United States
Environmental Protection Air and Radiation EPA-430-B-97-015
Agency <6202J) February 2004
Manual For Developing Biogas
Systems at Commercial Farms in
u.s. Environmental
Protection Agency
the United States
AgSTAR Handbook
Editors: K.F. Roos, J.B. Martin, Jr., and M.A. Moser
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From the Editors
Rising energy prices in the 1970s triggered interest in using anaerobic digestion on
U.S. farms to produce and use biogas from animal manures and resulted in the
construction of several full-scale systems on commercial farms. Lessons learned
during this developmental period (1975-1985) have resulted in improvements in
design and operating parameters, equipment, and cost effectiveness.
The past decade has marked a period of significant expansion in the use of
commercially proven biogas production and utilization systems by the dairy and
swine industry. This growth in farm sector demand is due largely to improved
technology and services, favorable renewable energy policies, federal and state
incentive programs, and the "neighbor friendly" environmental advantages digester
technologies provide as residential development expands in rural areas and regulatory
pressures increase. There are currently about 70 animal waste digesters in operation
on swine and dairy farms. Included are three centralized systems that provide waste
treatment services to multiple farms. An additional 40 systems are in initial
development stages and are planned to be operational in the next few years. These
120 systems have the potential to provide 25 MW of grid connected base load
renewable energy while reducing greenhouse gases (methane) by about 40,000 metric
tons per yearequivalent to 840,000 metric tons CO2
This handbook was developed to provide guidance for farms that are considering
anaerobic digestion as a manure management option. When coupled with the use of
FarmWare, the handbook is intended to provide a step by step methodology to assist
users in making a preliminary technical, financial, and environmental assessment of a
project's feasibility, based on farm size, current manure management practices,
energy use profiles, and technology choice. The handbook has been printed as loose-
leaf pages in a ring binder. This format was chosen because it facilitates updating
material to keep pace with an expanding industry and technology base.
The first edition of the AgSTAR Handbook was prepared jointly by the U.S. EPA
and ICF Inc. under contract #68-D4-0088. The editors also wish to acknowledge the
following individuals for their contributions to the first edition:
First Edition Handbook reviewers and other contributors
Barry Kintzer, USDA-NRCS
Philip Lusk, Resource Development Associates
Ron Miner, Oregon State University
Don Stettler, USDA-NRCS
Peter Wright, Cornell University
SECOND EDITION From the Editors . {
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From the Editors
FarmWare Version 2.0 reviewers and other contributors
Philip Lusk, Resource Development Associates
Richard Mattocks, Environomics, Inc.
Dave Moffit, USDA-NRCS
James Rickman, USDA-NRCS
Leland Saele, USDA-NRCS
The second edition of the AgSTAR Handbook was updated jointly by the U.S. EPA
and ERG, Inc. under contract # GS-10F-0036K. The editors wish to acknowledge
the following individuals for their contribution to the second edition:
Second Edition Handbook reviewers and other contributors
Richard Mattocks, Environomics, Inc.
Barry Kintzer, USDA-NRCS
Ann Wilkie, University of Florida
FarmWare Version 3.0 reviewers and other contributors
Kurt Roos, U.S. EPA
John Martin, Hall Associates
Douglas Williams, California Polytechnic State University
SECOND EDITION
From the Editors -11
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Introduction
Many livestock facilities in the United States handle manure as liquids
and slurries. Stored manure liquids and slurries decompose anaero-
bically (i.e., in the absence of oxygen) producing large volumes of gas.
This gas is often referred to as biogas. Biogas contains between 60 and 80
percent methane (about 600-800 BTU/ft3) and is considered a renewable
energy resource.
Substantial opportunities exist across the country to recover and use bio-
gas energy by adapting manure management practices to include biogas
generation and collection. This handbook focuses on identifying and
evaluating opportunities for recovering and utilizing this energy through
the implementation of biogas technology.
This handbook is for livestock producers, developers, investors, and oth-
ers in the agricultural and energy industry that may consider biogas tech-
nology as a livestock manure management option. The handbook pro-
vides a step-by-step method to determine whether a particular biogas re-
covery system is appropriate for a livestock facility. This handbook com-
plements the guidance and other materials provided by the AgSTAR pro-
gram to the development of biogas technologies at commercial farms in
the United States.
The AgSTAR Program
The AgSTAR Program is a voluntary effort jointly sponsored by the U.S.
Environmental Protection Agency, the U.S. Department of Agriculture,
and the U.S. Department of Energy. The program encourages the use of
biogas capture and utilization at animal feeding operations that manage
manures as liquids and slurries. A biogas system reduces emissions of
methane, a greenhouse gas, while achieving other environmental benefits.
In addition, converting livestock wastes into an energy source may
increase net farm income.
AgSTAR currently provides the following reports and tools to assist
livestock producers and other interested parties in making informed
business decisions about the financial and environmental performance of
these technologies:
General Information
The AgSTAR Program - Managing Manure with Biogas Recovery Systems
AgSTAR Digest: an annual newsletter
SECOND EDITION Introduction - i
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Introduction
Project Development Tools
AgSTAR Handbook: A Manual for Developing Biogas Systems at Com-
mercial Farms in the United States
FarmWare: A pre-feasibility software package that accompanies the
AgSTAR Handbook
Industry Directory for On-farm Biogas Recovery Systems: a listing of
digester designers and equipment suppliers
Funding On-farm Biogas Recovery Systems: A Guide to National and
State Funding Resources
Market Opportunities for Biogas Recovery Systems: A Guide to
Identifying Candidates for On-farm and Centralized Systems
Environmental Performance
Dairy Cattle Manure Management: A Case Study of a Plug Flow An-
aerobic Digestion System
Swine Manure Management: A Case Study of a Covered Lagoon An-
aerobic Digestion System (under development)
Swine Manure: A Case Study of a Complete Mix Digester System (under
development)
All these products are free of charge and can be downloaded at
www.epa.gov/agstar.
Introduction - ii
SECOND EDITION
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Introduction
Organization of this Handbook
This handbook is organized into chapters according to the process of biogas project
development as presented in Exhibit 1. Chapter 1 provides an overview of the
technology. The subsequent chapters lead you through two stages of project
development. Supporting information is included in the appendices. The two stages
of project development are:
I. Project Feasibility Assessment. Chapters 2, 3, and 4 provide guidance on
screening for project opportunities, selecting a gas use option and conducting site-
assessments to identify technically appropriate and cost-effective biogas recovery
option(s). Chapter 9 examines the feasibility of centralized digester projects.
II. Project Implementation. Chapters 5 through 8 discuss the steps to develop a
biogas project. The steps include: securing an energy contract; selecting a developer;
obtaining project financing; and complying with permitting requirements.
Exhibit 1 Project Development Process
I.
PROJECT FEASIBILITY ASSESSMENT
Ch. 2 - Preliminary Screening for Project Opportunities
Ch. 3 - Selecting a Gas Use Option
Ch. 4 - Technical and Economic Feasibility Assessment
Ch. 9 - Centralized Biogas Systems
\\
PROJECT IMPLEMENTATION
Ch. 5 - Securing an Energy Contract
Ch. 6 - Selecting a Consultant/Developer/Partner
Ch. 7 - Obtaining Project Financing
Ch. 8 - Permitting and Other Regulatory Issues
Exhibit 2 summarizes how this handbook can be used to meet various objectives. The
first column lists several common objectives and the second column lists the chapter
to consult and key elements of that chapter.
SECOND EDITION
Introduction - iii
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Introduction
Exhibit 2 How to use this Handbook - Quick Reference
CHAPTER TO CONSULT
I WANT AN OVERVIEW OF BIOGAS TECHNOLOGY?
What is biogas technology?
Why would I use biogas technology?
How successful has biogas technology been?
1. Overview of Biogas Technology
1.1 What is Biogas Technology?
1.2 Benefits of Biogas Technology
1.3 The U.S. Biogas Experience
Part I. Project Feasibility Assessment
SHOULD I CONSIDER BIOGAS RECOVERY AS AN OPTION FOR MY LIVE-
STOCK FACILITY?
How do I know if my facility is ready to operate a biogas sys-
tem?
What information do I need to identify promising opportunities
for a biogas system?
How do I know if I have the skills and support to operate a bio-
gas system?
2. Preliminary Screening for Project
Opportunities
2.1 Is Your Facility "Large", with Animals in
Confinement?
2.2 Is Your Manure Management Compatible
with Biogas Technology?
2.3 Is there a Use for Energy?
2.4 Can You Manage the Farm Effectively?
2.5 Initial Appraisal Results
CAN I USE BIOGAS AT MY FACILITY ?
What are the main uses of biogas?
How do I determine which biogas utilization option will maxi-
mize economic return?
What are the electricity generation options? How do I deter-
mine which option is suitable for my facility?
3. Selecting a Gas Use Option
3.1 Electricity Generation
3.2 Direct Combustion
3.3 Other Options
Is A BIOGAS SYSTEM TECHNICALLY AND FINANCIALLY FEASIBLE FOR
MY FACILITY ?
How do I decide which biogas technology is appropriate for my
livestock facility?
What information do I need to evaluate the technical and eco-
nomic feasibility of a biogas project?
How do I compare the costs and revenues from a biogas project?
4. Technical and Economic Feasibility
Assessment
4.1 Match a Digester to Your Facility's Waste
Management Practices
4.2 Complete Evaluation Sheets
4.3 Enter Information into
FarmWare
4.4 Evaluate Results
Part II. Project Implementation
How Do I CLOSE THE UTILITY DEAL?
Do I need a utility deal?
How do I know if I'm getting the best possible deal?
How do I negotiate a "win/win" deal?
Where do I get help?
5. Securing an Energy Contract
5.1 Operation Modes
5.2 Interconnection Requirements
5.3 Who to Contact
5.4 What to Ask for
5.5 Elements of and Agreement
5.6 Why Negotiate and What to Watch Out For
5.7 Future Possibilities for Selling Electricity
Introduction - iv
SECOND EDITION
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Introduction
OBJECTIVE
How Do I SELECT A CONSULTANT/DEVELOPER/PARTNER?
How do I know whether I need a consultant/developer/partner?
What should I look for in a consultant/developer/partner?
What should I include in a contract?
How Do I GET FINANCING FOR THE PROJECT?
What are the sources of funding for biogas projects?
What do lenders/investors look for?
How do I evaluate different financing options?
WHAT Do I NEED To KNOW ABOUT THE PERMITTING PROCESS?
What permits do I need?
How do I get these permits?
Do I need to worry about meeting air quality emission
standards from 1C engines?
Is A CENTRALIZED BIOGAS SYSTEM FEASIBLE?
How do I perform a preliminary feasibility evaluation?
Should we establish a formal legal entity?
How do I select a consultant?
What are the elements of a feasibility study?
What are the next steps if I want to proceed?
WHERE ARE BIOGAS SYSTEMS CURRENTLY OPERATIONAL?
WHERE CAN I GET A LIST OF NRCS AND OTHER KEY
CONTACTS?
WHERE CAN I GET HELP ON USING FARMWARE?
WHERE CAN I GET THE NRCS PRACTICE STANDARDS?
WHAT INFORMATION Is NEEDED FROM THE UTILITY FOR A
PRELIMINARY FEASIBILITY ASSESSMENT?
WHERE CAN I SEE WHAT TYPICAL UTILITY RATE SCHEDULES
LOOK LIKE?
WHERE CAN I GET A LIST OF DEVELOPERS AND EQUIPMENT
SUPPLIERS?
WHERE CAN I GET DEFINITIONS OF TECHNICAL TERMS
MENTIONED IN THIS HANDBOOK?
CHAPTER TO CONSULT
6. Selecting a Consultant/Developer/Partner
6.1 The Do-it- Yourself/Turnkey Decision
6.2 Selecting a Consultant/Consulting Firm
6.3 Selecting a Turn-Key Developer
6.4 Selecting a Partner
6.5 Preparing a Contract
7. Obtaining Project Financing
7. 1 Financing: What Lenders/Investors Look For
7.2 Financing Approaches
7. 3 Capital Cost of Different Financing Alternatives
8. Permitting and Other Regulatory Issues
8.1 The Permitting Process
8.2 Zoning and Permitting 8.3 Community Acceptance
8.4 Regulations Governing Air Emissions from Energy
Recovery Systems
9. Centralized Biogas Systems
9. 1 Preliminary Evaluation
9.2 Organization
9.3 Selecting a Consultant
9.4 The Feasibility Study
9.5 Next Steps
Appendix A: http://www.epa.gov/agstar/proiects/index.html
Appendix B:
http://offices.sc. egov.usda.gov/locator/app?agencv=nrcs
and
http://wwwl .eere.energv.gov/biomass/state regional.html
Appendix C: FarmWare User's Manual - Version 3.4
Appendix F: NRCS Practice Standards
Appendix G: Utility Letter of Request (Sample)
Appendix H: Utility Rate Schedules, Riders, and Interconnection
Requirements (Samples)
Appendix I: List of Designers, Equipment Suppliers, and
Vendors
Glossary
Introduction - v
SECOND EDITION
-------
Chapter 1 Overview of Biogas Technology
Contents:
List of Exhibits:
1-1. What are the Components of a Biogas System?
1
1-1.1 Manure Collection 1
1-1.2 Digester Types 2
1-1.3 Effluent Storage 3
1-1.4 Gas Handling 4
1-1.5 Gas Use 4
1-2. Benefits of Biogas Technology 4
1-3. The U.S. Biogas Experience 5
1-3.1 Reasons for Success 5
1-3.2 Reasons for Failure 6
1-3.3 Today's Experiences 6
Exhibit 1-1 Summary Characteristics of Digester Technologies 2
Exhibit 1 -2 Floating Cover Module for Lagoon Application 3
SECOND EDITION
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Chapter 1
Overview of Biogas Technology
'"The U.S. biogas experience in the 1970s and
1980s has demonstrated that biogas technology
is not applicable for all farms. In many situations
however, it can be a cost-effective and environmen-
tally friendly method for treating manure and liquid
waste. Biogas production is best suited for farms
that handle large amounts of manure as a liquid,
slurry, or semi-solid with little or no bedding added.
Biogas systems require a financial investment and a
management responsibility. The system must be
designed by an experienced animal waste digester
designer, who is well versed with the common prob-
lems associated with these types of systems. Addi-
tionally, the farm owner or operator must be com-
mitted to the digester's success.
This chapter provides an overview of biogas tech-
nology and opportunities to use this technology in
livestock facilities across the United States. First, a
brief description of biogas technology is provided.
Then the benefits of biogas technology are dis-
cussed. Finally, the experience and status of biogas
technology development in the United States are
described.
1-1. What are the Components of a
Biogas System?
Biogas technology is a manure management tool
that promotes the recovery and use of biogas as en-
ergy by adapting manure management practices to
collect biogas. The biogas can be used as a fuel
source to generate electricity for on-farm use or for
sale to the electrical grid, or for heating or cooling
needs. The biologically stabilized byproducts of
anaerobic digestion can be used in a number of
ways, depending on local needs and resources. Suc-
cessful byproduct applications include use as a crop
fertilizer, bedding, and as aquaculture supplements.
A typical biogas system consists of the following
components:
^ Manure collection
^ Anaerobic digester
^ Effluent storage
^ Gas handling
^ Gas use.
Each of these components is discussed briefly.
1-1.1 Manure Collection
Livestock facilities use manure management sys-
tems to collect and store manure because of sanitary,
environmental, and farm operational considerations.
Manure is collected and stored as either liquids, slur-
ries, semi-solids, or solids.
^ Raw Manure. Manure is excreted with a solids
content of 8 to 25 percent, depending upon ani-
mal type. It can be diluted by various process
waters or thickened by air drying or by adding
bedding materials.
^ Liquid Manure. Manure handled as a liquid
has been diluted to a solids content of less than
5 percent. This manure is typically "flushed"
from where it is excreted, using fresh or recy-
cled water. The manure and flush water can be
pumped to treatment and storage tanks, ponds,
lagoons, or other suitable structures before land
application. Liquid manure systems may be
adapted for biogas production and energy re-
covery in "warm" climates. In colder climates,
biogas recovery can be used, but is usually lim-
ited to gas flaring for odor control.
^ Slurry Manure. Manure handled as a slurry
has been diluted to a solids content of about 5 to
10 percent. Slurry manure is usually collected
by a mechanical "scraper" system. This manure
can be pumped, and is often treated or stored in
tanks, ponds, or lagoons prior to land applica-
tion. Some amount of water is generally mixed
SECOND EDITION
1-1
-------
Chapter 1
Overview of Biogas Technology
with the manure to create a slurry. For example,
spilled drinking water mixes with pig manure to
create a slurry. Manure managed in this manner
may be used for biogas recovery and energy
production, depending on climate and dilution
factors.
Semi-Solid Manure. Manure handled as a
semi-solid has a solids content of 10 to 20 per-
cent. This manure is typically scraped. Water is
not added to the manure, and the manure is typi-
cally stored until it is spread on local fields.
Fresh scraped manure (less than one week old)
can be used for biogas and energy production in
all climates, because it can be heated to promote
bacterial growth.
Solid Manure. Manure with a solids content of
greater than 20 percent is handled as a solid by a
scoop loader. Aged solid manure or manure that
is left "unmanaged" (i.e., is left in the pasture
where it is deposited by the animals) or allowed
to dry is not suitable for biogas recovery.
1-1.2 Digester Types
The digester is the component of the manure man-
agement system that optimizes naturally occurring
anaerobic bacteria to decompose and treat the ma-
nure while producing biogas. Digesters are covered
with an air-tight impermeable cover to trap the bio-
gas for on-farm energy use. The choice of which
digester to use is driven by the existing (or planned)
manure handling system at the facility. The digester
must be designed to operate as part of the facility's
operations. One of three basic options will gener-
ally be suitable for most conditions. Appendix F
contains several NRCS Conservation Practice Stan-
dards for digesters. Exhibit 1-1 summarizes the
main characteristics of these digester technologies:
^ Covered Lagoon Digester. Covered lagoons
are used to treat and produce biogas from liquid
manure with less than 3 percent solids. Gener-
ally, large lagoon volumes are required, prefera-
bly with depths greater than 12 feet. The typical
volume of the required lagoon can be roughly
estimated by multiplying the daily manure flush
volume by 40 to 60 days. Covered
Exhibit 1-1 Summary Characteristics of Digester Technologies
Characteristics
Digestion Vessel
Level of Technology
Supplemental Heat
Total Solids
Solids Characteristics
HRT* (days)
Farm Type
Optimum Location
Covered
Lagoon
Deep Lagoon
Low
No
0.5 - 3%
Fine
40-60
Dairy, Hog
Temperate and
Warm Climates
Complete Mix
Digester
Round/Square
In/Above -Ground
Tank
Medium
Yes
3 - 10%
Coarse
15+
Dairy, Hog
All Climates
Plug Flow
Digester
Rectangular
In-Ground Tank
Low
Yes
11 -13%
Coarse
15+
Dairy Only
All Climates
Fixed Film
Above Ground
Tank
Medium
No
3%
Very Fine
2-3
Dairy, Hog
Temperate and
Warm
* Hydraulic Retention Time (HRT) is the average number of days a volume of manure remains in the digester.
1-2
SECOND EDITION
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Chapter 1
Overview of Biogas Technology
lagoons for energy recovery are compatible with
flush manure systems in warm climates. Covered
lagoons may be used in cold climates for seasonal
biogas recovery and odor control (gas flaring).
There are two types of covers, bank-to-bank and
modular. A bank-to-bank cover is used in moderate
to heavy rainfall regions. A modular cover is used
for arid regions. Exhibit 1-2 illustrates a modular
floating cover for lagoon applications. Typically,
multiple modules cover the lagoon surface and can
be fabricated from various materials.
^ Complete Mix Digester. Complete mix digest-
ers are engineered tanks, above or below
ground, that treat slurry manure with a solids
concentration in the range of 3 to 10 percent.
These structures require less land than lagoons
and are heated. Complete mix digesters are
compatible with combinations of scraped and
flushed manure.
^ Plug Flow Digester: Plug flow digesters are
engineered, heated, rectangular tanks that treat
scraped dairy manure with a range of 11 to
13 percent total solids. Swine manure cannot be
treated with a plug flow digester due to its lack
of fiber.
^ Fixed Film Digester. Fixed-film digesters
consist of a tank filled with plastic media.
The media supports a thin layer of anaerobic
bacteria called biofilm (hence the term
"fixed-film"). As the waste manure passes
through the media, biogas is produced. Like
covered lagoon digesters fixed-film digest-
ers are best suited for dilute waste streams
typically associated with flush manure han-
dling or pit recharge manure collection.
Fixed-film digesters can be used for both
dairy and swine wastes. However, separa-
tion of dairy manure is required to remove
slowly degradable solids.
1-1.3 Effluent Storage
The products of the anaerobic digestion of manure
in digesters are biogas and effluent. The effluent is
a stabilized organic solution that has value as a fer-
Exhibit 1-2 Floating Cover Module for Lagoon Application in Arid Regions
Flotation on the underside
of cover, aH-foursides and
between cells
Tie-down points to
guy the cover
The cover is divided into
two or more cells for
efficiency and safety
w
deep skirt
eight on all
with chain
four sides
Courtesy of Engineered Textile Products, Inc.
SECOND EDITION
1-3
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Chapter 1
Overview of Biogas Technology
tilizer and other potential uses. Waste storage facili-
ties are required to store treated effluent because the
nutrients in the effluent cannot be applied to land
and crops year round.
The size of the storage facility and storage period
must be adequate to meet farm requirements during
the non-growing season. Facilities with longer stor-
age periods allow flexibility in managing the waste
to accommodate weather changes, equipment avail-
ability and breakdown, and overall operation man-
agement.
1-1.4 Gas Handling
A gas handling system removes biogas from the di-
gester and transports it to the end-use, such as an
engine or flange. Gas handling includes: piping; gas
pump or blower; gas meter; pressure regulator; and
condensate drain(s).
Biogas produced in the digester is trapped under an
airtight cover placed over the digester. The biogas
is removed by pulling a slight vacuum on the collec-
tion pipe (e.g., by connecting a gas pump/blower to
the end of the pipe), which draws the collected gas
from under the cover. A gas meter is used to moni-
tor the gas flow rate. Sometimes a gas scrubber is
needed to clean or "scrub" the biogas of corrosive
compounds contained in the biogas (e.g., hydrogen
sulfide). Warm biogas cools as it travels through the
piping and water vapor in the gas condenses. A
condensate drain(s) removes the condensate pro-
duced.
1-1.5 Gas Use
Recovered biogas can be utilized in a variety of
ways. The recovered gas is 60 - 80 percent methane,
with a heating value of approximately 600 - 800
Btu/ft3. Gas of this quality can be used to generate
electricity; it may be used as fuel for a boiler, space
heater, or refrigeration equipment; or it may be di-
rectly combusted as a cooking and lighting fuel.
Chapter 3 provides more information on biogas use.
Electricity can be generated for on-farm use or for
sale to the local electric power grid. The most
common technology for generating electricity is an
internal combustion engine with a generator. The
predicted gas flow rate and the operating plan are
used to size the electricity generation equipment.
Engine-generator sets are available in many sizes.
Some brands have a long history of reliable opera-
tion when fueled by biogas. Electricity generated in
this manner can replace energy purchased from the
local utility, or can be sold directly to the local elec-
tricity supply system. In addition, waste heat from
these engines can provide heating or hot water for
farm use.
Biogas can also be used directly on-site as a fuel for
facility operations. Equipment that normally uses
propane or natural gas can be modified to use bio-
gas. Such equipment includes boilers, heaters, and
chillers.
^ Boilers and Space Heaters. Boilers and space
heaters fired with biogas produce heat for use in
the facility operations. Although this may not
be the most efficient use of the gas, in some
situations it may be a farm's best option.
^ Chilling/Refrigeration. Dairy farms use con-
siderable amounts of energy for refrigeration.
Approximately 15 to 30 percent of a dairy's
electricity load is used to cool milk. Gas-fired
chillers are commercially available and can be
used for this purpose. For some dairies, this
may be the most cost effective option for biogas
utilization.
Other energy use options may exist. For example, a
nearby greenhouse could be heated with the biogas,
and carbon dioxide from the heater exhaust could be
used to enhance plant growth. These options need
to be evaluated on a case-by-case basis.
1-2. Benefits of Biogas Technology
Most confined livestock operations handle manure
as liquids, slurries, semi-solids, or solids that are
stored in lagoons, concrete basins, tanks, and other
containment structures. These structures are typi-
cally designed to comply with local and state envi-
ronmental regulations and are a necessary cost of
production.
Biogas technology can be a cost-effective, environ-
ment and neighborhood friendly addition to existing
1-4
SECOND EDITION
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Chapter 1
Overview of Biogas Technology
manure management strategies. Biogas technologies
anaerobically digest manure, resulting in biogas and
a liquefied, low-odor effluent. By managing the
anaerobic digestion of manure, biogas technologies
significantly reduce Biochemical Oxygen Demand
(BOD), and pathogen levels; remove most noxious
odors; and convert most of the organic nitrogen to
plant available inorganic nitrogen.
The principal reasons a farmer or producer would
consider installing a biogas system are:
^ On-Site Farm Energy. By recovering biogas
and producing on-farm energy, livestock pro-
ducers can reduce monthly energy purchases
from electric and gas suppliers.
^ Reduced Odors. Biogas systems reduce offen-
sive odors from overloaded or improperly man-
aged manure storage facilities. These odors im-
pair air quality and may be a nuisance to nearby
communities. Biogas systems reduce these of-
fensive odors because the volatile organic acids,
the odor causing compounds, are consumed by
biogas producing bacteria.
^ High Quality Fertilizer. In the process of an-
aerobic digestion, the organic nitrogen in the
manure is largely converted to ammonium.
Ammonium is the primary constituent of com-
mercial fertilizer, which is readily available and
utilized by plants.
^ Reduced Surface and Groundwater Con-
tamination. Digester effluent is a more uniform
and predictable product than untreated manure.
The higher ammonium content allows better
crop utilization and the physical properties al-
low easier land application. Properly applied,
digester effluent reduces the likelihood of sur-
face or groundwater pollution.
^ Pathogen Reduction. Heated digesters reduce
pathogen populations dramatically in a few
days. Lagoon digesters isolate pathogens and
allow pathogen kill and die-off prior to entering
storage for land application.
Biogas recovery can improve profitability while im-
proving environmental quality. Maximizing farm
resources in such a manner may prove essential to
remain competitive and environmentally sustainable
in today's livestock industry. In addition, more
widespread use of biogas technology will create jobs
related to the design, operation, and manufacture of
energy recovery systems and lead to the advance-
ment of U.S. agribusiness.
1-3. The U.S. Biogas Experience
Rising oil prices in the 1970's triggered an interest
in developing "commercial farm-scale" biogas sys-
tems in the United States. During this developmen-
tal period (1975-1990) approximately 140 biogas
systems were installed in the United States, of which
about 71 were installed at commercial swine, dairy,
and caged layer farms.
Many of these initial biogas systems failed. How-
ever, learning from failures is part of the technology
development process. Examining past failures and
successes led to improvements and refinements in
existing technologies and newer, more practical sys-
tems. The main reasons for the success and failure
of biogas recovery projects follow.
1-3.1 Reasons for Success
Biogas recovery projects succeeded because:
1. The owner/operator realized the benefits biogas
technology had to offer and wanted to make it
work.
2. The owner/operator had some mechanical
knowledge and ability and had access to techni-
cal support.
3. The designer/builder built systems that were
compatible with farm operation.
4. The owner/operator increased the profitability of
biogas systems through the utilization and sale
of manure byproducts. Some facilities generate
more revenues from the sale of electricity and
other manure byproducts than from the sale of
milk.
SECOND EDITION
1-5
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Chapter 1
Overview of Biogas Technology
1-3.2 Reasons for Failure
Biogas recovery projects failed because:
1. Operators did not have the skills or the time re-
quired to keep a marginal system operating.
2. Producers selected digester systems that were
not compatible with their manure handling
methods.
3. Some designer/builders sold "cookie cutter" de-
signs to farms. For example, of the 30 plug flow
digesters built, 19 were built by one designer
and 90 percent failed.
4. The designer/builders installed the wrong type
of equipment, such as incorrectly sized engine-
generators, gas transmission equipment, and
electrical relays.
5. The systems became too expensive to maintain
and repair because of poor system design.
6. Farmers did not receive adequate training and
technical support for their systems.
7. There were no financial returns of the system or
returns diminished overtime.
8. Farms went out of business due to non-digester
factors.
This handbook draws from these lessons and pro-
vides a realistic screening process for livestock fa-
cilities to decide if biogas technology is an appropri-
ate match for the farm and farm owner.
1-3.3 Today's Experiences
The development of anaerobic digesters for
livestock manure treatment and energy production
has accelerated at a very face pace over the past few
years. Factors influencing this market demand
include: increased technical reliability of anaerobic
digesters through the deployment of successful
operating systems over the past decade; growing
concern of farm owners about environmental
quality; an increasing number of states and federal
programs designed to cost share in the development
of these systems; and the emergence of new state
energy policies designed to expand growth in
reliable renewable energy and green power markets.
There are currently about 70 operating digester
systems, with another 35 planned for construction in
2004. Six of these centralized systems provide
manure treatment for surrounding farms. Currently,
three centralized systems are operational and three
more are planned. A methodology for assessing and
reviewing centralized projects is discussed further in
Chapter 9. More information on some of the
operating digesters can be found in Appendix A.
1-6
SECOND EDITION
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Chapter 2
Preliminary Screening for
Project Opportunities
Contents:
List of Exhibits:
2-1. Is the Confined Livestock Facility "Large"? 1
2-1.1 Is the Livestock Facility "Large" 1
2-1.2 Is Manure Production and Collection Stable Year Round? 2
2-2. Is Your Manure Management Compatible with Biogas
Technology?
2-2.1 What Type of Manure is Collected?
2-2.2 Is the Manure Collected at One Point?
2-2.3 Is the Manure Collected Daily or Every Other Day?.
2-2.4 Is the Manure Free of Large Amounts of Bedding?...
.3
.3
.4
.4
2-3. Is There a Use for Energy?
2-4. Can You Manage a Biogas System Effectively?
2-5. Initial Appraisal Results
Exhibit 2-1 Checklist for Facility Characteristics.
Exhibit 2-2 Appropriate Manure Characteristics and Handling Systems for
Specific Types of Biogas Digester Systems 3
Exhibit 2-3 Checklist for Manure Management 4
Exhibit 2-4 Checklist for Energy Use 5
Exhibit 2-5 Checklist for Management 6
Exhibit 2-6 Initial Appraisal Results Checklist 7
SECOND EDITION
2-i
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Chapter 2
Preliminary Screening for Project
Opportunities
This chapter presents a preliminary screening
process for livestock producers, developers, or
others considering biogas recovery to determine if
their livestock facility is a candidate for a biogas
project. In general, facilities that collect large
amounts of manure daily, or at least weekly, should
consider biogas technology.
The screening criteria are as follows:
1. Is Your Confined Livestock Facility (Dairy or
Hog) "Large"? For screening purposes, live-
stock facilities with at least 500 head of dairy
cows/steers or 2,000 sows or feeder pigs in con-
finement, where at least 90 percent of the ma-
nure is collected regularly, are potential candi-
dates. Facilities of this size produce enough
manure to generate the biogas required to sup-
port a financially viable project. It should be
noted, however, that this size criterion is not ab-
solute. Smaller confined facilities could poten-
tially support successful recovery projects,
given certain site-specific and market condi-
tions.
Note: "Large" is referred to here for purposes
of biogas assessment, and does not
pertain to any other agency definition
or program.
2. Is Manure Production and Collection Stable
Year-Round? Animal facilities that have little
variation in the daily confined animal popula-
tions have predictable manure production. This
will ensure that a consistent amount of manure
is available for collection year-round.
3. Is Your Manure Management Compatible
with Biogas Technology? Biogas technology
requires the manure to be: managed as liquid,
slurry, or semi-solid; collected at one point; col-
lected regularly (daily or weekly); and free of
large quantities of bedding and other materials
(e.g., rocks, stones, sand, straw). Farms with
such manure management practices provide an
opportunity to install a biogas system.
4. Is There a Use for the Energy Recovered?
The potential to use the recovered biogas for en-
ergy plays a significant role in determining the
cost-effectiveness of the biogas project. Both
on-farm energy requirements and the possibility
of selling energy off-site should be considered.
In general, any piece of equipment that uses
propane or natural gas as a fuel source can po-
tentially be operated using biogas.
5. Will You be Able to Manage the System Effi-
ciently? Biogas systems are a management re-
sponsibility. Efficient system management re-
quires the owner/operator to:
1. pay regular attention to system opera-
tions;
2. provide necessary repair and mainte-
nance; and,
3. have the desire to see the system succeed.
Each of the steps in the assessment is discussed in
turn. This chapter concludes with a summary of the
overall appraisal.
2-1. Is the Confined Livestock Facility
"Large"?
Confined animals produce collectable manure for
digestion consistently all year round. Large live-
stock facilities generally produce enough manure to
support a biogas project. Such farms have predict-
able biogas yields available to offset energy usage.
2-1.1 Is the Livestock Facility "Large"
Livestock facility size is a primary indicator of
whether biogas recovery will be economically feasi-
ble.
Although there are many factors that influence bio-
gas production from livestock manure, the amount
of manure collected determines the amount of bio-
gas that can be produced. The amount of manure
produced by a livestock facility will be directly
related to the number of animals in the facility.
However, biogas can only be produced from fresh
manure collected on a regular schedule, with a
minimum amount of contamination. With this in
mind, the number of animals (dairy cows or hogs) in
a facility can be used as an indicator of whether that
SECOND EDITION
2-1
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Chapter 2
Preliminary Screening for Project
Opportunities
operation generates, or has the potential to generate,
a significant amount of biogas. The number of ani-
mals and proportion of the manure collected can be
used to indicate whether more detailed technical
assessments should be undertaken.
As a general rule of thumb, manure collection
equivalent to the total daily manure production from
500 dairy cows or 2,000 sows or feeder pigs is the
minimum size to be considered. This rough estimate
takes into account the general manure production
rate and manure composition of these animals. This
minimum value is not absolute. Other factors, such
as climate, diet, value of energy, odor and other en-
vironmental concerns, and existing manure man-
agement system can affect this minimum value. The
software tool, Farm Ware contained in this handbook
allows you to evaluate the impact of these factors in
terms of farm costs and benefits.
2-1.2 Is Manure Production and Collection
Stable Year Round?
In addition to a minimum number of animals from
which manure is collected, candidate facilities
should have relatively constant animal populations
year round. This will ensure that a consistent
amount of manure is available for collection year
round. Knowing the amount of collectible manure is
critical in sizing the digester and gas use compo-
nents. If the daily manure produced is greater or
less than the digester capacity, there will be addi-
tional costs of manure management or loss of reve-
nues and/or savings from under-utilization.
For example, in a free-stall dairy where the animals
remain confined in a free-stall barn throughout the
year, manure can be collected consistently - allow-
ing the digester to be fueled all year round. Alterna-
tively, animals that are pastured in summer and
housed in a barn in winter will not provide a steady
supply of manure to the digester year round.
2-2. Is Your Manure Management
Compatible with Biogas Technology?
Biogas production is best suited for farms that col-
lect liquid, slurry, or semi-solid manure with little or
no bedding regularly. This requires the facility to
collect manure:
^ as a liquid, slurry, or semi-solid;
^ at a single point;
^ every day or every other day;
^ free of large amounts of bedding or other mate-
rials (e.g., rocks, stones, straw, sand)
These conditions ensure consistent digester feed-
stock and continued biogas production. Each condi-
tion is discussed in turn.
Exhibit 2-3 presents a simple checklist for manure
Exhibit 2-1 Checklist for Facility Characteristics
Do you have at least 500 cows/steer or 2,000 pigs at your facility?
Are these animals in confinement all year round?
Yes Q No
Yes a No
The average animal population does not vary by more than 20% in a
year?
If the answer is to all the above questions, your facility is in good shape.
If the answer is to one or more of the above questions, the produc-
tion 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 bio-
However, collecting and flaring biogas can reduce odors. Therefore, also
proceed to the next section if you have the need for an effective odor control strategy.
2-2
SECOND EDITION
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Chapter 2
Preliminary Screening for Project
Opportunities
management conditions favoring biogas technology.
2-2.1 What Type of Manure Is Collected?
Livestock facilities that collect manure as a liquid,
slurry, or semi-solid are the best candidates for bio-
gas recovery projects. At such facilities, farm op-
erators will know the daily operational management
requirements for these materials and it is likely that
the manure can be digested to produce biogas.
Whether manure is handled as a semi-solid, slurry,
or liquid at a particular facility depends on its total
solids content. Exhibit 2-2 shows the manure char-
acteristics and handling systems that are appropriate
for specific types of biogas production systems.
Manure handled as a liquid has a total solids content
of less than 5%; a manure slurry has a solids content
of 5% to 10%; and semi-solid manure has a solids
content of 10% to 20%. Liquid, slurry, and semi-
solid systems have high biogas production potentials
and offer substantial greenhouse gas reduction po-
tential. These management systems are widely used
on swine and dairy operations, and under some con-
ditions can produce undesirable odor events. Dry lot
housing or manure packs produce manure with total
solids above 25%. These high solid systems do not
promote anaerobic conditions that lead to biogas
production, and should not be considered as inputs
to a biogas system.
Facilities that handle solid manure will find it diffi-
cult to adopt biogas technology. They will need to
incorporate a new manure handling system and rou-
tine. Such changes can be expensive. In these situa-
tions, other effective manure management options
(e.g., composting) should be considered.
2-2.2 Is the Manure Collected at One Point?
Generally, most confined facilities collect manure at
one point. Facilities that collect and deliver manure
to a common point every day or every other day are
better candidates for biogas technology. The com-
mon point may be a lagoon, pit, pond, tank, or other
similar structure.
Collecting manure at a common point makes it eas-
ier to load the digester. At this point, the manure
may be pre-treated before entering a digester. Pre-
treatment adjusts the total solids content as required
by digesters. This may include adding water, sepa-
rating solids, manure mixing, or manure heating.
If the facility does not collect manure at a common
point, you should assess the feasibility of altering
current practices to do so. If there are only two or
three points of collection, it may be possible to use a
Exhibit 2-2 Appropriate Manure Characteristics and Handling Systems for Specific Types of Biogas Di-
gester Systems
Total Solids (%)
0 5 10 15 20 25 30
Manure
Water Added
Bedding Added
As Excreted
Classification Liquid Slurry
Semi-Solid
Solid
Handling Options
Pump
Scrape
Scrape and Stack
Biogas Production
Recommended
Not Recommended
Digester Type
Covered
Lagoon or
Fixed Film
Complete
Mix
Plug
Flow
SECOND EDITION
2-3
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Chapter 2
Preliminary Screening for Project
Opportunities
digester at the largest of these points.
2-2.3 Is the Manure Collected Daily or
Every Other Day?
Manure is the feedstock for a digester system.
While an occasional daily feeding of a digester
might be missed with little consequence under nor-
mal operations, not feeding a digester for a week can
lead to a loss of biogas production. More
importantly, feeding the digester in irregular inter-
vals can disrupt the biological process and cause the
system to work inefficiently or stop entirely. There-
fore, most digesters are designed to be fed daily.
With continuous feed and discharge of material from
the system, the bacteria work efficiently and higher
volumes of manure are processed.
Daily manure collection is also efficient in terms of
conserving the nutrient values of the manure and
preserving its gas production potential. Any de-
composition of organic material outside the digester
will reduce biogas production. Therefore, it is best
to feed fresh manure to a digester.
If you do not collect manure daily, you should con-
sider converting to daily manure collection.
2-2.4 Is the Manure Free of Large Amounts
of Bedding?
The manure should be free of large quantities of
bedding and other materials such as sand, rocks, and
stones. Only a small amount of bedding can be tol-
erated by most digesters.
Bedding materials (e.g., sawdust, straw) often end
up in the manure. Clumps of bedding will clog in-
fluent and effluent pipes of the digester and hinder
operation. Small amounts of bedding will not be a
problem and minimizing bedding addition to digest-
ers is relatively simple, in most cases.
Other materials such as feed additive including anti-
biotics and equipment cleaning and maintenance
compounds (e.g., detergents, acids, halogens, etc.)
may be harmful to anaerobic bacterial action. The
typical use of these materials has not been found to
be a problem in full scale digesters. However,
threshold levels for these compounds have not been
established, so operators should be careful not to
release large quantities of such materials into the
manure before it is fed to the digester.
Exhibit 2-3 Checklist for Manure Management
Do you collect manure as a liquid/slurry/semi-solid?
Is the manure collected and delivered to one common point?
Is the manure collected daily or every other day?
Is the manure sand relatively free of clumps of bedding and other material, such
Yes Q No
Yes a No
Yes a No
to all the above questions, manure management criterion is satisfied.
, to any of the questions, you may need to change your manure management routine.
2-4
SECOND EDITION
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Chapter 2
Preliminary Screening for Project
Opportunities
2-3. Is There a Use for Energy?
The most cost effective biogas projects are those
where the energy in the biogas can be used or sold.
In many cases, the value of the energy produced
from the gas can more than offset the cost of collect-
ing and processing the gas, thereby making the pro-
ject cost effective on its own. The purpose of this
step is to assess whether it is likely that there are
suitable uses for the gas recovered from the live-
stock facility manure.
There are two main gas use options: (1) generation
of electricity for on-site use or sale to the power
grid; and (2) direct use of the gas locally, either on-
site or nearby.
The biogas can be used to fuel a reciprocating en-
gine or gas turbine, which then turns a generator to
generate electricity. Modern mechanized dairies and
swine facilities typically require a significant
amount of electricity to operate equipment. For ex-
ample, dairies operate vacuum pumps, chillers, feed
mixers, and fans. Swine facilities typically operate
heat lamps and ventilation equipment. If the elec-
tricity is not required on-site, it could be sold to the
local power grid.
On-farm use of the gas is often simple and
cost-effective. The biogas can be used to fuel boil-
ers or heaters, and in most processes requiring heat,
steam, or refrigeration. Dairies and swine farms
generally require hot wash water for cleaning and
other operations. However, most farms can produce
far more gas than they require to replace on-site gas
needs.
Other energy use options may present themselves on
a case-by-case basis. For example, a specialized
need for gas nearby, or a simple flare may be used to
control odor and reduce greenhouse gas emissions.
Exhibit 2-4 presents a checklist to assess whether
energy use options are likely to exist.
2-4. Can You Manage a Biogas System
Effectively?
Good design and management is key to the success
of a biogas system. Many systems have failed be-
cause operators did not have the technical support,
the time, the skills, or the interest required to keep
the system operating. The owner should realize that
a digester requires regular attention, but not much
time. If the owner is committed to seeing a digester
succeed, generally it will. Effective management
requires the following:
^ Technical Support. There are key components
of a digester system with which the owner must
become familiar. Operation and maintenance of
the digester and biogas use system should be
taught by the designer to the owner. Competent
technical support from the digester designer or a
designer consultant may be needed occasionally
to solve rare or unusual problems.
^ Time. System operation requires a time com-
mitment. Daily maintenance and monitoring of
Exhibit 2-4 Checklist for Energy Use
Are there on-site uses (e.g., heating, electricity, refrigeration) for the energy
Are there facilities nearby that could use the biogas?
Yes Q No
Are there electric power distribution systems in your area that could or do
buy power from projects such as biogas recovery? _X^9__No_Q.
to any of the above questions,
the energy use criterion is satisfied for initial screening purposes.
SECOND EDITION
2-5
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Chapter 2
Preliminary Screening for Project
Opportunities
a system require approximately 15-30 minutes.
Additionally, infrequent blocks of time for re-
pair and preventive maintenance are required.
The time required for these tasks ranges from
approximately 10 minutes to 10 hours, with
most maintenance tasks requiring 30 minutes to
2 hours. The need for (and lack of) infrequent
major repairs has led to the failure of many sys-
tems.
Technical skills. A biogas system will require
some maintenance. In addition to the general
mechanical skills found at most farms, an indi-
vidual skilled in engine repair and maintenance
is invaluable. This does not imply that a full-
time mechanic is required. Rather, an individual
with some mechanical knowledge and ability is
sufficient. Typical skills required include en-
gine repair, maintenance, and overhauls; trou-
bleshooting and repair of electrical control prob-
lems; plumbing; and welding. Additionally, re-
pair parts and services should be easily accessi-
ble. These services are often available through
equipment dealers. Access to these services is
an important consideration when making a deci-
sion on equipment purchases.
Desire. The owner must accept the system as
his/her own and want to operate it. Owners
should understand how the technology works
and be committed to seeing the system succeed.
Systems where the management was left to sea-
sonal farm labor or third parties often failed be-
cause of lack of motivation and incentive.
In the ideal management scenario, a trained per-
son would spend approximately 30 minutes to 1
hour a day operating the system. This person
would understand the fundamentals of anaerobic
digestion and would be involved in the opera-
tion and maintenance of the system. Addition-
ally, this person would possess the technical
acuity to understand and operate mechanical
equipment. Ideally, this person would be part of
the planning and construction of the system. In
cases where the operator is not the owner, oper-
ating incentives such as bonuses based on sys-
tem "up time" may be considered.
Exhibit 2-5 Checklist for Management
Is there a "screw driver friendly" person on the farm that can operate and
maintain the technical equipment?
If YES, can this person spend about 30 minutes a day to manage the system
and 1 to 10 hours on occasional repair and maintenance?
Will this person be available to make repairs during high labor use events at
the farm?
Will the owner be overseeing system operations?
Yes Q No
Yes a No
to the above questions, the management criterion is satisfied.
In general, if the owner is committed to seeing the system succeed, it will.
2-6
SECOND EDITION
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Chapter 2
Preliminary Screening for Project
Opportunities
2-5. Initial Appraisal Results
Using the information from the above four steps, the
initial appraisal can be performed. Exhibit 2-6 lists
the questions addressed by the four steps.
Even if one or more questions cannot be answered
"Yes," there may be opportunities for biogas recov-
ery under certain circumstances.
Special Conditions
The following types of special conditions would
favor gas recovery from livestock manure facilities:
^ Severe Odor Problems. At some farms, the
odors associated with livestock manure impair
air quality, are a nuisance to neighbors, and may
become grounds for lawsuits. In areas where
odor related problems are significant, the instal-
lation of a biogas recovery system will be fa-
vored, as it removes offensive manure odors.
Using digesters primarily for odor control is
cost-effective if the costs of not controlling odor
are substantial.
Environmental Problems. The Federal Clean
Water Act requires zero discharge of contami-
nated run-off because manures are a source of
agricultural pollution, affecting waterways, soil,
and groundwater. Biogas recovery systems can
help reduce this pollution by giving the owner a
point of control and revenue from manure man-
agement.
High Energy Cost. High energy costs favor
biogas recovery projects. In high cost environ-
ments (e.g., electricity costing more than $0.08
per kWh), smaller sites (e.g., 200 cows) could
potentially support profitable gas recovery pro-
jects.
High Cost of Commercial Fertilizer. High
costs of commercial fertilizers favor biogas re-
covery projects. In the process of biogas recov-
ery, the organic nitrogen content of the manure
is largely converted to ammonium, a higher
value and more predictable form of plant avail-
able nitrogen.
Exhibit 2-6 Initial Appraisal Results Checklist
Are there at least 500 cows/steers or 2,000 hogs in confinement at your
facility year round?
Is your manure management compatible with biogas technology?
Can you use the energy?
Can you be a good operator?
Yes Q No
Yes a No
Yes a No
Yes a No
to all questions, there are promising options for gas recovery. Proceed to Chap-
ter 3, where the project technical and economic feasibility will be determined. If you answered
to any of the questions, you may need to make some changes. Read the relevant section, evaluate the
cost of changes required, if any, before proceeding.
SECOND EDITION
2-7
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Chapter 2 Preliminary Screening for Project
Opportunities
Compost, Potting Soil, and Soil Amendment
Markets. Digested dairy manure solids can be
used to replace purchased bedding or can be
sold alone and in mixes for potting soil and gar-
den soil amendments. Regional markets exist
for soil products. Digested solids have been
sold to wholesale and retail customers.
Niche Applications. Options for utilizing the
by-products of anaerobic digestion may present
themselves. For example, the digester effluent
may be used to stimulate the growth of algae in
fishponds and thereby provide feed for fish.
These niche options must be evaluated on a
case-by-case basis.
SECOND EDITION
-------
Chapter 3 Selecting a Gas Use Option
Contents:
3-1. Electricity Generation 2
3-1.1 Electricity Generation System Components 2
3-1.2 Electricity Generation Options 3
3-2. Direct Combustion 4
3-2.1 Heating 4
3-2.2 Chilling/Refrigeration 4
List of Exhibits:
Exhibit 3-1 Summary of Potential Gas Use Options 1
Exhibit 3-2 Typical Engine-Generator Set 3
Exhibit 3-3 Hot Water Mats Replace Heat Lamps in Farrowing
Buildings for Additional Energy Savings 4
SECOND EDITION 3~l
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Chapter 3
Selecting a Gas Use Option
The purpose of this chapter is to examine how
biogas can be used at a farm. Electricity genera-
tion with waste heat recovery (cogeneration) is usu-
ally the most profitable option for a farm. However,
other options may be profitable in certain circum-
stances. This chapter serves as a reference to deter-
mine what factors need to be considered when de-
termining how to use the biogas.
There are several important factors to be considered
when selecting a biogas use option:
^ What type of energy does the farm use?
Farms use electricity, natural gas, propane, or
fuel oil energy. Biogas can be used to replace
purchased energy for electricity, heating, or
cooling. For most farms, the most profitable
biogas use option will be to fuel an internal
combustion (1C) engine or gas turbine driven
generator to produce electricity. Other options
include using biogas to fuel forced air furnaces,
direct fire room heaters, and adsorption chillers.
^ How much energy does the farm use and
when? Farm energy requirements will vary
daily and seasonally. For example: heating and
air conditioning are seasonal uses; most lighting
is used at night; milking two or three times a day
for four hours is a very uneven use of electricity;
and hog barn ventilation varies by the time of
day and season. Most farm operations have the
potential to produce most or all their energy
needs if they collect and convert all suitable ma-
nure produced to biogas.
^ Will the potential energy production offset
energy needs? When matching biogas avail-
ability to energy requirements, it is important to
keep in mind that biogas is produced year round
and biogas storage for more than several hours
is expensive. Therefore, the most cost-effective
biogas use option is one that uses the gas year
round. Direct gas use options, such as space
heating and cooling, vary seasonally. Further-
more, these options can use only a small fraction
of the potential energy from biogas. Designing
a system for such a limited use will generally
not be cost effective, unless the system is for
purposes of odor control. Large farms may be
able to match biogas energy production more
closely to energy use than will small farms.
^ Is electricity the primary energy require-
ment? In the United States, electricity is the
largest stationary use of energy on farms. Elec-
tric motors for pumps, fans, and motors, as well
as lights are generally in use all year round.
Usually electricity production for on-farm use is
the most viable option.
^ Can the engine generator be serviced? Easy
access for maintenance tasks and ready
availability of parts and services are critical con-
siderations.
The potential gas use options are discussed in turn
and summarized in Exhibit 3-1.
For further discussion of gas use options, review
The Handbook of Biogas Utilization, available from
General Bioenergy, P.O. Box 26, Florence, Alabama
35631, Phone: (256) 740-5634.
Exhibit 3-1 Summary of Potential Gas Use
Options
Option
Electricity
Generation
Applicability
Suitable for most facili-
ties (electricity accounts
for approximately 70 to
100% of energy use).
Direct Combustion
Boiler/Furnace
Chiller
Seasonal use or special-
ized situations
Dairy refrigeration (ap-
proximately 15 to 30%
of dairy electricity use);
seasonal cooling; and
specialized situations
SECOND EDITION
3-1
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Chapter 3
Selecting a Gas Use Option
3-1. Electricity Generation
Electricity can be generated for on-farm use or for
sale to the local electric power grid. Modern dairies
and swine facilities require a significant amount of
electricity to operate equipment. Hog nurseries re-
quire a large amount of circulating heat, but few
have hot water heat. Almost all use electric heat
lamps and supplemental propane heaters to maintain
a suitable temperature. Similarly, 30 percent of
dairy electricity consumption is used to cool milk.
The most commonly used technology for generating
electricity is an internal combustion engine with a
generator. Recovering waste heat from these en-
gines can provide heating, hot water for farm use, or
hot water for digester heating thereby improving the
overall energy efficiency of the system.
3-1.1 Electricity Generation System
Components
Typical electricity generation systems consist of: (1)
an 1C engine or gas turbine; (2) a generator; (3) a
control system, and (4) an optional heat recovery
system. Each component is discussed briefly, in
turn.
1. 1C Engine or Gas Turbine. Both 1C en-
gines and gas turbine driven generators sets
are being used to generate electricity from
biogas.
^ 1C Engine. Natural gas or propane engines
are easily converted to burn biogas by modi-
fying carburetion and ignition systems.
Natural gas engines are available in virtually
any capacity that is required. The most suc-
cessful engines are industrial natural gas en-
gines that can burn wellhead natural gas. A
biogas fueled engine generator will nor-
mally convert 18-25 percent of the biogas
BTUs to electricity, depending on engine
design and load factor. Gas treatment is not
necessary if proper maintenance procedures
are followed. Biogas engines less than 200
horsepower (150 kW) generally meet the
most stringent California pollution restric-
tions without modification if run with a lean
fuel mixture. Exhibit 3-2 shows a typical
engine-generator set.
^ Gas Turbines. Small gas turbines that are
specifically designed to use biogas are also
available. An advantage to this technology
is lower NOx emissions and lower mainte-
nance costs, however energy efficiency is
less than with 1C engines and it costs more.
2. Generator. There are two types of generators
that are used on farms: induction generators and
synchronous generators.
^ Induction Generator. An induction genera-
tor will operate in parallel with the utility
and cannot stand alone. Induction genera-
tion derives phase, frequency, and voltage
from the utility. Negotiations with a utility
for interconnection of a small induction
generator are generally much easier.
^ Synchronous Generator. A synchronous
generator will operate either isolated or in
parallel. The synchronous generator can
provide electricity to the farm if the utility is
shut down. Synchronous parallel generation
requires a sophisticated interconnection to
match generator output to utility phase, fre-
quency, and voltage. This is typically more
expensive than controls for an induction
generation.
Most farm-scale systems will use induction gen-
erators. The options for electricity generation
modes (isolated versus parallel) are discussed
further in Section 3-1.2.
3. Control System. Controls are required to pro-
tect the engine and to protect the utility. These
systems are well developed. Control packages
are available that shut the engine off due to me-
chanical problems such as high water tempera-
ture or low oil level. The control system will
also shut off the engine if the utility power is
off, or if utility electricity is out of its specified
voltage and frequency range. It is important to
recognize that the control system selected must
be designed to operate in a damp environment
where corrosive gases, such as ammonia, may
be present.
3-2
SECOND EDITION
-------
Chapter 3
Selecting a Gas Use Option
4. Waste Heat Recovery. Approximately 75 per-
cent of fuel energy input to an engine is rejected
as waste heat. Therefore, it is common practice
to recover engine heat for heating the digester
and providing water and space heat for the farm.
Commercially available heat exchangers can re-
cover heat from the engine water cooling system
and the engine exhaust. Properly sized heat ex-
changers will recover up to 7,000 BTUs of heat
per hour for each kW of generator load, increas-
ing energy efficiency to 40 - 50 percent.
3-1.2 Electricity Generation Options
A farm may choose to use a stand-alone engine-
generator to provide all or part of its own electricity
as an "isolated" system (disconnected from the util-
ity). It may also operate connected to and interfac-
ing electricity with the utility, "in parallel". Most
farms will opt for parallel power production.
^ Isolated Power Production. An isolated sys-
tem must be able to function continuously,
without interruption, to meet fluctuating levels
of electricity demand while maintaining a
smooth and steady 60 cycle current. Varying
electric loads or large motor starting loads can
lead to drift in the 60 cycle current. Drift results
in wear on the motors, speed up or slow down of
clocks and timers, and operating problems with
computers and programmable logic controllers.
Isolated systems require a sophisticated control
system and a gas reservoir to meet changing
loads. They are generally oversized to accom-
modate the highest electrical demand while op-
erating less efficiently at average or partial load.
The primary advantage of an isolated power
production system is that it is free from the util-
ity.
The disadvantages of isolated power production
include: (1) having to operate and maintain the
system at all times; (2) purchasing oversized and
costly equipment, if high quality electricity is
needed; (3) purchasing and maintaining a
backup generation system or paying the utility
for backup service, if electricity is critical to
farm operations; (4) requiring an engine that is
sized to meet maximum farm load (varying load
means that the engine has to increase or de-
crease output implying that the engine is operat-
ing inefficiently); and (5) managing electricity
use to reduce demand fluctuations.
^ Parallel Power Production. A parallel system
is directly connected to the utility and matches
the utility phasing, frequency and voltage so the
farm produced electricity blends directly with
the utility line power. A utility interconnection
panel with safety relays is required to operate in
parallel and to disconnect the farm generator if
there is a problem with either utility or farm
generation.
Parallel operation allows the farm generator to
run at a constant output regardless of farm de-
mand. Constant output allows more efficient
use of biogas and less wear on the engine. The
engine-generator can be sized for the biogas
availability as opposed to farm requirements.
The farm buys power when under-producing
and sells power when overproducing. The util-
ity is the backup system if engine maintenance
is required.
The key issue in developing a profitable biogas re-
covery system is the value of the energy to the
owner. A careful review of utility rates and inter-
connection requirements are necessary prior to se-
lecting the operating mode. Rate negotiation is ap-
propriate for farm scale projects as most rules are set
Exhibit 3-2 Typical Engine-Generator Set
SECOND EDITION
3-3
-------
Chapter 3
Selecting a Gas Use Option
up for very large independent power producers.
Chapter 5 discusses how a livestock producer should
negotiate with a utility. Farm Ware can help you un-
derstand the impact of utility rates on electrical costs
and expected revenues from the project.
3-2. Direct Combustion
The recovered biogas can be used directly on-site as
a fuel. Equipment that normally uses propane or
natural gas such as boilers, forced air furnaces, and
chillers, can be modified to use biogas. Typical
farms use only a limited amount of these fuels com-
pared to electricity.
3-2.1 Heating
Heating is usually a seasonal operation. Boilers and
forced air furnaces can be fired with biogas to pro-
duce heat. Although this may be an efficient use of
the gas, it is generally not as convenient as electric-
ity. Nevertheless, in some situations it may be a
best option.
^ Boilers. Thousands of biogas-fired boilers are
in use at municipal waste treatment plants in the
United States, where they provide hot water for
building and digester heat. Conversion efficien-
cies are typically at 75 to 85 percent. Several
have been installed on farm digesters. Farms
require hot water year round, but there is typi-
cally more biogas available than hot water re-
quired. Farrow to wean and farrow to nursery
hog farms in cold climates are the only type of
farm where heat requirements could consume
most or all of the available biogas production
potential. Exhibit 3-23 shows.
A cast iron natural gas boiler can be used for
most farm applications. The air-fuel mix will
require adjustment and burner jets will have to
be enlarged for medium BTU gas. Cast iron
boilers are available in a wide range of sizes,
from 45,000 BTU/hour and larger. Untreated
biogas can be burned in these boilers. However,
all metal surfaces of the housing should be
painted. Flame tube boilers with heavy gauge
flame tubes may be used if the exhaust tempera-
ture is maintained above 300°F to minimize
condensation. High hydrogen sulfide (H2S)
concentration in the gas may result in clogging
of flame tubes.
Forced Air Furnaces. Forced air furnaces
could be used in hog farms in place of direct
fired room heaters, which are commonly used in
hog farrowing and nursery rooms. A farm will
typically have multiple units. Biogas fired units
have not been installed in the United States due
to a number of reasons. These heaters are avail-
able and in use in Taiwan.
3-2.2 Chilling/Refrigeration
Dairy farms use considerable amounts of energy for
refrigeration. Approximately 15 to 30 percent of a
dairy's electricity load is used to cool milk. Gas-
fired chillers are commercially available and can be
used for this purpose. For some dairies, this may be
the most profitable option for biogas utilization.
Gas-fired chillers produce cold water for milk cool-
ing or air conditioning. Dairies cool milk every day
of the year. Chilled water or glycol can be used in
milk precoolers in place of well water. Units are
under development that should produce glycol at
temperatures less than 30°F and allow direct refrig-
eration. A dairy generally requires 0.014 tons of
cooling per hour of milking per cow per day. This is
about 15 percent of the potential biogas production
Exhibit 3-3 Hot Water Mats Replace Heat
Lamps in Farrowing Buildings for Additional En-
ergy Savings
SECOND EDITION
-------
Chapter 3 Selecting a Gas Use Option
from the same cow (one ton of cooling = 12,000
BTU/hour).
Double effect chillers, producing hot and cold water
simultaneously, are available for applications of
over 30 tons and could be coupled with a heated
digester.
SECOND EDITION 3"5
-------
Chapter 4 Technical and Economic Feasi-
bility Assessment
Contents:
4-1. Match a Digester to Your Facility
4-1.1 Where Is The Facility Located?
4-1.2 What is the Total Solids Content of the Manure? .......................... 3
What is the Raw Manure Total Solids Percentage? .............................. 3
How do the Waste Management Practices affect Manure Total Solids
Percentage? [[[ 3
4-1.3 Summary Appraisal [[[ 4
4-2. Complete Evaluation Forms 5
4-3. Enter Information into Farm Ware 6
4-4. Evaluate Results 7
List of Exhibits:
Exhibit 4-1 Covered Lagoons for Energy Recovery - Below the Line of
Climate Limitation [[[ 2
Exhibit 4-2 "As Excreted" Value by Animal Type ......................................... 3
-------
Chapter 4
Technical and Economic Feasibility
Assessment
'"The purpose of this chapter is to lead you through
the technical and economic feasibility assessment
of biogas technology at a facility. This process in-
volves several steps. First, the compatibility of ex-
isting manure management practices with potential
digester types is examined. Then site-specific data
are collected using evaluation forms. These data are
entered into FarmWare, the decision support soft-
ware developed by AgSTAR. It will perform the
technical and economic feasibility analyses. Finally,
the results from FarmWare are evaluated and a final
appraisal of project opportunities is performed.
It is expected that the owner/operator or the person
most knowledgeable about the facility will be col-
lecting data and performing this assessment. In
some areas, NRCS may be contacted for assistance.
See Appendix B for a list of contacts. Checklists
and screening forms have been provided to assist
you through the process. Additionally, sample case
studies have been presented in Appendix E to assist
you further.
To select an appropriate and cost effective biogas
technology option(s), complete the following steps:
1. Match a Digester to Your Facility. Whether a
digester can be integrated into a facility's exist-
ing or planned manure management system de-
pends on the climate and solids content of the
manure. Section 4-1 discusses this step in more
detail.
2. Complete Evaluation Forms. These forms
record the information required to complete the
FarmWare assessment. A separate form is pro-
vided for swine and dairy facilities. Section 4-2
presents the screening forms and necessary di-
rections.
3. Enter Information into FarmWare. The in-
formation from Step 2 is entered into Farm-
Ware, the decision support software provided
with this handbook (Appendix C). Section 4-3
discusses this step in more detail.
4. Evaluate Results. Using the results from the
FarmWare analyses, a final appraisal of project
opportunities can be performed. This process is
presented in Section 4-4.
Each step is discussed in turn.
4-1. Match a Digester to Your Facility
The choice of which digester to use is driven primar-
ily by the climate and characteristics of the existing
manure management system, in particular how the
system affects the total solids content of the manure.
As mentioned in Chapter 1, one of four digester
types will be suitable for most manure management
conditions: covered lagoon; complete mix digester;
plug-flow digester, and fixed film.
^ Covered Lagoon Digester. Covered lagoons
require warm climates to be cost effective
unless odor management is the goal. They
can be used to treat liquid manure with up to 3
percent total solids.
^ Fixed Film Digester. Fixed film digesters are
best suited for use in warm climates. They can
treat liquid manure with up to 3 percent total
solids after removal of coarse solids by settling
or screening.
^ Complete Mix Digester. Complete mix digest-
ers are applicable in all climates. They can treat
manure with total solids in the range of about
3 to 10 percent.
^ Plug Flow Digester: Plug flow digesters are
applicable in all climates. They can treat only
dairy manure with a range of about 11 to
13 percent total solids.
This section will help you decide which digester is
suitable for your facility. First, the digesters appro-
priate for the climatic conditions at your facility are
identified. Then the process of determining the total
solids content of the manure is presented. Using the
information from the first two steps, the digester
appropriate for your facility is determined. The ta-
ble presented in Exhibit 4-4 outlines this selection
process.
SECOND EDITION
4-1
-------
Chapter 4
Technical and Economic Feasibility
Assessment
4-1.1 Where Is The Facility Located?
Temperature is one of the major factors affecting the
growth of bacteria responsible for biogas produc-
tion. Biogas production can occur anywhere be-
tween 39° and 155°F (4° to 68°C). As the tempera-
ture increases, the gas production rate also increases,
up to a limit.
Complete mix digesters and plug flow digesters are
usable in virtually all climates. Plug-flow digesters
and complete-mix digesters use supplemental heat to
ensure optimal temperature conditions in the 95° to
130°F range (35° to 55 °C). Capturing waste heat
from a generator set is the preferred method for
heating these types of digesters.
Covered lagoons generally do not use supplemental
heat because there is not enough waste heat avail-
able to heat the large volume of dilution water. La-
goons require large capacities to treat the liquid ma-
nure properly at low temperatures; providing heat
for these large capacities is expensive and usually
not cost-effective. Therefore, covered lagoons for
energy recovery are feasible only in moderate to
warm climates, where additional heat will not be
required.
However, covered lagoons may be considered for
use as an odor management and greenhouse gas re-
duction system in colder climates. Since gas pro-
duction varies by season, covered lagoons in colder
climates should be equipped with a simple flare sys-
tem to combust the biogas produced in the lagoon.
Flared gas makes a strong odor management state-
ment. However, flaring available gas does not guar-
antee odor free manure availability for crop applica-
tions. Manure characteristics during crop applica-
tion events are dependent upon lagoon sizing and
operational parameters.
To determine which regions have a climate warm
enough to install a covered lagoon for energy use,
experts use a simple rule of thumb. Facilities in re-
gions below the line of climate limitation (shown in
Exhibit 4-1) should be warm enough to consider
recovering biogas for energy use. In regions north
of the line of climate limitation, sustaining the nec-
essary temperature for the cost effective recovery of
biogas, for energy use from covered lagoons, will
Exhibit 4-1 Covered Lagoons for Energy Recovery - Locations for Energy Production Generally Fall Below
the 40th Parallel
Source: NRCS, Anaerobic Digester, Ambient Temperature: Practice Standard No. 365, 2003.
4-2
SECOND EDITION
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Chapter 4
Technical and Economic Feasibility
Assessment
not be cost effective in most cases.
4-1.2 What Is the Total Solids Content of the
Manure?
The total solids (TS) content of the collected manure
is another controlling factor in determining which
digester to use. TS content, usually expressed as a
percentage, indicates the fraction of the total weight
of the manure that is not water.
TS content depends on the animal type and the ma-
nure management strategy. The animal physiology
and feed regimen determines the "as excreted" TS
content. Manure "as excreted" may have a total sol-
ids content from 9 to 25 percent, depending on the
animal type. This percentage may be increased by
air drying or the addition of materials such as bed-
ding. Adding fresh water, waste water, or recycle
flush water lowers the TS content of collected ma-
nure.
What is the Raw Manure Total Solids Per-
centage?
The "as excreted" solids value of raw manure for an
animal is an average value established by research.
Since different animals have different diets, the sol-
ids content of their manure - as excreted - differs
within a range.
Exhibit 4-2 presents the solids content of manure for
various animal types.
Exhibit 4-2 Typical as Excreted Values
Animal Type
Swine
Beef
Dairy
Caged Layers
Total Solids (%)
9.2-10.0
11.6-13.0
11.6- 12.5
25
Source: NRCS, Agricultural Waste Management
Field Handbook, 1998.
How do the Waste Management Practices
affect Manure Total Solids Percentage?
Common waste management practices that decrease
and increase manure solids are briefly discussed be-
low. Exhibit 4-3 shows the manure characteristics
and handling systems that are appropriate for spe-
cific types of biogas production systems.
Practices that Decrease Solids Concentration
Water dilutes manure. The addition of water to ma-
nure may be deliberate (e.g., process water addition)
or incidental (e.g., rainfall). Since the TS percent-
age is the controlling factor in determining which
digester to use, knowing the extent of dilution of the
solids by water is important. Excess water and in-
creased waste volume can limit the capacity of ma-
nure handling and storage facilities. All water enter-
ing the waste management system must be ac-
counted for in designing the digester system.
^ Process (Fresh) Water Addition: Process wa-
ter dilutes manure solids. In dairies, process wa-
ter from the milking parlor is the largest new
source of liquids reaching the manure manage-
ment system. Most hog farms spend several
days a week washing buildings for sanitation
purposes. Water sprays or misters are often
used for cooling hogs and cows and may con-
tribute process water. Hogs waste water when
drinking or when playing with hog waterers.
These practices contribute 1 to 4 gallons of fresh
wastewater per gallon of hog manure added to
the collection system.
^ Flush or Pit Recharge Manure Collection:
Manure may be collected in hog or dairy build-
ings using recycle flush systems. Hog farms
may use a pit recharge collection where 4 to 12
inches of fresh or lagoon recycle water is kept
under the floors of the hog building and re-
placed every week or two. Small farms may use
a daily hose wash. Flush collection dilutes fresh
manure but delivers fresh volatile solids daily to
a lagoon. If all manure is collected daily, then
there is no loss of digestible volatile solids. Pit
recharge delivers somewhat older manure to a
lagoon, with some loss of digestibility. Manure
SECOND EDITION
4-3
-------
Chapter 4
Technical and Economic Feasibility
Assessment
that is collected by flush removal is diluted to
less than 2% total solids. Careful management
of pit recharge systems may allow collection of
manure with up to 3% total solids.
^ Rainfall Dilution: Manure left on feedlot or
open lots during rainfall will be diluted, result-
ing in lower solids.
Because the quantity of water added to manure var-
ies among farms, dilution should be evaluated on a
site specific basis. Simple ratios of water to manure
added are presented in Exhibit 4-4 for different ma-
nure handling routines. These are the default values
used in FarmWare if no other values are given.
Practices that Increase Solids Concentration
+ Dry Matter Addition: Solids content of raw
manure may be increased by the addition of
straw, sand, and sawdust bedding. Bedding ma-
terials are generally dry and used to absorb ma-
nure liquids. These practices result in solid ma-
nure managed by solid manure equipment such
as flail manure spreaders.
^ Sun Drying of Dry Lot and Corral Manure:
Manure drying in the sun will have a higher to-
tal solids percentage. Often indigestible dirt or
stones are collected with corral manure. Manure
begins to significantly decompose after one
week and is probably not worth collecting for
digestion. Typically, these practices are not
compatible with biogas utilization strategies,
and other waste management options should be
considered.
4-1.3 Summary Appraisal
Section 4-1.1 outlined why location was important;
Section 4-1.2 described the impacts of manure
management practices on manure solids. Using the
information from the above two steps, an appropri-
ate digestion technology can be selected for your
facility.
Exhibit 4-4 presents a simple table that outlines the
digester selection process. Facility operators may
use this table to determine which digester is best
suited for the farm. This information should not be
used in place of the FarmWare water use inventory
worksheet.
Exhibit 4-3 Appropriate Manure Characteristics and Handling Systems for Specific Types of Biogas Di-
gester Systems
Manure
Total Solids (%)
10 15 20
Water Added
As Excreted
25
30
Bedding Added
Classification | Liquid | Slurry
Handling Options
Pump
Scrape
Scrape and Stack
Biogas Production
Recommended
Not Recommended
Digester Type Covered Complete
Lagoon or Mix
Fixed Film
4-4
SECOND EDITION
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Chapter 4
Technical and Economic Feasibility
Assessment
Exhibit 4-4 Matching a Digester to Your Facility
Climatet
Moderate
to Warm
Cold
Animal
Type
Dairy
Swine
Dairy
Swine
Collection System
Flush
Scrape & Parlor Wash
Water
Scrape - Manure Only
Flush
Scrape
Pull Plug
Managed Pull Plug
Flush
Scrape & Parlor Wash
Water
Scrape - Manure Only
Flush
Scrape
Pull Plug
Managed Pull Plug
Estimated Min.
Ratio of
WatenManure*
10:1
4:1-1.1:1
N/A
10:1
2:1
5:1
3:1
10:1
4:1-1.1:1
N/A
10:1
2:1
5:1
3:1
%TS
<3%
3% -11%
>11%
<3%
3% - 6%
<2%
3% - 6%
<3%
3% - 8%
>11%
<3%
3% - 8%
<3%
3% - 6%
Digester Type
Covered Lagoon
Fixed Film
Complete Mix
Plug Flow
Covered Lagoon
Fixed Film
Complete Mix
Covered Lagoon
Complete Mix
Limited possibility for Covered
Lagoon
Complete Mix
Plug Flow
Limited possibility for Covered
Lagoon
Complete Mix
Limited possibility for Covered
Lagoon
Complete Mix
t The moderate to warm is the region below the 40th parallel and cold is the region above the 40th parallel (see Exhibit 4-1).
* These ratios are default estimates used in FarmWare.
SECOND EDITION
4-5
-------
Chapter 4
Technical and Economic Feasibility
Assessment
4-2. Complete Evaluation Forms
Evaluation forms are provided starting on pages 4-8
for recording the site-specific information required
by FarmWare to complete the technical and eco-
nomic feasibility assessment. Forms have been pro-
vided for both dairy and swine facilities. It is sug-
gested that additional copies of these forms be made
prior to completing them.
Each form contains the following five sections:
1. Climate Information. Enter the location (state
and county) of the facility.
2. Farm Type. Enter the farm type, farm size,
manure collection method, and manure treat-
ment method.
3. Livestock Population. Enter the number of
animals on the farm by animal type.
4. Manure Management. Enter information on
the manure management routine of the farm.
5. Energy Information. Enter the overall energy
rates, by season, as well as the monthly break-
down of electricity and propane costs. Appen-
dix G contains a sample letter to a utility re-
questing a monthly billing history and rate
schedules and should be submitted for accurate
figures.
These forms should be completed by the person
most knowledgeable about the facility. It is expected
that this person will also be completing the Farm-
Ware analysis.
The evaluation is only as good as the accuracy of the
input information. It may be useful to run Farm-
Ware several times and change the inputs to see the
effects on the output.
For assistance in completing the screening forms or
using FarmWare call 1-800-95AgSTAR. The Na-
tional Resource Conservation Service (NRCS) may
be of assistance in completing the evaluation forms.
See Appendix B for a list of NRCS contacts in your
area. AgSTAR participants may elect to mail com-
pleted screening forms to the AgSTAR program.
The AgSTAR program representative will conduct
the FarmWare assessment and report the results of
the assessment via mail. Please fill in a contact
phone number in case a representative needs to ver-
ify information.
4-3. Enter Information into Farm-
Ware
FarmWare is a computer software package that
enables owners, operators, or others investigating
biogas technology as a manure management option
to survey their facility, assess energy options, and
evaluate system financial performance.
To use FarmWare, you must have an IBM compati-
ble computer with the following features:
^ A Pentium processor
+ At least 128MB RAM (256MB RAM is
recommended);
^ Windows 98 or later; and
^ At least 50 MB of hard disk space.
The FarmWare manual is included in Appendix C.
The manual will guide you through the installation
and use of FarmWare.
After installing the program, open FarmWare, and
following the manual, input the data you recorded in
the evaluation form.
Additionally, two case studies showing FarmWare
analysis procedures have been presented for your
reference in Appendix E. The first group of case
studies is for dairy facilities. The next group is for
swine facilities. These studies are examples of typi-
cal production facilities and waste handling strate-
gies encountered at dairy and swine facilities. The
case studies presented include:
4-6
SECOND EDITION
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Chapter 4
Technical and Economic Feasibility
Assessment
Dairy Case Study
1,200 Cow Flush Barn with Scraped Outdoor Lot
Baseline Waste Management System:
Storage Pond
Manure Stack
Biogas Waste Management System:
Covered Lagoon Digester
Manure Stack
Swine Case Study
1,400 Sow Farrow-Finish Farm with Pit Recharge
Barn.
Baseline Waste Management System:
Anaerobic Lagoon
Biogas Waste Management System:
Covered Lagoon Digester
4-4. Evaluate Results
Project economics depend on a number of site spe-
cific factors, such as the details of the manure man-
agement system, farm energy needs, energy billing,
and regulatory requirements. These factors affect
the potential amount and quality of recoverable
methane and consequently affect the potential reve-
nues (or savings).
FarmWare estimates the costs and revenues from the
project and presents the results in the Quick Finan-
cial Report screen. This screen also shows results
for the three main techniques for assessing the eco-
nomic feasibility of the project:
^ Payback Method. The payback method in-
volves determining the number of years it would
take for a project to generate profits equal to the
initial capital outlay. This method may be par-
ticularly suitable where there is a great amount
of risk and uncertainty associated with a project
and the emphasis is on recovering capital ex-
penditure as quickly as possible. The main dis-
advantages of this method are: it does not con-
sider the costs and benefits that accrue at the end
of the payback period; and it takes no account of
the time when costs are incurred or benefits are
received. The payback method is appropriate to
use when making a rough preliminary assess-
ment of a project's economic feasibility.
^ Discounted Cash Flow Method (Net Present
Value). The basic premise of the discounted
cash flow technique is that costs or benefits oc-
curring in the future are worth less than those
occurring now. This means that annual costs
and benefits are not simply added up over the
years of the project. The costs and benefits in
each year of the project are adjusted by a dis-
count factor so that costs or benefits occurring
in one year can be compared with the costs or
benefits occurring in another year. The dis-
counted costs and benefits in each year can be
aggregated to give a net present value of future
cash flows of the project. The discount rate
used will normally be chosen on the basis of
prevailing interest rates or on the basis of the
minimum desired rate of return for the project.
If the net present value is zero or greater, the
appraisal shows that the project is capable of
yielding the threshold of return.
^ Internal Rate of Return Method. The internal
rate of return is the discount rate at which the
net present value of the project would be zero.
This value shows the total rate of return
achieved by the project. This rate can be com-
pared to return rates from alternative investment
opportunities.
Sensitivity analyses should be done to examine how
changes in key parameters such as electricity prices
can affect the economic viability of the project.
These sensitivity analyses can be carried out before
the financing arrangements for the project have been
worked out and are useful in providing an initial
indication of the project's viability. Further analysis
can be conducted to examine the implications for
viability of different financing schemes.
SECOND EDITION
4-7
-------
AgSTAR
Evaluation Form: Dairy Facility
Farm Name:
Contact Person:
Phone:
Date:
1. SITE CLIMATE INFORMATION
State:
County:
2. FARM TYPE
Type of Farm
Dairy
Replacement
Heifer
Manure Collection Method
Flush Barn
Scrape Barn
Flushed Outdoor Lot
Scraped Outdoor Lot
Pasture
3. LIVESTOCK POPULATIONS
lactating cow
dry cow
dairy heifer
dairy calf
4. ANIMAL DISTRIBUTION
Indicate the number of hours the animals spend in each area, per day:
Barn
Outdoor Lot
Pasture
Milking Center
TOTAL HOURS
Lactating Cow
Dry Cow
Dairy Heifer
Dairy Calf
4. MANURE MANAGEMENT
WATER USE
Building
Milking
Center
Barn
Outdoor Lot
(1)
Number of Flush
Tanks in All
Buildings
(2)
Gallons of
Recycle Water
per Tank
Gallons of Fresh
Water per Tank
(3)
TOTAL
OR
(4)
Total Flush
(Gallons per day)
Other systems
Scrape Systems: Frequency of collection
Per day / Per week/ Per month / Per year (circle one)
Solid Separators: Vibrating screen / Screw press / Inclined Screen / Gravity Settling Basing (circle one)
5. ENERGY INFORMATION
(Complete this section, or bypass it by attaching copies of past 12 months of energy bills)
Overall Energy Costs:
Energy Source
Electricity
Liquid Propane
Fuel Oil
Natural Gas
Annual Cost
($ per year)
Average Unit Cost
($ per unit)
Unit
kWh
gallons
gallons
cubic feet
-------
Month
January
February
March
April
May
June
July
August
September
October
November
December
Electric
Peak kW
kWh
Cost
Liquid Propane
gals
Cost
Fuel Oil
gals
Cost
Natural Gas
Cubic Feet
Cost
6. HAVE YOU OBTAINED YOUR BILLING HISTORY AND RATE SCHEDULES? (See Appendix G for sample utility letter)
-------
AgSTAR
Evaluation Form: Swine Facility
Farm Name:
Contact Person:
Phone:
Date:.
1. SITE CLIMATE INFORMATION
State:
County:
2. FARM TYPE
Type of Farm
_Farrow-to-Finish
Farrowing
_Nursery
_Farrow Plus Nursery
Grower-Finish
Manure Collection Method
Flush Barn
Pull Plug Barn
Pit Recharge
Deep Pit
Hoop Barn
Pasture
3. LIVESTOCK POPULATIONS
lactating sows
gestating sows
_nursing pigs
weaned pigs
feeder pigs
boars
4. MANURE MANAGEMENT
Recycle Flush System
Building
1
2
3
(1)
Tanks per
Building
(2)
Gallons of Recycle
Water per Tank
(3)
Flush Frequency
(per day? per week?)
TOTAL
OR
(4)
Total Flush
(Gallons per day)
Pull Plug and Pit Recharge Barns
Building
1
2
3
(1)
Gallons of Recycle
Water per Pit
(2)
Flush Frequency
(per day? per week?)
TOTAL
OR
(3)
Total Flush
(Gallons per day)
5. ENERGY INFORMATION
(Complete this section, or bypass it by attaching copies of past 12 months of energy bills)
Overall Energy Costs:
Energy Source
Electricity
Liquid Propane
Fuel Oil
Natural Gas
Annual Cost
($ per year)
Average Unit Cost
($ per unit)
Unit
kWh
gallons
gallons
cubic feet
-------
Month
January
February
March
April
May
June
July
August
September
October
November
December
Electric
Peak kW
kWh
Cost
Liquid Propane
gals
Cost
Fuel Oil
gals
Cost
Natural Gas
Cubic Feet
Cost
6. HAVE YOU OBTAINED YOUR BILLING HISTORY AND RATE SCHEDULES? (See Appendix G for sample utility letter)
-------
Chapter 5 Securing an Energy Contract
Contents:
5-1. Operational Modes 1
5-1.1 Sale of Electricity to the Utility 1
Buy All - Sell All 2
Surplus Sale 2
Net Metering 2
5-2. Interconnection Requirements 2
5-3. Whom to Contact 3
5-4. What to Ask For 3
5-5. Elements of an Energy Agreement 4
5-6. Why Negotiate and What to Watch Out For 4
5-6.1 Examples of Contract Elements that May Be Included and Must Be
Identified and Renegotiated 4
5-6.2 Benefits to the Utility from Farm Biogas Systems 5
5-7. Transmission (Wheeling) Arrangements 6
SECOND EDITION 5~l
-------
Chapter 5
Securing an Energy Contract
This chapter provides a guide to the issues in-
volved in negotiating a contract to operate a
small biogas fired generator in parallel with a utility.
When electrical production is the desired mode of
operation, the utility contract is the most important
issue affecting the profitability of a project.
While utilities are legally required to work with
farm biogas electrical generators, there are no set
industry rules or procedures that govern the process
for small power producers (<250 kW), as most rules
were developed for very large independent power
producers (>1 MW). In general, utility rules apply
to interconnection requirements, capacity guaran-
tees, and energy payment/purchase rates. In the best
of cases, some utilities have developed handbooks
of procedures, specifications, options and draft con-
tracts in an effort to provide small power producers
with a standard contractual process. In these cases,
the process is orderly and straightforward. In other
cases, some utilities have dispersed responsibilities
across a number of different groups within their or-
ganizational structure. These groups may include
metering, rates, engineering, agricultural services,
and others. In these cases, the process can become
confusing, time consuming, and may present im-
pediments to project development. Negotiation is an
appropriate method to develop successful small
power contracts, given the many approaches utilities
may take toward these types of projects. Since con-
tract negotiation is often a complex process, farm
owner/operators and developers may want to consult
an expert for information and guidance in this area.
Since the first edition of this handbook was written,
deregulation has resulted in a major restructuring of
electric utilities. Many utilities have sold their
generating capacity to independent power producers
and now purchase all the electricity delivered to
their customers charging a fee for distribution.
Theoretically, each customer has or will have choice
as to the source of the electricity that they purchase.
However, the progress toward total deregulation has
varied among states and in some states there is only
one choice, especially for residential customers.
Conversely, customers in other states may have
several options including a supplier that generates
"green power" from a renewable resource such as
biogas. As a source of green power, farms selling
electricity produced using biogas may be able to
receive a premium price for the electricity that they
sell to their local utility due to a higher rate structure
for electricity generated from a renewable resource.
In Chapter 3, considerations of the types of genera-
tion arrangements were discussed. This chapter ap-
plies to farm biogas generators operating in parallel
with a utility. Operating modes are described, utility
contracts are discussed, and the utility contract proc-
ess is presented.
5-1. Operational Modes
The key issue in developing a biogas recovery sys-
tem is the value of the energy to the owner. A care-
ful review of utility rates and interconnection re-
quirements are necessary prior to selecting the oper-
ating mode. In addition, the owner or developer
must realistically estimate the potential to generate
electricity and analyze the farm's monthly energy
use and history. The analysis may show that the
farm will make some surplus electricity or require
more than it can produce. Once the potential sur-
plus/shortfall situation is known, the following op-
tions may be considered. Not all utilities offer these
options under these names.
5-1.1 Sale of Electricity to the Utility
In 1978, the Public Utilities Regulatory Policy Act
(PURPA) required an electric utility to buy electric-
ity from a power project, that is granted Qualifying
Facility (QF) status by the Federal Energy Regula-
tory Commission (FERC). The electricity would be
bought at the utilities' current avoided cost rate. A
power project is granted QF status as either a "small
power producer" or a "qualifying cogenerator."
PURPA prohibits utilities or utility holding compa-
nies from having more than 50 percent ownership in
QF projects, and it stipulates size and fuel require-
ments as follows:
"Small Power Producer. Small power
producers must be no more than 80 MW in
size and must use a primary energy source
of biomass, waste, renewable resources, or
geothermal resources."
Biogas fueled electricity generation qualifies by
definition. However, because the avoided cost of-
fered by utilities for purchasing power from QF's,
SECOND EDITION
5-1
-------
Chapter 5
Securing an Energy Contract
under PURPA, is much lower today, energy may be
more profitably utilized in other operational modes.
One option that warrants immediate investigation is
the direct sale of energy to a neighboring facility
that can use the power.
Currently, the electricity market is undergoing rapid
change, including electric utility re-structuring. Re-
structuring may provide opportunities as well as
challenges that may affect small power production
contracts. State actions may impact technology op-
tions and the system economics.
The following are typical operating modes for paral-
lel farm digester generators.
Buy All - Sell All
Some utilities offer an agreement where they will
continue to sell the farm all electricity requirements
and then buy all the generator output. There are
very few advantages to this type of arrangement in
today's market. In general, utilities offer to pay an
avoided cost rate which is 1/4 to 1/3 of what they
charge for a retail kilowatt-hour. In rare circum-
stances a utility will pay an amount close to the
value per kilowatt-hour that they charge. However,
there also is another version of a Buy All - Sell All
agreement that may be available in which the elec-
tric utility purchases and uses the biogas produced to
generate electricity on the farm. Under this type of
agreement, the utility owns the generator set and the
interconnection equipment and the electricity gener-
ated, which is delivered to the utility's distribution
grid. Although all of the electricity used on the farm
must be purchased from the utility, the capital and
operating costs of the biogas production system are
reduced.
Surplus Sale
In a "surplus sale" agreement a farm produces elec-
tricity in parallel for use on farm. Excess production
is sold at avoided cost and excess consumption is
purchased at the retail rate. The surplus sale allows
the farm to realize the retail value of a kilowatt-hour
by keeping it on farm and using it. In recent years,
some utilities have begun charging "standby" rates
on these types of projects. The purpose of the
standby charge is to pay for the availability of elec-
tricity to the farm when the generator is not running.
Typically the standby charge is adequate to recover
all utility profits on kilowatt-hours not sold.
Net Metering
In net metering, the generator output is offset on a
monthly or yearly basis against the farm consump-
tion with surplus production purchased by the utility
or shortages purchased by the farm. The farm is, in
effect, trading electricity with the utility (Exhibit 5-
1). Many states (AK, CA, CT, DE, HI, ID, IL, IA,
LA, MA, ME, MI, MN, NV, NH, NM, ND, NY,
OH, OK, PA, RI, TX, VT, WI, WY) allow a net me-
tering arrangement for small generators, but the up-
per limit for generator size varies from state to state.
Net metering may be available from individual utili-
ties in other states, so check with your utility.
5-2. Interconnection Requirements
An integral part of the contract negotiation involves
the interconnection requirements. Each utility has
interconnection requirements for protective relays to
disconnect the generator automatically if the power
line near the farm is accidentally broken or there is a
problem with the generator. These relays are neces-
sary for protection of farm and utility personnel. It
is recommended that a professional familiar with
interconnection equipment negotiate with the utility
and supply the appropriate gear. Negotiation is nec-
essary because of the potential cost of the intercon-
nection. Solid state relays and electromechanical
relays perform the same generator (disconnect)
function. However, electromechanical relays may
cost 10 times more. A utility may need high cost
relays for very large power producers but lower cost
relays are appropriate for smaller farm scale power
production.
5-2
SECOND EDITION
-------
Chapter 5
Securing an Energy Contract
5-3. Whom to Contact
The utility may have a representative who will be
able to start you on the path to an energy agreement.
The responsible person is usually found in the mar-
keting department. Some utilities have assembled a
handbook of procedures, options, and draft con-
tracts. In these cases, the procedure is orderly and
straightforward, but will take time. Other utilities
have dispersed the responsibilities. In such cases it
will take a lot of time to determine what you have to
do to interconnect with the utility. The best advice
is to ask questions, and if you do not get answers, to
ask to talk to someone more senior. In some cases,
contacting the state Public Utility Commission
(PUC) may be helpful. In all cases, contacting the
utility early on in the project development process is
essential because of the long lead times often en-
countered in completing small power contracts. It is
suggested that the sample utility letter in Appendix
G be used as a tool to initiate this process.
5-4. What to Ask For
To begin the contract process the information you
need includes but is not limited to:
1. Avoided cost rate schedules
2. Contract Options - for renewable energy pro-
jects
A. Buy-sell agreement
B. Surplus sale agreement
C. No sale parallel agreement
D. Net sale agreement, if available
E. Any other currently available agreements
3. Interconnection requirements
4. Any charges, riders, rate schedules that may be
applied to the project (e.g., standby charges)
Examples of some of these documents can be found
in Appendix H.
Exhibit 5-1 The Advantage of Net Metering
This example shows the costs under net metering for a 550 cow, scrape freestall dairy farm with a plug flow
digester. The farm generates an average of 70 kW with an average on-farm demand of 50 kW. The example
uses a typical utility rate schedule (Service Class 2-D) for the State of New York (Appendix H-5). The genera-
tor operates 95 percent of the time.
Delivery rate, $/kWh $0.0265
Supply rate, $/kWh $0.0500
Monthly energy use, kWh 34,200
Monthly excess to grid, kWh 13,680
Net $ credit at $.0765/kWh $909
Total demand/fixed costs -$645
Net monthly credit $264
Energy credit at $.0765/kWh, kWh 3,449
Monthly $ credit at $.050/kWh $172
Net metering annual credit $2,069
After deducting demand charges, the farm's monthly electricity bill includes a 3,449 kWh credit to be carried
forward for netting against future month's electricity bills (i.e., whenever farm demand for electricity exceeds
the biogas system generation rate). After 12 months, any unused energy credit would be converted to a dollar
credit at the utility's avoided energy cost (i.e., supply rate). If on-farm energy demand were fully met each
month, the value of the 12-month credit would be $2,069. Including the value of energy generated for on-farm
use, the annual value of the biogas is $33,465.
SECOND EDITION
5-3
-------
Chapter 5
Securing an Energy Contract
5-5. Elements of an Agreement
A long-term contract is usually favored to ensure
revenues for projects, and is usually required to ob-
tain financing. However, review short and medium
term options to be sure to choose the most beneficial
options to the project. Many utilities have a stan-
dard offer contract for qualifying facilities such as
farm-scale anaerobic digesters.
The entire contract offered by a utility should be
carefully reviewed by the project developer and le-
gal counsel to ensure that each of the terms is ac-
ceptable. If they are not, a more acceptable, revised
version of the contract should be presented to the
utility for negotiation. The details of the agreements
are crucial to limiting issues that may adversely im-
pact the system in the future.
Primary contract considerations include:
^ Term. The contract term should be sufficient to
support financing and/or the life of the project.
A satisfactory term is usually 15 years or more.
^ Termination. Grounds for contract termination
should be very limited in order to protect the
long-term interests of all parties.
^ Assignment. The contract should consider as-
signment for purposes such as financing. For
example, allowing for contract assignment to
heirs or to partners may be advisable to avoid
ownership arrangement difficulties.
^ Force Majeure. Situations that constitute force
majeure (e.g., storms, acts of war) should be
agreed upon, otherwise this clause could be used
to interrupt operations or payment.
^ Schedule. There should be some flexibility al-
lowed for meeting milestone dates and exten-
sions (e.g., in penalty provisions such as non-
performance). This is necessary in case unfore-
seen circumstances cause delays.
^ Price. The contract price should ensure the
long-term viability of the project, which means
that accounting for potential cost escalation
through the contract term will be very important.
5-6. Why Negotiate and What to
Watch Out For
Negotiating is a difficult task and only experience
can help. Patience and common sense are virtues.
If a contract clause request seems unreasonable, it
might be negotiable. However, remember that
power contract agreements are binding with the util-
ity, and therefore any changes or agreements need to
be in writing.
Utility contracts or standard offers tend to have one
or more unique clauses that must be recognized as
potentially costly to the project. Some standard of-
fers are developed for certain QF's and then applied
to all projects. This is fine if the contract was de-
veloped for a small cogenerator, but can be fatal to a
small project if the standard clauses were developed
for a 2 MW steam turbine project. Some unfavor-
able clauses from some utility standard offers are
summarized below as examples. The
owner/developer should be aware that these and
other clauses might exist. At a minimum, the finan-
cial impact of these clauses on the project, must be
fully assessed. Where clauses appear to be unrea-
sonable, they should be renegotiated.
5-6.1 Examples of Contract Elements that
May Be Included and Must Be Identified and
Renegotiated
These include:
^ Change in the farm retail rate. The utility
may mandate a new retail rate for a farm with
biogas cogeneration. A change in rate affects
project financial performance, and must be ac-
counted for in the project's financial analysis.
^ Standby charges. Standby charges may be ap-
plied to the project by the utility. Standby or
"backstand" charges typically are rate schedules
or riders that add additional charges to the pro-
ject. Utilities levy these charges on customers
that purchase power on an intermittent or 'as
needed' basis, such as those using a farm-scale
biogas system. These charges need to be care-
fully evaluated in terms of their financial im-
5-4
SECOND EDITION
-------
Chapter 5
Securing an Energy Contract
pacts on the project, in relation to the expected
engine generator performance.
^ Interconnection requirements. The Federal
Energy Regulatory Commission (FERC)
proposed expedited grid-connection procedures
for smaller generators, such as digester
electricity projects to help standardize the
interconnection process and make it less of a
burden. Appendix H contains the proposed
rules. It is recommended that project developers
contact their local utility early in the process to
discuss interconnection requirements.
^ Insurance Requirements. Liability insurance
is a requirement for any project. Most farms
have adequate insurance for the operation that
will also cover the digester with minimal addi-
tional premium. Some utilities have asked
farms to add the utility to the policy and to in-
crease the limits of the insurance to levels higher
than any farm insurance carrier normally writes.
^ Monitoring and Reporting. Some utility com-
panies have clauses requiring such things as
hourly reporting of generator output and thermal
heat use. They are designed to ensure that natu-
ral gas cogenerators meet PURPA thresholds.
Such requirements are generally not necessary
for a farm digester, and should be renegotiated.
^ Telemetry. Some contracts can mandate direct
control of the farm generator from the utility
power management center, via a leased phone
line. This is excessive for small power contracts
and is an example of applying large power pro-
duction specifications to small power producers.
^ Construction of the Interconnection. Some
utilities prohibit cogenerators from supplying
their own equipment. This action can add costs
to the project that can affect financial perform-
ance. This is another example of applying large
power production specifications to small power
producers.
The farm has to be careful in rate analysis because
"high" demand charges can negate half the value of
the electricity produced. "Demand" is usually the
highest rate of electricity consumption for 15 min-
utes during the month. To offset demand charges, a
generator must achieve 99.6% operation. Some
utilities offer a "backup" or "standby" charge that is
usually a lower fee than a demand charge. Farm-
Ware can be used to evaluate these financial im-
pacts.
5-6.2 Benefits to the Utility from Farm Bio-
gas Systems
When working with a utility, it is important to re-
member that these projects can also meet their needs
and to emphasize how successful implementation of
the project will benefit both parties. For example,
there are several non-monetary benefits to a utility
from a farm anaerobic digester generator that utili-
ties should consider in project negotiations, includ-
ing:
1. Customer Retention. A digester may allow a
farm to continue in business and continue pur-
chasing some of its electricity needs, when a
methane recovery system eliminates odor prob-
lems with neighbors.
2. Demand Reduction. Most utilities try to man-
age the peak demand by demand side manage-
ment programs that reward customers for not us-
ing electricity during peak demand times. A di-
gester generator reduces farm demand for utility
power meeting the management goal.
3. Voltage Support. Where farms are near the
end of utility transmission laterals, the generator
supports the line voltage, keeping it from fluctu-
ating. This saves the utility the cost of provid-
ing voltage support or paying for burned out
motors.
4. Deferred Capital Expenditures. In rural areas,
a digester generator (distributed generation)
provides a remote generation source. It can de-
lay the need for increasing system capacity and
defer expenditures for conductors and substa-
tions, by supplying electricity at the point of
use.
5. Greenhouse Gas Reductions. Several utilities
have joined the Climate Leaders Program to re-
duce emissions of greenhouse gases. Methane
recovery from animal wastes and combustion
reduces its atmospheric effects. The recovery of
SECOND EDITION
5-5
-------
Chapter 5 Securing an Energy Contract
one pound of methane is the same as reducing
carbon dioxide emissions by 21 pounds. By en-
couraging biogas production and its use to gen-
erate electricity, the utility objectives to reduce
greenhouse gas emissions are advanced without
capital expenditures.
6. Renewable Portfolio Standards. A Renew-
able Portfolio Standard (RPS) requires that a
minimum amount of renewable energy is
included in the portfolio of electricity resources
serving a particular area. Utility purchases of
electricity from biogas projects may help meet
these RPS requirements.
5-7. Transmission (Wheeling)
Arrangements
Another option for producing revenue from biogas
generated electricity is the direct sale to a third party
using the local utility transmission lines. This
strategy may be possible if the local utility is
required to enter into a long-term contract to deliver
or "wheel" electricity from other generators at a
reasonable price. Also, farms with more than one
site may be able to wheel surplus electricity via the
local utility lines to their other locations. Wheeling
could produce more revenue than the sale of surplus
electricity to the local electric utility or may be an
option if an acceptable long-term purchase
agreement cannot be negotiated with the local
utility. Before considering wheeling, contact the
Public Utility Commission to determine if electric
utilities in the state are required to wheel electricity
generated by small power producers.
5'6 SECOND EDITION
-------
Chapter 6 Selecting a Consultant/Developer/
Partner
Contents:
6-1. The Do-It- Yourself/Turn-key Decision
6-2. Selecting a Consultant/Consulting Firm
6-3. Selecting a Turn-Key Developer
6-4. Selecting a Partner
6-5. Preparing a Contract
1
4
4
4
5
List of Exhibits:
Exhibit 6-1 The Developer Selection Process...
Exhibit 6-2 Project Development Tasks
Exhibit 6-3 Elements of a Consultant Contract.
.2
..3
..6
SECOND EDITION
6-i
-------
Chapter 6
Selecting a Consultant/Developer/Partner
T
Ihis chapter provides a guide to selecting a con-
sultant, turn-key developer, or partner.
The selection of a consultant or developer is a
critical decision. The farm owner often relies on
the consultant or developer to manage the process
of transforming a feasible idea into a functioning
facility. Some owners have the expertise, re-
sources, and desire to lead the development effort
on their own, but even in this case, choosing the
right consultant can greatly improve the likelihood
of project success. This chapter provides guidance
to owners who are attempting to determine: (1) the
role that they might take in the development proc-
ess; (2) the right consultant to get the project de-
veloped, financed, and built; and (3) if an invest-
ment partner would be advisable.
From the owner's perspective, there are three gen-
eral ways to structure the development of a biogas
project:
1. Owner-Builder. Farm owner hires a consult-
ant, plans and manages the design-
construction effort, and maintains ownership
control of the project. This approach maxi-
mizes economic returns to the owner, but also
places most of the project risks on the owner
(e.g., construction, equipment performance,
financial performance).
2. Purchase Turn-Key Project. Owner selects
a qualified development company to provide
the owner with a "turn-key" digester plant,
which is built by the developer but owned by
the farm owner.
The "turn-key" digester plant option requires
expertise in developing the following areas:
(1) Digester; (2) Gas Handling; (3) Engines;
(4) Utility Interconnection; and (5) Utility
Rates.
3. Team With a Partner: Owner teams with an
equipment vendor, engineering/procurement
/construction (EPC) firm or investor to
develop the project and to share the risks and
financial returns.
With these structures in mind, a farm owner can
determine his or her desired role in the project
development process by considering two key
questions:
^ Should the owner self-develop, buy a turn-key
project, or find a partner?
^ If a partner is desired, what kind of partner
best complements the owner and the project?
The owner can answer the first question by con-
ducting a frank examination of his or her own ex-
pertise, objectives, and resources. The second
question is more complicated because it entails an
assessment of the owner's specific needs and a
search for the right partner to complement those
needs.
Appendix I provides a list of suppliers, vendors,
and EPC firms.
Exhibit 6-1 illustrates the process of determining
the best development approach. As it indicates, in
cases where the owner wants to be involved in the
project development process, a number of issues
must be considered. These issues are discussed in
the following sections.
6-1. The Do-It-Yourself/Turn-key
Decision
Before deciding whether to develop the project
internally, the owner must understand the tasks
involved in a project, which are outlined in Ex-
hibit 6-2.
Next, an assessment of the owner's objectives, ex-
pertise, and resources determines whether or not
the owner should undertake project development
independently or try to find a turn-key developer.
SECOND EDITION
6-1
-------
Chapter 6
Selecting a Consultant/Developer/Partner
Exhibit 6-1 The Developer Selection Process
Determine the Economic
Viability of the
Project (Chapter 4)
Desire
to
Self-
Develop?
Desire
to
be a
Partner?
or
Equipment
xpertise'?
Have
an
Energy
Sales
Contract?
Other
Expertise
or Ability to
Finance?
Funding
and/or
Personnel
vailable?
Willing
to Pay
to
Limit Risk
Willing
to
^ < Share
Risk/Rewards
Willing
to
Accept
Risk?
Yes
Self-Develop Option
Turn-Key Option
Partner Option
Decreasing Owner's Risk
6-2
SECOND EDITION
-------
Chapter 6
Selecting a Consultant/Developer/Partner
An owner with the following attributes is a good
candidate for developing a project with a consult-
ant alone:
^ strong desire to develop a successful, profit-
able energy project;
^ willingness to accept project risks (e.g., con-
struction, equipment, permitting, financial per-
formance);
^ expertise with technical projects or energy
equipment;
^ high confidence level regarding biogas quan-
tity and quality (i.e., modeling or testing
have been completed);
^ sufficient internal electricity demand or pos-
session of a power sales agreement with a lo-
cal electric utility or an electric consumer; and
^ funds and personnel available to commit to the
construction process.
Similarly, a strong desire for new business oppor-
tunities and/or visibility is beneficial. The type of
owner that fits this profile is one who owns, oper-
ates, and repairs farm equipment.
If the owner is uncertain about several of the at-
tributes listed above, particularly the desire to
build, the willingness to take significant risks,
and/or their level of technical expertise, then he or
she might instead choose a turn-key builder.
The following are several good reasons to develop
the project with a turn-key builder:
^ limited desire to lead the development effort;
Exhibit 6-2 Project Development Tasks
Determine Bioqas Supply If the owner has not already completed this step, then the first development step
will be to determine the biogas supply using calculations, computer modeling, and/or testing.
Scope Out the Project Project scoping includes preliminary tasks such as selecting a site, developing a site
plan, determining structural and equipment needs, estimating costs and biogas production potential, and
contacting the local utility.
Conduct Feasibility Analysis Feasibility analysis includes detailed technical and economic calculations to
demonstrate the technical feasibility of the project and estimate project revenues and costs.
Select Equipment Based on the results of the feasibility analysis, primary equipment is selected and vendors
are contacted to assess price, performance, schedule, and guarantees.
Create a Financial Pro Forma A financial pro forma is usually created to model the cash flows of a project and
to predict financial performance.
Negotiate the Utility Agreement The terms of the agreement must be negotiated with the purchasing electric
utility.
Obtain Environmental and Site Permits All required environmental permits and site permits/licenses must be
acquired.
Gain Regulatory Approval Some power projects must obtain approval from state regulators or certification by
the Federal Energy Regulatory Commission (FERC).
Secure Financing All the tasks above are needed to determine economic viability to allow financiers to loan
money for the project.
Contract with Engineering, Construction, Eguipment Supply Firms Firms must be selected and contracts and
terms negotiated.
SECOND EDITION
6-3
-------
Chapter 6
Selecting a Consultant/Developer/Partner
^ limited technical resources and/or experience;
^ need to share or avoid specific project risks;
^ difficulty financing the project alone;
^ inability to dedicate personnel or time to the
development effort;
^ project development outside the scope of or-
ganization.
The questions in Exhibit 6-1 illustrate other criti-
cal considerations in making the owner-
builder/turn-key decision. Most owners choose
self build with consultant or turn-key options.
6-2. Selecting a Consulting Firm
Once the decision to self build with a consultant
has been made, the owner should review the capa-
bilities of individual consulting firms that meet the
owner's general needs. When selecting a consult-
ant, there are several qualities and capabilities that
owners should look for, including:
^ previous biogas project experience;
^ a successful project track record; and
^ in-house resources (e.g., engineering, finance,
operation) including experience with envi-
ronmental permitting and community issues.
Information about individual firm qualifications
can be gained from reports, brochures, and project
descriptions, as well as from discussions with ref-
erences, other owners, and engineers. Potential
warning signs include: lawsuits, disputes with
owners, lack of operating projects and failed pro-
jects (although a few failed efforts and/or under-
performing projects can normally be found in the
portfolio of any consultant). Published informa-
tion can be obtained by researching trade litera-
ture, through legal information services, and
through computer research services.
6-3. Selecting a Turn-Key Developer
Selecting a turn-key developer to manage the de-
velopment process is a good way for the owner to
shed development responsibility and risks, and get
the project built at a guaranteed cost. In addition,
the developer typically provides the owner with
the strongest development skills and experience.
Other reasons for selecting a turn-key developer
include:
^ the developer's skills and experience may be
invaluable in bringing a successful project on-
line and keeping it operational; and
^ some developers have access to financing.
In return for accepting project risks, most turn-key
projects cost more than self built systems. The
turn-key option is a good approach if the owner
does not want the risk and responsibility of con-
struction. In a turn-key approach, the developer
assumes development responsibility and construc-
tion risk, builds the facility, and then receives
payment when the facility is complete and per-
forming up to specifications. The turn-key ap-
proach enables each entity to contribute what it
does best: the developer accepts development,
construction, and performance risk; and the owner
accepts financial performance risk.
6-4. Selecting a Partner
A partner reduces risks to the owner by bearing or
sharing the responsibilities of project develop-
ment, although the amount of risk reduction pro-
vided depends on the type of partner chosen.
Selecting a partner who is not a developer is a
good choice if two key conditions exist:
6-4
SECOND EDITION
-------
Chapter 6
Selecting a Consultant/Developer/Partner
1. The owner wants to keep management control
of the project and has sufficient in-house ex-
pertise and resources to do so; and,
2. The partner can fulfill a specific role or pro-
vide equipment for the project.
In this case, the owner must have a clear desire to
manage the development process and should have
sufficient technical experience, personnel, and
funds to support the effort. The owner should also
have a relatively high confidence level regarding
biogas production capability, as well as a willing-
ness to accept a significant share of the project's
risks (e.g., financial, environmental permitting,
community acceptance).
There are three basic types of firms that may enter
into partnership agreements with owners: equip-
ment vendors, EPC firms, and investors. Each of
these firms has different strengths and will assume
different types of project risk. The key character-
istics of these types of firms are summarized be-
low.
^ Equipment Vendors. Some equipment ven-
dors such as engine manufacturers become
partners in energy projects, including biogas
projects, as a way to support the sale of
equipment and services to potential customers.
Equipment vendors may assist in financing the
project, and may be willing to accept the
equipment performance risk over a specified
length of time for the equipment that they
provide. However, equipment vendors typi-
cally do not take on responsibilities beyond
their equipment services, and they generally
want to recover their interest in a project as
quickly as possible after the project has been
built.
^ EPC Firms. Similarly, some of the biogas
EPC firms may become partners in biogas
power projects with the objective of selling
services and gaining a return on equity and/or
time invested. However, this type of partner
tends primarily to pursue large projects (i.e.,
>1 MW) where the EPC's strength as a man-
ager of large, complex projects is more valu-
able.
Investment Firm. Finally, an individual or
investment company might become a partner
in the biogas project if it has significant use
for any available tax credits, or if the project
has an attractive rate of return on investment.
6-5. Preparing a Contract
Once the firm has been selected, the terms of the
agreement should be formalized in a contract. The
contract should accomplish several objectives,
including allocating risk among project partici-
pants. Some of the key elements of a contract are
listed in Exhibit 6-3.
As Exhibit 6-3 indicates, contracting with a devel-
oper or partner in a biogas energy project can be a
complex issue. Each contract will be different
depending on the specific nature of the project and
the objectives and limitations of the participants.
Because of this complexity, the owner may wish
to hire a qualified attorney to prepare and review
the contract.
SECOND EDITION
6-5
-------
Chapter 6 Selecting a Consultant/Developer/Partner
Exhibit 6-3 Elements of a Consultant Contract
The contract between the owner and the consultant, developer, or partner should describe in detail the responsi-
bilities of each party, any payments to be made, and any warranties and/or guarantees. Some specific items that
should be addressed include:
Ownership shares
Allocation of responsibility
Decision-making rights
Commitments of equity, financing, equipment, and/or services
Payments, fees, royalties
Hierarchy of project cash distributions
Allocation of tax credits
Allocation of specific risks (e.g., equipment performance, gas flow)
Penalties, damages, bonuses
Schedules and milestones
Termination rights clause
Buy-out price
Remedies/arbitration procedures
6-6 SECOND EDITION
-------
Chapter 7 Obtaining Project Financing
Contents:
List of Exhibits:
7-1. Financing: What Lenders/Investors Look For
1
7-2. Financing Approaches 1
7-2.1 Looking for Low Interest Loans or Cost .Share Funding 4
7-2.2 Debt Financing 4
Lender's Requirements 4
Securing Project Financing 4
7-2.3 Equity Financing 5
Investor's Requirements 5
Securing Equity Financing 6
7-2.4 Third-Party Financing 6
Lease Financing 6
7-2.5 Project Financing 6
7-3. Capital Cost Effects of Financing Alternatives 7
Exhibit 7-1 Addressing Biogas Project Risks 2
Exhibit 7-2 Financing Strategy Decision Process 3
SECOND EDITION
7-i
-------
Chapter 7
Obtaining Project Financing
This chapter provides a guide to obtaining project
financing and provides some insights into what
lenders and investors look for. It is assumed that the
farm owner has experience borrowing money from
banks or other agricultural lenders, and has first dis-
cussed financing a biogas system with their own
lender.
This chapter discusses alternative financing meth-
ods, some advantages and disadvantages of each
method, and some potential sources for financing.
The following general categories of project financ-
ing avenues may be available to biogas projects:
^ waste management cost sharing or renewable
energy loan/grant programs,
^ debt financing,
^ equity financing,
^ third-party financing, and
^ project financing.
Federal cost sharing or state energy low interest
loans or partial grants may be available for anaero-
bic digester projects. Debt financing is probably the
most common method used for funding agricultural
biogas projects. Equipment leasing, one method of
third-party financing is used occasionally. Equity
financing other than by the owner is rarely used,
while project financing has never been used, but
may be available to very large projects in the future.
7-1. Financing: What Lend-
ers/Investors Look For
Lenders and investors will decide to finance a bio-
gas project based upon its expected financial per-
formance and risks. Financial performance is usu-
ally evaluated using a pro forma model of project
cash flows as discussed in Chapter 4. FarmWare,
when properly used, can provide financial perform-
ance information for securing financing.
A lender or investor usually evaluates the financial
strength of a potential project using the two follow-
ing measures:
^ Debt Coverage Ratio: The main measure of a
project's financial strength is the farm's ability
to adequately meet debt payments. Debt-
coverage is the ratio of operating income to debt
service requirements, usually calculated on an
annual basis.
+ Owner's Rate of Return (ROR) on Equity: If
a digester system is essential to continuation of
farm operations, a break-even project is very
satisfactory to the owner. However, banks or
other lenders currently prefer to see a ROR be-
tween 12% and 18% for most types of projects.
Outside investors will typically expect a ROR of
15% to 20% or more.
Exhibit 7-1 summarizes the project risk categories,
viewed from the lender's perspective. The most im-
portant actions to control risks are to obtain con-
tracts securing project construction costs and reve-
nues. Potential investors and lenders will look to see
how the farm owner or project developer has ad-
dressed risks through contracts, permitting actions,
project structure, or financial strategies.
7-2. Financing Approaches
This section briefly discusses funding resources for
digester projects and the means of securing financ-
ing from the five sources listed above. The use of
third-party financing is briefly discussed. The ad-
vantages and disadvantages of each approach are
also discussed. Exhibit 7-2 is a flow chart summa-
rizing the decision process for selecting the appro-
priate source of financing.
SECOND EDITION
7-1
-------
Chapter 7
Obtaining Project Financing
Exhibit 7-1 Addressing Biogas Project Risks
Risk Category
Risk Mitigation Measure
Biogas Production Potential
Use FarmWare to model gas production over time
Hire expert to report on gas production potential
Provide for back-up fuel if necessary
Execute fixed-price turn-key contracts
Include monetary penalties for missing schedule
Establish project acceptance standards, warranties
Be sure the project conforms to NRCS standards
Construction
Equipment performance
Select proven designer, developer, and technology
Design for biogas Btu content
Get performance guarantees, warranties from vendors
Select and train qualified operators on farm
Environmental permitting
Obtain permits prior to financing (waste management,
building)
Community acceptance
Obtain zoning approvals
Demonstrate community support
Utility agreement
Have signed contract with local utility
Make sure all aspects are covered
Get sufficient term to match debt repayment schedule
Confirm interconnection point, access, requirements
Make sure on-line date is achievable
Include force majeure provisions in agreement
Financial performance
Create financial pro forma
Calculate cash flows, debt coverages
Commit equity to the project
Ensure positive NPV
Maintain working capital, reserve accounts
Budget for major equipment overhauls
7-2
SECOND EDITION
-------
Chapter 7
Obtaining Project Financing
Exhibit 7-2. Financing Strategy Decision Process
Project has a Positive NPV and Owner has a Portion of Equity to Invest in the
Project and/or Project is Environmentally Necessary
Eligible
or Low-lntere
Loan or Partial
Grant?
Take
All Risk,
Keep All
Reward?
Willing
To Share
Risk/Reward?
illing
To Share
Tax Benefits?
No
Is Sponsoring Program Willing to
Finance or Cost-Share Project?
Yes
No
Can You Borrow Based on Project
Assets and Cash Flow?
.No
Will Lender Finance Based on
Farm Assets & Project Cash Flow?
^,No
Will Equity Investor Buy Stake in
Project?
No
Will Capital Leasing Company Buy
and Lease Back?
Yes
Yes
Yes
Yes
No
Will Suppliers or Contractors | Yes
Provide Financing?
Start Over
No
Government Sponsored
Grant or Loan
Project Financing
(Non-Recourse Debt - Very Rare)
Typical Secured Debt Financing
3rd Party Equity Investor Partner-
ship
3rd Party Lease Financing
3rd Party Private Lease, Debt or
Partnership Financing
SECOND EDITION
7-3
-------
Chapter 7
Obtaining Project Financing
7-2.1 Looking for Cost Share Financing or
Low Interest Loans or Grants
There are few outright grant programs remaining for
anaerobic digestion system funding. It may be
possible to receive a portion of the project funding
from public agency sources. The Environmental
Quality Incentives Program (EQIP), administered by
USDA's Natural Resources Conservation Service
(NRCS), promotes agricultural production and
environmental quality as compatible goals. EQIP
was reauthorized and the funding amount
significantly expanded under the Farm Security and
Rural Investment Act of 2002, which requires that
60 percent of EQIP funds be spent on animal
operations. Anaerobic digesters may may qualify for
cost share funding under NRCS programs. The
owner should check with the local or state NRCS
offices to see if a digester project may qualify.
Another potential source of funding is a state energy
program. At the time of publication, the status of
renewable energy low-interest loan or grant pro-
grams is in flux. AgSTAR has identified approxi-
mately 30 states that offer financial assistance in the
form of low-interest loans, property tax exemptions,
and grants. To learn more about these state pro-
grams and other federal funding opportunities, re-
view the AgSTAR publication, Funding On-Farm
Biogas Recovery Systems, EPA-430-F-04-002, De-
cember 2003. Also Appendix B provides a list of
NRCS and Department of Energy contacts who
should be able to help the owner contact the correct
person in his state.
The advantage to receiving funding is the reduced
project cost. The disadvantages are the time and
effort it takes to apply for and receive funding
monies.
7-2.2 Debt Financing
Most agricultural biogas projects built in the last 15
years used debt financing, where the owner bor-
rowed from a bank or agricultural lender. The big-
gest advantage of debt financing is the ability to use
other people's money without giving up ownership
control. The biggest disadvantage is the difficulty in
obtaining funding for the project.
Debt financing usually provides the option of either
a fixed rate loan or a floating rate loan. Floating rate
loans are usually tied to an accepted interest rate
index like U.S. treasury bills.
Lender's Requirements
In deciding whether or not to loan money, lenders
examine the expected financial performance of a
project and other underlying factors of project suc-
cess. These factors include contracts, project partici-
pants, equity stake, permits, technology, and some-
times, market factors. A good borrower should have
most, if not all, of the following:
^ Signed interconnection agreement with local
electric utility company
^ Fixed-price agreement for construction
^ Equity commitment
^ Environmental permits
^ Any local permits/approval
However, most lenders look at the assets of an
owner or developer, rather than the cash flow of a
digester project. If a farm has good credit, adequate
assets, and the ability to repay borrowed money,
lenders will generally provide debt financing for up
to 80 percent of a facility's installed cost.
Lenders generally expect the owner to put up an eq-
uity commitment of about 20 installed using his/her
own money and agree to an 8 to 15 year repayment
schedule. An equity commitment demonstrates the
owner's financial stake in success, as well as imply-
ing that owner will provide additional funding if
problems arise. The expected debt-equity ratio is
usually a function of project risk.
Lenders may also place additional requirements on
project developers or owners. Requirements include
maintaining a certain minimum debt coverage ratio
and making regular contributions to an equipment
maintenance account, which will be used to fund
major equipment overhauls when necessary.
Securing Project Financing
Agricultural biogas projects have historically ex-
perienced difficulty in obtaining debt financing from
7-4
SECOND EDITION
-------
Chapter 7
Obtaining Project Financing
commercial lenders because of their relatively small
size and the perceived risk associated with the tech-
nology. The best opportunities for agricultural bio-
gas projects to secure debt financing are with banks,
smaller capital companies, where the owner cur-
rently borrows money, or at one of the energy in-
vestment funds that commonly finance smaller pro-
jects.
There are public sources that may provide debt fi-
nancing for agricultural biogas projects. The US
Department of Agriculture's Farm Service Admini-
stration (FSA) is a common source of debt financing
for agricultural projects. Additionally, the Small
Business Administration can guarantee up to
$1,000,000 for Pollution Control Loans to eligible
businesses. Pollution Control Loans are intended to
provide loan guarantees to eligible small businesses
for the financing of the planning, design, or installa-
tion of a pollution control facility. The SBA suggests
that farmers first exhaust FSA loan possibilities.
It may be worth contacting local and regional com-
mercial banks. Some of these banks have a history
of providing debt financing for small energy pro-
jects, and may be willing to provide project financ-
ing to a "bundle" of two or more farm biogas pro-
jects. However, transaction costs for arranging debt
financing are relatively high, owing to the lender's
due diligence (i.e., financial and risk investigation)
requirements. It is often said that the transaction
costs are the same for a 100-kW project as they are
for a 10-MW or greater project. For this reason,
most large commercial banks and investment houses
hesitate to lend to farm scale projects with capital
requirements less than about $20 million.
7-2.3 Equity Financing
Investor equity financing is a rarely used method of
financing agricultural biogas projects. Project inves-
tors typically provide equity or subordinated debt.
Equity is invested capital that creates ownership in
the project, like a down payment on a home mort-
gage. Equity is more expensive than debt, because
the equity investor accepts more risk than the debt
lender. This is because debt lenders usually require
that they be paid from project earnings before they
are distributed to equity investors. Thus, the cost of
financing with equity is usually significantly higher
than financing with debt. Subordinated debt is re-
paid after any senior debt lenders are paid and be-
fore equity investors are paid. Subordinated debt is
sometimes viewed as an equity-equivalent by senior
lenders, especially if provided by a credit-worthy
equipment vendor or industrial company partner.
There are two methods for equity finance: self and
investor. Regardless of method, the following basic
principles apply.
In order to use equity financing, an investor must be
willing to take an ownership position in the potential
biogas project. In return for this share of project
ownership, the investor is willing to fund all or part
of the project costs. Project, as well as some equip-
ment vendors, fuel developers, or nearby farms
could be potential equity investors.
The primary advantage of this method is its avail-
ability to most projects; the primary disadvantage is
its high cost.
Investor's Requirements
The equity investor will conduct a thorough due
diligence analysis to assess the likely ROR associ-
ated with the project. This analysis is similar in
scope to banks' analyses, but is often accomplished
in much less time because of the entrepreneurial na-
ture of equity investors as compared to institutional
lenders. The equity investor's due diligence analy-
sis typically includes a review of contracts, project
participants, equity commitments, permitting status,
technology and market factors.
The key requirement for most pure equity investors
is sufficient ROR on their investment. The due dili-
gence analysis, combined with the cost and operat-
ing data for the project, enables the investor to cal-
culate the project's financial performance (e.g., cash
flows, ROR) and determine its investment offer
based on anticipated returns. An equity investor
may be willing to finance up to 100% of the pro-
ject's installed cost, often with the expectation that
additional equity or debt investors will be located at
a later time.
Some types of partners who provide equity or sub-
ordinated debt may have unique requirements. Po-
tential partners such as equipment vendors generally
expect to realize some benefits other than just cash
SECOND EDITION
7-5
-------
Chapter 7
Obtaining Project Financing
flow. The desired benefits may include equipment
sales, service contracts, tax benefits, and economical
and reliable energy supplies. For example, an en-
gine vendor may provide equity or subordinated
debt up to the value of the engine equipment, with
the expectation of selling out its interest after the
project is built. A nearby farm company might want
to gain access to inexpensive fuel or derived energy.
The requirements imposed by each of these potential
investors are sure to include an analysis of the tech-
nical and financial merit of the project, and a con-
sideration of the unique objectives of each investor.
Securing Equity Financing
To fully explore the possibilities for equity or sub-
ordinated debt financing, farm owners should ask
potential developers if this is a service they can pro-
vide. The second most common source of equity
financing is an investment bank that specializes in
the placement of equity or debt. Additionally, the
equipment vendors, and companies that are involved
in the project may be willing to provide financing
for the project, at least through the construction
phase. The ability to provide financing could be an
important consideration when selecting a builder,
equipment vendor, or other partners.
7-2.4 Third-Party Financing
Should a farm owner or project developer be unable
to raise the required capital using equity or debt or
be unwilling to accept project risks, one last form of
financing might be considered. With each of the
following methods, the project sponsor gives up
some of the project's economic benefits in exchange
for a third-party becoming responsible for raising
funds, project implementation, system operation, or
a combination of these activities. Some of the disad-
vantages of third-party financing include accounting
and liability complexities, as well as the possible
loss of tax benefits by the farm owner.
Lease Financing
Lease financing encompasses several strategies in
which a farm owner leases all or part of the project's
assets from the asset owner(s). Typically, lease ar-
rangements provide the advantage of transferring tax
benefits such as accelerated depreciation or energy
tax credits to an entity that can best use them. Lease
arrangements commonly provide the lessee with the
option, at pre-determined intervals, to purchase the
assets or extend the lease. Several large equipment
vendors have subsidiaries that lease equipment, as
do some financing companies. There are several
variations on the lease concept including:
^ Leveraged Lease. In a leveraged lease, the
equipment user leases the equipment from the
owner, who finances the equipment purchase
with extended debt and/or equity.
^ Sales-Leaseback. In a sales-leaseback, the
equipment user buys the equipment, then sells it
back to a corporation, which then leases it back
to the user under contract.
^ Energy Savings Performance Contracting
(ESPC). ESPC is another contracting agree-
ment that might enable a large project to be im-
plemented without any up-front costs. The
ESPC entity, such as a venture capitalist or
green investor, actually owns the system and in-
curs all costs associated with its design, installa-
tion, or maintenance in exchange for a share of
any cost savings. The ESPC entity recovers its
investment and ultimately earns a profit. It is
earned by charging the farm for supplied energy
at a rate below what energy from a conventional
utility would cost. The end-user must usually
must commit to take a specified quantity of en-
ergy or to pay a minimum service charge. This
"take or pay" structure is necessary to secure the
ESPC.
7-2.5 Project Financing
"Project finance" is a method for obtaining commer-
cial debt financing for the construction of a facility.
Lenders look at the credit-worthiness of the facility
to ensure debt repayment rather than at the assets of
the developer/sponsor. Farm biogas projects have
historically experienced difficulty securing project
financing because of their relatively small size and
the perceived risks associated with the technology.
However, project financing may be available to
large projects in the future. In most project finance
cases, lenders will provide project debt for up to
about 80% of the facility's installed cost and accept
a debt repayment schedule over 8 to 15 years. Pro-
7-6
SECOND EDITION
-------
Chapter 7
Obtaining Project Financing
ject finance transactions are costly and often an on-
erous process of satisfying lenders' criteria.
The biggest advantage of project finance is the abil-
ity to use others' funds for financing, without giving
up ownership control. The biggest disadvantage is
the difficulty of obtaining project finance for farm
biogas projects.
The best opportunities for farm biogas projects to
secure project financing are with project finance
groups at smaller investment capital companies and
banks. Opportunities also exist at one of several
energy investment funds that commonly finance
smaller projects. Some of these lenders have ex-
perience with landfill gas projects and may also be
attuned to the unique needs of smaller projects.
7-3. Capital Cost Effects of Financing
Alternatives
Each financing method produces a different
weighted cost of capital. This affects the amount of
money that is spent to pay for a farm biogas power
project and the energy revenue or savings needed to
cover project costs.
The weighted cost of capital is dependent on the
share of project funds financed with debt and equity,
and on the cost of that debt or equity (i.e., interest
rate on debt, ROR on equity). The more common
private equity structure is the 50% debt case, and the
more common project finance structure is the 80%
debt case. For example, in a project finance sce-
nario with a debt/equity ratio of 80/20, an interest
rate on debt of 9%, and an expected ROR on equity
of 15%, the weighted cost of capital is 10.2%. De-
creasing the amount of debt to 70% means that more
of the project funds must be financed with equity,
which carries a higher interest rate than debt, so the
weighted cost of capital becomes 10.8%. Increasing
the weighted cost of capital means that project reve-
nues must be increased to pay the added financing
charges. In contrast a lower weighted cost of capital
lessens the amount of money spent on financing
charges, which makes the project more competitive.
Interest rates are an important determinant of project
cost if the owner decides to borrow funds to finance
the project. For example, raising interest rates by
1% would cause an increase of about 2% to 3% in
the cost of generating electricity from a biogas pro-
ject. Interest rates are determined by the prevailing
rate indicators at a particular time, as well as by the
project and lender's risk profiles.
Among the five main financing methods presented
above, cost sharing by public agencies coupled with
debt financing usually produces the lowest financing
costs over time, while private equity financing pro-
duces the highest. Generally, the five financing
methods are ranked from lowest cost to highest cost
as follows:
1. Cost share plus debt financing
2. Debt financing
3. Lease financing
4. Project financing
5. Private equity financing.
SECOND EDITION
7-7
-------
Chapter 8 Permitting and Other Regulatory
Issues
Contents:
8-1. The Permitting Process
8-2. Zoning and Permitting
8-2.1 Zoning/Land Use
8-2.2 Permitting Issues
8-3. Community Acceptance
8-4. Regulations Governing Air Emissions from Energy Recovery
Systems
8-4.1 NOX Emissions from Energy Conversion
8-4.2 SOX Emissions from Energy Conversion.
4
.4
.5
List of Exhibits:
Exhibit 8-1 The Permitting Process 2
SECOND EDITION
-------
Chapter 8
Permitting and Other Regulatory Issues
This chapter provides a guide to permitting and
other regulatory issues. In general, there have
been few permits required for farm biogas systems.
Today, however, permitting activities for all farm
manure management systems are increasing.
Obtaining the required environmental, siting, and
other permits is an essential step in the project de-
velopment process. Permit conditions may affect
project design, and neither construction nor opera-
tion should begin until all permits are in place. The
process of permitting a digester gas-to-energy pro-
ject may take anywhere from 4 to 9 months to com-
plete, depending on the project's location and recov-
ery technology. For example, a project sited in a
location that requires no zoning variances will
probably take much less time to permit than a pro-
ject subject to zoning hearings.
It should be noted that states are generally granted
the authority to implement, monitor, and enforce the
federal regulations by establishing their own permit
programs. As a result, some state permit program
requirements are more stringent than those outlined
in the federal regulations and there is a large state-
to-state variance in agencies and standards. For this
reason, owner/operators and project developers
should determine state and local requirements before
seeking project permits.
8-1. The Permitting Process
There are four general steps (outlined in the flow-
chart in Exhibit 8-1) in the permitting process:
^ Step 1. Hold preliminary meetings with key
regulatory agencies. Meet with regulators to
identify permits that may be required and any
other issues that need to be addressed. These
meetings also give the developer the opportunity
to educate regulators about the project, since
biogas technologies may be unfamiliar to
regulators.
^ Step 2. Develop the permitting and design
plan. Determine the requirements and assess
agency concerns early on, so permit applications
can be designed to address those concerns and
delays will be minimized.
^ Step 3. Submit timely permit applications to
regulators. Submit complete applications as
early as possible to minimize delays.
^ Step 4. Negotiate design changes with regula-
tors in order to meet requirements. Permit-
ting processes sometimes provide opportunities
to negotiate with regulators. If negotiation is al-
lowed, it may take into account technical as well
as economic considerations.
As these steps indicate, the success of the permitting
process relies upon a coordinated effort between the
developer of the project and various agencies who
must review project plans and analyze their impacts.
Project developers might have to deal with separate
agencies with overlapping jurisdictions, underscor-
ing the importance of coordinating efforts to mini-
mize difficulties and delays.
In some cases, permitting authorities may be unfa-
miliar with the characteristics and unique properties
of biogas. Where appropriate, the owner/operator or
project developer should approach the permitting
process as an opportunity to educate the permitting
authorities, and should provide useful, targeted in-
formation very early in the process. Local and state
NRCS representatives may be of assistance regard-
ing whom to contact.
Emphasizing the pollution and odor control aspects
of biogas energy recovery projects can be an effec-
tive approach in seeking permits and may make the
permitting process much easier.
SECOND EDITION
8-1
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Chapter 8
Permitting and Other Regulatory Issues
Exhibit 8-1 The Permitting Process
Contact/Meet Regulatory
Authorities and Determine
Requirements
Develop Permitting and
Design Plan, Data
Collection
Submit
Permit
Applications
YES
Design
Changes
Requested?
Meetings are beneficial to educate
permitting authorities and address
their concerns
Project design should reflect all
permitting criteria
Design changes may be necessary
to meet permitting requirements
NO
Application Process
and
Approval
The process approval time varies
depending on a number of factors
Local approval of a project is crucial to its success.
This approval refers not only to the granting of per-
mits by local agencies, but also to community accep-
tance of the project. Strong local sentiment against
a project can make permitting difficult, if not
impossible.
8-2. Zoning and Permitting
Project siting and operation are governed by local
jurisdictions (in addition to federal regulations).
Therefore, it is imperative to work with regulatory
bodies throughout all stages of project development
to minimize permitting delays, which cost both time
and money. This is especially important since the
pollution prevention benefits of projects may not
initially be considered.
8-2
SECOND EDITION
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Chapter 8
Permitting and Other Regulatory Issues
8-2.1 Zoning/Land Use
The first local issue to be addressed is the compati-
bility of the project with community land use speci-
fications. Projects on existing farms should have
few problems. Most communities have a zoning and
land use plan that identifies where different types of
development are allowed (e.g., residential, commer-
cial, industrial). The local zoning board determines
whether or not land use criteria are met by a new
farm project, and can usually grant variances if con-
ditions warrant.
8-2.2 Permitting Issues
In addition to land use specifications, local agencies
have jurisdiction over a number of other parameters
that may or may not be applicable to the project or
location, such as the following:
^ Confined Animal Facility Operation Permits
(CAFO). Depending on the size of the animal
confinement operation, a state agency regulated
confined animal facility operation (CAFO) per-
mit may be in force. The permit was developed
under the National Pollution Discharge Elimina-
tion System (NPDES). Generally, any alteration
in methodologies employed to manage manure
require review and approval by that agency.
Discussion of project benefits (odor, pathogen,
weedseed, nutrient mineralization) may aid the
regulators during preliminary conversation and
subsequent authorization.
^ Recycling. Projects with financial viability de-
pendent on sale of recycled materials likely are
subject to review of the state/regional agency
governing recycling programs. Some degree of
marketing research and product purchase com-
mitment may be required. This is particularly
true of projects generating revenues through the
receipt of "tipping" fees to receive wastes for
disposal and processing. Regulators do not
want materials received for an income-
generating fee to accumulate and not be subse-
quently sold.
^ Noise. Most local zoning ordinances stipulate
the allowable decibel levels for noise sources.
These levels vary, depending on the zoning
classification at the source site (e.g., a site lo-
cated near residential areas will have a lower
decibel requirement than one located in an iso-
lated area). Even enclosed facilities may be re-
quired to meet these requirements; therefore, it
is important to keep them in mind when design-
ing project facilities.
Wastewater. All farms remain under zero dis-
charge rules for digester effluent. The CAFO
permits control facilities and operations.
Water. Water requirements depend on the type
and size of the project. If current facilities can-
not meet the needs of the project, then new fa-
cilities (e.g., pipeline, pumping capacity, wells)
may need to be constructed. Groundwater per-
mits could be required if new wells are needed
to supply the project's water needs.
Solid Waste Disposal. The only solid wastes
generated by a biogas project are likely packag-
ing materials, cleaning solvents, and equipment
fluids. While there may only be a small amount
of solid waste generated, it must be properly
disposed.
Stormwater Management. State environ-
mental agencies regulate stormwater manage-
ment, and may require a permit for discharges
during construction and operation. Good facil-
ity design that maintains the predevelopment
runoff characteristics of the site allows the pro-
ject to easily meet permitting requirements.
8-3. Community Acceptance
As any project developer will attest, community
support is extremely important to the success of a
project, especially since some communities require
public participation in project zoning/siting cases.
Many farms are encountering local opposition such
as the "not in my backyard (NIMBY)" syndrome, or
perceptions of project impacts (e.g., odor, ground-
water pollution). Therefore, it is important to edu-
cate the public and to develop a working relation-
ship with the neighboring community in order to
dispel any fears or doubts about the expected impact
SECOND EDITION
8-3
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Chapter 8
Permitting and Other Regulatory Issues
of the project. Project details should always be pre-
sented in a very forthcoming and factual manner.
Biogas projects bring many benefits to the neighbor-
ing community (e.g., improved air quality, reduction
of odor and pollution potential). These benefits
should be emphasized during the permitting process.
AgSTAR materials may be used to fulfill some of
these needs.
8-4. Regulations Governing Air Emis-
sions from Energy Recovery Systems
New Source Review (NSR) is a preconstruction re-
view program under the Clean Air Act that applies
to new and modified major sources. In almost all
cases, farm scale biogas systems will be too small to
trigger NSR permitting. NSR most likely will apply
only to biogas-fueled boilers, engine-generator sets,
and flares for very large projects and projects on
farms near large urban areas. However, each state
has a permitting program for new or modified minor
sources. The emission thresholds for requiring a
minor source permit or registration vary by state.
Therefore, you should check with your local air
permitting authority about permit requirements early
in the planning process.
Links to state and local air pollution control agen-
cies can be found at www.cleanairworld.org.
Regulations have been promulgated under the Clean
Air Act governing airborne emissions from new and
existing sources. These regulations require new or
modified major sources to undergo the NSR process
before they can commence construction. The addi-
tion of a biogas recovery system at an existing farm
would be an example of a modified source. The
purpose of NSR is to ensure that new and modified
major sources meet the applicable air quality stan-
dards and that emissions are controlled using state-
of-the-art technology.
The permit requirements will vary depending on
local air quality. All areas of the country are classi-
fied by their attainment status with National Ambi-
ent Air Quality Standards (NAAQS) for six pollut-
ants - sulfur dioxide, particulate matter, nitrogen
dioxide, carbon dioxide, lead, and ozone. Areas
that meet the NAAQS for a particular air pollutant
are classified as in "attainment" for that pollutant.
Areas that do not meet the NAAQS are classified as
in "nonattainment" for that pollutant.
Permitting requirements are more stringent for non-
attainment areas. Under NSR, sources in attainment
areas undergo Prevention of Significant Deteriora-
tion (PSD) permitting while those in nonattainment
areas undergo nonattainment area NSR permitting.
Nonattainment area permitting requires more strin-
gent emission controls and imposes other require-
ments. Because a location can be classified as at-
tainment for some pollutants and nonattainment for
others, a source may be permitted under both PSD
and nonattainment area NSR. For example, a biogas
combustion engine may be reviewed under PSD for
carbon monoxide and nonattainment NSR for ozone.
In summary, small projects that are typical of most
farm scale biogas systems may find the air
permitting process to be quite straightforward. Very
large projects (i.e., >500 kW), particularly those in
urban nonattainment areas, may require NSR. The
process of obtaining a NSR permit can be extensive
and can require lead times of 6 to 9 months to obtain
a permit. Construction of a project cannot begin
until the permit is issued. Given the complexity of
the air permitting regulations, an owner/operator
may wish to consult an expert familiar with the NSR
process in a particular area.
8-4.1 NOX Emissions from Energy
Conversion
Combustion of biogas ~ in an engine, turbine, or
boiler ~ generates nitrogen oxides (NOX). For bio-
gas combustion sources, NOX is likely to be the
emission of greatest concern to state air pollution
regulators. Nitrogen oxides contribute to the forma-
tion of atmospheric ozone and fine particulate mat-
ter. Obtaining a permit may require selection of a
combustion device with low NOX emissions.
Reciprocating Internal Combustion Engines
There are two basic types of reciprocating engines:
naturally aspirated and fuel injected lean-burn:
8-4
SECOND EDITION
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Chapter 8
Permitting and Other Regulatory Issues
4 Naturally Aspirated engines draw combus-
tion air and biogas through a carburetor in
stoichiometric proportions, much the same
way that an automobile equipped with a
carburetor would draw its air/fuel mixture.
Just enough air is drawn into the combus-
tion chamber to ignite the air/biogas mix. In
addition, residence time in the combustion
chamber is relatively long. Therefore, this
type of engine emits relatively high levels of
NOX
^ Fuel injected lean-burn engines inject bio-
gas into the combustion chamber along with
air that is in excess of the stoichiometric
mix. This type of engine provides both
greater engine power output and fewer NOX
emissions than a comparable naturally aspi-
rated engine. In recent years, manufacturers
have developed engines with very low NOX
emissions.
When internal combustion engines are used in
conventional natural gas applications, catalysts
can be used to reduce NOX emissions. To date,
catalysts have not been required in any farm
scale applications because the impurities found
in biogas quickly limit the ability of the catalyst
to control NOX emissions.
Turbines and Boilers
With modern designs, gas-fired boilers and turbines
emit levels of NOX that are lower than fuel injected
lean burn internal combustion engines. For typical
farm scale systems, additional controls should not be
required to obtain a permit.
8-4.2 SOX Emissions from Energy
Conversion
Combustion of biogas also can generate sulfur ox-
ides (SOX). Sulfur oxides are generated when biogas
containing hydrogen sulfide and other reduced sul-
fur compounds are combusted. Sulfur oxides con-
tribute to the formation of fine particulate matter.
In some areas, obtaining a permit may require instal-
lation of a scrubbing technique to remove hydrogen
sulfide and other reduced sulfur compounds before
biogas combustion. It is likely that only biogas pro-
duced from large swine operations would contain
enough sulfur compounds to warrant the considera-
tion of scrubbing.
SECOND EDITION
8-5
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