laws, rules and 

other measures to reduce emissions from construction equipment and other diesel sources. Go to 

www.epa.gov/cleandiesel/construction/contract-lang.htm for examples of language that address air 

quality issues, particularly diesel emissions, from construction equipment and other diesel sources. 

Laws and Regulations 

The following are some state incentives and laws concerning alternative fuels and clean diesel 

practices. As of the writing of this document, no relevant laws were found for Hawaii, Nevada, or the 

Pacific Islands. Go to www.eere.energy.gov/afdc/laws/incen_laws.html for a more comprehensive 

list of state and local incentives and rules. 

Arizona 

□ Alternative Fuel and Alternative Fuel Vehicle (AFV) Tax Exemption: The Arizona Use-Tax does 

not apply to the following: natural gas or liquefied petroleum gas used in motor vehicles; AFVs if 

the AFV was manufactured as a diesel fuel vehicle and converted to operate on an alternative 

fuel; and equipment that is installed in a conventional diesel fuel motor vehicle to convert the 

vehicle to operate on an alternative fuel. 

□ Alternative Fuel Vehicle License Tax: The initial annual vehicle license tax on an AFV is lower 

than the license tax on conventional vehicles. The vehicle license tax on an AFV is $4 for every 

$100 in assessed value. The assessed value of the AFV is determined as follows: during the 

first year after initial registration, the value of the AFV is one percent of the manufacturer's base 

retail price (as compared to 60 percent for conventional vehicles); during each succeeding year, 

the value of the AFV is reduced by 15 percent. The minimum amount of the license tax is $5 per 

year for each motor vehicle subject to the tax. 

□ Alternative Fuel Vehicle Special License Plate: AFVs must display an AFV license plate. State 

or agency directors who conduct activities of a confidential nature and have a vehicle powered 

by an alternative fuel are exempt from the requirement of displaying an AFV special license 

plate. The Arizona Department of Transportation has the authority to issue regular plates to 

AFVs that are used by law enforcement and the federal government. 

□ Clean Fuel Diesel for Heavy-Duty Equipment: Any state agency that contracts for the use of onor off-road heavy-duty diesel equipment in Maricopa County, Pima County, and Pinal County 

must construct its Requests for Proposals in a manner that gives incentives to bidders that use: 

Chapter 8: Cleaner Diesel 78 
 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

equipment retrofitted with diesel retrofit kits; newer clean diesel technologies and fuels; or 

biodiesel or other cleaner petroleum diesel alternatives. 

□ Idle Reduction Requirement: Heavy-duty diesel vehicles operated in Maricopa County with a 

gross vehicle weight rating of more than 14,000 pounds must limit idling time to no more than 5 

minutes. Exemptions apply for emergency vehicles, certain traffic or weather conditions, certain 

driver accommodations, and idling necessary for refrigeration equipment. 

California 

□ Idle Reduction Requirement – Trucks: The new engine requirements call for 2008 and newer 

model year heavy duty diesel engines to be equipped with a non-programmable engine 

shutdown system that automatically shuts down the engine after 5 minutes of idling or optionally 

meets a 30 gram per hour NOx idling emission standard. The in-use truck rules require 

operators of sleeper berth-equipped trucks to manually shut down their engine when idling more 

than 5 minutes at any location within California beginning in 2008. The penalty for violating this 

measure is $100 per violation. 

□ In-Use Off-Road Diesel Vehicle Regulation: This regulation establishes fleet average emission 

rates for PM and NOx that decline over time. Each year, the regulation requires each fleet to 

meet the fleet average emission rate targets for PM or apply the highest level verified diesel 

emission control system to 20 percent of its total horsepower. In addition, large and medium 

fleets are required each year to meet the fleet average emission rate targets for NOx or to “turn 

over” a certain percent of their horsepower. “Turn over” means repowering with a cleaner 

engine, retiring a vehicle, replacing a vehicle with a new or used piece, or designating a dirty 

vehicle as a low-use vehicle. If retrofits that reduce NOx emissions become available, they may 

be used in lieu of turnover as long as they achieve the same emission benefits. 

• Large fleet (>5,000 hp) first average compliance date: 2010 

• Medium fleet (2,501 hp – 5,000 hp) first average compliance date: 2013 

• Small fleet (≤2,500 hp) first average compliance date: 2015 

For more information on this regulation, go to www.arb.ca.gov/msprog/ordiesel/ordiesel.htm. 

8.4 SUCCESS STORIES 

AMCO Superfund Site, Oakland, CA, Region 9 

The AMCO Superfund site was owned and operated by AMCO Chemical as a chemical distribution 

facility from the 1960s to 1989. Removal of lead soil in residential neighborhoods occurred in the 

summer of 2007. The mini-excavator and skid-steer used on the site were fueled with a B10 

biodiesel blend. The biodiesel was picked up from a biodiesel distributor about 6 miles away from 

the site. The rental company allowed a maximum of 10 percent biodiesel blend fuel to be used in 

their equipment, although there are usually no technological barriers to using a higher blend. In 

total, this removal used 150 gallons of B10. No issues were encountered with the use of B10 in the 

equipment used at the AMCO removal. The use of biodiesel avoided 45 grams of PM emissions. 

Chapter 8: Cleaner Diesel 79 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Site Contact: 

Harry L. Allen 

OSC, EPA Region 9 

Phone: (415) 972-3063 

E-mail: allen.harryl@epa.gov 

Camp Pendleton Marine Corps Base, Superfund Site, about 40 miles north of San Diego, CA, 

Region 9 

Camp Pendleton Marine Corps Base has nine areas of soil and groundwater contamination due to 

past disposal practices. From late 2007 to early 2008, 120,000 ft3

 of soil were excavated and 

removed. Camp Pendleton made efforts to use newer engines, biodiesel, and to retrofit engines 

with DPFs for the excavation. Two pieces of equipment had the latest (Tier 3†

) technology and were 

retrofitted with DPFs. Four pieces of equipment had the latest (Tier 3) technology and were fueled 

with B20. Two pieces of equipment were fueled with B5. The retrofits and DPFs reduced PM 

emissions by 27 percent. Compared to Tier 1 engines, Tier 3 engines emit 63 percent less PM. 

Site Contact: 

Martin Hausladen 

RPM, EPA Region 9 

Phone: (415) 972-3007 

E-mail: hausladen.martin@epa.gov 

†

 Tiers are levels of federal emissions standards that vary depending on vehicle type, size, and year of 

manufacture. Higher tiers are stricter than lower tiers. For more information, go to 

www.dieselnet.com/standards/. 

Chapter 8: Cleaner Diesel 80 
 

 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Chapter 9 Table of Contents 

9.1 Resources for Finding Funding 

Opportunities and Funding Opportunities 

Chart 

9.2 National Funding 

9.3 Arizona Funding 

9.4 California Funding 

9.5 Hawaii Funding 

9.6 Nevada Funding 

CHAPTER 9: FUNDING RESOURCES AND OPPORTUNITIES 

This chapter includes resources that provide 

information on funding opportunities for energy 

efficiency, renewable energy technologies, and 

diesel emissions reductions efforts. Details are 

provided for some national, regional, and state-wide 

incentives that are applicable in Region 9 (local 

incentives are not included). See Table 10 for a 

chart that summarizes these opportunities. This 

chart provides a quick overview on the type of 

funding and technology, sector, and geographic 

applicability. Details such as funding amounts, 

requirements, and contact information on the funding 

opportunities listed are included following the chart. 

9.1 RESOURCES FOR FINDING FUNDING OPPORTUNITIES AND FUNDING 

OPPORTUNITIES CHART 

Below is a list of resources for finding funding opportunities for energy efficiency, renewable energy, 

and diesel emissions reduction efforts. Check these resources for national, regional, state, county, 

and local funding opportunities. See Table 10 for a chart summarizing some national, regional, and 

state-wide incentives found through these resources. 

• Clean Diesel Technology Forum: Funding resources for diesel emissions reductions efforts. 

www.dieselforum.org/retrofit-tool-kit-homepage/retrofit-grants/ 

• Database of State Incentives for Renewables and Efficiency by North Carolina State 

University: Includes national, regional, state and local funding opportunities. 

www.dsireusa.org 

• DOE E-Center Business and Financial Opportunities with Energy: Energy efficiency and 

renewable energy funding resources. http://e-center.doe.gov/ 

• EERE Federal Energy Management Program (FEMP): Incentives database for energy 

efficiency improvements. 

www1.eere.energy.gov/femp/program/utility/utilityman_energymanage.html 

• Emission Reduction Incentives for Off-Road Diesel Equipment Used in the Port and 

Construction Sectors: Report of diesel emissions reduction funding opportunities prepared 

for EPA by ICF Consulting published in May 2005. 

www.epa.gov/sectors/pdf/emission_20050519.pdf 

• Federal grants: Search for energy efficiency, renewable energy, and cleaner diesel federal 

grants. http://grants.gov 

Chapter 9: Funding Resources and Opportunities 81 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

• Funding On-Farm Biogas Recovery Systems: A Guide to Federal and State Resources: 

Funding opportunities for anaerobic digesters published by the AgStar Program. 

www.epa.gov/agstar/pdf/ag_fund_doc.pdf 

• Funding Opportunities: A Directory of Energy Efficiency, Renewable Energy and 

Environmental Assistance Programs: Document by the EPA State and Local Capacity 

Building Branch published September 2006. 

www.dep.state.pa.us/dep/deputate/pollprev/PDF/FundingOpportunities.pdf 

• LMOP Funding Guide: Funding opportunities for landfill gas-to-energy projects. 

www.epa.gov/lmop/res/guide/index.htm 

• NREL Solicitations and Request for Proposals: Renewable energy funding opportunities. 

www.nrel.gov/business_opportunities/solicitations_rfps.html 

• Tax Incentives Assistance Project: Service provided by a coalition of public interest nonprofit 

groups, government agencies, and other organizations in the energy efficiency field for 

information on energy efficiency and renewable energy tax incentives. 

www.energytaxincentives.org/ 

• West Coast Diesel Collaborative: List of funding opportunities for diesel emissions 

reductions efforts. www.westcoastcollaborative.org/grants and 

http://westcoastcollaborative.org/fed-funding.htm 

Chapter 9: Funding Resources and Opportunities 82 
CLEA

DIESEL EMISSIONS & 

Table 10 Summary of National, Regional, and State Funding Opportunities for Cleaner Energy and Diesel 

Funding Program Applicability Type of Funding Applicable Sector 

Energy

Efficiency 

Solar

Wind

Air Pollution Control Program Support EPA p. 88 National Grant 

State, tribal, municipal, intermunicipal, and interstate agencies 

Biodiesel Tax Credit IRS p. 88 National Tax Credit Biodiesel producers Clean Renewable Energy Bonds (CREBs) IRS p. 88 National 

"Interest-Free" Loan 

Governmental bodies and mutual or cooperative electric companies x x 

Congestion Mitigation Air Quality (CMAQ) Improvement Program U.S. Department of Transportation (DOT) p.88 National Various 

State DOTs, metropolitan planning organizations, and transit agencies 

Conservation Innovation Grants (CIG) USDA Natural Resources Conservation Service p. 89 National Grant 

Non-federal governmental and non-governmental organizations, tribes, and individuals 

Consolidated Research/Training Grants EPA Office of Research and Development p. 89 National Grant 

State, territory and possession of the U.S., District of Columbia, universities and colleges, hospitals, laboratories, local government, tribes, and nonprofit institutions 

Environmental Quality Incentives Program (EQIP) USDA Natural Resources Conservation Service p. 90 National Cost-Share Agricultural producers Farm Pilot Project Coordination (FPPC), Inc. p. 91 National Grant Agricultural producers 

Chapter 9: Funding Resources and Opportunities 
CLEA

DIESEL EMISSIONS & 

Funding Program Applicability Type of Funding Applicable Sector 

Energy

Efficiency 

Solar

Wind

Federal Tax Credit (Business Energy Tax Credit) IRS p. 91 National Tax Credit Commercial and residential x Modified Accelerated CostRecovery System (MACRS) IRS p. 92 National 

Depreciation Deduction Commercial and industrial x x 

National Clean Diesel Campaign (NCDC) EPA p. 92 National Various Various Pollution Prevention (P2) Grants Program EPA Office of Pollution Prevention and Toxics p. 93 National Grant 

States, the District of Columbia, any territory or possession of the U.S., any agency or instrumentality of a state including state colleges, universities, and indian tribes 

Public Interest Energy Research (PIER) Program California Energy Commission p. 93 National Various Commercial x x x Renewable Electricity Production Tax Credit (REPC) IRS p. 94 National Tax Credit Various x Renewable Energy Systems and Energy Efficiency Improvements Program U.S. Department of Agriculture (USDA) p. 95 National Various 

Agricultural producers or rural small businesses x x x 

Chapter 9: Funding Resources and Opportunities 
CLEA

DIESEL EMISSIONS & 

Funding Program Applicability Type of Funding Applicable Sector 

Energy

Efficiency 

Solar

Wind

Renewable Energy Production Incentive (REPI) IRS p. 96 National Payment Incentive 

Not-for-profit electrical cooperatives, public utilities, state governments, commonwealths, U.S. territories, tribal governments x x 

Renewable Energy Grants and Loans Programs USDA Rural Development p. 97 National Various 

Corporations, states, territories, and subdivisions and agencies thereof, municipalities, people's utility districts, and cooperative, nonprofit, limited-dividend or mutual associations that provide retail or power supply service needs in rural areas x x x 

Sustainable Agriculture Research and Education (SARE) Grants USDA Cooperative State Research, Education, and Extension Service p. 97 National Grant 

Researchers, agricultural educators, farmers and ranchers, and students 

West Coast Collaborative EPA p. 98 

CA, OR, WA, AL, AZ, ID, NV, HI, Canada, Mexico Grants 

Public institutions, non-profit organizations, universities, and tribes 

Commercial/Industrial Solar & Wind Tax Credit (Corporate) AZ Dept. of Commerce p. 98 AZ Tax Credit Businesses x x California Emerging Renewables Program (ERP) California Energy Commission p. 99 CA Rebate 

Customers of PG&E, SCE, SDG&E, or BVE x 

Chapter 9: Funding Resources and Opportunities 
CLEA

DIESEL EMISSIONS & 

Funding Program Applicability Type of Funding Applicable Sector 

Energy

Efficiency 

Solar

Wind

California Solar Initiative (CSI) California Public Utilities Commission p. 100 CA Payment Incentive 

Governmental bodies, nonprofits, residential, business x 

Carl Moyer Memorial Air Quality Standards Attainment Program CARB p. 103 CA Grant Any public or private entity Energy Efficiency and Renewable Generation Emerging Technologies, Agriculture and Food Industries Loan Program California Energy Commission p. 103 CA Loan 

Agricultural and food processing industries x 

Self Generation Incentive Program (SGIP) California Public Utilities Commission p. 104 CA Rebate 

Customer of PG&E, SCE, SDG&E, or SCGC x 

Hawaii Renewable Energy Tax Credits OR Capital Goods Excise Tax State of Hawaii, Department of Business, Economic Development and Tourism p. 106 HI Tax Credit Commercial and residential x x Renewable Energy Producers Property Tax Abatement Nevada Commission on Economic Development p. 107 NV Tax Abatement 

New or expanded commercial businesses x x 

Renewable Energy Systems Property Tax Exemption Nevada Department of Taxation p. 107 NV Tax Exemption Commercial and industrial x 

Chapter 9: Funding Resources and Opportunities 
CLEA

DIESEL EMISSIONS & 

Funding Program Applicability Type of Funding Applicable Sector 

Energy

Efficiency 

Solar

Wind

Solar Generations PV Rebate Program Sierra Pacific & Nevada Power Companies p. 108 NV Rebate 

Commercial, residential, schools, local government, state government, other public buildings x 

Chapter 9: Funding Resources and Opportunities 
 

CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

9.2 NATIONAL FUNDING 

□ Air Pollution Control Program Support, EPA 

This program assists state, tribal, municipal, intermunicipal, and interstate agencies in 

implementation of national primary and secondary air quality standards. It is also a resource that 

can assist in planning, developing, establishing, improving, and maintaining adequate programs 

for prevention and air pollution control. 

Go to the Catalog of Federal Domestic Assistance listing for details: 

http://12.46.245.173/pls/portal30/CATALOG.PROGRAM_TEXT_RPT.SHOW?p_arg_names=pro 

g_nbr&p_arg_values=66.001. 

William Houck 

National Air Grant Coordinator

Phone: (202) 564-1234 

E-mail: houck.william@epa.gov

□ Biodiesel Tax Credit, IRS 

In 2005, Congress granted federal tax credits for biodiesel producers. The tax credit is 50¢ per 

gallon of biodiesel (recycled cooking oil) and $1 per gallon for “agri-biodiesel” (virgin vegetable 

oil). Biodiesel producers claim the credit by filling out IRS Form 8864 (www.irs.gov/pub/irspdf/f8864.pdf). 

Go to www.biodiesel.org/news/taxincentive/ for more information. 

□ Clean Renewable Energy Bonds (CREBs), IRS 

CREBs offer a source of funding for renewable energy projects by providing essentially an 

interest free loan for a renewable energy project. The IRS allocates bonds to qualified lending 

authorities. Governmental bodies and mutual or cooperative electric companies are eligible to 

apply for the bonds as a funding source for renewable energy projects. These bonds are 

designed to be “interest free” because the holder is given a tax credit for the interest. The Tax 

Relief and Health Care Act of 2006 extended issuance of CREBs until December 31, 2008. 

Check the IRS website for future extensions. 

For more details, go to www.irs.gov/irb/2007-14_IRB/ar17.html and 

www.elpc.org/energy/farm/crebs.php. 

For more information on CREBs, call the IRS Office of Associate Chief Counsel (Tax Exempt & 

Government Entities) at (202) 622-3980. 

□ Congestion Mitigation and Air Quality (CMAQ) Improvement Program, U.S. Department of 

Transportation (DOT) 

The CMAQ Improvement Program provides financial assistance to areas striving to attain federal 

air quality standards. State DOTs, metropolitan planning organizations (MPOs), and transit 

agencies can invest more than $1.6 billion annually until 2009 in projects that reduce criteria air 

Chapter 9: Funding Resources and Opportunities 88 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

pollutants regulated from transportation-related sources. Clean diesel retrofit projects are 

eligible for CMAQ consideration. 

CMAQ funds are available only to National Ambient Air Quality Standards non-attainment and 

maintenance areas . 

While $1.6 billion are available on a nationwide basis, areas should consult the CMAQ program 

and their state DOT and MPOs to determine how much CMAQ funding is available (funds are 

allocated to areas according to population and severity of non-attainment designation). 

Under the 2005 re-authorization of the CMAQ program, diesel engine retrofits were given high 

priority for CMAQ funding. 

For more information, go to www.fhwa.dot.gov/environment/cmaqpgs/. 

Michael Koontz 

CMAQ Coordinator 

Federal Highway Administration 

Phone: (202) 366-2076 

E-mail: michael.koontz@fhwa.dot.gov

□ Conservation Innovation Grants (CIG), USDA Natural Resources Conservation Service 

The CIG program is a voluntary program intended to stimulate the development and adoption of 

innovative conservation approaches and technologies while leveraging federal investment in 

environmental enhancement and protection, in conjunction with agricultural production. 

Biomass-to-energy projects may qualify. 

• Eligible applicants include: non-federal governmental or non-governmental 

organizations, Tribes, or individuals. 

• CIG usually has two competitions—National and State. 

• National categories for potential projects change year to year. FY 2007 offered a 

National Technology Category that included methane recovery as a subtopic. 

For details, go to www.nrcs.usda.gov/programs/cig/. 

For Region 9, only California (www.ca.nrcs.usda.gov/programs/cig/) and Hawaii 

(www.hi.nrcs.usda.gov/programs/cig/index.html) are participating. 

Tessa Chadwick 

US Department of Agriculture 

Phone: (202) 720-2335 

E-mail: tessa.chadwick@wdc.usda.gov

□ Consolidated Research/Training Grant, EPA ORD 

The Consolidated Research/Training Grant supports research and development to determine the 

environmental effects of air quality, drinking water, water quality, hazardous waste, toxic 

substances, and pesticides. It is available for each state, territory and possession, and tribal 

nation of the U.S., including the District of Columbia, for public and private state universities and 

colleges, hospitals, laboratories, state and local government departments, other public or private 

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nonprofit institutions, and in some cases, individuals who have demonstrated unusually high 

scientific ability. 

Go to the Catalog of Federal Domestic Assistance listing for details: 

http://12.46.245.173/pls/portal30/CATALOG.PROGRAM_TEXT_RPT.SHOW?p_arg_names=pro 

g_nbr&p_arg_values=66.511. 

Mark Thomas 

EPA HQ

Phone: (202) 564-4763 

E-mail: thomas.mark@epa.gov

□ Environmental Quality Incentives Program (EQIP), USDA Natural Resources Conservation 

Service 

EQIP is a voluntary program that provides assistance to farmers and ranchers who face threats 

to soil, water, air, and related natural resources on their land. EQIP was reauthorized in the 

Farm Security and Rural Investment Act of 2002 (Farm Bill). Persons who are engaged in 

livestock or agricultural production on eligible land may participate in the EQIP program. 

EQIP may cost-share up to 75 percent of the costs of certain conservation practices. Incentive 

payments may be provided for up to three years to encourage producers to carry out 

management practices they may not otherwise use without the incentive. However, limited 

resource producers and beginning farmers and ranchers may be eligible for cost-shares up to 90 

percent. Farmers and ranchers may elect to use a certified third-party provider for technical 

assistance. An individual or entity may not receive, directly or indirectly, cost-share or incentive 

payments that, in the aggregate, exceed $450,000 for all EQIP contracts entered during the term 

of the Farm Bill. 

Some EQIP Requirements: 

• Only land that has been irrigated for two of the last 5 years prior to application for 

assistance will be eligible for cost-share or incentive payments for irrigation related 

structural and land management practices. 

• Funding may be used towards improving land management practices, such as nutrient 

management, manure management, integrated pest management, irrigation water 

management, wildlife habitat enhancement, and developing comprehensive nutrient 

management plans. 

• Producers who are engaged in crop or livestock production on eligible land are eligible 

for the program. Eligible land includes cropland, rangeland, pasture, private nonindustrial forestland, and other farm or ranch lands, as determined by the Secretary of 

Agriculture. 

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For more information, go to www.nrcs.usda.gov/programs/eqip/. 

Arizona 

www.az.nrcs.usda.gov/programs/eqip Nevada 

Sherman Reed www.nv.nrcs.usda.gov/programs/eqip200 

Farm Bill Specialist 6.html 

Phone: (602) 280-8829 Peggy Hughes 

E-mail: sherman.reed@az.usda.gov Assistant State Conservationist, Programs 

(Phone: (775) 857-8500, ext 103 

California E-mail: peggy.hughes@nv.usda.gov 

www.ca.nrcs.usda.gov/programs/eqip/ 

Alan Forkey Rodney Dahl 

Program Manager Resource Conservationist, Programs 

Phone: (530) 792-5653 Phone: (775) 857-8500, ext. 146 

E-mail: alan.forkey@ca.usda.gov E-mail: Rod.Dahl@nv.usda.gov 

□ Farm Pilot Project Coordination, Inc. (FPPC) 

FPPC, a non-profit organization, was designated by Congress (Public Law 107-76) to assist in 

implementing innovative treatment technologies to address the growing waste issues associated 

with animal feeding operations (AFO). FPPC’s objective is to foster the conservation, 

development and wise use of land, water, and related resources, while providing AFOs with 

opportunities for profitable operation. Funding for approved pilot projects comes from monies 

appropriated by Congress and overseen by the Natural Resource Conservation Service, a 

division of the USDA. Requests for proposals are issued about twice a year. FPPC grants 

approximately $2-$3 million per RFP round. The main goal of this program is to encourage pilot 

projects that reduce nutrient content in waste streams generated from animal feeding operations. 

To apply and for more information, go to www.fppcinc.org. 

Farm Pilot Project Coordination, Inc. 

Phone: (800) 829-8212 

E-mail: info@fppcinc.org

Fax: (813) 222-3298 

□ Federal Investment Tax Credit (Business Energy Tax Credit), IRS 

The Federal Investment Tax Credit is a corporate tax credit for solar PV, solar water heat, solar 

space heat, solar thermal electric, solar thermal process heat, geothermal electric, fuel cells, 

solar hybrid lighting, direct use geothermal, and microturbines. 

• Solar: Businesses and residents are eligible for a tax credit of 30 percent of the capital 

costs of a solar PV system. For solar, there is no cap for commercial installations. 

Credit drops to 10 percent of the capital cost if the system is installed after January 1, 

2009. 

• Microturbine: Businesses and residents are eligible for a tax credit of 10 percent of the 

capital costs for microturbines. The maximum microturbine credit is $200 per kW of 

rated capacity. For microturbines, the credit expires January 1, 2009. 

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• Fuel cell: Businesses and residents are eligible for a tax credit of 30 percent of the 

capital costs of a fuel cell system. The credit for fuel cells is capped at $500 per 0.5 kW 

of capacity. For fuel cells, the credit expires January 1, 2009. 

• To apply, fill out IRS Form 3468 (www.irs.gov/pub/irs-pdf/f3468.pdf). 

For more information, go to 

http://dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=US02F&State=federal&curre 

ntpageid=1&ee=0&re=1 and http://www.seia.org/getpdf.php?iid=21. 

Information Specialist - IRS 

1111 Constitution Avenue, N.W. 

Washington, DC 20224 

Phone: (800) 829-1040 

www.irs.gov 

□ Modified Accelerated Cost Recovery System (MACRS), IRS 

Commercial and industrial sectors are eligible for recovering investments in certain property 

through depreciation deductions. 

Microturbine, fuel cell, solar PV, solar water heat, solar space heat, solar thermal electric, solar 

thermal process heat, solar hybrid lighting, wind, geothermal electric and direct use geothermal 

properties are eligible. 

• Solar power, wind power, fuel cell and microturbine property are eligible for five year 

accelerated depreciation. 

• Fill out IRS Form 4562 (www.irs.gov/pub/irs-pdf/f4562.pdf). 

For information on how to estimate accelerated depreciation, go to 

www.sdenergy.org/uploads/PV-Federal%20Tax%20Credits%20Summary%206-01­

04%20FINAL.pdf. 

For more information, go to 

www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=US06F&State=Federal&curre 

ntpageid=1. 

Information Specialist - IRS 

1111 Constitution Avenue, N.W. 

Washington, DC 20224 

Phone: (800) 829-1040 

www.irs.gov 

□ National Clean Diesel Campaign (NCDC), EPA 

The NCDC is an EPA program that works to reduce pollution resulting from existing diesel 

vehicles and equipment. Fleet owners are encouraged to install pollution-reducing devices on 

the vehicles and to use cleaner-burning diesel fuel. 

For a listing of potential funding resources, go to www.epa.gov/cleandiesel/grantfund.htm. 

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□ Pollution Prevention (P2) Grants Program, EPA Office of Pollution Prevention and Toxics 

The goal of the P2 Grants Program is to assist businesses and industries to better identify 

environmental strategies and solutions for reducing or eliminating waste at the source. Funds 

awarded through this grant program support businesses and industries to reduce the release of 

potentially harmful pollutants across all environmental media: air, water, and land. EPA is 

interested in supporting projects that reflect comprehensive and coordinated pollution prevention 

planning and implementation efforts within the state or tribe. 

Eligible applicants include the 50 States, the District of Columbia, the U.S. Virgin Islands, the 

Commonwealth of Puerto Rico, any territory of or possession of the U.S., any agency or 

instrumentality of a state including state colleges, universities, and Indian Tribes that meet the 

requirement for treatment in a manner similar to a state in 40 CFR 35.663 (Code of Federal 

Regulations) and intertribal consortia that meet the requirements in 40 CFR 35.504. Local 

governments, private universities, private nonprofit organizations, private businesses, and 

individuals are not eligible for funding. 

• Grant recipients must provide at least a 50 percent match of the total allowable project 

cost by the time of award to be considered eligible to receive funding. 

• For purposes of this grant announcement, pollution prevention/source reduction is 

defined as any practice which: 

• Reduces the amount of any hazardous substance, pollutant, or contaminant entering 

any waste stream or otherwise released into the environment (including fugitive 

emissions) prior to recycling, treatment or disposal; 

• Reduces the hazards to public health and the environment associated with the 

release of such substances, pollutants, or contaminants; and 

• Reduces or eliminates the creation of pollutants through increased efficiency in the 

use of raw materials, energy, water, or other resources; or protection of natural 

resources by conservation. 

• $4.5 million in total program funding were available for FY 2007. 

• P2 Grants is an annual program. Go to the link below to check for RFPs. 

For more information, go to www.epa.gov/oppt/p2home/pubs/grants/ppis/ppis.htm. 

EPA, Region 9 

Eileen Sheehan 

Pollution Prevention Coordinator 

Waste Division 

75 Hawthorne St. 

San Francisco, CA 94105 

Phone: (415) 972-3287 

E-mail: sheehan.eileen@epa.gov

□ Public Interest Energy Research (PIER) Program, California Energy Commission (CEC) 

The PIER Program supports energy research, development and demonstration (RD&D) projects 

that will help improve the quality of life in California by bringing environmentally safe, affordable 

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and reliable energy services and products to the marketplace. Applicants need not be a 

California business. 

The PIER Program annually awards up to $62 million to conduct public interest energy research 

by partnering with RD&D organizations including individuals, businesses, utilities, and public or 

private research institutions. 

PIER funding efforts are focused on the following RD&D program areas: 

• Renewable Energy Technologies 

• Energy Innovations Small Grant Program 

• Energy-Related Environmental Research 

• Energy Systems Integration 

• Buildings End-Use Energy Efficiency 

• Climate Change Program 

• Environmentally-Preferred Advanced Generation 

• Industrial/Agricultural/Water End-Use Energy Efficiency 

• Natural Gas Research 

• Transportation Research 

For more information, go to www.energy.ca.gov/pier. 

For current solicitations, go to www.energy.ca.gov/contracts/pier.html. 

Martha Krebs 

Deputy Director 

PIER Program 

Phone: (916) 654-4878 

E-mail: mkrebs@energy.state.ca.us

□ Renewable Electricity Production Tax Credit (REPC), IRS 

This incentive applies to biomass, landfill gas, wind power, hydroelectric, geothermal electric, 

municipal solid waste, refined coal, and indian coal. First enacted under the Energy Policy Act of 

1992, it has subsequently been renewed, most recently by the Tax Relief and Health Care act of 

2006 which extends it to December 31, 2008. Commercial and industrial entities may apply for 

this tax credit. 

• Indexed for inflation, wind power currently receives 1.9¢ per kWh produced. 

• Indexed for inflation, landfill gas currently receives 1.0¢ per kWh produced for the first 

10 years of operation. 

• Indexed for inflation, “open-loop biomass” currently receives 1.0¢ per kWh produced for 

the first 10 years of operation. 

• “Open-loop biomass” is residual biomass that otherwise may be considered “waste” 

materials, e.g., livestock manure, forestry residues. 

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• Indexed for inflation, “closed-loop biomass” currently receives 1.9¢ per kWh produced 

for the first 10 years of operation. 

• “Closed-loop biomass” is biomass that was produced specifically for fuel generation. 

• To apply for the credit, a business must complete Form 8835, "Renewable Electricity 

Production Credit" (www.irs.gov/pub/irs-pdf/f8835.pdf), and Form 3800, "General 

Business Credit" (www.irs.gov/pub/irs-pdf/f3800.pdf). 

For more information, go to 

http://dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=US13F&State=federal&curre 

ntpageid=1&ee=1&re=1. 

Information Specialist - IRS 

1111 Constitution Avenue, N.W. 

Washington, DC 20224 

Phone: (800) 829-1040 

www.irs.gov 

□ Renewable Energy Systems and Energy Efficiency Improvements Program, USDA 

The 2002 Farm Bill established the Renewable Energy Systems and Energy Efficiency 

Improvements Program under Title IX, Section 9006. This section directs the Secretary of 

Agriculture to make loans, loan guarantees, and grants to farmers, ranchers and rural small 

businesses to purchase renewable energy systems and make energy efficiency improvements. 

Congress provided nearly $23 million to fund the program in each fiscal year from 2003-2006. 

For FY 2007 there were approximately $11.4 million in funding for competitive grants and $176.5 

million in authority for guaranteed loans. Funds are expected to be available in the future. 

Applicants may qualify for a grant, a guaranteed loan, or a combination of both. 

• Eligible renewable energy projects include systems that generate energy from wind, 

solar, biomass, or geothermal source or that produce hydrogen derived from biomass 

or water using a renewable energy source. 

• Energy efficiency projects typically involve installing or upgrading equipment that 

results in a significant reduction in energy use from current operations. 

• Eligible applicants are agricultural producers and rural small businesses demonstrating 

financial need. 

• The renewable energy or energy efficiency project must be located in a rural area. 

• The project must be for a pre-commercial or commercially available and replicable 

technology. 

• Grant request must not exceed 25 percent of the eligible project costs. Renewable 

energy grants can range from $2,500 to $500,000. Energy efficiency grants can range 

from $1,500 to $250,000. 

• Loan guarantees can be for up to 50 percent of total eligible project costs. Guarantees 

can range from $5,000 to $10,000,000 per project. 

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• Eligible project costs include: Post-application purchase and installation of equipment, 

except agricultural tillage equipment and vehicles; Post-application construction or 

project improvements, except residential; Energy audits or assessments; Permit fees; 

Professional service fees, except for application preparation; Feasibility studies; 

Business plans; Retrofitting; and Construction of a new facility only when the facility is 

used for the same purpose, is approximately the same size, and based on the energy 

audit will provide more energy savings than improving an existing facility. Only costs 

identified in the energy audit for energy efficiency projects are allowed. 

For more information go to www.rurdev.usda.gov/rbs/farmbill/. 

To apply, contact your State Office Rural Energy Coordinators: 

Arizona Hawaii 

Alan Watt Tim O'Connell 

USDA RD USDA RD 

230 N. 1st. Avenue, Suite 206 Federal Building, Room 311 

Phoenix, AZ 85003-1706 154 Waianuenue Avenue

Phone: (602) 280-8769 Hilo, HI 96720 

E-mail: alan.watt@az.usda.gov Phone: (808) 933-8313 

E-mail: tim.oconnell@hi.usda.gov

California 

Charles M. Clendenin Nevada 

USDA RD Dan Johnson

430 G Street, # 4169 USDA RD 

Davis, CA 95616-4169 555 West Silver Street, Suite 101 

Phone: (530) 792-5825 Elko, NV 89801 

E-mail: chuck.clendenin@ca.usda.gov Phone: (775) 738-8468, ext. 112 

E-mail: dan.johnson@nv.usda.gov 

□ Renewable Energy Production Incentive (REPI), IRS 

The REPI provides payments for electricity produced and sold by new qualifying renewable 

energy generation facilities. This incentive applies to solar PV, wind, geothermal, biomass, 

landfill gas, livestock methane, ocean technologies, and fuel cells using renewable fuels. The 

REPI program was created by the Energy Policy Act of 1992 to provide financial incentives for 

renewable energy electricity produced and sold by qualified renewable energy generation 

facilities. 

Eligible electric production facilities that may be considered to receive REPI payments include 

not-for-profit electrical cooperatives, public utilities, state governments, commonwealths, 

territories of the United States, District of Columbia, Indian tribal governments, and political 

subdivision thereof, and native corporations that sell the facility's electricity. 

• Qualifying facilities are eligible for annual incentive payments of 1.5¢ per kWh 

produced and sold (1993 dollars and indexed for inflation) for the first 10-year period of 

their operation, subject to the availability of annual appropriations in each federal fiscal 

year of operation. 

• Applicants must meet qualified technology and facility location requirements. 

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To apply and for more information go to www.eere.energy.gov/repi/. 

Christine Carter Information Specialist - REPI 

DOE DOE 

1617 Cole Boulevard Weatherization and Intergovernmental 

Golden, Colorado 80401 Program 

Phone: (303) 275-4755 Washington, DC 

E-mail: christine.carter@go.doe.gov E-mail: repi@ee.doe.gov 

□ Renewable Energy Grants and Loans Programs, USDA Rural Development 

Under the authority of the Rural Electrification Act of 1936, USDA Electric Programs make direct 

loans and loan guarantees to electric utilities to serve customers in rural areas. 

• High Energy Cost Grants (CFDA 10.859): These grants are available for communities with 

average home energy costs exceeding 275 percent of the national average. Funds may be 

used for improving and providing energy generation, transmission and distribution facilities. 

Grant funds may be used for on-grid and off-grid renewable energy projects, energy 

efficiency and energy conservation projects serving eligible communities. For more details, 

go to www.usda.gov/rus/electric/hecgp/overview.htm. 

• Treasury Loans: These loans are available for distribution, subtransmission, and renewable 

generation facilities that provide retail or power supply service needs in rural areas. For 

more details, go to www.usda.gov/rus/electric/loans.htm. 

Karen Larsen 

Rural Development Electric Programs 

USDA 

1400 Independence Avenue, SW Stop 1560, Room 5165-South 

Washington, DC 20250-1560 

Phone: (202) 720-9545 

E-mail: energy.grants@wdc.usda.gov. 

Fax: (202) 690-0717 

□ Sustainable Agriculture Research and Education (SARE) Grants, USDA Cooperative State 

Research, Education, and Extension Service 

The SARE program is part of USDA's Cooperative State Research, Education, and Extension 

Service, first funded by Congress in 1988. SARE is a competitive grants program providing 

grants to researchers, agricultural educators, farmers and ranchers, and students in the United 

States. The SARE program is divided into four regions, with each region announcing its own 

calls for proposals. 

• Research and Education Grants: Ranging from $30,000 to $150,000 or more, these 

grants fund projects that usually involve scientists, producers, and others in an 

interdisciplinary approach. 

• Professional Development Grants: To spread the knowledge about sustainable 

concepts and practices, these projects educate Cooperative Extension Service staff 

and other agriculture professionals. 

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• Producer Grants: Producers apply for grants that typically run between $1,000 and 

$15,000 to conduct research, marketing and demonstration projects and to share 

results with other farmers and ranchers. 

For more information on the Western Region, go to http://wsare.usu.edu/. 

Western Region SARE 

Utah State University 

Phone: (435) 797-2257 

E-mail: wsare@mendel.usu.edu

□ West Coast Diesel Collaborative Grants, NCDC 

The National Clean Diesel Campaign provides monies for regional collaboratives to award as 

grants for projects that reduce diesel emissions from existing diesel engine operations. States, 

Federally Recognized Indian Tribes and Tribal Consortia, local governments, international 

organizations, public and private universities and colleges, hospitals, laboratories, and other 

public or private nonprofit institutions are eligible to apply. Applicable technologies, fuels, and 

practices include emissions control technologies, idling reduction strategies, cleaner burning 

fuels, and alternative and biofuels production, distribution, and use. All projects must 

demonstrate applications, technologies, methods or approaches that are new, innovative or 

experimental. 

Go to www.epa.gov/region09/funding/cleandiesel.html and www.epa.gov/diesel/grantfund.htm 

for more information. 

Wayne Elson 

West Coast Diesel Collaborative Construction Sector Lead 

EPA Region 10 

1200 Sixth Avenue 

Seattle, WA 98101 

Phone: (206) 553-1463 

E-mail: elson.wayne@epa.gov

9.3 ARIZONA FUNDING 

□ Commercial/Industrial Solar & Wind Tax Credit (Corporate) 

This tax credit was established by the Arizona legislature in 2006 to stimulate the production and 

use of solar energy in commercial and industrial applications by subsidizing the initial cost of 

solar energy devices. It is applicable towards solar PV, wind power, passive solar space heat, 

solar water heat, solar thermal electric, solar thermal process heat, solar cooling, solar pool 

heating, and daylighting. 

• Businesses are eligible for a tax credit equal to 10 percent of the installed cost of the 

PV or wind power system. 

• Tax credit applies to taxable years from January 1, 2006 through December 31, 2012. 

• The maximum credit per taxpayer is $25,000 for any one building in the same year and 

$50,000 in total credits in any year. 

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• To qualify for the tax credits, a business must submit an application to the Arizona 

Department of Commerce. The Department of Commerce may certify tax credits up to 

a total of $1 million each calendar year. 

For more information, go to: 

• Arizona Department of Commerce 

www.azcommerce.com/BusAsst/Incentives/Solar+Energy+Tax+Incentives+Program.htm 

• Commercial Solar Energy Tax Incentives Program Summary 

www.azcommerce.com/doclib/finance/solar%20program%20summary.pdf 

• Commercial Solar Energy Tax Credit Program: Program Guidelines 

www.azcommerce.com/doclib/finance/solar%20guidelines.pdf 

Arizona Department of Commerce Arizona Department of Revenue 

1700 W. Washington St., Suite 600 1600 W. Monroe 

Phoenix, AZ 85007 Phoenix, AZ 85007-2650

Phone: (602) 771-1100 Phone: (602) 255-2060 

www.azcommerce.com www.azdor.gov 

9.4 CALIFORNIA FUNDING 

□ California Emerging Renewables Program (ERP), California Energy Commission (CEC) 

The ERP provides incentives for wind turbines and fuel cells. The ERP is an element of the 

Renewable Energy Program pursuant to Senate Bill 10381, Senate Bill 1832, Senate Bill 12503, 

and Senate Bill 107.4. 

• Wind power: First 7.5 kW receives $2.50 per watt, then increments between 7.5-kW 

and 30-kW receives $1.50 per watt. Wind turbines must be rated 50 kW or less. 

• Fuel cell: $3.00 per kW. Incentive available for up to 30 kW. 

Requirements: 

• Must be customer of Pacific Gas and Electric (PG&E), Southern California Edison 

(SCE), San Diego Gas and Electric (SDG&E), or Southern California Water Company 

(Bear Valley Electric Service). 

• Must use new components that are approved by the California Energy Commission. 

Find a list of eligible equipment at 

www.consumerenergycenter.org/erprebate/equipment.html. 

• System must have a five-year warranty. 

• System must be sized to produce electricity primarily to offset part or all of the 

customer’s needs at the site of installation. The expected production of electricity by 

the system may not be more than the historical or expected electrical needs of the 

electricity consumer at the site of installation. 

• All systems must be installed with a performance meter. 

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For more information and to apply, go to 

www.consumerenergycenter.org/erprebate/program.html. 

See the Emerging Renewables Program Final Guidebook, Eighth Edition, December 2006, 

(www.energy.ca.gov/2006publications/CEC-300-2006-001/CEC-300-2006-001-ED8F.PDF) for 

more details. 

California Energy Commission 

Emerging Renewables Program 

1516 Ninth Street MS-45 

Sacramento, CA 95814 

Phone: (800) 555-7794 in CA or (916) 654-4058 outside CA 

E-mail: renewable@energy.state.ca.us

□ California Solar Initiative (CSI), California Public Utilities Commission 

The California Solar Initiative is made up of two components. The California Public Utilities 

Commission (CPUC) will provide over $2 billion in incentives over the next decade for existing 

residential homes and existing and new business, industrial, non-taxable (government and nonprofit) and agricultural properties. The CSI also includes an additional $350 million from the 

California Energy Commission (CEC) for the New Solar Homes Partnership. Find the California 

Solar Initiative Program Handbook at www.gosolarcalifornia.ca.gov/documents/index.html. 

The CSI includes two incentives types (customers can only participate in one): 

• Performance Based Incentive (PBI) 

For this incentive type, all customers that install systems greater than 100 kW CEC–AC∗

 will 

receive a monthly payment based on the actual energy produced, for a period of 5 years. 

Systems less than 100 kW CEC-AC may opt for PBI. PBI is required for Building Integrated 

PV (BIPV) Systems. Once the PBI incentive rate has been determined and a confirmed 

reservation issued, the incentive rate per kWh will remain constant for the 5-year term (Fig. 

47). Program Administrators will make monthly payments to applicants based on actual 

electricity generated in kWh per the monthly reading of the meter after commissioning of the 

system. 

• Expected Performance Base Buydown (EPBB) 

Under this incentive, all systems less than 100 kW will be paid a one-time, up-front incentive 

based on expected system performance, which considers factors such as equipment ratings, 

geographic location, tilt, and shading (Fig. 47). Residential and small projects can also 

choose to opt-in to the PBI payment approach. On January 1, 2008, PBI will apply to 

∗

 CEC-AC is California Energy Commission Rated AC output of the PV system that takes into 

consideration real-world conditions and inverter efficiency. 

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systems equal to or greater than 50 kW CEC-AC. Starting in 2010, all systems greater than 

30 kW will be under the PBI. 

Figure 47 PBI and EPBB incentive amounts by step. Step increases based on participation. Go 

to www.csi-trigger.com to see current step level. Image courtesy CPUC275 

Requirements to qualify for PBI or EPBB: 

• Must be customer of PG&E, SCE, or SDG&E. 

• System equipment and retailers must be certified by CEC. 

(www.consumerenergycenter.org/erprebate/equipment.html) 

• PV systems must be at least 1 kW to be eligible. The maximum limit for an eligible 

system is 5,000 kW though the incentive can only apply up to 1,000 kW. 

• System output (kW) are calculated using CEC-AC standards. See the CSI Program 

Handbook, Section 2.2.5 “System Size” for details 

(www.gosolarcalifornia.ca.gov/documents/CSI_HANDBOOK.PDF). EPBB applicants 

go to www.csi-epbb.com/ for the EPBB calculator. 

• All existing residential and commercial customers are required to have an energy 

efficiency audit conducted on their home or building. See Section 2.3 “EnergyEfficiency Requirements” of the CSI Handbook for details 

(www.gosolarcalifornia.ca.gov/documents/CSI_HANDBOOK.PDF). 

• All systems must have a minimum 10-year warranty provided both by the manufacturer 

and installer to protect the purchaser against defective workmanship, system or 

component breakdown, or degradation in electrical output of more than 15 percent from 

their originally rated electrical output during the ten-year period. The warranty must 

cover the solar generating system and provide for no-cost repair or replacement of the 

system or system components, including any associated labor during the warranty 

period. 

• Meters must have a one-year warranty to protect against defective workmanship, 

system or component breakdown, or degradation in electrical output of more than 15 

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percent from their originally rated electrical output during the warranty period. On or 

before January 1, 2008, the warranty requirements will be increased to a minimum of 5 

years for meters, unless the CEC establishes alternate requirements. 

• Equipment installed under the CSI program is intended to be in place for the duration of 

its useful life. Only permanently installed systems are eligible for incentives. 

• The Host Customer, or designate, must also submit an application and enter into an 

interconnection agreement with their local electric utility for connection to the electrical 

distribution grid. Proof of interconnection and parallel operation is required prior to 

receiving an incentive payment. 

• The CSI program requires accurate solar production meters for all projects that receive 

CSI program incentives. For systems with a system rating of less than 10 kW, a basic 

meter with accuracy of ± 5 percent is required. For systems with a system rating of 10 

kW and greater, an interval data meter with accuracy of ± 2 percent is required. 

When to apply for CSI incentives: 

• Select a solar installer 

• Determine that the cleanup site is eligible for CSI Incentives 

• Apply for and reserve your incentives 

PG&E customers visit: www.pge.com/csi

SCE customers visit: www.sce.com/rebatesandsavings/CaliforniaSolarInitiative/

SDG&E customers visit:

www.sdenergy.org/ContentPage.asp?ContentID=377&SectionID=406&SectionTarget=370 

• Install the PV system 

• Collect the rebate or payments 

For details on the application process, refer to Chapter 4 of the CSI Handbook 

(www.gosolarcalifornia.ca.gov/documents/CSI_HANDBOOK.PDF). 

Pacific Gas & Electric 

Program Manager, California Solar Initiative Program 

Attn: California Solar Initiative 

P.O. Box 7265 

San Francisco, CA 94120-7265 

Phone: Business Customers: 1-800-468-4743; Solar Hotline: 1-415-973-3480 

Fax: 415-973-2510 

E-mail: solar@pge.com 

www.pge.com/solar 

San Diego Area: California Center for Sustainable Energy (formerly the San Diego Regional 

Energy Office) 

John Supp, Program Manager 

California Center for Sustainable Energy 

Attn: CSI Program Manager 

8690 Balboa Avenue Suite 100 

San Diego, CA 92123 

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Phone: (858) 244-1177; (866)-SDENERGY 

Fax: 858-244-1178 

E-mail: csi@energycenter.org

www.energycenter.org

Southern California Edison 

California Solar Initiative Administrator 

6042A Irwindale Avenue

Irwindale, CA 91702 

Phone: (800) 799-4177 

Fax: (626) 302-6253 

E-mail: greenh@sce.com

www.sce.com/rebatesandsavings/CaliforniaSolarInitiative/

□ Carl Moyer Memorial Air Quality Standards Attainment Program (CMP), CARB 

CMP is administered by CARB in partnership with local air quality districts throughout the state. 

CMP funds may only be used to generate surplus emission reductions such as to reduce 

emissions beyond what is required by applicable standards or regulations, not to be used to 

comply with any applicable emission standards or regulations. Both public agencies and private 

entities that own and operate eligible diesel equipment can apply for CMP grant funds. Eligible 

projects may include the repowering or retrofitting of existing engines and vehicles, as well as 

the purchase of new low-emission engines or vehicles. 

For more information, go to www.arb.ca.gov/msprog/moyer/moyer.htm. 

To apply, contact your local air district: www.arb.ca.gov/msprog/moyer/contacts.htm. 

California Air Resources Board 

Phone: (916) 323-6169 

□ Energy Efficiency and Renewable Generation Emerging Technologies, Agriculture and Food 

Industries Loan Program (Loan Program), California Energy Commission 

The Loan Program offers 3.2 percent interest loan funds for the purchase of proven costeffective energy efficient and renewable generation emerging technologies applicable to the 

agricultural and food processing industries. 

Applicable technologies include: 

• Food and animal waste bio-energy generation 

• Solar PV and solar thermal systems 

• Thermal heat pumps 

• Electrodialysis membrane systems 

• Enterprise energy management systems 

• Heating and cooling topping cycle systems 

• Ultra-low NOx controlled energy efficient burners 

An energy efficient emerging technology is defined as a technology that is commercially 

available, is proven through an independent evaluation to reach new efficiency performance 

Chapter 9: Funding Resources and Opportunities 103 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

benchmarks when compared to current technologies, and has yet to be adopted by no more 

than 10 percent of the agricultural and food industries in California. 

Available Funding 

The Loan Program has approximately $3 million available for project financing. The maximum 

loan amount for any applicant is $500,000 to finance a single project or multiple projects. The 

minimum loan amount for any applicant is $50,000. Funds are available for the design, 

purchase and installation of the eligible emerging technology. The interest rate is 3.2 percent. 

Interest will be calculated as simple interest and the rate will remain fixed during the life of the 

loan. The maximum repayment term cannot exceed 7 years. Interest accrues starting from the 

date funds are disbursed to the loan recipient. 

Only the following types of facilities are eligible to apply for funding under this program: 

• Food and Fiber Processing 

• Animal Feeding and Processing 

• Breweries, Wineries, Creameries 

• Irrigation Districts 

• Agricultural Production 

Application Process 

Securing the loans will require one of the following types of collateral: 

• Standby Letter of Credit (a letter of credit is the preferred security) 

• Certificate of Deposit (a CD will be considered if applicant is unable to obtain a letter of 

credit on terms acceptable to the Commission) 

Applications are continuously accepted on a first come first served basis as long as funds are 

available. The program began in April of 2007. 

For more information and applications, go to 

www.energy.ca.gov/process/agriculture/loansolicitation/index.html. 

Ricardo Amón 

California Energy Commission

Grants and Loans Office 

Attn: Emerging Energy Efficient Technologies Loan Demonstration Program 

1516 Ninth Street, MS-1 

Sacramento, CA 95814-5512 

Phone: (916) 654-4019 

E-mail: ramon@energy.state.ca.us

□ Self Generation Incentive Program (SGIP), California Public Utilities Commission 

California’s Assembly Bill 970, enacted in September 2000, ordered the establishment of 

additional energy supply and programs in the state. In March 2001, the California Public Utilities 

Commission introduced the SGIP. Eligible technologies include wind turbines, gas turbines, 

internal combustion engines, microturbines, and fuel cells using renewable fuels (Fig. 48). 

Approximately $500 million was made available for 2003 to 2008. 

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Figure 48 Self-Generation Incentive Program incentive rates.276 

Minimum Requirements: 

• Must be customer of Pacific Gas and Electric (PG&E), Southern California Edison 

(SCE), San Diego Gas and Electric (SDG&E), or Southern California Gas Company. 

• May not use more than 25 percent fossil fuel annually. 

• All self-generation equipment must be connected to the electricity grid and installed on 

the customer’s side of the utility meter. 

• Self-generation equipment must be new and permanent; demonstration units are not 

eligible. 

• A portion of the facility’s electric load must be offset by the equipment. 

The 2007 Self-Generation Incentive Program Handbook is available at 

www.socalgas.com/business/selfgen/docs2007/2007_SGIP_Handook.pdf. 

For more information, go to www.cpuc.ca.gov/PUC/energy/051005_sgip.htm and contact local 

utilities to apply. 

Pacific Gas & Electric Co. San Diego, CA 92101 

Self-Generation Incentive Program Phone: (619) 595-5630 

P.O. Box 770000 Fax: (619) 595-5305 

Mail Code B29R E-mail: selfgen@sdenergy.org 

San Francisco, CA 94177 http://www.sdenergy.org/ContentPage.asp 

Phone: (415) 973-6436 ?ContentID=35&SectionID=24 

Fax: (415) 973-2510 

E-mail: selfgen@pge.com Southern California Edison 

http://www.pge.com/selfgen/ Program Manager, Self Generation 

Incentive Program 

San Diego Regional Energy Office 2131 Walnut Grove Avenue 

(Administrator for San Diego Gas & 3rd floor, MS B10 

Electric) Rosemead, CA 91770 

401 B Street, Suite 800 Phone: (800) 736-4777 

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Fax: (626) 302-6253 555 West Fifth Street, GT15F4 

E-mail: greenh@sce.com Los Angeles, CA 90013 

www.sce.com/RebatesandSavings/SelfGe Phone: (800) GAS-2000 

nerationIncentiveProgram/ Fax: (213) 244-8384 

Southern California Gas Company E-mail: selfgeneration@socalgas.com 

Self-Generation Incentive Program www.socalgas.com/business/selfgen 

Administrator 

9.5 HAWAII FUNDING 

□ Hawaii Renewable Energy Tax Credits OR Capital Goods Excise Tax 

These two incentives are tax credits and are essentially the same and one may not be used in 

conjunction with the other. Businesses and residents are eligible to apply. Eligible technologies 

include solar PV, wind power, solar water heat, solar space heat, and solar thermal electric. 

For PV systems, the maximum allowable credits are as follows: 

• Commercial property is eligible for a credit of 35 percent of the initial cost or $500,000, 

whichever is less. 

• Single-family residential property is eligible for a credit of 35 percent of the initial cost or 

$5,000, whichever is less. 

• Multi-family residential property is eligible for a credit of 35 percent of the initial cost or 

$350 per housing-unit, whichever is less. 

For wind power systems, the maximum allowable credits are as follows: 

• Commercial property is eligible for a credit of 20 percent of the actual cost or $500,000, 

whichever is less. 

• Single-family residential property is eligible for a credit of 20 percent of the actual cost 

or $1,500, whichever is less. 

• Multi-family residential property is eligible for a credit of 20 percent of the actual cost or 

$200 per unit, whichever is less. 

For more information, go to www.hawaii.gov/dbedt/info/energy/renewable/solar. 

Hawaii Department of Taxation 

Taxpayer Services Branch 

P.O. Box 259 

Honolulu, HI 96809 

Phone: (808) 587-4242 

www.state.hi.us/tax 

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9.6 NEVADA FUNDING 

□ Renewable Energy Producers Property Tax Abatement 

This incentive is a tax abatement for new or expanded commercial businesses. This incentive is 

applicable for solar PV, wind, solar thermal electric, landfill gas, biomass, municipal solid waste, 

and anaerobic digesters. Expires June 30, 2009. 

• The incentive is a 50 percent property tax abatement for 10 years for real and personal 

property used to generate electricity from renewable energy resources or for a facility 

for the production of an energy storage device. 

• The generation facility must have a capacity of at least 10 kW and use biomass, solar, 

or wind resources as its primary source of energy. 

• The business must also meet capital expenditure, employee compensation, and other 

requirements to be eligible for the incentive. 

For more information, go to: 

• Nevada Commission on Economic Development Tax Abatement Factsheet 

www.expand2nevada.com/whatwedo/pdfs/08renewableenergy.pdf 

• Database of State Incentives for Renewables and Efficiency by North Carolina State 

University 

www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=NV01F&state=NV& 

CurrentPageID=1&RE=1&EE=0 

To apply, contact: 

Susan Combs 

Nevada Commission on Economic Development 

108 E. Proctor Street 

Carson City, NV 89701 

Phone: (775) 687-4325 

Phone 2: (800) 336-1600

Fax: (775) 687-4450 

E-mail: scombs@bizopp.state.nv.us

□ Renewable Energy Systems Property Tax Exemption 

This incentive is a property tax exemption that applies to solar PV, passive solar space heat, 

solar water heat, and solar space heat. Commercial and industrial sectors may apply. This 

exemption was enacted in 1997 and runs until January 2009. The renewable energy property 

tax exemption cannot be claimed if another state tax abatement or exemption is claimed by the 

same building. 

• There is a 50 percent tax abatement for qualifying systems for 10 years. 

• The generation facility must have a capacity of at least 10 kW. 

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For more information, go to 

http://www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=NV02F&state=NV&Curr 

entPageID=1&RE=1&EE=0. 

Information Specialist – Dept. of Taxation 

NV Department of Taxation 

1550 E. College Parkway, Suite 115 

Carson City, NV 89706 

Phone: (775) 684-2000 

Fax: (775) 684-2020 

□ Solar Generations PV Rebate Program, Sierra Pacific Power and Nevada Power 

Solar Generations is a program administered by Sierra Pacific Power Company and Nevada 

Power Company to help these utilities meet their renewable portfolio standards. It provides a 

rebate on PV systems for businesses, residences, schools, local government, state government, 

and other public buildings serviced by Sierra Pacific Power or Nevada Power. The utilities will 

own the renewable energy credits from the electricity produced by the customer’s PV system 

(See Section 2.5 page 11). 

Incentive amounts are: 

• Schools: $5 per watt AC (up to a total capacity of 570 kW for all school projects). 

• Public Buildings: $5 per watt AC (up to a total capacity of 570 kW for all public building 

projects). 

• Residences/Small Businesses: $3 per watt AC (up to a total capacity of 760 kW each 

of the remaining program years). 

Eligibility requirements: 

• Rebate applies to a maximum of 5 kW of rated AC output for residential systems and 

30 kW of rated AC output for small businesses, schools, or public buildings. 

• The equipment installed must be on the list of certified PV modules and inverters 

provided by the California Energy Commission (CEC) Program found at 

www.consumerenergycenter.org/erprebate/equipment.html. 

• A Nevada-licensed electrical contractor must install the system. The State of Nevada 

requires PV system installers in Nevada to hold an annually renewable PV license 

requirement. A list of contractors who have participated in Solar Generations training is 

available at www.solargenerations.com/contractors.html though this does not 

guarantee that they are properly licensed. 

• Program participants must also sign a net metering agreement with the utility. 

For more information, go to www.solargenerations.com. 

SolarGenerations Rebate Program 

6100 Neil Road 

Reno, NV 89511 

Phone: (866) 786-3823 

E-mail: info@SolarGenerations.com

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Chapter 10 Table of Contents 

10.1 Energy Efficiency Calculators, Technical 

Assistance Resources and Informational 

Resources 

10.2 Purchasing Clean Energy Informational 

Resources 

10.3 General Renewable Energy Economic 

Calculations 

10.4 General Renewable Energy Calculators, 

Technical Assistance, Informational 

Resources and Contractor Licensing 

Information 

10.5 Solar Power Tools 

10.6 Wind Power Tools 

10.7 Landfill Gas-to-Energy Tools 

10.8 Anaerobic Digestion Tools 

10.9 Biomass Gasification Tools 

10.10 Clean Diesel Tools 

CHAPTER 10: TOOLS 

This chapter includes tools related to energy 

efficiency, purchasing cleaner energy, renewable 

energy, and cleaner diesel. Energy efficiency tools 

include calculators to assess efficiency of pumps, 

potential federal technical assistance resources, 

and a toolkit on greener cleanups. Tools to assist in 

purchasing cleaner energy include resources of 

further information on how to buy green energy, 

where to find clean energy programs, and a 

resource on clean energy technical assistance. 

General renewable energy tools include calculators 

to estimate emissions and emissions reductions, 

software to help model the energy outputs and 

benefits of a renewable energy system, map data 

depicting renewable energy resources in the state, 

potential technical assistance resources, and 

resources on checking a renewable energy 

contractor’s licenses. There is a tools section for 

each of the renewable energy technologies detailed 

in this guide with calculators and models, surveying 

equipment, sources of further information and potential technical assistance resources. The clean 

diesel tools section includes calculators to help quantify emissions and emissions reductions, 

sources of further information, and potential technical assistance resources for cleaner diesel fuels, 

practices, and technologies. 

10.1 ENERGY EFFICIENCY CALCULATORS, TECHNICAL ASSISTANCE 

RESOURCES, AND INFORMATIONAL RESOURCES 

□ Agricultural Pumping Efficiency Program (California Public Utilities Commission (CPUC) and 

California State University (CSU) Fresno): The Agricultural Pumping Efficiency Program is a 

local resource for California. It is comprised of a partnership between the CPUC and CSU at 

Fresno's Center for Irrigation Technology. PG&E and SCE customers are eligible. This program 

provides free pump efficiency tests, educational seminars, and incentives for pump retrofits. 

Check with your local utility to see if similar programs are available for your cleanup site. 

www.pumpefficiency.org/ 

For the Pumping Cost Analysis Calculator for electric pumps, go to 

http://www.pumpefficiency.org/Pumptesting/costanalysis.asp. 

Agricultural Pumping Efficiency Program 

Center for Irrigation Technology 

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6014 North Cedar Ave. 

Fresno, CA 93710 

Phone: (800) 845-603

□ Federal Energy Management Program (FEMP) (EERE): FEMP is a potential resource to help 

improve energy efficiency and implement renewable energy projects at your site. FEMP works 

to reduce costs and environmental impacts of the federal government by advancing energy 

efficiency and water conservation, promoting the use of distributed and renewable energy, and 

improving utility management decisions at federal sites. FEMP helps federal energy managers 

identify, design, and implement new construction and facility improvement projects. This service 

may be applicable for fund-lead sites. www1.eere.energy.gov/femp/ 

FEMP Help Desk

1000 Independence Ave., SW 

Washington, DC 20585-0121 

Phone: (202) 586-5772 

www1.eere.energy.gov/femp/about/contacts.html 

□ Greener Practices for Business, Site Development and Site Cleanups: A Toolkit (Minnesota 

Pollution Control Agency): Use this online toolkit of greener cleanup options, a decision tree, 

and success stories, to determine how to reduce the environmental footprint from remediation 

activities. www.pca.state.mn.us/programs/p2-s/toolkit/index.html 

□ Pumping System Assessment Tool (EERE): The Pumping System Assessment Tool is an online 

calculator that helps industrial users assess the efficiency of pumping system operations. 

www1.eere.energy.gov/industry/bestpractices/software.html#psat 

□ Technical Assistance Project (TAP) for State and Local Officials (EERE): TAP is available to 

provide state and local officials with quick, short-term access to experts at DOE national 

laboratories for assistance with their renewable energy and energy efficiency policies and 

programs. TAP projects are available on a first come, first served basis. Project budgets are 

limited to $5,000 in staff time and travel. Typically, this can provide a few days of on-site 

assistance or a week's worth of analysis and consultations via phone and e-mail. 

www.eere.energy.gov/wip/tap.cfm 

To apply, go to www.eere.energy.gov/wip/how_to_apply.cfm. 

Julie Riel 

DOE Golden Field Office 

Golden, Colorado 

Phone: (303) 275-4866 

E-mail: julie.riel@go.doe.gov

10.2 PURCHASING CLEAN ENERGY INFORMATIONAL RESOURCES 

□ EERE Green Power Network: Find state-by-state clean energy purchasing options. 

www.eere.energy.gov/greenpower/buying/buying_power.shtml 

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□ The Guide to Purchasing Green Power (DOE, EPA, World Resources Institute, and Green-e, 

September 2004): Document detailing steps to purchasing clean energy. 

www.epa.gov/greenpower/buygp/guide.htm 

□ Green Power Marketing in the United States: A Status Report (NREL March 2003): Document 

detailing the status of green power marketing in the U.S. www.nrel.gov/docs/fy04osti/35119.pdf 

□ EPA Green Power Partnership: The EPA Green Power Partnership is a program that 

encourages U.S. organizations to voluntarily purchase green power as a way to reduce the risk 

of climate change and the environmental impacts associated with conventional electricity use. 

This program can assist in navigating the complexities of making a green power purchase. The 

Green Power Partnership is also available to help identify green power products. To find stateby-state green power products, go to http://www.epa.gov/greenpower/pubs/gplocator.htm. 

www.epa.gov/greenpower/ 

James Critchfield 

EPA HQ 

Green Power Partnership 

Phone: (202) 343-9442 

E-mail: critchfield.james@epa.gov 

10.3 GENERAL RENEWABLE ENERGY ECONOMIC CALCULATIONS 

There are many different ways to look at the economic benefits of installing a renewable energy 

system. A few methods of analyzing the economics are: (1) rate of return, (2) payback time, and (3) 

total lifecycle payback. An explanation of these analyses follows using solar PV as an example. 

Simple Calculation of Monthly Electricity Bill Savings 

The simple calculation in Box 8 estimates 

electricity bill savings from your site’s renewable 

energy system. Enter the proposed rated power 

output of the system and the average kWh 

production each month per rated kW. Using 

solar PV as an example, 135-150 kWh per 

month is the general estimate of monthly energy 

Box 8 Monthly Electricity Bill Savings 

B = S ∗ O ∗ U 

B = Monthly Electricity Bill Savings ($) 

S = Rated Power Output (kW)

O = Average Energy Output (kWh per kW per month); 

U = Utility price per kWh ($) 

production from a 1-kW system in Region 9 states. Look on your electricity bill for your cost of 

electricity per kWh. This simple calculation does not take into account that electricity prices are 

steadily increasing. 

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Simple Payback Time277 

Simple payback time is defined as the time it takes for a renewable energy system to save enough 

money to pay for itself. This simplified calculation (Box 9) usually only takes into consideration the 

capital cost of the system and monetary savings from a reduced or eliminated energy bill and does 

not include operation and maintenance costs. In this 

model, reduced pollution levels and other nonmonetary valued benefits are also not included. 

Another shortfall of simple payback time is that it does 

not account for the savings accrued after the payback 

time. This equation may overestimate the payback 

time since energy prices are expected to continue to 

increase. 

Total Lifecycle Payback278 

The total lifecycle payback accounts for savings 

gained after the payback time until the end of the 

useful life of a renewable energy system (Box 10). 

Solar PV systems usually last 25-30 years, 

resulting in savings 2-3 times greater than the initial 

capital cost. The drawback of this calculation is 

that it does not reflect the time value of money 

Box 9 Simple Payback Time 

PB = C ÷ B 

PB = Payback Time (years) 

C = Capital Cost ($) 

B = Annual Electricity Bill Savings ($ per year) 

Box 10 Total Lifecycle Payback 

R = B ÷ C ∗ Y 

R = Total Lifecycle Payback Ratio 

B = Annual Electricity Bill Savings ($ per year) 

C = Capital Cost ($) 

Y = Years of operation (years)

(having a dollar today is worth more than having a dollar in the future). 

10.4 GENERAL RENEWABLE ENERGY CALCULATORS, TECHNICAL 

ASSISTANCE, INFORMATIONAL RESOURCES AND CONTRACTOR 

LICENSING INFORMATION 

□ EPA’s Power Profiler: Use this online calculator to determine the emissions emitted from 

electricity use. It can also be used to determine the pollution avoidance from a renewable 

energy system. Estimate CO2, NOx, and SO2 emissions avoidance from using renewable energy 

rather than conventional electricity. To calculate pollutants avoided, enter the estimated amount 

of renewable energy produced by your renewable energy system into the Profiler instead of 

entering total electricity consumed. www.epa.gov/cleanenergy/powerprofiler.htm 

□ Federal Energy Management Program (FEMP) (EERE): FEMP is a potential resource to help 

improve energy efficiency and implement renewable energy projects at your site. FEMP works 

to reduce costs and environmental impacts of the federal government by advancing energy 

efficiency and water conservation, promoting the use of distributed and renewable energy, and 

improving utility management decisions at federal sites. FEMP helps federal energy managers 

identify, design, and implement new construction and facility improvement projects. This service 

may be applicable for fund-lead sites. www1.eere.energy.gov/femp/ 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

FEMP Help Desk

1000 Independence Ave., SW 

Washington, DC 20585-0121 

Phone: (202) 586-5772 

www1.eere.energy.gov/femp/about/contacts.html 

□ Greenhouse Gas Equivalencies Calculator (EPA): Translate tons of CO2 and other pollutants 

into terms that are easier to conceptualize such as number of passenger cars driven, number of 

seedlings planted, and number of homes powered for a year. 

www.epa.gov/cleanenergy/energy-resources/calculator.html 

□ The Guide to Purchasing Green Power (DOE, EPA, World Resources Institute, and Green-e, 

September 2004): Document detailing steps to purchasing clean energy including developing a 

renewable energy project. www.epa.gov/greenpower/buygp/guide.htm 

□ HOMER (NREL): Optimization software model to analyze the technical and economic feasibility 

of distributed power including solar PV, wind power, microturbine, fuel cell, and generators. 

https://analysis.nrel.gov/homer/ 

□ Renewable Energy Atlas of the West: Maps of solar, wind, geothermal and biomass resources 

created by the Western Resource Advocates, Northwest Sustainable Energy for Economic 

Development, GreenInfo Network, and Integral GIS, Inc. that can help assess renewable energy 

potential in the area surrounding a cleanup site. www.energyatlas.org 

Arizona: www.energyatlas.org/PDFs/atlas_state_AZ.pdf

California: www.energyatlas.org/PDFs/atlas_state_CA.pdf

Hawaii: not yet available 

Nevada: www.energyatlas.org/PDFs/atlas_state_NV.pdf

□ RETScreen International (Natural Resources Canada): This website provides green energy 

analysis tools developed by Natural Resources Canada in partnership with international 

organizations such as the United Nations Environmental Programme, NASA, and the World 

Bank. This MS Excel-based program requires detailed inputs of renewable energy equipment 

data. This tool can be used for solar, wind, and biomass renewable energy projects. 

www.retscreen.net 

□ Technical Assistance Project (TAP) for State and Local Officials (EERE): TAP is available to 

provide state and local officials with quick, short-term access to experts at DOE national 

laboratories for assistance with their renewable energy and energy efficiency policies and 

programs. TAP projects are available on a first come, first served basis. Project budgets are 

limited to $5,000 in staff time and travel. Typically, this can provide a few days of on-site 

assistance or a week's worth of analysis and consultations via phone and e-mail. 

www.eere.energy.gov/wip/tap.cfm 

To apply, go to www.eere.energy.gov/wip/how_to_apply.cfm. 

Julie Riel 

DOE Golden Field Office 

Phone: (303) 275-4866 

E-mail: julie.riel@go.doe.gov

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Renewable Energy Contractors’ Licenses 

Below are websites that will help you to determine whether a prospective contractor is licensed in 

that state. 

□ Contractor’s License Reference Site: www.contractors-license.org/ 

□ North American Board of Certified Energy Practitioners: www.nabcep.org 

□ Arizona Registrar of Contractors: www.rc.state.az.us/ 

□ California Contractors State License Board: www.cslb.ca.gov 

□ Hawaii Department of Commerce: http://hbe.ehawaii.gov/cogs/search.html 

□ Nevada State Contractors Board: www.nvcontractorsboard.com 

10.5 SOLAR POWER TOOLS 

Solar Power Calculators 

□ My Solar Estimator (FindSolar.com): Findsolar.com is created through a partnership among solar 

professional organizations and DOE. This site provides information on solar incentives, a listing 

of qualified solar professionals, and a user-friendly PV sizing and economic analysis tool called 

“My Solar Estimator.” This tool outputs solar availability, size of system (kW), space 

requirements, costs, rebates, loan considerations, savings and benefits including increased 

property value, return on investment, break even point, and monthly energy bill savings. 

www.findsolar.com 

□ PV Watts (Renewable Resource Data Center): PV Watts is a tool hosted by the Renewable 

Resource Data Center which is supported by the National Center for Photovoltaics and managed 

by EERE. Use PV Watts to estimate the energy output of your PV system and energy bill 

savings. www.pvwatts.org 

□ Clean Power Estimator (Clean Power Research): Clean Power Research provides consulting 

and software that evaluates the economics of clean energy investments. Use the Clean Power 

Estimator to estimate the energy output, emissions reductions, and financial benefits of a gridconnected PV system. www.consumerenergycenter.org/renewables/estimator/index.html 

□ Economic Analysis Tool (OnGrid Solar): OnGrid Solar is a private company that provides 

financial payback analysis for solar PV installations. Visit the site for a free demo of the Excel 

tool. Subscription starts at $100 per month. www.ongrid.net 

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Solar Power Surveying Equipment 

Figure 49 Solar Pathfinder. Image 

courtesy Solar Pathfinder279 

□ Solar Pathfinder: This device can be used to evaluate 

annual sun/shading data and is useful for siting a PV 

system. Its polished transparent dome reflects 

surrounding buildings, trees, and other obstructions that 

create shadows (Fig. 49). Included in the kit are “Sunpath 

Diagrams,” which show the sun’s average path through the 

sky specific to your site. The device helps to determine 

year-round shadows made by surrounding obstructions. 

As of the writing of this guide, one Pathfinder set costs 

$259. www.solarpathfinder.com 

The Pacific Energy Center, run by PG&E, lends Solar 

Pathfinders and other surveying tools free of charge to 

customers working on energy efficiency and renewable 

energy projects in California. Tools may be loaned for about 2-4 weeks. 

http://www.pge.com/mybusiness/edusafety/training/pec/toolbox/tll/. 

For other states and territories, check your local utility for similar services. 

Solar Power Informational Resources 

□ A Consumer's Guide: Get Your Power from the Sun (EERE, December 2003): A EERE 

document written for residents who are interested in installing a PV system for their homes. 

www.nrel.gov/docs/fy04osti/35297.pdf 

□ EERE Solar PV Website: Website with technology information on solar PV. 

www1.eere.energy.gov/solar/photovoltaics.html 

10.6 WIND POWER TOOLS 

Wind Power Calculators 

□ Wind Energy Payback Period Workbook (EERE): Use this tool to estimate the payback period 

for your wind power system. 

www.eere.energy.gov/windandhydro/windpoweringamerica/filter_detail.asp?itemid=1415 

□ Wind Speed Calculator (Danish Wind Industry Association ): Input a known wind speed at a 

certain height and this calculator outputs estimated wind speeds at other heights. Enter wind 

speeds in meters per second. This calculator also takes into account variation in terrain which 

would affect wind speed estimates. www.windpower.org/en/tour/wres/calculat.htm 

Wind Surveying Equipment 

□ Pacific Energy Center (PG&E): The Pacific Energy Center, run by PG&E, lends anemometers 

and other surveying tools free of charge to customers working on energy efficiency and 

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renewable energy projects in California. Tools may be loaned for about 2-4 weeks. 

http://www.pge.com/mybusiness/edusafety/training/pec/toolbox/tll/. 

For other states and territories, check your local utility for similar services. 

Wind Power Technical Support 

□ California Wind Energy Collaborative (California Energy Commission and University of California 

at Davis): The California Wind Energy Collaborative is a partnership between the University of 

California at Davis and the California Energy Commission that supports the development of wind 

power in California. They provide short training courses for the general public that provides 

practical information on selecting, installing, and owning a wind turbine. http://cwec.ucdavis.edu/ 

California Wind Energy Collaborative 

E-mail: info@cwec.ucdavis.edu

Dr. C.P. (Case) van Dam Dr. Bruce R. White 

Department of Mechanical and Department of Mechanical and 

Aeronautical Engineering Aeronautical Engineering

University of California, Davis University of California, Davis 

1 Shields Avenue 1 Shields Avenue 

Davis, CA 95616 Davis, CA 95616 

Phone: (530) 752-7741 Phone: (530) 752-6451 

E-mail: cpvandam@ucdavis.edu E-mail: brwhite@ucdavis.edu

Wind Power Informational Resources 

□ American Wind Energy Association (AWEA): This website provides information on 

installers/contractors, state-specific wind power rules, interconnection issues, and wind power 

incentives (www.awea.org/smallwind/states.html). Find general information on planning a wind 

project using the AWEA “Small Wind Toolbox” (www.awea.org/smallwind/toolbox). 

www.awea.org 

□ British Wind Energy Association Briefing Sheet: Wind turbine technology factsheet. 

www.bwea.com/pdf/briefings/technology05_small.pdf 

□ Danish Wind Industry Association: More information on how wind turbines work and wind 

turbine technology. http://www.windpower.org/en/core.htm 

□ Permitting Small Wind Turbines: A Handbook (American Wind Energy Association): Guide on 

permitting information for wind turbines. www.awea.org/smallwind/documents/permitting.pdf 

□ Small Wind Electric Systems: A U.S. Consumer’s Guide (EERE, March 2005): An EERE 

document written mainly for residents who are interested in installing a wind turbine. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf 

□ Small Wind Electric Systems: An Arizona Consumer's Guide (EERE, March 2005): An EERE 

document written mainly for residents who are interested in installing a wind turbine with 

information specific to Arizona. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_az.pdf 

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□ EERE Wind Power Website: Information on wind power technology. 

www1.eere.energy.gov/windandhydro/wind_technologies.html 

□ NREL Wind Power Website: Information on wind power technology. www.nrel.gov/wind/ 

□ Wind Energy Manual (Iowa Energy Center, 2006): Details on wind power history, technology, 

and considerations. www.energy.iastate.edu/Renewable/wind/wem-index.htm 

10.7 LANDFILL GAS-TO-ENERGY TOOLS 

LFGE Calculators 

□ LFGE Benefits Calculator (LMOP): The LFGE Benefits Calculator can be used to estimate 

direct, avoided, and total GHG reductions, as well as environmental and energy benefits from a 

landfill gas-to-energy project. www.epa.gov/landfill/res/calc.htm 

□ LFGE Potential Project Locator Tool (LMOP): This LMOP tool can help developers determine 

potential LFGE project sites within a 20-25 mile radius of a particular address. Contact LMOP 

for assistance. www.epa.gov/lmop/contact/index.htm 

□ Landfill Gas Emissions Model (LandGEM) (EPA Technology Transfer Network): This model can 

be used to estimate total LFG and methane generation, as well as emissions of CO2, NMOCs, 

and other air pollutants from MSW landfills. It is not intended to characterize emissions from codisposal landfills. www.epa.gov/ttncatc1/products.html#software 

□ Landfill Gas Energy Cost Model (EPA, LMOP): Use this tool to estimate the economic feasibility 

of your MSW LFGE project. http://www.epa.gov/lmop/res/#5 

LFGE Informational Resources 

□ A Landfill Gas to Energy Project Development Handbook (EPA LMOP, September 1996): This 

LMOP handbook includes information on the major aspects of LFG project development, 

including economic analysis, financing, choosing project partners, environmental permitting, and 

contracting for services. http://epa.gov/lmop/res/pdf/handbook.pdf 

See Appendix A: Calculations of Landfill Gas Energy Recovery Project Costs for an overview of 

costs. Though the cost estimates are outdated, it may be useful to better understand the 

services and equipment that must be included and their relative costs. 

www.epa.gov/lmop/res/pdf/hbookapp.pdf 

□ Guidance for Evaluating Landfill Gas Emissions From Closed or Abandoned Facilities (EPA, 

September 2005): Use this guidance document for procedures on how to evaluate emissions 

from co-disposal landfills. www.epa.gov/nrmrl/pubs/600r05123/600r05123.pdf 

□ Landfill Gas-To-Energy Potential in California (California Energy Commission, September 2002): 

Document that provides information on landfills in California, their potential for generating 

electricity, applicable technologies, and information on current LFGE projects in California. 

www.energy.ca.gov/reports/2002-09-09_500-02-041V1.PDF 

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□ Economic and Financial Aspects of Landfill Gas to Energy Project Development in California 

(California Energy Commission, April 2002): Provides general information on LFGE technology 

and summarizes existing LFGE projects in California. 

www.energy.ca.gov/pier/final_project_reports/500-02-041v1.html 

LFGE Technical Resources 

□ Landfill Methane Outreach Program, (EPA): The Landfill Methane Outreach Program (LMOP) is 

an EPA assistance and partnership program that promotes the use of landfill gas as a renewable 

energy source. LMOP provides technical, informational, and marketing services, such as: 

• Technical assistance, guidance materials, and software to assess a potential project's 

economic feasibility; 

• Assistance in creating partnerships and locating financing for projects; 

• Informational materials to help educate the community and the local media about the 

benefits of LFG; and 

• Networking opportunities with peers and LFG experts to allow communities to share 

challenges and successes. 

www.epa.gov/lmop 

Contact LMOP for assistance on your landfill project (www.epa.gov/lmop/contact). 

□ Methane to Markets Partnership: The Methane to Markets Partnership is a voluntary, nonbinding framework for international cooperation to advance the recovery and use of methane as 

a valuable clean energy source. www.methanetomarkets.org 

10.8 ANAEROBIC DIGESTION TOOLS 

Anaerobic Digestion Calculators 

□ Biomass Cost of Energy Calculator (California Biomass Collaborative): Use this calculator to 

estimate the cost of energy generated from an anaerobic digester. Requires input of detailed 

technical, financial, and economic assumptions. 

http://faculty.engineering.ucdavis.edu/jenkins/CBC/Calculator/index.html 

□ FarmWare (AgStar): Decision support software package that can be used to conduct prefeasibility assessments for swine and dairy manure digesters. 

www.epa.gov/agstar/resources/handbook.html 

□ Financial Analysis Model (New York Agriculture Innovation Center): This spreadsheet model is 

useful for potential manure digester projects. It estimates financial projections for implementing 

anaerobic digestion, cogeneration, solids separation, composting, and liquid manure spreading 

for a farm. Requires detailed inputs including capital costs, depreciation terms, projected 

construction schedule, and operating costs such as labor hours, fuel use, and insurance costs. 

This model can be used after initial consultation with vendors. 

http://hive.bee.cornell.edu/extension/manure/FinancialAnalysis.htm 

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Anaerobic Digestion Informational Resources 

□ Agricultural Biogas Casebook Update 2004,(Resource Strategies, Inc.): Collection of case 

studies of digesters in the Great Lakes region. 

www.rs-inc.com/downloads/Experiences_with_Agricultural_Biogas_Systems-2004_Update.pdf 

□ Cornell University Anaerobic Digester Website: Technical papers and case studies on anaerobic 

digesters. www.manuremanagement.cornell.edu/HTMLs/AnaerobicDigestion.htm 

□ Minnesota Department of Agriculture Anaerobic Digester Web Page: Collection of anaerobic 

digester studies. www.mda.state.mn.us/renewable/waste/digester-refs.htm 

□ Penn State University Anaerobic Digester Website: General information on digester 

technologies, digester safety, case studies, and vendors. 

www.biogas.psu.edu/anaerobicdigestion.html 

□ EERE Anaerobic Digester Web Pages: DOE website providing basic information on digesters. 

www.eere.energy.gov/consumer/your_workplace/farms_ranches/index.cfm/mytopic=30002 

Anaerobic Digestion Technical Resources 

□ AgStar Program: The AgSTAR Program is a voluntary effort jointly sponsored by the EPA, the 

USDA, and DOE. The program encourages the use of biogas capture and utilization at animal 

feeding operations that manage manures as liquids and slurries. www.epa.gov/agstar 

AgStar Handbook This handbook is for livestock producers, developers, investors, and others in 

the agricultural and energy industry that may consider biogas technology as a livestock manure 

management option. www.epa.gov/agstar/resources/handbook.html 

Managing Manure with Biogas Recovery Systems Improved Performance at Competitive Costs 

This document provides a general overview on anaerobic digesters. 

www.epa.gov/agstar/pdf/manage.pdf 

□ Methane to Markets Partnership: Methane to Markets is a voluntary partnership among 

international corporations and organizations to advance the recovery and use of methane as a 

valuable clean energy source. www.methanetomarkets.org 

10.9 BIOMASS GASIFIER TOOLS 

The following is a list of state-specific information and biomass energy organizations that may be 

able to provide assistance. Also provided are potential consulting resources that may be able to 

help to plan a gasifier project. 

Biomass Gasifier Informational Resources 

□ Analysis of Hawaii Biomass Energy Resources for Distributed Energy Applications (University of 

Hawaii at Manoa for the State of Hawaii, December 2002): Research paper studying energy 

content and chemical composition of different biomass resources available in Hawaii. 

www.hawaii.gov/dbedt/info/energy/publications/biomass-der.pdf 

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□ “Arizona Biomass Energy Opportunities” (Prepared by TSS Consultants for Greater Flagstaff 

Forests Partnership, March 2004): Report discussing benefits of using biomass waste from 

Arizona forest management practices for energy production. 

www.cc.state.az.us/divisions/utilities/electric/EPS-TSSC.pdf 

□ Bioenergy Feedstock Information Network: Database of biomass-to-energy documents from the 

DOE Oak Ridge National Laboratory, DOE Idaho National Laboratory, NREL, and other research 

organizations. http://bioenergy.ornl.gov/main.aspx 

□ “Biomass Energy Project Guide” (Oregon Department of Energy): List of steps to plan and 

implement a gasification project. www.oregon.gov/ENERGY/RENEW/Biomass/guide.shtml 

□ California Biomass Collaborative: Collaboration of government, industry, educational institutions 

supporting the growth of biomass energy administered by the University of California at Davis. 

http://biomass.ucdavis.edu/ 

□ California Biomass Energy Alliance: Association of biomass fueled power plants in California. 

www.calbiomass.org/ 

□ International Energy Agency (IEA) Bioenergy: IEA Bioenergy is an organization set up in 1978 

by the IEA with the aim of improving cooperation and information exchange between countries 

that have national programs in bioenergy research, development and deployment. Go to their 

website for technical documents related to gasifiers. www.ieabioenergy.com/ 

IEA Bioenergy’s Task 33 has the goal of promoting biomass gasification. It is being conducted 

by experts from Austria, Canada, Denmark, European Commission, Finland, Germany, Italy, The 

Netherlands, New Zealand, Sweden, Switzerland, and the U.S. 

www.gastechnology.org/webroot/app/xn/xd.aspx?it=enweb&xd=iea/homepage.xml 

□ www.TarWeb.net: Information on tars and other contaminants in gasifier-produced syngas. 

□ Gasification Technologies Council: Organization of gasifier companies that focus mainly on 

fossil fuel gasification. Find information on gasification technology. www.gasification.org 

□ Intelligent Energy for Europe Programme Gasification Guide: "Guideline for Safe and Ecofriendly Biomass Gasification" project supported by the Intelligent Energy for Europe 

Programme. The document is not yet completed but check the website for updates. 

www.gasification-guide.eu/ 

Potential Biomass Gasifier Technical Resources 

□ Arizona Department of Commerce Energy Programs: www.azcommerce.com/Energy/ 

□ Biomass Energy Resource Center: The Biomass Energy Resource Center is a non-profit 

organization that works on projects around the country to install systems that use biomass, 

focusing on woody biomass, to produce heat and/or electricity. They have partnered with 

schools, communities, colleges, businesses, utilities, and government agencies. Services 

include: 

• Providing information for potential projects; 

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• Carrying out or coordinating project-related pre-feasibility studies, feasibility studies, 

and other reports; 

• Carrying out, coordinating, or consulting on the development of biomass energy 

projects; 

• Managing the operations of biomass energy projects; and 

• Conducting assessments of working biomass systems. 

www.biomasscenter.org 

Biomass Energy Resource Center 

Montpelier, VT 05601 

Phone: (802) 223-7770 

E-mail: contacts@biomasscenter.org

□ Hawaii Natural Energy Institute (University of Hawaii at Manoa): www.hnei.hawaii.edu/ 

□ Nevada Biomass Working Group (Office of the Governor, Nevada State Office of Energy): 

http://energy.state.nv.us/renewable/biomass.htm 

□ Nevada Renewable Energy & Energy Conservation Task Force: 

www.nevadarenewables.org/?section=biomass 

□ Renewable Energy Center (University of Nevada at Reno): 

www.unr.edu/geothermal/UNRREC.htm 

□ Western Governors’ Association Western Regional Biomass Energy Program: 

www.westgov.org/wga/initiatives/biomass/index.htm 

10.10 CLEAN DIESEL TOOLS 

Clean Diesel Calculators 

□ EPA Modeling and Inventories: Go to www.epa.gov/otaq/models.htm for a list of EPA models to 

inventory emissions across a city, county, or state. 

□ The Quantifier (EPA): Calculate diesel emissions from your site and the reductions from using 

cleaner and alternative fuels, retrofits, and engine upgrades for both on-road and off-road 

engines using this EPA online tool. Emissions output units are in tons. 

http://cfpub.epa.gov/quantifier/ 

□ Biodiesel Emissions Reduction Calculator (OTAQ): Estimate the percent emissions reductions 

from different blends of biodiesel with this OTAQ MS Excel calculator. Follow the “biodiesel 

reduction spreadsheet” link found at www.epa.gov/otaq/retrofit/techlist-biodiesel.htm. 

□ National Biodiesel Board Emissions Calculator: Enter the amount of biodiesel used to calculate 

emissions reductions in terms of percentage and pounds of pollutant. 

www.biodiesel.org/(X(1)S(ux4dpq55txmx5rjnj25h1k55))/tools/calculator/default.aspx?AspxAutoD 

etectCookieSupport=1 

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□ Biodiesel Comprehensive Calculator (BioFleet): Estimate quantified emissions reductions from 

using biodiesel with the BioFleet calculator. BioFleet is a biodiesel market development program 

sponsored by the Canadian government. Note that input and output values are in metric units. 

http://biofleet.net/index.php?option=com_wrapper&Itemid=58 

□ Construction Mitigation Calculator (Sacramento Metropolitan Air Quality Management District): 

The purpose of this MS Excel tool is to calculate emissions from construction activities to see if 

the levels are below required thresholds. This tool can be used to estimate total PM and NOx 

emissions for a cleanup project. www.airquality.org/ceqa/index.shtml#construction 

□ Idle Reduction Savings Calculator (Argonne National Laboratory): While this tool was developed 

with a focus on on-road vehicles, it can provide approximate values for emissions savings from 

idle reduction of off-road vehicles. Follow the link in the right side navigation bar. 

www.transportation.anl.gov/research/technology_analysis/idling.html 

Clean Diesel Informational and Technical Assistance Resources 

□ Alternative Fuel Station Locater Website (EERE): Visit this website to find a biodiesel, natural 

gas, or ethanol fueling station. www.eere.energy.gov/afdc/infrastructure/locator.html 

□ Diesel Technology Forum: The Diesel Technology Forum is a non-profit educational organization 

that provides information on cleaner and alternative fuels and cleaner diesel technology. 

www.dieselforum.org 

□ Manufacturers of Emission Controls Association (MECA): Go to MECA’s website for information 

on diesel emission reduction technologies and manufacturers of diesel retrofits. www.meca.org 

□ National Biodiesel Board: The National Biodiesel Board is the national trade association for the 

biodiesel industry. Visit their website for more information on biodiesel and locations of biodiesel 

distributors. www.biodiesel.org 

□ Off-road Diesel Retrofit Guidance Document (Western Regional Air Partnership [WRAP], 

November 2005): The WRAP is a voluntary organization of western states, tribes and federal 

agencies. It was formed in 1997 as the successor to the Grand Canyon Visibility Transport 

Commission to help the region comply with EPA's regional haze regulations. Use this document 

to help guide you through retrofitting a fleet. www.wrapair.org/forums/msf/offroad_diesel.html 

□ EPA National Clean Diesel Campaign (NCDC): The National Clean Diesel Campaign is an 

OTAQ program. NCDC is a public-private partnership that collaborates with businesses, 

government and community organizations, industry, and others to reduce diesel emissions and 

protect human health and the environment. www.epa.gov/cleandiesel 

Go to www.epa.gov/cleandiesel/publications.htm for informational publications. 

□ EPA Office of Air and Radiation: Visit this website for more information on diesel PM. 

www.epa.gov/airtrends/pm.html 

□ West Coast Collaborative: The West Coast Collaborative is the NCDC regional collaborative that 

serves Alaska, Arizona, California, Canada, Hawaii, Idaho, Mexico, Oregon, and Washington. 

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Contact the West Coast Collaborative for assistance in reducing diesel emissions. 

www.westcoastcollaborative.org 

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APPENDIX I: ERRS AND RAC CONTRACT LANGUAGE 

ERRS Language 

Region 9 Emergency and Rapid Response Service (ERRS) contracts include the following diesel 

emissions reduction language. 

CLEAN TECHNOLOGIES 

The contractor will use clean technologies and/or fuels on all diesel equipment to the 

extent practicable and/or feasible. The preference is for clean diesel technologies, 

but alterative fuels, such as biodiesel or natural gas-powered vehicles are also 

acceptable. These alternative fuels will be used where they are available and within 

a reasonable distance to sites. For equipment retrofits, the contractor will employ the 

Best Available Control Technology (BACT) on non-road and on-road diesel powered 

equipment used at a site. Examples of clean diesel technologies include diesel 

particulate filters (DPFs), and diesel oxidation catalysis (DOCs). For alternative fuel 

usage, the contractor will use at least a B20 blend (e.g., 20 percent biodiesel and 80 

percent petrodiesel) or higher in the equipment engines that are used at a site. 

RAC Language 

Region 9 Response Action Contracts (RAC) include the following diesel emissions reduction and 

renewable energy use language. 

Clean Air 

In the performance of all activities performed under this contract, the contractor shall 

where directed by EPA use cleaner engines, cleaner fuel and cleaner diesel control 

technology on diesel powered equipment with engines greater than 50 horsepower 

whether the equipment is owned or rented. Direction will be provided on a Task 

Order by Task Order basis. The contractor shall provide a break-out cost for each 

task order in accordance with the instruction in contract clause addressing 

submission of cost proposal. 

Cleaner engines include non-road engines meeting Tier I or cleaner standards and 

on-road engines meeting 2004 On-Highway Heavy Duty Engine Emissions 

Standards or cleaner, whether the equipment is owned or rented. Cleaner fuels 

include biodiesel blends or ultra low sulfur diesel. Cleaner diesel control technology 

includes EPA or California Air Resources Board ("CARB") verified diesel particulate 

filters ("DPFs") or diesel oxidation catalysts ("DOCs"). The contractor shall track 

emissions reduced (i.e., tons of diesel particulate matter reduced) associated with 

using cleaner diesel equipment and fuels. 

Renewable Energy 

The contractor shall evaluate all reasonably feasible renewable energy sources when 

conducting work related to selecting a cleanup remedy, constructing a cleanup 

remedy, and when optimizing an existing cleanup remedy. Sources of renewable 

energy include solar, wind, and biomass and biogas. Examples of renewable energy 

technologies include photovoltaic panels, wind turbines, digesters, gasifiers, and 

micro turbines. Part of evaluating renewable energy sources and technologies will 

involve a cost analysis, comparing the energy costs from renewable sources versus 

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traditional electricity sources provided by local utilities, over the expected life of the 

cleanup remedy. Similarly, an evaluation of the avoided emissions as a result of 

using renewable energy sources versus traditional energy sources provided by local 

utilities shall be performed. The contractor shall also evaluate the cost of purchasing 

green power from organizations that offer green power within the appropriate state. 

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APPENDIX II: FEDERAL REGULATIONS AND GOALS

The following are some federal regulations and goals that pertain to reducing GHGs and diesel 

emissions. 

□ Diesel Emissions Reduction Act of 2005 (DERA): DERA authorizes $200 million per year over 

five years in grants and loans for states and organizations to clean up existing diesel fleets. 

□ EPA Administrator’s Action Plan:

280 This plan aims to provide certainty for consumers and 

protect the environment by seeking passage of Clear Skies (www.epa.gov/clearskies) legislation; 

expand the use of biofuels and promote diesel emissions reductions through retrofit and other 

technologies; promote clean air and energy security through voluntary conservation programs, 

such as Energy Star (www.energystar.gov) and SmartWay Transport (www.epa.gov/smartway); 

and make timely permitting decisions and foster technological innovations to support the clean 

development of domestic energy resources (oil, gas, nuclear, coal, wind, and solar). 

□ EPA Region 9 Energy and Climate Change Strategy:

281 Included in this strategy is the 

promotion of renewable energy production on contaminated sites by working with land owners 

and utilities to encourage the production/use of renewable energy on revitalized lands. 

□ Energy Independence and Security Act of 2007:

282 Signed into law by President George W. 

Bush on December 17, 2007, this act increases renewable fuel standards and raises fuel 

economy standards for cars, trucks, and SUVs. It also aims to further develop carbon capture 

technology. 

□ Energy Policy Act (EPAct) of 2005:

283 The EPAct 2005 was passed by Congress on June 29, 

2005 and signed into law by President George W. Bush on August 8, 2005. It addresses 

growing energy problems, provides tax incentives and loan guarantees for energy production of 

various types. Each federal agency is required to increase renewable energy use and reduce 

energy intensity. Federal agencies are also required to purchase products that are Energy Starqualified (www.energystar.gov) or designated by the Federal Energy Management Program 

(FEMP) (www1.eere.energy.gov/femp/procurement/index.html). 

□ Executive Order (EO) 13134 “Developing and Promoting Bio-based Products and Bioenergy”:

284 

Issued August 12, 1999, EO 13134 develops a comprehensive national strategy, including 

research, development, and private sector incentives, to stimulate the creation and early 

adoption of technologies needed to make bio-based products and bioenergy cost-competitive in 

large national and international markets. 

□ Executive Order 13148 “Greening the Government Through Leadership in Environmental 

Management”:

285 Issued April 22, 2000, EO 13148 encourages integrating environmental 

accountability into agency day-to-day decision-making and long-term planning processes, across 

all agency missions, activities, and functions. It stresses that environmental management 

considerations must be a fundamental and integral component of Federal Government policies, 

operations, planning, and management. 

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□ Executive Order 13221 “Energy-Efficient Standby Power Devices”:

286 Signed on July 31, 2001, 

EO 13221 calls for Federal agencies to purchase products that use minimal standby power when 

possible. 

□ Executive Order 13423 “Strengthening Federal Environmental, Energy, and Transportation 

Management”:

287 Signed on January 24, 2007, EO 13423 mandates new sustainability goals for 

the federal government that match or exceed previous statutory and EO requirements. It 

mandates an annual 3 percent reduction and cumulative 30 percent reduction in energy intensity 

by 2015 (compared to a fiscal year 2003 baseline) and requires that 50 percent of current 

renewable energy purchases come from new renewable sources—sources that have been 

developed after January 1, 1999. This requirement seeks to reduce GHG emissions and 

achieve in 10 years the same level of energy efficiency improvement that federal agencies 

achieved in the last 20 years. EO 13423 is 50 percent more stringent than the requirements of 

EPAct of 2005. 

□ Executive Order 13432 “Cooperation Among Agencies in Protecting the Environment With 

Respect to Greenhouse Gas Emissions From Motor Vehicles, Nonroad Vehicles, and Nonroad 

Engines”: Signed on May 14, 2007, EO 13432 requires EPA to protect the environment with 

respect to GHG emissions from motor vehicles, non-road vehicles, and non-road engines. The 

Order calls for EPA to work in collaboration with the U.S. Department of Transportation (DOT) 

and the DOE in conducting research and developing policy. Key considerations in developing 

policy include sound science, analysis of costs and benefits, public safety, and economic growth. 

□ Greening EPA:

288 EPA continuously works to reduce the environmental impact of its facilities 

and operations, from building new, environmentally sustainable structures to improving the 

energy efficiency of older buildings. EPA is striving to significantly reduce its reliance on energy 

sources that emit GHGs. For more information, go to www.epa.gov/greeningepa. The EPA 

purchases Green Tags to offset 100 percent of its energy use in EPA facilities nationwide. The 

EPA strives to acquire alternative fuel vehicles, reduce its use of petroleum fuel, (improving its 

own fleet fuel efficiency by 3 percent annually) and encourage private sector organizations to 

follow its lead. Go to www.epa.gov/greeningepa/greenfleet for more information. 

□ National Clean Diesel Campaign (NCDC): The NCDC is a public-private partnership that 

collaborates with businesses, government and community organizations, industry, and others to 

reduce diesel emissions. NCDC is a program within EPA’s Office of Transportation and Air 

Quality (OTAQ); contacts are in each EPA region. For more information, go to 

www.epa.gov/cleandiesel. 

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APPENDIX III: SOLAR POWER 

MORE SOLAR PV TERMS AND DEFINITIONS 

Azimuth Horizontal angle between a point in the sky and true north 

(Fig. 50). To optimize annual energy production, solar arrays 

should be oriented to face true south, i.e., with an azimuth of 180 ̊.

Insolation Amount of solar energy received on a given area over time 

measured in kilowatt-hours per square meter (kWh/m2

).290 

Irradiance The direct, diffuse, and reflected solar radiation that strikes 

a surface. Usually expressed in kilowatts per square meter 

Figure 50 Azimuth. Image 

courtesy CSI289 

(kW/m2

). Irradiance multiplied by time is insolation.291 

Peak Sun Hours Peak sun hours are the hours equivalent to the number of hours per day with solar 

irradiance equaling 1,000 W/m2

. To determine peak sun hours, determine the energy from total 

sunlight throughout the day. Next, determine how many hours with solar irradiance equaling 

1,000 W/m2

 this equates to. This is equal to peak sun hours. In other words, six peak sun hours 

means that the energy received during total daylight hours equals the energy that would have 

been received had the sun shone for six hours with an irradiance of 1,000 W/m2

.

292 

Tilt Angle Angle between the horizontal and the 

solar panel (Fig. 51). For maximum average 

annual insolation for a fixed-tilt PV system, 

the tilt angle should be equal to the latitude of 

the site. For maximum average insolation in 

summer months, the tilt angle should be 

equal to the latitude minus 15 ̊. For 

maximum average insolation in winter 

months, the tilt angle should be equal to the 

latitude plus 15 ̊.

For more solar energy terms, go to EERE’s Solar Glossary 

(www1.eere.energy.gov/solar/solar_glossary.html). 

SOLAR PV TECHNOLOGY 

Solar Cell294 

PV cells are composed of at least two layers of semiconductor material, commonly silicon. Silicon 

has a valence of four, meaning that there are four electrons in its outer orbital. Each silicon atom 

shares one of its valence electrons with each of its closest neighboring atom in a covalent bond. 

Figure 51 Tilt angle. Image courtesy Solar On-Line293 

Appendix III: Solar Power 128 
These electrons can be knocked loose by a photon, 

creating an electron-hole pair. The “hole” refers to 

the positive charge created by the loss of the freed 

electron. Electrons and holes can migrate given an 

electric field within the material. The strength of the 

current depends on the concentration density of free 

electrons and holes. A small fraction of the silicon 

atoms can be substituted with a different element, a 

process known as doping. An “n” type 

semiconductor is doped with an element having 5 

valence electrons, usually phosphorus, making the Figure 52 Substituting a phosphorus atom (with layer negatively charged (Fig. 52). five valence electrons) for a silicon atom in a silicon 

crystal leaves an extra, unbonded electron that is A “p” type semiconductor is doped with boron which relatively free to move around the crystal. Image

has three valence electrons to create holes. A small courtesy EERE295 

amount of these impurities in the silicon does not 

alter the lattice structure but allows 

electrons on the n-type to be more easily 

freed and creates holes on the p-type 

semiconductor. Photons striking the cell 

releases electrons from the negative layer 

and they flow towards the positive layer 

(Fig. 53). A metal wire is placed 

separately on the p and n side to power a 

load with the induced current. 

Series and Parallel Circuits 

Each PV module is rated at a certain 

voltage and amperage. A 50-watt PV 

module is nominally 12 volts (DC) and three amps in full sun.297 PV modules can be wired together 

to obtain different volts and amps to better suit the electricity needs of the site (Fig. 54). By wiring 

modules or batteries in series, voltage additively increases while amps do not change. Wiring 

modules or batteries in parallel will increase amps additively but voltage stays the same. To obtain 

required amps and voltages, modules and batteries may be wired with a combination of series and 

parallel circuits.298 

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Figure 53 The pn-junction of a solar PV cell. Image courtesy 

Special Materials and Research Technology296 

Appendix III: Solar Power 129 
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Figure 54 Parallel circuit (left) and series circuit (right). Images courtesy Solar On-Line299 

Batteries 

A battery is defined as two or more electrochemical cells enclosed in a container and electrically 

interconnected in an appropriate series/parallel arrangement to provide the required operating 

voltage and current levels. 300 Batteries can be used with any renewable energy system to store 

electricity for later use when the renewable energy system is not generating enough energy for a 

cleanup site’s operations. For sites that are not grid-tied, batteries should be included in the 

renewable energy project if a constant electricity source is necessary. In these cases, the 

renewable energy system must be sized to provide enough electricity to power your site as well as 

charge the battery. Sites that are grid-tied can still consider including a battery to reduce reliance on 

the grid. There are many types of rechargeable batteries that can be used with your project. The 

two main categories of battery technology are lead-acid and alkaline. Lead-acid batteries are used 

with most renewable energy projects.301 

Lead-Acid: Lead-acid batteries are rechargeable, widely available, relatively inexpensive compared 

to alkaline batteries, easily maintained, and has comparable longevity for the price. Lead-acid 

batteries are distinguished between deep cycle and shallow cycle batteries. 302 

Deep cycle: Lead-acid deep cycle batteries may be discharged for an extended amount of time up 

to 80 percent of their rated capacity and are compatible with renewable energy projects. Two 

types of deep cycle lead acid batteries are liquid electrolyte and captive electrolyte batteries. 

Lead-acid deep cycle liquid electrolyte: Liquid electrolyte batteries are found on golf carts and 

forklifts. Most renewable energy systems use these batteries (Fig. 55). They vent hydrogen gas 

that is produced as the battery nears full charge. Some batteries may require periodic filling as 

water is lost through the vent. A properly sized and maintained deep-cycle liquid electrolyte 

lead-acid batter will last 3-10 years. The life of a battery depends on temperature and how 

deeply the batteries are discharged. A battery cycle is one complete discharge and 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Figure 55 Liquid electrolyte lead-acid battery. Image 

courtesy Solar On-Line303 

charge. Batteries that operate on a cycle 

that discharges to 50 percent of capacity will 

last about twice as long as batteries that are 

discharged to 80 percent.304 

Lead-acid deep cycle captive electrolyte: 

Captive electrolyte batteries do not have a 

vent for electrolytes to escape. Therefore 

they require minimal maintenance though 

they are about twice as expensive as liquid 

electrolyte batteries. Less power is 

available in cold temperatures and high 

temperatures decrease battery life. 

Shallow Cycle: Shallow cycle batteries, like car 

batteries, are discharged for a very short 

duration and are not recommended for 

renewable energy system use. 

Alkaline Batteries: Alkaline batteries have higher voltages compared to lead acid batteries. They 

are not as effected by temperatures, can be deeply discharged, and have a useful life of about 

30 years. They are significantly more expensive than lead-acid batteries. These are 

recommended for remote areas with extreme temperatures in cases where costs are not the 

most important issue.305 

To properly size a battery for a renewable energy system, one must consider the following:306 

Days of autonomy This refers to the number of days a battery system will provide enough energy for 

a load without recharging 

Battery capacity Battery capacity is rated in amp-hours (AH). Theoretically, a “100 AH battery” will 

deliver one amp for 100 hours or roughly two amps for 50 hours before the battery is considered 

fully discharged. 

Rate and depth of discharge The rate at which a battery is discharged directly affects its capacity. 

Discharging a battery over a shorter amount of time decreases its capacity. The depth of 

discharge refers to how much electricity is withdrawn from the battery. Shallow depths of 

discharge, which is to draw little energy from the battery compared to the battery capacity, 

prolongs battery life. 

Life expectancy Life expectancy for batteries is measured in number of cycles (one discharge and 

one charge). Batteries lose capacity over time and are considered to be at the end of their lives 

when 20 percent of their original capacity is lost. 

Environmental conditions Battery capacity is reduced at extreme temperatures. 

Appendix III: Solar Power 131 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

To estimate the number of batteries you would need, look at the specifications offered for a battery 

and use the following equations (Fig. 56). 

Figure 56 Estimate number of batteries needed. Image courtesy Solar On-Line307 

Controllers308 

Controllers prevent batteries from being overcharged by the PV system and overly discharged by the 

load. The size of the controller is measured by its amps. Controllers can be wired in parallel if high 

currents are necessary. There are four different types of PV controls: 

• Shunt Controllers -- Shunt controllers are designed for small systems and prevent 

overcharging by “shunting” or by-passing the batteries when they are fully charged. Excess 

power is converted into heat. 

• Single-stage Controllers – Single-stage controllers switch the current off when the battery 

voltage reaches a certain pre-set value and reconnect the array and battery if the voltage 

falls below a certain value. 

• Multi-stage Controllers -- Multi-stage controllers establish different charging currents 

depending on the battery’s state-of-charge. 

• Pulse Controllers – Pulse controllers rapidly switch the full charging current on and off when 

the battery voltage reaches the pre-set charge termination point. 

Inverters309 

Inverters are necessary to change DC electricity produced by PV modules and stored in batteries to 

alternating current for use in AC loads. They are also needed to feed electricity into the utility grid. 

For grid-tied PV systems, contact the utility for inverter requirements. 

Optimal features of an inverter: 

• High efficiency – converts 80 percent or more of direct current input into alternating current 

output 

• Low standby losses – highly efficient when no loads are operating 

• High surge capacity – able to provide high current often required to start motors or run 

simultaneous loads 

• Frequency regulation – maintains 60 Hertz output over a variety of input conditions 

Appendix III: Solar Power 132 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

• Harmonic distortion – can “smooth out” unwanted output peaks to minimize harmful heating 

effects on appliances 

• Serviceability – easily field-replaced modular circuitry 

• Reliability – provide dependable long-term low maintenance service 

• Automatic warning or shut-off – protective circuits which guard the system 

• Power correction factor – maintains optimum balance between power source and load 

requirements 

• Lightweight – to facilitate convenient installation and service 

• Battery charging capability – allows the inverter to be used as a battery charger 

• Low cost – inverters are about $700 per kW 

Inverter Types 

Inverters can be sorted into two categories. Synchronous (also known as line-tied) inverters are 

used with grid-tied PV systems. Static inverters are used with non-grid-tied PV systems. 

Inverters also produce different wave forms: 

• Square Wave Inverters – appropriate for small resistive heating loads, some small 

appliances and incandescent lights 

• Modified Sine Wave Inverters – appropriate for operating motors, lights, and standard 

electronic equipment 

• Sine Wave Inverters – appropriate for sensitive electronic hardware 

MORE QUESTIONS TO ASK YOUR POTENTIAL SOLAR INSTALLER310 

• Is the company a full service or specialty firm? 

• How long has the company been in business? 

• How many projects like yours have they completed in the past year? In the past three 

years? 

• Can they provide a list of references for those projects? 

• What PV training or certification do they have? 

• What can they tell you about local, state and national incentives? 

• How much do they know about zoning and electrical requirements and codes? 

• Do they offer adequate warranties? 

• Does the company carry workers’ compensation and liability insurance? Do their 

subcontractors, if applicable, carry liability insurance? Can they show you a copy of their 

policy? 

• What permits are needed for this project? Who is going to obtain and pay for them? 

• If applicable, will the city require a structural review of the roof by an architect or professional 

engineer? Who will pay for this service? 

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• Will they provide written guarantees on all materials and workmanship? 

• What is the exact schedule of payments to be made? Besides materials and labor, does the 

estimate include sales tax, permit fees, structural analysis fees, interconnection fees, and 

shipping costs? 

• How soon can they respond to a service call if the PV system is not working properly? Would 

they be the one to repair the system? 

• What service do they offer after installation? Do they offer updates of manuals and 

catalogues?

• Ask for a cost estimate. Do they include the type of mounting requested, type of solar PV, 

etc? Ask for peak and average kW output estimates for specific conditions and seasons 

(sunny, summer, etc.) to be included in the bid. For battery systems, ask for specifications 

on battery capacity, recharging times, and the recharging cycle that will be used. Less 

expensive estimates may not include a service or device or may have hidden costs. 

CONCENTRATED SOLAR POWER (CSP)312 

Concentrated solar power technology can also convert 

solar power into electricity. Mirrors are oriented to focus 

heat from the sun to heat a liquid or gas in a tube to very 

high temperatures (Fig. 57). Energy from the liquid or 

gas can then be utilized in steam engine generators. 

CSP technology is less expensive than PV. However, 

current concentrated solar power projects are usually 

constructed at a large scale of greater than one MW, and 

may exceed the electrical needs of a cleanup. 

Companies that tailor CSP projects for industrial sectors 

are emerging. Go to www.nrel.gov/learning/re_csp.html 

for more information. 

Figure 57 Parabolic-trough concentrating 

solar power system. Image courtesy NREL311 

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APPENDIX IV: WIND POWER 

WIND TECHNOLOGY 

Extracting Energy from Wind 

The theoretical maximum efficiency for a wind turbine is 59 percent (the Betz limit). It is not possible 

to extract all the energy from wind. If total kinetic (motion) energy were extracted, there would be no 

wind passing through the turbine. You would need a solid disk to trap all the wind. But if this were 

the case, the wind would blow around the solid disk and no energy would be captured. Thus, wind 

blades can extract only a portion of the total wind energy.313 

When air passes over a wind turbine’s blade, it travels faster over the top of the blade than it does 

below. This makes the air pressure above the blade lower than it is underneath. Due to the unequal 

pressures the blade experiences a lifting force, causing the blades to spin. Since the wind turbine 

captured some kinetic energy from the wind, wind blows more slowly downwind of the turbine.314 

Towers315 

A general rule of thumb is to install a wind turbine on a tower with the bottom of the rotor blades at 

least 30 feet (9.1 meters) above any obstacle that is within 300 feet (91 meters) of the tower. 

Relatively small investments in increased tower height can yield very high rates of return in power 

production. For instance, a 10-kW turbine on a 100-foot tower costs 10 percent more than a 10-kW 

turbine on a 60-foot tower, but it can produce 29 percent more power. 

There are two basic types of towers: self-supporting (free 

standing) and guyed. Most small wind power systems use 

a guyed tower. Guyed towers, which are the least 

expensive, can consist of lattice sections, pipe, or tubing 

(depending on the design), and supporting guy wires (Fig. 

58). They are easier to install than self-supporting towers. 

However, because the radius of the circle created by guy 

wires must be one-half to three-quarters of the tower height, 

guyed towers require enough space to accommodate them. 

You may also opt to install tilt-down towers (Fig. 59), which 

lower the system to the ground for maintenance or during 

hazardous weather such as hurricanes. Although tilt-down 

towers are more expensive, they offer the consumer an 

easy way to perform maintenance on smaller light-weight 

turbines, usually 5-kW or less. 

Figure 58 A 10-kW wind turbine with guyed 

lattice tower. Image courtesy NREL316 

Appendix IV: Wind Power 135 
Aluminum towers are prone to 

cracking and should be avoided. 

Most turbine manufacturers 

provide wind energy system 

packages that include towers. 

Mounting turbines on rooftops is 

not recommended since 

vibrations from the turbines may 

damage buildings. This can 

lead to noise and structural 

problems with the building. 

Rooftops can also cause 

excessive turbulence that can 

shorten the life of a turbine. 

CALCULATING WIND TURBINE OUTPUT POWER 

See Box 11 for equations on estimating wind turbine output power with assumptions of blade length. 

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 Figure 59 Tilt-down tower schematic. Image courtesy EERE317 

Box 11 Wind Turbine Output Power318 

Step 1: Calculate swept area 

A = 3.14 ∗ r2 

A = swept area 

r = radius, length of one blade, one-half of the diameter of the rotor 

Step 2: Calculate power in the swept area 

P = 0.5 ∗ ρ ∗ A ∗ V3 

P = power in watts (746 watts = 1 hp) (1,000 watts = 1 kilowatt) 

ρ = air density (about 1.225 kg/m3

 at sea level, less higher up) 

A = swept area (m2

) 

V = wind speed in meters/sec (20 mph = 9 m/s) (2.24 mph = 1 m/s) 

Step 3: Calculate wind turbine power 

P = 0.5 ∗ ρ ∗ A ∗ Cp ∗ V3 ∗ Ng ∗ Nb 

P = power in watts (746 watts = 1 hp) (1,000 watts = 1 kilowatt) 

ρ = air density (about 1.225 kg/m3

 at sea level, less at higher altitudes) 

A = swept area (m2

) 

Cp = Coefficient of performance (0.59 [Betz limit] is the maximum theoretically 

possible, 0.35 for a good design) 

V = wind speed in m/s (20 mph = 9 m/s) 

Ng = generator efficiency (0.50 for car alternator, 0.80 or possibly more for a 

permanent magnet generator or grid-connected induction generator) 

Nb = gearbox/bearings efficiency (depends, could be as high as 0.95)

Appendix IV: Wind Power 136 
 

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APPENDIX V: LANDFILL GAS-TO-ENERGY 

PRELIMINARY EVALUATION WORKSHEET 

Use the following worksheet to complete a preliminary feasibility evaluation of a LFGE project for an 

MSW landfill. (Worksheet created by LMOP) 

Landfill Gas to Energy Project Preliminary Evaluation Worksheet319 

A. Is your landfill a municipal solid waste landfill? 

If not, you may encounter some additional issues in project development due to the presence of hazardous or nonorganic waste in the landfill. Stop and consult an energy recovery expert. 

B. Add your score for the next three questions: 

1. How much MSW is in your landfill? 

Tons Score 

Greater than 3 million 40 

1-3 million 30 

 0.75-1 million 20 

Less than 0.75 million 10 +Score____ 

2. Is your fill area at least 40 feet deep? 

Yes = 5 

No = 0 +Score____ 

3. Is your landfill currently open? If yes, answer 3(a). If no, answer 3(b). 

(a) How much waste will be received in the next 10 years? For each 500,000 tons, score 5 points. 

Total tons ÷ 500,000 tons x 5 points = +Score____ 

(b) If closed for less than one year, enter 0. If closed for one year or more, multiply each year since the 

closure by 5, and subtract that amount from the total score 

Years since closure x 5 points = -Score____ 

Total your answers to questions 1-3: Total Score____ 

C. If your score is: 

≥ 30: Your landfill is a good candidate for energy recovery (go to section D). 

20-30: Your landfill may not be a good candidate for conventional energy recovery option. However, you may want to 

consider on-site or alternative uses for the landfill gas. 

D. If your landfill is a good candidate, answer the following two questions: 

1. Are you now collecting gas at your landfill (other than from perimeter wells), or do you plan to do so soon for 

regulatory or other reasons? If yes, your landfill may be an excellent candidate for energy recovery. 

2. (a) Is annual rainfall less than or equal to 25 inches a year? 

(b) Is construction and demolition waste mixed into the municipal waste or is it a large portion of total waste? 

If YES to questions D.2(a) or (b), your annual landfill gas production may be lower than otherwise expected. Your 

landfill may still be a strong candidate, but you may want to lower your estimated gas volumes slightly during project 

design and evaluation. 

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COMBINED HEAT AND POWER (CHP) 320 

Combined heat and power, also known as cogeneration, is an approach that increases efficiency 

from prime movers by generating and utilizing both electricity and heat. In conventional electricity 

generation, the electricity produced is utilized but the co-produced heat is often wasted. About 75 

percent of fuel energy input into an engine is output as heat. In CHP applications, this waste heat is 

captured for space heating, water heating, steam generation to run a steam turbine, and cooling. 

Heat exchangers can recover up to 7,000 BTUs of heat per hour for each KW of the generator load. 

Utilizing waste heat can increase efficiency to 40-50 percent. 

Go to EPA’s Combined Heat and Power Partnership website (www.epa.gov/chp/) and see the 

EPA’s Combined Heat and Power Partnership Catalogue of CHP Technologies 

(www.epa.gov/CHP/basic/catalog.html) for more information. 

ELECTRICITY GENERATION 

Details are provided below for the prime movers mentioned this guide. These include reciprocating 

engines, gas turbines, microturbines, boilers and steam engines, and fuel cells. 

Reciprocating Engines / Internal Combustion (IC)Engine 

Reciprocating engines, also called internal 

combustion engines, are a widespread 

and well-known technology. They require 

fuel, air, compression, and a combustion 

source to function. The two categories 

they generally fall into are (1) sparkignited engines, typically fueled by 

gasoline, natural gas or landfill gas, and 

(2) compression-ignited engines, typically 

fueled by diesel fuel.322 Figure 60 Reciprocating engine cycle. Image courtesy EERE321 

How Does a Reciprocating Engine Work? 

Four-stroke spark-ignited reciprocating engine process (Fig. 60):323 

Intake: As the piston moves downward in its cylinder, the intake valve opens and the upper portion 

of the cylinder fills with fuel and air. 

Compression: When the piston returns upward in the compression cycle, the spark plug emits a 

spark to ignite the fuel/air mixture. 

Power: The piston is forced down, thereby turning the crank shaft and producing power. 

Exhaust: The piston moves back up to its original position and the spent mixture is expelled through 

the open exhaust valve. 

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Applicability 

Reciprocating engines can be used for landfill gas or biogas and are used in a wide variety of 

applications because of their relatively small size, low unit costs, and useful thermal output. For 

power generation, reciprocating engines are available in sizes ranging from a few kilowatts to over 5 

MW.324 The main advantage of reciprocating engines as compared to other power generation 

technologies is a better heat rate at lower capacities. Heat rate is the amount of gas needed to 

generate one kWh of electricity, and is closely related to system efficiency. The heat rate for a 

typical reciprocating engine plant is 10,600 BTU/kWh.325 Another advantage of reciprocating 

engines is that the units are available in different incremental capacities, which makes it easy to 

tailor the IC engine size to the specific gas production rates of a landfill or digester. 

Reciprocating engines are the most widely used prime movers for LFG-fired electric power 

generation.326 Worldwide, there are more than 200 LFG-fired reciprocating engine power plants.327 

Reciprocating engines with power output from 0.1 MW to 3.0 MW have been proven suitable with 

landfill gas.328 

Disadvantages of Reciprocating Engines 

An important disadvantage of reciprocating engines is that they produce higher emissions of NOx, 

CO, and NMOCs than other electric power generation technologies. However, significant progress 

has been made in reducing NOx emissions in recent years. A second disadvantage to reciprocating 

engines is that their operation/maintenance costs on a per kWh basis are higher than for other 

power generation technologies. In general, reciprocating engines require a relatively simple LFG or 

biogas pretreatment process consisting of compression and removal of free moisture.329 Water 

droplets are removed by the use of simple moisture separators (knockout drums), cooling of the 

biogas in ambient air-to-gas heat exchangers, and coalescing-type filters. Through compression 

and cooling, some of the NMOCs in the LFG are removed. The reciprocating engines can require 3­

60 pounds per square inch gauge (psig) of fuel pressure.330 

Information Resources 

□ EERE Distributed Energy Program Web Page: More information on gas-fired reciprocating 

engines. www.eere.energy.gov/de/gas_fired/ 

□ The California Energy Commission’s Distributed Energy Resource Guide: More information on 

performance, costs, strengths and weaknesses, and vendors of electricity generation equipment. 

www.energy.ca.gov/distgen/equipment/equipment.html 

Combustion (Gas) Turbine (CT) 

Landfill gas, digester biogas, and gasifier syngas can be used in gas turbines to produce heat and 

electricity. Gas turbines are heat engines that use high-temperature, high-pressure gas as the fuel. 

A portion of the heat supplied by the gas is converted directly into mechanical work. 

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How Does a Gas Turbine Work? 

High-temperature and high-pressure gas rushes out of the combustor and pushes against the 

turbine blades, causing them to rotate. Gas turbines are often referred to as "combustion" turbines 

because in most cases, hot gas is produced by burning a fuel in air. Gas turbines are used widely in 

industry, universities and colleges, hospitals, and commercial buildings because they are compact, 

lightweight, quick-starting, and simple to operate.331 Simple-cycle gas turbines convert a portion of 

input energy from fuel to electricity. The remaining energy produces heat which is normally expelled 

into the atmosphere. Simple-cycle turbines have efficiencies of 21-40 percent.332 Combined-cycle 

gas turbines utilize high-quality waste heat to generate steam to power another turbine. The waste 

heat can also be used for cooling (e.g., absorption chillers), space or water heating, and other power 

applications. When taking advantage of the normally wasted heat, efficiencies increase to nearly 90 

percent in some cases.333 

Advantages and Disadvantages of a Gas Turbine 

The main advantages of a CT as compared to a reciprocating engine are its lower air emissions and 

lower operation/maintenance costs. The main drawback to the combustion turbine is its high net 

heat rate. Combustion turbine net heat rates vary from 12,200 BTU per kWh to 16,400 BTU per 

kWh. Larger, new combustion turbines are more fuel efficient. Combustion turbines require a higher 

pressure fuel supply than reciprocating engines of 150-250 psig. Two stages of LFG compression 

are employed. Particles in the LFG have sometimes caused problems with the combustion turbine’s 

fuel injection nozzles. A small water wash scrubber is normally provided in the pretreatment process 

to prevent this problem. 334 

For more information performance, costs, strengths and weaknesses, and vendors of electricity 

generation equipment, see The California Energy Commission’s Distributed Energy Resource Guide 

(www.energy.ca.gov/distgen/equipment/equipment.html). 

Microturbines 

Microturbines are a relatively new technology. They are small combustion turbines, approximately 

the size of a refrigerator, with outputs of 30-250 kW.335 Microturbines are best suited for relatively 

small applications that are less than 1 MW and for on-site electricity use or distribution to sites in 

close proximity.336 They can be powered using landfill gas, digester biogas, or natural gas. 

Microturbines are ideal for LFGE or digester projects with low gas production or low methane 

concentration. A 30-kW microturbine can power a 40-hp motor or supply energy to about 20 

homes.337 

How do Microturbines Work? 

Landfill gas, biogas, or other fuel, is supplied to the combustor section of the microturbine at 70-80 

psig of pressure. Air and fuel are burned in the combustor, releasing heat that causes the 

combustion gas to expand. The expanding gas powers the gas turbine that in turn operates the 

generator; the generator then produces electricity. To increase overall efficiency, microturbines are 

typically equipped with a recuperator that preheats the combustion air using turbine exhaust gas. A 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

microturbine can also be fitted with a waste heat recovery unit for auxiliary heating applications. 

They are different from traditional combustion turbines because they spin at much faster speeds.338 

Applicability339 

Microturbines provide advantages over other electrical generation technologies for landfills in cases 

where: 

• LFG or biogas flow is low. 

• LFG or biogas has low methane content. 

• Air emissions, especially NOx, are of concern (i.e., in NOx nonattainment areas where the 

use of reciprocating engines might be precluded). 

• Electricity produced will be used for on-site facilities rather than for export. 

• Electricity supply is unreliable and electricity prices are high. 

• Hot water is needed on-site or nearby. 

Advantages 

Compared to other IC engines, gas turbines and boiler steam-engine sets, microturbines have the 

following advantages. 

• Portable and easily sized. 

• Compact and fewer moving parts. 

• Require minimal operation and maintenance. 

• Use of air bearings coupled with air-cooled generator eliminates the need for lubrication and 

liquid cooling systems. 

• Lower pollutant emissions (e.g., NOx emissions levels from microturbines are typically less 

than one-tenth of those best-performing reciprocating engines and lower than those from 

LFG flares). 

• Ability to generate heat and hot water. 

Microturbine Concerns340 

Microturbine long-term reliability and operating costs are not yet confirmed. They also have lower 

efficiencies than reciprocating engines and other types of turbines, by as much as 55 percent. 

Microturbines are more sensitive to siloxane contamination, so LFG needs more pretreatment 

measures to be used in a microturbine than in conventional engines. 

For More Information on Microturbines 

□ EERE Distributed Energy Program Web Page : General information on microturbines. 

www.eere.energy.gov/de/microturbines/ 

□ “Powering Microturbines with Landfill Gas” (EPA, LMOP): LFG-powered microturbine factsheet. 

www.epa.gov/lmop/res/pdf/pwrng_mcrtrbns.pdf 

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□ The California Energy Commission’s Distributed Energy Resource Guide: More information on 

performance, costs, strengths and weaknesses, and vendors of electricity generation equipment. 

www.energy.ca.gov/distgen/equipment/equipment.html 

Boilers and Steam Engines 

Boilers and steam engines may use landfill gas, biogas, or syngas to produce electricity. They are 

often most applicable for projects that can produce enough fuel for more than 10 MW of power. 

Since the steam cycle power plant emit lower air emissions than either reciprocating engines or 

combustion turbines, steam cycles have been preferred in regions with stringent air quality 

regulations, even when the size of the plant was relatively small.341 While landfills usually produce 

less than 10 MW, more than 60 organizations in the U.S. are operating their boilers with LFG.342 

The steam cycle is at an economic disadvantage when compared to reciprocating engines and 

combustion turbines although the steam cycle power plant becomes more cost competitive as the 

size of the plant increases.343 Net heat rates for the steam cycle are in the range of 11,000 BTU per 

kWh to 16,500 BTU per kWh. Steam cycles with higher temperature (1,000 ̊F) and pressure (1,350 

psig), air preheaters, and up to five stages of feedwater heating, increase efficiency. The least 

efficient units operate at low temperature (650 ̊F) and pressure (750 psig), and are not equipped 

with air preheaters or feedwater heaters. 344 

See LMOP’s factsheet, “Adapting Boilers to Utilize Landfill Gas” for more information 

(www.epa.gov/lmop/res/pdf/boilers.pdf). 

Fuel Cells 

Similar to a battery, fuel cells create electricity through the process of an electro-chemical reaction. 

This clean technology’s byproducts are water and heat. The applicability of fuel cell use for is not 

widely established for landfill gas, biogas, and syngas. See the California Energy Commission 

website on fuel cells for more information: 

www.energy.ca.gov/distgen/equipment/fuel_cells/fuel_cells.html. 

Appendix V: Landfill Gas-to-Energy 142 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

APPENDIX VI: ANAEROBIC DIGESTION 

PRELIMINARY EVALUATION CHECKLIST FOR MANURE FEEDSTOCK 

Checklist to Assess Digester Potential345 

1. Facility Characteristics 

a. Do you have at least 500 cows/steer or 2,000 pigs at your facility? Yes □ No □

b. Are the animals confined year-round? Yes □ No □

c. Is the animal population stable (varies less than 20% in a year)? Yes □ No □

If the answer is YES to all the above questions, your facility is in good shape. Proceed to the next section. If the 

answer is NO to one or more of the above questions, the production and utilization of biogas as a fuel may not be 

suitable for your facility. For biogas production and utilization to succeed, a continuous and relatively consistent 

flow of biogas is required. 

2. Manure Management 

a. Is manure collected as a liquid (solids less than 4%), a slurry (solids less than 10%), 

or a semi-solid (solids less than 20%)? Yes □ No □

b. Is the manure collected and delivered to one common point? Yes □ No □

c. Is manure collected daily or every other day? Yes □ No □

d. Is the manure relatively free of clumps of bedding, rocks, stones, and straw? Yes □ No □

If the answers are YES to all the above questions, manure management criterion is satisfied. If the answer is NO to 

any of the questions, you may need to change your manure management routine. 

3. Energy Use 

a. Are there on-site uses for the energy recovered such as for heating, electricity, 

or refrigeration? Yes □ No □

b. Are there nearby facilities that could use the biogas? Yes □ No □

c. Are there electric utilities in your area that are willing to buy power from 

biogas projects? Yes □ No □

If the answer is YES to any of the above questions, the energy use criterion is satisfied for initial screening purposes. 

4. Management 

a. Is there a person available on the farm who can operate and maintain the 

technical equipment? Yes □ No □

b. If YES, can this person spend about 30 minutes a day to manage the system 

 and 1-10 hours on occasional repair and maintenance? Yes □ No □

c. Will this person be available to make repairs during high labor use 

events at the farm? Yes □ No □

d. Is technical support (access to repair parts and services) available? Yes □ No □

e. Will the owner be overseeing system operations? Yes □ No □

If the answers are YES to all questions, there are promising options for gas recovery. Review the AgStar Handbook 

Chapter 3 (www.epa.gov/agstar/pdf/handbook/chapter3.pdf) to determine technical and economic feasibility of 

the project. If the answer was NO to any of the questions, you may need to make some changes. Evaluate the 

cost of the required changes before proceeding. 

Appendix VI: Anaerobic Digestion 143 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

lbs(VS) lb(VS)destroyed ft 3biogas =1,000cows×10 ×60% ×12 

cow − day lb(VS) lb(VS)destroyed 

= 72,000 ft 3

biogas ×50% ft 3 methane 

×1,000 BTU 

day ft 3

biogas ft 3 methane 

BTU 1kWh 1day = 36,000,000 × ×

day 14,000BTU 24hours 

$2,500 =107kW ×

kW 

CALCULATING ENERGY POTENTIAL IN DAIRY MANURE346 

How Much Power Can be Generated from 1,000 Dairy Cows? 

Step 1: How much biogas can be produced from a farm with 1,000 dairy cows? 

Assumptions: 

• One dairy cow weighing 1,000 pounds generates 10 pounds (dry weight) of volatile solids (VS) per 

day (Source: American Society of Agricultural Engineering Standard). 

• 60% of VS can be degraded during anaerobic digestion process. 

• 12 ft3

 of biogas can be generated per pound of VS destroyed. 

Volume of biogas produced daily: 

= 72,000 ft 3

biogas / day 

Step 2: What is the BTU content for the biogas produced from a farm with 1,000 cows? 

Assumptions: 

• Methane content in biogas is about 50%. 

• Energy content of methane is 1,000 Btu/ft3 

BTU content of the biogas produced: 

= 36,000,000BTU / day 

Step 3: How much power can be generated using the biogas produced from a farm with 1,000 cows? 

Assumption: 

• The efficiency of a biogas fueled engine is 24% (Engine-driven generator has a heat rate of ~14,000 

BTU/kWh) 

Power production from 1,000 cows: 

=107kW 

Step 4: What is the estimated capital cost to install an anaerobic digestion to electricity system for a farm with 

1,000 cows? 

Assumption: 

• The capital cost for an anaerobic digestion to electricity system is: $2,500 per kW. Note: Does not 

account for economies of scale. 

Total estimated capital cost to build an anaerobic digestion system for a farm with 1,000 cows: 

= $267,500 

Appendix VI: Anaerobic Digestion 144 
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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

DIGESTER BIOLOGY 

Anaerobic digesters produce methane from anaerobic bacteria breaking down organic material. 

Methane production in a digester is a three stage process (Fig. 61). First, bacteria decompose the 

organic matter into molecules such as sugar. Second, another group of bacteria convert the 

decomposed matter to organic acids. Finally, the acids are converted to methane gas by methaneforming bacteria.347 

Figure 61 Stages of biogas production. Courtesy Penn State University348 

Temperature is one of the most important factors in determining the rate of digestion and biogas 

production.349 Anaerobic bacteria communities thrive best at temperatures of about 98°F (36.7°C) 

(mesophilic) and 130°F (54.4°C) (thermophilic).350 Decomposition and biogas production occur 

faster in thermophilic conditions than in the mesophilic range. However, thermophilic bacteria are 

highly sensitive to disturbances, such as changes in feed materials or temperature. Mesophilic 

bacteria are less sensitive but the digester must be larger to accommodate for the longer HRT. 

Also, while all anaerobic digesters reduce the viability of weed seeds and pathogens, the higher 

temperatures of thermophilic conditions result in more complete destruction.351 In most areas of the 

United States, anaerobic digesters usually require some level of insulation and/or heating if outdoor 

temperatures are too low. Digesters can be heated by circulating the coolant from the biogaspowered engines in or around the digester. 

Other digestion rate and biogas production factors: 

pH: Optimum biogas production is achieved when the pH value of input mixture in the digester is 

between 6 and 7.352 In most digesters, the pH is self-regulating. Bicarbonate of soda can be 

added to the digester to maintain a consistent pH.353 

Carbon-to-nitrogen (C:N) ratio: A C:N ratio ranging from 20:1 to 30:1 is considered optimum for 

anaerobic digestion. Organic materials with high C:N ratio could be mixed with those with a low 

C:N ratio to bring the average ratio of the influent to a desirable level (Table 11). 354 

Appendix VI: Anaerobic Digestion 145 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Other factors that affect the rate and 

amount of biogas output include the 

liquid to solid ratio, mixing of the 

influent material, the particle size of 

the feedstock, and retention time. 

Pre-sizing and mixing of the feed 

material for a uniform consistency 

allows the bacteria to work more 

quickly. It may be necessary to add 

water to the feed material if it is too 

dry or if the nitrogen content is very 

high. Occasional mixing of the 

material inside the digester can aid 

the digestion process. Be aware that 

antibiotics in livestock feed may kill 

the anaerobic bacteria in digesters.356 

Table 11 Carbon to Nitrogen Ratio of Various Organic Materials355 

Organic Material C:N Ratio 

Cow manure 24:1 

Swine manure 18:1 

Chicken manure 10:1 

Duck manure 8:1 

Goat manure 12:1 

Sheep manure 19:1 

Straw (maize) 60:1 

Straw (rice) 70:1 

Straw (wheat) 90:1 

Sawdust >200:1 

SLUDGE OR EFFLUENT 

The digested organic material from an anaerobic digester is called sludge or effluent. It is rich in 

nutrients such as ammonia, phosphorus, potassium, and more than a dozen other trace elements.357 

Biomass digestion can also help reduce pathogens. For wastewater treatment sewage, operating 

digesters at mesophilic temperatures around 98-99 ̊F for 15 days results in 0.5-4.0 log reduction in 

fecal coliform, 0.5-2.0 log reduction in enteric viruses, and about 0.5 log reduction in protozoa and 

helminth ova. Operating digesters at thermophilic temperatures may reduce pathogens to nondetectable levels, depending on the solids-content and HRT (see 40 CFR 503.32(a) for 

calculations).358 The digester sludge can then be used as a soil conditioner. Effluent has also been 

used as a livestock feed additive when dried. Be aware that toxic compounds (e.g., pesticides) that 

are in the digester feedstock material may become concentrated in the effluent. Therefore, it is 

important to test the effluent before using it on a large scale.359 

Appendix VI: Anaerobic Digestion 146 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

APPENDIX VII: BIOMASS GASIFICATION 

HOW DOES GASIFICATION WORK?360 

The gasification process includes: (a) pre-treating the feedstock; (b) feeding it into the gasifier; (c) 

treating the generated syngas; (d) use of the syngas to produce electricity and heat; and (e) proper 

disposal of other byproducts. Inside the gasifier itself, biomass is added in either a dry form or 

mixed with water. The feedstock then reacts with steam and air or oxygen (O2) at high temperatures 

(up to 2,600oF) and pressure (up to 1,000 psig). To heat the gasifier, the char byproduct of 

gasification may be combusted.361 The feedstock undergoes three thermal and chemical processes 

within the gasifier. There are a few types of gasifiers (updraft, downdraft, bubbling fluidized bed, 

circulating fluidized bed) but the following processes occur in each type: 

1. Pyrolysis 

Pyrolysis is a chemical breakdown of complex compounds due to heat. It occurs as the organic 

matter heats up. Volatile substances such as tar, H2, and CH4 are released and a combustible 

residue resembling charcoal, called char, is produced. 

2. Oxidation 

Then, volatile products and some char are burned in a controlled manner to form CO2 and CO in 

a process called oxidation. 

3. Reduction 

Last, in the reduction stage, the char 

reacts with the CO2 and steam to produce 

CO and H2, with some CH4, which 

together make up syngas. The high 

temperature in the gasifier converts the 

inorganic materials left behind by 

gasification and fuses them into a glassy 

material, generally referred to as slag. 

The slag has the consistency of coarse 

sand. It is chemically inert and may have 

a variety of uses in the construction and 

building industries. 

TYPES OF GASIFIERS363 

Updraft Gasifier 

The updraft gasifier is the oldest and simplest 

type of gasifier (Fig. 62 ). It is also known as counter-current or counter-flow gasification. Biomass 

Figure 62 Updraft gasifier. 

Image courtesy United Nations362 

Appendix VII: Biomass Gasification 147 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

is introduced at the top of the gasifier while air intake is at the bottom. Syngas leaves at the top of 

the gasifier. 

Advantages: 

• Proven technology, low cost process. 

• Able to handle high moisture biomass and high inorganic content (e.g., municipal solid 

waste). 

• Low gas exit temperatures and high equipment efficiency. 

Disadvantages: 

• Syngas contains 10-20 percent tar by weight, requiring extensive syngas cleanup before 

engine, turbine, or synthesis applications. 

Downdraft Gasifier 

The downdraft gasifier is also known as 

cocurrent-flow gasification (Fig. 63). Like 

the updraft gasifier, biomass is introduced 

at the top but in this case air is introduced 

at or above the oxidation zone in the 

gasifier. The syngas is removed from the 

bottom. The high-temperature syngas 

exiting the reactor requires a secondary 

heat recovery system. 

Advantages: 

• Proven technology, low cost 

process. 

• Up to 99.9 percent of tar is broken 

down. 

• Lower level of organic 

components in the condensate, 

less environmental objections than updraft gasifiers.

Figure 63 Downdraft gasifier. 

Image courtesy United Nations364 

Disadvantages: 

• Requires low moisture content feedstock (<20 percent) which necessitates a dryer. 

• 4-7 percent of the carbon remains unconverted. 

• Low density feedstock materials may cause flow problems and excessive pressure drop and 

the fuel may require pelletizing before use. 

• May suffer from the problems associated with high ash content fuels (slagging) to a larger 

extent than updraft gasifier. 

Appendix VII: Biomass Gasification 148 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

• The necessity to maintain uniform high temperatures over a given cross-sectional area 

makes it impractical to use downdraught gasifiers in a power range above about 350 kW. 

Fluidized Bed Gasifier 

In a fluidized bed gasifier, air, oxygen, 

or steam is blown through a bed of 

solid particles, such as sand or 

alumina, at a sufficient velocity to keep 

them in a state of suspension (Fig. 64). 

The “fluidized” particles can quickly 

break up and heat the biomass. 

Advantages: 

• Feedstock flexibility due to 

easy control of temperature. 

• Can handle low density, fine 

grained feedstock (e.g., 

sawdust) without preprocessing. 

• Yields uniform product gas. 

• Suitable for rapid reactions. 

Disadvantages: 

• Poor response to load changes. 

Figure 64 Fluidized bed gasifier. Image courtesy United Nations365 

Appendix VII: Biomass Gasification 149 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

APPENDIX VIII: CLEANER DIESEL 

VERIFIED TECHNOLOGIES 

Use Table 12 to help evaluate which verified retrofit technologies are compatible with your off-road 

engines. Go to EPA’s Verified Technologies List (www.epa.gov/otaq/retrofit/verif-list.htm) and 

CARB’s Verified Diesel Emission Control Strategies List (www.arb.ca.gov/diesel/verdev/vt/cvt.htm) 

for technologies for on-road engines and stationary engines (e.g., electricity generators). 

The EPA’s Diesel Retrofit Program signed a memorandum of agreement (MOA) with CARB for the 

Coordination and Reciprocity in Diesel Retrofit Device Verification. The MOA establishes reciprocity 

in verifications of hardware or device-based retrofits, and further reinforces EPA's and CARB's 

commitment to cooperate on the evaluation of retrofit technologies. 

Acronyms 

*DPF: Diesel particulate filter 

*DOC: Diesel oxidation catalyst 

*EGR: Exhaust gas recirculation 

*LSD: Low sulfur diesel. Diesel fuel with less than 500 ppm sulfur content. 

*ULSD: Ultra-low-sulfur diesel. Diesel fuel with less than 15 ppm sulfur content. 

Table 12 Non-Road Verified Retrofit Technology Options 

Verified Technology for 

NON-ROAD Engines Minimum Engine Requirements Potentially Applicable 

Engines 

Caterpillar Inc. 

Passive DPF 

www.cat.com 

EPA verified 

http://www.epa.gov/otaq/retrofit/techli 

st-cat.htm#dpf 

Model year 1996-2005 

Turbocharged 

130 kW-225 kW 

Exhaust temperature of 260 ̊C for 40% of 

the cycle for NOx:PM ratios of less than or 

equal to 20:1 and for NOx:PM ratios equal 

to or greater than 25:1, only 200 ̊C for 

40% of the cycle is required 

Fueled with LSD 

Complete requirements: 

http://www.epa.gov/otaq/retrofit/documents/v 

erif-letter-cat2.pdf 

Any engine that meets 

“Engine Requirements” 

Engine Control Systems 

Combifilter 

Active DPF 

http://enginecontrolsystems.com 

CARB verified 

http://www.arb.ca.gov/diesel/verdev/l 

evel3/level3.htm 

Model year 2007 or older 

Engine displacement ≤12 liters 

Must be able to return to regeneration panel 

after 8-10 hours of operation 

Fueled with LSD 

Complete requirements: 

http://www.arb.ca.gov/diesel/verdev/level3/e 

o_de04012_01.pdf 

Must NOT belong to engine 

families found at 

http://www.arb.ca.gov/diese 

l/verdev/level3/ef_eode040 

12_01.pdf 

Appendix VIII: Cleaner Diesel 150 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

HUSS Umwelttechnik GmbH 

FS-MK Series 

Active DPF 

http://www.huss-umwelt.com/en/ 

CARB verified 

http://www.arb.ca.gov/diesel/verdev/l 

evel1/level1.htm 

Model year 2006 or older 

Complete Requirements: 

http://www.arb.ca.gov/diesel/verdev/level3/e 

o_de06007_01.pdf 

Must NOT belong to engine 

families found at 

http://www.arb.ca.gov/diese 

l/verdev/level3/ef_de06007 

_01.pdf 

Paceco Corporation 

Mitsui Engineering and Shipbuilding 

DPF 

Passive DPF 

http://www.pacecocorp.com/ 

CARB verified 

http://www.arb.ca.gov/diesel/verdev/l 

evel1/level1.htm 

Must be a rubber-tired gantry crane 

225 kW - 450 kW 

Achieves exhaust temperature of 250 ̊C or 

greater at least 50% of the time. 

Maximum consecutive minutes operating 

below passive regeneration temperature: 

120 mins 

Max exhaust temp: 550 ̊C 

Fueled with ULSD or ≤B20 

Complete Requirements: 

http://www.arb.ca.gov/diesel/verdev/ltrs/pac 

ecomesdpfeo.pdf 

Any engine that meets 

“Engine Requirements” 

Donaldson 

DCM DOC 

DOC 

http://www.donaldson.com/en/index.h 

tml 

CARB verified 

http://www.arb.ca.gov/diesel/verdev/l 

evel1/level1.htm 

Yard tractor, large lift trucks, top picks, side 

picks or gantry crane 

Model year 1996-2003 

150 hp-600 hp 

Complete Requirements: 

http://www.arb.ca.gov/diesel/verdev/eodonal 

dsondoc88_90.pdf 

Manufactured by the 

following companies AND 

listed in attachment below: 

Case Corporation 

Caterpillar 

Cummins 

Detroit Diesel 

Komatsu 

http://www.arb.ca.gov/diese 

l/verdev/level1/ef_donaldso 

n_offroad.pdf 

Engine Control Systems 

AZ Purifier and AZ Purimuffler 

DOC 

http://enginecontrolsystems.com/hom 

e.aspx 

CARB verified 

http://www.arb.ca.gov/diesel/verdev/l 

evel1/level1.htm 

Port, railway, or other intermodal/freight 

handling applications 

Model year 1996-2002 

Tolerate 20% reduced peak engine power 

No optical/conductive fuel sensors nor water 

absorbing fuel filters 

Must not use Bosch fuel pump VP30 nor 

VP44 

Certified at PM emissions between 0.01 

g/bhp-hr and 0.4 g/bhp-hr 

Fueled with ULSD 

Complete Requirements: 

http://www.arb.ca.gov/diesel/verdev/ltrs/azp 

urifieandpurimuffleeo.pdf 

Manufactured by the 

following companies AND 

listed in attachment below: 

Case 

Cummins 

Navistar 

Komatsu 

http://www.arb.ca.gov/diese 

l/verdev/ltrs/purifilterenginef 

amilies.pdf 

Extengine Inc. 

Advanced Diesel Emission Control 

Rubber tired excavators, loaders, dozers, or 

utility tractor rigs 

Model year 1991-1995 

Must be manufactured by 

Cummins 

Appendix VIII: Cleaner Diesel 151 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

INITIAL INJECTION TIMING 14 DEG. BTC 

ENGINE FAMILY YDDXH12.7EGL 

MODE L SERIES 60, 12.7L 

IMPORTANT ENGINE INFORMATION 

2000 THIS ENGINE CONFORMS TO U.S. EPA AND CALIFORNIA 

50S REGULATIONS APPLICABLE TO 2000 MODEL YEAR NEW 

HEAVY DUTY DIESEL CYCLE ENGINES. THIS ENGINE HAS 

A PRIMARY INTENDED SERVICE APPLICATIONS AS A 

HEAVY DUTY ENGINE. 

FUEL RATE AT ADV. HP 205. 6MM3 / STROKE ADV. HP 200 AT 2100 RPM 

DISP. 12. 7 LITERS 

MIN. IDLE 600 RPM 

MFG. DATE FEB 2000 

UNIT 06R0577657 CONFORMS TO AUSTRALIAN DESIGN RULE 

System 5.9 liter 

DOC and SCR 150 hp-200 hp 

www.extengine.com Duty cycle w/average exhaust >180 ̊C for at 

least 55% of operating cycle 

CARB verified Turbocharged 

http://www.arb.ca.gov/diesel/verdev/l Mechanically controlled 

evel1/level1.htm Requires pressurized anhydrous ammonia 

Fueled with LSD 

May incur 1% fuel economy loss 

Complete Requirements: 

http://www.arb.ca.gov/diesel/verdev/eode05 

001.pdf 

ENGINE FAMILY NAME 

The engine family name is an alphanumerical code designated to engines by the EPA. It identifies 

engines by make, year, displacement, and emissions characteristics. It is important to get the 

engine family name for each engine as well as the individual specifications to facilitate the process of 

finding the appropriate retrofit device. EPA and CARB verify retrofit technologies for certain engines 

and other requirements, such as minimum engine temperature. The engine family name can be 

found on a sticker on 

the engine itself (Fig. 

65). If this code cannot 

Figure 65 Sample engine emissions label with engine family name.366

be found, retrofit 

technology dealers 

may be able to 

determine the family 

name from the other 

engine information 

provided. Off-road 

engines manufactured 

before 1996 typically 

do not have an engine 

family name. 

ESTIMATING EMISSIONS FROM ON-ROAD TRANSPORT TRUCKS 

Use the equations in Box 12 for a general estimate of NOx, CO, and PM emissions from transport 

trucks to determine the approximate baseline emissions without pollution reduction measures. 

Assumptions: 

• Gas mileage of 6 miles per gallon 

• Steady state operation of the trucks on interstate type roads 

Appendix VIII: Cleaner Diesel 152 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

• Urban highway heavy-duty truck emission factors cited from Assessing the Effects of 

Freight Movement on Air Quality at the National and Regional Level: Final Report, April 

2005 by the DOT, Federal Highway Administration. 

Box 12 Estimating on-road trucking emissions 

Miles per Round Trip Number of Trips Emissions per Mile (g) Total Emissions 

[ ] x 

[ ] x 

[ ] x 

[ ] x 25.65 = 

[ ] x 2.48 = 

[ ] x 0.37 = 

[ 

[ 

[ 

] Grams NOx 

] Grams CO 

] Grams PM 

Appendix VIII: Cleaner Diesel 153 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

APPENDIX IX: REGION 9 SUPERFUND ELECTRICITY AND 

DIESEL EMISSIONS INVENTORY 

Superfund Electricity and Diesel Emissions Inventory 

US EPA Region 9 

Superfund 

Prepared by: 

Ashley DeBoard MacKenzie 

Environmental Protection Agency GRO Fellow

August 16, 2007 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 154 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Background and Goals 

The Cleanup-Clean Air (CCA) initiative is a regional pilot program in US EPA Region 9. 

It is demonstrating the feasibility of using cleaner diesel vehicles and reducing greenhouse gases 

(GHG) in Superfund and developing tools to make it easier to do in the future. CCA is focused 

on encouraging, facilitating and supporting implementation of diesel emissions and greenhouse 

gas reductions technologies and practices at Superfund cleanup and redevelopment sites. 

Furthermore, the initiative strives to measure and reduce Superfund’s environmental footprint, 

reduce exposure to Superfund communities, save energy costs in the long term, and serve as role 

model for other programs. 

There were two specific goals set forth for this project within Cleanup-Clean Air. First, 

the project was designed to attain a rough estimate of the emissions footprint associated with 

remediation activities at Superfund National Priorities List (NPL) sites in Region 9. The second 

goal was to establish a baseline of electricity and diesel emissions to which any future 

measurable changes can be compared. Emissions associated with diesel equipment use and 

electricity production evaluated in this study include Carbon Dioxide (CO2), Nitrogen Oxides 

(NOx), Carbon Monoxide (CO), and particulate matter (PM). However, other pollutants such as 

Sulfur Dioxide (SO2) and Polycyclic Aromatic Hydrocarbons (PAHs) are also present in diesel 

exhaust and combustion of fossil fuels for electricity production. Some of the associated health 

effects are listed below (EPA 2007a). 

CO2 : High concentrations of this greenhouse gas (GHG) are most significantly 

linked to global climate change. 

PM: 90% of PM is PM2.5. Exposure is linked to premature mortality, chronic 

bronchitis, chronic obstructive pulmonary disease (COPD), asthma 

aggravation, pneumonia, and heart attacks. 

NOx : Is a precursor causing ground level ozone (smog) through a series of 

atmospheric chemical changes. It contributes to global warming, acid rain, 

low visibility, deteriorated water quality, and a myriad of respiratory 

problems. 

CO: Exposure affects human health in several ways. Depending on the 

concentration, CO can cause fatigue, flu-like symptoms, loss of brain 

function and even fatality. It affects the ability of blood to absorb oxygen. 

CO is also oxidized to form CO2 in the atmosphere. 

SO2: Contributes to and aggravates respiratory illnesses; contributes to formation 

of acid rain; and it forms atmospheric particles that refract light and 

decrease visibility. 

PAHs: Are highly carcinogenic compounds such as benzene and formaldehyde 

that are found in diesel emissions. 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 155 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Methods 

Information collected centered on construction activities (past, present, and projected 

future); specifications of treatment systems; past fuel and electricity use, and types of diesel 

equipment used for remediation activities (models and hours operating). Surveys were developed 

and distributed to Remedial Project Managers (RPMs) in two branches (Federal Facilities Branch 

and Site Cleanup Branch) of EPA Region 9’s Superfund division. Data were collected through 

use of the surveys and personal meetings with each RPM, review of their associated site design 

documents, and contact with their contractors. See Appendix E. 

The response rate for the surveys was roughly 50%, and therefore, emissions were only 

estimated for the sites that had completed surveys. Limited detail of information available for 

past remediation activities necessitated a method for creating rough estimates of emissions for 

sites with the incomplete information. Extrapolations and assumptions from the data were made 

and recorded, and consistent methods were applied across the data set when not otherwise 

specified. Assumptions involving site conditions, remedy design, construction and operations 

were made when the records were not available. A professional cost estimator from the Army 

Corps of Engineers was used to provide industry averages of typical equipment and associated 

operating times based upon the size and scope of the standard projects. See Appendices A for a 

list of emissions assumptions regarding diesel and electricity, B for a list of assumptions that 

estimate equipment use for construction activities, and Appendix C for list of assumptions that 

encompass emissions estimates for diesel barges. 

To calculate the total mass of pollutants emitted (in grams), the following formula was used: 

Pollutants Emitted = hours x horsepower x EF (g/bhp-hr) 

where, 

Hours: Hours were determined by assuming the amount of time each piece of equipment 

operated 

Horsepower (hp): Assumed to be an average of 330 hp for all pieces of equipment unless 

otherwise specified. 330 hp represents a midsized piece of equipment and should even out with 

larger and smaller pieces of equipment used at each site. 

Emissions Factors (EF): Were provided by Sacramento Air Resources Board for each standard 

assumed piece of equipment that was used in their emissions inventory model, Road 

Construction Modeler.Ver5.2.xls (Christensen 2007). Units are measured in grams/brakehorsepower-hour (g/bhp-hr). EFs are also equipment specific (grader, off-highway truck, 

excavator, etc), model year specific, and operating year specific. 

This formula was applied to each piece of equipment for individual construction activities 

conducted on sites, and the total grams for each individual pollutant (NOx, CO, and PM) were 

aggregated and converted to tons. When unavailable, a model year was assumed for each piece 

of equipment to attain the EF. This was done by using the median use life of an equipment piece 

and subtracting it from the year construction commenced. (See Appendix D). It was also 

assumed that for the general estimating purposes of this project, bhp-hr and hp-hr were equal. 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 156 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

There were also certain construction activities that were omitted because there were no EFs 

available or because the information gaps in records regarding scale of projects made estimations 

impossible. Future projections, beyond 2009, were also estimated for known projected 

remediation activities. 

Estimations of emissions associated with electricity consumption were conducted by 

gathering records of actual yearly kWh averages consumed at remediation sites. For sites without 

available electricity records, specifications of treatment systems were gathered that summarized 

the treatment facility type, number of extraction wells, flow rates, and dates of operation. These 

specifications were then inputted into the independent cost estimation software, Remedial Action 

Cost Engineering and Requirements (RACER), version 2006, developed by Earth Tech, Inc. and 

the Army Corps of Engineers (Earth Tech 2006.) Several assumptions about system conditions 

were made that are listed in Appendix A. This software provided an estimated amount of kWh 

needed to operate each specific treatment facility. Electricity amounts from both site records and 

RACER estimates were combined to get a total kWh consumed over time (1990-2009) for each 

site. Future projections were also established based on known treatment systems that will be 

operational for decades beyond 2009. EPA’s database Emissions and Generation Resource 

Integrated Database (eGRID), released April 2007, was used to estimate tons of CO2 associated 

with electricity production from the utility companies in the area (EPA 2007b). The database 

provided an average, “statewide” factor that was multiplied by kWh to attain CO2 emissions. 

Results 

See Appendix F for Results Tables and Charts 

Results pictured for emissions from both diesel exhaust and electricity production are 

approximately 50% of all Region 9 NPL sites surveyed. Although this information is not 

complete, data may be collected from the remaining sites in the future. Until that time, results 

for the whole region can be roughly estimated by multiplying these results by a factor of 2 and 

noting the assumption. 

Total diesel emissions from 1985-2009 were estimated to be 3,140 tons NOx, 848 tons 

CO, and 105 tons PM. The highest period of NOx output was from 2000-2004 with 1,339 tons. 

The highest period of CO output was 1995-1999 with 268 tons. Lastly, the highest period for 

PM output was 2000-2004 with 38 tons. The lowest period of output for all pollutants was 1985­

1989 with 186, 93, and 11 tons for NOx, CO and PM respectively. It should be noted however, 

that although PM output was significantly lower in mass, the microscopic properties of the 

particles make this pollutant especially dangerous to human health by bypassing the body’s 

natural defenses, such as cilia in the lungs. 

 Total CO2 emissions associated with electricity consumption from 1990-2009 for Region 

9 sites were estimated to be 428,174 tons. This is the equivalent of 84,000 cars on the road for 

one year or powering about 50,000 single family homes for one year. Future projections based 

only on known treatment facilities on grid as of 2007, Superfund is expected to use an additional 

113.2 million kWh per year, equating to about 44,600 tons of CO2. This would be equivalent to 

adding an additional 8700 cars or 5100 homes per year projected out for decades. (EPA 2005) 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 157 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Discussion 

As stated previously, the level of detail sought for emissions estimates was not always 

available from the RPMs when completing the surveys. This is because much of the information 

was tracked on a sub-contractor level, far from RPM involvement. It was especially difficult to 

obtain complete, detailed information of site remediation from the past, as many records were 

not preserved at a level regarding detail of fuel and electricity consumption or equipment 

associated with construction activities. 

It is recommended that this information be tracked in the future. If specific information 

associated with emissions (i.e., gallons used, type of equipment used, and kWh consumed) is 

tracked throughout the life of the remediation activities, it is much easier to estimate the GHG 

emissions associated with each activity. Furthermore, the information gathered in this study, 

combined with detailed future tracking may help to normalize our data. In the future, it could be 

taken to the next step by putting it into a form that can be applied to all activities. For example, 

to achieve a baseline at any given point, we could calculate the emissions for each pound of 

contaminant removed during remediation. 

The initial steps of tracking this information for Region 9 have already begun through 

inputting conditions into contract language. Regions 9 and 10 now have Emergency and Rapid 

Response contracts, and Region 9 is soon to have Remedial Action contracts in place that are or 

will soon require contractors to track use of cleaner diesel equipment, energy efficiencies, and 

renewable energy to power remediation on sites. 

It is important to note that although results for diesel emissions are pictured within 5 year 

periods over the course of 25 years, the data is really a historical snapshot of past emissions 

rather than a trend. This is because the diesel work takes significantly less time in relation to 

electricity use for remediation. Generally, using heavy diesel equipment to complete 

construction activities on-site is accomplished on the time scale of several months to several 

years. In contrast, remediation that is tied into the electricity “grid” is conducted for decades or 

longer. It still may have fluctuations resulting from commencement or termination of treatment 

systems, but it is expected that these treatment facilities remain more stable in their electricity 

use and consequently the associated emissions. Therefore, fluctuations in diesel use over time 

may be a reflection of the phase of remediation at the Superfund site rather than a trend-like 

increase or decrease. 

This emissions inventory also has applications beyond regional remediation. The process 

for collecting this data as well as the picture of our emissions footprint will help to inform larger 

Office of Solid Waste and Emergency Response (OSWER) efforts to estimate emissions across 

all regions. Furthermore, this data can likely be applied to EPA’s COBRA model to quantify 

health care costs (in dollar amounts) associated with human health exposure to pollutants 

resulting from remediation activities. 

We have quantified measurable adverse impacts to air quality resulting from remediation 

activities. While the estimates are rough, they provide an idea of our emissions footprint and 

clarified the need to track this information in the future for more accurate emissions inventories. 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 158 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Possible mitigation of these impacts to air quality includes the use of cleaner diesel equipment, 

energy efficiencies, and renewable energy technologies. The Smart Energy Resource Guide 

(SERG) is currently being developed as a “one stop shop” tool for RPMs to implement these 

mitigation techniques and gain insight into reducing their emissions footprint at each of their 

Superfund sites. 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 159 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Citations 

1. Christensen, Peter. Sacramento Air Resources Board. Emissions Factors for Diesel 

Construction Equipment. Road Construction Modeler.Ver5.2.xls. Provided August 2007. 

2a. Environmental Protection Agency. Air Pollutants. Updated May 2, 2007. 

http://www.epa.gov/air/airpollutants.html Accessed August 10, 2007. 

2b. Environmental Protection Agency. eGRID (Emissions and Generation Resource Integrated 

Data Base). Released April 2007. 

3. Environmental Protection Agency. Global Warming Calculators. “Equivalencies.” Updated 

June 27, 2005. 

http://yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterToolsCalculators. 

html Accessed August 10, 2007. 

4. Earth Tech Inc. RACER (Remedial Action Cost Engineering and Requirements). Version 

2006. http://talpart.earthtech.com/RACER.htm 

5. McMindes, Daniel. US Army Corps of Engineers. Construction Estimates for Diesel 

Equipment. Provided July 2007. 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 160 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Appendix A 

List of Assumptions 

 Diesel Estimates 

1. Assumed standard pieces of equipment provided by Army Corps of Engineers. See 

Appendix B. 

2. Assumed 330 horsepower for all pieces of equipment 

3. Assumed 1999 EFs for all construction activities using equipment on or before 1999. 

4. For all construction after 1999, used EFs that fell closest to the year the EFs were 

available (1999, 2002, 2005, 2008, and 2010). For example, equipment used in 2001 

would use a 2002 emissions factor. 

5. For all Heavy Trucks (20 yd, 15 yd, and other hauling trucks), used an Emissions Factor 

configuration from Sacramento Air Resources Board. EFs were done for 5 year intervals 

averaging models from 1965 to year of EF. Assumption made to round down to closest 5 

year interval from time the truck was used. For example, a truck used in 2002 would have 

a 2000 EF. These EFs assume 30 mph for all heavy trucks. 

6. Assumed water trucks and hydro-seed trucks to be “off-highway”. Assumed cement, 

slurry, 15-yd, and 20-yd trucks to be on-highway trucks. 

7. Construction activities not accounted for because of incomplete information: pumping 

hazardous liquids, helicopter flights, building demolitions, carbon regeneration. 

Electricity Estimates 

1. RACER assumption for groundwater extraction wells of unconsolidated, sandy-silt soil, 

50 ft to top of contamination, and 75 ft to base of contamination. 

2. RACER assumptions for contamination levels are 500 ppb influent, 5 ppb effluent. 

3. RACER assumptions for GAC treatment systems include dual capacity system for higher 

flow rate systems (above 200 gpm). 

4. Assumed flow rate for each extraction well is equal and adds up to total flow rate of 

treatment facility. 

5. Assumed an average Emissions Factors by state where power production occurred. This 

factor provided by eGRID. 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 161 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Appendix B 

Equipment 

Estimates from 

Dan McMindes 

CONVERSIONS 

1 acre= 43,560 sf 

1 cy= 27 cubic feet 

1cy=1.35 tons or 1 ton=0.74 

cy 

1 US Gallon=0.00495 cy 

Some unit 

assumptions**unless 

otherwise specified: 

Excavation depth to get 

sf: 2' 

Landfill depth to get sf: 

15' 

wells to get lf: 50' 

depth/well 

Cap: Assume 4 feet fill (2' 

low perm and 2' veg layer­

-->add inches that are 

specified to total volume 

if under 12" b/c it usually 

means an additional 

impermeable layer 

Hauling trucks *nearby 

import and haul with ~6mi 

roundtrip for total of 75 

mi per day. 

Remediation Activity 

Activity 

Components Units Units/day 

Construction 

Equipment 

Excavation and Backfill clear and grub sf 128,000 sf/day scraper 

assumptions excavation cy 480cy/day excavator 

no benching offhaul near site cy 120cy/day 15 yard truck 

easy excavation no 

rock/boulders import fill cy 120cy/day 15 yard truck 

backfill and roller/sheepsfoot 

small sf to cy ratio recompact cy 480cy/day compacter 

with compactor water truck 

rough grade site sf 40000 sf/day scraper/grader 

fine grade site sf 40000 sf/day scraper/grader 

4 15cy trucks one day 15 12 rounds/day 

minutes per round at holding 10 cy per 

approx 30 miles per hour load assuming 

would generate approx 75 6.25 mi round 

miles per day per vehicle trip=75 mi/day 

soil aeration rip soil 6 inches sf 10000sf/day dozer with rippers 

8'wide x 1000' long 6 to 12" 

deep 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 162 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Landfill Capping 

use clear and grub above 

for grading operations clear and grub sf 128,000 sf/day grader/scraper 

fill with 2 feet of low perm rough grade sf 40000 sf/day grader/scraper 

fill with 2 feet of veg layer import fill cy 160cyd/day 20 cyd end dumps 

backfill and 

recompact sf 480cy/day 

roller/sheepsfoot 

compacter 

with compactor water truck 

import fill cy 160cyd/day 20 cyd end dumps 

backfill and 

recompact sf 480cy/day 

roller/sheepsfoot 

compacter 

with compactor water truck 

fine grade sf 40000 sf/day grader/scraper 

revegetation water truck sf 42000sf/day 

hydroseed 

equipment/truck sf 42000sf/day 

clay capping same as 

landfill capping 

dewatering same as 

aeration 

well installation push type rig lf 100lf/day sampling rig 

drill type rig lf 400 lf/day hollow stem auger 

hauling is the same as 

import or export 

ust removal is like 

excavation, but add cy for 

backfill and add a crane for 

4 hours per tank as well as 

a truck for 4 hours to haul 

the tank away 

slurry walls under 12 feet 

deep 

excavate and 

stockpile lf 100lf per day backhoe 

add slurry 80cy/dy slurry truck 

offhaul excess 

soils 

100*12*2/ 

27=88.88 120cyd/dy 15 cyd truck 

J.H. Baxter--example from 

Travis Cain 

Construction of a 

slurry wall 

(4377'x 2' width, 

slurry wall depth 

50 ft); and 2 

bioventing 

blowers at 500 

cf/min; 

slurry=162 

11 cy; 

drilling: 

218850 lf; 

hollow stem 

auger: 547.1 

days; sample rig: 

2188.5 days; 

slurry truck: 

202.6 days; 15 

cy truck: 135.1 

days 

slurry walls over 12 feet use 

same effort as drill rigs plus 

effort for slurry and offhaul 

above, * leave out the 

excavate and stockpile 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 163 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

fencing 500lf per day 

pickup (ignore 

this) 

assume all bushes and 

brush and trees gone 

backhoe with 

auger attachment 

Pipeline 

36" diam-­

> 300 lf/day Excavator to dig 

60" diam-­

-> 150 

lf/day 

Backhoe with 

sheepsfoot 

attachment to 

backfill 

Water truck for 

same time as 

backhoe 

Dams treat as fill 

concrete 

dam 10 cy/day concrete truck 

earthen 

dam 

fill (cy to place 

and compact) 

15 yd trucks, 

sheepsfoot roller, 

(see excavation) 

Sediment ponds are same 

as excavation 

Removal of drums of Haz 

Waste 

similar to 

excavation 

, but 

double the 

time it 

takes to 

remove. 240 cy/day excavator 330 hp 

10 barrels per 

truck 

Hauling truck 

(assume 200 hp) 

20 barrels/day 

forklift to put on 

truck 330 hp 

backfill 

and 

recompact 480 cy/day 

roller/sheepsfoot 

compactor 330 hp 

same time water truck 

15cy truck will hold between 

8 and 10 cyds depending 

on density and weight of 

material. Assumed 10. 

All equipment is assumed 

to be 330 hp 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 164 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Appendix C 

Emissions Estimates for Diesel Barges 

Puget Sound Maritime Emissions Inventory: Used to estimate emissions from diesel barges 

when capping sediments. 

Horsepower ranges from 40-350 hp, with the average barge engine having 188 hp. 

*Assumed 1 engine (propulsion)—some have more than one, auxiliary and propulsion 

*Assumed a median use life, since unavailable, to be 7 years (2001 model year). 

*Assumed this was a non-road model, not an ocean going vessel (OGV) 

*Assumed 130 kW Tier 1 (2001) engine 

- Emissions from this engine are 9.8 g/kW-hr NOx, 1.5 g/kW-hr CO, and 0.4 g/kW-hr for 

PM. 

*Formula is <XX g/kWh x Hours x kW engine> 

*Assumed barges hold 1⁄2 ton of material for capping per load. Estimated area of cap and volume 

needed to cover area to determine approximate miles vessel would travel. Then assumed 5 mph 

to estimate total hours in the water 

See Table 4.7, page 273 

http://www.maritimeairforum.org/emissions.shtml 

Wayne Elson 

EPA, Region 10, AWT-107 

Office of Air, Waste, and Toxics 

1200 6th Avenue 

Seattle, WA 98101 

206-553-1463 (voice) 

206-553-0110 (fax) 

elson.wayne@epa.gov 

www.westcoastdiesel.org 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 165 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Appendix D 

Median Use Life Provided by Road Construction Modeler 

Backhoe: 1⁄2 use life= 8 yrs 

Bore/Drill Rigs: 1⁄2 use life= 2 yrs 

Crane: 1⁄2 use life= 5 yrs 

Dozer: 1⁄2 use life= 8 yrs 

Dredgers: Not available. Assume 5 yrs 

Excavator: 1⁄2 use life= 4 yrs 

Forklift: 1⁄2 use life= 4 yrs 

Grader: 1⁄2 use life= 5 yrs 

Generator: not available. Assume 8 yrs 

Loaders: 1⁄2 use life= 3 yrs 

Off Highway Trucks (Water Truck and Hydro-seed Trucks): 1⁄2 use life= 5 yrs 

Pumps: 1⁄2 use life= assume 5 yrs 

Roller: 1⁄2 use life= 4 yrs 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 166 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Appendix E 

Site Survey 

Site Name: 

ID #: 

Location (county & state): 

RPM: 

As part of the Cleanup-Clean Air initiative, the Superfund Program is trying to reduce our 

emissions footprint at cleanup and redevelopment sites. In order to implement greener cleanup 

practices, we are first trying to gain insight into our energy use trends (past, present, and future), 

and corresponding emissions produced. The information you provide is invaluable in 

ascertaining knowledge we can put forth into further greening our operations in Region 9, so 

please be as specific as possible. If any information is already filled in for your site, please 

confirm its accuracy. If any projects are missing on the tabs, please contact Ashley DeBoard (7­

4109) immediately so that she can help reformat your workbook. Furthermore, if more OUs are 

listed for your site than you are responsible for, please answer only for YOUR OUs. For those 

RPMs who may still be in “Pre RA” phase (see below), feel free to add any info you have 

available in the “Present RA” questions, regardless if they are rough estimates. Thank you for 

your time and effort; it is deeply appreciated. 

1. What is the Lead type for your site? (Fund, PRP, Federal) If more than one Lead applies 

to your site, please list who is directing the current phase by OU or area. 

2. How many operable units are at this site? 

3. What phase is each of the operable units in? Please specify if the stage is planned or 

complete. 

a. Pre Remedial Action? Circle One (RI/FS, ROD, RD) 

b. Present Remedial Action? (RA, LTRA, O&M) 

4. (Pre RA only) 

a. If no ROD, what are the contaminated media, and an approximate size of 

contamination? (i.e. yd3

 of soil, volume/dimensions of groundwater plume) Can you 

predict a method, or range of methods of remediation? 

b. If plan is in place, what are the estimated energy needs and an approximate length of 

time the OU will be active? Please give answers concerning energy needs in units of 

kW hrs/year and gallons of diesel fuel/ appropriate time frame (years, months, weeks). 

5. (Present RA) How long will each operable unit be actively remediated? 

a. Diesel: (If applicable) How long will use of a diesel fleet be required to remediate 

contamination? 

b. Electricity: (If applicable) How long will use of grid power be necessary to maintain 

remediation operations at site? 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 167 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

6. (Present RA) DIESEL: (For each OU) 

a. What are the types of diesel equipment being used in your fleet? 

b. How many of each type are being used? 

c. What is the time frame of their use? 

d. What was the previous fuel consumption in the life of the RA unit? How has it 

changed, and over what time periods? 

e. What is the amount of current fuel use? (Please specify units) ex: 1000 

gal/month/vehicle or OU 

f. Will the fuel use on the site decrease or increase in the future and when? Please specify 

how rate of fuel consumption will change over different time periods. (ex: fuel use will 

drop from 1000 gal/mo to 500 gal/mo after 10 months, and to 250 gal/mo after 24 

months. The project for OU-02 will be complete in 4 years.) 

7. (Present RA) ELECTRICITY: (For each OU) **This info can be obtained from a utility 

bill. 

a. What is the type of facility/equipment requiring grid power? 

b. What is the time frame of its electricity use? 

c. What was the previous level of electricity consumption in the life of the RA unit? How 

has it changed, and over what time periods? 

d. What is the amount of current electricity use (kW hrs/year)? 

e. Will the energy use on the site be decreased in the future and when? To what level? (ex: 

OU-04 will pump and treat groundwater at 400 gal/min for the first 3 yrs, and will 

decrease then to 150 gal/min for the remaining 10 years, after which the project will be 

complete. Corresponding kW hrs drop from 1200 to 600/mo during this time) 

8. For previous “specs” questions regarding fuel and electricity use, if questions cannot be 

answered completely by RPM, may we have permission to discuss such energy needs 

with your contractor for the site? If so, please list contact information. 

9. Are there currently “Green Practices” taking place at your site such as: cleaner equipment 

(DPFs, DOCs), cleaner fuels (ULSD), alternative fuels (biodiesel), “renewables” (solar, 

wind), or participation with utility companies to use their green energy options? Please 

specify. 

10. Can you list the utility being used at your site for electricity? 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 168 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Appendix F 

Charts and Tables 

Diesel 

Diesel Nox(tons) 

CO 

(tons) 

PM 

(tons) 

1985­

1989 186 93 11 

1990­

1994 247 104 12 

1995­

1999 630 268 27 

2000­

2004 1339 262 38 

2005­

2009 740 120 18 

Future 

(per year) 325 119 14 

NOx 

0 

200 

400 

600 

800 

1000 

1200 

1400 

1600 

1985­

1989 

1990­

1994 

1995­

1999 

2000­

2004 

2005­

2009 

Future 

(per 

year) 

Year 

Pollutant emitted (short tons) 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 169 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Appendix F, (cont.) 

Diesel 

CO 

0 

50 

100 

150 

200 

250 

300 

1985­

1989 

1990­

1994 

1995­

1999 

2000­

2004 

2005­

2009 

Future 

(per 

year) 

Years 

Pollutant Emitted (short tons) 

PM 

0 

5 

10 

15 

20 

25 

30 

35 

40 

1985­

1989 

1990­

1994 

1995­

1999 

2000­

2004 

2005­

2009 

Future 

(per 

year) 

Year 

Pollutant Emitted (short tons) 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 170 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Appendix F, (cont.) 

Electricity 

Total kWH 

Total CO2 

(tons) Cars Homes 

1990­

1994 73,890,266 36,633 7,193 4,266 

1995­

2009 176,433,435 83,097 16,317 9,677 

2000­

2004 262,114,529 115,162 22,613 13,504 

2005­

2009 481,351,734 193,282 37,953 22,509 

Future 

(per 

year) 

113,177,235 44,611 

8,670 5,195 

Appendix IX: Region 9 Superfund Electricity and Diesel Emissions Inventory 171 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

APPENDIX X: UTILITY RATE SCHEDULES 

This section provides web addresses to rate schedules for various utilities in Region 9 states and 

territories. Examine different rate schedules offered by your utility to determine which is optimal for 

the electricity demands of your site. Also consider demand response rate schedules for remedial 

activities that do not require a continuous source of power to reduce energy bills. Customers 

subscribing to this schedule take the risk of utilities shutting off their power during times of peak 

demand in return for less expensive electricity. 

Arizona 

Arizona Public Service (APS) 

Business: www.aps.com/main/services/business/rates/BusRatePlans_9.html

Residential: www.aps.com/aps_services/residential/rateplans/ResRatePlans_11.html

Salt River Project (SRP) 

Business: www.srpnet.com/prices/business/default.aspx

Residential: www.srpnet.com/prices/home/basic.aspx

Tucson Electric Power (TEP) 

www.tucsonelectric.com/Business/Programs/pricingplans/tariffs.asp 

UniSource Energy Services 

http://uesaz.com/Customersvc/PaymentOptions/PricingPlans/tariffs.asp 

California 

Pacific Gas and Electric Company (PG&E) 

http://pge.com/tariffs/ERS.SHTML#ERS 

Southern California Edison (SCE) 

General Service: 

www.sce.com/AboutSCE/Regulatory/tariffbooks/ratespricing/businessrates.htm 

Agricultural Pumping: 

www.sce.com/AboutSCE/Regulatory/tariffbooks/ratespricing/agriculturerates.htm 

San Diego Gas and Electric (SDG&E) 

www.sdge.com/regulatory/tariff/current_tariffs.shtml 

Appendix X: Utility Rate Schedules 172 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Commercial and Industrial: www.sdge.com/regulatory/tariff/elec_commercial.shtml 

Guam 

Guam Power Authority 

www.guampowerauthority.com/rates/schedules.html 

Nevada 

Sierra Pacific Power Company 

www.sierrapacific.com/rates/ca/schedules/ 

Nevada Power Company 

www.nevadapower.com/rates/tariffs/schedules/ 

Appendix X: Utility Rate Schedules 173 
CLEA

DIESEL EMISSIONS & 

APPENDIX XI: GREEN PRICING PROGRAMS 

Table 13 Utility Green Pricing Programs367 

State Utility Green Pricing Program Renewable Resource Price Prem

AZ Arizona Public Service Green Choice Program 

http://www.aps.com/main/gr een/choice/choice_7.html 

Wind, Geothermal $1.00 (plus tax) per 100-kWh bloc

Minimum one year commitment. 

AZ Salt River Project EarthWise www.srpnet.com/environme 

nt/earthwise/business.aspx 

Solar $3.00 per 100-kWh block in additi

AZ Tucson Electric Power 

Company 

GreenWatts 

www.greenwatts.com/ 

Solar $2.00 for 20-kWh, $3.50 for 40-kW

$6.50 for 80-kWh, $8.00 for 100-kregular bill. 

AZ UniSource Energy Services GreenWatts www.greenwatts.com/ Solar $2.00 for 20-kWh, $3.50 for 40-kW

$6.50 for 80-kWh, $8.00 for 100-kregular bill. 

CA Anaheim Public Utilities Green Power 

www.anaheim.net/utilities/a dv_svc_prog/green_power/ about_gpower.htm 

Various $1.50 per 100-kWh; $15.00 for 1,0

2,000-kWh, or $45.00 per 3,000-kMinimum six month commitment . 

CA Los Angeles Department of 

Water and Power 

Green Power for Green LA 

www.ladwp.com/ladwp/cms/ ladwp000851.jsp 

Wind, Landfill Gas $0.03 per kWh. Minimum 12 mon

CA PacifiCorp: Pacific Power Blue Sky www.pacificpower.net/Articl 

e/Article35885.html 

Wind, Solar, Landfill Gas 

$1.95 per 100-kWh increments. 

CA Pacific Gas and Electric 

(PG&E) 

Climate Smart 

www.pge.com/myhome/envi ronment/whatyoucando/clim atesmart/ 

Forest Conservation, Biomass Projects 

$0.0025 per kWh used each mont

Appendix XI: Green Pricing Programs 
CLEA

DIESEL EMISSIONS & 

CA Palo Alto Utilities Palo Alto Green 

www.cityofpaloalto.org/form s/pagreenenrollment/ 

Wind, Solar $0.015 per kWh. 

CA Pasadena Water and 

Power 

Green Power Program 

www.ci.pasadena.ca.us/wat erandpower/greenpower/de fault.asp 

Wind $25.00 per 1,000-kWh block or Al

per kWh used each month. 

CA Roseville Electric Green Roseville 

www.roseville.ca.us/electric/ green_roseville 

Wind, Solar $0.015 extra per kWh used each m

1,000-kWh block. 

CA Sacramento Municipal 

Utility District 

Greenergy 

www.smud.org/communityenvironment/greenergy/inde x.html 

Wind, Biomass $0.01 per kWh used each month o

block (one year commitment for la

CA Silicon Valley Power 

partnering with 3 Phases 

Santa Clara Green Power 

www.siliconvalleypower.co m/green 

Solar, Sind $0.015 per kWh used each month 

block. 

HI Hawaiian Electric 

Company, Inc. 

Sun Power for Schools 

www.heco.com/portal/site/h eco/menuitem.508576f78ba a14340b4c0610c510b1ca/? vgnextoid=b9a85e658e0fc0 10VgnVCM1000008119fea 9RCRD&vgnextchannel=52 9bf2b154da9010VgnVCM1 0000053011bacRCRD&vgn extfmt=default&vgnextrefres h=1&level=0&ct=article 

Solar Monthly donation to support PV o

NV Nevada Power Green Power Program 

www.nevadapower.com/co menv/env/greenpower/ 

Solar Monthly tax-deductible donations 

education and the construction of facilities at schools in Nevada. 

Appendix XI: Green Pricing Programs 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

APPENDIX XII: NET METERING PROGRAMS 

Net metering programs allow grid-tied utility customers who generate electricity in excess of their 

consumption at a certain time to “bank” their energy and use it at another time. This is also called 

net excess generation (NEG). Net metering programs help reduce the payback time for a renewable 

energy project. Not all utilities offer net metering. The following data on net metering programs 

were adapted from the Database of State Incentives for Renewables and Efficiency 

(www.dsireusa.org) and Interstate Renewable Energy Council 

(http://www.irecusa.org/fileadmin/user_upload/ConnectDocs/NM_table.pdf). Contact the local utility 

for more information on your local net metering program. For more information, see 

www.eere.energy.gov/greenpower/markets/netmetering.shtml. 

Arizona 

Arizona Public Service (APS) 

Applicable Sectors: All customers 

Applicable Technologies: Solar, Wind, Biomass 

Maximum Customer System Size: 100 kW 

Maximum enrollment: 15 MW 

Any customer NEG will be carried over to the customer's next bill at the utility's retail rate, as a kWh 

credit. For customers taking service under a time-of-use rate, off-peak generation will be credited 

against off-peak consumption, and on-peak generation will be credited against on-peak 

consumption. The customer’s monthly bill is based on the net on-peak kWh and net off-peak kWh 

amounts. Any monthly customer NEG will be carried over to the customer's next bill as an off-peak 

or on-peak kWh credit. Any NEG remaining at the customer’s last monthly bill in a calendar year or 

at the time of a customer shut-off will be granted to the utility. 

Though different from net metering, a July 1981 decision by the Arizona Corporation Commission 

allows net billing at the utility's avoided-cost rate. APS allows net billing. 

APS 

428 E. Thunderbird Road #749 

Phoenix, AZ 85022 

Phone: (602) 216-0318 

www.aps.com 

Salt River Project 

Applicable Sectors: Residential 

Applicable Technologies: PV 

Maximum Customer System Size: 10 kW 

Maximum enrollment: none 

For each billing cycle, the kWh delivered to SRP are subtracted from the kWh delivered from SRP 

for each billing cycle. If the kWh calculation is net positive for the billing cycle, SRP will bill the net 

kWh to the customer under the applicable price plan, Standard Price Plan E-23 or E-26. If the kWh 

Appendix XII: Net Metering Programs 176 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

calculation is net negative for the billing cycle, SRP will credit the net kWh from the customer at an 

average market price. Net negative kWh will not be transferred to subsequent months. 

Katie Herring

SRP 

1521 N. Project Drive 

Tempe, AZ 85281-2025 

Phone: (602) 236-5816 

http://www.srpnet.com 

Tucson Electric Power Company (TEP) 

Applicable Sectors: Commercial, Residential 

Applicable Technologies: PV, Wind 

Maximum Customer System Size: 10 kW 

Maximum enrollment: 500 kW 

TEP credits NEG to the following month's bill. After each January billing cycle, any remaining credit 

is granted to the utility. Installations must meet the IEEE-929 standard, local requirements and 

National Electrical Code requirements. Installations must be completed within six months of preinstallation approval. Time-of-use net metering is not permitted. 

Though different from net metering, a July 1981 decision by the Arizona Corporation Commission 

allows net billing at the utility's avoided-cost rate. TEP allows net billing. 

Steve Metzger 

Tucson Electric Power 

3950 E Irvington Road

Mailstop RC 116 

Tucson, AZ 85702 

Phone: (520) 745-3316 

E-mail: smetzger@tep.com

www.tucsonelectric.com/

California 

All Utilities 

Applicable Sectors: All customers of all utilities 

Applicable Technologies: PV, Wind; Investor owned utilities: PV, Wind, Biogas and Fuel Cells 

Maximum Customer System Size: 1 MW 

Maximum enrollment: 2.5 percent of each utility’s peak demand 

NEG is carried forward to a customer's next bill for up to 12 months. Any NEG remaining at the end 

of each 12-month period is granted to the customer's utility. Customers subject to time-of-use rates 

are entitled to deliver electricity back to the system for the same time-of-use price that they pay for 

power purchases. However, time-of-use customers who choose to net meter must pay for the 

metering equipment capable of making such measurements. Customer-generators retain ownership 

of all renewable-energy credits associated with the generation of electricity. 

Appendix XII: Net Metering Programs 177 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Les Nelson 

Western Renewables Group 

30012 Aventura, Suite A 

Rancho Santa Margarita, CA 92688 

Phone: (949) 713-3500 

Fax: (949) 709-8044 

E-mail: lnelson@westernrenewables.com

www.westernrenewables.com

Hawaii 

All Utilities 

Applicable Sectors: Residential, Small Commercial (including government) 

Applicable Technologies: Solar, Wind, Biomass, Hydroelectric 

Maximum Customer System Size: 50 kW 

Maximum enrollment: 0.5 percent of each utility’s peak demand 

A customer whose system produces more electricity than the customer consumes during the month 

may carry forward NEG in the form of a kWh credit that is applied to the next month's bill. Excess 

credits can be carried over for a maximum of 12 months. At the end of the 12-month reconciliation 

period, NEG credits will be granted to the utility without customer compensation unless the customer 

enters into a purchase agreement with the utility. 

Maria Tome 

Hawaii Department of Business, Economic Development, and Tourism 

Strategic Industries Division 

P.O. Box 2359 

Honolulu, HI 96804 

Phone: (808) 587-3809 

Fax: (808) 587-3820 

E-mail: mtome@dbedt.hawaii.gov

http://hawaii.gov/dbedt/info/energy/

Nevada 

Investor-Owned Utilities 

Applicable Sectors: Commercial, Industrial, Residential 

Applicable Technologies: Solar, Wind, Biomass, Hydroelectric, Geothermal 

Maximum Customer System Size: 1 MW (utilities may impose fees on systems greater than 100 

kW) 

Maximum enrollment: 1 percent of each utility's peak capacity 

For all net-metered systems, customer NEG is carried over to the following month as a kWh credit, 

without expiration. If a customer is billed for electricity under a time-of-use schedule, any customer 

NEG during a given month will be carried forward to the same time-of-use period as the time-of-use 

period in which it was generated, unless the subsequent billing period lacks a corresponding time-ofuse period. If there is no corresponding time-of-use period, then the NEG carried forward must be 

apportioned evenly among the available time-of-use periods. Excess generation fed to the grid is 

Appendix XII: Net Metering Programs 178 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

considered electricity generated or acquired by the utility to comply with Nevada's energy portfolio 

standard. 

Peter Konesky 

Office of the Governor 

Nevada State Office of Energy

727 Fairview Drive, Suite F 

Carson City, NV 89701 

Phone: (775) 687-9704 

Fax: (775) 687-9714 

E-mail: pkonesky@dbi.state.nv.us

http://energy.state.nv.us

Appendix XII: Net Metering Programs 179 
CLEANUP – CLEAN AIR 

DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

Citations 

1

 DOE. http://eia.doe.gov/oiaf/1605/ggrpt/carbon.html. 2

 Dellens, Amanda, EPA National Network for Environmental Management Studies Fellow. “Green Remediation and the Use of 

Renewable Energy Sources for Remediation Projects.” http://cluin.org/s.focus/c/pub/i/1474/. 3

 Olsen, Ken. Solar On-Line: Learning Center. PV 201 course materials. sol@solenergy.org. www.solenergy.org and 

Nondestructive Testing Resource Center. www.ndt-ed.org/EducationResources/HighSchool/Electricity/voltage.htm. 4

 DOE, Energy Information Administration. 

http://www.eia.doe.gov/kids/classactivities/MeasuringElectricityIntermediateSecondaryJuly2003.pdf. 5

 Ibid 

6

 Ibid 

7

 Olsen, Ken. Solar On-Line: Learning Center. PV 201 course materials. sol@solenergy.org. www.solenergy.org. 8

 DOE, Energy Information Administration. http://www.eia.doe.gov/kids/glossary/index.html#Btu. 9

 EPA, CHP Partnership. Catalogue of CHP Technologies. Page 1. 

http://www.epa.gov/chp/documents/catalog_of_%20chp_tech_entire.pdf. 10 EPA. http://www.epa.gov/CHP/definitions.html#three. 11 EPA, Office of Solid Waste and Emergency Response, Gill, Michael and Mahutova, K. May 2004. Introduction to Energy 

Conservation and Production at Waste Cleanup Sites. EPA Engineering Forum Issue Paper. EPA 542-S-04-001. Page 10. 

www.epa.gov/swertio1/tsp/download/epa542s04001.pdf 12 EERE. http://www.eere.energy.gov/greenpower/markets/netmetering.shtml. 13 Dellens, Amanda, EPA National Network for Environmental Management Studies Fellow. “Green Remediation and the Use of 

Renewable Energy Sources for Remediation Projects.” Page 3. http://cluin.org/s.focus/c/pub/i/1474/. 14 EPA. http://www.epa.gov/climatechange/emissions/co2_human.html#carbonsequestration. 15 Ibid 16 NETL. http://www.netl.doe.gov/technologies/carbon_seq/FAQs/project-status.html#Terrestrial_Field. 17 EPA. http://www.epa.gov/sequestration/local_scale.html. 18 EPA. http://www.epa.gov/sequestration/faq.html. 19 EPA. http://www.epa.gov/sequestration/rates.html. 20 EPA. http://www.epa.gov/sequestration/faq.html. 21 EERE. http://www1.eere.energy.gov/solar/pv_physics.html. 22 Lawton Ltd. http://www.lawton-bes.co.uk/sun21/solar_electricity.html. 23 EERE. http://www1.eere.energy.gov/solar/solar_glossary.html. 24 Ibid 25 NorCal Solar. 2006-2007. Solar Energy Resource Guide. 7th edition. Page 4. 26 NorCal Solar. 2006-2007. Solar Energy Resource Guide. 7th edition. Page 53 and EERE 

www1.eere.energy.gov/solar/solar_glossary.html. 27 NorCal Solar. 2006-2007. Solar Energy Resource Guide. 7th edition. Page 49. 28 Olsen, Ken. Solar On-Line: Learning Center. PV 201 course materials. sol@solenergy.org. www.solenergy.org. 29 Ibid 30 EERE. http://www1.eere.energy.gov/solar/solar_glossary.html. 31 Ibid 32 EERE. http://www.eere.energy.gov/greenpower/markets/netmetering.shtml. 33 EERE. http://www1.eere.energy.gov/solar/pv_systems.html. 34 EERE. http://www1.eere.energy.gov/solar/solar_cell_materials.html. 35 NorCal Solar. 2006-2007. Solar Energy Resource Guide. 7th edition. Page 3. 36 Olsen, Ken. Solar On-Line: Learning Center. PV 101 course materials. sol@solenergy.org. www.solenergy.org. 37 Nano Solar. www.nanosolar.com 38 Kyocera International Inc. http://global.kyocera.com/news/2005/0201.html. 39 California Public Utilities Commission, CA Solar Initiative. http://www.gosolarcalifornia.ca.gov/solar101/orientation.html. 40 Northern Arizona Wind and Sun. http://store.solar-electric.com/zomuttracmou4.html. 41 NREL. http://rredc.nrel.gov/solar/old_data/nsrdb/redbook/atlas/Table.html (select “Flat Plate Tilted South at Latitude.”) 42 Ibid 43 Olsen, Ken. Solar On-Line: Learning Center. PV 201 course materials. sol@solenergy.org. www.solenergy.org. 44 Ibid 45 EERE. December 2003. A Consumer’s Guide: Get Your Power from the Sun. Page 5. www.nrel.gov/docs/fy04osti/35297.pdf. 46 Olsen, Ken. Solar On-Line: Learning Center. sol@solenergy.org. PV 201 course materials. www.solenergy.org. 47 Ibid 48 Ibid 49 Ibid 50 Olsen, Ken. Solar On-Line: Learning Center. sol@solenergy.org. PV 101 course materials. www.solenergy.org. 51 Ibid 52 Ibid 

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53 Ibid 54 Ibid 55 Olsen, Ken. Solar On-Line: Learning Center. sol@solenergy.org. PV 201 course materials. www.solenergy.org. 56 NorCal Solar. 2006-2007. Solar Energy Resource Guide. 7th edition. Page 17. 57 Olsen, Ken. Solar On-Line: Learning Center. sol@solenergy.org. PV 201 course materials. www.solenergy.org. 58 Olsen, Ken. Solar On-Line: Learning Center. sol@solenergy.org. PV 201 course materials. www.solenergy.org. 59 NorCal Solar. 2006-2007. Solar Energy Resource Guide. 7th edition. Page 17. 60 Gipe, Paul. “Rate of Return Calculator of Solar PV Using @IRATE Function.” www.windworks.org/Solar/RateofReturnCalculationofSolarPVUsingIRATEFunction.html. 61 The Solar Guide. www.thesolarguide.com/solar-energy-systems/choosing-a-solar-provider.aspx. and Sustainable Development 

Fund Solar Photovoltaics Grant Program. “Solar PV Grant Program Tips on Choosing a PV Installer.” 

http://www.trfund.com/sdf/solarpv_documents/PV_Con_Tips.pdf. 62 The Solar Guide. http://www.thesolarguide.com/solar-energy-systems/warrantees.aspx. 63 EERE. December 2003. A Consumer’s Guide: Get Your Power from the Sun. Page 14. www.nrel.gov/docs/fy04osti/35297.pdf. 64 San Francisco Sierra Club. Sept-Oct 2006. “Volunteers make solar power easier and more affordable for homeowners.” Sierra 

Club Yodeler. http://sanfranciscobay.sierraclub.org/yodeler/html/2006/09/feature3.htm 65 EERE. January 2004. “PV FAQs.” www.nrel.gov/docs/fy04osti/35489.pdf. 66 Zweibel, Ken, NREL. Presentation “PV Module Recycling in the US.” March 2004. Page 3. 

www.nrel.gov/pv/thin_film/docs/pv_module_recycling_in_the_us.ppt 67 EERE. www1.eere.energy.gov/solar/panel_disposal.html. 68 Caraway, Rosemarie, EPA Region 9, Remedial Project Manager. Caraway.RoseMarie@epa.gov. 69 EERE. www1.eere.energy.gov/windandhydro/wind_how.html. 70 Ibid 71 Institut für Solare Energieversorgungstechni. http://www.iset.unikassel.de/pls/w3isetdad/www_iset_page.show_menu?p_name=7261007&p_lang=eng. 72 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 7. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 73 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 5. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf 74 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 5. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 75 EERE. www1.eere.energy.gov/windandhydro/wind_how.html. 76 Aermotor Windmill. http://www.aermotorwindmill.com/Links/Education/Index.asp. 77 EERE. http://www1.eere.energy.gov/windandhydro/wind_how.html. 78 American Wind Energy Association. http://www.awea.org/smallwind/toolbox2/factsheet_what_is_smallwind.html. 79 NREL. http://rredc.nrel.gov/wind/pubs/atlas/tables/A-8T.html. 80 Solcomhouse. www.solcomhouse.com/Darrieus-windmill.jpg. 81 American Wind Energy Association. Sept 2003. Permitting Small Turbines: A Handbook. Page 14. 

http://www.awea.org/smallwind/documents/permitting.pdf. 82 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 4. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 83 Iowa Energy Center. 2006. Wind Energy Manual. www.energy.iastate.edu/Renewable/wind/wem-index.htm. 84 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 7. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 85 Iowa Energy Center. 2006. Wind Energy Manual. www.energy.iastate.edu/Renewable/wind/wem-index.htm. 86 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 3. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 87 Iowa Energy Center. 2006. Wind Energy Manual. http://www.energy.iastate.edu/Renewable/wind/wem/systems.htm#seven. 88 De Montfort University. www.dmu.ac.uk/. 89 Iowa Energy Center. 2006. Wind Energy Manual. http://www.energy.iastate.edu/Renewable/wind/wem/systems.htm#seven. 90 California Energy Commission. www.energy.ca.gov/distgen/equipment/wind/cost.html. 91 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 12-13. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 92 American Wind Energy Association. http://www.awea.org/faq/basicen.html. 93 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 10. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 94 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 4. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 95 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 16. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 96 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 19. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 97 EERE. http://www.eere.energy.gov/greenpower/markets/netmetering.shtml. 

Citations 181
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98 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 3. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 99 American Wind Energy Association. www.awea.org/smallwind/toolbox/INSTALL/financing.asp. 100 Windustry’s Wind Farmers Network. windfarmersnetwork.org/eve/forums/a/tpc/f/3840095483/m/9190067093. 101 American Wind Energy Association. www.awea.org/smallwind/toolbox/INSTALL/financing.asp. 102 Ibid 103 American Wind Energy Association. http://www.awea.org/faq/sagrillo/ms_used_0211.html. 104 Argonne National Laboratory, Wind Energy Development Programmatic EIS. http://windeis.anl.gov/guide/photos/photo2.html. 105 Ibid 106 American Wind Energy Association. www.awea.org/faq/sagrillo/ms_OandM_0212.html. 107 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 3. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 108 American Wind Energy Association. Sept 2003. Permitting Small Turbines: A Handbook. Page 20. 

www.awea.org/smallwind/documents/permitting.pdf and American Wind Energy Association. 

www.awea.org/faq/sagrillo/ms_codesnov04.html. 109 American Wind Energy Association. http://www.awea.org/faq/sagrillo/ms_zoning3.html. 110 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 15. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 111 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 17. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 112 American Wind Energy Association. Sept 2003. Permitting Small Turbines: A Handbook. Page 16. 

http://www.awea.org/smallwind/documents/permitting.pdf. 113 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 8. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 114 EPA, Technology Innovation Program. Sept 2004. “Technology News and Trends.” http://www.cluin.org/products/newsltrs/tnandt/view.cfm?issue=0904.cfm. 115 EPA, LMOP. September 1996. A Landfill Gas to Energy Project Development Handbook. Page 3-12, 

http://epa.gov/lmop/res/pdf/handbook.pdf. 116 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Page 9. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF 117 Ibid 118 EPA, LMOP. http://epa.gov/lmop/overview.htm#converting. 119 EPA, LMOP. October 2002. Powering Microturbines with Landfill Gas. EPA430-F-02-012. Page 1. 

http://www.epa.gov/lmop/res/pdf/pwrng_mcrtrbns.pdf. 120 Oregon Department of Energy. www.oregon.gov/ENERGY/RENEW/Biomass/docs/landfill.PDF. 121 EPA, LMOP. October 2002. Powering Microturbines with Landfill Gas. EPA430-F-02-012. Page 3. 

http://www.epa.gov/lmop/res/pdf/pwrng_mcrtrbns.pdf. 122 CA Energy Commission. http://www.energy.ca.gov/distgen/equipment/microturbines/cost.html. 123 Ibid 124 EPA. http://www.epa.gov/methane/sources.html. 125 DOE, Energy Information Administration. http://www.eia.doe.gov/oiaf/1605/gwp.html. 126 EPA, LMOP. http://epa.gov/lmop/overview.htm#methane. 127 EPA, LMOP. http://epa.gov/lmop/over-photos.htm#3. 128 EPA. http://www.epa.gov/landfill/benefits.htm. 129 Ibid 130 EPA, LMOP. September 1996. A Landfill Gas to Energy Project Development Handbook. Page 3-2 to 3-6, 

http://epa.gov/lmop/res/pdf/handbook.pdf. 131 EPA, LMOP. May 2007. “An Overview of Landfill Gas Energy in the United States.” Page 5. 

http://www.epa.gov/landfill/docs/overview.pdf. 132 EPA, LMOP. May 2007. “An Overview of Landfill Gas Energy in the United States.” Page 7. 

http://www.epa.gov/landfill/docs/overview.pdf. 133 EPA, LMOP. September 1996. A Landfill Gas to Energy Project Development Handbook. Page 2-2, 

http://epa.gov/lmop/res/pdf/handbook.pdf. 134 EPA, LMOP. http://epa.gov/lmop/over-photos.htm#5. 135 EPA Combined Heat and Power Partnership. Catalogue of CHP Technology. Page 1. 

http://www.epa.gov/CHP/basic/catalog.html. 136 EPA, LMOP. September 2006. A Landfill Gas to Energy Project Development Handbook. Page 9-13. 

http://epa.gov/lmop/res/pdf/handbook.pdf. 137 EPA, LMOP. September 2006. A Landfill Gas to Energy Project Development Handbook. Page 3-16. 

http://epa.gov/lmop/res/pdf/handbook.pdf. 138 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Pages 26-28. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF. 139 California Climate Action Team. December 2005. Draft State Agency Work Plans. Page 80. 

http://www.climatechange.ca.gov/climate_action_team/reports/2006-02-06_AGENCY_WORKPLANS.PDF. 

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140 EPA, LMOP. www.epa.gov/lmop/faq-3.htm. 141 EPA, Office of Solid Waste and Emergency Response, Gill, Michael and Mahutova, K. May 2004. “Introduction to Energy

Conservation and Production at Waste Cleanup Sites.” EPA Engineering Forum Issue Paper. EPA 542-S-04-001. Pages 5-6. 142 Chern, Shiann-Jang, RPM, EPA Region 9. Chern.Shiann-Jang@epa.gov 143 National Aeronautics and Space Administration. http://www.nasa.gov/centers/goddard/news/topstory/2003/0508landfill.html and 

EPA, LMOP. http://www.epa.gov/lmop/res/nasa.htm. 144 BMW. http://www.bmwusfactory.com//community/environment/gastoenergy.asp. 145 California Energy Commission. http://www.energy.ca.gov/pier/renewable/biomass/anaerobic_digestion/index.html. 146 EERE. http://www.eere.energy.gov/consumer/your_workplace/farms_ranches/index.cfm/mytopic=30004. 147 Penn State University. www.biogas.psu.edu/terminology.html. 148 Penn State University. www.biogas.psu.edu/plugflow.html. 149 EPA, AgStar Program. 1997. AgStar Handbook. Page i. www.epa.gov/agstar/pdf/handbook/intro.pdf. 150 California Energy Commission. http://www.energy.ca.gov/pier/renewable/biomass/anaerobic_digestion/index.html. 151 EERE. http://www.eere.energy.gov/consumer/your_workplace/farms_ranches/index.cfm/mytopic=30004. 152 California Energy Commission. http://www.energy.ca.gov/pier/renewable/biomass/anaerobic_digestion/index.html and Penn 

State University. www.biogas.psu.edu/terminology.html. 153 California Energy Commission. http://www.energy.ca.gov/pier/renewable/biomass/anaerobic_digestion/index.html. 154 Penn State University, www.biogas.psu.edu/basics.html. 155 EPA, AgStar Program. 1997. AgStar Handbook. Chapter 1. http://epa.gov/agstar/pdf/handbook/chapter1.pdf. 156 EPA, AgStar Program. 2002. Managing Manure with Biogas Recovery Systems Improved Performance at Competitive Costs. 

Page 4. http://www.epa.gov/agstar/pdf/manage.pdf. 157 Schanbacher, Floyd, Ohio State University, Dept. of Animal Sciences Ohio Agriculture R & D Center. January 31, 2007. 

“Digester Basics.” Powerpoint presented at Waste-to-Energy Workshop for the Ohio Livestock & Food Processing Industries. 

http://www.chpcentermw.org/pdfs/070131-Wooster-OH/2007_Jan31_WoosterOH_Schanbacher.pdf. 158 EPA, AgStar Program. 2002. Managing Manure with Biogas Recovery Systems Improved Performance at Competitive Costs. 

Page 8. http://www.epa.gov/agstar/pdf/manage.pdf. 159 Schanbacher, Floyd, Ohio State University, Dept. of Animal Sciences Ohio Agriculture R & D Center. January 31, 2007. 

“Digester Basics.” Powerpoint presented at Waste-to-Energy Workshop for the Ohio Livestock & Food Processing Industries. 

http://www.chpcentermw.org/pdfs/070131-Wooster-OH/2007_Jan31_WoosterOH_Schanbacher.pdf. 160 EPA, AgStar Program. 2002. Managing Manure with Biogas Recovery Systems Improved Performance at Competitive Costs. 

Page 8. http://www.epa.gov/agstar/pdf/manage.pdf. 161 Schanbacher, Floyd, Ohio State University, Dept. of Animal Sciences Ohio Agriculture R & D Center. January 31, 2007. 

“Digester Basics.” Powerpoint presented at Waste-to-Energy Workshop for the Ohio Livestock & Food Processing Industries. 

http://www.chpcentermw.org/pdfs/070131-Wooster-OH/2007_Jan31_WoosterOH_Schanbacher.pdf. 162 EPA, AgStar Program. 2002. Managing Manure with Biogas Recovery Systems Improved Performance at Competitive Costs. 

Page 8. http://www.epa.gov/agstar/pdf/manage.pdf. 163 California Energy Commission. http://www.energy.ca.gov/pier/renewable/biomass/anaerobic_digestion/index.html; The 

Minnesota Project. Aug 2002. Final Report: Haubenschild Farms Anaerobic Digester. Pages 5-8. 

www.mnproject.org/pdf/Haubyrptupdated.pdf and Penn State University. www.biogas.psu.edu. 164 Wilkie, Ann, University of Florida, Soil and Water Science Department. 2003. “Anaerobic Digestion of Flushed Dairy Manure.” 

http://dairy.ifas.ufl.edu/files/WEF-June2003.pdf. 165 Ohio Biomass Energy Program. Turning Manure into Gold. Page 9. 

www.manuremanagement.cornell.edu/Docs/TurningManuretoGold.pdf. 166 EPA, AgStar Program. 1997. AgStar Handbook. Page 3-2. www.epa.gov/agstar/pdf/handbook/chapter3.pdf. 167 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Page 6. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF. 168 EPA, LMOP. Sept 1996. A Landfill Gas to Energy Project Development Handbook. Page 3-12. 

http://epa.gov/lmop/res/pdf/handbook.pdf. 169 California Energy Commission. http://www.energy.ca.gov/distgen/equipment/microturbines/cost.html. 170 Schanbacher, Floyd, The Ohio State University, Dept. of Animal Sciences Ohio Agriculture R & D Center. January 31, 2007. 

“Digester Basics.” Powerpoint presented at Waste-to-Energy Workshop for the Ohio Livestock & Food Processing Industries. 

http://www.chpcentermw.org/pdfs/070131-Wooster-OH/2007_Jan31_WoosterOH_Schanbacher.pdf. 171 California Energy Commission. www.energy.ca.gov/pier/renewable/biomass/anaerobic_digestion/index.html. 172 EPA, AgStar. 2002. Managing Manure with Biogas Recovery Systems Improved Performance at Competitive Costs. Page 8. 

http://www.epa.gov/agstar/pdf/manage.pdf. 173 Ibid 174 EPA, AgStar Program. 1997. AgStar Handbook. Pages 8-4—8.5. www.epa.gov/agstar/pdf/handbook/chapter8.pdf. 175 EPA, AgStar, ASERTTI, USDA. Jan 2007. A Protocol for Quantifying and Reporting the Performance of Anaerobic Digestion 

Systems for Livestock Manures. Pages 15-16. http://epa.gov/agstar/pdf/protocol.pdf. 176 Intergovernmental Panel on Climate Change. 2006. 2006 IPCC Guidelines for National Greenhouse Gas Inventories. Page 

10.7. http://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/4_Volume4/V4_10_Ch10_Livestock.pdf. 177 Eastern Research Group, Inc. July 2005. An Evaluation of a Mesophilic, Modified Plug Flow Anaerobic Digester for Dairy Cattle 

Manure. http://www.epa.gov/agstar/pdf/gordondale_report_final.pdf. 178 California Energy Commission. http://www.energy.ca.gov/pier/renewable/biomass/anaerobic_digestion/projects.html. 

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179 Zhang, Zhiqin, California Energy Commission. Presentation at the Organic Residuals Symposium. July 12-14, 2006, 

Sacramento, California. “Recycling of Non-Hazardous Organic Residuals to Products and Energy.” Page 17. 

www.energy.ca.gov/2006publications/CEC-999-2006-013/CEC-999-2006-013.PDF. 180 Zhang, Zhiqin, California Energy Commission. Presentation at the Organic Residuals Symposium. July 12-14, 2006, 

Sacramento, California. “Recycling of Non-Hazardous Organic Residuals to Products and Energy.” Page 18. 

www.energy.ca.gov/2006publications/CEC-999-2006-013/CEC-999-2006-013.PDF. and Emigh, Michael, Valley Fig Growers. 

Presentation at the Clean Fuels for California and the West Conference. January 18, 2006. 

http://www.energetics.com/napavalleyCHPworkshop/pdfs/emigh.pdf. and Emigh, Michael, Valley Fig Growers. Presentation at the 

6th Annual Microturbine Applications Workshop. January 19, 2006. 

http://www.ms.ornl.gov/maw06/pdfs/presentations/Day3/Emigh.pdf. 181 Emigh, Mike, Valley Fig Growers. Presentation at the Clean Fuels for California and the West Conference. January 18, 2006. 

Page 14, 16, 34-35. http://www.energetics.com/napavalleyCHPworkshop/pdfs/emigh.pdf; Emigh, Mike, Valley Fig Growers. 

Presentation at the 6th Annual Microturbine Applications Workshop. January 19, 2006. Page 21, 23-28. 

http://www.ms.ornl.gov/maw06/pdfs/presentations/Day3/Emigh.pdf; 182 Emigh, Mike, Valley Fig Growers Association. Presentation at the Clean Fuels for California and the West Conference. January 

18, 2006. Page 16. http://www.energetics.com/napavalleyCHPworkshop/pdfs/emigh.pdf. 183 Emigh, Mike, Valley Fig Growers Association. Presentation at the Clean Fuels for California and the West Conference. January 

18, 2006. Page 35-45. http://www.energetics.com/napavalleyCHPworkshop/pdfs/emigh.pdf and Emigh, Mike, Valley Fig Growers. 

Presentation at the 6th Annual Microturbine Applications Workshop. January 19, 2006. Pages 23-28. 

http://www.ms.ornl.gov/maw06/pdfs/presentations/Day3/Emigh.pdf. 184 Southern Illinois University at Carbondale. http://www.siu.edu/~perspect/05_sp/coalsidebar2.html. 185 NETL. http://www.netl.doe.gov/technologies/coalpower/gasification/basics/glossary.html. 186 NETL. http://www.netl.doe.gov/technologies/coalpower/gasification/basics/1.html. 187 Coaltec Energy USA. http://www.coaltecenergy.com/poultrylitterproject.html. 188 NETL. http://www.netl.doe.gov/technologies/coalpower/gasification/basics/1.html. 189 EERE. http://www1.eere.energy.gov/biomass/gasification.html. 190 NETL. http://www.netl.doe.gov/technologies/coalpower/gasification/basics/index.html. 191 International Energy Agency, Task 33. May 2005. Observations on the Current Status of Biomass Gasification. Page 1. 

http://media.godashboard.com/gti/IEA/58_BiomassGasification.pdf. 192 Gasification Guide. http://www.gasification-guide.eu/index.php?id=10&r=6. 193 NETL. http://www.netl.doe.gov/technologies/coalpower/gasification/basics/7.html. 194 NETL. http://www.netl.doe.gov/technologies/coalpower/gasification/basics/6.html. 195 EERE. http://www1.eere.energy.gov/biomass/small_modular_gasification.html. 196 Ibid 197 NETL. http://www.netl.doe.gov/technologies/coalpower/gasification/basics/2.html. 198 Bioenergy Feedstock Information Network. http://bioenergy.ornl.gov/faqs/index.html#eco3. 199 NREL. February 2000. Small Modular Biopower Initiative Phase I Feasibility Studies Executive Summaries. NREL/TP-570­

27592. http://www.nrel.gov/docs/fy00osti/27592.pdf. 200 Rizzo, Rob, Mt. Wachusett Community College. Presentation June 2007. http://www.delaware-energy.com/Download/BIOMASS-CONF/Rob%20Rizzo.pdf. 201 EPA. www.epa.gov/oar/particlepollution/health.html and EPA. www.epa.gov/air/urbanair/nox/hlth.html. 202 EPA. May 2002. Health Assessment Document for Diesel Engine Exhaust. EPA/600/8-90/057F. Page 603. 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=29060 and EPA Region 1. http://www.epa.gov/ne/eco/diesel/. 203 California Air Resources Board. “Facts about California’s Accomplishments in Reducing Diesel Particulate Matter Emissions.” 

Page 1. http://www.arb.ca.gov/diesel/factsheets/dieselpmfs.pdf. 204 EPA. 2005. National Emissions Inventory. www.epa.gov/ttn/chief/trends. 205 EPA, West Coast Collaborative. June 2005. “Public Health and Environmental Impacts of Diesel Emissions.” Page 1. 

http://westcoastcollaborative.org/files/outreach/Health-Enviro-Factsheet.pdf. 206 EPA. www.epa.gov/nonroad-diesel/2004fr/420f04032.htm. 207 Ibid 208 EPA. 2005. National Emissions Inventory. www.epa.gov/ttn/chief/trends. 209 EPA, West Coast Collaborative. “West Coast Collaborative PowerPoint.” Page 22. 

http://westcoastcollaborative.org/files/outreach/WCCppt.pdf. 210 EPA, West Coast Collaborative. “West Coast Collaborative PowerPoint.” Page 4. 

http://westcoastcollaborative.org/files/outreach/WCCppt.pdf. 211 California Air Resources Board. “Facts about California’s Accomplishments in Reducing Diesel Particulate Matter Emissions.” 

Page 1. http://www.arb.ca.gov/diesel/factsheets/dieselpmfs.pdf. 212 EPA. www.epa.gov/oar/particlepollution/health.html. 213 EPA. March 2007. Cleaner Diesels: Low Cost Ways to Reduce Emissions from Construction Equipment. Page 5. 

http://www.epa.gov/sectors/pdf/emission_0307.pdf. 214 EPA. March 2007. Cleaner Diesels: Low Cost Ways to Reduce Emissions from Construction Equipment. Page 5-6. 

http://www.epa.gov/sectors/pdf/emission_0307.pdf 215 Manufacturers of Emission Controls Association. 

http://www.meca.org/cs/root/diesel_retrofit_subsite/what_is_retrofit/what_is_retrofit. 

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216 EPA, West Coast Collaborative. www.westcoastcollaborative.org. 217 Manufacturers of Emission Controls Association. 

http://www.meca.org/cs/root/diesel_retrofit_subsite/what_is_retrofit/what_is_retrofit. 218 ICF Consulting for EPA. May 2005. Emission Reduction Incentives for Off-Road Diesel Equipment Used in the Port and 

Construction Sectors. Page 17. http://www.epa.gov/sectors/pdf/emission_20050519.pdf. 219 Manufacturers of Emission Controls Association. 

http://www.meca.org/cs/root/diesel_retrofit_subsite/what_is_retrofit/what_is_retrofit. 220 Schattanek, Guido. November 2004. “The Greening of Construction: Implementing Clean Diesel Control Programs on 

Transportation Projects.” Sustainable Development, Issue 59. 

http://www.pbworld.com/news_events/publications/network/issue_59/images/schattanek_fig1_250.jpg. 221 Manufacturers of Emission Controls Association. 

http://www.meca.org/cs/root/diesel_retrofit_subsite/what_is_retrofit/what_is_retrofit. 222 Virginia Department of Environmental Quality. http://www.deq.virginia.gov/mobile/mobcomp.html 223 Lenox, Katey, Oak Ridge National Laboratory. June 18-22 2000. “Extending Exhaust Gas Recirculation Limits in Diesel 

Engines.” Air and Waste Management Association 93rd Annual Conference presentation. Salt Lake City, UT. Page 15. 

http://www-chaos.engr.utk.edu/pap/crg-awma2000-slides.pdf; CA Air Resources Board. 

http://www.arb.ca.gov/diesel/verdev/vt/cvt.htm; and EPA. http://www.epa.gov/otaq/retrofit/verif-list.htm. 224 Manufacturers of Emissions Controls Association. April 2006. Retrofitting Emission Controls On Diesel-Powered Vehicles. Page 

14. https://vault.swri.edu/Retrofit/Documents/TechPaper.pdf. 225 Manufacturers of Emissions Controls Association. April 2006. Retrofitting Emission Controls On Diesel-Powered Vehicles. Page 

9. https://vault.swri.edu/Retrofit/Documents/TechPaper.pdf. 226 Manufacturers of Emissions Controls Association. April 2006. Retrofitting Emission Controls On Diesel-Powered Vehicles. Page 

18. https://vault.swri.edu/Retrofit/Documents/TechPaper.pdf. 227 EPA, West Coast Collaborative. “Diesel Emissions Mitigation Opportunities.” Page 2. 

http://westcoastcollaborative.org/files/outreach/Diesel%20Emission%20Mitigation.pdf. 228 Ibid 229 Ibid 230 EPA, West Coast Collaborative. “Diesel Emissions Mitigation Opportunities.” Page 1. 

http://westcoastcollaborative.org/files/outreach/Diesel%20Emission%20Mitigation.pdf. 231 EPA, West Coast Collaborative. “Diesel Emissions Mitigation Opportunities.” Page 2. 

http://westcoastcollaborative.org/files/outreach/Diesel%20Emission%20Mitigation.pdf. 232 Manufacturers of Emission Controls Association. April 2006. Retrofitting Emission Controls On Diesel-Powered Vehicles. Page 

16. https://vault.swri.edu/Retrofit/Documents/TechPaper.pdf. 233 California Air Resources Board. October 2000. “Appendix XI, Diesel PM Control Technologies.” Page 40. 

http://www.arb.ca.gov/diesel/documents/rrpapp9.pdf. 234 Washington State University Extension Energy Program. “Diesel Oxidation Catalyst.” Page 3. www.energy.wsu.edu/ftpep/pubs/renewables/DieselOxidation.pdf. 235 Washington State University. “Diesel Oxidation Catalyst.” www.energy.wsu.edu/documents/renewables/DieselOxidation.pdf. And 

Washington State University. “Diesel Particulate Filters.” 

www.energy.wsu.edu/documents/renewables/Retrofitparticualtefilters.pdf. 236 EPA, Office of Enforcement and Compliance Assurance. December 2006. “Diesel Pump Labeling Requirements.” Page 4. 

http://www.clean-diesel.org/images/DPLabelFacts121406.pdf. 237 EPA, OTAQ. http://www.epa.gov/otaq/highway-diesel/regs/420f06064.htm and http://www.epa.gov/nonroad-diesel/. 238 Clean Air Fleets. http://www.cleanairfleets.org/altfuels.html. 239 EPA, OTAQ. http://www.epa.gov/otaq/highway-diesel/regs/420f06064.htm. 240 EPA, OTAQ. http://epa.gov/otaq/regs/fuels/diesel/diesel.htm. 241 EPA. http://www.epa.gov/smartway/growandgo/documents/factsheet-biodiesel.htm. 242 NREL. Williams, A., R.L. McCormick, R. Hayes, and J. Ireland. March 2006. Biodiesel Effects on Diesel Particulate Filter 

Performance. NREL/TP-540-39606. http://www.nrel.gov/docs/fy06osti/39606.pdf. 243 EPA. http://www.epa.gov/smartway/growandgo/documents/factsheet-biodiesel.htm. 244 NREL. April 2005. “Biodiesel Blends: Clean Cities Factsheet.” DOE/GO-102005-2029. 

http://www.nrel.gov/vehiclesandfuels/npbf/pdfs/37136.pdf. 245 Clean Air Initiative. http://www.cleanairnet.org/infopool/1411/article-33906.html. 246 EERE. http://www.eere.energy.gov/afdc/fuels/natural_gas_cng_lng.html. 247 EERE. http://www.eere.energy.gov/afdc/fuels/natural_gas_benefits.html. 248 EPA. http://www.epa.gov/cleandiesel/construction/strategies.htm#fuels 249 EPA. http://www.epa.gov/cleanschoolbus/retrofit.htm, 250 Clean Air Fleets. http://www.cleanairfleets.org/altfuels.html. 251 Ibid 252 Ibid 253 Ibid 254 EPA, Region 9. http://www.epa.gov/region09/waste/biodiesel/questions.html. 255 EPA, OTAQ. http://www.epa.gov/otaq/retrofit/documents/biodiesel_calc.xls. 256 EPA, Region 9. http://www.epa.gov/region09/waste/biodiesel/questions.html. 

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257 EPA, OTAQ. http://www.epa.gov/otaq/retrofit/documents/biodiesel_calc.xls. 258 EPA, Region 9. http://www.epa.gov/region09/waste/biodiesel/questions.html. 259 EERE. http://www.epa.gov/region09/waste/biodiesel/benefits.html. 260 EERE. http://www.eere.energy.gov/afdc/fuels/natural_gas_benefits.html. 261 EERE. http://www.eere.energy.gov/afdc/fuels/natural_gas_benefits.html. 262 Ibid 263 EPA, OTAQ. “Clean Alternative Fuels: Compressed Natural Gas Fact Sheet.” http://eerc.ra.utk.edu/etcfc/docs/EPAFactSheetcng.pdf. 264 Ibid 265 EPA. http://www.epa.gov/otaq/diesel/construction/strategies.htm. 266 Ibid 267 EPA. http://epa.gov/otaq/retrofit/techlist-lubrizol.htm. 268 Ibid 269 EPA. http://www.epa.gov/otaq/highway-diesel/regs/420f06064.htm. 270 EERE. July 2007. “Clean Cities Alternative Fuel Price Report.” Page 3. www.eere.energy.gov/afdc/pdfs/afpr_jul_07.pdf. 271 EPA, OTAQ. “Clean Alternative Fuels: Compressed Natural Gas Fact Sheet.” http://eerc.ra.utk.edu/etcfc/docs/EPAFactSheetcng.pdf. 272 EPA, OTAQ. June 2003. Clean Fuel Options for Heavy-Duty Trucks and Buses. EPA420-F-03-015. Page 4. 

http://www.epa.gov/otaq/retrofit/documents/f03015.pdf. 273 Clean Air Fleets. http://www.cleanairfleets.org/altfuels.html. 274 EERE. http://www.eere.energy.gov/afdc/progs/all_state_summary.cgi?afdc/0. 275 California Public Utilities Commission. Sept 2007. California Solar Initiative Program Handbook. Page 7. 

http://www.gosolarcalifornia.ca.gov/documents/CSI_HANDBOOK.PDF. 276 Pacific Gas and Electric Company, San Diego Gas and Electric, San Diego Regional Energy Office, Southern California Edison, 

Southern California Gas Company. May 2007. Self-Generation Incentive Program Handbook. Page 3. 

http://www.sce.com/NR/rdonlyres/2FE187D0-3629-4201-A93F-AE7A827F5D03/0/2007_SGIP_Handbookr3070508.pdf. 277 NorCal Solar. 2006-2007. Solar Energy Resource Guide. 7th edition. Page 17. 278 NorCal Solar. 2006-2007. Solar Energy Resource Guide. 7th edition. Page 18. 279 Solar Pathfinder. http://www.solarpathfinder.com/index2.html. 280 EPA. http://www.epa.gov/adminweb/administrator/actionplan.htm. 281 EPA Region 9. Machol, Ben. Energy and Climate Change Strategy. December 2007. Page 14. 282 Whitehouse. http://www.whitehouse.gov/news/releases/2007/12/20071219-1.html. 283 EPA. http://www.epa.gov/greeningepa/energy/fedreq.htm and EERE. http://www1.eere.energy.gov/femp/about/legislation.html. 284 EPA, Energy Star Program. http://www.energystar.gov/index.cfm?c=pt_reps_purch_procu.pt_reps_exec_orders. 285 Ibid 286 EERE. http://www1.eere.energy.gov/femp/about/legislation.html. 287 EPA. http://www.epa.gov/greeningepa/energy/fedreq.htm. 288 EPA. http://www.epa.gov/greeningepa/greenpower/buy.htm. 289 California Solar Initiative. http://www.csi-epbb.com/. 290 EERE. http://www.eere.energy.gov/solar/cfm/faqs/third_level.cfm/name=Photovoltaics/cat=The%20Basics. 291 EERE. http://www1.eere.energy.gov/solar/solar_glossary.html. 292 EERE. http://www.eere.energy.gov/solar/cfm/faqs/third_level.cfm/name=Photovoltaics/cat=The%20Basics. 293 Olsen, Ken, Solar On-Line: Learning Center, sol@solenergy.org, PV 201 course materials, www.solenergy.org. 294 EERE. http://www1.eere.energy.gov/solar/photoelectric_effect.html. 295 EERE. http://www1.eere.energy.gov/solar/printable_versions/doping_silicon.html. 296 Special Materials and Research Technology. www.specmat.com/Overview%20of%20Solar%20Cells.htm. 297 Olsen, Ken, Solar On-Line: Learning Center, sol@solenergy.org, PV 201 course materials, www.solenergy.org. 298 Ibid 299 Ibid 300 EERE. www1.eere.energy.gov/solar/solar_glossary.html#battery. 301 EERE. http://www1.eere.energy.gov/windandhydro/wind_consumer_faqs.html. 302 Olsen, Ken, Solar On-Line: Learning Center, sol@solenergy.org, PV 201 course materials, www.solenergy.org 303 Ibid 304 Ibid 305 Ibid 306 Ibid 307 Ibid 308 Ibid 309 Ibid 310 The Solar Guide. http://www.thesolarguide.com/solar-energy-systems/choosing-a-solar-provider.aspx and Sustainable 

Development Fund Solar Photovoltaics Grant Program. “Solar PV Grant Program Tips on Choosing a PV Installer.” 

http://www.trfund.com/sdf/solarpv_documents/PV_Con_Tips.pdf. 311 NREL. http://www.nrel.gov/learning/re_csp.html. 312 Ibid 

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313 British Wind Energy Association. http://www.bwea.com/edu/extract.html. 314 Ibid 315 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 6. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 316 NREL. Photographic Information Exchange. http://www.nrel.gov/data/pix/Jpegs/14676.jpg. 317 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 6. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf. 318 EERE. March 2005. Small Wind Electric Systems: A U.S. Consumer’s Guide. Page 22. 

www.eere.energy.gov/windandhydro/windpoweringamerica/pdfs/small_wind/small_wind_guide.pdf and American Wind Energy 

Association. http://www.awea.org/faq/windpower.html. 319 EPA, LMOP. September 1996. A Landfill Gas to Energy Project Development Handbook. Page 2-3, 

http://epa.gov/lmop/res/pdf/handbook.pdf. 320 EPA, AgStar Program. 1997. AgStar Handbook. Page 3-3. www.epa.gov/agstar/pdf/handbook/chapter3.pdf. 321 EERE. http://www.eere.energy.gov/de/gas_fired/tech_basics.html. 322 Ibid 323 EERE. http://www.eere.energy.gov/de/gas_fired_engines.html. 324 EPA, February 2002. A Brief Characterization of Reciprocating Engines in Combined Heat and Power Applications. Page 2. 

http://www.epa.gov/lmop/res/pdf/chp_recipengines.pdf. 325 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Page 6. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF. 326 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Page 5. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF. 327 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Page 6. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF. 328 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Page 5. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF. 329 Ibid 330 Ibid 331 EERE. http://www.eere.energy.gov/de/industrial_turbines/tech_basics.html. 332 Ibid 333 Ibid 334 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Page 8. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF. 335 EERE. www.eere.energy.gov/de/microturbines/tech_basics.html. 336 EPA, LMOP. October 2002. Powering Microturbines with Landfill Gas. EPA430-F-02-012. Page 1. 

http://www.epa.gov/lmop/res/pdf/pwrng_mcrtrbns.pdf. 337 Ibid 338 EPA, LMOP. October 2002. Powering Microturbines with Landfill Gas. EPA430-F-02-012. Page 2. 

http://www.epa.gov/lmop/res/pdf/pwrng_mcrtrbns.pdf. 339 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Page 11-12. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF. 340 EPA, LMOP. October 2002. Powering Microturbines with Landfill Gas. EPA430-F-02-012. Page 3. 

http://www.epa.gov/lmop/res/pdf/pwrng_mcrtrbns.pdf. 341 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Page 9. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF. 342 EPA, LMOP. “Adapting Boilers to Utilize Landfill Gas.” www.epa.gov/lmop/res/pdf/boilers.pdf. 343 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Page 9. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF. 344 California Energy Commission. April 2002. Economic and Financial Aspects of Landfill Gas to Energy Project Development in 

California. Page 9. http://www.energy.ca.gov/reports/2002-04-08_500-02-020F.PDF. 345 Adapted from EPA, AgStar Program. 1997. AgStar Handbook. Pages 2-2, 2-4,2-5,2-6,2-7. 

www.epa.gov/agstar/pdf/handbook/intro.pdf. 346 Dairy Power Production Program. http://www.energy.ca.gov/pier/renewable/biomass/anaerobic_digestion/projects.html. 347 CA Energy Commission. http://www.energy.ca.gov/development/biomass/anaerobic.html. 348 Leggett, Jeannie, Graves, Robert, Lanyon, Les, Penn State University, College of Agricultural Sciences G77. “Anaerobic 

Digestion: Biogas Production and Odor Reduction from Manure.” http://www.age.psu.edu/extension/factsheets/g/G77.pdf. 349 EERE. http://www.eere.energy.gov/consumer/your_workplace/farms_ranches/index.cfm/mytopic=30003. 350 Ibid 351 Ibid 352 Food and Agriculture Organization of the United Nations. http://www.fao.org/sd/EGdirect/EGre0022.htm. 353 EERE. http://www.eere.energy.gov/consumer/your_workplace/farms_ranches/index.cfm/mytopic=30003. 354 Food and Agriculture Organization of the United Nations. http://www.fao.org/sd/EGdirect/EGre0022.htm. 355 Ibid 356 EERE. http://www.eere.energy.gov/consumer/your_workplace/farms_ranches/index.cfm/mytopic=30003. 

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DIESEL EMISSIONS & GREENHOUSE GAS REDUCTIONS 

357 Ibid 358 Fondahl, Lauren, EPA Region 9. Personal communication. October 5, 2007 and 40 CFR 503.32(a). 

http://ecfr.gpoaccess.gov/cgi/t/text/textidx?c=ecfr&sid=fdf2e06805b14dec0ec66ed24d7b7e67&rgn=div8&view=text&node=40:29.0.1.2.40.4.13.3&idno=40. 359 EERE. http://www.eere.energy.gov/consumer/your_workplace/farms_ranches/index.cfm/mytopic=30003. 360 NETL. http://www.netl.doe.gov/technologies/coalpower/gasification/basics/5.html and 

http://www.netl.doe.gov/technologies/coalpower/gasification/basics/4.html. 361 EPA. September 2006. Alternative Technologies/Uses for Manure Draft. www.epa.gov/npdes/pubs/cafo_report.pdf. 362 Food and Agriculture Organization of the United Nations. http://www.fao.org/DOCREP/T0512E/T0512e0a.htm. 363 Food and Agriculture Organization of the United Nations. http://www.fao.org/DOCREP/T0512E/T0512e0a.htm and NETL. June 

2002. Benchmarking Biomass Gasification Technologies for Fuels, Chemicals, and Hydrogen Production. Pages 7-8. 

www.netl.doe.gov/technologies/coalpower/gasification/pubs/pdf/BMassGasFinal.pdf. 364 Ibid 365 Ibid 366 Modified from image courtesy Dennis Johnson, EPA. Johnson.Dennis@epa.gov. 367 Adapted from EERE. http://www.eere.energy.gov/greenpower/markets/pricing.shtml?page=1. 

Citations 188