United States
Environmental Protection
Agency
Air and Radiation
(6202J)
EPA 430-B-96-0004
September 1996
oEPA Turning a Liability into an Asset:
A Landfill Gas-to-Energy Project
Development Handbook
OUTREACH PROGRAM
Internet Address (URL) • http://www.epa.gov
Recycled/Recyclable .Printed with Vegetable Oil Based Inks on Recycled Paper (20% Postconsumer)
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Turning a Liability into an Asset:
A Landfill Gas-to-Energy Project Development Handbook
Landfill Methane Outreach Program
U.S. Environmental Protection Agency
September 1996
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TABLE OF CONTENTS
1. INTRODUCTION 1-1
1.1 The Benefits of Landfill Gas Energy Recovery 1-1
1.1.1 Environmental Benefits 1-2
1.1.2 Economic Benefits 1-2
1.1.3 Energy Benefits 1-2
1.2 The EPA Landfill Methane Outreach Program 1-3
1.3 How To Use This Handbook 1-3
2. DETERMINING IF A PROJECT IS RIGHT FOR YOUR LANDFILL 2-1
2.1 Step 1: Basic Screening for Project Potential 2-2
2.2 Step 2: Estimating Gas Quantity 2-4
2.2.1 Methods for Estimating Gas Flow 2-4
2.2.2 Correcting for Collection Efficiency 2-8
2.2.3 Comparing Your Gas Flow Rate to Existing Projects 2-8
3. DETERMINING WHAT PROJECT CONFIGURATION IS RIGHT FOR YOUR LANDFILL . . 3-1
3.1 Options For Using Landfill Gas 3-1
3.1.1 Collection System and Flare 3-2
3.1.2 Gas Treatment 3-5
3.1.3 Energy Recovery System 3-6
3.2 Choosing an Energy Recovery Option 3-14
4. INTRODUCTION TO PART II: DETAILED ASSESSMENT OF PROJECT OPTIONS 4-1
5. EVALUATING PROJECT ECONOMICS 5-1
5.1 Economic Evaluation Process 5-1
5.2 Power Generation/Cogeneration 5-4
5.2.1 Step 1: Estimate Energy Sales Revenues 5-4
5.2.2 Step 2: Quantify Capital and O&M Expenses 5-9
5.2.3 Step 3: Compare Project Expenses and Revenues 5-15
5.2.4 Step 4: Create a Pro Forma Model of Project Cash Flows 5-21
5.2.5 Step 5: Assess Economic Feasibility 5-22
5.3 Sale of Medium-Btu Gas 5-22
5.3.1 Step 1: Estimate Energy Sales Revenues 5-23
5.3.2 Step 2: Quantify Capital and O&M Expenses 5-25
5.3.3 Step 3: Compare Project Expenses and Revenues 5-27
5.3.4 Steps 4 and 5: Create a Pro Forma and Assess Economic
Feasibility 5-27
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5.4 Alternative Options 5-29
5.4.1 Upgrade to Pipeline Quality Gas 5-29
5.4.2 Vehicle Fuel Applications 5-29
5.4.3 Fuel Cells 5-30
5.4.4 Niche Applications 5-30
5.5 Comparison of All Economically-Feasible Options 5-31
5.5.1 Head-to-Head Economic Comparison 5-31
5.5.2 Consideration of Non-Price Factors 5-31
6. ASSESSING FINANCING OPTIONS 6-1
6.1 Financing: What Lenders/Investors Look For 6-3
6.2 Financing Approaches 6-4
6.2.1 Private Equity Financing 6-4
6.2.2 Project Finance 6-7
6.2.3 Municipal Bond Financing 6-9
6.2.4 Direct Municipal Funding 6-11
6.2.5 Lease Financing 6-11
6.2.6 Public Debt Financing 6-12
6.3 Capital Cost Effects of Financing Alternatives 6-12
7. SELECTING A PROJECT DEVELOPMENT PARTNER 7-1
7.1 The Partner/No Partner Decision 7-2
7.2 Selecting A Development Partner 7-5
7.2.1 Selecting a Pure Developer 7-6
7.2.2 Selecting a Partner (Equipment Vendor, EPC Firm, Fuel Firm,
Industrial) 7-7
7.3 Evaluating Individual Firms 7-9
7.3.1 Issuing a Request for Proposals (RFP) 7-9
7.3.2 Preparing a Contract 7-10
8. WINNING/NEGOTIATING AN ENERGY SALES CONTRACT 8-1
8.1 Power Sales Contracts 8-2
8.1.1 Standard Offer Contracts 8-4
8.1.2 Bidding/Negotiating a Power Sales Agreement (PSA) with an
Electric Utility 8-5
8.1.3 Bidding/Negotiating a PSA with an End User 8-8
8.1.4 Wheeling Arrangements 8-10
8.2 Gas Sales Contract (Medium or High-Btu) 8-12
8.2.1 Medium-Btu Gas Sales 8-12
8.2.2 High-Btu Gas Sales 8-14
9. SECURING PROJECT PERMITS AND APPROVALS 9-1
9.1 The Permitting Process 9-2
9.2 RCRA Subtitle D 9-3
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9.3 Clean Air Act 9-4
9.3.1 Landfill Gas Emissions 9-4
9.3.2 Regulations Governing Air Emissions from Energy Recovery
Systems 9-5
9.4 Local Issues 9-14
9.4.1 Zoning and Permitting 9-14
9.4.2 Community Acceptance 9-16
10. CONTRACTING FOR EPC AND O&M SERVICES 10-1
10.1 EPC/Turnkey Contracting . 10-1
10.2 O&M Services Contracting 10-4
10.3 Good O&M Practices 10-5
10.3.1 Collection Systems 10-5
10.3.2 Energy Recovery Systems 10-6
APPENDICES
Appendix A: Calculations of Landfill Gas Energy Recovery Project Costs
Appendix B: List of U.S. EPA Offices
Appendix C: Executive Summary of a Power Purchase Agreement
Appendix D: Sample Request for Proposals for Landfill Gas Energy Project Developer
Appendix E: EPA Memorandum on Pollution Control Projects and New Source Review
(NSR) Applicability
Appendix F: Map and Listing of Nonattainment Areas
Appendix G: Listing of Municipal Solid Waste Landfill Organizations and Related Service
Providers
Appendix H: List of References
Appendix I: Acid Rain Fact Sheet
Appendix J: Glossary of Terms
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UST OF FIGURES
Figure 3.1 Typical Landfill Gas Extraction Well 3-2
Figure 3.2 Typical Landfill Gas Extraction Site Plan 3-3
Figure 5.1 The Economic Evaluation Process 5-2
Figure 5.2 Deciding Among Energy Project Options 5-32
Figure 6.1 Assessing Financing Options 6-2
Figure 6.2 Capacity Price Produced by Different Financing Approaches 6-3
Figure 7.1 The Developer/Partner Selection Process 7-3
Figure 8.1 Types of Companies that Contracted with Landfill Gas Energy Recovery
Projects for the Purchase of Gas or Electricity in 1994 8-2
Figure 8.2 Winning/Negotiating An Energy Sales Contract
(Power Sales Agreement) 8-3
Figure 8.3 Winning/Negotiating An Energy Sales Contract (Gas Sales) 8-13
Figure 9.1 Project Permitting 9-3
Figure 9.2 Applicability of New Source Review Requirements in
Attainment Areas for Ozone 9-7
Figure 9.3 Applicability of New Source Review Requirements in
Serious Non-Attainment Areas for Ozone 9-9
Figure 10.1 The EPC/Turnkey Contracting Process 10-2
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LIST OF TABLES
Table 2.1 Suggested Values for First Order Decay Model Variables 2-6
Table 3.1 Summary of Representative Collection System Costs . 3-5
Table 3.2 Landfill Gas Flows Based on Landfill Size 3-7
Table 3.3 Estimated 1996 Costs of Electricity 3-18
Table 5.1 Estimated First Year Power Project Revenues at Example Landfill 5-8
Table 5.2 Estimated Power Project Capital Costs for Three Landfill Sizes 5-11
Table 5.3 Estimated Power Project Capital Costs at Example Landfill 5-12
Table 5.4 Estimated Cost of Electricity Production for Three Project Configurations
at Example Landfill 5-16
Table 5.5 First Year Project Revenues and Expenses for Three Project
Configurations at Example Landfill 5-20
Table 5.6 Estimated Medium-BTU Project Capital Costs at Example Landfill 5-26
Table 5.7 Estimated Cost of Producing Medium-BTU Gas at Example Landfill 5-28
Table 6.1 Addressing Landfill Gas Energy Project Risks 6-5
Table 6.2 Capital Cost Effects of Financing Approaches 6-14
Table 8.1 Typical Bid Components 8-9
Table 9.1 Attainment Area Limits for NOx and CO 9-8
Table 9.2 Nonattainment Area Limits for NOx and CO 9-10
Table 9.3 Emission Factors By Technology Type 9-13
Table 9.4 NOx Emissions Table 9-13
Table 10.1 Elements of an Effective EPC or Turnkey Contract 10-3
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LIST OF BOXES
Box 2.1 Is a Project Right for Your Landfill? 2-3
Box 2.2 Example Using Simple Approximation Method 2-5
Box 2.3 Example Using First Order Decay Model 2-7
Box 2.4 Energy Recovery at Two Very Different Landfills 2-9
Box 3.1 Examples of Direct Use Applications 3-7
Box 3.2 Considerations When Using Landfill Gas as a Medium-Btu Fuel 3-8
Box 3.3 Comparison of Electricity Generation Technologies 3-10
Box 3.4 Design Considerations When Sizing Power Projects 3-11
Box 3.5 Landfill Gas as a Vehicle Fuel 3-14
Box 3.6 Converting Gas Flowrates into Power Potential 3-15
Box 5.1 Assumptions for Five Million Metric Ton Landfill Example 5-5
Box 5.2 Displacement of Energy Purchases at the Prince George's County Correctional
Complex 5-7
Box 5.3 Classification of O&M Expenses 5-13
Box 5.4 Examples of How a Project Can Be Structured to Take Advantage of Section
29 Tax Credits 5-18
Box 5.5 The Pro Forma 5-21
Box 5.6 Multiple End Uses of Landfill Gas Create a Baseload Demand for Fred Weber,
Inc 5-24
Box 5.7 Natural Gas Price Variations by Customer Type 5-24
Box 5.8 Medium-Btu Gas Sales to AT&T 5-25
Box 6.1 Private Equity Financing - Advantages\Disadvantages 6-6
Box 6.2 Project Finance - Advantages\Disadvantages 6-8
Box 6.3 Municipal Bond Financing - Advantages\Disadvantages 6-10
Box 6.4 Direct Municipal Funding - Advantages\Disadvantages 6-12
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Box 7.1 The Role of the Project Developer 7-4
Box 7.2 Developer Selection at (-95 Landfill 7-7
Box 7.3 Elements of a Partnership Contract 7-11
Box 8.1 Multi-Part Pricing 8-8
Box 8.2 Potential Competitive Advantages of Landfill Gas Projects 8-10
Box 9.1 Some of the Local Permits Required for the Fresh Kills Landfill Methane
Recovery Project 9-17
Box 10.1 EPC and Turnkey Budget Items 10-4
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ACKNOWLEDGEMENTS
This handbook was prepared with the assistance of numerous individuals. Staff at
Boston Pacific provided technical expertise and provided the first draft of most of the
document. Staff at ICF Incorporated compiled the chapters, reviewed and edited them, and
produced the entire document.
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1. INTRODUCTION
The Project Development Process
Parti
Preliminary Assessment of
Project Options
Determining if a Project is Right for Your Landfill
Determining What Project Configuration is Right
for Your Landfill
\
Part II
Detailed Assessment of
Project Economics
Each person in the United States
generates about 4.5 pounds of solid waste
per day-almost one ton per year. Most of
this waste is deposited in municipal solid
waste landfills. As this landfilled waste
decomposes (a process that may take 30
years or more), it produces landfill gas.
Landfill gas contributes to the formation of
smog and poses an explosion hazard if
uncontrolled. Furthermore, because landfill
gas is about 50 percent methane, it is both
a potent greenhouse gas and a valuable
source of energy.
Substantial opportunities exist across
the country to harness this energy resource
and turn what would otherwise be a liability
into an asset. The purpose of this
handbook is to help landfill owners,
operators, and others considering landfill
gas projects determine whether landfill gas
energy recovery is likely to succeed at a
particular landfill, and to clarify the steps
involved in developing a successful project.
The handbook is organized
according to the process of landfill gas
project development, as the flowchart on
this page illustrates. It contains two major
sections: Part I - Preliminary Assessment of Project Options provides the landfill
owner/operator with basic screening criteria to assess the viability of a landfill energy recovery
project and make a preliminary economic comparison of the primary energy recovery options;
and Part II - Detailed Assessment of Project Options outlines and discusses the major
steps involved in development of a landfill gas energy recovery project, from estimating
expenses and revenues to constructing and operating the project. The flowchart on this page
can be found at the front of each chapter, with the current section and chapter highlighted.
Additional information is contained in Appendices A through J of the handbook.
Evaluating Project Economics
Assessing Financing Options
Selecting a Project Development Partner
Winning/Negotiating an Energy Sales Contract
Securing Project Permits and Approvals
Contracting for EPC and O&M Services
1.1 THE BENEFITS OF LANDFILL GAS ENERGY RECOVERY
Landfill gas energy recovery offers significant environmental, economic, and energy
benefits. These benefits are enjoyed by many, including the landfill owner/operator, the
project developer, the energy product purchaser and consumer, and the community living
near the landfill.
Introduction
September 1996
Page 1-1
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1.1.1 Environmental Benefits
Landfill gas contains volatile organic compounds, which are major contributors to
ground-level ozone and which include air toxics. When little is done to control them, these
pollutants are continuously released to the atmosphere as waste decomposes. When landfill
gas is collected and burned in an energy recovery system, these harmful pollutants are
destroyed.
Regulations already require many landfills to collect their landfill gas emissions, and
new federal air regulations will soon require additional control. Once the gas is collected,
landfill owner/operators have two choices: (1) flare the gas; or (2) produce energy for sale or
on-site use. Both options address local air quality and safety concerns, but only energy
recovery capitalizes on the energy value of landfill gas, while displacing the use of fossil fuels.
Offsetting coal and oil use further reduces emissions of a number of pollutants, including
sulfur dioxide, a major contributor to acid rain, as well as the production of ash and scrubber
sludge from utilities. Furthermore, landfill gas collection systems operated for energy
recovery are often more carefully managed than those designed to flare the gas. This means
that more of the gas generated in the landfill may be collected and combusted, with fewer
emissions to the atmosphere.
Landfill gas energy recovery also has the potential to significantly reduce the risk of
global climate change. Landfill gas is the single largest source of anthropogenic methane
emissions in the United States, contributing almost 40 percent of these emissions each year.
Reducing methane emissions is critical in the fight against global climate change because
each ton of methane emitted into the atmosphere has as much global warming impact as 21
tons of carbon dioxide over a 100 year time period. In addition, methane cycles through the
atmosphere about 20 times more quickly than carbon dioxide, which means that stopping
methane emissions today can make quick progress toward slowing global climate change.
1.1.2 Economic Benefits
New federal regulations, promulgated in March 1996, require several hundred landfills
across the country to collect and combust their landfill gas emissions. Once installation and
operation of a collection system is a required cost of doing business, incurring the extra cost
of installing an energy recovery system becomes a more attractive investment. Sale or use of
landfill gas will often lower the overall cost of compliance and, when site-specific conditions
are favorable, the landfill may realize a profit.
More widespread use of landfill gas as an energy resource will also create jobs related
to the design, operation, and manufacture of energy recovery systems and lead to
advancements in U.S. environmental technology. Local communities will also benefit, in terms
of both jobs and revenues, through the development of local energy resources at area
landfills.
1.1.3 Energy Benefits
Landfill gas is a local, renewable energy resource. Because landfill gas is generated
continuously, it provides a reliable fuel for a range of energy applications, including power
generation and direct use. Electric utilities that participate in landfill gas-to-energy projects
can benefit by enhancing customer relations, broadening their resource base, and gaining
valuable experience in renewable energy development. Landfill gas power projects provide
Introduction September 1996 Page 1-2
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important demand side management benefits, as transmission losses from the point of
generation to the point of consumption are negligible. The National Association of Regulatory
Utility Commissioners recognized the value of landfill gas as an energy resource when it
adopted a resolution in March 1994 "urging regulators to focus their regulatory attention on
the landfill gas resources in their States to determine the role that energy from landfill gas can
play as an energy resource for utilities and their customers." Industrial facilities, universities,
hospitals, and other energy users can benefit by tapping into landfill gas, a low-cost, local fuel
source.
1.2 THE EPA LANDFILL METHANE OUTREACH PROGRAM
The EPA Landfill Methane Outreach Program encourages landfill owner/operators to
develop landfill gas energy recovery projects wherever it makes economic sense to do so.
EPA estimates that over 700 landfills across the United States could install economically
viable landfill gas energy recovery systems, yet only about 140 energy recovery facilities are
in place. Through the Outreach Program, EPA is working with municipal solid waste landfill
owners and operators, states, utilities, industry and other federal agencies to lower the
barriers to economic landfill gas energy recovery.
This handbook is one component of the Landfill Methane Outreach strategy for
overcoming information barriers to development of energy recovery projects. By providing
information that can be used to assess project feasibility and outlining the project
development process to landfill owner/operators and others considering energy recovery
projects, this handbook can help spur development of successful projects. For more
information on the Outreach Program, contact EPA's Hotline at 1 -888-STAR-YES.
1.3 How To USE THIS HANDBOOK
If you are a landfill owner/operator - or anyone considering a landfill gas-to-energy
project - you can use this handbook to conduct a preliminary assessment of the potential for
your landfill to support an energy recovery project. First, review Section 2.1 with the
parameters of your landfill in mind. If your landfill meets the basic screening criteria (or has
site-specific factors that make it a good candidate for energy recovery), use the information
provided in Section 2.2 to develop a rough estimate of available landfill gas. Next, examine
the economic comparison in Chapter 3, referring to the landfill gas estimate closest to that for
your landfill, and determine which energy recovery option may be most cost-effective. Finally,
carefully review Part II of the handbook (Chapters 4 to 10) to gain an understanding of the
steps involved in developing an energy recovery project at your landfill. You may want to
consult some of the references listed in Appendix H for more detailed information on the gas
being generated at your landfill and the collection and energy recovery system you are
considering.
This handbook is not meant to be an exhaustive guide to the landfill gas development
process, nor is it a technical guide to project design. Once you have decided to pursue a
gas-to-energy project, you may want to consult experts with experience in project
development as well as technical resources regarding construction, equipment, operation,
and other aspects of project design. The Landfill Methane Outreach Program can provide
you with a list of landfill gas-to-energy project developers, engineers, equipment
Introduction September 1996 Page 1-3
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manufacturers, financiers, and end-users, and Appendix G contains a listing of organizations
that can refer you to additional experts in project design, development, and operation.
Introduction September 1996 Page 1-4
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PARTI
PRELIMINARY ASSESSMENT OF PROJECT OPTIONS
The Project Development Process
Determining if a Project is Right for Your Landfill
Determining What Project Configuration is Right
for Your Landfill
I
Part II
Detailed Assessment of
Project Economics
Evaluating Project Economics
Assessing Financing Options
Selecting a Project Development Partner
Winning/Negotiating an Energy Sales Contract
Securing Project Permits and Approvals
Contracting for EPC and O&M Services
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2. DETERMINING IF A PROJECT Is RIGHT FOR YOUR LANDFILL
The preliminary assessment of
project options includes two major phases.
First, the landfill owner/operator must
determine whether a project is likely to
succeed at his or her landfill. If the landfill
meets the criteria for a conventional energy
recovery project—or has other
characteristics that make it a good energy
recovery candidate—the owner/operator
next determines what project configuration
would be most cost-effective. This chapter
describes the steps involved in the first of
these phases.
Determining if an energy recovery
project may be right for a particular landfill is
the first phase involved in assessing project
options, as shown in the flowchart on this
page. This phase involves two steps:
The Project Development Process
Parti
Preliminary Assessment of
Project Options
Determining What Project Configuration is Right
for Your Landfill
Part II
Detailed Assessment of
Project Economics
Evaluating Project Economics
Assessing Financing Options
Selecting a Project Development Partner
Winning/Negotiating an Energy Sales Contract
Securing Project Permits and Approvals
(1) application of basic screening
criteria to determine if the
landfill has the characteristics
that apply generally to
successful landfill gas energy
recovery projects; and
Contracting for EPC and O&M Services
(2) estimation of the quantity of
landfill gas that can be
collected, as gas quantity is a
critical factor in determining whether landfill gas energy recovery is a viable
option.
The approximately 140 landfill gas energy recovery projects operating in the United
States exhibit a wide range of landfill characteristics and gas flows, illustrating that many
different types of landfills can support successful projects. Nevertheless, there are a few
basic criteria that can be used for site screening to determine whether a project is likely to
succeed at a particular landfill. For example, a large landfill that is still receiving waste will, in
general, be an attractive candidate for landfill energy recovery. These and other criteria, and
how to apply them, are discussed in Section 2.1.
For landfills that appear to be candidates for energy recovery, estimating landfill gas
flows is essential. The amount of gas that can be collected is dependent upon a number of
factors, including, among others, the amount of waste in place, the depth of the landfill, the
age and status of the landfill, and the amount of rainfall the landfill receives. There are
several ways to estimate landfill gas quantity, ranging from "back of the envelope" calculations
to sophisticated computer modeling. Not surprisingly, both the degree of certainty that
Part
September 1996
Page 2-1
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collected gas quantity will match the estimate and the cost of developing the estimate
increase along this spectrum. Section 2.2 describes some of the various methods available
to estimate the gas generation and collection rate.
If the landfill under consideration for energy recovery already has a gas collection
system that is likely to be representative of the area from which gas will be drawn (i.e., not
just perimeter wells), the task of estimating gas quantity is essentially complete. The quantity
of gas collected with the current system can be used to estimate the amount of gas available
for energy recovery.
2.1 STEP 1: BASIC SCREENING FOR PROJECT POTENTIAL
The purpose of basic screening is to quickly identify landfills that are good candidates
for energy recovery. The questions in Box 2.1 can help guide a landfill owner/operator
through the process of evaluating screening criteria, which are identified below. It is likely that
the best candidates for energy recovery will have the following characteristics:
• At least one million tons of waste in place;
• Still receiving waste, or closed for not more than a few years; and
• Landfill depth of 40 feet or more.
Landfills that meet these criteria are likely to generate enough landfill gas to support a gas-to-
energy project. An industry rule of thumb places the "economically viable" gas generation
rate at one million cubic feet per day (1 mmcf/day). However, this figure, like the screening
criteria, should be considered only as a guideline - in fact, many landfills that do not meet all
of the criteria could support successful energy recovery projects because of important site-
specific characteristics. For example, energy recovery projects are currently underway at
landfills with as little as 50,000 tons of waste in place, gas flows of 20,000 cf/day and depths
of just 10 feet. In addition, about forty percent of existing and planned projects are sited at
closed landfills, with about half of these closed during the 1980s [Berenyi and Gould, 1994].
Landfills that already collect their landfill gas, or that will be required to collect the gas,
may be attractive candidates for energy recovery, especially if they meet most or all of the
other criteria. Once installation and operation of a collection system is a required cost of
doing business, the extra cost of energy recovery becomes a more attractive investment. In
this situation, energy recovery may be the most cost-effective compliance strategy, even if it
does not provide a net profit.
Some additional characteristics may also be indicative of energy recovery potential.
These include:
• Climate: Moisture is an important medium for the bacteria that break down the
waste. In areas with very low rainfall (i.e., less than 25 inches per year), yearly
generation of landfill gas is likely to be relatively low. Therefore, less gas may
be available for energy recovery each year at arid landfills (although gas
production may continue for a longer period of time than in a wetter
environment),
• Waste Type: Methane is generated when organic waste, such as paper and
food scraps, decomposes. Therefore, landfills (or cells within landfills) that
Part I September 1996 Page 2-2
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Box 2-1 Is a Project Right for Your Landfill?
A. Is your landfill a municipal solid waste landfill?
If not, you may encounter some additional issues in project development due to the presence of hazardous or
non-organic waste in the landfill. Stop and consult an energy recovery expert
B. Add your score for the next 3 questions:
1. How much waste is in your landfill? Score
Tons Score
> 3 million 40
1-3 million 30
0.75-1 million 20
< 0.75 million 10
2. Is your fill area at least 40 feet deep?
Yes = 5
No =0
3. Is your landfill currently open? If yes, answer 3{a). If no, answer 3{b).
(a) How much waste will be received in the next 10 years?
For each 500,000 ton, score 5 points. +
(b) tf closed < 1 year, enter 0.
If closed > 1 year, multiply each year since closure by 5, and
subtract that amount from the total. -
Total your answers to questions 1-3: =
C. If your score is:
> 30: Your landfill is a good candidate for energy recovery (go to section D).
20-30: Your landfill may be a good candidate for energy recovery, particularly if a factory or other
energy user with constant fuel demand is located within a few miles of the landfill (go to Section D).
< 20: Your landfill may not be a good candidate for conventional energy recovery options.
However, you may want to consider on-srte or alternative uses for the landfill gas.
D. If your landfill is a good candidate, answer the following questions:
1. Are you now collecting gas at your landfill (other than from perimeter wells), or do you plan to do so
soon for regulatory or other reasons? If yes, your landfill may be an excellent candidate for energy
recovery.
2. (a) Is annual rainfall less than or equal to 25 inches per year?
(b) Is construction and demolition waste mixed into the municipal waste or is it a large portion of
total waste?
If yes to questions D.2(a) or D.2(b), your annual landfill gas production may be lower than otherwise
expected. Your landfill may still be a strong candidate, but you may want to lower your estimated
gas volumes slightly during project design and evaluation.
Part I September 1996 Page 2-3
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contain large proportions of synthetic or slowly-decomposing organic waste,
such as plastic and construction/demolition waste, may be less attractive
candidates for energy recovery.
Nearby Energy Use: A smaller landfill may still be a good candidate for energy
recovery if there is a use for the gas at or near the landfill. Such landfills
should not be discounted without exploration of direct gas use options.
2.2 STEP 2: ESTIMATING GAS QUANTITY
Once the landfill owner/operator has determined that energy recovery may be
attractive, the next step is to estimate landfill gas flow. Information from this step is of critical
importance in determining the technical specifications of the project and in assessing its
economic feasibility. There are a variety of methods, ranging from very basic desktop
estimates to actual field tests, as described below. Because both the cost and the reliability
of the estimates increases for more detailed methods, it is recommended that the basic
estimation approaches be used first, and more detailed methods be used (if warranted) as
project assessment progresses.
2.2.1 Methods for Estimating Gas Flow
Three gas flow estimation methods are presented below. The first two are relatively
simple approaches that require limited site-specific information. Because landfill
characteristics, and therefore gas generation rates, can vary substantially among landfills
(even those with the same amount of waste in place), Methods A and B will provide only
rough gas flow estimates. When using these methods, the landfill owner/operator should
assume that actual gas flows may be 50 percent higher or lower. For example, lower gas
flows may occur at landfills located in arid areas (i.e., receiving less than 25 inches of rainfall
per year) or at landfills containing large amounts of construction/demolition debris. Method
C, in contrast, relies on data from the landfill itself, and should provide more accurate
estimates.
Method A: Simple Approximation
A rough approximation of landfill gas production can be estimated easily using the
amount of waste in place as the only variable. The procedure described below for
approximating gas production is derived from the ratio of waste quantity to gas flow observed
in the many, often very different, projects in operation. It reflects the average landfill that has
an energy recovery project, and may not accurately reflect the waste, climate, and other
characteristics present at a specific landfill. Therefore, it should be used primarily as a
screening tool to determine if a more detailed assessment is warranted (such as can be
developed using Method C).
The simple approximation method only requires knowledge of how much waste is in
place at the target landfill. Based on their extensive experience at many landfills, industry
experts have developed a rule of thumb that landfill gas generation rates range from 0.05 to
over 0.20 cubic feet (cf) of gas per pound (Ib) of refuse per year, with the average landfill
generating 0.10 cf of landfill gas per Ib per year [WMNA, 1992; Walsh, 1994].
Parti September 1996 Page 2-4
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Using this rule of thumb results in the following equation:
Annual Landfill Gas Generation (cf) = 0.10 cf/lb x 2000 Ib/ton x Waste-ln-Place (tons)
A sample calculation using this
method is shown in Box 2.2. Because the
amount of gas generated declines as waste
ages in the landfill, the above gas
generation estimate is only appropriate for
the first year or two of project operation if
no new waste is added. As a result, gas
generation rates may be on the low end of
the range for landfills that have been closed
for several years. In addition, the landfill
owner/operator should adjust downward his
or her rough estimate of gas flows over the
life of the project by 2 to 3 percent per year
[Wolfe and Maxwell].
Model
Method B: First Order Decay
Box 2-2 Example Using Simple
Approximation Method
For a landfill with one million tons of
waste in place, this method yields a
rough estimate of 200 million cubic feet
of landfill gas per year, or about 550,000
cubic feet per day (cfd). The uncertainty
associated with this estimate should be
accounted for by adding and subtracting
50 percent, yielding a range for the
landfill's gas flow of 275,000 to 825,000
cfd.
The second approach - a "First Order Decay Model" - can be used to account for
changing gas generation rates over the life of the landfill of a proposed project.
Understanding the rate of gas flow over time is critical to evaluating project economics (see
Chapter 5), The first order decay model is more complicated than the rough approximation
described above, and requires that the landfill owner/operator know or estimate five variables:
• the average annual waste acceptance rate;
• the number of years the landfill has been open;
the number of years the landfill has been closed, if applicable;
• the potential of the waste to generate methane; and
• the rate of methane generation from the waste.
The basic first order decay model is as follows:
LFG = 2
Where:
LFG
i?
k
t
c
(e'kc - e'w)
Total amount of landfill gas generated in current year (cf)
Total methane generation potential of the waste (cf/lb)
Average annual waste acceptance rate during active life (Ib)
Rate of methane generation (1/year)
Time since landfill opened (years)
Time since landfill closure (years)
The methane generation potential, Lg, represents the total amount of methane that one
pound of waste is expected to generate over its lifetime. Thus, it is much higher than the
landfill gas generation constant used in Method A to represent landfill gas generation per
year. The decay constant, k, represents the rate at which the methane will be released from
Part
September 1996
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each pound of waste. If these terms were known with certainty, the first order decay model
would predict methane generation relatively accurately; however, the values for LQ and k are
thought to vary widely, and are difficult to estimate accurately for a particular landfill.
The values for LQ and k are dependent in part on local climatic conditions and waste
composition; therefore, a landfill owner/operator may want to consult others in the local area,
with similar landfills who have installed gas collection systems to narrow the range of potential
values. On March 12, 1996, EPA issued final regulations for the control of landfill gas at new
and existing municipal solid waste landfills with design capacities of 2.5 million metric tons or
more1. Affected landfills model their gas emissions using the first order decay model. The
regulations include the following default values (as well as a non-methane organic compound
default value of 4000 ppm, which a landfill can replace with site-specific data):
LO = 2.72 cf/lb
• k = 0.05/year
Ranges for LQ and k values developed by an industry expert are presented in Table 2-1. Note
that for different climatic conditions, the LQ (total amount of landfill gas generated) remains the
same, but the k value (rate of landfill gas generation) changes, with dry climates generating
gas more slowly.
Table 2-1 Suggested Values for First Order Decay Model Variables
Variable
LQ (cf/lb)
k (1/yr)
Range
0-5
0.003-0.4
Suggested Values
Wet Climate
2.25-2.88
0.1-0.35
Medium Moisture
Climate
2.25-2.88
0.05-0.15
Dry Climate
2.25-2.88
0.02-0.10
Source: Landfill Control Technologies, "Landfill Gas System Engineering Design Seminar," 1994.
Because of the uncertainty in estimating LQ and k, gas flow estimates derived from the first
order decay model should also be bracketed by a range of plus or minus 50 percent. Box
2.3 shows a sample calculation using the first order decay model.
Method C: Pump Test
The most accurate method for estimating gas quantity, short of installing a full
collection system, is to conduct a pump test. A pump test involves sinking test wells and
installing pressure monitoring probes, then measuring the gas collected from the wells under
a variety of controlled extraction rates. When conducting a pump test, it is important that the
1 61 FR 9905, Tuesday March 12, 1996.
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Box 2-3 Example Using First Order Decay Model
For a landfill with the following characteristics:
• open for 25 years;
• still accepting waste; and
• average annual waste acceptance rate of 40,000 tons
The first order decay model would yield a rough estimate of 310 million cubic feet of
landfill gas per year, or about 850,000 cfd (using the NSPS k and LQ values). The
uncertainty associated with this estimate should be accounted for by adding and
subtracting 50 percent, yielding a range for the landfill's gas flow of 425,000 to 1.3
million cfd.
Note that a landfill with the same amount of waste in place (i.e., one million tons) but a
lower waste acceptance rate would have a lower gas flow rate, while a younger landfill
that was taking in waste more quickly would have a higher gas flow rate. The choice of
different values for k and LQ in the first order decay model would also yield different gas
flow estimates.
test wells are placed to be representative of the waste from which the gas will be eventually
drawn, since gas generation rates may vary across the landfill.
A benefit of this method is that the collected gas can be tested for quality, as well as
quantity. It should be analyzed for Btu content in addition to hydrocarbon, sulfur, particulate,
and nitrogen content. Information obtained from a pump test is important since it is used in
the design of the processing and energy recovery system, as well as in obtaining project
financing.
The cost to drill test wells can range from $5,000 to $10,000 per well [Smithberger,
1994; Merry, 1994]. However, for budgetary purposes, the total cost of installing a well and
extracting gas can be estimated to be approximately $60 per linear foot, with a typical test
well being 100 feet deep [Bilgri, 1995]. This estimate includes costs for the well pipe, pipe
casing, backfill, and labor. The total number of wells required to accurately predict landfill
gas quantity will depend on factors such as landfill size and waste homogeneity.
Other Estimation Methods
Landfill gas energy recovery experts, if consulted by the landfill owner/operator, will
almost certainly want to review and verify estimates developed using the above methods,
particularly estimates developed with Methods A or B. Each energy recovery expert has his
or her own preferred method for estimating landfill gas quantity, and will likely want to use this
method to verify estimates prepared using any of the above methods.
Parti September 1996 Page 2-7
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2.2.2 Correcting for Collection Efficiency
Before gas generation estimates developed from Methods A or B are used to size a
collection/energy recovery system, it is necessary to correct for landfill gas collection
efficiency. There are several factors which affect the overall collection efficiency of a landfill
gas extraction system, which can vary from about 50 to over 90 percent. The permeability of
the landfill's cover layer will determine how much of the landfill gas generated will escape to
the atmosphere; however, a portion of the landfill gas will escape through the cover of even
the most tightly constructed and controlled collection system. Well spacing and depth, which
are determined by economic and other site specific factors, also affect collection efficiency, as
can bottom and side liners, leachate and water level, and meteorological conditions.
Collection systems operated for energy recovery may be more efficient than those
where the collected gas is not put to productive use because each cubic foot of gas will have
a monetary value to the owner/operator. In addition, newer systems may be more efficient
than the average system in operation today. Nevertheless, there continues to be economic
limits on the tightness of well spacing and other factors that are difficult or impossible to
control. Therefore, a reasonable assumption for a newer collection system operated for
energy recovery is 75 to 85 percent collection efficiency.
Multiplying the total landfill gas generation estimated by Methods A or B by 75 to 85
percent should yield a reasonable estimate of the landfill gas available for energy recovery.
Even the results of Method C may have to be corrected for collection efficiency, since the
results of the pump test may not provide an indication of gas flows across the landfill
[Kraemer, 1995].
2.2.3 Comparing Your Gas Flow Rate to Existing Projects
For gas flow estimates to be meaningful, the landfill owner/operator must assess
whether the available gas flow is sufficient to support an energy recovery project. The
average energy recovery facility collects just over 2.5 million cubic feet per day (mmcfd) of
landfill gas. However, the ability of a particular gas flow to support an energy recovery
project is largely a function of the energy purchaser's or user's needs. Existing project sizes
range from 20,000 cfd to over 30 mmcfd, and about one-third of the projects (existing and
planned) use less than 1 mmcfd [Berenyi and Gould, 1994]. Two projects spanning much of
this range are described in Box 2.4. Information on which project configurations are most
cost-effective for a particular gas flow rate is provided in the next section and in Part II of this
handbook.
Part I September 1996 Page 2-8
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Box 2-4 Energy Recovery at Two Very Different Landfills
Puente Hills Landfill
The Puente Hills Landfill in Whittier, CA, receives 12,500 tons of waste per day, and
collects over 30 mmcfd from 400 vertical wells and 50 miles of horizontal collection
piping. The Los Angeles County Sanitation Districts, which operates the landfills, uses
the landfill gas in three ways:
• in a boiler/steam turbine configuration, located at the landfill, to generate almost 50
MW of power;
• as vehicle fuel, in the form of compressed natural gas;
• as fuel for a boiler at Rio Hondo college, located one mile away
Puente Hills is the largest landfill energy recovery power project in the United States.
It has been operational since the early 1980s.
City of Keene. New Hampshire Landfill
The City of Keene is using landfill gas from a 15 acre landfill to power its new
recycling/transfer station. The station, located at the City landfill, requires three-phase
electricity for its process machinery but the local electric utility's nearest three-phase
power line stops several miles away from the site. By instead using gas from the
landfill, the City will save more than $200,000 over the expected life of the landfill gas
project.
A blower pulls the gas from 10 vertical wells, through simple particle and moisture
filters to the (internal combustion) engine-generator set. The recycling/transfer station
equipment runs 24 hours per day but is only heavily used during facility working hours.
The landfill gas-to-energy system provides peak operating loads at about 180 kW, with
the average over a full day at 50 kW. The project was built for a total of $280,000,
including the gas collection system, and is expected to cost approximately $25,000 per
year in operating costs. [Allan McLane, Vermont Energy Recovery]
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3. DETERMINING WHAT PROJECT CONFIGURATION Is RIGHT FOR YOUR
LANDFILL
The Project Development Process
Parti
Preliminary Assessment of
Project Options
Determining if a Project is Right for Your Landfill
I
After estimating the quantity of gas
available for energy conversion, the landfill
owner/operator must decide which
conversion option or options make the most
sense for the landfill (see Flowchart).
Several options may be appropriate. The
best choice will depend upon site-specific
factors, including the characteristics of the
landfill as well as local energy markets.
Section 3.1 describes the basic energy
conversion options and how a landfill
owner/operator can assess which one(s) will
be most cost-effective at his or her landfill.
Section 3.2 compares the major energy
recovery options on a cost basis for three
landfill sizes.
An important consideration in the
evaluation of energy conversion options is
the availability of federal, state, or local
incentives. For example, Section 29 of the
Internal Revenue Service Code provides a
tax credit for sale of landfill gas to an
unrelated party, and the Department of
Energy provides an incentive for publicly
owned landfill gas facilities that generate
electricity. Several states and some
localities also provide incentives to landfill
projects, such as low cost loan programs or
other subsidies. Landfill owner/operators should determine if incentives are available and, if
so, how a project must be structured to take advantage of them. (See Chapter 5 for more
information on incentives).
Part II
Detailed Assessment of
Project Economics
Evaluating Project Economics
Assessing Financing Options
Selecting a Project Development Partner
Winning/Negotiating an Energy Sales Contract
Securing Project Permits and Approvals
Contracting for EPC and O&M Services
3.1 OPTIONS FOR USING LANDFILL GAS
Landfill gas can be converted into useable energy in a number of ways, including use
as a fuel for internal combustion engines or turbines to produce electricity, direct use of the
gas as a boiler fuel, and upgrade to pipeline quality gas, among others. Each of these
options entails three basic components: (1) a gas collection system and backup flare; (2) a
gas treatment system; and, (3) an energy recovery system. This section provides a brief
overview of each component, and outlines the major characteristics of energy recovery
systems that determine their applicability at a given site.
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3.1.1 Collection System and Flare
Typical landfill gas collection systems have three central components: collection
wells; a condensate collection and treatment system; and a compressor. In addition, most
landfills with energy recovery systems will have a flare for the combustion of excess gas and
for use during equipment down times. Each of these components is described below,
followed by a brief discussion of collection system and flare costs. Figure 3.1 illustrates the
design of a typical landfill gas extraction well, and Figure 3.2 shows a sample landfill gas
extraction site plan.
Figure 3-1 Typical Landfill Gas Extraction Well
-VALVE
SPECIAL BACKHU
VARIES
Gas Collection Wells
Gas collection typically begins after a portion of a landfill (called a cell) is closed.
There are two collection system configurations: vertical wells and horizontal trenches.
Vertical wells are by far the most common type of well used for gas collection. Trenches may
be appropriate for deeper landfills, and may be used in areas of active filling. Regardless of
whether wells or trenches are used, each wellhead is connected to lateral piping, which
transports the gas to a main collection header. Ideally, the collection system should be
designed so that the operator can monitor and adjust the gas flow it necessary.
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Figure 3-2 Sample Landfill Gas Extraction Site Plan
Condensate TVap
Gas Extraction Well
-------
Condensate Collection and Treatment
An important part of any gas collection system is the condensate collection and
treatment system. Condensate forms when warm gas from the landfill cools as it travels
through the collection system. If condensate is not removed, it can block the collection
system and disrupt the energy recovery process. Condensate control typically begins in the
field collection system, where sloping pipes and headers are used to allow drainage into
collecting ("knockout") tanks or traps. These systems are typically augmented by post-
collection condensate removal as well. Some of the methods for disposal of condensate are
discharge to the public sewer system, on-site treatment, and recircutation to the landfill. The
best method for a particular landfill will depend upon the characteristics of the condensate
(which may vary depending on site-specific waste constituents), regulatory considerations,
and the cost of treatment and disposal.
B lower/Compressor
A blower is necessary to pull the gas from the collection wells into the collection
header, and a compressor may be required to compress the gas before it can enter the
energy recovery system. The size, type, and number of blowers and compressors needed
depends on the gas flow rate and the desired level of compression, which is typically
determined by the energy conversion equipment.
Flare
A flare is simply a device for igniting and burning the landfill gas. Flares are
considered a component of each energy recovery option because they may be needed
during energy recovery system startup and downtime. In addition, it may be most cost-
effective to gradually increase the size of the energy recovery system and to flare excess gas
between system upgrades (e.g., before addition of another engine). Flare designs include
open (or candle) flares and enclosed flares. Enclosed flares are more expensive but may be
preferable (or required) because they allow for stack testing and can achieve slightly higher
combustion efficiencies. In addition, enclosed flares may reduce noise and light nuisances.
Collection System Costs
Total collection system costs will vary widely, based on a number of site specific
factors. If the landfill is deep, collection costs will tend to be higher due to the fact that well
depths will need to be increased. Collection costs also increase with the number of wells
installed. Table 3-1 presents estimated capital and operating and maintenance costs for
collection systems (including flares) at typical landfills with 1, 5, and 10 million metric tons of
waste in place. For a landfill with 1 million metric tons of waste, collection system and flare
capital costs will likely be approximately $628,000, increasing to about $2.1 million for a 5
million metric ton landfill and $3.6 million for a 10 million metric ton landfill. Annual operation
and maintenance costs for the landfill gas collection system may range from $89,000 for the
typical 1 million metric ton landfill, increasing to $152,000 for the 5 million metric ton landfill
and $218,000 for the 10 million metric ton landfill. [All cost data are in 1994 dollars.]
Flaring costs have been incorporated into the estimated costs of landfill gas collection
systems (which are presented in Table 3.1 and in more detail in Chapter 5), since excess gas
may need to be flared at any time, even if an energy recovery system is installed. Flare
systems typically account for 5 to 15 percent of the capital cost of the entire collection system
Part I September 1996 Page 3-4
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(i.e., including flares). For a typical landfill with 1 million metric tons of waste in place, flare
system capital costs will be approximately $88,000, increasing to about $146,000 for a 5
million metric ton landfill and $205,000 for a 10 million metric ton landfill.1 Note, however,
that flare costs will vary with local air pollution control monitoring requirements and the
owner's own safety requirements. For example, if it is necessary to enclose the flare in a
building for security or climatic reasons, the proceeding cost figures would increase by
approximately $100,000 [Nardelli, 1993].
Annual operation and maintenance costs for flare systems are less than 10 percent of
the total collection system costs, and thus range from approximately $8,000 for a 1 million
metric ton landfill, increasing to $15,000 for a 5 million metric ton landfill and $21,000 for a 10
million metric ton landfill.
Table 3-1 Summary of Representative Collection System Costs* ($1994)
Landfill Size
Waste In Place
1 million metric tons
5 million metric tons
10 million metric tons
Estimated Gas Flow
(mcf/day)
642
2,988
5,266
Capital Costs
($000)
628
2,088
3,599
Annual O&M
Costs ($000)
89
152
218
Collection system costs include flaring costs.
3.1.2 Gas Treatment Systems
After the landfill gas has been collected, and before it can be used in a conversion
process, it must be treated to remove any condensate that is not captured in the knockout
tanks, as well as particulates and other impurities. Treatment requirements depend on the
end use application. Minimal treatment is required for direct use of gas in boilers, while
extensive treatment is necessary to remove C02 for injection into a natural gas pipeline.
Power production applications typically include a series of filters to remove impurities that
could damage engine components and reduce system efficiency.
The cost of gas treatment depends on the gas purity requirements of the end use
application; the cost to filter the gas and remove condensate for power production is
considerably less than the cost to remove carbon dioxide and other constituents for injection
into a natural gas pipeline or for conversion to vehicle fuel. These costs are incorporated into
the energy recovery system costs presented in Section 3.1.3 below.
1 The costs quoted here refer only to the flare system which includes the flare and monitoring
equipment. Other items such as the blower and condensate handling system have been reflected in
collection system costs.
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3.1.3 Energy Recovery System
The goal of a landfill gas-to-energy project is to convert landfill gas into a useful
energy form such as electricity, steam, boiler fuel, vehicle fuel, or pipeline quality gas. There
are several technologies that can be used to maximize the value of landfill gas when
producing these energy forms, the most prevalent of which are:
(1) direct medium-Btu gas use
(2) power production/cogeneration
(3) sale of upgraded pipeline quality gas
The best configuration for a particular landfill will depend upon a number of factors including
the existence of an available energy market, project costs, potential revenue sources, and
many technical considerations. This section focuses on the technical issues that determine a
project's feasibility, and, more specifically, on the technical issues related to direct use and
power production, since these are the most common recovery options. Section 3.2 provides
more information on choosing among the potential energy recovery technologies.
Option 1: Sale of Medium-Btu Gas
The simplest and often most cost-effective use of landfill gas is as a medium-Btu fuel
for boiler or industrial process use (e.g., drying operations, kiln operations, and cement and
asphalt production). In these projects, the gas is piped directly to a nearby customer where it
is used in new or existing combustion equipment as a replacement or supplementary fuel.
Only limited condensate removal and filtration treatment is required, but some modification of
existing equipment may be necessary. There are currently about 30 direct use landfill gas
projects in operation in the United States, and others are under development [Thorneloe,
Pacey, 1994]. Box 3.1 provides specific examples of how landfill gas is being used as a
medium-Btu fuel in some of these projects.
Before landfill gas can be used by a customer, a pipeline must first be constructed to
access the supply. Pipeline construction costs can range from $250,000 to $500,000 per
mile;2 therefore, proximity to the gas customer is critical for this option. Often, a third party
developer is involved in the project who will assume the cost of installing the pipeline.
The customer's gas requirements are also an important consideration when evaluating
a sale of medium-Btu gas. Because there is no economical way to store landfill gas, all gas
that is recovered must be used as available, or it is essentially lost, along with associated
revenue opportunities. Therefore, the ideal gas customer will have a steady, annual gas
demand compatible with the landfill's gas flow. In situations where a landfill's gas flow is not
enough to support the entire needs of a facility, it may still be used to supply a portion of
needs. For example, some facilities have only one piece of equipment (e.g., a main boiler) or
set of burners dedicated to burn landfill gas. They also may have equipment that can use
landfill gas along with other fuels.
Table 3-2 gives the expected annual gas flows on a MMBtu basis from different sized
landfills. While actual gas flows will vary, these numbers may be used as a first step toward
determining the compatibility of customer gas requirements and landfill gas output. A general
2Pipeline construction costs vary due to terrain differences, right-of-way costs, and other site-specific factors.
Part I September 1996 Page 3-6
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Box 3.1 Examples of Direct Use Applications
The City of Industry, CA has found several uses for landfill gas at its
Recreation/Convention Center. Landfill gas is used in boilers to provide hot
water for laundry and space heating for the Convention Center. The medium-
Btu fuel is also used to heat the Center's swimming pool.
The Kentucky-Tennessee Clay Company, located in Aiken County, SC, burns
landfill gas in its rotary dryer to dry kaolin clay before shipment.
Ogden Martin Systems, Inc. operates a waste-to-energy plant in Huntsville, AL
to supply the steam needs of the U.S. Army's Redstone Arsenal. Landfill gas
is used in a supplementary boiler at the waste-to-energy plant to meet the
Arsenal's additional steam needs during peak demand periods [Mahin, 1991].
In Langely, British Columbia, landfill gas is used in a greenhouse to provide
heating and C02for growth enhancement [Thorneloe, Pacey, 1994].
Methane collected from the Acme Landfill in Martinez, CA is used at the
Contra Costa Wastewater Treatment Facility.
rule of thumb to use when comparing boiler fuel requirements to landfill gas output is that
approximately 8,000 to 10,000 pounds per hour of steam can be generated for every 1 million
metric tons of waste in place at a landfill.3 Using this rule of thumb, it can be estimated that
a 5 million metric ton landfill would support the needs of a large facility requiring about 50,000
pounds per hour of steam for process use.
Table 3-2 Landfill Gas Flows Based on Landfill Size
Landfill Size
LFG Output (MMBtu/year)1
Steam Flow Potential (Ibs/hr)
1 MM Mg
100,000
10,000
5 MM Mg
490,000
45,000
10 MM Mg
850,000
85,000
1 Assumes a 90% capacity (i.e., availability) factor
Output figures reflect rounding
If an ideal customer is not accessible, then it may be possible to create a steady gas
demand by serving multiple customers whose gas requirements are complementary. For
example, an asphalt producer's summer gas load could be combined with a municipal
building's winter heating load to create a year-round demand for landfill gas.
This rule of thumb is based on steam delivery at 50 psig, saturated.
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Equipment modifications or adjustments may be necessary to accommodate the lower
Btu value of landfill gas, and the costs of modifications will vary. Costs will be minimal if only
boiler burner retuning is required. However, boiler burner retrofits are typically customized,
and total installation costs can range from $120,000 for a 10,000 Ib/hr boiler to $300,000 for
an 80,000 Ib/hr boiler [Brown, 1995]. As with pipeline construction costs, a third party project
developer may assume the costs of equipment modifications or additions. This was the case
when Natural Power, Inc. paid $600,000 to install a new 26,000 Ib/hr Cleaver-Brooks boiler to
burn landfill gas to serve the steam needs of Ajinomoto USA, Inc., a pharmaceutical plant
[Augenstein, Pacey, 1992].
Operation and maintenance (O&M) costs associated with using landfill gas in boilers,
kilns, dryers, or other industrial equipment are typically equivalent to O&M costs when using
conventional fuels. In general, O&M costs will depend on how well the equipment is
maintained and how well the gas collection system is controlled. Some O&M considerations
when using landfill gas as a medium-Btu fuel are listed in Box 3.2.
Box 3.2 Considerations When Using Landfill Gas as a Medium-Btu Fuel
It is important to consider the unique aspects of collecting and using landfill
gas in equipment such as boilers, kilns, or dryers. Examples of considerations that
can help to ensure optimal equipment performance include:
Moisture content - Landfill gas generally has three to seven percent
moisture when it is collected. Sloped piping and condensate traps
must be used to avoid water blockage in landfill gas piping or blowers
which can be a cause of system interruptions (e.g., water can trip a
gas blower or cause a loss of flame in a boiler).
• Lower flame temperature - Landfill gas has a lower flame temperature
than natural gas, and thus may result in lower superheater
temperatures in boilers. Boilers may therefore require larger
superheaters to accommodate the use of landfill gas.
Lower Btu value - The heating value of landfill gas can be reduced if
collection wells draw in large amounts of air or if breaks in the
collection piping occur. Good design and operating practices can
prevent such problems [Eppich and Cosulich, 1993].
Option 2: Power Generation
The most prevalent use for landfill gas is as a fuel for power generation, with the
electricity sold to a utility and/or a nearby power customer. Power generation is
advantageous because it produces a valuable end product--electricity~from waste gas.
Facilities that use landfill gas to generate electricity can qualify as a "small power producer"
under the Public Utilities Regulatory Policy Act (PURPA), which requires electric utilities to
purchase the output from such facilities at the utility's avoided cost. The electricity can in
some cases be used on-site to displace purchased electricity or be sold to a nearby
electricity user (e.g., municipality, industrial).
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Cogeneration is an alternative to producing electricity only. Cogeneration systems
produce electricity and thermal energy (i.e., steam, hot water) from one fuel source. Whereas
the thermal efficiencies of electricity-only generation range from 20% to 50%, Cogeneration
systems can achieve substantially higher efficiencies by putting to use the "waste" heat that is
a by-product of most power generation cycles. Thermal energy cogenerated by landfill gas
projects can be used on-site for heating, cooling, and/or process needs, or piped to a nearby
industrial or commercial user to provide a second revenue stream to the project.
Several good conversion technologies exist for generating power - internal
combustion engines, combustion turbines, and boiler/steam turbines - each of which is
described below. Box 3.3 highlights important aspects of each option. In the future, other
technologies, such as fuel cells, may also become commercially available. Box 3.4 provides
some discussion on the design considerations when sizing a landfill gas power project.
Internal Combustion Engine
The reciprocating internal combustion (1C) engine is the most commonly used
conversion technology in landfill gas applications; almost 80 percent of all existing landfill gas
projects use them [Thorneloe, 1992]. The reason for such widespread use is their relatively
low cost, high efficiency, and good size match with the gas output of many landfills. In the
past, the general rule of thumb has been that 1C engines have generally been used at sites
where gas quantity is capable of producing 1 to 3 MW [Thorneloe, 1992], or where landfill
gas flows are approximately 625,000 to 2 million cubic feet per day at 450 Btu per cubic foot
[Jansen, 1992].
1C engines are relatively efficient at converting landfill gas into electricity. 1C engines
running on landfill gas are capable of achieving efficiencies in the range of 25 to 35 percent.
Historically, these engines have been about 5 to 15 percent less efficient when using landfill
gas compared with natural gas operation, although the newest engine designs now sacrifice
less than 5 percent efficiency when landfill gas is used [Augenstein, 1995]. Efficiencies
increase further in Cogeneration applications where waste heat is recovered from the engine
cooling system to make hot water, or from the engine exhaust to make low pressure steam.
1C engines adapted for landfill gas applications are available in a range of sizes, and can be
added incrementally as landfill gas generation increases in a landfill.
Environmental permitting may be an issue for some 1C engine projects. 1C engines
typically have higher rates of nitrogen oxide (NOX) emissions than other conversion
technologies, so in some areas it may be difficult to obtain permits for a project using several
1C engines. To address this problem, engine manufacturers are developing engines that
produce less NOX using improved combustion and other air emission control features. These
advances should give plant designers more flexibility to use 1C engines on large projects.
The installed capital costs for landfill gas energy recovery projects using 1C engines
are estimated to range from about $1,100 per net kW output to $1,300 per net kW output
(1996 on-line date). These costs are indicative of power projects at landfills ranging in size
from 1 million metric tons to 10 million metric tons of waste in place, and the costs include
the engine, auxiliary equipment, interconnections, gas compressor, construction, engineering,
'h'he most commonly used 1C engines for landfill gas applications are rated at about 800 and 3,000 kW.
Part I September 1996 Page 3-9
-------
Box 3.3 Comparison of Electricity Generation Technologies
Typical Project Size
(MW)
Landfill Gas
Requirements
(mcf/day)
Typical Capital
Costs
($/kW)
Typical O&M Costs
(0/kWh)
Electric Efficiency
(%)
Cogeneration
Potential
Compression
Requirements
(Input Gas
Pressure (psig))
Advantages
Disadvantages
*
All costs reflect a 1 996
1C Engines
* 1
^625
1,100-1,300
1.8
25-35
Low
Low
(2 - 35)
• Low cost
• High efficiency
• Most common
technology
• Problems due to
particulate
matter buildup
• Corrosion of
engine parts
and catalysts
• High NOX
emissions
on-line date.
Combustion
Turbines
> 3
> 2,000
1 ,200 - 1 ,700
1.3-1.6
20 - 28 (CT)
26 - 40 (CCCT)
Medium
High
(165+)
• Corrosion
resistant
• Low O&M costs
• Small physical
size
• Low NOX
emissions
• Inefficient at part
load
• High parasitic
loads, due to
high gas
compression
requirements
Steam
Turbine/Boiler
> 8
> 5,000
2,000 - 2,500
1 .0 - 2.0
20-31
High
Low
(2-5)
• Corrosion
resistant
• Can handle gas
composition and
flow variations
• Inefficient at
smaller sizes
• Requires large
amounts of
clean water
• High capital
costs
Part I
September 1996
Page 3-10
-------
Box 3.4 Design Considerations When Sizing Power Projects
Determining the optimum size for a landfill gas power project requires a careful balance between
maximizing electricity production and landfill gas use, and minimizing the risk of insufficient gas supplies in
later years. The challenge arises because landfill gas production rates change over time. Gas generation
may be increasing at an open landfill or decreasing at a closed landfill. System designers must also
consider factors such as current and future electricity payments, equipment costs, and any penalties for
shortfalls in electricity output.
The optimum design and operating scenario for a particular landfill gas project is likely to fall
somewhere between two general scenarios: (1) minimum gas flow design; and (2) maximum gas flow
design. However, a third design scenario-a modular approach-may be used at landfills where gas flow
rates are expected to change substantially over time.
(1) Minimum Gas Flow Design. In this scenario, the electric generation equipment is sized based
on the minimum expected gas flows over the life of the project. This ensures that the fuel supply (i.e.,
landfill gas) is seldom or never limited, and the electric generation system always runs at or near its
maximum availability. This is a more conservative design, which puts a premium on constant and reliable
electrical output over the project life. The disadvantage of this design is that some landfill gas will go
unused in years when gas is plentiful; a lost opportunity to generate electricity and earn revenues. This may
be a good design choice when project economics are robust and substantial contract penalties exist for
shortfalls in electrical deliveries from the project. Capacity factors for this type of project are determined
mainly by the generating equipment outage rates, which are approximately 6% to 10% for 1C engine systems
and 4% to 6% for combustion turbine-based systems.
(2) Maximum Gas Flow Design. In this scenario, the electric generating equipment is sized based
on maximum gas flows over the life of the project. Landfill gas usage and electrical output are generally
maximized, but there may be occasions when there is insufficient landfill gas supply to run the generating
equipment at its rated capacity. This is a more aggressive design which puts a premium on full utilization of
the landfill gas, and it has the advantage of higher electrical generating capacity, revenues, and landfill gas
utilization than the first scenario. However, the disadvantages are that the project may suffer from periods
when electrical output is below the rated capacity because of intermittent gas supply shortages or declining
landfill production. This is an acceptable design if maximizing early-year revenues is critical, the power
purchase contract is short-term, shortfall penalties are nonexistent, and/or alternate or augmented fuel
supplies exist. Capacity factors for this type of project are determined by generating equipment outage
rates and expected periods when fuel supply is limited. Part-load generating efficiency is a consideration in
this type of project; 1C engines and fuel cells generally exhibit better part-load performance (e.g., efficiency,
wear) than CT-based systems.
(3) Changing Gas Flow Design. In this scenario, a series of smaller electric generating units is
installed (or removed) over time as gas flow rate increases (or decreases). This modular approach helps
ensure that landfill gas output is properly matched to equipment size, even when gas flow rates change.
This approach has the dual benefit of maximizing gas use and electric output over time. However, a
modular approach may also produce higher installation costs and lower efficiencies than other approaches.
If gas flow is decreasing over time, designers must consider what to do with units that are no longer useful.
and soft costs. (Chapter 5 provides more detail on technology costs.) The costs associated
with the landfill gas collection system are not included in these cost estimates.
Combustion Turbine
Combustion turbines (CTs) are typically used in medium to large landfill gas projects,
where landfill gas volumes are sufficient to generate a minimum of 3 to 4 MW (i.e., where gas
flows exceed approximately 2 million cfd). This technology is competitive in larger landfill gas
Part I September 1996 Page 3-11
-------
electric generation projects because, unlike most 1C engine systems, CT systems have
significant economies of scale. The cost per kW of generating capacity drops as CT size
increases, and the electric generation efficiency generally improves as well.
Simple-cycle CTs applicable to landfill gas projects typically achieve efficiencies of 20
to 28 percent at full load; however, these efficiencies drop substantially when the unit is
running at partial load. Combined-cycle configurations, which recover the waste heat in the
CT exhaust to make additional electricity, can boost the system efficiency up to approximately
40 percent, but this configuration is also less efficient at partial load [EPA, 1993]. One of the
primary disadvantages of CTs is that they require high gas compression (165 pounds per
square inch (psig) or greater), causing high parasitic load loss. This means that more of the
plant's power is required to run the compression system, as compared to other generator
options [WMNA, 1992]. An advantage is that turbines are much more resistant to corrosion
damage than 1C engines and have lower NOX emission rates. In addition, combustion
turbines are relatively compact and have low operations and maintenance costs in
comparison to 1C engines.
The installed capital costs for landfill gas energy recovery projects using simple cycle
CTs are estimated to range from about $1,200 per net kW output to $1,700 per net kW output
(1996 on-line date), for power projects at landfills ranging in size from 1 million metric tons to
10 million metric tons of waste in place, respectively. The costs include the CT, auxiliary
equipment, interconnections, gas compressor, construction, engineering, and soft costs.
(Chapter 5 provides more detail on technology costs.) The costs associated with the landfill
gas collection system are not included in these cost estimates. For combined-cycle systems
installed at landfills ranging in size from 5 million metric tons to 10 million metric tons of waste
in place, the installed capital costs range from about $1,400 per net kW output to $1,700 per
net kW output (1996 on-line date). A combined-cycle system is not likely to be economically
competitive at landfills with less than about 5 million metric tons of waste in place.
Boiler/Steam Turbine
The boiler/steam turbine configuration is the least used of the three landfill gas power
conversion technologies. It is applicable mainly in very large landfill gas projects, where gas
flows support systems of at least 8 to 9 MW (i.e., where gas flows are greater than 5 mmcfd)
[EPA, 1993]. The boiler/steam turbine consists of a conventional gas/liquid fuel boiler, usually
a packaged unit, and a steam turbine generator that produces electricity. This technology
usually requires a complete water treatment and cooling cycle, plus an ample source of
process and cooling water. Boiler/steam turbine systems have a significantly higher cost per
kW than either 1C engines or CT systems, so only the largest landfill gas projects can afford
to use this technology.
Fuel Cell
Fuel cells that run on landfill gas show great promise for power generation because of
their modularity, small capacity, high efficiency, quiet operation, and low environmental
impact. It is for these reasons that fuel cells may be an ideal technology for generating
power from landfill gas, once they have been fully demonstrated. While a few fuel cells
running on natural gas are in commercial operation, fuel cells capable of using landfill gas are
still in the development/demonstration phase. The biggest hurdle has been development of a
feasible system for cleaning landfill gas prior to use in the fuel cell.
Part I Septemoer 1996 Page 3-12
-------
Fuel cells create energy by combining hydrogen (obtained from a fuel source such as
landfill gas) and oxygen (supplied from the air) in at electrochemical reaction. Electricity is
produced continuously, as long as there is a supply of fuel and air, at high efficiencies (e.g.,
50 percent or more). There are three types of fuel cells suitable for power generation:
phosphoric acid fuel cells; molten carbonate fuel cells; and solid oxide fuel cells. Phosphoric
acid fuel cells (PARC), which use hydrogen gas or reformed methanol as fuel sources, are the
closest to commercialization for a landfill gas application. A 200-kW PAFC plant has been
tested by the EPA at the Penrose Landfill in Sun Valley, California [Swanekamp, 1995].5
Northeast Utilities installed the test unit at the Flanders Road Landfill in Groton, Connecticut in
late 1995, and operation at the site began in June, 1996. Connecticut Light & Power, a
subsidiary of Northeast Utilities, is operating and maintaining the test unit, and using 140 kW
of the power it produces. In addition, the Department of Energy is working to demonstrate
molten carbonate fuel cell technology for landfill gas applications.
Option 3: Upgrade to High-Btu Gas
A third project option is to upgrade the landfill gas to a high-Btu product for injection
into a natural gas pipeline. Because of the relatively high capital cost of this option, it may be
cost-effective only for those landfills with substantial recoverable gas (i.e., at least 4 million cfd
[Maxwell, 1990]). This application requires relatively extensive treatment of the gas to remove
CO2 and Impurities. In addition, gas companies require that gas injections into their pipeline
systems conform with strict quality specifications, which can impose additional quality control
and compression requirements. However, this may be an attractive option for some landfill
owners, since it is possible to utilize all gas that is recovered.
Upgraded gas will require significant compression in order to conform with the pipeline
pressure at the interconnect point. High pressure lines may require pressures of as much as
300 to 500 pounds per square inch (psig), while low and medium-pressure lines may require
10 to 30 psig.
Option 4: Alternative Uses
Other landfill gas utilization options include on-site use of the gas (which may be
particularly appropriate for small landfills), heating greenhouses, producing carbon dioxide
and other niche applications, or use as vehicle fuel, such as compressed natural gas and
methanol. On-site and niche applications are in limited use. Vehicle fuel uses are currently in
the commercialization phase, with only a few projects in place (Box 3.5 highlights two of
these projects). These and other emerging applications must be evaluated on a case-by-
case basis. Their likelihood of success at a particular landfill depends on site-specific factors
such as the needs of the landfill, its size, and the quality of the gas. Regulatory
developments, the goals of the owner/operator (e.g., an alternative, low emissions fuel source
may be attractive for a municipality's fleet), and the needs of potential customers are also
important. Because these applications are not fully commercial, they are not discussed
extensively in this handbook.
5 In July, 1996, Ron Spiegel of EPA's Office of Research and Development, was named a finalist for the 1996
Discover Magazine awards for his work in applying fuel cell technology to landfill gas.
Part I September 1996 Page 3-13
-------
Box 3.5 Landfill Gas as a Vehicle Fuel
CNG Application
The Los Angeles County Sanitation District's Puente Hills Landfill has
succeeded in turning landfill gas into a clean vehicle fuel. The Sanitation District has
installed a compressed landfill gas fueling station on-stte and has converted a Sierra
pickup truck, a Hercules water truck and the first of four garbage trucks to run on the
compressed gas. This project has eliminated the need to flare excess gas from the
landfill, and has reduced vehicle emissions at the same time.
Methanol Production
Using $500,000 in funding from the South Coast Air Quality Management
District of California, TeraMeth Industries, Inc. modified its proprietary technology to
produce Grade A methanol from landfill gas. Methanol (the critical ingredient in
MTBE for federal and state reformulated gasoline requirements) is produced by first
creating a synthesis gas which is then fed into a catalyst.
TeraMeth's California facility will produce 16,667 gallons per day of methanol
when it begins operation in 1997 [Bonny, 1996].
3.2 CHOOSING AN ENERGY RECOVERY OPTION
The primary factor in choosing the right project configuration for a given landfill is the
cost of the energy recovered. In general, sale of medium-Btu gas to a nearby customer,
which requires minimal gas processing and typically is tied to a retail gas rate rather than an
electric utility buyback rate, is the simplest and most cost-effective option. If a suitable
customer is nearby and willing to purchase the gas, this option should be thoroughly
examined. For many landfills, however, power production is and will continue to be the best
available option. This section therefore focuses on the power production options.
At the foundation of any cost estimation is the expected amount of landfill gas that will
be available for energy recovery. For initial assessments, an estimate of landfill gas quantity
is all that is needed to estimate power potential. Assumptions regarding the Btu value of the
gas, the efficiency of the generator, and the amount of downtime can then be used to convert
the gas volume into power potential, as shown in Box 3.6.
This section compares the power production options on a unit cost basis for typical
landfills with 1, 5, and 10 million tons of waste in place.6 In addition to the landfill size and
its associated gas production, a number of other factors are also important to project costs.
These include: project scope (i.e., whether both a collection system and an energy recovery
amount of landfill gas associated with these landfill sizes was estimated using an EPA model that falls
within the range of methods A and B presented in Chapter 2.
Part I September 1996 Page 3-14
-------
Box 3.6 Converting Gas Flow Rates into Power Potential
1) Estimate the Gross Power Generation Potential. This is the installed power
generation capacity that the gas flow can support. It does not account for parasitic
loads from auxiliary systems and equipment, or for system down time. Gross Power
Generation Potential is estimated using the following formula:
kW = Landfill Gas Flow (cf/d) x Energy Content (Btu/cf) x 1/Heat Rate
(kWh/Btu) x 1d/24hr
where:
• Landfill Gas Flow is the net quantity of landfill gas per day that is
captured by the collection system, processed, and delivered to the power
generation equipment (usually 75% to 85% of the total gas produced in
the landfill)
• Energy Content of landfill gas is approximately 500 Btu per cubic foot
Example Heat Rates are:
12,000 Btu/kWh for 1C Engines and combustion turbines (above 5 MW);
and
8,500 Btu/kWh for combined-cycle combustion turbines.
2) Estimate the Net Power Generation Potential. This is the Gross Power Generation
Potential less parasitic loads from compressors and other auxiliary equipment. Parasitic
loads are estimated to range from 2% for 1C engines to 6% or higher for combustion
turbines.
3) Estimate the Annual Capacity Factor. This is the share of hours in a year that the
power generating equipment is producing electricity at its rated capacity. Typical
Annual Capacity Factors for landfill gas projects range between 80% and 95% and are
based upon generator outage rates (4% to 10% of annual hours), landfill gas
availability, and plant design. The assumed Annual Capacity Factor in the equation
found in 4) is 90%. (See Table 3-2).
4) Estimate the Annual Electricity Generated. This is the amount of electricity
generated per year, measured in kWh, taking into account likely energy recovery
equipment downtime. It is calculated by multiplying the Net Power Generation Potential
by the number of operational hours in a year. Annual operational hours are estimated
as the number of hours in a year multiplied by the Annual Capacity Factor. Thus:
Annual Electricity Generated (kWh) = Net Power Generation Potential (kW) x 24
hr/day x 365 days/yr x 90%
Parti September 1996 Page 3-15
-------
system are required or only an energy recovery system); financing method; and available
incentives to encourage landfill gas energy recovery. Each of these factors is discussed
briefly below.
• Project Scope: Project scope depends upon the extent of landfill gas collection
activities already underway (or planned) at the landfill, and it can have a significant
impact on project costs. There are two typical landfill project scopes:
• Total Project: refers to those projects at landfills with no current gas collection
or energy recovery. For these projects, the entire project (including both gas
collection and energy recovery systems) must be installed and the full costs
must be recovered through the revenues from energy sales; and
• Energy Recovery Project: refers to projects at landfills where gas collection
systems have already been (or will soon be) installed. At these landfills, the
costs associated with the collection system are sunk costs, and the only costs
that need to be taken into consideration for the economic analysis are those
associated with the additional equipment (i.e., the energy conversion system).
Financing Method: As discussed in Chapter 6, there are many different financing
methods available for landfill projects. The most common financing methods are
private equity financing, "project finance" using a combination of debt and equity, and
municipal bond finance, where public organizations issue bonds to raise project debt.
The choice of financing method can have a significant impact on project costs; in
general, municipal bond financing is much less expensive than financing with
commercial debt and/or equity.
• Available Incentives: Because of the importance of encouraging landfill gas energy
recovery, a number of federal, state and local incentives are available to these
projects. The most important incentives are likely to be the IRS Section 29 tax credit,
which may be available to private project developers, and the Department of Energy's
Renewable Energy Production Incentive (REP!), which is available to public project
developers. Both of these incentives can significantly improve project economics.
The Section 29 tax credit is currently worth about 00.9 to 01.3/kWh, depending upon
the efficiency of the generating equipment. The REPI is worth up to 01.5/kWh.
The cost per kilowatt hour for each power generation option - 1C engine, combustion
turbine, or steam turbine - will vary with the size of the landfill and these other factors, as
shown in Table 3-3. Table 3-3 can be used to estimate the likely costs of a power generation
project in the following way:
1. Determine whether it will be necessary to install both a gas collection system
and an energy recovery system at the landfill, or only an energy recovery
system. If both systems are required, examine the 'Total Project" entries; if
only an energy system is required, examine the "Energy Recovery Project Only"
entries.
2. Determine whether municipal or private financing will be used. If the landfill is
owned by a municipality, it is possible that municipal bonds can be issued to
cover costs; otherwise, private financing will likely be required.
Parti September 1996 Page 3-16
-------
3. Determine whether financial incentives may be available. If the project will be
developed by a private developer and the gas sold to a third-party, Section 29
tax credits may be available. Public or non-profit landfill owners or developers,
in contrast, may be eligible for the REPI program.
4. Determine the likely project size based on the amount of waste in place at the
landfill.
Making these four decisions will enable a landfill owner/operator to determine likely power
production costs for a range of generating technologies. In many cases, the lowest cost
generating option will be selected. In some cases, however, it may be necessary to select a
higher cost option due to other important considerations. 1C engines may not be the best
technology choice in certain areas, for example, due to their higher NOx emissions as
compared to turbines.
As Table 3-3 illustrates, the estimated costs of power production can vary substantially
depending on the factors presented above. At the high end, costs for a 'Total Project'
financed with private finance and unable to obtain any incentives could range from 07.4 to
07.9 per kWh for a 1 million ton landfill. The availability of municipal financing could reduce
these costs by about 00.8 per kWh and developing an ""Energy Recovery System Only""
project could save approximately 02.5 per kWh. The lowest cost scenario-an ""Energy
Recovery System Only"" project built with municipal financing and obtaining available
incentives-has estimated costs ranging from 02.8 to 04.0 per kWh, which is less than half of
the high cost case.
The same phenomenon is observed at the larger 5 and 10 million ton landfills. On the
high end, 'Total Project" costs at a 5 million ton landfill are estimated to range from 06.0 to
06.5 per kWh. This same project, implemented with municipal financing and available
incentives, however, could cost only 04.0 to 04.3 per kWh. If the landfill already has (or plans
to install) a gas collection system, the "Energy Recovery System Only" costs could be as low
as 02.7 per kWh.
At the 10 million ton landfill, high end Total Project" costs of 05.6 to 05.9 per kWh
drop to 02.3 to 02.9 per kWh for an "Energy Recovery System Only" project with municipal
bond financing and incentives. Interestingly, at this size the CT is more cost-effective than 1C
engine. In addition, the effects of economies of scale are evident, as the costs of similar
projects at a 10 million ton landfill are an average of 20 to 30 percent lower than the 1 million
ton landfill and 5 to 15 percent lower than the 5 million ton landfill.
It is important to recognize that the cost estimates presented here are rough estimates
developed using assumptions related to "typical" landfills. Conditions at any particular site
could be quite different and these site-specific conditions must be fully accounted for when
developing detailed cost estimates for specific projects.
Part II of this handbook discusses in more detail the major steps involved in the
development of a landfill gas energy recovery project, from estimating expenses and revenues
to constructing and operating the project. In addition, EPA is developing a simple financial
model that landfill owner/operators and others can use to estimate project costs and run
sensitivity analyses. To obtain a copy of this model when it becomes available, call the EPA
Landfill Methane Outreach Program Hotline at 1-888-STAR-YES.
Part I September 1996 Page 3-17
-------
Table 3-3 Estimated 1996 Costs of Electricity
TW«*PtOj«c*
1 Million
5 Million
10 Million
1C Engine
Municipal
Financing
6.7
5.5
5.2
Private
Financing
7.4
6.0
5.8
Combustion Turbine
Municipal
Financing
*
7.0
5.6
5.0
Private
Financing
Combined Cycle CT
Municipal
Financing
s,,.
7.9
6.2
5.6
NA
5.8
5.3
Private
Financing
, - /,/
NA
6.5
5.9
ToWFte}tt<3«^ttfittfl^Ftrt^^ • " '•• :;-:'; ' i
1 Million
5 Million
10 Million
5.2
4.0
3.7
6.1
4.7
4.5
5.5
4.1
3.5
6.6
4.9
4.3
NA
4.3
3.8
NA
5.6
5.0
&^ Recovery Sy»^<^w^RH.^ - ' '
1 Million
5 Million
10 Million
4.3
4.2
4.1
4.8
4.6
4.5
4.7
4.2
3.8
5.3
4.7
4.2
N.A.
4.7
4.3
N.A.
5.3
4.8
a^ayRec^ve^Sy^mOnJyw^Ftaa^lnc^fltiv^^/Wh)
1 Million
5 Million
10 Million
2.8
2.7
2.6
3.5
3.3
3.2
3.2
2.7
2.3
4.0
3.4
2.9
NA
3.4
2.9
NA
4.4
3.9
NA: Technology was not evaluated at this landfill size.
The municipal finance scenarios were calculated using a capital charge rate of 0.1 1 1 , which is based on financing with
tax-exempt municipal bonds at an interest rate of 6.5%.
The incentive under the municipal finance plan scenario is the proposed federal REPI subsidy of 1 .5 cents/kwh.
The private finance scenarios were calculated using a capital charge rate of 0.136. which is based on a project finance
structure using: 80% debt, 20% equity; 9% interest in debt; 15% return on equity; 10 year depreciation.
Incentives under the project finance scenarios are IRS Section 29 Tax Credits, which are estimated to be worth their full
value of $0.979/MMBtu in 1994, or 0.9 to 1 .3 cents/kwh in 1996. In some cases, only a percentage of the tax credit
value can be applied to a project rf the credits are transferred between parties. For example, if 60% of the tax credit
value can be applied to the project, then 1996 electricity costs would increase by 0.4 to 0.5 cents/kwh.
All scenarios include a royalty payment of 0.5 cents/kwh.
Part
September 1996
Page 3-18
-------
PART II
DETAILED ASSESSMENT OF PROJECT ECONOMICS
The Project Development Process
Parti
Preliminary Assessment of
Project Options
Determining if a Project is Right for Your Landfill
Determining What Project Configuration is Right
for Your Landfill
II
Evaluating Project Economics
Assessing Financing Options
Selecting a Project Development Partner
Winning/Negotiating an Energy Sales Contract
Securing Project Permits and Approvals
Contracting for EPC and O&M Services
-------
Page Intentionally Left Blank
-------
4. INTRODUCTION To PART II: DETAILED ASSESSMENT OF PROJECT OPTIONS
Once the landfill owner/operator has determined that an energy recovery project is
right for a particular landfill, and has made a preliminary assessment of the project options,
he or she must conduct a more detailed assessment of the options, considering cost,
financing, project structure, and other aspects of project development. This section contains
information on each step in the assessment of project options, organized into the following
chapters:
Chapter 5: Evaluating Project Economics
Chapter 6: Assessing Financing Options
Chapter 7: Selecting a Project Development Partner
Chapter 8: Winning/Negotiating an Energy Sates Contract
Chapter 9: Obtaining Project Permits and Approvals
Chapter 10: Contracting for EPC and O&M Services
Each chapter contains the basic information—illustrated throughout with examples-
- needed to conduct one step in the project assessment process. By reviewing each chapter
with a particular landfill in mind, an owner/operator can develop a solid understanding of the
most cost-effective and appropriate options and project structure.
While this handbook provides valuable information to assist the owner/operator in
evaluating choices and proposals, it does not serve as a technical guide to project
development. The owner/operator may wish to consult a landfill gas energy recovery expert
before beginning the development process.
Part II September 1996 Page 4-1
-------
Page Intentionally Left Blank
-------
5. EVALUATING PROJECT ECONOMICS
After the available quantity of landfill
gas has been estimated and a preliminary
assessment of project options has been
completed, the next step in developing a
landfill gas energy recovery project is a
detailed economic assessment of converting
landfill gas into a marketable energy
product. The economics of a landfill gas-to-
energy project depend on a number of
factors, including landfill gas quantity, local
energy prices, and equipment choice. This
chapter presents a methodology for
evaluating project economics, and shows
sample economic evaluations for the
principal energy recovery options. Once
economic feasibility has been determined,
the cost and financial performance data
from the economic analysis can be carried
forward to the assessment of financing
options, partner selection, and negotiation
of energy sales and equipment contracts,
which are discussed in subsequent
chapters.
The Project Development Process
Parti
Preliminary Assessment of
Project Options
Determining if a Project is Right for Your
Landfill
Determining What Project Configuration is
Right for Your Landfill
I
Part II
Detailed Assessment of
Project Economics
Assessing Financing Options
Selecting a Project Development Partner
Winning/Negotiating an Energy Sales Contract
Securing Project Permits and Approvals
Contracting for EPC and O&M Services
5.1 ECONOMIC EVALUATION PROCESS
An economic evaluation of a
potential energy recovery project involves
comparing the expenses of a particular
project with the revenues that it is likely to
receive. Figure 5.1 outlines the basic steps
of the economic evaluation of energy
recovery projects, and these steps are described in more detail below.
Step 1. Estimate Energy Sales Revenues - Energy sales revenues include any
cash that flows to the project from sales of electricity, steam, gas, or other
derived products. Potential markets for energy products include electric
utilities, municipal utilities, industrial plants, commercial or public facilities, and
fuel companies. Revenues to the landfill gas energy recovery project are
usually calculated based on the estimated quantity of energy delivered and the
contract prices paid by the customer.
Step 2. Quantify Capital and O&M Expenses - This step involves quantifying
the capital costs and operation and maintenance (O&M) costs, plus in some
cases landfill gas royalties and/or fees. Capital costs include not only the initial
cost of the equipment, but also installation costs, debt service, owner's costs,
Part II
September 1996
Page 5-1
-------
Figure 5-1 The Economic Evaluation Process
Stepl:
Estimate Energy |^_
Sales Revenues
1
Step 2:
Quantify Capital and
O&M Expenses
Step 3:
Compare Project
Expenses and
Revenues
1st
Year
Revenues and
Expenses
Comparable
No
Consider Changing
Design to Improve
Economics
Yes
Step 4:
Create a Pro
Forma Model
Step 5:
Assess Economic
Feasibility
Is
the
Project
Economically
Feasible
No
Modify Project
Assumptions or
Future Reevaluation
Y3S
Repeat for Other
Options and Select
Economic Winner(s)
Part
September 1996
Page 5-2
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and returns on equity. Many of these costs vary with site-specific
characteristics of the landfill.
• Step 3. Compare Project Expenses and Revenues - Once the estimates of the
project's expenses and revenues have been made, an initial assessment of
project economics can be made by checking to see if the first-year expenses
and revenues are roughly equivalent. If they are comparable in the first year of
project operation, then further economic evaluation is warranted. If not, it is
usually necessary to re-examine technology, design, cost assumptions, and/or
energy revenue assumptions to find ways to improve the economics.
• Step 4. Create a Pro Forma Model of Cash Flows - For a more accurate
estimate of the probable lifetime economic performance of a project, the
expenses and revenues should be calculated and compared on a year-by-year
basis over the expected life of the project. This in-depth economic analysis,
known as a pro forma, typically includes detailed calculations of project
performance over time, escalation in project expenses and energy prices,
financing costs, and tax considerations (e.g., depreciation, income tax).
• Step 5. Assess Economic Feasibility - Based on the pro forma model, the
project economic feasibility can be assessed by calculating annual net cash
flows, the net present value of future cash flows, and/or the owner's rate of
return. These measures of financial performance are calculated over the life of
the project and are the most reliable measures of economic performance. If
these indicators are below the project proponent's criteria, he or she should re-
examine the project for assumptions and/or options that can be modified.
If a landfill owner/operator has the opportunity to produce and sell more than one type
of energy product, then the net cash flows of each option should be compared head-to-head
to determine the best option. Cash flows of competing projects can be compared on an
annual, net present value, and/or rate of return basis. After selecting an economic winner, the
landfill owner/operator should then consider non-price factors including risks, ability to obtain
financial backing, environmental performance, and reliability of assumptions. The option that
produces the best financial performance while meeting the desired environmental, risk, and
operating requirements is the overall winner.
The remainder of this chapter discusses the process of conducting a step-by-step
economic analysis for the various landfill gas energy recovery options. The economic
analyses presented in this chapter provide the landfill owner/operator with basic estimates of
project costs and market prices for energy products. The landfill owner/operator can use the
concepts presented to create his or her own economic analysis.
Example Landfill
Throughout this chapter, the key aspects of the economic evaluation process are
illustrated with examples. These examples are based on a hypothetical landfill with 5 million
metric tons of waste in place and a net sustainable landfill gas production level of 2,988
mcf/day. Box 5.1 presents the operating and cost assumptions that are used consistently in
this chapter.
Part II September 1996 Page 5-3
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Appendix A contains the supporting performance and cost calculations for the 5
million metric ton example, and for two other landfill sizes-1 million metric tons and 10 million
metric tons. Appendix A also contains sample cost calculations for a medium-Btu gas sales
project.
5.2 POWER GENERATION/COGENERATION
The opportunity to collect landfill gas and burn it to produce electric power is available
to most landfill owners. Whether or not this option is economically feasible depends largely
on local electricity prices, which vary dramatically across regions of the country. Other
important factors include access to electricity purchasers, landfill gas volume, and technology
selection. This section presents a sample economic analysis - using the five steps outlined
above - for a landfill gas power generation project.
5.2.1 Step 1: Estimates Energy Sales Revenues
A landfill gas power project can have one or more sources of revenue, depending on
whether it produces just electricity or also cogenerates steam and/or other thermal energy.
An important potential source of revenue is use of a portion of the landfill gas or the derived
electricity or steam to offset energy costs (e.g., natural gas, oil, electricity) at its own facilities.
The savings that are achieved by offsetting energy purchases can be counted as a type of
revenue. The following paragraphs describe the principal sources of revenue for power
projects.
Electric Buyback Rate
The economic factor that will usually have the greatest impact on a power project's
economic feasibility is the local electric utility's buyback rate (i.e., the price the utility is willing
to pay for the electricity produced by a non-utility electric generator). The buyback rate
reflects the utility's own avoided costs of generating electricity, incorporating the cost of
building new generating capacity if needed. The costs of generating electricity, and thus
buyback rates, vary considerably among utilities and regions. Factors such as fuel mix,
availability of cheap hydropower, utility financial health, and reserve margins have a large
influence over local electricity costs and the rate (i.e., price) at which electric utilities will buy
electricity from a landfill gas project.
U.S. electric utilities are currently required by the Public Utility Regulatory Policies Act
(PURPA) to buy electricity from qualifying facilities, which include small power producers and
cogenerators. Small power producers are defined as electric generating facilities that
produce up to 80 MW and use mostly non-fossil fuels. Landfill gas energy recovery facilities
are eligible to be classified under PURPA as small power producers. PURPA dictates that
electric utilities must buy electricity at a rate no higher than the utility's "avoided cost,1" which
is the cost that the utility would pay to generate the next increment of electricity using its own
resources.
Avoided costs are typically filed with the state utility regulators on a regular basis, and
some utilities publish buyback tariffs, accompanied by standard offer contracts, based on
their avoided cost. (More information on standard offer contracts is provided in Chapter 8.)
Utility buyback tariffs regularly include an avoided energy price, and some utilities also pay an
additional component for their avoided capacity costs. The energy price component is based
Part II September 1996 Page 5-4
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Box 5.1 Assumptions for 5 Million Metric Ton Landfill Example
Operating Assumptions
Waste in place: 5 million metric tons
Collection efficiency: 85%
Net sustainable LFG production: 2,988 mcf/day
LFG calculation method: EPA Report to Congress Equation [EPA]
Electric output calculation: kw = (cf/hr) x (500 Btu/cf) / (Btu/kwh)
Electric heat rate (Btu/kwh): 12,000 for 1C engine & CT
8,500 for combined cycle CT
Online date: June, 1996
Annual capacity factor: 80%
Annual full load operating hours: 7,008
Capital Cost Assumptions
Energy conversion system cost includes engine/generator, auxiliary equipment,
interconnections, gas compressor, and construction costs.
LFG collection system includes collection wells, blower, and flare system.
Engineering costs = 5% of installed equipment costs.
Soft costs include owners' costs (e.g., legal, permitting, insurance, taxes),
escalation during construction, interest during construction, and contingency.
Incremental Capital Requirement = Total Costs - LFG Collection System Costs.
Cost of Electricity
Cost of Electricity = Capital component + O&M component + Royalty
Capital Charge Rate assumptions:
Project Finance Case Muni Finance Case
20 year project life • 20 year project life
80% debt, 20% equity • 100% tax-exempt bonds
• 9% interest on debt • 6.5% interest on debt
15% return on equity • No income tax
• 10-year depreciation
Royalty/gas payment estimated at 0.5 c/kWh (about 10% of project revenues).
Part II September 1996 Page 5-5
-------
on the utility's fuel costs and operation and maintenance costs, which may vary depending
on the time of day or year. The capacity price component is usually fixed, based on the
utility's cost of building or buying additional capacity. Only utilities that actually
need additional generating capacity will typically offer a capacity price component.
The avoided energy price component alone may not be enough to support a landfill
gas power project. In these cases, landfill gas power project developers must seek electric
utility customers that need additional capacity and are offering a capacity price component as
well. Some utilities might offer a premium for renewable energy or environmentally beneficial
projects such as landfill gas energy recovery. In some cases the utility's published tariff will
be acceptable, but more often the project developer must attempt to negotiate a more
favorable rate. (Chapter 8 discusses the different avenues to obtaining power sales
contracts.)
In addition to possible sales to an electric utility, state regulators may allow direct
electricity sales to one or more local customers. These sales are usually conditioned on the
fact that they are limited to a number of contiguous neighbors. If such sales are allowed, the
landfill gas power project must negotiate a rate with the customer. It is usually necessary to
offer the customer an electricity rate that provides a discount over the rate currently paid to
the local utility, unless the project is offering something that the local utility does not, such as
higher reliability. Since retail electric rates are typically higher than the buyback rates offered,
this type of arrangement can be very attractive to the seller and the buyer.
Historically, landfill gas power projects have received electric buyback rates ranging
from 02/kWh to 010/kWh, averaging about 06/kWh. However, newer projects generally report
receiving only 03/kWh to 04/kWh [EPA, 1993]. The chief reasons for lower rates in recent
years are a slowdown in the rate of electric demand growth, and an abundance of generating
capacity in some parts of the country (e.g., Southwest, New England). Generally, significant
economic potential for landfill gas power projects exists where electric buyback rates are
above 04/kWh, although technology improvements, emerging applications, and requirements
to recover landfill gas for environmental reasons are increasingly making projects viable at
rates below 04/kWh [EPA, 1993].
Displacement of On-Srte Energy Purchases
It may be practical to use a portion of the generated electricity to displace some or all
of the electricity purchases at commonly-owned facilities near the project site. For example,
for a county-owned landfill, opportunities for displacement savings may include energy use at
county office buildings, maintenance shops, water treatment plants, community centers, and
correctional facilities. Displacement savings are calculated by determining the amount of on-
site electricity usage that can be met by the energy project, then determining the cost of that
electricity usage, based on the current retail rates or recent electric bills. The retail rates paid
by the landfill owner/operator to the utility are typically higher than the buyback rate offered
by the utility to purchase the power.
Displacement savings may also be achieved when the landfill owner/operator can use
a portion of the landfill gas produced to offset natural gas or oil purchases at nearby facilities
under the same ownership. The economic incentive for the owner/operator to try and offset
these fuel costs will mainly be determined by the landfill's proximity to facilities that use
natural gas or oil to meet process or heating needs. The savings possible from these offsets
will depend on the existing fuel costs of the facilities and the amount of landfill gas that can
Part II September 1996 Page 5-6
-------
Box 5.2 Displacement of Energy Purchases at the Prince George's County
Correctional Complex
The Brown Station Road Landfill (4 million tons waste in place and growing)
in Prince George's County, Maryland provides landfill gas to meet the electrical and
heating needs of the County Correctional Complex. This energy recovery system
generates electricity using three 850-kw 1C engine generators and also delivers
medium-Btu gas to two conventional boilers located at the correctional complex. The
three electric generators provide almost all of the correctional complex's electrical
needs; excess electricity generated by the project is sold to the local electric utility
(PEPCO). The boilers, which were originally designed to burn No. 2 fuel oil or natural
gas, were adapted for landfill gas fuel and provide heat and hot water for the
correctional complex. The project configuration was selected from among several
options based on an economic comparison which examined lifetime costs and
revenue to the county.
The project displaces most of the county's electricity and heating fuel costs
associated with the correctional complex. The county estimates that the gross
benefits are about $1.2 million per year in energy cost savings [Augenstein and
Pacey, 1992].
be used by the facilities. Box 5.2 describes a landfill gas energy recovery project that
displaces boiler fuel purchases and generates electricity for a Prince George's County,
Maryland facility.
Thermal Energy Revenues
Landfill gas energy recovery projects can generate thermal energy such as steam or
chilled water for use in nearby industrial plants or commercial facilities (e.g., hospitals, office
buildings, hotels, universities). The economic incentive to cogenerate steam and other forms
of thermal energy along with electricity using a cogeneration configuration is determined
mainly by the potential customer's existing costs of generating thermal energy, and by the
project's proximity to the customers. Typical steam costs range from $1.5 per million Btu
(MMBtu) to $6/MMBtu, depending on the existing fuel and technology being used. Steam
generation from waste fuels, wood, and sometimes coal can achieve costs at the low end of
this range, while gas- and oil-fired steam is usually more expensive. Landfill project
owner/developers should expect to offer some discount, often on the order of 5% to 30%,
over a potential customer's current steam cost in order to be attractive.
Sample Calculation of First Year Revenues
For the hypothetical 5 million metric ton landfill described in Box 5.1, revenues are
assumed to be created by generating electricity for: (1) sale to the local electric utility; and (2)
displacement of retail electric purchases at a municipal office building. This example
assumes that the electric buyback rate in 1996 is 04.8/kWh. It also assumes that there is a
nearby office building, owned by the landfill owner/operator, that consumes 3 million kWh per
year at a retail rate of 05.9/kWh jn 1996. Table 5-1 presents a calculation of first-year
revenues, which range from $1.7 million for an 1C engine system to $2.3 million for a
combined-cycle CT system. The combined-cycle CT produces more revenues than the other
Part II September 1996 Page 5-7
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Table 5.1 Estimated First-Year Power Project Revenues at Example Landfill
Example: Landfill waste in place =
PROJECT OPERATING DATA
Net sustainable landfill gas production
Gross electric output
Net electric output
Annual electricity generated
Annual electricity sold
Net electricity sold to utility
Electricity used on— site
ELECTRICITY PRICES
Buy-back price
Retail price
ANNUAL EXAMPLE REVENUES
Electricity Sales to Utility in 1st Year
Electricity Sales On- Site in 1st Year
Total Annual Revenues
Revenues per kWh sold
5
Units
met/day
kW
kW
kWh
kWh
kWh
c/kWh
c/kWh
$000
$000
$000
c/kWh
million metric
1C Engine
2,988
5,188
4,934
34,577,472
31,577,472
3,000,000
4.8
5.9
$1422
$177
$1,699
4.9
tons |
Combustion
Turbine
2,988
5,188
4,727
33,126,816
30,126,816
3,000,000
4.8
5.9
Sl,452
$177
$1,629
4.9
Combined
Cycle CT
2,988
7324
6,763
47395,104
44395,104
3,000,000
4.8
5.9
$2,140
$177
$2317
4.9
(a)
I D)
I V I
(c)
(d)
(e)
Notes:
(a) Calculated using statistical model 42 in EPA Report to Congress. [EPA] The resulting methane
production estimate is within the range predicted by the models presented in Part I.
(b) Assumed for example purposes.
(c) Product of utility sales kWh and assumed 19% buyback electricity rate of 4.8 c/kWh.
(d) Product of on-site sales kWh and assumed 19% reiail electricity rate of 5.9 c/kWh.
(e) Total annual revenues divided by total kWh generated. Note that this shows potential revenues, not the
cost of generating electricity from landfill gas.
Part I!
September 1996
Page 5-8
-------
technologies because it generates more electricity, but the Step 2 analysis will show that the
combined-cycle CT is also more expensive to build. The first-year revenues amount to
04.9/kWh for ail three technologies on a per KWh basis, calculated by dividing the annual
revenues by the total kWh generated and sold. In Step 3 this revenue estimate will be
compared against the cost of generating electricity from landfill gas, which varies significantly
among the technologies as described in the next section.
5.2.2 Step 2: Quantify Capital and O&M Expenses
To evaluate the economic feasibility of a landfill gas power project, the project
expenses must be subtracted from revenues to determine potential gains (or losses). The
chief project expenses are the amortization of up-front capital costs and the annual O&M
expenses. Some projects have other expenses such as payment of fees or royalties for
landfill gas rights. The following sections describe the different categories of project
expenses.
Capital Costs
The total capital requirement for a landfill gas power project includes the costs of the
major equipment (e.g., engine, CT), as well as the costs associated with the auxiliary
equipment, construction, emissions controls, interconnections, gas compression and
treatment, engineering, and "soft costs." Soft costs typically include up-front owner's costs
(e.g., development staff, legal, permitting, insurance, property tax), escalation during
construction, interest during construction, and owner's contingency, all of which are real costs
incurred prior to and during the construction process.
The costs of the landfill gas collection system (e.g., equipment, installation, soft costs)
can be excluded from the economic analysis if the collection system is either already in place
or required by air emissions regulations. The energy recovery system can then be evaluated
using an incremental cost approach. Under the incremental cost approach, the collection
system costs are not included because these are sunk costs that would be incurred whether
the recovered landfill gas is put to use or just flared. In the 5 million metric ton landfill
example, the total cost includes the costs associated with the energy conversion system plus
the landfill gas collection system, while the incremental cost does not include the capital or
O&M costs associated with the landfill gas collection system.
Capital costs for landfill gas power projects vary widely depending on landfill size,
conversion technology, and project design. Table 5-2 presents the estimated capital costs of
landfill energy recovery systems for landfills with 1, 5, and 10 million metric tons of waste in
place. For these hypothetical energy recovery projects beginning operation in 1996, the total
capital requirement is estimated to range between $1,595/kW and $2,423/kW, and the
incremental capital requirement is estimated to range between $1,109/kW and $1,691/kW1.
These cost data are expressed in as-spent dollars, which means that equipment cost
escalation (e.g., inflation) prior to and during construction is included in the cost estimate. As
1 Not included in the capital cost data are preliminary project development expenses, the major
component of which is landfill gas quantity testing. The most reliable method of testing is to drill test wells
and conduct a pump test. Test wells typically cost between $5,000 and $10,000 per well [Smithberger,
1994; Merry, 1994], and the number of wells required to accurately predict landfill gas quantity will depend
on a number of factors such as landfill size and waste homogeneity.
Part II September 1996 Page 5-9
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the cost data show, the capital cost per kW generated ($/kW) generally decreases with
increasing project size, owing mainly to economies of scale, particularly for the CT-based
technologies.
In the example cost calculation for the 5 million metric ton landfill producing about 3
million cf of landfill gas per day in 1996, the total capital requirement ranges from $1,675/kW
for an 1C engine system to $2,025/kW for a combined-cycle CT system, including the cost of
the gas collection system (see Table 5-3). On an incremental basis, the capital requirement
ranges from $1,177/kW for the 1C engine to $1,658/kW for the combined-cycle CT. These
costs are in as-spent dollars, reflecting a June 1996 on-line date. A boiler/steam turbine
system would not be economically competitive at this size, but boiler/steam turbine system
costs would probably become competitive at larger gas flow rates above roughly 5 to 7
million cf/day.
Although capital cost is the major determinant of the cost of generating electricity from
landfill gas projects, the technology with the lowest capital cost is not always the choice. A
good example is the 10 million metric ton landfill case presented in Appendix A. In that case,
the 1C engine has the lowest capital cost, but after O&M and royalty expenses are taken into
account, the CT option yields the lowest cost of electricity. Other factors such as reliability
and emissions also should be considered when deciding among technologies (see Part I for
more on technology issues).
O&M Expenses
The O&M expenses vary considerably among projects due to different equipment
types and gas treatment processes. Typically, O&M expenses include both fixed and variable
expenses, as described in Box 5.3. Fixed O&M expenses are predictable and are not
dependent on the amount of time that the project operates or the amount of electricity
generated. Variable O&M expenses are usually dependent on the amount of time that the
project operates, which can be measured by the amount of electricity (i.e., kWh) produced.
The total generator system O&M costs for 1C engines are about
-------
Table 5.2 Estimated Power Project Capital Costs for Three Landfill Sizes
Estimated
Net
Sustainable Net
LFG Electric
LANDFILL SIZE Production Output
Waste in Place (mcf/day) (kW)
1 million metric tons
1C Engine 642 984
Combustion Turbine 642 963
5 million metric tons
1C Engine 2,988 4,934
Combustion Turbine 2,988 4,727
Combined Cycle CT 2,988 6,763
10 million metric tons
1C Engine 5,266 8,709
Combustion Turbine 5,266 8,344
Combined Cycle CT 5,266 12,008
Notes:
Source is cost calculation tables for each size landfill (see
All costs are based on net electric (kW) output.
CAPITAL COSTS
Installed
LFG
Collection
System
($/kW)
$638
$652
$423
$442
$309
$413
$431
$300
Appendix A).
(a) Included are owners' costs (legal, permitting, insurance, taxes), escalation
and interest during construction.
Installed
Energy
Conversion
System
($/kW)
$1,052
$1,412
$958
$1,153
$1,360
$919
$1,037
$1,208
Total
Soft
Costs +
Engineering
($/kW)
(a)
$310
$359
$294
$334
$356
$263
$288
$306
Total
Capital
Requirement
($/kW)
$2,000
$2,423
$1,675
$1,928
$2,025
$1,595
$1,756
$1,813
Incremental
Capital
Requirement
_l$/kWl
(b)
$1,283
$1,691
$1,177
$1,409
$1,658
$1,109
$1,249
$1,458
during construction (6 - 24 mos)
(b) Excludes capital and soft costs associated with the LFG collection system.
-------
Table 5.3 Estimated Power Project Capital Costs at Example Landfill
I Example: Landfill waste in place
Cost Category
OPERATING DATA
Net electric output
On— line date
5
Units
kW
EQUIPMENT & INSTALLATION COSTS
Energy Conversion System ($1994) $000
LFG Collection System ($1994)
Engineering ($ 1994) @ 5 .0%
CAPITAL REQUIREMENT
System cost ($1994)
Soft Costs
Total Capital Requirement
(as— spent dollars, 1996 on-line date)
$000
$000
$000
$000
$000
$/kW net
million metric tons !
1C Engine
4,934
6/96
4,725
2,088
341
7,154
1,109
8,263
1,675
Combustion
Turbine
4,727
6/96
5,450
2,088
377
7,915
uoo
9,115
1,928
Combined
Cycle CT
6,763
6/96
9,200
2,088
564
11,853
1,841
13,694
2,025
Incremental Capital Requirement $000
(as-spent dollars, 1996 on-line date) $/kW net
5,807
1,177
6,659
1,409
11,216
1,658
Notes:
See Chapter Appendix for notes on these calculations.
(a) Excludes capital and soft costs associated with the LFG collection system.
Part
September 1996
Page 5-12
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Box 5.3 Classification of O&M Expenses
O&M expenses include both fixed and variable expenses, as shown below.
Fixed O&M expenses Variable O&M expenses
Labor Periodic maintenance and overhauls
Property taxes Water
Insurance Consumables (e.g., lubricating oil,
Administrative expenses hydraulic fluid, filters)
Spare parts
Fees
Emissions offsets
The distinction between fixed and variable expenses is important, because
fixed O&M expenses are incurred regardless of the amount of electricity generated.
The 5 million metric ton landfill example includes an annual royalty payment/gas
payment equal to about 10% of revenues. Including a royalty/gas expense demonstrates the
economic effect that royalties have; namely, they make landfill gas projects more expensive.
In the example, paying the royalty increases costs by 00.5/kWh, which could make the
difference between an economically attractive project and an unattractive project. In the
future, landfill owner/operators may have additional incentive to forego royalty payments
because of the environmental benefit of a landfill gas recovery project.
Estimating the Cost of Electricity
The cost of generating electricity (0/kWh) from a landfill gas power project is
equivalent to the sum of capital expenses, O&M expenses, and royalty/gas expenses (if any),
divided by the kWh of electricity delivered. Estimating this cost has two steps:
(1) Amortize capital costs and divide by the annual kWh produced; and
(2) Add O&M and royalty expenses.
Each of these steps is described below and illustrated with an example.
Step 1: Amortize Capital Costs: Capital costs are commonly "levelized," or amortized
in equal annual amounts over the economic life of the project (i.e., over the period that
the project will generate revenues). If the productive landfill life is 20 years, then a
typical term for the levelized capital cost calculation would be 20 years. For the
purposes of economic analysis, the capital costs are often amortized using a capital
charge rate (CCR). A CCR is used to convert the installed cost into a levelized capital
cost that can be charged to the project in each year of the project life. The CCR is
the levelized percentage of the total capital that must be recovered in each year to
cover:
return of equity;
Part II September 1996 Page 5-13
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• return on equity;
interest on debt;
• depreciation;
• general and administrative expenses;
• property tax; and
• income tax.
The CCR can be calculated by estimating annual interest and return on equity
payments on the outstanding loan value over the life of the project (similar to a home
mortgage) and adding annual amounts for depreciation, expenses, and taxes. The
main variables in the CCR calculation are the debt/equity ratio and interest rates. The
CCR for a privately financed landfill gas-to-energy project will be higher than the CCR
for a project financed with municipal bonds (More detailed information regarding CCRs
under different financing scenarios is contained in Chapter 6.):
• Project Finance Case: A CCR of approximately 0.136 would result in the case
where a project is financed with a debt/equity ratio of 80/20, a nominal interest
rate on debt of 9%,2 an after tax return on equity of 15%, and a 10-year tax
depreciation. (To take advantage of 10-year depreciation, the project life is
assumed to be just under 20 years.)3
• Municipal Bond Finance Case: Thus, a CCR of approximately 0.111 would
result from the case where a project is financed with 100% municipal tax-
exempt bonds that have a 6.5% interest rate.
To obtain a levelized capital cost (LCC) in c/kWh units, the annual cost calculated as
described above must be divided by the expected operating hours per year as
follows:
LCC = Installed Cost x CCR / ( CF x Hours per Year) x (0100/$) (Eq. 5.1)
where:
LCC = levelized capital cost (0/kWh)
Installed Cost = total or incremental capital requirement ($/kW)
CCR = capital charge rate
CF = annual average capacity factor
Hours per year = 8,760
Using the 5 million metric ton landfill example, the levelized capital cost for the !C
2 Interest rates are determined by the prevailing rate indicators (e.g., U.S. treasuries,
prime rate, LIBOR) and a host of project- and lender-specific factors. When this document was
written, rates for nonrecourse debt for a "strong" landfill gas project ranged from 9% to 9.8%. [Seifullin,
1995; DePrinzio, 1995] Increasing interest rates by 1% would cause the cost of electricity to increase
by 2% to 3%.
3 Landfill gas energy recovery projects appear to be eligible to use 10-year depreciation for
income tax purposes. [Jansen, 1992; Mumford and Lacher, 1993] Property with a life of 16 years or more,
but less than 20 years, can use the 10-year Modified Accelerated Cost Recovery System (MACRS)
depreciation schedule. [RIA, 1992]
Part II September 1996 Page 5-14
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engine option would be 03.2/kWh, calculated as follows using an 80% capacity
factor4:
03.2/kWh = ($1,675/kW x 0.136) / (80% x 8760 hrs) x (0100/$)
If the project were financed with 100% tax-exempt municipal bonds (CCR = 0.111), the
levelized capital cost would be 02.7/kWh.
Step 2: Add O&M Expenses: This step is straightforward-add the estimated O&M
expenses and royalty expenses (if any) to the capital expense to get the total cost of
electricity.
Based on the capital, O&M, and royalty expenses discussed above, the total first year
cost of generating electricity from the 5 million metric ton landfill in 1996 are presented in
Table 5-4. As the table shows, the cost of the conversion system plus the gas collection
system could range from 06.0/kWh to 06.5/kWh if the project were financed with 80% debt
and 20% equity. Financing 100% of the project costs with tax-exempt municipal bonds would
achieve a cost of electricity ranging from 05.5/kWh to 05.8/kWh. The incremental cost of
electricity, which excludes collection system costs, would be approximately 20% to 25%
lower, or 04.6/kWh to 05.3/kWh for the project finance case, and 04.2/kWh to 04.7/kWh for
the municipal bond finance case. [Note that these costs of electricity include a royalty
payment of 00.5/kWh and do not include the effects of incentives, which could trim another
01/kWh or more off the electricity cost if applicable (incentives are factored into the
calculation in Step 3).]
The 1C engine appears at this landfill size to have a slight cost advantage over the CT
and a substantial advantage over the combined-cycle CT, owing mainly to the 1C engine's
lower engine and gas compressor costs, and gas compressor auxiliary load. However, the 1C
engine loses some of its advantage because of higher O&M costs.
5.2.3 Step 3: Compare Project Expenses and Revenues
As a first cut at assessing a particular project's economics, first-year expenses and
revenues are often compared to see if a project configuration warrants further analysis. At
this point it is important to include any tax credits or other incentives in the economic
assessment. If first-year project revenues are comparable with expenses, making sure to take
into account any tax credits that are available, then it is advisable to proceed to the next step:
creating a pro forma model of project cash flows. If the estimated revenues fall significantly
short of the project costs, one or both of the following two options should be pursued:
1) Look for additional sources of revenue (e.g., on-site sales, thermal sales) or
alternative customers (e.g., electric utilities, municipal utilities) that may offer a
higher electricity price; and/or
2) Change the project configuration (e.g., size, technology, equipment vendor,
energy outputs) and re-examine the economics.
4 See Box 3.6 in Chapter 3 for a discussion of capacity factors.
Part II September 1996 Page 5-15
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Table 5.4 Estimated Cost of Electricity Production for Three Project
Configurations at Example Landfill
Example: T-andfill waste in place =
5 million metric tons
Total Electricity Cost in 1996
Project Finance Case
(80% debt, 20% equity)
Municipal Finance Case
(tax-exempt bonds at 65%)
j Municipal Finance Case
(tax-exempt bonds at 6.5%)
Combustion Combined
Units 1C Engine Turbine Cycle CT
c/kWh
c/kWh
Incremental Electricity Cost in 1996
Project Finance Case c/kWh
(80% debt, 20% equity)
c/kWh
6.0
55
4.6
42
62
5.6
4.7
42
6.5
5.8
53
4.7
(a)
Notes:
See Chapter Appendix for notes on these calculations.
All cost estimates include a 0.5 c/kWh royalty payment. Tax incentives and subsidies are not included.
(a) Incremental Electricity Cost does not include capital and O&M costs associated with LFG collection system.
Pan II
September 1996
Page 5-16
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Tax Credits/Incentives
Tax credits and federal incentive payments can significantly improve project
economics, and help to justify an otherwise marginal project. Currently, federal tax credits
listed under Section 29 of the Internal Revenue Code are available for the recovery and use of
unconventional gas fuels such as landfill gas. Additionally, the "Renewable Energy
Production Incentive" (REPI) program, which was mandated under the 1992 Energy Policy Act
and is being implemented by the U.S. Department of Energy, provides an incentive to publicly
owned facilities that generate electricity from renewable energy sources such as landfill gas.
The applicability of these incentives depends on the structure of the project and the
owner/operators' tax situation. Therefore, a full understanding of the tax laws and how they
may be applied is critical to ensuring a project's ability to take advantage of the incentives.
Section 29: The Internal Revenue Service (IRS) Section 29 tax credit, currently due to
expire in the year 2007, is available to landfill gas projects that are operating before
June 30, 1998. This tax credit has been extended several times by the U.S. Congress
since its initial inception, but there are no guarantees that the extensions will continue.
The credit is worth $5.83 per barrel of oil-equivalent (on a MMBtu basis) and is
adjusted annually for inflation [Conversation with Tommy Thompson, U.S. Internal
Revenue Service, April 1996]. The current value of the credit is $1.001 per MMBtu
[Conversation with Tommy Thompson, U.S. Internal Revenue Service, April 1996]. At
full value, this converts to about 0.90 to 1.30/kWh for a typical landfill gas electricity
project, depending on the efficiency of the generating equipment used.
The Section 29 tax credits apply only to landfill gas that is produced and then sold to
an unrelated third party (for example, when landfill gas is sold as a medium-Btu fuel to
an industrial customer) [RIA, 1992]. As a result of this stipulation, project developers
may bring in or create a separate company when developing power projects in order
to take advantage of the credits. Several project structures exist that would allow a
landfill gas project to benefit, either directly or indirectly, from the tax credits. Three
such structures are presented in Box 5.4. Depending on the structure used, the
project may receive only a fraction of the value of the tax credits. For example, if a
tax-paying company takes responsibility for gas collection and sells the gas to a
power project, the collection company is entitled to the Section 29 tax credits.
However, if this company cannot fully use the credits, as is often the case, the
company might transfer the credits to outside investors who can use them. Usually
the gas collection company must "sell" the tax credits at a discounted price, leaving
the collection company with as little as 60% of the full value of the tax credits.
REPI: Section 1212 of the Energy Policy Act of 1992 stipulated that a cash subsidy of
1.50 per kWh (adjusted annually for inflation) would be available to renewable energy
power projects owned by a state or local government or nonprofit electric cooperative,
that are first used during the period October 1993 through September 2003 [Federal
Register, July 19, 1995]. Solar, wind, geothermal (except dry steam geothermal), and
biomass (including landfill gas, but excluding municipal solid waste) projects are
defined to be renewable energy projects.
The availability of funding for REPI payments is subject to annual appropriation by
Congress. Approximately $2.2 million was appropriated for the program for fiscal year
1995, and $3 million was appropriated for 1996 [Klunder, 1995]. Payments will be
made first (and on a pro rata basis if necessary) to qualified renewable energy facilities
Part II September 1996 Page 5-17
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Box 5.4 Examples of How A Project Can Be Structured to Take Advantage of
Section 29 Tax Credits
Privately Owned Landfill:
Scenario One:
• The landfill owner owns and operates the gas collection system (GASCO), and
sells the gas to the developer for use in the energy recovery project (GENCO).
• The GENCO is owned and operated by a developer who is unrelated to the
landfill owner.
Result: The landfill owner receives gas revenues and tax credits, which can be used or
sold along with the GASCO to another party.
Publicly Owned Landfill:
The following scenarios describe structures that enable a landfill owner who cannot
take direct advantage of tax credits (e.g., a municipality) to benefit from the transfer of
credits.
Scenario One:
• An entity (GASCO) unrelated to the landfill owner purchases the gas rights from
the landfill and operates the gas collection system. It sells the gas to the energy
recovery project (GENCO).
• The GENCO is owned and operated by a developer who is unrelated to the
landfill owner.
Result: The landfill owner receives a one-time payment for its gas rights, and the owner
of the GASCO receives the tax credits.
Scenario Two:
• The landfill leases gas rights, for a "production fee," to an unrelated party
(GASCO) who sells the gas to the energy recovery project (GENCO).
• The GENCO is owned and operated by a developer who is unrelated to the
landfill owner.
Result: The landfill owner receives production payments and a share of the tax credits.
The GASCO receives the majority of the tax credits.
In many of these cases, the developer of the energy recovery project and the
purchaser/lessor of the gas rights may have overlapping ownership of up to 50%.
[Martin, 95]
Part II September 1996 Page 5-18
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using solar, wind, geothermal, and closed-loop biomass technologies.5 Payments will
then be made (on a pro rata basis if necessary) to all other qualified renewable energy
facilities [10 CFR, Part 451] including landfill gas-to-energy facilities. The 1995
appropriation was enough to make all approved payments.
According to the rules governing the REPI program, projects must apply annually for
the payments, which may continue for up to ten years. Applications for energy
produced in a fiscal year must be submitted to the Department of Energy during the
period October 1 through December 31 of the following fiscal year [10 CFR Part 451].
Example Calculation of Project Cash Flow (First Year)
An estimate of first year cash flow and economic viability is obtained by subtracting
the first-year expenses from revenues, and adding available tax credits/incentives. If this
calculation yields an amount of zero or greater (i.e., surplus cash flow), the assumed
revenues can support the project expenses, as well as meet the project's financing
requirements (e.g., a 15% return on equity in the project finance case). The financing
requirements are included in this analysis as part of the project expenses. A negative result
indicates a cash flow shortfall, which means that expenses will not be covered or debt service
requirements will not be met in the first year. Since this calculation only provides a rough
indication of economic viability, the most important result is simply whether or not the
calculation yields a non-negative amount.
Continuing the 5 million metric ton landfill example, the assumed electric buyback rate
of 04.8/kWh would be capable of supporting various project configurations depending on the
financing assumptions and the cost basis assumption, as shown in Table 5-5. As shown in
the table, all three technologies are estimated to be viable on an incremental cost basis for
both the project finance and municipal bond finance cases. However, on a total cost basis,
only the 1C engine power configuration appears viable in the project finance case. In
contrast, the cost advantages of municipal bond financing (tax exempt) allows all thrae
technologies to be viable even under a total cost basis. This analysis demonstrates that the
availability of municipal bond financing has an important effect on the economic viability of
the technology options.
It is clear that for the example landfill, the 1C engine power configuration appears most
promising at this stage of the analysis, so the analysis of this option should proceed to
Step 4. Because the CT option is relatively close to the 1C engine under all scenarios, it
would be reasonable to carry the CT forward for further evaluation in Step 4 as well. The
combined-cycle CT should only be considered if municipal bond financing is an option.
Landfill gas power project economics have the potential to improve over time, but
future performance must nevertheless be carefully examined. Economics can improve,
because most of the costs are fixed (e.g., capital and gas collection costs) and not subject to
significant escalation over time. Only the O&M costs are expected to increase significantly.
Project revenues, which are driven by buyback rates, can increase over time and should more
than offset any O&M increases. However, these positive effects can be easily negated by
declining gas flows in later years, because the project will have diminished revenues (see
5 Closed-loop biomass means any organic material from a plant which is planted exclusively for
purposes of being used to generate electricity [10 CFR, Part 451].
Part II September 1996 Page 5-19
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Table 5.5 First Year Project Revenues and Expenses for Three Project
Configurations at Example Landfill
1 Example: Landfill waste in place =
REVENUES
PROJECT FINANCE CASE
Expenses (including Owner's Return)
Total
Incremental
Revenues Minus Expenses
Total
Incremental
19% Tax Credit
Estimated Surplus (Shortfall') Cash Flow
Total Cost Basis
Incremental Cost Basis
MUNICIPAL BOND FINANCE CASE
Expenses (including financing costs)
Total
| Incremental
Revenues Minus Expenses
Total
Incremental
19% REPI Subsidy
Estimated Surplus (Shortfall) Cash Flow
i Total Cost Basis
Incremental Cost Basis
5
Units
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
After Taxes
c/kWh
$000
c/kWh
$000
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
After Taxes
c/kWh
$000
c/kWh
$000
million metric tons 1
Combustion Combined
1C Engine Turbine Cycle CT
4.9 4.9 4.9
6.0 6.2 65
4.6 4.7 53
(1.1) (13) (1.6)
03 02 (0.4)
13 13 0.9 (a)
and Owner's Return
02 0.0 (0.7)
$69 $0 ($332)
1.6 15 0.5
$553 $497 $237
5.0 5.1 53
3.7 3.7 4.2
(0.1) (0.2) (0.4)
1.2 12 0-7
0.0 0.0 0.0
and Financing Expenses
(0.1) (0.2) (0.4)|
($35) ($66) ($190)1
1.2 1.2 0.7
$415 $398 $332
;
Notes:
(a) In many cases, only a fraction of the tax credit gets applied to the project. If only 60% of the available
credit gets applied, then the project becomes more expensive by about 0.5 c/kWh, or $173,000 per year.
See Appendix A for notes on calculations.
Pan
September 1996
Page 5-20
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Chapter 3 for more on project sizing).
The results of the analysis are, of course, driven by the key assumptions that affect
costs and revenues, including: incentives, royalty payments, capital and O&M costs, electro
buyback rate, financing method, and annual capacity factor. In this example, the full value of
tax credits or subsidies contribute 0.9c/kWh to 1.50/kWh to project cash flows, and all
scenarios include a royalty/gas payment expense of 0.50/kWh.
5.2.4 Step 4: Create a Pro Forma Model of Project Cash Flows
After an initial comparison of expenses and revenues has demonstrated that a
particular project configuration could be competitive (e.g., 1C engine, CT), the next step is to
create a pro forma model of project cash flows over the life of the project. This type of cash
flow model is known as pro forma because it usually contains several standard items
including a listing of financial assumptions and operating parameters, energy pricing data,
calculation of annual expenses and revenues, an income statement, a cash flow statement,
and financial results (see Box 5.5). An income statement usually lists the elements of project
revenues and expenses, and shows a calculation of operating income, depreciation, taxes,
and net book income. A cash flow statement typically shows project cash flows including
pre-tax and after-tax cash flows, and distributions to project owners. Financial results include
debt coverage ratios, rate of return (ROR), and net present value (NPV).
Box 5.5 The Pro Forma
The elements of a well-designed pro forma include:
• Project specifications and cost data
• Operations summary (e.g., kwh generated, Btu delivered, gas consumed)
• Financing and depreciation summary (e.g., interest rates, schedules)
• Price escalators for fuels, consumables, services, equipment
• Operating expense calculation (annual costs for royalties, fuel, O&M)
• Revenue calculation (annual revenues from sales of electricity, energy)
• Financing costs (e.g., interest and principal payments, investor's cash flow)
• Income statement (calculation of operating income, book income)
• Income tax and tax credit calculation
• Cash flow statement (e.g., pre-tax and after-tax cash flow calculations)
• Financial performance calculation (e.g., debt coverages, ROR, NPV of cash flows)
A well-designed pro forma should give the owner/developer a clear idea of project
revenues, expenses, and sensitivities, and it can also serve to convince investors of project
financial viability and returns. Preparing a detailed pro forma is an important step in ensuring
the financial feasibility of a landfill gas-to-energy project. The pro forma model is usually
created by the project developer using a. computer spreadsheet format, which makes it easy
to change inputs and assumptions if needed. This feature also makes the pro forma a useful
tool for testing the project's economic sensitivity to alternative assumptions and options.
A pro forma will yield a much more reliable assessment of economic viability than the
first-year comparison. Therefore, it is generally recommended that a pro forma be developed
Part II September 1996 Page 5-21
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for all options that achieve positive or close-to-positive results in Step 3.
5.2.5 Step 5: Assess Economic Feasibility
The key financial results of a pro forma model are used to assess the economic
feasibility of a power project. Economic feasibility is usually measured by indicators such as
debt coverage ratios, ROR on equity, and NPV. The debt coverage ratio, which is the annual
ratio of operating income to the debt service requirement, is a measure of the project's ability
to meet its debt repayment requirements, and is usually expected to be in the range of 1.3 to
1.5. Lenders often view projects with debt coverage ratios below 1.3 as having a high risk of
defaulting on loan repayment, which can make financing difficult. The ROR on equity and the
NPV of owner's cash flows are two measures of the financial returns to the project owner.
The owner's rate of return on equity ranges from approximately 12% to 18% for most types of
power projects.
An acceptable owner's ROR for a particular project is a function of project risks and
the owner's objectives. If the landfill owner views the project mainly as a cost-effective
pollution control measure, then financial returns are not the only consideration and a ROR of
12% or less may be acceptable. Likewise, if risks have been removed because extensive
testing has been done or permits are in hand, then lower RORs may be acceptable.
However, if uncertainties such as unconfirmed gas flow rates or potential permitting difficulties
are present, then the owner/developer may expect a higher ROR to compensate for the risks.
5.3 SALE OF MEDIUM-BTU GAS
If there is a suitable buyer nearby, direct sales of medium-Btu gas is generally the
most economic recovery option, because it entails minimum processing requirements and
capital costs. The suitability of a potential buyer depends largely on two considerations: (1)
the buyer's proximity to the landfill and (2) the buyer's gas requirements.
The proximity of a potential customer to the landfill is critical because the cost to
deliver the gas may be prohibitive if the customer is located far from the landfill. Ideally, the
customer will be no further than one to two miles away. If there are no potential customers
nearby, it may be possible to entice new industrial facilities to locate near the landfill by
offering a low cost fuel.6
The total annual gas or steam requirements of a potential customer are important,
since they will determine whether landfill gas production rates will support the entire needs of
the customer or only a portion. For example, a five million metric ton landfill could support
the processing needs of a large kiln operation, while a one million metric ton landfill may only
provide enough gas to supplement needs during peak periods. When evaluating the needs
of a customer who will be using landfill gas in boilers to generate steam, a general rule of
thumb is that approximately 10,000 pounds per hour of steam can be provided by every one
6 New industries that are searching for a suitable facility location often work through local or state
economic development specialists to identify candidate sites. Therefore, educating economic
development specialists about the benefits of using landfill gas as a fuel so they can offer its
advantages to potential customers may be worthwhile.
Part II September 1996 Page 5-22
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million metric tons of landfill waste in place.7
A potential buyer's seasonal gas demand is also important due to the nature of landfill
gas production. If a customer has only an intermittent gas load, much of the landfill gas
recovered will be flared rather than sold, since landfill gas storage is not economical. A
baseload gas user which uses gas on a continuous basis is usually preferred over an
intermittent user, such as a facility that uses gas mainly for seasonal heating needs. It is
more difficult to justify the economics of selling gas to an intermittent user, because gas sales
revenues are reduced during non-heating seasons and the landfill gas must be flared or used
elsewhere.
Using landfill gas as a medium-Btu fuel in boilers that create steam to meet process or
space heating needs is one of the simplest and most common direct use applications. Other
industrial applications include drying operations, kiln operations, and cement and asphalt
production. If one of these applications provides only a seasonal market for the landfill gas,
multiple uses may be combined to achieve a continuous baseload. Box 5.6 describes how
one company successfully created a year-round demand for its landfill gas production by
combining the demands of its asphalt manufacturing operation with its space heating needs
in the winter months. Another landfill gas application that may be ideal is to provide
supplemental fuel to waste-to-energy plants, which are often located near landfills. For
example, at the 45-MW Ridge waste-to-energy plant in Florida, landfill gas from the adjacent
landfill comprises five percent of total fuel input on a heat-input basis [Swanekamp, 1994].
The economic viability of the project can be determined once a potential gas user has
been identified using the steps described below.
5.3.1 Step 1: Estimate Energy Sales Revenues
Revenues for a medium-Btu gas project come from gas sales to a direct use
customer. Potential landfill gas customers include industrial energy users, commercial
buildings, universities, incinerators, and district heating systems. Typically, medium-Btu gas
customers will buy landfill gas at a price that is no higher than their current delivered price of
natural gas on a Btu basis, since landfill gas combustion may require burner retrofits,
controls, and maintenance that natural gas does not. In fact, landfill gas project
owner/developers should expect to offer landfill gas at a discount off the customer's current
natural gas price; discounts of approximately ten to twenty percent are common in existing
projects. Delivered natural gas prices vary by location and customer type. For example, the
price paid by a large industrial gas user will likely be less than that of a customer who only
uses gas for space heating purposes such as commercial buildings and district heating
systems. Box 5.7 illustrates these price variations, which should be kept in mind when
negotiating with potential customers.
Displacement savings, realized by using landfill gas to offset natural gas purchases at
facilities owned by the landfill owner/operator, should also be credited to the project.
Tax credits or other incentives may be used to supplement gas revenues. However, if
the tax credits are to be used by a third party developer, they may not yield full face value to
the project since there are soft costs (i.e., legal and transaction fees) associated with placing
7 This rule of thumb assumes that steam is supplied at 50 psig, saturated.
Part II Septemoer 1996 Page 5-23
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Box 5.6 Multiple End Uses of Landfill Gas Create a Baseload Demand for
Fred Weber, Inc.
Fred Weber, Inc., a cement and asphalt producer, collects landfill gas from a
landfill near St. Louis, Missouri and directly uses the medium-Btu gas in three
different, seasonal applications, for savings of about $100,000 per year.
• In the summer months, landfill gas is burned in the aggregate dryer at
the firm's asphalt plant which is located adjacent to the landfill.
• In the winter months, Fred Weber, Inc. uses landfill gas in its concrete
plant to heat water for the preparation of ready-mixed concrete.
• Landfill gas is also used to heat the firm's adjacent commercial
greenhouse.
By using landfill gas in complementary applications, Fred Weber, Inc. has
created a baseload demand for its landfill gas supply.
[Mahin, 1991]
Box 5.7 Natural Gas Price Variations by Customer Type
Natural gas consumers can either purchase their own gas supplies and
then pay the local distribution company (LDC) a delivery charge, or they can
purchase delivered supplies directly from the LDC. Most large industrial and
commercial consumers choose the former purchase alternative, since it is usually
less expensive than buying from the LDC.
Regardless of the purchase strategy used, large industrial customers
typically pay less for natural gas than other types of consumers:
Industrial Commercial Residential
Average Price ($/mcf) 3.00 5.22 6.89
All dollar values are in 1994 dollars.
[Energy Information Administration, 1995]
the ownership of the gas rights and collection system with an independent party. In addition,
if the company cannot fully use the credits , the company may transfer the credits to an
outside investor. These outside investors usually buy the credits at a discounted price,
leaving the sellers with as little as 60% of the full value of the tax credit.
Part II September 1996 Page 5-24
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5.3.2 Step 2: Quantify Capital and O&M Costs
The gas collection costs for a medium-Btu gas sales project would be similar to those
incurred in a power project, although gas processing costs would probably be much less,
since only minimal clean-up is usually required for direct use applications. The capital cost?
associated with delivering landfill gas to the customer would normally include pipeline
construction costs (about $250,000 to $500,000 per mile, installed), additional gas
compression costs, and metering. If there are low points in the pipeline which would allow
moisture to accumulate, then the costs of installing dehydration equipment may also be
incurred.
The customer may incur capital costs if equipment retrofits are necessary in order to
burn landfill gas. For example, due to the lower flame temperature of landfill gas as
compared to natural gas, lower boiler superheater temperatures may be experienced and
thus a larger boiler superheater could be required [Eppich and Cosulich, 1993]. Retrofit costs
will vary, since most require customized installation. For example, one project reported that
new rotary kiln burners would cost $30,000 each [LaReaux, 1995], while boiler burner retrofits
may range in cost from $120,000 to $300,000 [Brown, 1995]. The landfill project may assume
some of these retrofit costs, as was the case in the AT&T project described in Box 5.8.
Box 5.8 Medium-Btu Gas Sales to AT&T
Network Energy of Ohio, owner of landfill gas rights at a landfill near
Columbus, Ohio, is selling landfill gas to a nearby AT&T Network Wireless Systems
plant. The AT&T plant uses the landfill gas as boiler fuel to generate about 40,000
pounds of steam per hour for plant heating, process uses, and hot water heating.
Use of the landfill gas enables AT&T to reduce the purchases of its normal boiler
fuel-natural gas. Even with some natural gas still used to supplement the landfill
gas supply, AT&T expects to achieve annual fuel savings of about $100,000.
To make the medium-Btu purchase attractive to AT&T, Network Energy paid
the $1 million cost of building a 1.5-mile pipeline from the landfill to the plant and
converting one AT&T boiler to burn landfill gas. A custom low-NOx burner was
designed by Coen Company to burn a controlled mixture of landfill gas and natural
gas. The burner control system is able to respond to changes in landfill gas line
pressure and Btu content.
The agreement between Network Energy and AT&T provides that all key
boiler equipment installed in the conversion is owned by AT&T. In addition, AT&T
had input in the design process and obtained the air permit for the modified burner.
Network Energy is responsible for ensuring that all other environmental conditions
are met [Source: Power. April 1994].
Table 5-6 shows the total capital costs for the example 5 million metric ton landfill,
serving a gas consumer who is assumed to be located one mile away. The cost of providing
gas to this customer is estimated to be $3.39 million, including the cost of the gas collection
system. These costs (in as-spent dollars, reflecting a June 1996 on-line date) would increase
with longer pipeline distances.
Part II September 1996 Page 5-25
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Table 5.6 Estimated Medium-BTU Project Capital Costs at Example Landfill
Example: Landfill waste in place ==
Cost Category
OPERATING DATA
Net sustainable landfill gas production
Net fuel output (MMBtu)
On-line date
Capacity factor (lifetime annual average)
Annual full load operating hours
Annual volume of gas sold
EQUIPMENT & INSTALLATION COSTS
Gas Delivery System ($1994)
Condensate removal/filtration
Compressor/Blower station
Pipeline interconnect
Fuel burning equipment conversion
Gas delivery system cost ($1994)
LFG collection system cost ($1994)
Engineering ($1994)
5 million metric tons
Units Baseload user
(continuous)
mcf/day 2,988
MMBtu/day 1,494
6/96
90%
hours 7,884
MMBtu 490,811
$000 15
$000 100
$000 350
$000 150
615
$000 2,098
$000 136
Heat load user
(seasonal)
2,988
1,494
6/96
40% (a)
3,504
218,138
15
100
350
150
615
2,098
136
Notes:
See Chapter Appendix for notes on these calculations.
(a) Assumes baseload user has a year-round need for gas, and heat load user only uses gas in the
five winter months.
(b) Excludes capital and soft costs associated with the LFG collection system.
'CAPITAL REQUIREMENT
System cost ($1994)
: System cost ($1996)
Soft costs($ 1996)
Owners costs, escalation, interest
Contingency @5.0%
Total Soft Costs
Total Capital Requirement
(as-spent dollars, 1996 on-line date)
Incremental Capital Requirement
$000
$000
$000
$000
$000
2,848
3,051
190
153
343
3,394
769
2,848
3,051
190
153
343
3,394
769 (b)
Part
September 1996
Page 5-26
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O&M costs are relatively low for medium-Btu gas projects. The gas consumer is
usually responsible for the O&M of its own fuel-burning equipment. For the project developer,
gas delivery system O&M expenses might include pipeline marking costs (to prevent pipeline
rupture during excavations), labor costs, insurance, and property taxes. The Wilder's Grove
landfill gas project in North Carolina reports that its only routine gas delivery system
maintenance tasks are to clean the automated condensate drain filter and replace the
pumping station filter when significant pressure drops occur [Augenstein and Pacey, 1992].
Gas collection system O&M costs are calculated to be about $0.31 per MMBtu in 1996 dollars
[EPA, 1993].
5.3.3 Step 3: Compare Project Expenses and Revenues
To evaluate the economics of selling medium-Btu gas, the expenses associated with
collecting, processing, and delivering the landfill gas must be compared against the gas
revenues. A first-year comparison can give a quick estimate of project economic feasibility,
while a pro forma model of cash flows will provide a more precise model of economic
performance.
Using the capital cost assumptions described in Table 5-6, the first year cost of
producing a medium-Btu fuel for direct use can be calculated for the example 5 million metric
ton landfill. The results are presented in Table 5-7. Costs are displayed in the example for a
baseload gas user, who consumes gas at a relatively constant rate over the course of a day
or year, and a heat load user, who consumes gas mainly for seasonal heating needs. The
results of the cost calculations affirm the following conclusions about medium-Btu gas
projects in general:
• The incremental cost of installing a gas delivery system is very low. For the
example landfill, the cost of the gas delivery system represents only about 23%
of the total capital requirement.
• The fuel consumption pattern of a potential gas customer greatly affects the
unit cost of gas. The example shows that producing and delivering gas to a
heat load only customer would cost over twice that of producing and delivering
to a baseload customer ($2.87 per MMBtu versus $1.28 per MMBtu on a total
system basis).
• IRS Section 29 tax credits can make a substantial difference in offsetting gas
production costs. When the full benefit of tax credits is factored into the cost
of an incremental gas delivery system, the gas can essentially be recovered for
free.
5.3.4 Steps 4 and 5: Create a Pro Forma and Assess Economic Feasibility
As with landfill gas power projects, the next steps in the project development process
are to create a pro forma and assess economic feasibility. The concepts for analyzing a
medium-Btu gas project are the same as those for a power project:
Step 4: Create a pro forma that includes a listing of financial assumptions and
operating parameters, energy pricing data, calculation of annual
expenses and revenues, an income statement, a cash flow statement,
and financial results.
Part II September 1996 Page 5-27
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Table 5.7 Estimated Cost of Producing Medium-BTU Gas at Example Landfill
I Example: Landfill waste in ptace =
5 million metric tons
I Cost Category
1GAS PRODUCTION COSTS
Capital Costs (as-spent, 1996 online)
Total capital requirement
Incremental capital requirement
O&M Costs (1996)
LFG collection system
; Gas delivery system
I Tax Credit (1996)
Units
$/MMBtu
$/MMBtu
$/MMBtu
S/MMBtu
S/MMBtu
Baseload user
(continuous)
6.92
1.57
0.31
0.02
1.049
Heat load user
(seasonal)
15.56
3.53
0.70
0.06
1.049
FIRST YEAR COST OF GAS (1996)
Capital charge rate
Total Gas Cost
Levelized capacity price
1996 O&M price
Total 1996 cost of gas
Cost ofgas including tax credit
Incremental Gas Cost
Levelized capacity price
1996 O&M price
Total 1996 cost of gas
i Cost of eas including tax credit
Notes:
See Chapter Appendix for notes
(a) Incremental Gas Cost does not i]
S/MMBtu
S/MMBtu
S/MMBtu
S/MMBtu
S/MMBtu
$/MMBtu
S/MMBtu
S/MMBtu
on these calculations.
nclucle capital and O&M
0.136
0.94
0.34
128
0.23
021
0.02
0.24
(0.81)
costs associated with LFG collection
0.136
2.12
0.75
2.87 1
1.82J
(a)
0.48
0.06
0.53'
(0.51)
system.
Part II
September 1996
Page 5-28
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Step 5: Assess economic feasibility based on cash flows, debt coverage
ratios, owner's ROR, and NPV of cash flows.
5.4 ALTERNATIVE OPTIONS
Although the conventional power generation option and the medium-Btu gas sales
option account for the vast majority of landfill gas energy recovery projects, there are several
additional gas use alternatives that may be worth exploring. These alternatives, described
briefly below, include: upgrading landfill gas to pipeline quality gas; using landfill gas as a
vehicle fuel; using landfill gas in niche applications; and using landfill gas in fuel cells.
5.4.1 Upgrade to Pipeline Quality Gas
Upgrading gas to pipeline quality is relatively expensive, because of substantial
processing requirements to remove nitrogen and other constituents of raw landfill gas. This
option is currently viable only at larger landfills (i.e., more than 4 million cf per day) where
significant economies of scale can be achieved. Landfill gas developers report that the
revenues required to support such a project are in the range of $3.62 to $4.14 per MMBtu
(1994$) [SCS Engineers, 1994]. Tax credits, such as IRS Section 29 credits, may be available
to qualifying projects to help the economics of this type of project. Higher natural gas prices
would increase the attractiveness of this option.
Local distribution companies (LDCs) are the best potential market for upgraded gas
sales, because they have a large existing market for the gas. The price an LDC will pay for
upgraded landfill gas will probably be based on the price it pays for natural gas from
producers and gas marketers. There are many different pricing methods used by LDCs. One
of the most common is to index the gas price to the monthly market, or "spot," price. Spot
prices vary among geographic areas and pipeline systems, and they fluctuate month-to-
month. In the last few years, spot prices have been low due to a glut of natural gas supply
on the market. Although this glut is disappearing, gas prices are not expected to increase
dramatically in the next few years. LDCs may require gas testing for certain constituents, and
assurances that these constituents will be removed or kept to a very low level.
5.4.2 Vehicle Fuel Applications
There are a few potential vehicle fuel applications for landfill gas - compressed
natural gas (CNG), liquified natural gas, and methanol - that are in the early stages of
development or commercialization. At this time, CNG and other alternate-fuel vehicles make
up a very small percentage of automobiles in the U.S., so there is not a large demand for
CNG as a vehicle fuel. Environmental regulations may increase demand; for example, in
southern California and the Northeast, alternate-fuel vehicles are expected to become a way
to reduce local ozone pollution. Recent federal regulations may favor methanol produced
from a renewable source, such as landfill gas.
Cost savings can be realized for landfill owner/operators who own vehicles or other
nearby fleets (e.g., municipal vehicles, delivery trucks) that can be converted to run on
alternate fuels. Key factors in the economic evaluation of this option are: (1) the cost of
installing a fueling station; and, (2) the costs of retrofitting vehicles to run on the alternate
fuel. The cost of installing a compressed landfill gas fueling facility can be significant-the
installation of the Puente Hills Landfill fueling station in California cost approximately $1
Part II September 1996 Page 5-29
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million [McCord, 1994]. However, under the Energy Policy Act of 1992, a federal tax
deduction of up to $100,000 is available for the installation of alternate fueling stations [Webb,
1992; Adkins, 1995]. Vehicle conversion costs, which currently run about $3,500 for
passenger vehicles and $4,000 for trucks, can also be offset by tax deductions.8 Up to
$2,000 per vehicle is available for conversions of conventional fuel vehicles and up to $5,000
per vehicle is available for medium-duty fleet purchases or conversions [GRI, 1995].
Fleet vehicles are an especially good application for alternate fuels because these
vehicles usually travel less than 200 miles per day and they return to a central location at
night for refueling and storage. Also, having a fleet of vehicles will increase fuel usage and
therefore decrease average fuel costs, since capital recovery of fueling station construction
costs represents the majority of fuel production costs (operation and maintenance costs for
alternate fuel vehicle stations are minimal). For example, fuel costs at the Puente Hills CNG
station range from 480 per gallon gasoline equivalent at a 100 percent station utilization factor
to $1.26 per gallon gasoline equivalent at a 25 percent station utilization factor [Wheless,
Thalenburg, Wong, 1993].
5.4.3 Fuel Cells
The use of fuel cells to chemically convert landfill gas to electricity is a promising
application, largely because of the high efficiency and minimal emissions resulting from this
process. At this time, use of fuel cells for landfill gas applications is in the demonstration
phase.
The phosphoric acid fuel cell (PAFC) is one of the three types of fuel cells suitable for
stationary power production. This technology is considered commercially viable today, for
other fuels, and there are over 40 MW of PAFC demonstration units in operation
[Swanekamp, 1995]. The capital cost of the PAFC unit is $3,000 per kW for delivery in 1995,
and is projected to decrease to approximately $1,500 per kW by 1998 [Strait, Doom, and
Roe]. Variable O&M costs for the units are estimated to be 1.70/kWh [FCCG, 1993],
Landfill gas-powered fuel cells are in the demonstration phase. Northeast Utilities
installed a test unit at the Flanders Road Landfill in Groton, Connecticut in late 1995, and
operation at the site began in June, 1996. Northeast Utilities expected to spend $150,000 to
install and maintain the 200 kW fuel cell. [Electric Power Daily, 1995]. Currently, Connecticut
Light & Power, a subsidiary of Northeast Utilities, is operating and maintaining the test unit.
The $1.5 million, 200-kW PAFC demonstration unit, owned by the EPA, has already been
tested at the Penrose Landfill in Sun Valley, CA.
5.4.4 Niche Applications
An important alternative application, particularly for smaller and/or closed landfills, is
the local use of landfill gas for niche applications such as heating of greenhouses. Where
these applications are available, they may be the most economically attractive for landfills that
fail the economic tests of traditional applications. The costs of these applications will vary,
depending on type of equipment used. For example, if landfill gas is used in an existing
natural gas boiler to heat a greenhouse, costs may be minimal if burner adjustment is all that
o
Note that the tax deduction applies to the conversion of vehicles to various alternate fuels (e.g.,
CNG, LNG, LPG, or methanol).
Part II September 1996 Page 5-30
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is required.
Other niche applications are currently being developed, such as the use of landfill gas
to produce commercial high purity carbon dioxide (CO2). With retail prices for this product
between $50 and $200 per ton (1992$), this may become a valuable use of landfill gas [Strait,
Doom, and Roe]. The process used to recover landfill gas C02 is in the field-scale testing
and demonstration phase.
5.5 COMPARISON OF ALL ECONOMICALLY-FEASIBLE OPTIONS
If a landfill owner/operator has the opportunity to produce and sell more than one type
of energy product, he or she should compare the net cash flows of each option head-to-head
to determine the best option, as illustrated in Figure 5.2. After completing an initial economic
analysis for each option, including the development of a pro forma for the most promising
options, the owner/operator can compare the results of the economic analysis (Step 5). After
ranking the options and selecting an economic winner, the landfill owner/operator should then
consider non-price factors including risks, ability to obtain financial backing, environmental
performance, and reliability of assumptions. The option that produces the best financial
performance while meeting the desired environmental, risk, and operating requirements is the
winner.
5.5.1 Head-to-Head Economic Comparison
The results of Step 5 of the economic analysis-annual cash flows, NPV, debt
coverage, and ROR-can be used independently or together to rank options and select an
economic winner. There is no single measure of financial performance that guarantees
economic viability, so it is wise to consider several measures together. One approach is to
rank options according to the NPV of future after-tax cash flow, making sure that minimum
debt coverage and ROR requirements are also met. The option with the highest NPV that
meets the minimum debt coverage and rate of return requirements is the economic winner.
5.5.2 Consideration of Non-Price Factors
Although economic feasibility and financial results are important, the final selection of
the project technology and configuration should take into account non-price factors such as
environmental performance, reliability, and accuracy of assumptions. In the power generation
example used above, the 1C engine produced the maximum income for the owner, but the
use of a CT may still be more attractive if low nitrogen oxide (NOX) emissions are a priority
(see Chapter 9). The permitting process might determine that low NOx emission levels are
required, potentially making the 1C engine more expensive and/or more difficult to permit than
the CT. As another example, a medium-Btu gas sale may show superior economic results
when compared to the power generation options, but there may be additional risks entailed in
pipeline construction or boiler conversion. Non-price factors have real impacts on project
viability and must be taken into consideration.
Part II September 1996 Page 5-31
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Figure 5-2 Deciding Among Energy Project Options
Power Production/
(^generation Sales
Economic Results
Medium -Btu
Gas Sales
Economic Results
Hkjh-BtuGas
Sales
Economic Results
Alternative
Application
Economic Results
Compare Results of
Economic Feasibility
Analyses (Step 5)
Rank Options
Select
Economic
Winner(s)
Consider
Non-Price
Factors (Risks,
Financing,
O&M, Environment)
Select
Overall
Winner
Part
September 1996
Page 5-32
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6. ASSESSING FINANCING OPTIONS
Financing a landfill gas energy
recovery project is one of the most
important and challenging tasks facing a
landfill owner or project developer. A
number of potential financing avenues are
available, including finding equity investors,
using project finance, and issuing municipal
bonds. This chapter provides insights into
what lenders and investors look for under
each financing method, how to secure
financing, and some advantages and
disadvantages of each method.
The following six general categories
of financing methods may be available to
landfill gas projects:
(1) private equity financing
(2) private nonrecourse debt
financing (i.e., "project
financing")
(3) municipal bond financing
(4) direct municipal funding
(5) lease financing
(6) public financing through
institutional or public stock
offerings
The Project Development Process
Parti
Preliminary Assessment of
Project Options
Determining if a Project is Right for Your Landfill
Determining What Project Configuration is Right
for Your Landfill
I
Part II
Detailed Assessment of
Project Economics
Evaluating Project Economics
Selecting a Project Development Partner
Winning/Negotiating an Energy Sales Contract
Securing Project Permits and Approvals
Contracting for EPC and O&M Services
The first four types are common among smaller energy projects such as landfill gas projects.
Of the last two types, lease financing is used occasionally and public financing is not
commonly used for landfill gas projects, but landfill owners should be aware that they exist. A
recent survey of landfill gas energy projects concluded that private debt or equity financing
was used in 85% of the cases [Berenyi and Gould, 1994]. The same survey showed that
over 10% of the projects were funded directly by city, county, or other municipal revenues.
The selection of financing method is usually driven by cost and applicability, since not
all financing methods are available to all types of projects and project owners. A flow chart
that illustrates the general process of deciding on the optimal financing method is presented
in Figure 6.1. The cost effects of various financing methods are illustrated in Figure 6.2,
which shows a sample capacity price for the same project under different financing methods.
The capacity price incorporates the cost of building and financing a landfill gas project,
annualized over the project life. It is sensitive to interest rates; higher interest rates lead to
higher financing costs and a more expensive project compared with a lower interest rate
scenario.
From the landfill owner's perspective, often the simplest and lowest cost financing
method is to use direct municipal funding through the municipal operating budget. Because
Part II
September 1996
Page 6-1
-------
Figure 6-1: Assessing Financing Options
Start
Modify
Projeci
Are
Sufficient
Municipal
Bonds
Available
Can
Private
Equity
Investor
Be
Located
Use Direct
Municipal
Funding
Lowest
Cost
Issue
Tax-Exempt
Muni Bonds
Issue
Taxable
Muni Bonds
Use
Project
Financing
Use Private
Equity
Financing
t
Highest
Cost
CS3016-1-4
Part
September 1996
Page 6-2
-------
Figure 6-2: Capacity Price Produced by Different Financing Approaches
5 Million metric ton landfill example 1C engine electric generating project
«
u
•o a
0 U
0
Private Equity
(50% debt/50% equity)
Project Finance
(80% debt/20% equrty)
Financing Method
the amount of municipal funds available is usually limited, however, this method may not be
possible for many projects. Issuing municipal bonds is also a low-cost option, particularly for
projects owned by a public agency, but local and federal applicability rules must be satisfied
in order to use this method. If neither of these options is viable, then the project must look to
higher-cost debt or private equity for financing. Selecting a developer with equity to invest or
a demonstrated ability to obtain financing for landfill gas projects is a convenient strategy for
landfill owners exploring these financing options.
6.1 FINANCING: WHAT LENDERS/INVESTORS LOOK FOR
Most lenders and investors decide whether or not to lend to or invest in a landfill gas
project based on the expected financial performance of the project. Financial performance is
usually evaluated using a pro forma model of project cash flows (discussed in Chapter 5).
Thus, preparing a detailed pro forma is an important step in ensuring the financial feasibility
of a landfill gas energy project.
A lender seeking demonstration of project financial strength will usually examine the
following measures:
• Debt coverage ratio - The lender's main measure of project financial strength
is the ability of a project to adequately meet debt payments. Debt coverage
ratio is the ratio of operating income to debt service requirement and is usually
calculated on an annual basis. Debt coverage ratios are usually expected to
be in the 1.3 to 1.5 range.
• Owner's rate of return (ROR) on equity - The desired ROR currently ranges
from about 12% to 18% for most types of power projects. Outside equity
investors will typically expect a ROR of 15% to 20% or more, depending mainly
Part II
September 1996
Page 6-3
-------
on the project risk profile. These RORs reflect early-stage investment
situations; investments that are made later in the development or operation
phases of the project typically receive lower returns because the risks have
been substantially reduced.
The feasibility of a particular landfill gas energy project is also determined by the
quality of supporting project contracts and permits, and by risk allocation among project
participants. The uncertainties about whether a power project will perform as expected or
whether assumptions will match reality are viewed as risks. To the extent possible, the •
project's costs, revenues, and risk allocation are spelled out through contracts with energy
purchasers, equipment suppliers, fuel/landfill gas suppliers, engineering/construction firms,
and operating firms, as well as through the presence of permits, developer experience, and
financial commitments. Table 6-1 summarizes the principal project risk categories, viewed
from the beginning of the development process, and presents possible risk mitigation
strategies, the most important of which are usually obtaining contract(s) securing project
revenues and verification of landfill gas availability. Potential lenders and investors will look to
see how the project developer has addressed each risk through contracts, permitting actions,
project structure, or financial strategies.
6.2 FINANCING APPROACHES
Capital for landfill gas energy projects is most commonly obtained from private equity
financing, project financing, municipal bonds, or direct municipal funds. This section focuses
on the lenders' requirements, the means of securing financing, and the advantages and
disadvantages of each of the four major financing approaches. Two other potential financing
methods - lease financing and public debt financing - are also discussed briefly.
6.2.1 Private Equity Financing
Historically, private equity financing has been one of the most widely used methods of
financing landfill gas energy projects. In order to use private equity financing, an investor
must be located who is willing to take an ownership position in the landfill gas energy project.
In return for a significant share of project ownership, the investor is willing to fund part or all
of the project costs using its own equity or privately placed equity or debt. Some landfill gas
developers are potential equity investor/partners, as are some equipment vendors, fuel
suppliers, and industrial companies. Investment banks are also potential investors. The
advantages and disadvantages of private equity financing are presented in Box 6.1. The
primary advantage of this method is its availability to most projects; the primary disadvantage
is its high cost.
Equity investors typically provide equity or subordinated debt for projects. Equity is
invested capital that creates ownership in the project, like a down-payment in a home
mortgage. Equity is more expensive than debt, because the equity investor accepts more risk
than the debt lender. (Debt lenders usually require that they be paid before project earnings
get distributed to equity investors.) Thus the cost of financing with equity is usually
significantly higher than financing with debt. Subordinated debt gets repaid after any senior
debt lenders are paid and before 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.
Part II September 1996 Page 6-4
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Table 6-1 Addressing Landfill Gas Energy Project Risks
Risk Category
Risk Mitigation Measure
Landfill gas availability
• Drill test wells, monitor samples
• Hire expert to report on gas availability
• Model gas production over time
• Execute gas delivery contract/penalties with landfill owner
• Provide for back-up fuel if necessary
Construction
Execute fixed-price turnkey contracts
Include monetary penalties for missing schedule
Establish project acceptance standards, warranties
Equipment performance
Select proven technology
Design for landfill gas Btu content
Design to take landfill gas impurities into account
Get performance guarantees, warranties from vendor
Include major equipment vendor as partner
Select qualified operator
Environmental permitting
Obtain permits prior to financing (air, water, building)
Plan for condensate disposal
Community acceptance
Purchase site, sign lease, execute option agreement
Obtain zoning approvals
Demonstrate community support
Power sales agreement
(PSA)
Have signed PSA with local utility, or industrial plant
Match PSA pricing, escalation to project expenses
Where possible, get capacity payment to cover fixed costs
Get sufficient term to match debt repayment schedule
Confirm interconnection point, access, requirements
Make sure online date is achievable
Include force majeure provisions in PSA
Energy sales agreements
• Match energy pricing and escalation to project costs
• Limit liability for interruptions, have back-up
• Include industrial firm, fuel company as partner
(see PSA items above)
Financial performance
Create financial pro forma
Calculate cash flows, debt coverages
Commit equity to the project
Ensure robust ROR
Maintain working capital, reserve accounts
Budget for major equipment overhauls
Part II
September 1996
Page 6-5
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Box 6-1 Private Equity Financing - Advantages/Disadvantages
Advantages
• For some power projects under 20 MW without access to municipal bonds,
this may be the only means of obtaining financing.
• Transaction costs are usually less than with project financing or bond
financing.
• Equity partners can often move faster than commercial lending institutions,
enabling tight project schedules to be met.
• Bringing in an equity or subordinated debt partner is an effective means of
risk-sharing, provided that the risk allocation is reflected in the project
structure.
Disadvantages
• Equity is expensive; returns on equity will be paid to the investor out of
project cash flows.
• Project owners will have to give up some project ownership and control to
an equity investor.
• The addition of a subordinated debt partner can complicate the financing
process if project financing is being used.
• A partner who is an equipment vendor, fuel company, or industrial company
might have different objectives than the landfill owner (e.g., operation for
optimum emissions control may not be a priority).
Investor's Requirements
The equity investor will conduct a thorough due diligence analysis to assess the likely
ROR associated with the project. This analysis is similar in scope to banks' analyses, but is
often accomplished in much less time because of the entrepreneurial nature of equity
investors as compared to institutional lenders. The equity investor's due diligence analysis
will typically include 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 diligence analysis, combined with the cost and
operating data for the project, will enable the investor to calculate 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 project's installed
cost, often with the expectation that additional equity or debt investors will be located later.
Some types of partners that might provide equity or subordinated debt may have
unique requirements. Potential partners such as equipment vendors, fuel suppliers, and
industrial companies generally expect to realize some benefit other than just cash flow. The
Part II September 1996 Page 6-6
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desired benefits may include equipment sales, service contracts, tax benefits, and economical
and reliable energy supplies. For example, an engine 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 fuel supplier might also become an equity partner to
gain access to a low-cost gas supply, or a nearby industrial company might want to gain
access to fuel or derived energy. The requirements imposed by each of these potential
investors are sure to include not only an analysis of the technical and financial viability, but
also a consideration of the unique objectives of each investor.
Securing Private Equity Financing
To fully explore the possibilities for private equity or subordinated debt financing,
landfill owners should ask potential developers if this is a service they can provide. The
second most common source of private equity financing is an investment bank that
specializes in the private placement of equity and/or debt. Additionally, the equipment
vendors, fuel companies, and industrial companies that are involved in the project may also
be willing to provide financing for the project, at least through the construction phase. The
ability to provide financing is often an important consideration when selecting a developer,
equipment vendors, and/or other partners.
6.2.2 Project Finance
"Project finance" is a method for obtaining commercial debt financing for the
construction of a facility, where lenders look at the credit-worthiness of the facility to ensure
debt repayment rather than at the assets of the developer/sponsor. 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. Project finance usually provides the
option of either a fixed rate loan or a floating rate loan, which is tied to an accepted interest
rate index (e.g., U.S. treasury bills, London Interbank rate). Typically, the facility sponsor(s)
will set up a separate subsidiary company to develop and manage the facility, and lenders in
effect provide financing to the subsidiary company with limited or no recourse to the
subsidiary's parent(s). Thus project financing is often known as "nonrecourse" financing
because the project debt is secured by facility assets and contracts, with no recourse (or
limited recourse) to parent companies should the facility experience financial under-
performance or failure.
Most private power projects, especially those built in the last 15 years by third-party
developers, were completed using project finance. The major advantages and disadvantages
of project finance are listed in Box 6.2. The biggest advantage of project finance is the ability
to use others' funds for financing, without giving up ownership control. The biggest
disadvantages are the difficulty of obtaining project finance for landfill gas projects, which
tend to be smaller than traditional power projects. In addition, project finance transactions
are costly and often an onerous process of satisfying lenders' criteria.
Lenders' Requirements
In deciding whether or not to provide project finance to a power project, lenders
examine not only the expected financial performance of the project; they also consider
several other factors that underlie facility success such as contracts, project participants,
equity stake, permits, technology, and sometimes market factors. A good candidate for
project financing should have most, if not all, of the following:
Part II September 1996 Page 6-7
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Box 6-2 Project Finance - Advantages/Disadvantages
Advantages
• Project debt is usually nonrecourse to the landfill owner and/or energy
project sponsor; however, the owner and sponsor remain liable for explicit
warranties and misrepresentations.
• The project debt can usually be kept off the project sponsor's balance sheet.
• Project sponsors can retain sole or majority ownership of the landfill energy
project.
Disadvantages
• The small capital requirements of landfill gas projects relative to other power
projects can make project financing difficult to obtain, because transaction
costs and risk perceptions remain high.
• Lenders usually require most key contracts and permits to be in place on or
before financial closing, which adds to project lead time.
• Lenders may place other requirements on the project such as minimum
equity contribution, minimum debt coverage, and creation of a major
maintenance fund.
• Debt must usually be repaid over an 8 to 15 year term.
• Signed energy sales agreement from a credit-worthy electricity or gas customer
(e.g., utility, industrial, municipality)
• Fixed-price agreement with engineering/construction firm(s)
• Equity commitment
• Operation and maintenance agreement
• Fuel supply analysis and supply/transport agreement(s)
• Control of the project site (e.g., option agreement or ownership)
• Environmental permits
Local permits/approval
In addition, lenders may place additional requirements on the project developers such as
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.
In addition, in cases where project finance is used, lenders generally expect the
project sponsors to make some equity commitment of their own. An equity commitment
shows that project sponsors also have a financial stake in project success, and it implies that
sponsors will be more likely to step in with additional funds if problems arise. The expected
debt-equity ratio is usually a function of project risks. In the mid-1980s, some power projects
obtained project financing with little or no equity contribution, based mainly on the financial
strength of the project and supporting contracts. However, most lenders now do not accept
Part II September 1996 Page 6-8
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such highly leveraged projects and instead require at least a 20% equity stake on the part of
project sponsor(s).
Securing Project Financing
Landfill gas projects have historically experienced some difficulty securing project
financing, because of their relatively small size and the perceived risks associated with the
technology. In addition, the transaction costs for arranging project financing are relatively
high, owing to the lender's extensive due diligence (i.e., financial and risk investigation)
requirements; it is often said that the transaction costs may be the same for a 10 MW project
as for a 100 MW project. For this reason, most of the project finance groups at the large
commercial banks and investment houses hesitate to lend to projects with capital
requirements less than about $20 million (or a 20 MW or larger power project).
The best opportunities for landfill gas projects to secure project financing are generally
with the project finance groups at smaller investment capital companies and banks, or at one
of several energy investment funds that commonly finance smaller projects. Some of these
lenders have experience with landfill gas projects and may also be attuned to the unique
needs of smaller projects. Depending on the project economics, some investment capital
companies and energy funds may consider becoming an equity partner in the landfill gas
project in addition to, or instead of, providing debt financing. Additionally, it is worth
contacting local and regional commercial banks. Some of these banks have a history of
providing debt financing for small energy projects, and may be willing to provide project
financing to a "bundle" of two or more landfill gas projects.
6.2.3 Municipal Bond Financing
Municipally owned landfills occasionally issue tax-preferred municipal bonds to finance
landfill gas energy projects. The biggest benefit of using this financing method is that the
resulting debt has an interest rate that is often 1 % to 2% below commercial debt or taxable
bond debt (see Box 6.3). For a bond issue to qualify for tax-exempt status, a number of
complex IRS conditions concerning project ownership and purpose must be met.
Additionally, state-specific laws and policies may also impact the ability to issue tax-exempt
bonds. Since the rules governing the applicability of tax-exempt bond financing are complex,
it is wise to consult the IRS tax code and a tax expert before deciding on a particular
approach.
The important factors in qualifying for and obtaining municipal bond financing are
described below.
Lenders' Requirements
Generally speaking, a government entity (e.g., municipality, public utility district, county
government) can issue either tax-exempt governmental bonds or private activity bonds, which
can be either taxable or tax-exempt. Bonds can either be secured by general government
revenues (i.e., revenue bonds), or by the specific revenues from the energy project (i.e.,
project bonds). The term for bond financing usually does not exceed the useful life of the
facility; terms extending up to 30 years are not uncommon, however.
In addition to initial qualification requirements, many tax-exempt bond issuers find that
strict debt coverage and cash reserve requirements must be imposed on an energy project to
Part II September 1996 Page 6-9
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Box 6-3 Municipal Bond Financing - Advantages/Disadvantages
Advantages
• Tax exempt financing provides access to debt at interest rates that are 1 % to 2%
below the rates offered by commercial lenders.
• Debt repayment can be extended over the life of the facility, which may be 20
years or more.
Disadvantages
• The financial performance requirements (e.g., debt coverage, cash reserves)
placed on the project by the bond issuer may exceed project finance lender's
requirements.
• Public disclosure requirements exist.
• The project may have to contend with state caps on the amount of private activity
bonds that can be issued.
• It is difficult to obtain additional capital for the project in cases where the design,
equipment, or other conditions change.
ensure that the financial stability of the issuer is preserved. These requirements may be even
more rigorous than those imposed by commercial banks under a project finance approach.
Securing Municipal Bond Financing
To qualify for a governmental bond issue, a project must meet at least two criteria:
(1) Private business use test - No more than 10% of the bond proceeds are to
be used in the business of an entity other than a state or local government.
(2) Private security of payment test - No more than 10% of the payment of
principal or interest on the bonds can be directly or indirectly secured by
property used for private business use.
Under these rules, a government entity could issue tax-exempt governmental bonds to
finance a landfill gas energy project if the project would be owned and operated by the same
government entity. If private owners or operators are involved, however, the project may not
qualify for tax-exempt governmental bond status [Snohomish, 1994; Martin, 1993]. Private
business use can include private ownership of all or part of a landfill gas project.
If a particular project fails to qualify for a governmental bond issue, it may still achieve
tax-exempt bond status through one of several exemptions for projects that provide some
form of public benefit. Among these exemptions are at least two that could apply to certain
landfill gas projects with partial private ownership [Kulakowski, 1994; Martin, 1993]:
Part II September 1996 Page 6-10
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Local furnishing of electricity - Tax-exempt status is provided for a power project that
sells electricity to a utility (public or investor-owned) that is a net importer of power
and serves no more than two contiguous counties or one county and one contiguous
city. It is unclear whether or not the financing for the landfill gas extraction/collection
portion of the project can be included in this exemption.
Local district heating and cooling - Tax-exempt status is provided for an energy
project that sells steam, chilled water, and/or other thermal energy to two or more
unrelated entities, which must be within two counties. The exemption covers the
equipment used to generate the thermal energy.
Two additional exemptions may be applicable to landfill gas projects, although it is
unknown whether any landfill gas projects have successfully used these exemptions:
Prepayment of fuel supply - Tax-exempt status is provided for a governmental entity
that purchases a long-term fuel supply such as gas reserves. Tax-exempt status
covers only the purchase of fuel supplies that are used in electric generation which
serves a governmental entity.
Solid waste disposal - Tax-exempt status is provided for facilities that burn solid
waste fuel that has no market value as a saleable product.
The mechanics of issuing municipal bonds vary according to the type of bond,
method of qualification, and the state or municipality in which the bond is issued. Qualified
local tax or financial experts should be consulted for guidance.
6.2.4 Direct Municipal Funding
Landfill gas energy recovery projects can also be funded directly through the
operating budget of a city, county, landfill authority, or other municipal government. Using
this method, the costs of project development, equipment, and installation are expensed
directly from the municipal budget, thus eliminating the need for outside financing or
partnering. Typically this method is used to fund small projects that fit within the
municipality's budget capabilities and priorities. Advantages and disadvantages are
described in Box 6.4.
6.2.5 Lease Financing
Lease financing encompasses several leasing strategies in which the project
operator/equipment user leases part or all of the energy project assets from the asset
owner(s). Typically, lease arrangements provide the advantage of enabling the transfer of 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 predetermined
time 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 external debt and possibly
equity.
Part II September 1996 Page 6-11
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Box 6-4 Direct Municipal Funding - Advantages/Disadvantages
Advantages
• The need to meet tough lender's requirements (e.g., debt coverage, equity
input, credit-worthiness, contracts in place) is eliminated, although any
municipal funding criteria must still be met.
• Expensing the project's funding requirements directly from the municipal
budget will eliminate interest charges on project debt, making this generally
the lowest-cost financing method.
• The project is not subject to delays caused by lenders' time requirements for
evaluating the project and setting up the financing.
Disadvantages
• Usually the amount of municipal funds are limited, thus limiting the size of the
project.
• The municipality loses the opportunity to share risks with other project
partners.
• A public approval process may be required, making the project vulnerable to
political forces.
Sale-Leaseback - In a sale-leaseback, the equipment user buys the equipment, then
sells it to a corporation, which then leases it back to the user under contract.
Some of the disadvantages of lease financing include accounting and liability
complexities, as well as the loss of tax benefits by the project operator/user.
6.2.6 Public Debt Financing
Financing power projects with public debt such as secured notes and bonds offered
to institutional investors has recently received much attention from developers of large,
conventional-fueled power projects. This approach is not likely to be an option for the typical
landfill gas project, however, unless several high-quality landfill gas projects can be
"packaged" together under single ownership. In this case, the debt could be raised for the
package of projects through a single offering, and due diligence costs would be minimized by
standardizing the projects. In order to qualify for public debt financing, a project must be
rated at or near investment grade by rating agencies, have solid supporting contracts, and be
large enough - approximately $100 million or more - to offset the transaction costs.
6.3 CAPITAL COST EFFECTS OF FINANCING ALTERNATIVES
Each financing method produces a different weighted cost of capital, which affects the
amount of money that is spent to pay for a landfill gas power project and the price that is
Part II September 1996 Page 6-12
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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). For example, in a project finance scenario with a
debt/equity ratio of 80/20, an interest rate on debt of 9%, and an expected ROR on equity cf
15%, the weighted cost of capital is 10.2%. Decreasing 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 revenues 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.
Among the four main financing methods presented above, direct municipal funding
usually produces the lowest financing costs over time, while private equity financing produces
the highest. Generally speaking, the four financing methods are ranked from lowest cost to
highest cost as follows:
1) Direct municipal funding
2) Municipal bond financing
3) Project financing
4) Private equity financing
The advantage associated with direct municipal funding is created by the elimination
of interest on debt, and by the low expected ROR. Municipal bond financing achieves its
advantage through access to low-interest debt - assumed to be currently about 6.5% for tax-
exempt bonds and 8.25% for taxable bonds [Snohomish, 1994]. Project finance produces a
higher capacity price because funds are required to pay interest charges as well as ROR on
equity (assumed to be 15%). Finally, private equity is the most expensive because it usually
demands a higher ROR (assumed to be 18%) on equity than project finance, and equity
makes up a larger share of the capital requirement.
Interest rates are an important determinant of project cost if the project sponsor
decides to borrow funds, either through lending institutions or bond offerings, 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 landfill gas project. Interest rates are
determined by the prevailing rate indicators at a particular time, as well as by the project and
lender's risk profiles. The interest rate for fixed-rate nonrecourse debt is usually determined
by the lender's "spread" over an index such as U.S. treasuries. Likewise, the interest rate for
floating-rate nonrecourse debt is based on a spread above variable indices such as the prime
rate or the London Interbank Offered Rate (LIBOR). The lender's spread varies widely, but a
landfill gas project with reliable gas availability, experienced participants, and a strong power
purchase contract might expect a spread of 2.0% to 2.75% above the index. [Seifullin, 1995;
DePrinzio, 1995]. Smaller projects requiring less than roughly $5 million of nonrecourse debt
could also expect to pay an interest rate premium to compensate the lender for
disproportionate transaction costs.
Table 6-2 illustrates the economic impact of different financing methods for the 5
million metric ton landfill example described in Chapter 5, which showed an 1C engine power
project with a capital cost of $1,675/kW. As Table 6-2 indicates, the levelized capacity price is
more than doubled when comparing the low-cost municipal budget method with the high-cost
private equity method (20% debt and 80% equity). [The capacity price refers to the initial cost
of financing and building the project, levelized over the project life. This is the interest rate-
Part II September 1996 Page 6-13
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sensitive portion of the project cost. Note that O&M and royalty expenses must be added, as
described in Chapter 5, to determine the total project cost.] The more common private equity
structure is the 50% debt case, and the more common project finance structure is the 80%
debt case.
Table 6-2 Capital Cost Effects of Financing Approaches
Case: 5 million metric ton landfill (waste-in-place)
5 MW 1C engine electric generating project
Installed Capital Requirement: 1 ,675 $/kW
Annual full load operating hours 7,008
Financina Method
Private Equity Financing
20% Debt/80% Equity
50% Debt/50% Equity
Project Finance
70% Debt/30% Equity
80% Debt/20% Equity
Municipal Bond Funding
Taxable Bond
Tax-Exempt Bond
Municipal Budget
Interest
Rate
on
Debt
9.00%
9.00%
9.00%
9.00%
8.25%
6.50%
NA
After-tax
Return
on
Equity
18%
18%
15%
15%
NA
NA
5%
Weighted
Cost
of
Capital
16.20%
13.50%
10.80%
10.20%
8.25%
6.50%
5.00%
Capital
Charge
Rate
0.225
0.182
0.145
0.136
0.124
0.111
0.100
Levelized
Capacity
Price
Required
(C/kWh)a
5.38
4.35
3.47
3.25
2.96
2.65
2.39
Notes:
a Levelized Capacity Price (c/kWh) =
(Installed Capital Requirement) x (Cap Charge Rate)/(Annual hours)
This price only represents the capital
O&M and royalties must be added to
cost portion of the project; other
get to a total project cost.
expenses
such as
Part
September 1996
Page 6-14
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7. SELECTING A PROJECT DEVELOPMENT PARTNER
The selection of a project
development partner is a critical decision
because the landfill owner often relies on
the developer to manage the process of
transforming a landfill energy project from a
feasible idea on paper into a functioning,
multi-million dollar facility. Some landfill
owners have the expertise, resources, and
desire to lead the development effort on
their own, but even in this case, choosing
the right development partner(s) can greatly
improve the likelihood of project success.
This chapter provides guidance to landfill
owners who are attempting to determine: (1)
the role that they might take in the
development process; and (2) the right
partner to get the project developed,
financed, and built.
From the landfill owner's perspective,
there are three general ways to structure the
development and ownership of a landfill gas
energy project:
The Project Development Process
Parti
Preliminary Assessment of
Project Options
Determining if a Project is Right for Your Landfill
Determining What Project Configuration is Right
for Your Landfill
I
Part II
Detailed Assessment of
Project Economics
Evaluating Project Economics
Assessing Financing Options
Winning/Negotiating an Energy Sales Contract
Securing Project Permits and Approvals
Contracting for EPC and O&M Services
(1) Develop the project internally
- Landfill owner manages the
development effort and
maintains ownership control
of the project. This approach maximizes economic returns to the owner, but
also places most of the project risks on the owner (e.g., construction,
equipment performance, financial performance).
(2) Team with a pure project developer - Landfill owner selects a qualified
developer to develop and build the project. This option shifts most risks onto
the developer, but the landfill owner usually gives up control, ownership rights,
and some or all of the potential for financial returns. A variation on this option
is selecting a developer to provide the landfill owner with a "turnkey" plant,
which is built by the developer but owned by the landfill owner.
(3) Team with a partner - Landfill owner teams with an equipment vendor,
engineering/procurement/construction (EPC) firm, industrial company, or fuel
company to develop the project and to share the risks and financial returns.
With these structures in mind, a landfill owner can determine his or her desired role in
the project development process by considering two key questions:
• Should the landfill owner self-develop or find a partner?
Part
September 1996
Page 7-1
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• If a partner is desired, what kind of partner best complements the landfill owner
and the project?
The landfill owner can answer the first question by conducting a frank examination of his or
her own expertise, objectives, and resources. The second question is more complicated
because it entails an assessment of the landfill owner's specific needs and a search for the
right partner to complement those needs.
Figure 7.1 illustrates the process of determining the best development approach. As it
indicates, in cases where the landfill 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.
7.1 THE PARTNER/NO PARTNER DECISION
Before deciding whether to develop the project internally, the landfill owner must
understand the role of the project developer, which is outlined in Box 7.1. Next, an
assessment of the landfill owner's objectives, expertise, and resources will determine whether
or not the owner should undertake project development independently or include a
partner/developer. A landfill owner who is a good candidate for developing a project alone
will have many of the following attributes:
• strong desire to develop a successful, profitable energy project;
• willingness to accept project risks (e.g., construction, equipment, permitting,
financial performance);
• expertise with technical projects (e.g., power, infrastructure, or industrial) or
energy equipment;
• high confidence level regarding landfill gas quantity and quality (i.e., modeling
or test wells have been completed);
• possession of a power sales agreement with a local electric utility, an electric
consumer, a gas purchaser, or sufficient internal demand; and
• funds and personnel available to commit to the development process.
In addition, other attributes may improve a landfill owner's likelihood of success in
developing a project in-house. Ownership or control of multiple landfills, for example, may be
desirable because it will enable the owner to leverage his/her time and resources spent.
Similarly, a strong desire for new business opportunities and/or visibility may be beneficial.
An example of the type of landfill owner that fits this profile is a municipal utility district that
might have responsibility for local electricity procurement and distribution, water supply,
and/or sewage treatment, in addition to landfill management.
11 the landfill owner is uncertain about several of the attributes listed above, particularly
the desire to develop, the willingness to take significant risks, and/or their level of technical
Part II September 1996 Page 7-2
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Figure 7.1 The Developer/Partner Selection Process
Determine Economic
Viability of
Project
Funds
and/or
Personnel
Available
No
No
"Pure"
Developer
Option
Decreasing Landfill/Owner's Risk
Part II
September 1996
Page 7-3
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Box 7.1 The Role of the Project Developer
Determine Landfill Gas Supply - If the landfill owner has not already completed this
step, then the first development step will be to determine the landfill gas supply using
calculations, computer modeling, and/or test wells.
Scope Out the Project - Project scoping includes early-stage tasks such as selecting a
location for the equipment, sizing the energy output to the landfill gas supply,
contacting potential energy customers, and selecting key equipment.
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.
Prepare the Bid - If the project must bid in a utility solicitation in order to obtain a
power sales agreement (PSA), a responsive bid package will be prepared and
submitted.
Negotiate the Power Sales Agreement (PSA) - The terms of the PSA must be
negotiated with the purchasing electric utility.
Negotiate the Gas or Steam Sales Agreements - For projects that intend to sell landfill
gas or steam, agreements must be negotiated with the energy customers.
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).
Negotiate Partnership Agreement(s) - If project ownership is to be shared with partners
or investors, then the project will require negotiation of ownership agreements.
Secure Financing - Securing financing for the project is a critical task that requires
specific expertise, depending on the type of financing being used.
Contract with Engineering, Construction, Operating Firms - Firms must be selected
and contracts and terms negotiated.
Part II September 1996 Page 7-4
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expertise, then he or she might instead choose a partner. The following are several good
reasons to develop the project with a partner:
• limited desire to lead the development effort;
• 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 organizational charter; and
• difficulty spending funds to determine landfill gas quantity.
The questions in Figure 7.1 illustrate other critical considerations in making the partner/no
partner decision.
Most landfill owners choose to bring in a developer to build and/or own the energy
recovery project, either alone or in partnership with the landfill owner or others. A recent
survey of existing and planned landfill gas energy recovery projects shows that about 78% of
gas collection systems and 88% of gas processing/energy recovery systems are owned by
private firms or in partnership with private firms [Berenyi and Gould, 1994].
7.2 SELECTING A DEVELOPMENT PARTNER
Once the decision has been made to include a project development partner, the next
step is to decide what type of partner to select. There are several different types of
development partners to choose from, so the landfill owner should look for a partner that
provides the best match for the specific energy project and the landfill owner's in-house
capabilities. Five general types of project development partners, listed in order of decreasing
scope of services, include:
Pure Developer - A firm primarily in the business of developing, owning, and/or
operating landfill gas energy projects. Some developers focus on landfill gas power
projects, while others may be involved in a broad project portfolio of technologies and
fuel types. Pure developers usually will own the completed landfill gas energy facility,
but sometimes a developer will build a turnkey facility for the landfill owner.
Equipment Vendor - A firm primarily in the business of selling power or energy
equipment, although it will participate in project development and/or ownership in
specific situations where its equipment is being used. The primary objective of this
type of developer is to help facilitate purchases of its equipment and services.
EPC Firm - A firm primarily engaged in providing engineering, procurement, and
construction services. Some EPC firms have project development groups that develop
energy projects and/or take an ownership position.
Part II Septemoer 1996 Page 7-5
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Fuel Company - A firm primarily engaged in providing fuels and/or fuel procurement
services. These firms may have project development subsidiaries or agree to take a
specific development role such as securing a customer for the landfill gas.
Industrial Company - A firm primarily engaged in manufacturing a product and
managing an industrial manufacturing facility. Some industrial firms have power
project development subsidiaries or may take a specific role such as guaranteeing
energy purchases or assisting with financing.
Ideally, a developer or partner can be identified that fills specific project needs such as ability
to secure a power purchase contract, finance the project, or supply equipment. Issuing a
request for proposals (RFP) is often a good way to attract and evaluate partners.
A partner reduces risks to the landfill owner by bearing or sharing the responsibilities
of project development, although the amount of risk reduction provided depends on the type
of partner chosen. For example, a "pure developer" partner will usually take the
risk/responsibility of construction, equipment performance, environmental permitting,
community acceptance, energy sales agreements, and financing, whereas an equipment
vendor partner may only bear the risks of equipment performance.
7.2.1 Selecting a Pure Developer
Selecting a pure project developer to manage the development process and own the
landfill gas energy project is a good way for the landfill owner to shed development
responsibility and risks, and get the project built at no net cost to the landfill. In addition, the
pure project developer typically provides the landfill owner with the strongest development
skills and experience, since pure developers focus exclusively on landfill gas projects. Other
reasons for selecting a pure project developer include:
• the developer's skills and experience may be invaluable in bringing a
successful project online;
some developers are ready to invest equity or have access to financing; and
• the developer might be in possession of a power sales agreement that was
previously won and/or negotiated with a nearby electric utility.
In return for accepting project risks, most developers require a significant share of
project profits, potentially up to 100 percent. As a result, the landfill owner generally loses
control and ownership of the energy project. Such an ownership arrangement may be
appropriate for a particular landfill if, for example, development of an energy recovery system
is the lowest cost method for complying with environmental regulations. It may also be
necessary to involve a developer in order to take advantage of IRS Section 29 tax credits (see
Chapter 5 for more on tax credits). If the developer becomes the sole or controlling owner,
" however, he/she will tend to make decisions to protect his/her interest in the project, namely
the energy revenues, and may be less concerned with the landfill owner's priorities such as
controlling landfill gas migration.
The case of the I-95 Landfill in Lorton, Virginia illustrates the key issues involved in
taking the pure developer approach. As described in Box 7.2, this landfill partnered with a
pure developer to develop a successful energy recovery project. By carefully structuring its
Part II September 1996 Page 7-6
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Box 7.2 Developer Selection at 1-95 Landfill
The 1-95 Landfill Project in Lorton, Virginia illustrates one landfill owner's
successful experience in selecting a project developer. The 1-95 Landfill Project is a
17.5 million ton sanitary landfill that supports a 6,400-kw electric generating system,
using 8 Caterpillar internal combustion engines. The landfill gas collection system is
owned and operated by Fairfax County and the electric generating equipment is owned
by Landfill Energy Systems, a division of Michigan Cogeneration Systems.
Fairfax County found that selecting a pure developer resulted in the successful
completion of the landfill gas power project. Fairfax County hired a consultant to
assess the landfill gas quantity and quality, then issued a request for proposals (RFP)
to select a project developer. The developer ultimately selected to build the project had
experience with other landfill gas projects, a power sales agreement with the local utility,
and the ability to finance the project.
A thoughtful contracting approach eliminated potential conflicts between the
developer and landfill owner. Fairfax County was most concerned with controlling
landfill gas migration and emissions, while the developer wanted to optimize gas output
for power generation. The two parties recognized that the best gas collection strategy
for minimizing gas migration is often different from the strategy that maximizes power
output. In a worst case scenario where an uncooperative developer owns the gas
collection system, a landfill owner might be forced to drill collection wells at the landfill
perimeter to control offsite migration, which could draw gas away from the developer's
collection wells. To avoid this potential scenario, Fairfax County opted to keep control
of the entire collection system and now supplies landfill gas to Landfill Energy Systems'
electric generating equipment
contract with the developer, the landfill owner was able to ensure that safety and other
concerns were given top priority by the developer.
Arranging for a turnkey project represents a variation on the pure developer approach.
The turnkey option is a good approach if the landfill owner wants to retain energy project
ownership or the project's return on investment does not meet the developer's criterion. In a
turnkey approach, the developer assumes development responsibility and construction risk,
finances and builds the facility, and then transfers ownership to the landfill owner when the
facility is complete and performing up to specifications. In return, the developer can receive a
fee, a share of project proceeds, gas rights, and/or a long-term operation and maintenance
contract. Sometimes the landfill owner will use municipal bonds to finance the project, so the
developer essentially develops and builds the project for a fee. The turnkey approach
enables each entity to contribute what it does best: the developer accepts development,
construction, and performance risk; and the owner accepts financial performance risk.
7.2.2 Selecting a Partner (Equipment Vendor, EPC Firm, Fuel Firm, Industrial)
Selecting a development partner who is not a pure developer is a good choice if two
key conditions exist:
Part II September 1996 Page 7-7
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(1) The landfill owner wants to keep management control of the project and has
sufficient in-house expertise and resources to do so; and,
(2) The partner can fulfill a specific role or provide equipment for the project.
in this case, the landfill owner must have a clear desire to manage the development process
and should have sufficient technical experience, personnel, and development funds to
support the development effort. The owner should also have a relatively high confidence
level regarding landfill gas production capability, as well as a willingness to accept a
significant share of the project's risks (e.g., financial, environmental permitting, community
acceptance). Other factors that could make the partnering approach an appropriate choice
include the ownership of a power or energy purchase agreement, or control of multiple
landfills that could each be developed into a landfill gas project, thus leveraging the time and
resources invested.
There are four basic types of firms that enter into partnership agreements with landfill
operators: equipment vendors, EPC firms, fuel suppliers, and industrial companies. Each of
these firms have different strengths and will assume different types of project risk. The key
characteristics of these types of firms are summarized below.
Equipment vendors: Some equipment vendors such as engine and turbine
manufacturers become partners in energy projects, including landfill gas projects, as a
way to support the sale of equipment and services to potential customers. Equipment
vendors may assist in financing the project, and are often willing to accept the
equipment performance risk over a specified length of time for the equipment that they
provide. However, equipment vendors typically do not take on responsibilities beyond
their equipment services, and they generally want to sell their interest in a project as
quickly as possible after the project has been built.
EPC firms: Similarly, some of the larger EPC firms will become partners in power
projects with the objective of selling services and gaining a return on equity and/or
time invested. However, this type of potential partner tends primarily to pursue large
fossil-fueled projects where the EPC's strength as a manager of large, complex
projects is more valuable.
Fuel suppliers: A fuel supplier or marketing company can be a potential development
partner in landfill gas projects where marketable gas is the energy product for sale.
For example, a local natural gas distribution company might become a partner to gain
access to a local, low cost gas supply. This type of partner would typically take a very
limited role such as guaranteeing a market for the landfill gas or owning the gas
collection and processing systems. However, several natural gas suppliers and
pipeline companies also have power project development subsidiaries that resemble
pure developers in terms of experience and capabilities, and that may be willing to
take on a larger role in the project.
Industrial companies: Finally, an industrial company might become a partner in the
landfill gas project if it has significant use for the landfill gas or derived energy (i.e.,
electricity, steam). The industrial company is likely to prefer a limited involvement in
the development process.
Part II September 1996 Page 7-8
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7.3 EVALUATING INDIVIDUAL FIRMS
Once the right partnering strategy has been identified, the landfill owner should review
the capabilities of individual firms that meet the owner's general needs. When selecting a firm
to become a development partner, there are several qualities and capabilities that landfill
owners should look for, including:
previous landfill gas project experience;
• a successful energy project track record;
• access to capital and/or financing; and
• in-house resources (e.g., engineering, finance, operation) including experience
with environmental permitting and community issues.
Information about individual firm qualifications can be gained from annual reports, brochures,
and project descriptions, as well as from discussions with references, other landfill owners,
and engineers. Potential warning signs include lawsuits, disputes with landfill owners, and
failed projects, although a few failed development efforts and/or underperforming projects can
normally be found in the portfolio of any project developer. Published information can be
obtained by researching trade literature, through legal information services, and through
computer research services.
7.3.1 Issuing a Request for Proposals (RFP)
A landfill owner may find it advantageous to issue an RFP for a developer or partner,
because if the RFP is prepared correctly, respondents will generally offer creative, informative,
and useful responses. The RFP process is a good way to screen proposals and focus on the
best one(s) for further discussions and negotiation.
A landfill owner who plans on issuing an RFP should carefully examine his needs and
ask respondents to propose ways to meet those needs or solve problems. For example, if a
landfill gas energy project needs a power sales agreement or energy sales contract, then the
landfill owner should state in the RFP that the ability to secure one of these agreements is a
central selection criterion. Likewise, if ability to secure financing or environmental permits is
important, that should also be stated in the RFP. In this way, respondents will be encouraged
to offer innovative proposals that meet the project's specific needs.
In general, RFP respondents should be asked to provide the following information:
• Description of the energy project and available options;
Scope of services being offered (e.g., developer, owner, operator);
Project development history and performance;
• Pricing and escalation (e.g., royalties/payments to landfill owner, electricity
price, energy prices) including buyout price and terms;
• Turnkey facility bid (if appropriate);
Part II September 1996 Page 7-9
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• Plan for obtaining energy revenues (e.g., PSA with utility, gas sales contract,
steam contract);
• Technology description and performance data;
• Well placement strategy (if applicable);
• Well field operations responsibility;
• Responsibility for environmental compliance;
• Environmental permitting and community approval plan;
• Financing plan;
• Schedule; and
• Operation and Maintenance plan.
Landfill owners should state in the RFP that the owner reserves the right to select
none, one, or several respondents for further negotiation, depending on the proposal's
responsiveness to the owner's criteria. Appendix D contains a sample RFP that was issued
by one landfill. This particular RFP is not very detailed; therefore, the respondent would have
some leeway in preparing his or her bid package.
7.3.2 Preparing a Contract
Once the partner has been selected, the terms of the partnership should be formalized
in a contract. The contract should accomplish several objectives, including allocating risk
among project participants. Some of the key elements of a partnership contract are listed in
Box 7.3.
As Box 7.3 indicates, contracting with a developer or partner in a landfill gas energy
project is 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,
it is imperative that the landfill owner consult in-house counsel or hire a qualified attorney to
serve as a guide through the contracting process.
Part II September 1996 Page 7-10
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Box 7.3 Elements of a Partnership Contract
The contract between the landfill owner and the developer or partner should
describe in detail the responsibilities 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 development responsibility;
• Decisionmaking 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;
• Schedule and milestones;
• Termination rights clause;
• Buy-out price; and
• Remedies/arbitration procedures.
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Page Intentionally Left Blank
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8. WINNING/NEGOTIATING AN ENERGY SALES CONTRACT
The Project Development Process
Parti
Preliminary Assessment of
Project Options
Determining rf a Project is Right for Your Landfill
Determining What Project Configuration is Right
for Your Landfill
I
Part II
Detailed Assessment of
Project Economics
Evaluating Project Economics
Assessing Financing Options
Selecting a Project Development Partner
An energy sales contract will
determine the success or failure of a project,
since it secures the project's source of
revenue. Therefore, successfully obtaining
a contract is the crucial milestone in the
project development process. This chapter
provides a guide to the issues involved in
bidding for, winning, and negotiating an
energy sales contract. Because contract
negotiation is often a complex process,
owner/operators and developers may want
to consult an expert for further information
and guidance.
Depending on the configuration of
the landfill gas-to-energy project, one of two
types of energy sales contracts may be
obtained:
Power sales contract - A long-term
sales contract is necessary to ensure
revenues for power projects, and is
usually required to obtain financing.
The power sales contract may be
negotiated with an electric utility
and/or a local end user. Additionally,
if the sales contract is with a utility
other than the one directly
interconnected to the project, then arrangements with the local utility will be necessary
to transport the power to the buyer. If the landfill gas-to-energy project will also sell
steam or thermal energy, then the project must have a steam sales contract with the
end user. Such contracts are directly negotiated between the project developer and
the end user.
Gas sales contract - A gas sales contract is required when medium- or high-Btu gas
sales are made. In cases where medium-Btu gas is sold as boiler (or other industrial
equipment) fuel, a contract between the gas purchaser and the project developer is
necessary. Such contracts are the result of direct negotiation. If high-Btu gas sales
are made, the gas sales contract is typically between the local gas distribution
company and the project developer, although a contract with a gas marketer is also
possible.
The majority (about 69%) of existing landfill gas-to-energy projects have obtained
power and gas sales contracts with investor-owned utilities. The remaining projects have
contracts with private sector customers such as industrial facilities (14%), government-owned
gas or electric utilities (8%), other public sector buyers, or subsidiaries of landfill gas plant
owners [Berenyi and Gould, 1994], These results are shown in Figure 8.1.
Securing Project Permits and Approvals
Contracting for EPC and O&M Services
Part II
September 1996
Page 8-1
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Figure 8-1 Types of Companies that Contracted with Landfill Gas Energy Recovery
Projects for the Purchase of Gas or Electricity in 1994
or
Investor Owned Electric/Gas Utility 68.9%
Government Owned Electric/Gas Utility 7.9%
Private Sector 13.7%
Subsidary of Owner 3.2%
Public Sector 6.3%
A landfill owner can either pursue a contract on its own or bring in an experienced
project developer who will take the responsibility of obtaining a contract. This chapter
provides insights on how landfill owners and project developers can win energy sales
contracts with appropriate energy buyers, and contains a detailed outline of a power sales
bid to an electric utility. Because the terms and conditions of the energy sales contract will
determine the project's long-term viability, critical contract provisions are also briefly
discussed.
8.1 POWER SALES CONTRACTS
There are two common types of power sales contracts: (1) standard offers and (2)
power sales agreements either negotiated or won through a competitive bidding process.
Figure 8.2 illustrates the steps involved in obtaining a power sales contract. As the figure
indicates, standard offer contracts with local utilities are generally preferred when they are
available at favorable terms. The majority of existing landfill gas power projects hold standard
offer contracts with their local utilities because in the past they have been the easiest to
obtain (however, standard offer contracts are disappearing and becoming more difficult to
obtain). In cases where standard offers are either not available or not appropriate, however,
power sales agreements may be sought. It is likely that the power sales agreement will be
sought from the local utility. However, it may be possible to negotiate an agreement with a
utility other than the one directly interconnected to the project, or to negotiate a contract with
an end use consumer.
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September 1996
Page 8-2
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Figure 8-2 Winning/Negotiating An Energy Sales Contract (Power Sales Agreement)
Determine Warty
Need for Power
A standard offer contract will
likely be the easiest to obtain.
Sign Contract
Develop Project
Design and Pricing
Prepare and Present
Bid Package
Utility needs may change, offering a
future opportunity to develop a project
Reevaluate
Prefect, Bid
Review Contract
Terms and Conditions
Contract negotiations with
the utility wiH rikety invoke
compromise on some terms
Part II
September 1996
Page 8-3
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Key issues related to power sales contracts are discussed below. Also discussed are
the considerations to be taken into account when the power sales contract is negotiated with
an entity other than the interconnected utility and wheeling arrangements are necessary.
8.1.1 Standard Offer Contracts
A standard offer contract is sometimes available from electric utilities that forecast a
need for additional generating capacity. The standard offer contract specifies the terms and
price that the utility will grant to eligible projects. Many standard offers require that projects
be certified as "qualifying facilities" as defined by the Public Utilities Regulatory Policies Act
(PURPA). Landfill gas projects are eligible to be qualifying facilities.
The standard offer price typically includes both a capacity payment and a variable
energy payment. Standard offer contract prices are based on the utility's avoided costs; that
is, the cost the utility would otherwise incur in providing electricity generating capacity and
energy if it did not purchase this capacity and energy from the qualifying facility (QF). Most
electric utilities are required to calculate their avoided cost and have it reviewed and approved
by their state regulatory authority.
Many utilities go through cycles where capacity is needed, contracts are offered,
contracts are signed, and then the standard offer is withdrawn until more capacity is needed.
During the periods when additional generating capacity is not needed, utilities are likely to
offer only a variable avoided short-term energy payment. Unfortunately, avoided energy
payments are often too low to economically justify developing a project. For example, 1992
average U.S. utility avoided energy costs were in the 2.9 to 3.50/kWh range [ICF, 1994].
Even though a standard offer contract may not be available, project developers should still
approach utilities to see if a contract can be negotiated.
How to Qualify for Standard Offers
In order to qualify for most standard offer contracts, a project must conform to the
guidelines set by PURPA. Under PURPA, an electric utility is obligated to buy electricity from
a power project at its current avoided cost rate if the project is granted QF status by the
Federal Energy Regulatory Commission (FERC) as either a "small power producer" or a
"qualifying cogenerator." PURPA prohibits utilities or utility holding companies from having
more than 50 percent ownership in QF projects, and it stipulates size and fuel requirements
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. Most landfill projects would be considered small power
producers.1
Qualifying cogeneration facility - A cogeneration QF must produce useful thermal
energy as well as electricity for sale to the utility. There is no size limitation; however,
at least five percent of the cogeneration QF's total energy output must be provided to
1 There are proposals within Congress to lift the 80 MW size limit. There is also some debate as
to whether PURPA should be repealed completely.
Part II September 1996 Page 8-4
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a thermal energy user if a 'lopping cycle" is used.2 An efficiency standard must also
be met for facilities using natural gas or oil. For topping cycles, this efficiency
standard will depend on the amount of useful thermal energy output provided [18
CFR, §292.205].
In addition to placing QF requirements into standard offer contracts, utilities also
commonly require that size and operating conditions be met. For example, the contract may
limit the amount of generating capacity (i.e., MW) for which the utility will pay. Applicants are
also usually required to provide some type of reliability guarantee (e.g., posting a bond),
backed up by penalties or reduced payments for nonperformance. It should be noted that
reliability guarantee requirements vary from state to state. Note that some standard offer
contracts may be available only to projects such as renewable energy or waste-to-energy
projects that have special advantages. Such programs can create additional incentives to
develop landfill gas projects.
Executing a Standard Offer
The electric utility's supply planning or power purchase department can provide details
about available standard offer contracts and current avoided costs. This information can then
be used in project economic calculations to determine if the project is viable. Standard offers
usually provide variable short-term and fixed long-term payment options. The developer
should choose the option that produces acceptable economics and enables the project to
meet financing requirements. Appendix C contains the executive summary of a representative
standard offer contract that was issued by one utility.
If the landfill owner/operator determines that the project is feasible under the set rates
and contract conditions, the standard offer contract can be signed. In most cases, however,
the state regulatory authority will review and approve the executed contract before it takes
effect.
8.1.2 Bidding/Negotiating a Power Sales Agreement (PSA) With an Electric Utility
If a suitable standard offer is not available, a PSA may be pursued either through a
utility bidding process or by presenting an unsolicited offer to the utility. This section
discusses how to successfully negotiate a PSA by describing: (1) the request for proposals
process; (2) what to include in an offer; (3) how utilities judge offers; and (4) contract
considerations.
The Request for Proposal (RFP) Process
Utilities constantly review their energy needs and plan for the future, and this is usually
done through the development of an integrated resource plan. If an energy need is identified,
2 A lopping cycle" first uses energy input to produce power, then the rejected heat is used to
provide useful thermal energy. In a 'bottoming cycle', the sequence of energy use is reversed. There
is no operating standard for a bottoming cycle QF.
Part II Septemoer 1996 Page 8-5
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a utility will sometimes solicit bids from power producers to fulfill that need by issuing an
RFP.3 Sometimes, an RFP will call for specific project types, such as renewables, although
the majority of RFPs are all-source solicitations, meaning any technology bid is permitted.
A potential bidder must be aware of the specific type of electric capacity that a utility
needs (i.e., baseload versus peaking capacity). Landfill gas projects are well-matched to
utility baseload, or around-the-clock, needs, because landfill gas must be continuously
recovered throughout the year to prevent migration and to efficiently operate the recovery
equipment. In contrast, landfill gas projects are not compatible with peaking needs, or needs
that occur only during the times of highest electric demand (typically 5 percent or less of the
year). In a peaking project, most of the landfill gas would have to be flared, and the energy
recovery project would be idle for the majority of the year.
Even when no RFP is outstanding, a project proponent can offer an unsolicited bid to
the utility, In this situation, the project proponent would take the initiative to approach the
utility (typically the supply planning or power purchase department) and present his or her
project concept.
Bid Requirements
Bid requirements will determine the level of detail and the specific components to be
included in a bid package. If an RFP is issued, the requirements are set by the utility, and its
format must be followed. However, if an unsolicited bid is to be offered, there is some
flexibility in format, although enough information should be included to allow the utility to
make a judgement. A complete bid document is comprised of many components which
describe and document the various aspects of a project. The most important aspects are
pricing, equipment description, and contract terms. Standard bid components for RFP
responses are outlined in Table 8.1.
Before compiling the separate components of a bid document, the bidder should
identify the project's competitive advantages. A good way to do this is to first prepare a
project summary that sets the tone for the whole bid. By keeping the project's competitive
advantages in mind throughout the bid preparation process, each component can be
integrated to enhance the entire bid. Examples of a landfill gas project's potential competitive
advantages are listed in Box 8.1.
Bid Evaluation Process
Cost will likely be an overriding factor when the utility is judging a bid, and landfill gas
projects may have to compete against a utility's self-build option or a conventional natural
gas-fired project. Additional non-price factors that impact bid evaluation and may benefit
landfill gas projects include: societal benefits, environmental benefits, location, project timing,
reliability, and risks.
3 Developers often study a utility's integrated resource plan (IRP) to anticipate upcoming capacity
needs and solicitations. The electric utility and state regulatory authority can usually provide copies of
the IRP.
Part II September 1996 Page 8-6
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Contract Considerations
The economic terms of a PSA are vital to a project; however, other contract terms and
conditions affect the long-term viability and liability of the project as well. The entire contract
offered by a utility should be carefully reviewed by the project developer and reliable legal
counsel to ensure that each of the terms is acceptable. If they are not, a more acceptable,
revised version of the contract should be presented to the utility for negotiation.
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 [Knapp, 1990].
Termination - Grounds for contract termination should be very limited in order to
protect the long-term interests of all parties.
Assignment - The contract should contemplate assignment for purposes such
as financing. For example, allowing for contract assignment to a subsidiary or
to partners may be advisable to avoid ownership arrangement difficulties
[Knapp, 1990].
Force maieure4 - 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 allowed for meeting milestone
dates and extensions (e.g., in penalty provisions). This is necessary in case
unforeseen 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
will be very important. An example price structure that can be negotiated to
accomplish this is multi-part pricing, described in Box 8.2.
4 A force majeure clause provides for situations that occur when circumstances beyond the control
of either party disrupt normal operations. Penalties may be waived or reduced during force majeure
events. Examples of force majeure events are earthquakes, hurricanes, strikes, riots, and acts of war.
Part II September 1996 Page 8-7
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Box 8.1 Multi-Part Pricing
A multi-part pricing scheme is one way to ensure long-term project viability by matching
revenues with project expenses. The objective of this price structure is to ensure coverage
of fixed costs (e.g., debt payment, fixed O&M), regardless of how often the project is called
upon to run. The utility's decision to run the project is based on how the project's energy
costs compare to those of other generating sources (in the case of landfill gas projects,
these costs are very low, thus encouraging high levels of operation). A multi-part price
contains two or more of the following components:
Capacity payment ($/kW) - This fixed payment is based on the capital costs of the
project. The payment should be high enough to ensure that the project can meet
its debt service and equity return requirements, regardless of how often the utility
chooses to run the project.
Energy payment ($/kWh) - A variable energy payment is usually tied to fuel costs,
which are very low for landfill gas projects.
Operation & Maintenance ($/kWh and/or $/kW) - This is a variable and/or fixed
payment, which covers O&M costs of the project.
Start-up payment ($) - A fixed price is sometimes paid to the project each time it
is called upon to run. It covers the costs of start-up (e.g., electric demand costs,
equipment wear).
8.1.3 Bidding/Negotiating a PSA with an End User
Some state regulatory authorities will allow non-utility power projects to make
electricity sales directly to end users. However, such sales, when permitted, are typically
limited to a number of contiguous neighbors.5 In the near future, unconditional sales to
retail end users may be permitted as a result of deregulation in the electric industry. When
end user sales are sought, it is up to the landfill gas power project to negotiate contract terms
and conditions with the customer.
When negotiating an end user PSA, it will likely be necessary to offer the customer an
electricity rate that provides a discount over the rate currently paid to the local utility (i.e., a
rate based on the customer's avoided cost). Since retail electric rates are typically higher
than the buyback rates available from utilities, this type of displacement arrangement can be
very attractive to both the buyer and seller. For example, in 1992, the average posted U.S.
retail electric rate to industrial customers was 04.8/kWh; commercial rates averaged 07.6/kWh
for the same period [Energy Information Administration, 1994]. In comparison, average 1992
utility avoided cost buyback rates ranged from 02.9/kWh to 03.5/kWh [ICF, 1994].
5 Because state regulatory policies vary, it is essential that landfill owners/operators contact
authorities to determine any limitations or conditions governing direct electricity sales to end users
before trying to negotiate a PSA.
Part II September 1996 Page 8-8
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Table 8-1 Typical Bid Components
BID COMPONENT
Siting
Electric Interconnect
Technology
Fuel Supply
Experience
Timing
Permitting
Financing
Pricing
Regulatory Status
Operation & Maintenance
Contract Terms
DOCUMENTATION CHECKLIST
• map, showing site location (e.g., USGS map)
• site plan
• purchase option agreement (if necessary)
• description of rignts-of-way (if applicable)
• environmental assessment
• load flow study (if required)
• location of point of interconnection
• project design configuration
• equipment specifications
• technology status, experience
• vendor guarantees (performance, timing, cost)
• reports on viability of field (reliability is key)
• cost, fuel price escalation
• documentation of long-term supply (historical data)
• documentation of gas rights
• description of developer experience
• timeline for permitting, construction
• commercial operation date
• zoning plan
• air plan
• water plan
• plan
• debt coverage ratios
• pro forma
• breakdown of project cost
• capacity
• energy
• indices (e.g. fuel price escalation)
• FERC QF filing
• agreement with steam host (if applicable)
• maintenance schedule
• flexibility
• marked-up contract terms
(see section on contract considerations)
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September 1996
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Box 8.2 Potential Competitive Advantages of Landfill Gas Projects
Landfill gas comes from one local source, and it usually costs less than conventional
fuels.
Landfill gas energy recovery is a proven technology. Operators and equipment
manufacturers have gained experience with the conversion technologies used in landfill
gas recovery operations.
Landfill gas recovery projects provide a net environmental benefit by reducing methane
and volatile organic compounds emissions, conserving fossil fuels, reducing explosive
hazards, and reducing odor. In addition these benefits ease the permitting process,
may be shared with the utility, or used as a bargaining chip.
Most landfill gas projects are situated at a landfill site, which may ease or eliminate
local permitting and zoning requirements.
The price of fuel and equipment is fixed at the project outset; there is only minimal
price escalation.
Landfill gas projects can serve on-site electrical loads at dispersed locations, thus
reducing the need for new generating plants and transmission facilities.
Landfill gas projects offer a way for utilities to attain Climate Challenge voluntary
greenhouse gas emission reduction targets.
Title IV of the Clean Air Act (Acid Rain Program) creates a quantifiable value for
avoided SO2 emissions. Each ton of SO2 avoided through generation of electricity
from landfill methane saves one emission allowance for utilities affected by Title IV. For
those utilities not affected until the year 2000, each 500 MWh of electricity produced
by landfill gas may be worth one "bonus" allowance (currently at $150 each). See
Appendix I.
The basic contract terms and conditions to be considered when negotiating a PSA
with an end user will be the same as those outlined above for a utility PSA: term, termination,
assignment, force majeure, schedule, and price. Also, it is usually desirable to use a multi-
part price structure (see Box 8.2), even with non-utility customers. The concept should not be
foreign to industrial and commercial facilities, because electricity and gas are commonly
purchased under a tariff that includes an energy component, demand component, and
customer charge.
8.1.4 Wheeling Arrangements
A power project may be unable to obtain a favorable power sales contract with the
utility to which it is directly interconnected. In such instances it may be possible for the
project to transport, or "wheel," its power over the local utility's transmission system in order
to sell to a third party. When wheeling is necessary to reach a buyer, arrangements must be
made with the local utility to specify the terms and conditions for the wheeling service.
Parti! September 1996 Page 8-10
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The three basic types of wheeling services are: (1) wholesale; (2) self-service; and, (3)
retail. As a result of recent regulation, all utilities will soon be required to provide wholesale
wheeling to power producers at specified rates. However, self-service wheeling is currently
only permitted in three states (Connecticut, Florida, and Maine) and retail wheeling is
currently only allowed in very limited circumstances in Nevada.
Wholesale Wheeling
Wholesale wheeling occurs when a utility transports power over its transmission
system for delivery to another utility. All utilities may soon be required by FERC to provide
wholesale wheeling services to power projects; however, there is currently much debate
about how to determine the rates charged for these services. It is important to keep in mind
that the transmission rates will determine if it is economical to make off-system sales. For
example, if it costs 04.7/kWh to produce electricity and 02/kWh to transport it to the buyer,
then the total delivered electricity cost of 06.7/kWh may not be low enough to justify the sales
transaction.
Self-Service Wheeling
If a landfill gas owner/operator wants to deliver power to another of its facilities located
elsewhere on the local utility's system, then it may be possible to have the utility transport the
project's output to the site on behalf of the landfill owner/operator. For example, if a county
that owns the local landfill, the county prison facility, and various other office buildings
located around town then develops a power project at the landfill site, it could arrange to
have the local utility transport (i.e., wheel) the electricity from the project to the prison and
courthouse. This type of transmission service is known as self-service wheeling.
Currently, only three states-Connecticut, Florida, and Maine-permit self-service
wheeling. However, self-service wheeling has never been tried in some states, so if it is
beneficial to a project, then the landfill owner/operator should contact state regulatory
authorities to determine if it would be permitted.
Retail Wheeling
In the future, there may be expanded opportunities for power projects to make sales
directly to retail end users such as industrial facilities, hotels, and commercial buildings.
Currently, "retail wheeling", which means the sale of electricity directly to a retail customer
using the local electric utility's transmission lines, is prohibited in most states. The concept of
retail wheeling includes transmission service, which sets it apart from on-site electric sales
from a power project to an adjacent facility. Retail wheeling is currently allowed in Nevada
under limited circumstances, Michigan will soon begin a retail wheeling experiment, and
California has proposed regulations which would permit retail wheeling for some customers
beginning in 1996. Several other states are also considering the issue. On-site electric sales
to adjacent facilities are allowed under certain circumstances in several states. In addition,
some utilities are beginning to launch pilot programs under which retail wheeling is allowed.
The possibility of direct sales to distant or adjacent facilities represents an important future
opportunity, since the revenues from retail electricity buyers would most likely be higher than
is available from wholesale (i.e., utility) buyers.
Part II September 1996 Page 8-11
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8.2 GAS SALES CONTRACT (MEDIUM OR HIGH-BTU)
Gas sales contracts are a product of successful negotiation between the landfill gas
project developer and the gas user or distributor. When negotiating a contract, it is important
to keep in mind the project's requirements (i.e., revenue, operational considerations),
while at the same time knowing where compromises can be made to accommodate the
customer's needs.
Figure 8.3 outlines the steps involved in winning a gas sales contract. As illustrated,
customer needs and contract considerations will vary, depending on whether the gas product
to be sold is medium-Btu or high-Btu gas. Medium-Btu sales contracts are obtained with
direct use customers, such as industrial companies or commercial complexes, whereas high-
Btu contracts are typically negotiated with local gas distribution companies. Customer
proximity is a primary factor in determining the feasibility of either type of project.
8.2.1 Medium-Btu Gas Sales
Medium-Btu sales contracts are usually unsolicited and initiated by the developer.
Negotiations for a contract should begin with a potential gas customer (as represented by a
plant manager or plant engineer) during initial feasibility studies. It is important that the
developer obtain an initial indication of the price and terms that the gas customer is willing to
accept, so that they can be taken into consideration during later contract negotiations.
Usually these are dependent on the price and delivery terms of the existing or alternate fuel
supply.
Specific contract items which document each party's responsibility and limit landfill
liability and risk exposure are:
Gas price - This $/MMBtu price could include fixed and variable components.
Equipment retrofit/modifications - It should be clear who is responsible for the
capital cost of any required changes to the gas purchaser's equipment; this will
avoid any confusion or misunderstanding between parties.
Pipeline construction and maintenance - Frequently, a dedicated pipeline will
be required to transport the landfill gas from the site to the customer.
Responsibility for pipeline construction costs and O&M should be clearly
defined, which will help ensure that the pipeline is completed on time and is
properly maintained.
Minimum purchase amounts - The amount (daily, annual, or total) of gas that
the customer is required to buy, and that the landfill is required to provide,
should be set, with some tolerances allowed. This will help to define the size
of the project and will ensure revenues.
Changes in purchase amounts - The situation in which either party wishes to
increase/decrease purchase amounts should be addressed, with flexibility
allowed (e.g., decrease in landfill gas production or plant needs).
Alternate fuel - If a backup, or secondary, fuel is required to operate the gas
purchaser's equipment, then the contract should clearly define who is
Part II September 1996 Page 8-12
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Figure 8-3 Winning/Negotiating An Energy Sales Contract (Gas Sales)
The potential customer can
provide guidance on what the
price and terms should be
Part
September 1996
Page 8-13
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responsible for purchasing the fuel under a variety of circumstances (e.g.,
landfill is responsible if production falls due to well maintenance problems).
8.2.2 High-Btu Gas Sales
Local distribution companies (LDCs) require a reliable supply of natural gas to serve
their customers, and they have a variety of supply contracts in place to meet these needs.
Some are long-term, while others only last for periods of one month or less. Contracts that
provide price stability and supply reliability are attractive. Landfill gas can provide both, and
may therefore have an advantage over conventional natural gas supplies if the energy
recovery project is economic.
Some LDCs occasionally request proposals lor gas supply packages; however, it is
unlikely that an RFP process will be used to obtain a high-Btu sales contract. The best way
to obtain a contract is to first contact the LDC's gas supply department to determine pricing
options. If the project is economically viable given the LDCs projected buyback rates, further
consideration should be given to specific contract terms.
Things to consider in negotiating a contract with an LDC include:
Take-or-pay clauses - It will be advantageous to the project if the utility is
required to pay for a set amount of gas even if it does not take delivery;
however, the LDC will likely resist such a clause.
Interconnect costs - The responsibility for the cost of construction and
maintenance of interconnect facilities (e.g., pipelines, connections, metering,
pressure regulation, filtering, moisture removal) should be clearly delineated.
Pass-through to the gas seller of taxes assessed on construction costs are an
especially important issue with interconnects, since project configuration may
determine their applicability.
Gas pressure and quality requirements - These must be defined at the outset,
as they will determine the amount of gas processing needed. This is important
for landfill gas projects because gas compression and enrichment are
expensive.
Standby or non-performance clauses - These should be defined at the outset as they
will determine any fines or penalties that are incurred as a result of non-compliance
with the contract.
Terms and times of delivery - The amount (daily, annual, or total) and times of
delivery of gas that the customer is required to buy, and that the landfill is required to
provide, should be set, with some tolerances allowed.
Part II September 1996 Page 8-14
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9. SECURING PROJECT PERMITS AND APPROVALS
Obtaining required environmental,
siting, and other permits is an essential step
in the development process. Permit
conditions often affect project design, and
neither construction nor operation can begin
until all permits are in place. The process of
permitting a landfill gas-to-energy project
may take anywhere from six to eighteen
months (or longer) to complete, depending
on the project's location and recovery
technology. For example, a project sited in
a location that requires no zoning variances
and that meets national air quality standards
will probably take much less time to permit
than a project subject to zoning hearings
and stringent air quality requirements.
Landfill gas energy recovery projects
must comply with federal regulations related
to both the control of landfill gas emissions
and the control of air emissions from the
energy conversion equipment. Regulations
promulgated under two separate federal
acts specifically address emissions from
municipal solid waste landfills:
The Project Development Process
Parti
Preliminary Assessment of
Project Options
Determining if a Project is Right for Your Landfill
Determining What Project Configuration is Right
for Your Landfill
I
Part II
Detailed Assessment of
Project Economics
Evaluating Project Economics
Assessing Financing Options
Selecting a Project Development Partner
Winning/Negotiating an Energy Sales Contract
Contracting for EPC and O&M Services
• Resource Conservation and
Recovery Act (RCRA)
regulations focus on landfill gas hazard and nuisance abatement [40 CFR,
§258.23].
• Clean Air Act regulations focus on control of landfill gas emissions [61 FR
9905, March 12, 1996].
Air emissions from energy recovery projects are addressed in other sections of the
Clean Air Act. This chapter briefly discusses these major federal regulations and their
impacts on landfill gas energy recovery projects. 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, landfill owner/operators and
project developers should determine state and local requirements before seeking project
permits.
Part II
September 1996
Page 9-1
-------
9.1 THE PERMITTING PROCESS
There are four general steps (outlined in the flowchart in Figure 9.1) that will help
ensure that the necessary permitting requirements under applicable state and federal
regulations are met:
Step 1. Hold preliminary meetings with key regulatory agencies. Discuss with
regulators the requirements and issues they feel must be addressed. These
meetings also give the developer the opportunity to educate regulators about
the project, since, in many cases, landfill gas-to-energy 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 regulators in order to meet
requirements. Permitting processes sometimes provide opportunities for
project sponsors to negotiate the appropriate control measure and level with
regulators. If negotiation is allowed, 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 local, state, and federal
agencies who must review project plans and analyze their impacts. For landfill gas projects
in particular, developers often must deal with separate agencies with overlapping jurisdictions
over landfill operations and energy recovery operations (e.g., solid waste and air quality
authorities). This underscores the importance of coordinating efforts to minimize difficulties
and delays.
In some cases, permitting authorities may be unfamiliar with the characteristics and
unique properties of landfill gas. Where appropriate, the landfill owner/operator or project
developer should approach the permitting process as an opportunity to educate the
permitting authorities, and should provide useful, targeted information very early in the
process.
Emphasizing the pollution control aspects of landfill gas energy recovery projects can
be an effective approach in seeking permits. If a landfill gas collection and flare system has
not yet been installed or does not collect the full quantity of landfill gas emitted, then there is
a substantial opportunity to reduce non-methane organic compounds (NMOC) and methane
emissions from the landfill. An energy recovery project can further reduce these emissions by
capturing additional landfill gas, as well as reducing emissions of carbon dioxide, sulfur
dioxide, and other pollutants by displacing a fossil fuel source. Approaching and presenting
the project as a pollution control project that will cause a net reduction in emissions can
make the air permitting process much easier.
Part II September 1996 Page 9-2
-------
Figure 9-1 Project Permitting
Contact/Meet
Regulatory Authorities
and Determine
Requirements
Meetings are beneficial to educate
permitting authorities and address
their concerns
Develop Permitting and
Design Plan,
Data Collection
Submit Permit
Applications
Design
Changes
Requested
Project design should reflect
all permitting criteria
Yes
Design changes may be necessary
to meet permitting requirements
No
Application Process
and
Approval
The process approval time will vary,
depending on a number of factors
9.2 RCRA SUBTITLE D
RCRA Subtitle D, established to ensure the protection of human health and the
environment, sets minimum national design, operating and closure criteria for municipal solid
waste landfills that were active on or after October 9, 1993. Virtually all currently operating
municipal solid waste landfills are considered affected landfills under RCRA. Landfill gas
control is one item addressed in the regulations.1
place.
' RCRA Subtitle D applies to affected landfills, regardless of whether an energy recovery project is in
Part II
September 1996
Page 9-3
-------
Landfill gas control is achieved by requiring affected landfills to establish a program to
periodically check for methane emissions and prevent offsite migration. Landfill owners or
operators must ensure that the concentration of methane gas does not exceed: (1) 25
percent of the lower explosive limit for methane in facility structures (excluding gas control or
recovery system components); and, (2) the lower explosive limit for methane at the facility
boundary. Permitted limits on methane levels reflect the fact that methane is explosive within
the range of 5 to 15 percent concentration in air. If methane emissions exceed permit limits,
corrective action (i.e., installation of a landfill gas collection system) must be taken [40 CFR,
§258.23]. Subtitle D may provide an impetus for some landfills to install energy recovery
projects in cases where a gas collection system is required for compliance.
Subtitle D requirements for methane emissions monitoring affect landfills not only
during operation, but also for a period of thirty years after closure.
9.3 CLEAN AIR ACT
The Clean Air Act (CAA) addresses landfill gas-to-energy recovery project emissions in
two ways:
(1) Regulation to control the emissions of non-methane organic compounds found
in landfill gas, and
(2) Regulation of airborne emissions from the combustion sources used in landfill
gas energy recovery.
This section explains how the CAA regulations apply to and impact landfill gas energy
recovery projects.
9.3.1 Landfill Gas Emissions
On March 12, 1996, EPA promulgated New Source Performance Standards (NSPS)
and Emissions Guidelines (EG) for landfills under the authority of Title I of the Clean Air Act
(61 FR 49, 9905, March 12, 1996). The regulations target landfill gas emissions because they
contain non-methane organic compounds (NMOCs), which contribute to smog formation.
The requirements of the NSPS and EG are basically the same, with the main difference being
the timing of implementation and the lead agency-the EPA administers the NSPS which takes
effect immediately, while the states implement the EG once they have completed and received
EPA approval of their implementation plans.
The regulations require landfill gas control at municipal solid waste landfills that meet
all of the following criteria:
Age - The NSPS apply to all "new" landfills-i.e., those that began construction,
reconstruction, or accepting wastes for the first time on or after May 30, 1991 (the
date the proposed regulations were published in the Federal Register). The EG apply
to "existing" landfills--i.e., those that accepted wastes on or after November 8, 1987.
Both "new" and "existing" landfills are referred to below as "affected" landfills." Landfills
that were closed prior to that date are not subject to the regulations.
Part II September 1996 Page 9-4
-------
Capacity - Affected landfills with a design capacity greater than 2,500,000 Mg
(2,750,000 tons) are subject to the emission rate criterion described below.
Emission rate - Affected landfills meeting the capacity criterion must collect
and combust their landfill gas if their maximum annual NMOC emission rate is
greater than 50 metric tons. This emission rate can be determined either by
desktop calculation using an EPA model (known as a Tier One analysis), or by
EPA-defined physical testing procedures (known as Tier Two or Tier Three
determinations).
Affected landfills that must collect and combust their landfill gas can use a flare system
or an energy recovery system that has been demonstrated to reduce NMOC emissions by 98
percent. Landfill gas-to-energy should be evaluated at each landfill site to determine whether
it is cost-effective, as it offers landfill owners an opportunity to mitigate the costs of
compliance with the regulations. In addition to control requirements, the proposed
regulations also contain recordkeeping and reporting requirements.
As the permitting process outlined in Figure 9.1 indicates, it will be important to
contact regulatory authorities in order to determine and verify applicability criteria before
developing a compliance plan. Appendix B is a list of regional and federal EPA offices that
can provide detailed information about the regulations.
9.3.2 Regulations Governing Air Emissions from Energy Recovery Systems
Regulations have been promulgated under the CAA governing airborne emissions
from new and existing sources. These regulations require new stationary sources and
modifications to existing sources of certain air emissions to undergo the New Source Review
(NSR) permitting process before they can operate.2 The purpose of these regulations is to
ensure that sources meet the applicable air quality standards for the area in which they are
located. The applicable air quality standards are determined, in part, by the National Ambient
Air Quality Standards (NAAQS), which have been set by EPA for six criteria air pollutants.
Two aspects of the NAAQS affect the stringency of the NSR permitting process. First,
it sets overall regional ambient air loadings for the criteria pollutants. Using these levels, most
areas of the country are classified as in "attainment" or "nonattainment" for each criteria
pollutant. Areas that meet the NAAQS for a particular air pollutant are classified as in
"attainment" for that pollutant, while areas that do not meet the NAAQS for a particular air
pollutant are classified as in "nonattainment" for that pollutant. The same area may be in
attainment for one air pollutant, but in nonattainment for another pollutant. Nonattainment
areas are further categorized by their degree of nonattainment: marginal, moderate, serious,
severe, and extreme. The greater the degree of nonattainment, the more stringent the
regulations are in bringing that area to attainment and the lower the acceptable emission
levels of particular pollutants will be. Some areas of the country are "unclassified" for all or
some pollutants. An area that is listed as "unclassified" for a particular pollutant is one that
has not had a project undergo the air permitting process for that pollutant.
2The EPA's NSR regulations for nonattainment areas are set forth in 40 CFR 51.165, 52.24 and part 51,
Appendix S. The PSD program is set forth in 40 CFR 52.21 and 51.166.
Part II September 1996 Page 9-5
-------
Second, the NAAQS sets emission levels for new stationary sources and for
modifications to existing sources. These levels are expressed in terms, of total atmospheric
loadings (i.e. tons emitted per year), as opposed to emission rates (tons/kwh), and are
dependent upon location (attainment or nonattainment area) and the type of source (new or
existing and its quantity of emissions). New sources or modifications to existing sources that
exceed these NAAQS emission levels are classified as "major" sources while those that do not
are classified as "minor" sources.
The principal air permitting requirements for landfill projects in attainment and
nonattainment areas are described in detail below. As the discussion indicates, new
stationary sources and modifications to existing sources in attainment areas undergo
Prevention of Significant Deterioration (PSD) permitting while those in nonattainment areas
undergo Nonattainment Area permitting. The basic difference between these processes is
that the NSR permitting requirements are more stringent for major sources or modifications in
nonattainment areas than for those same sources or modifications in attainment areas.
Most landfill energy recovery projects will likely be affected by the NAAQS standards
for nitrogen oxides (NOx) and carbon monoxide (CO). Whether a major NSR is required at a
particular landfill project will depend on the level of emissions resulting from the project
(which is primarily a function of project size and technology) and the project's location
(attainment or one of the five degrees of nonattainment). As discussed below, small projects
and/or those located in attainment areas may find the air permitting process to be quite
straightforward (minor NSR), while larger projects, particularly those in nonattainment areas,
may require major NSR, which is more extensive. In any event, given the complexity of the air
permitting regulations, a landfill owner or operator may wish to consult a local attorney or
other expert familiar with NSR permitting requirements in a particular area.
Attainment Area Permitting or PSD Permitting
PSD review is used in attainment areas to determine whether or not a new or modified
emissions source will cause significant deterioration of local air quality. All areas are
governed to some extent by PSD regulations because it is unlikely that a given location will
be in nonattainment for all criteria pollutants. Applicants must determine PSD applicability for
each individual pollutant. For gas-fired sources, including landfill gas energy recovery
projects, PSD and major NSR is required if the new source will emit or has the potential to
emit any criteria pollutant at a level greater than 250 tons per year. A modification to an
existing emission source is considered major if one of the following conditions is met: (1) the
existing source is already a major source of a particular air pollutant and the modification will
emit that air pollutant at a level greater than the PSD significance level or, (2) if the existing
source is minor for a particular air pollutant and the modification will emit that air pollutant at
a level greater than the major new source threshold. Figure 9.2 shows a simplified flow
diagram of determining whether a new source or modification is major in an attainment area.
For each pollutant for which the source is considered major, the PSD major NSR
permitting process requires that the applicants determine the maximum degree of reduction
achievable through the application of available control technologies. Specifically, major
sources may have to undergo any or all of the following four PSD steps: (1) Best Available
Control Technology (BACT) analysis, (2) monitoring of local air quality, (3) source impact
analysis/modeling (i.e. impact on local air quality), and (4) additional impact
analysis/modeling (i.e. impact on vegetation, visibility, and Class I areas). The key
component of the PSD process is the BACT analysis, which requires that the most stringent
Part II September 1996 Page 9-6
-------
Figure 9-2 Applicability of New Source Review Requirements
in Attainment Areas for Ozone:
Emissions of NOx Used as an Example
win
project emit
>250tpy
NOx
Expansion
of an
Existing
Project
Will
expansion
project emit
>40tpy after
netting
Pollution
Control
Project?
see notes
Notes:
A Pollution Control Project must be both:
(a) environmentally beneficial; and
(b) not cause or contribute to a violation of a NAAQS or PSD increment, or adversely affect
an AQRV in a Class I area.
In addition:
The permitting authority must determine that the project qualifies as a pollution control
project.
The permitting authority must provide an opportunity for public review and comment on
the project's application and the proposed NSR exclusion.
Part II
September 1996
Page 9-7
-------
control technology available must be used in a facility, unless the applicant can demonstrate
that it is not feasible due to energy, environmental, or economic reasons.
Minor sources and modifications are exempt from this rigorous process, but these
sources must still obtain construction and operating air permits. Minor sources must
demonstrate, through calculations, modeling, vendor guarantees, or other analysis, that the
source's emissions will not exceed applicable PSD levels. Many states require even minor
sources to complete a BACT analysis and use BACT, although minor sources are usually not
required to gather local air quality data or model impacts. New sources or modifications are
considered major for NOx or CO if they exceed the limits shown in Table 9.1.
Table 9-1 Attainment Area Limits for NOx and CO
Pollutant
NOx
CO
New Sources
are Considered
Major if Emissions
Exceed
(in TPY)
250
250
Modifications to
an Existing Minor
Source
are Considered
Major if Emissions
Exceed
(in TPY)
250
250
Modifications to
an Existing Major
Source
are Considered
Major if Emissions
Exceed
(in TPY)
40
100
Nonattainment Area Permitting
If a particular area - usually a county-wide area - does not meet the NAAQS levels for
any of the six criteria pollutants, then it is classified as being in "nonattainment" for that
pollutant. A listing of ozone nonattainment areas is provided in Appendix F, since this is the
most pervasive nonattainment pollutant and the most likely to affect landfill energy recovery
projects. An area may be nonattainment for one or more pollutants. For example, if a county
exceeds the NOx levels set by the NAAQS, but meets the standards for the other pollutants,
then the area is classified as nonattainment for ozone only (since ozone attainment is
regulated through NOx and VOCs).
A proposed new emission source or modification to an existing source located in a
nonattainment area must undergo nonattainment major NSR if the source or the modification
is classified as major. New sources or modifications are considered major for NOx or CO if
they exceed the limits shown in Table 9.2. Figure 9.3 shows a simplified flow diagram for
determining whether a new source or modification is major in a serious nonattainment area.
Two primary requirements must be fulfilled in order to obtain a nonattainment NSR
permit for criteria pollutants: (1) The project must use technology that achieves the Lowest
Achievable Emissions Rate (LAER) for the nonattainment pollutant, and (2) a source must
arrange for an emission reduction at an existing combustion source that more than offsets the
emissions from the new project.
Part
September 1996
Page 9-8
-------
Figure 9-3 Applicability of New Source Review Requirements in
Serious Non-Attainment Areas for Ozone:
Emissions of NOx Used as an Example
Will
project emit
>5Otpy
NOx
Expansion
of an
Existing
Project
Is
existing
project a
major source
of NOx
Will
expansion
project emit
>40 tpy after
netting
Pollution
Control
Project?
see notes
Notes:
A Pollution Control Project must be both:
(a) environmental!/ beneficial; and
(b) not cause or contribute to a violation of a NAAQS or PSD increment, or adversely affect
an AQRV in a Class I area.
In addition:
• The permitting authority must determine that the project qualifies as a pollution control
project.
• The permitting authority must provide an opportunity for public review and comment on
the project's application and the proposed KISR exclusion.
Part
September 1996
Page 9-9
-------
Table 9-2 Nonattainment Area Limits For NOx and CO
Pollutant
New Sources
are Considered
Major if Emissions
Exceed
(in TPY)
Modifications to
an Existing Minor
Source
are Considered
Major if Emissions
Exceed
(in TPY)
Modifications to
an Existing Major
Source
are Considered
Major if Emissions
Exceed
(in TPY)
NOx
Marginal
Moderate
Serious
Severe
Extreme
100
100
50
25
10
100
100
50
25
10
40
40
40
25
10
CO
Moderate
Serious
100
50
100
50
100
50
Defining the lowest achievable emission rate (LAER) can be a challenge for landfill gas
projects. Permitting authorities unfamiliar with the characteristics of landfill gas may expect a
landfill gas project to achieve the same LAER as a natural gas project. This can be difficult
for a number of reasons, including the inability of the catalysts designed to reduce NOx
emissions to function effectively on landfill gas, the variable flow, composition, and Btu value
of landfill gas, and the fact that landfill gas projects are often too small for the use of turbines,
which have lower NOx rates than 1C engines, to be economic. Cost, however, is not a
consideration in determining the LAER technology.
Obtaining emission offsets to ensure no net change in overall pollutant levels can also
be a challenge. Emission offsets are created when emission reductions are achieved at an
existing emissions source (typically, an industrial facility) in order to cover the increased
emissions of the new source. The most common type of offsets required by the new projects
are NOx offsets because there are many ozone nonattainment areas (i.e. areas whose NOx
and VOC levels do not meet NAAQS), and many combustion sources emit NOx at high
enough levels to become major sources and require offsets. Most of the northeast U.S. is
designated as an ozone nonattainment area, for example, known as the Northeast Ozone
Transport Region.
Part II
September 1996
Page 9-10
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The number of offsets required by a project is determined by applying an offsets ratio
to its emission level above the threshold. The ratio varies from 1:1.1 to 1:1.5 for ozone,
depending upon an area's degree of nonattainment, and is 1:1 for CO and other criteria
pollutants. For example, a project proposed for a severe ozone nonattainment area that has
the potential to emit 100 tons per year of NOx would be required to obtain 97.5 tons per year
of NOx offsets.3
NSR Exemption for Pollution Control Projects
On July 1, 1994, EPA's Office of Air Quality and Planning Standards issued guidance
to regional and state staff that increases their flexibility in permitting projects that are classified
as "pollution control projects". Under the guidance, the permitting authority may exempt the
project from major NSR, as long as emissions from the project and minor source
requirements are met. In nonattainment areas, offsets will still be required, but need not
exceed a 1:1 ratio. In order to qualify as a pollution control project, a landfill gas-to-energy
project must pass two tests: (1) the environmentally-beneficial test and (2) the air quality
impact assessment.
Under the environmentally-beneficial test, the proposed project is evaluated on its
overall environmental impact on air quality. If, on balance, there is a beneficial impact on air
quality, the project could qualify as a pollution control project. For example, a landfill gas-to-
energy recovery project could be considered a pollution control project if it reduces VOCs,
even if it generates some NOx.
Under the air quality impact assessment, the pollution control exclusion will not apply
if the emissions from the project would (e.g. NOx) cause or contribute to a violation of
NAAQS or PSD increment, or adversely impact visibility or other Air Quality Related Values
(AQRV) in a Class I area [see, e.g., Clean Air Act sections 110(a)(2)(C), 165, 169A(b), 173].
Therefore, where a pollution control project will result in a significant increase in emissions
and that increased level has not been previously analyzed for its air quality impact and raises
the possibility of a NAAQS, PSD increment, or AQRV violation, the permitting authority is to
require the source to provide an air quality analysis sufficient to demonstrate the impact of
the project. In the case of non-attainment areas, the State or the source must provide
offsetting emissions reductions (at a 1:1 ratio) for any significant increase in a nonattainent
pollutant (e.g. NOx) from the pollution control project. However, rather than having to apply
offsets on a case-by-case basis, States may consider adopting specific control measures or
strategies for the purpose of generating offsets to mitigate the projected collateral emissions
increases from a class or category of pollution control projects.
In addition to passing the two tests, there are two procedural safeguards that a
pollution control project must address. First, the project must receive approval from the
permitting authority (this is done on a case-by-case basis). Second, the application for
exclusion and the permitting agency's proposed decision must be subject to public notice
with the opportunity for public and EPA written comment.
number of tons that must be offset is calculated as follows: ["emissions level" (100 tons) minus
"threshold level for severe nonattainment" (25 tons)] multiplied by ("offsets ratio for severe nonattainment" (1.3)].
Part II September 1996 Page 9-11
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This guidance memorandum is included in Appendix E. It is important to recognize
that this is a guidance document and not a promulgated rule, which means that permitting
authorities may choose to adopt the guidance and exercise greater flexibility, or disregard it.
NOx Emissions from Energy Conversion
Combustion of landfill gas - in an engine, turbine, or other device - generates
nitrogen oxide (NOx). The amount of NOx generated and emitted depends primarily upon the
following two characteristics of the combustion process:
• Air/fuel Ratio: the ratio of air to fuel (i.e., landfill gas) in the combustion
chamber is a key factor in determining the quantity of NOx generated from
combustion of landfill gas. If air in excess of what is needed to achieve
combustion is introduced into the combustion chamber, fewer NOx emissions
are generated.
• Residence time: the amount of time that the landfill gas is in the combustion
chamber has a significant effect on NOx formation. Longer residence times
allow greater quantities of NOx to be formed and ultimately emitted.
\
The air/fuel ratio and residence time vary between the major technologies used in
landfill gas-to-energy applications (i.e., internal combustion engines and combustion
turbines) as well as among different types of engines; therefore, NOx emissions per cubic foot
of landfill gas burned as fuel in a combustion device also varies. When internal combustion
engines and turbines are used in conventional natural gas applications, catalysts are often
used to reduce NOx emissions. To date, catalysts have not proven effective in landfill gas
applications because the impurities found in landfill gas quickly limit the catalysts' ability to
control NOx emissions.
Table 9.3 provides emissions factors that can be used to estimate the range of NOx
emissions that could be expected from a landfill gas project employing internal combustion
engines (1C) or combustion turbines (CT). As the table indicates, the potential emission
factors for 1C engines span a relatively large range; the lower end of the range is represented
by lean-burn engines, which use excess air in the combustion process, while the high end is
represented by naturally aspirated 1C engines. Depending on the specific type of engine
being used, it should be possible to select an appropriate emission factor from within this
range. In contrast, only one emission factor is provided for combustion turbines. This factor
is appropriate for the most common type of turbine used for landfill gas applications (the
Solar Centaur gas turbine).
Part II September 1996 Page 9-12
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Table 9-3 Emission Factors By Technology Type
Emission factor
(Ib NCyMMBtu)
1C Engine
0.22 - 0.54
CT
0.12
Annual NOx emissions can be calculated by multiplying the appropriate emission
factor from Table 9.3 by the energy content (in MMBtu/year) of the landfill gas fuel. The
energy content can be calculated easily from the landfill gas flow, as follows:
Energy Content (Btu/Yr) = LFG (cfd) * Btu * 365 days
~cT yr
Landfill gas typically contains about 500 Btu per cubic foot. This can be used as a default if
the Btu value of landfill gas at a specific site is not known. For a 5 million ton landfill with a
gas flow of about 3 million cubic feet per day, the energy content would therefore be
calculated as follows:
3 mmcfd * 500 Btu. * 365 = 548 * 103 MMBtu/yr
cf
Table 9.4 illustrates a potential range of emissions in tons of NOx per year for typical
1, 5, and 10 million ton landfills. As Table 9.4 illustrates, NOx emissions from 1C engines are
substantially higher than emissions from CTs. Landfills located in ozone non-attainment areas
may therefore find that CTs are the most appropriate technology for medium or larger sized
landfill gas projects. The following sections describe the differences among 1C engines and
between 1C engines and CTs that result in the large range of emissions.
Table 9-4 NOx Emissions Table
Landfill Characteristics
Waste in Place
(million ton)
1
5
10
Landfill Gas Flow
(1000 cfd)
642
2988
5264
Estimated NOx Emissions (TRY)
1C Engine
13-32
60 - 1 47
106-260
CT
n/a
35
60
Internal Combustion Engines - There are two basic types of 1C engines: naturally
aspirated and lean-burn. Naturally aspirated 1C engines draw combustion air and
landfill gas through a carburetor in stoichiometric proportions, much the same way
Part II
September 1996
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that an automobile equipped with a carburetor would draw its air/fuel mixture. Just
enough air is drawn into the combustion chamber to ignite the air/landfill gas mix. In
addition, residence time in the combustion chamber is relatively long. Therefore, this
type of engine emits relatively high levels of NOx, and is represented by the high end
of the range shown in Table 9.4. For landfill gas-to-energy recovery projects, this type
of engine is best suited for smaller projects in ozone attainment areas.
Lean-burn 1C engines combust landfill gas with air in excess of the stoichiometric mix.
Since this type of engine uses a mixture with excess air, it provides both greater
engine power output and fewer NOx emissions than a comparable naturally aspirated
engine. This type of engine can be expected to emit NOx emissions on the low end
of the range shown in Table 9.4. It should be noted that manufacturers of these
engines are continually refining them and that newer, even lower NOx emitting engines
are expected to be commercially available soon. In addition, newer, more effective
add-on control systems are in development.
Combustion Turbines - CTs utilize large amounts of excess air and have relatively
short residence time. These factors combine to greatly reduce the amount of NOx
emitted relative to internal combustion engines. These lower emissions may be a
significant benefit of using a CT, particularly for medium to large landfill gas energy
recovery projects located in ozone non-attainment areas. However, because CTs are
not cost-effective at smaller projects (i.e., less than 3 MW), these projects typically do
not have the option of using CTs.
9.4 LOCAL ISSUES
Local approval of a project is crucial to its success. This approval refers not only to
the granting of permits by local agencies, but also to community acceptance of the project.
Strong local sentiment against a project can make permitting difficult, if not impossible.
9.4.1 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 in order to minimize permitting delays which cost both time and money.
This is especially important since the pollution prevention benefits of landfill gas projects may
not initially be considered and because different agencies' rules can often be conflicting
[Pacey, Doom, Thorneloe, 1994).
Zoning/Land Use
The first local issue to be addressed is the compatibility of the project site with
community land use specifications. Most communities have a zoning and land use plan that
identifies where different types of development are allowed (e.g., residential, commercial,
industrial). The local zoning board determines whether or not land use criteria are met by a
particular project, and can usually grant variances if conditions warrant.
Part II September 1996 Page 9-14
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A landfill gas project site will likely require an industrial zoning classification. One
advantage of landfill gas projects is that they are usually located at the landfill site, thus
zoning reclassification may not be necessary, especially if the landfill is still active.
Permitting Issues
In addition to land use specifications, local agencies have jurisdiction over a number
of other project parameters, such as the following:
Noise — Most local zoning ordinances stipulate the allowable decibel levels for
noise sources, and these levels vary, depending on the zoning classification at
the source site (e.g., a site located near residential areas will have a lower
decibel requirement than one located in an isolated area). Even enclosed
facilities are usually required to meet these requirements; therefore, it is
important to keep them in mind when designing project facilities.
Condensate - There may be unique permitting or treatment requirements for
landfill gas condensate. While some landfill gas projects can return the
condensate to the landfill, many dispose of condensate through the public
sewage system after some form of on-site treatment [Berenyi and Gould, 1994].
It is possible that the condensate may contain high enough quantities of heavy
metals and organic chemicals for it to be classified as a hazardous waste, thus
triggering additional, federal regulation.
Wastewater - The primary types of wastewater likely to be generated by a
landfill gas power project include maintenance/cleaning wastewater, domestic
wastewater, and cooling tower blowdown. The municipal engineer's office
should be contacted to provide information about available wastewater
handling capacity, and any unique condensate treatment requirements or
permits for landfills. The wastewater treatment facility operator is likely to have
standards governing the pollutant concentrations in incoming wastewater
streams. For projects that intend to discharge wastewater into rivers, lakes, or
other surface water (typically only the large power projects that use a steam
cycle), a National Pollution Discharge Elimination System (NPDES) permit will
be required. The authority to issue these permits is delegated to state
governments by the U.S. EPA.
Water - Water requirements will depend on the type and size of the project
and the environmental control technologies used. The city engineer's office
should also be able to provide data about available water supply capacity. If
current facilities cannot meet the needs of the project, then new facilities (e.g.,
pipeline, pumping capacity, wells) may need to be constructed. Groundwater
permits could be required if new wells are needed to supply the project's water
needs. (Note that the landfill itself, if active, will already be required by RCRA
Subtitle D to monitor groundwater.)
Solid waste disposal - The only solid wastes generated by a landfill gas power
project will likely be packaging materials, cleaning solvents, and equipment
fluids. While there may only be a small amount of solid waste generated, it
must be properly disposed of; which may be an important consideration if the
project landfill is closed.
Part II September 1996 Page 9-15
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Stormwater management - Public works departments regulate stormwater
management, and will require a permit for discharges during construction and
operation. Good facility design that maintains the predevelopment runoff
characteristics of the site will allow the project to easily meet permitting
requirements.
Stack height - Local codes may limit stack heights, especially near airports or
landing fields. Project design (e.g., plant layout, flare design) must take these
limits into account.
Other - There may be other issues that local agencies oversee. It is important
to find out what these issues are by contacting local authorities, especially
since they vary among project sites. As an example of such other issues, Box
9.1 partially lists the local permits that were required for the Fresh Kills Landfill
Methane Recovery Project, located in New York.
9.4.2 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. Like landfills, many power projects in the past have encountered local
opposition such as the "not in my backyard (NIMBY)" syndrome, or false perceptions of
project dangers (e.g., explosion risks, adverse health effects from electromagnetic fields).
Therefore, it is important to educate the public and to develop a working relationship with the
host community in order to dispel any fears or doubts about the expected impact of the
project. Project details should always be presented in a very forthcoming and factual manner.
Landfill gas-to-energy projects bring many benefits to the host community (e.g.,
improved air quality, reduction of landfill gas odor and explosive potential). These benefits
should be emphasized during the permitting process.
Part II September 1996 Page 9-16
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Box 9-1 Some of the Local Permits Required for the Fresh Kills Landfill Methane
Recovery Project
Agency
Bureau of Gas and Electricity
Division of Fire Protection
Department of Sanitation
Board of Standards and Appeals
Community Planning Board of
Staten Island
Department of Environmental
Protection
Permits
Certification that all
equipment is explosion proof
One hundred percent x-ray of
all pipe joints
Site approval
Approval of equipment on site
Compliance with
height restrictions
Department of Ports and Terminal
Department of Buildings
Source: "Regulatory Barriers to Landfill Gas Recovery Projects"
Air Quality approval
Well permits
Construction approvals
Part II
September 1996
Page 9-17
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10. Contracting For EPC And O&M Services
As discussed in Chapter 7, many
landfill owners may decide to work with
firms with extensive experience during
project development. Likewise, because the
construction and operation of landfill gas
energy recovery projects are complex
processes, they may be best managed by a
firm with proven experience, gained over the
course of implementing similar landfill gas
projects. Landfill owners that choose to
contract with an engineering, procurement,
and construction (EPC) firm and/or an
operating firm should be aware of some of
the basic elements of effective contracting.
This chapter provides some contracting
considerations for landfill owners, and lists
operating insights gained from a survey of
technical literature and interviews with
landfill energy project owners, developers,
and operators.
The Project Development Process
Parti
Preliminary Assessment of
Project Options
Determining if a Project is Right for Your Landfill
Determining What Project Configuration is Right
for Your Landfill
Part II
Detailed Assessment of
Project Economics
Evaluating Project Economics
Assessing Financing Options
Selecting a Project Development Partner
Winning/Negotiating an Energy Sales Contract
Securing Project Permits and Approvals
10.1 EPC/TURNKEY CONTRACTING
After a project proponent has
secured an energy sales contract and the
required permits and approvals, he or she
may contract with an EPC or turnkey firm
who will take responsibility for construction of the project. The tasks performed by an EPC
contractor include: conducting engineering design, procuring the equipment, preparing the
project site for construction, and pre-operation start-up testing. A turnkey contractor extends
its services beyond those of an EPC contractor by taking on many of the owner's and
developer's duties as well, which include environmental permitting, regulatory licensing,
interconnections, and project management.
The process of contracting with an EPC or turnkey firm is charted in Figure 10.1. As
this figure shows, the process has several key steps, beginning with the landfill owner and/or
project developer soliciting bids from contractors and ending with the selection of a
contractor who will take the project to commercial operation. Along the way, the
owner/developer and its chosen contractor must conduct engineering design, site
preparation, and plant construction.
An effective EPC or turnkey contract clearly establishes the responsibilities of each
contracting entity, and it also should mesh with other existing project documents. The
contractor is generally responsible for engineering and building the plant to predetermined
specifications, making sure that project construction milestones are met, and ensuring that
acceptable performance is achieved at the commercial operation date. The landfill owner
Part II
September 1996
Page 10-1
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Figure 10-1 The EPC/Turnkey Contracting Process
Owner/Developer
Solicits Bids from EPC
or Turnkey Contractors
Owner/Developer
Selects EPC or
Turnkey Contractors
Owner/Developer
Negotiates Contracts
EPC or Turnkey
Contractor Conducts
Engineering Design,
Site Preparation, &
Plant Construction
Yes
No
Select O&M
Contractor
Start-Up
Commercial
Operation
and/or project developer is generally responsible for making sure funds are available as
needed, that the site is available and ready, and that provisions are made for any necessary
interconnections related to gas utilization. The elements of an effective contract are
described in Table 10.1.
Because of the importance of securing and fulfilling the power sales agreement, the
EPC contract should specifically recognize each entity's role in meeting its key elements.
These elements include:
Part II
September 1996
Page 10-2
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Table 10-1 Elements of an Effective EPC or Turnkey Contract
Element
Commercial operation date
Milestones
Cost, rates, and fees
Performance guarantees
Warranties
Owner's acceptance criteria
and procedure
Bonus amounts and
conditions
Liquidated damages and
conditions
Assignment
Items to be Specified
Date on which facility should achieve commercial
operation (should precede date in Power Sales
Agreement (PSA))
Engineering completion, construction commencement,
engine delivery, start-up
Structures include: fixed EPC or turnkey price, hourly
labor rates, cost caps, fee amount or percentage
Specified output (kW, rncf), heat rate, availability,
power quality, gas quality (should match PSA)
Output, performance degradation, heat rate, outage
rates, component replacement costs
Testing methods and conditions, calculation formulae
Bonus for early completion, exceeding specifications
Damages for late completion, failure to meet
specifications
Ability to assign agreement to subsidiary, partnership,
bank
• Commercial operation date;
• Project output (e.g., kW electricity, mcf gas) and heat rate;
• Plant availability; and
• Interconnection requirements; and
• Maintenance provisions.
Power project developers usually prefer to sign fixed-price EPC or turnkey
agreements, which enable the plant's installed cost to be known up front. If a fixed-price
contract is selected, then the price, scope of services, and other terms must be clearly
specified in the contract. The contract price should have an underlying budget that includes
plant components as well as the services mentioned above. The most important budget
items are listed in Box 10.1.
Contracting with a turnkey plant provider is an extension of contracting for EPC
services, because the turnkey provider usually agrees to include within its scope of services
the owner's and developer's duties as well as EPC contracting. A turnkey plant provider is
usually an EPC firm or developer who agrees to develop and build a facility for a fixed price.
As shown in Table 10.1, a turnkey contract must include the following items that are in
addition to the typical EPC contract items: turnkey price, development milestones, and
contractor's responsibilities.
Part II
September 1996
Page 10-3
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Box 10.1 EPC and Turnkey Budget Items
The EPC budget for a landfill gas energy recovery project should include at least the
following items:
• Engine skid (e.g., 1C engine, CT, turbine/generator)
• Engine auxiliaries (e.g., lubricating oil system, cooling system, air intake
manifold and filters, intake and exhaust silencers, fuel injection system,
hydraulic system, piping, and ductwork)
• Foundations and sitework
• Gas processing system (e.g., filters, refrigeration)
• Gas compressor(s)
• Emissions controls
• Plant electrical equipment and switchgear
• Step up transformer(s)
• Interconnections (electric, water, landfill gas)
• Back-up fuel capability/storage
• Automatic control system
• Gas and electric metering
• Water treatment and cooling
• Building/enclosure
• Fire protection system
• Engineering costs and associated expenses
• EPC contingency
A turnkey facility provider should include the following additional items:
• Gas collection system (if applicable)
• Additional interconnection costs (e.g., rights-of-way, piping, transmission
lines)
• Permitting costs, legal, administration expenses, insurance
• Financing costs (if applicable)
• Escalation during construction
• Interest during construction
• Contingency
• Fee
10.2 O&M SERVICES CONTRACTING
Many landfill owners and/or project developers do not wish to take on the day-to-day
responsibility of operating their landfill gas energy recovery project due to lack of manpower,
experience, or desire. When this is the case, hiring an O&M contractor may be an attractive
alternative. A survey of existing and planned landfill gas energy recovery projects shows that
about 80% of gas collection systems and 89% of gas processing/energy recovery systems
are operated by private O&M firms or in partnership with a private O&M firm [Berenyi and
Gould, 1994].
Part II September 1996 Page 10-4
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When contracting with the provider of O&M services, the landfill owner should talk to
several competing companies and select a winner based on experience, price, and terms.
The O&M company should have experience operating and maintaining similar facilities, and
should demonstrate that its accumulated experience will be applied in the form of qualified
personnel and ongoing training activities. Competing O&M companies should be asked to
submit hourly rates, expected annual budgets for O&M services, and fees.
It is important that the scope of O&M services be well defined so all bids can be
compared on a consistent basis. For example, it should be clearly specified whether O&M
services are to be provided for the gas collection system and the energy recovery system
both or only for one. The EPC contractor or equipment vendor can usually supply estimates
for the costs and duration of periodic maintenance procedures and major overhauls.
The facility owner may choose to provide incentives to the O&M company in the form
of contractual bonus/damages clauses to improve performance. For example, if maximizing
annual operating hours is important to project economics, then the facility owner might
propose a cash bonus for plant availability or kWh generation which exceeds a
predetermined amount.
10.3 GOOD O&M PRACTICES
The power production and direct use technologies for landfill gas have been improved
since their first use about 15 years ago. Over this time, many of the operational problems
encountered have been addressed with technology or procedural improvements. Therefore,
many of the technical problems found in the landfill gas literature are no longer major
obstacles to successful landfill gas energy recovery (in fact, some of the problems are no
longer obstacles at all).
In a recent survey, however, at least 22% of operating landfill gas energy recovery
projects reported experiencing operating interruptions for reasons other than planned
maintenance [Berenyi and Gould, 1994]. Of the 29 plants that reported unplanned
interruptions, only two experienced problems resulting in plant failure. The main reason cited
for interruptions was gas collection or processing equipment problems. Other specific
operational problems related to the gas collection system causing plant interruptions include
pipe blockage or breakage and lack of landfill gas. In many cases, such problems can be
avoided with careful equipment selection and operation and maintenance. Good O&M
procedures are always important to the success of energy projects. They are even more
important with landfill gas projects due to the impurities and variability found in landfill gas.
This section presents insights on how to prevent or minimize operating problems.
10.3.1 Collection Systems
Before sizing an energy recovery project, a project developer should estimate landfill
gas quantity as accurately as possible to prevent oversizing the equipment and inefficiencies
due to gas shortfall during operation. After project start up, proper operation and
maintenance of the gas collection system is necessary to balance offsite gas migration
control with optimal equipment performance.
Collection system problems may occur when wellfields are located in active landfill
areas; therefore, it is important to account for future landfill operations when designing the
Part II September 1996 Page 10-5
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collection system. By planning ahead, plant shutdowns or reduced output levels due to
collection system repairs may be avoided. Two examples of potential problems that may be
prevented by good planning are:
• Decreased gas recovery rates due to limited well accessibility caused by
depositing additional refuse vertically on top of existing wells [WMNA, 1992];
• Reduced landfill gas generation and quality caused by reopening a section of
inactive landfill where an existing well is located.
Good operating procedures, in addition to good system design, will also help to
prevent problems. For example, routine monitoring and tuning of wells will ensure that gas
quality is suitable for the efficient operation of the recovery equipment.
10.3.2 Energy Recovery Systems
While energy recovery technologies have been adapted to landfill gas applications,
several important operating considerations must be kept in mind to minimize or avoid
problems that arise due to landfill gas's corrosive nature and low Btu content.
1C Engines
1C engines are the most susceptible of the three common electric generation
technologies to the effects of corrosion [Anderson], which attacks engine parts and causes
deposit buildup. Experience has shown the following steps to be useful in combatting
corrosion in 1C engines used at landfills:
• Perform frequent oil checks and changes.
• Use an oil with a high alkalinity reserve (i.e., oil with a high total base number)
[Schleifer, 1988], Oils with a total base number (TEN) of 10 are commonly used
[WMNA, 1992],
• Use oil filters that have been treated with chemicals to neutralize acids from the
combustion of landfill gas [Anderson].
« Chrome-plate components that are subject to attack [Pacey, Doom, and
Thorneloe, 1994].
CTs and Boiler/Steam Turbines
Although CTs and boiler/steam turbines are more resistant to corrosion than engines,
they each have their own set ol operational considerations:
« An extra filtration step may be necessary if the compressors used to reach the
required pressure for CT operation cause oil entrainment and heating of the
landfill gas [WMNA, 1992],
• Due to the Btu variability in landfill gas, CT fuel/air controls must react, very
quickly. If they do not, the temperature will overshoot and automatically shut
down the CT. To avoid temperature overshoot, landfill gas fueled-CTs should
Part II September 1996 Page 10-6
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be operated at a lower temperature setpoint than CTs using conventional fuels
[Pacey, Doom, and Thorneloe, 1994].
• Silica deposits, which can lead to turbine failure, can be prevented with gas
refrigeration to condense dimethyl siloxane before combustion; however, this
step may not be economically justified [Anderson, WMNA, 1992].
• Boiler tubes should be designed to withstand the corrosiveness of landfill gas.
The over 200 existing and planned landfill gas energy recovery projects illustrate that
the technology is well-demonstrated and generally reliable. As long as projects are well
planned, executed, and maintained, they can perform up to or beyond expectations for many
years.
Part II September 1996 Page 10-7
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APPENDIX A
CALCULATIONS OF LANDFILL GAS ENERGY RECOVERY
PROJECT COSTS
-------
Page Intentionally Left Blank
-------
This Appendix contains sample cost estimates and calculations for three
landfill sizes-1, 5, and 10 million metric tons of waste in place. The cost data
are intended to illustrate the types of cost items that should be included when
evaluating project economics. The actual costs of a specific project are
dependent on project configuration, design, equipment selection, location, and
site-specific factors. Thus, a qualified engineer should be consulted when
considering investing in a landfill gas energy recovery project.
This Appendix contains 20 tables. Tables A.1 through A. 14 present
costs and calculations for a landfill gas power project, and Tables A. 15 through
A.20 present costs and calculations for a medium-Btu gas project. Tables A.1
through A. 10 contain capital and O&M cost information for each of the landfill
sizes. The remainder of the power project tables-Tables A.11 through A.14-
contain sample comparisons of expenses and revenues for a 5 million metric
ton landfill power project. Project finance and municipal bond finance cases
are included.
-------
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-------
TABLE A.I SUMMARY OF ESTIMATED POWER PROJECT CAPITAL COSTS
LANDFILL SIZE
Waste in Place
1 million metric tons
1C Engine
Combustion Turbine
5 million metric tons
1C Engine
Combustion Turbine
Combined Cycle CT
10 million metric tons
1C Engine
Combustion Turbine
Combined Cycle CT
Estimated
Net
Sustainable
LFG
Production
(mcf/day)
642
642
2,988
2,988
2,988
5,266
5,266
5,266
CAPITAL COSTS
Net
Electric
Output
(kW)
984
963
4,934
4,727
6,763
8,709
8,344
12,008
Installed
LFG
Collection
System
($/kW)
$638
$652
$423
$442
$309
$413
$431
$300
Installed
Energy
Conversion
System
($/kW)
$1,052
$1,412
$958
$1,153
$1,360
$919
$1,037
$1,208
Total
Soft
Costs -f
Engineering
($/kW)
(a)
$310
$359
$294
$334
$356
$263
$288
$306
Total
Capital
Requirement
($/kW)
$2,000
$2,423
$1,675
$1,928
$2,025
$1,595
$1,756
$1,813
Incremental
Capital
Requirement
($/kW)
(b)
$1,283
$1,691
$1.177
$1,409
$1,658
$1,109
$1,249
$1,458
Notes:
Source is cost calculation tables for each size landfill.
All costs are based on net electric (kW) output.
(a) Included are owners' costs (legal, permitting, insurance, taxes), escalation during construction (6 - 24 mos)
and interest during construction.
(b) Excludes capital and soft costs associated with the LFG collection system.
-------
TABLE A.2 ESTIMATED CAPITAL COSTS (1 million Mg case)
Example: T-andfill waste in place =
Cost Category
OPERATING DATA
Net sustainable landfill gas production
Gross electric output
Auxiliary and compressor loads
Net electric output
On-line date
Capacity factor (lifetime annual average)
Annual full load operating hours
Annual electricity generated
EQUIPMENT & INSTALLATION COSTS
Energy Conversion System ($1994)
Engine, auxiliaries, construction
Interconnections (elec, water, LFG)
Gas compressor
Energy conversion system cost
LFG collection system cost ($1994)
Engineering ($1994) @ 5.0%
CAPITAL REQUIREMENT
System cost ($1994)
Soft Costs
Owners costs, escalation, interest.
Contingency @ 5.0%
Total Soft Costs
Total Capital Requirement
(as-spent dollars, 1996 on-line date)
Incremental Capital Requirement
(as -spent dollars, 1996 on-line date)
1
Units
mcf/day
kW
kW
kW
hours
kWh
$000
$000
$000
$000
$000
$000
$000
$000
$000
$/kW net
$000
$/kW net
million metric tons
1C Engine
642
1,029
46
984
6/96
80%
7,008
6,895,872
825
110
100
1,035
628
83
1,746
135
87
222
1,968
2,000
1,263
1,283
. Combustion
Turbine
642
1,029
66
963
6/96
80%
7,008
6,748,704
1,050
110
200
1360
628
99
2,087
142
104
246
2333
2,423
1,628
1,691
(•)
0>)
(c)
(«J)
(«)
(0
(g)
00
(0
(j)
Notes:
(a) Based on landfill size of approximately 1 million metric tons. [EPA] (mcf = thousand cubic feet)
1 cf landfill gas = 0.5 cf methane
(b) kW = (cf/hr methane) x (1000 Btu/cf) / (13,000 Btu/kWh)
(c) Compressor effects: 1C engine—2% parasitic load; CTs—4% parasitic load
(d) Conservative estimated capacity factor over project life. [EPA]
(e) Includes prime mover, generator, plant auxiliaries, construction, LFG modifications, emissions controls.
(f) Assumed to be $100,000 for electric, $10,000 for water.
(g) Calculated based on EPA Exhibit 4-7; includes collection system + flare. [EPA]
(h) Calculated as 5% of conversion and collection system costs.
(i) Included are owners' costs (legal, permitting, insurance, taxes), escalation during construction (6 mos)
and interest during construction.
(j) Excludes capital and soft costs associated with the LFG collection system.
-------
TABLE A.3 ESTIMATED COST OF ELECTRICITY (1 million Mg case)
Project Finance Case
1 Example: Landfill waste in place =
Cost Category
POWER PROJECT COSTS
Capital Costs (as-spent, 1996 online)
Conversion system + collection system
Conversion system only
O&M Costs (1996)
LFG collection system
Conversion system
Royalty Payments (1996)
FIRST YEAR COST OF ELECTRICITY
Capital charge rate (project finance)
Total Electricity Cost
Levelized capacity price
1996 O&M price
Royalty Payment
Total 1996 cost of electricity
Incremental Electricity Cost
Levelized capacity price
1996 O&M price
Royalty Payment
Total 1996 cost of electricity
1
Units
$/kW
$/kW
c/kWh
c/kWh
c/kWh
(1996)
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
million metric tons
1C Engine
2,000
1,283
12
1.8
0.5
0.136
3.9
3.0
0.5
7.4
25
1.8
0.5
4.8
Combustion
Turbine
2,423
1,691
12
15
05
0.136
4.7
2.7
0.5
7.9
3.3
1.5
0.5
53
(a)
0>)
(c)
(d)
(e)
(f)
(e)
Notes:
(a) Based on EPA estimate for collection + flare systems (Exhibit 4-7), in $1996. [EPA]
(b) Based on O&M estimates published by Wolfe & Maxwell in "Commercial Landfill Recovery Operations -
Technology and Economics," and in EPA Report to Congress (Exhibit 4-7).
(c) Royalty payments to the landfill owner are estimated to be 10% of revenues (4.9 c/kWh).
(d) Assumes: 20-year life, project finance with a 80/20 debt/equity ratio, 9% interest on debt;
includes 15% return on equity, 10-year depreciation.
(e) Calculated by multiplying capital $/kW by CCR and dividing by annual hours of operation.
(f) Conversion system only cost does not include capital and O&M costs associated with LFG collection system.
-------
TABLE A.4 ESTIMATED COST OF ELECTRICITY (1 million Mg case)
Municipal Bond Finance Case
1 Example: T-andfill waste in place =
Cost Category
POWER PROJECT COSTS
Capital Costs (as -spent, 1996 online)
Conversion system + collection system
Conversion system only
O&M Costs (1996)
LFG collection system
Conversion system
Royalty Payments (1996)
FIRST YEAR COST OF ELECTRICITY
Capital charge rate (muni bond finance)
Total Electricity Cost
Levelized capacity price
1996 O&M price
Royalty Payment
Total 1996 cost of electricity
Incremental Electricity Cost
Levelized capacity price
1996 O&M price
Royalty Payment
Total 1996 cost of electricity
1
Units
$/kW
$/kW
c/kWh
c/kWh
c/kWh
(1996)
c/kWh
c/kWh
c/kWh
c^Wh
c/kWh
c/kWh
c/kWh
c/kWh
million metric tons 1
1C Engine
2,000
1,283
12
1.8
05
0.111
3.2
3.0
05
6.7
2.0
1.8
05
43
Combustion
Turbine
2,423
1,691
12
15
0.5
0.111
3.8
2.7
05
7.0
2.7
15
05
4.7
(a)
0>)
(c)
(d)
(e)
1
CO
(e)
I]
Notes:
(a) Based on EPA estimate for collection + flare systems (Exhibit 4- 7), in $ 1996. [EPA]
(b) Based on O&M estimates published by Wolfe & Maxwell in "Commercial Landfill Recovery Operations-
Technology and Economics," and in EPA Report to Congress (Exhibit 4-7).
(c) Royalty payments to the landfill owner are estimated to be 10% of revenues (4.9 c/kWh).
(d) Assumes tax-exempt municipal bond financing at 65%.
(e) Calculated by multiplying capital $/kW by CCR and dividing by annual hours of operation.
(f) Conversion system only cost does not include capital and O&M costs associated with LFG collection system.
-------
TABLE A.5 ESTIMATED CAPITAL COSTS (5 million Mg case)
I Example: T^ndfTll waste in place =
5
million metric tons
Combustion Combined
Cost Category
OPERATING DATA
Net sustainable landfill gas production
Gross electric output
Auxiliary and compressor loads
Net electric output
On-line date
Capacity factor (lifetime annual average]
Annual full load operating hours
Annual electricity generated
Units
mcf/day
kW
kW
kW
hours
kWh
1C Engine
2,988
5,188
254
4,934
6/96
80%
7,008
34^77,472
Turbine
2,988
5,188
461
4,727
6/96
80%
7,008
33,126,816
Cycle CT
2,988
7,324
561
6,763
6/96
80%
7,008
47395,104
(a)
(b)
(c)
(d)
EQUIPMENT & INSTALLATION COSTS
Energy Conversion System ($1994)
Engine, auxiliaries, construction
Interconnections (elec, water, LFG)
Gas compressor
Energy conversion system cost
LFG collection system cost ($1994)
Engineering ($1994) @ 5.0%
CAPITAL REQUIREMENT
System cost ($1994)
Soft Costs
Owners costs, escalation, interest
Contingency @ 5.0%
Total Soft Costs
Total Capital Requirement
(as-spent dollars, 1996 on-line date)
Incremental Capital Requirement
(as— spent dollars, 1996 on— line date)
$000
$000
$000
$000
$000
$000
$000
$000
$000
$/kW net
$000
$/kW net
4,075
400
250
4,725
2,088
341
7,154
751
358
1,109
8,263
1,675
5,807
1,177
4,300
400
750
5,450
2,088
377
7,915
804
396
1,200
9,115
1,928
6,659
1,409
7,950
500
750
9,200
2,088
564
11,853
1,248
593
1,841
13,694
2,025
11,216
1,658
(e)
(0
(g)
CO
(i)
G)
Notes:
(a) Based on landfill size of approximately 5 million metric tons. [EPA] (mcf = thousand cubic feet)
1 cf landfill gas = 0.5 cf methane
(b) kW = (cf/hr methane) x (1000 Btu/cf) / (generator Btu/kWh)
(c) Compressor effects: 1C engine—2% parasitic load; CTs—6% parasitic load
(d) Conservative estimated capacity factor over project life. [EPA]
(e) Includes prime mover, generator, plant auxiliaries, construction, LFG modifications, emissions controls.
(f) Assumed to be $350,000 to $450,000 for electric, $50,000 for water.
(g) Calculated based on EPA Exhibit 4-7; includes collection system + flare. [EPA]
(h) Calculated as 5 % of conversion and collection system costs.
(i) Included are owners' costs (legal, permitting, insurance, taxes), escalation during construction (12 - 18 mos)
and interest during construction.
(j) Excludes capital and soft costs associated with the LFG collection system.
-------
TABLE A.6 ESTIMATED COST OF ELECTRICITY (5 million Mg case)
Project Finance Case
I Example: Landfill waste in place =
Cost Category
POWER PROJECT COSTS
Capital Costs (as -spent, 19% online)
Conversion system + collection system
Conversion system only
O&M Costs (1996)
LFG collection system
Conversion system
Royalty Payments (1996)
FIRST YEAR COST OF ELECTRICITY
Capital charge rate (project finance)
Total Electricity Cost
Levelized capacity price
1996 O&M price
Royalty payment
Total 1996 cost of electricity
Incremental Electricity Cost
Levelized capacity price
1996 O&M price
Royalty payment
Total 1996 cost of electricity
5
Units
$/kW
$/kW
c/kWh
c/kWh
c/kWh
(1996)
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
million metric tons 1
1C Engine
1,675
1,177
03
l£
0-5
0.136
32
23
03
6.0
23
1.8
03
4.6
Combustion
Turbine
1,928
1,409
03
13
03
0.136
3.7
2.0
03
6.2
2.7
13
03
4.7
Combined
Cycle CT
2,025
1,658
03
1.6
03
0.136
3.9
2.1
03
63
32
1.6
03
53
(a)
(b)
(c)
(d)
(<0
J
(0
(e)
H
Notes:
(a) Based on EPA estimate for collection + flare systems (Exhibit 4-7), in $1996. [EPA]
(b) Based on O&M estimates published by Wolfe & Maxwell in "Commercial Landfill Recovery Operations—
Technology and Economics," and in EPA Report to Congress (Exhibit 4-7).
(c) Royalty payments to the landfill owner are estimated to be 10% of revenues (4.9 c/kWh).
(d) Assumes: 20-year life, project finance with a 80/20 debt/equity ratio, 9% interest on debt;
includes 15% return on equity; 10-year depreciation.
(e) Calculated by multiplying capital $/kW by CCR and dividing by annual hours of operation.
(f) Incremental Electricity Cost does not include capital and O&M costs associated with LFG collection system.
-------
TABLE A.7 ESTIMATED COST OF ELECTRICITY (5 million Mg case)
Municipal Bond Finance Case
1 Example: T-andfill waste in place =
Cost Category
POWER PROJECT COSTS
Capital Costs (as-spent, 19% online)
Conversion system + collection system
Conversion system only (incremental)
O&M Costs (1996)
LFG collection system
Electric generation system
Royalty Payments (1996)
FIRST YEAR COST OF ELECTRICITY
Capital charge rate (muni bond finance)
Total Electricity Cost
Levelized capacity price
19% O&M price
Royalty payment
I Total 1996 cost of electricity
Incremental Electricity Cost
Levelized capacity price
1996 O&M price
Royalty payment
1 Total 19% cost of electricity
5
Units
$/kW
$/kW
c/kWh
c/kWh
c/kWh
(1996)
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
million metric tons [
1C Engine
1,675
1,177
0.5
1.8
0.5
0.111
2.7
23
0.5
55
1.9
1.8
0.5
4.2
Combustion
Turbine
1,929
1,409
0.5
1.5
0.5
0.111
3.1
2.0
0.5
5.6
22
15
05
4.2
Combined
Cycle CT
2,025
1,658
0.5
1.6
0.5
0.111
32
2.1
0.5
5.8
2.6
1.6
0.5
4.7
(a)
(b)
(c)
(d)
(*)
(0
(e)
Notes:
(a) Based on EPA estimate for collection + flare systems (Exhibit 4-7), in $1996. [EPA]
(b) Based on O&M estimates published by Wolfe & Maxwell in "Commercial Landfill Recovery Operations -
Technology and Economics," and in EPA Report to Congress (Exhibit 4-7).
(c) Royalty payments to the landfill owner are estimated to be 10% of revenues (4.9 c/kWh).
(d) Assumes tax- exempt municipal bond financing at 6.5 %.
(e) Calculated by multiplying capital $/kW by CCR and dividing by annual hours of operation.
(f) Incremental Electricity Cost does not include capital and O&M costs associated with LFG collection system.
-------
TABLE A.8 ESTIMATED CAPITAL COSTS (10 million Mg case)
Example: landfill waste in place =
Cost Category
OPERATING DATA
Net sustainable landfill gas production
Gross electric output
Auxiliary and compressor loads
Net electric output
On-line date
Capacity factor (lifetime annual average)
Annual full load operating hours
Annual electricity generated
EQUIPMENT & INSTALLATION COSTS
Energy Conversion System ($1994)
Engine, auxiliaries, construction
Interconnections (elec, water, LFG)
Gas compressor
Energy conversion system cost
LFG collection system cost ($1994)
Engineering ($1994) @ 5.0%
CAPITAL REQUIREMENT
System cost ($1994)
Soft Costs
Owners costs, escalation, interest
Contingency @ 5.0%
Total Soft Costs
Total Capital Requirement
(as- spent dollars, 1996 on-line date)
Incremental Capital Requirement
(as -spent dollars, 19% on-line date)
10
Units
mcf/day
kW
kW
kW
hours
kWh
$000
$000
$000
$000
$000
$000
$000
$000
$000
$/kW net
$GOO
$/kW net
million metric
1C Engine
5,266
9,142
433
8,709
6/96
80%
7,008
61,032,672
7,200
400
400
8,000
3^99
580
12,179
1,103
609
1,711
13,890
1,595
9,658
1,109
tons
Combustion Combined
Turbine Cvde CT
5,266
9,142
799
8^44
6/96
80%
7,008
58,474,752
7^50
400
900
8,650
3499
612
12,861
1,150
643
1,793
14,654
1,756
10,422
1,249
5,266
12^07
899
12,008
6/96
80%
7,008
84,152,064
13,100
500
900
14400
3499
905
19,004
1,820
950
2,770
21,774
1,813
17,504
1,458
(a)
0>)
(c)
(d)
(e)
(0
(g)
(t)
(0
0)
Notes:
(a) Based on landfill size of approximately 5 million metric tons. [EPA] (mcf = thousand cubic feet)
1 cf landfill gas = 0.5 cf methane
(b) Calculated according to EPA formula: kW = (cf/hr methane) x (1000 Btu/cf) / generator Btu/kWh)
(c) Compressor effects: 1C engine—2% parasitic load; CTs—6% parasitic load
(d) Conservative estimated capacity factor over project life. [EPA]
(e) Includes prime mover, generator, plant auxiliaries, construction, LFG modifications, emissions controls.
(f) Assumed to be $350,000 to $450,000 for electric, $50,000 for water.
(g) Calculated based on EPA Exhibit 4-7; includes collection system + flare. [EPA]
(h) Calculated as 5% of conversion and collection system costs.
(i) Included are owners' costs (legal, permitting, insurance, taxes), escalation during construction (18 mos)
and interest during construction.
(j) Excludes capital and soft costs associated with the LFG collection system.
-------
TABLE A.9 ESTIMATED COST OF ELECTRICITY (10 million Mg case)
Project Finance Case
j Example: Landfill waste in place
Cost Category
POWER PROJECT COSTS
Capital Costs (as -spent, 1996 online)
Conversion system + collection system
Conversion system only
O&M Costs (1996)
LFG collection system
Conversion system
Royalty Payments (1996)
FIRST YEAR COST OF ELECTRICITY
Capital charge rate (project finance)
Total Electricity Cost
Levelized capacity price
1996 O&M price
Royalty Payment
Total 1996 cost of electricity
Incremental Electricity Cost
Levelized capacity price
1996 O&M price
Royalty Payment
Total 1996 cost of electricity
10
Units
$/kW
$/kW
c/kWh
c/kWh
c/kWh
(1996)
c/kWh
c/k\Vh
c/k\Vh
c/k\Vh
c/k\Vh
c/k\Vh
c/k\Vh
c/k\Vh
million metric
1C Engine
1,595
1,109
0.4
1.8
0.5
0.136
3.1
22
0.5
5.8
22
1.8
0.5
4.5
tons j
Combustion
Turbine
1,756
1,249
0.4
13
0.5
0.136
3.4
1.7
0.5
5.6
2.4
1.3
0.5
4.2
Combined
Cycle CT
1,813
1,458
0.4 (a)
1.5 (b)
0.5 (c)
0.136 (d)
3.5 (e)
1.9
0.5
5.9
(0
2.8 (e)
1.5
0.5
4.8
Notes:
(a) Based on EPA estimate for collection + flare systems (Exhibit 4-7), in $1996. [EPA]
(b) Based on O&M estimates published by Wolfe & Maxwell in "Commercial Landfill Recovery Operations -
Technology and Economics," and in EPA Report to Congress (Exhibit 4-7).
(c) Royalty payments to the landfill owner are estimated to be 10% of revenues (4.9 c/kWh).
(d) Assumes: 20-year life, project finance with a 80/20 debt/equity ratio, 9% interest on debt;
includes 15% return on equity; 10-year depreciation.
(e) Calculated by multiplying capital $/kW by CCR and dividing by annual hours of operation.
(f) Conversion s\'stem only cost does not include capital and O&M costs associated with LFG collection system.
-------
TABLE A. 10 ESTIMATED COST OF ELECTRICITY (10 million Mg case)
Municipal Bond Finance Case
1 Example: T-andfni waste in place
Cost Category
POWER PROJECT COSTS
Capital Costs (as-spent, 1996 online)
Conversion system + collection system
Conversion system only
O&M Costs (19%)
LFG collection system
Conversion system
Royalty Payments (1996)
FIRST YEAR COST OF ELECTRICITY
Capital charge rate (muni bond finance)
Total Electricity Cost
Levelized capacity price
1996 O&M price
Royalty Payment
1 Total 1996 cost of electricity
Incremental Electricity Cost
Levelized capacity price
1996 O&M price
Royalty Payment
1 Total 1996 cost of electricity
10
Units
SAW
SAW
c/kWh
c/kWh
c/kWh
(1996)
c/kWh
c/kWh
c/kWh
c/kWh
c/kVfb
c/kWh
c/kWh
c/kWh
million metric
1C Engine
1,595
1,109
0.4
1.8
0.5
0.111
25
22
0.5
52
1.8
1.8
0.5
4.1
tons • |
Combustion
Turbine
1,756
1249
0.4
13
0.5
0.111
2.8
1.7
0.5
5.0
2.0
13
0.5
3.8
Combined
Cycle CT
1,813
1,458
0.4
1.5
0.5
0.111
2.9
1.9
0.5
53
23
1.5
0.5
43
00
(b)
(c)
(d)
(e)
(0
(e)
Notes:
(a) Based on EPA estimate for collection + flare systems (Exhibit 4-7), in $1996. [EPA]
(b) Based on O&M estimates published by Wolfe & Maxwell in "Commercial Landfill Recovery Operations -
Technology and Economics," and in EPA Report to Congress (Exhibit 4-7).
(c) Royalty payments to the landfill owner are estimated to be 10% of revenues (4.9 c/kWh).
(d) Assumes tax-exempt municipal bond financing at 6.5%.
(e) Calculated by multiplying capital $/kW by CCR and dividing by annual hours of operation.
(f) Conversion system only cost does not include capital and O&M costs associated with LFG collection system.
-------
TABLE A.11 COMPARISON OF PROJECT REVENUES & EXPENSES
(1 st Year)
I Example: landfill waste in place =
Revenues
PROJECT FINANCE CASE
Expenses (including Owner's Return)
Total
Incremental
Revenues Minus Expenses
Total
Incremental
1996 Tax Credit
Estimated Surplus (Shortfall) Cash Flow
Total Cost Basis
Incremental Cost Basis
MUNICIPAL BOND FINANCE CASE
Expenses (including financing costs)
Total
Incremental
Revenues Minus Expenses
Total
Incremental
1996 REPI Subsidy
Estimated Surplus (Shortfall) Cash Flow
Total Cost Basis
Incremental Cost Basis
5
Units
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
After Taxes
c/kWh
$000
c/kWh
$000
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
After Taxes
c/kWh
$000
c/kWh
$000
million metric tons • I
Combustion
1C*- cQcmc TtubiDG
4.9 4.9
6.0 62
4.6 4.7
(1.1) (13)
03 02
13 13
and Owner's Return
02 0.0
$69 $0
1.6 1.5
$553 $497
5.0 5.1
3.7 3.7
(0.1) (02)
12 12
0.0 0.0
and Financing Expenses
(0-1) (02)
($35) ($66)
12 12
$415 $398
Combined
Cycle CT
4.9
6.5
53
(1.6)
(0.4)
0.9
(0.7)
($332)
05
$237
53
42
(0.4)
0.7
0.0
(0.4)
($190)
0.7
$332
Notes:
See Tables A. 12-A. 14 for notes on calculations.
-------
TABLE A.12 EXAMPLE POWER PROJECT REVENUES (1st Year)
| Example: Landfill waste in place =
PROJECT OPERATING DATA
Net sustainable landfill gas production
Gross electric output
Net electric output
Annual electricity generated
Electricity used on- site
Net electricity sold to utility
ANNUAL REVENUES
Electricity Sates to Utility in 1st Year
Electricity Sales On-Site in 1st Year
Total Annual Revenues
REVENUES ON PER kWh BASIS
5
Units
mcf/day
kW
kW
kWh
kWh
kWh
$000
$000
$000
c/kWh
million metric
1C Engine
2,988
5,188
4,934
34,577,472
3,000,000
31,577,472
$1422
$177
$1,699
4.9
tons
Combustion Combined
Turbine Cycle CT
2,988
5,188
4,727
33,126,816
3,000,000
30,126,816
$1,452
$177
$1,629
4.9
2,988
7^24
6,763
47^95,104
3,000,000
44395,104
$2,140
$177
$2317
4.9
00
(b)
(c)
(d)
(«)
Notes:
(a) Calculated using statistical model 4.2 in EPA Report to Congress. [EPA] The resulting methane
production estimate is within the range predicted by the models presented in Part I.
(b) Assumed for example purposes.
(c) Product of utility sales kWh and assumed 19% buyback electricity rate of 4.8 c/kWh.
(d) Product of on-site sales kWh and assumed 1996 retail electricity rate of 5.9 c/kWh.
(e) Total annual revenues divided by total kWh generated.
-------
TABLE A.13 COMPARISON OF PROJECT REVENUES & EXPENSES
(1st Year)
Project Finance Case
Example: landfill waste in place =
REVENUES
EXPENSES (including Owner's Return)
Total
Incremental
REVENUES MINUS EXPENSES
Total
Incremental
1996 TAX CREDIT
ESTIMATED SURPLUS (SHORTFALL)
Total Cost Basis
Incremental Cost Basis
5
Units
c/kWh
c/kWh
c/kWh
million metric
1C Engine
4.9
6.0
4.6
c/kWh (1.1)
c/kWh 03
$/MMBtu 1.049
c/kWh 13
CASH AFTER TAXES
c/kWh
$000
c/kWh
$000
0.2
$69
1.6
$553
tons i
Combustion
Turbine
4.9
62
4.7
(13)
02
1.049
13
& OWNER'S
0.0
$0
15
$497
Combined
Cycle CT
4.9
6.5
53
(1.6)
(0.4)
1.049
0.9
RETURN
(0.7)
($332)
0.5
$237
(a)
0>)
(c)
(d)
(e)
(0
Notes:
(a) Calculated in Table A. 12
(b) Calculated in Table A.6. Income taxes, property taxes, and owner's 15% return on equity are included in
these expenses.
(c) Based on a tax credit of $0.979/MMBtu ($1994) escalated for 2 years @ 35%. [PUR]
If only 60% of tax credit is applied to project, credit drops by about 0.5 c/kWh, or about $173,000.
(d) Calculated by multiplying by an electric heat rate of 12.0 MMBtu/MWh for the 1C and CT,
and by 8.5 MMBtu/MWh for the combined cycle CT.
(e) Estimated Income is net of income taxes, property taxes, administrative expenses, and owner's 15% return
on equity. A negative value indicates that first—year cash flow does not cover the owner's desired 15%
return. It is assumed that the project/owner has sufficient tax liability to be able to take full advantage
of the tax credit. In many cases, only about 60% of the tax credit can be used.
-------
TABLE A.14 COMPARISON OF PROJECT REVENUES & EXPENSES
(1st Year)
Municipal Bond Finance Case
I Example: Landfill waste in place =
REVENUES
EXPENSES
Total
Incremental
REVENUES MINUS EXPENSES
Total
Incremental
1996 REPI SUBSIDY
ESTIMATED SURPLUS (SHORTFALL)
Total Cost Basis
Incremental Cost Basis
Units
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
c/kWh
CASH
c/kWh
$000
c/kWh
$000
5 million metric tons
Combustion Combined
1C Engine Turbine Cycle CT
4.9 4.9 4.9 (a)
(b)
5.0 5.1 53
3.7 3.7 42
(0.1) (02) (0.4)
12 12 0.7
0.0 0.0 0.0
AFTER TAXES & FINANCING EXPENSES
(0.1) (02) (0
($35) ($66) ($1S
12 12 0
$415 $398 $32
.4) (c)
«)
.7
12
Notes:
(a) Calculated in Table A.12
(b) Expenses include the financing costs associated with issuing tax-exempt municipal bonds with a 65%
interest rate (see Table A.7)
(c) Estimated Income is net of property taxes, administrative expenses, and bond financing expenses.
A positive value indicates that first-year cash flow exceeds expenses, including the bond debt
service expenses.
-------
TABLE A.15 ESTIMATED MEDIUM-BTU PROJECT CAPITAL COSTS
(1 million Mg case)
1 Example: Landfill waste in place =
Cost Category
OPERATING DATA
Net sustainable landfill gas production
Net fuel output (MMBtu)
On-line date
Capacity factor (lifetime annual average)
Annual full load operating hours
Annual volume of gas sold
EQUIPMENT & INSTALLATION COSTS
Gas Delivery System ($1994)
Condensate removal/filtration
Compressor/Blower station
Pipeline interconnect
Fuel burning equipment conversion
Gas delivery system cost ($1994)
LFG collection system cost ($1994)
Engineering ($1994)
CAPITAL REQUIREMENT
System cost ($1994)
System cost ($1996)
Soft costs($1996)
Owners costs, escalation, interest
Contingency @5.0%
Total Soft Costs
Total Capital Requirement
(as-spent dollars, 1996 on-line date)
Incremental Capital Requirement
1
Units
met/day
MMBtu/day
hours
MMBtu
$000
$000
$000
$000
$000
$000
$000
$000
$000
$000
$000
million metric tons I
Baseload user
(continuous)
642
321
6/96
90%
7,884
105,488
8
75
350
150
583
628
61
1771
1362
85
68
153
1415
729
Heat load user
(seasonal)
642 (a)
321 (b)
6/96
40% (c)
3^04
46,884
8(d)
75 (e)
350(£)
150 to
583
628 (h)
61(i)
1,271
1362
850)
68
153
1^15
729 (k)
Notes:
(a) Based on landfill size of approximately 1 metric ton.[EPA]
(b) Assumes landfill gas has 500 Btu/cf, or 1 cf landfill gas = 05 cf methane.
(c) Assumes caseload user has a year- round need for gas, and heat load user only uses gas in the five winter months.
(d) Based on an estimate obtained from Perry Equipment for liquid and solid filtration system.
(e) Based on estimates published by Wolfe & Maxwell in "Commercial Landfill Recovery Operations -
Technology and Economics", and in Augenstein and Pacey, "T andfill Gas Energy Utilization:
Technology Options and Case Studies"
(f) Based on the cost of a one mile pipeline (pipeline costs can range from $250,000 to $500,000 per mile).
(g) Based on the cost of retrofitting one boiler .[PTI]
(h) Calculated based on EPA Exhibit 4-7; includes collection system + flare. [EPA]
(i) Calculated as 5% of conversion and collection costs.
(j) Included are owners' costs (legal, permitting, insurance, taxes), escalation during construction
(6 months) and interest during construction.
(k) Excludes capital and soft costs associated with the LFG collection system.
-------
TABLE A.16 ESTIMATED COST OF MEDIUM-BTU GAS (IMMgcase)
I Example: Landfill waste in place =
Cost Category
GAS PRODUCTION COSTS
Capital Costs (as -spent, 19% online)
Total capita] requirement
Incremental capital requirement:
O&M Costs (19%)
LFG collection system
Gas delivery system
Tax Credit (1996)
FIRST YEAR COST OF GAS (1996)
Capital charge rate
Total Gas Cost
Levelized capacity price
19% O&M price
Total 19% cost of gas
Cost of gas including tax credit
Incremental Gas Cost
Levelized capacity price
19% O&M price
Total 19% cost of gas
Cost of gas including tax credit
1 million metric tons
Units Baseloaduser Heat load user
(continuous) (seasonal)
00
$/MMBtu 1436 3231
$/MMBtu 6.91 15.56
$/MMBtu 0.84 1.89 (b)
$/MMBtu 0.11 026 (c)
$/MMBtu 1.049 1.049 (d, h)
0.136 0.136 (e)
$/MMBtu 1.95 439 (f)
$/MMBtu 0.95 2.14
$/MMBtu 2.91
$/MMBtu 1.86
$/MMBtu 0.94
$/MMBtu 0.11
$/MMBtu 1.05
$/MMBtu 0.01
6.54
5.49
(g)
2.12
0.26
2371
132!
Notes:
(a) Assumes annual gas sales of 105,488 MMBtu to baseload user and 46,884 MMBtu to heat load user.
(b) Based on EPA estimate for collection + flare systems (Exhibit 4-7), escalated to $19%. [EPA]
(c) Based on pipeline delineation costs and minor filtration system maintenance costs. [Augenstein and Pacey]
(d) Based on a tax credit value of $0.979/MMBtu ($1994), escalated for 2 years. [PUR]
(e) Assumes: 20-year life, project finance with a 80/20 debt/equity ratio, 9% interest on debt;
includes 15% return on equity, 10-year depreciation
(f) Calculated by multiplying capital $/MMBtu by CCR.
(g) Incremental Gas Cost does not include capital and O&M costs associated with LFG collection system.
(h) Assumes total value of tax credit goes to the project. In some cases, only a percentage of the tax credit value
will be credited to the project due to transaction costs associated with transferring the credits to a third party.
For example, 60% of the tax credit may be realized by the project developer; therefore, the value of the tax credit
would only be (60% * $1.049), or S0.63/MMBtu.
-------
TABLE A.17 ESTIMATED MEDIUM-BTU PROJECT CAPITAL COSTS
(5 million Mg case)
I Example: 1 .anHfill waste in place =
Cost Category
OPERATING DATA
Net sustainable landfill gas production
Net fuel output (MMBtu)
On-line date
Capacity factor (lifetime annual average)
Annual full load operating hours
Annual volume of gas sold
EQUIPMENT & INSTALLATION COSTS
Gas Delivery System ($1994)
Condensate removal/filtration
Compressor/Blower station
Pipeline interconnect
Fuel burning equipment conversion
Gas delivery system cost ($1994)
LFG collection system cost ($1994)
Engineering ($1994)
CAPITAL REQUIREMENT
System cost ($1994)
System cost ($1996)
Softcosts($1996)
Owners costs, escalation, interest
Contingency @5.0%
Total Soft Costs
Total Capital Requirement
(as-spent dollars, 1996 on-line date)
Incremental Capital Requirement
5
Units
mcf/day
MMBtu/day
hours
MMBtu
$000
$000
$000
$000
$000
$000
$000
$000
$000
$000
$000
million metric tons 1
Baseload user
(continuous)
2,988
1,494
6/96
90%
7,884
490,811
15
100
350
150
615
2,098
136
2,848
3,051
190
153
343
3,394
769
Heat load user
(seasonal)
2,988 (a)
1,494 (b)
6/96
40% (c)
3,504
218,138
15 (d)
100 (e)
350 (f)
150 te)
615
2,098 (h)
f
136(i)
2,848
3,051
190 G)
153
343
3,394
769 (k)
Notes:
(a) Based on landfill size of approximately 5 metric tons.[EPA]
(b) Assumes landfill gas has 500 Btu/cf, or 1 cf landfill gas = 0.5 cf methane.
(c) Assumes baseload user has a year-round need for gas, and heat load user only uses gas in the five winter months.
(d) Based on an estimate obtained from Perry Equipment for liquid and solid filtration system.
(e) Based on estimates published by Wolfe & Maxwell in "Commercial Landfill Recovery Operations -
Technology and Economics", and in Augenstein and Pacey, "Landfill Gas Energy Utilization:
Technology Options and Case Studies"
(f) Based on the cost of a one mile pipeline (pipeline costs can range from $250,000 to $500,000 per mile).
(g) Based on the cost of retrofitting one boiler.[PTI]
(h) Calculated based on EPA Exhibit 4-7; includes collection system + flare. [EPA]
(i) Calculated as 5 % of conversion and collection costs.
(j) Included are owners' costs (legal, permitting, insurance, taxes), escalation during construction
(6 months) and interest during construction.
(k) Excludes capital and soft costs associated with the LFG collection system.
-------
TABLE A.18 ESTIMATED COST OF MEDIUM-BTU GAS (SMMgcase)
1 Example: T-andfill waste in place =
Cost Category
GAS PRODUCTION COSTS
Capital Costs (as-spent, 19% online)
Total capital requirement
Incremental capital requirement
O&M Costs (19%)
LFG collection system
Gas delivery system
Tax Credit (19%)
FIRST YEAR COST OF GAS (1996)
Capital charge rate
Total Gas Cost
Levelized capacity price
1996 O&M price
Total 19% cost of gas
Cost of gas including tax credit
Incremental Gas Cost
Levelized capacity price
19% O&M price
Total 19% cost of gas
Cost of gas including tax credit
Units
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
5 million metric tons 1
Baseload user
(continuous)
6.92
1.57
031
0.02
1.049
0.136
0.94
034
1.28
023
021
0.02
024
(0.81)
Heat load user
(seasonal)
(a)
1556
353
0.70 (b)
0.06 (c)
1.049 (d,h)
0.136 (e)
2.12 (f)
0.75
2.87
1.82
(g)
0.48
0.06
0.53
(051)
Notes:
(a) Assumes annual gas sales to baseload user of 490,811 MMBtu and sales of 218,138 MMBtu to heat load user.
(b) Based on EPA estimate for collection + flare systems (Exhibit 4-7), escalated to $19%. [EPA]
(c) Based on pipeline delineation costs and minor filtration system maintenance costs. [Augenstein and Pacey]
(d) Based on a tax credit value of $0.979/MMBtu ($1994), escalated for 2 years. [PUR]
(e) Assumes: 20-year life, project finance with a 80/20 debt/equity ratio, 9% interest on debt;
includes 15% return on equity, 10-year depreciation
(f) Calculated by multiplying capital $/MMBtu by CCR.
(g) Incremental Gas Cost does not include capital and O&M costs associated with LFG collection system.
(h) Assumes total value of the tax credit goes to the project In some cases, only a percentage of the tax credit value
will be credited to the project due to transaction costs associated with transferring the credits to a third party.
For example, 60% of the credit may be realized by the project developer; therefore, the value of the tax credit
would only be (60% * $1.049), or $0.63/MMBtu.
-------
TABLE A.19 ESTIMATED MEDIUM-BTU PROJECT CAPITAL COSTS
(10 million Mg case)
I Example: Landfill waste in place =
Cost Category
OPERATING DATA
Net sustainable landfill gas production
Net fuel output (MMBtu)
On— line date
Capacity factor (lifetime annual average)
Annual full load operating hours
Annual volume of gas sold
EQUIPMENT & INSTALLATION COSTS
Gas Delivery System ($1994)
Condensate removal/filtration
Compressor/Blower station
Pipeline interconnect
Fuel burning equipment conversion
Gas delivery system cost ($1994)
LFG collection system cost ($1994)
Engineering ($1994)
CAPITAL REQUIREMENT
System cost ($1994)
System cost ($1996)
Softcosts($1996)
Owners costs, escalation, interest
Contingency @5.0%
Total Soft Costs
Total Capital Requirement
(as— spent dollars, 1996 on— line date)
Incremental Capital Requirement
10 million metric tons 1
Units
met/day
MMBtu/day
hours
MMBtu
$000
$000
$000
$000
$000
$000
$000
$000
$000
$000
$000
Baseload user
(continuous)
5,266
2,633
6/96
90%
7,884
864,917
25
200
350
150
725
3,599
216
4,540
4,863
303
243
546
5,410
907
Heat load user
(seasonal)
5,266 (a)
2,633 (b)
6/96
40% (c)
3^04
384,408
25 (d)
200 (e)
350 (f)
150 to
725
3499 (h)
216 (i)
4,540
4,863
303®
243
546
5,410
907 (k)
Notes:
(a) Based on landfill size of approximately 10 metric tons.[EPA]
(b) Assumes landfill gas has 500 Btu/cf, or 1 cf landfill gas = 0.5 cf methane.
(c) Assumes baseload user has a year—round need for gas, and heat load user only uses gas in the five winter months.
(d) Based on an estimate obtained from Perry Eq uipmen t for liquid and solid filtration system.
(e) Based on estimates published by Wolfe & Maxwell in "Commercial Landfill Recovery Operations -
Technology and Economics", and in Augenstein and Pacey, "I andfill Gas Energy Utilization:
Technology Options and Case Studies"
(f) Based on the cost of a one mile pipeline (pipeline costs can range from $250,000 to $500,000 per mile).
(g) Based on the cost of retrofitting one boiler.[PTI]
(h) Calculated based on EPA Exhibit 4-7; includes collection system + flare. [EPA]
(i) Calculated as 5% of conversion and collection costs.
(j) Included are owners' costs (legal, permitting, insurance, taxes), escalation during construction
(6 months) and interest during construction.
(k) Excludes capital and soft costs associated with the LFG collection system.
-------
TABLE A.20 ESTIMATED COST OF MEDIUM-BTU GAS (10M Mg case)
Example: landfill waste in place =
Cost Category
GAS PRODUCTION COSTS
Capital Costs (as-spent, 1996 online)
Total capital requirement
Incremental capital requirement
O&M Costs (1996)
LFG collection system
Gas delivery system
Tax Credit (1996)
FIRST YEAR COST OF GAS (1996)
Capital charge rate
Total Gas Cost
Levelized capacity price
19% O&M price
Total 19% cost of gas
Cost of gas including tax credit
Incremental Gas Cost
Levelized capacity price
19% O&M price
Total 19% cost of gas
Cost of gas including tax credit
10
Units
$/MMBtu
$/MMBtu
S/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
million metric tons 1
Baseload user
(continuous)
625
1.05
025
0.01
1.049
0.136
0.85
027
1.12
0.07
0.14
0.01
0.16
(0.89)
Heat load user
(seasonal)
00
14.07
236
057 (b)
0.03 (c)
1.049 (d,h)
0.136 (e)
1.91 (f)
0.60
251
1.46
(g)
032
0.03
035
(0.70)
Notes:
(a) Assumes annual gas sales to baseload user of 864,917 MMBtu and sales of 384,408 MMBtu to heat load user.
(b) Based on EPA estimate for collection + flare systems (Exhibit 4-7), escalated to $19%. [EPA]
(c) Based on pipeline delineation costs and minor filtration system maintenance costs. [Augenstein and Pacey]
(d) Based on a tax credit value of $0.979/MMBtu ($1994), escalated for 2 years. [PUR]
(e) Assumes: 20-year life, project finance with a 80/20 debt/equity ratio, 9% interest on debt;
includes 15% return on equity, 10-year depreciation
(f) Calculated by multiplying capital $/MMBtu by CCR.
(g) Incremental Gas Cost does not include capital and O&M costs associated with LFG collection system.
(h) Assumes total value of tax credit goes to the project. In some cases, only a percentage of the tax credit value
will be credited to the project due to transaction costs associated with transferring the credits to a third party.
For example, 60% of the credit may be realized by the project developer; therefore, the value of the tax credit
would onty be (60% * S1.049), or $0.63/MMBtu.
-------
APPENDIX B
LIST OF U.S. EPA OFFICES
-------
Page Intentionally Left Blank
-------
U.S. Environmental Protection Agency Offices
EPA
Region
1
2
3
4
5
6
7
EPA Address
Landfill Methane Program
401 M St., SW, 6202J
Washington, DC 20460
John F.Kennedy Federal Bldg.
One Congress Street
Boston, MA 02203
Federal Office Bldg.
26 Federal Plaza
New York, NY 10278
Curtis Building
Sixth and Walnut Streets
Philadelphia, PA 19106
345 Courtland, NE
Atlanta, GA 30308
230 South Dearborn St.
Chicago, IL 60604
First International Bldg.
1202 Elm Street
Dallas, TX 75270
324 E. Eleventh Street
Kansas City, MO 641 06
States
Included in
Region
All
CT, ME, MA,
NH, Rl, VT
NJ, NY,
Puerto Rico,
Virgin
Islands
DE, DC, MD,
PA, VA, WV
AL, FL, GA,
MS, KY, NC,
SC.TN
IL, MN, Ml,
OH, IN, Wl
AR, LA, NM,
OK, TX
IA, KS, Ml,
NE
Regional
Contact
Jeanne
Cosgrove
Christine
DeRosa
Jim
Topsale
Scott
Davis
Charles
Hatten
Mick Cote
Ward
Burns
Phone
202-233-9042
617-565-9451
212-637-4022
215-566-2190
404-347-5014
Ext. 4144
312-886-6031
214-665-7219
913-551-7960
Fax
617-565-4940
212-637-3998
215-566-2124
404-347-3059
312-886-5824
214-665-2164
913-551-7065
-------
EPA
Region
8
9
10
EPA Address
1 860 Lincoln Street
Denver, CO 80295
21 5 Freemont Street
San Francisco, CA 94105
1200 Sixth Avenue
Seattle, WA 981 01
States
Included in
Region
CO, MN, ND,
SD, UT, WY
AZ, CA, HI,
NV, Guam,
American
Samoa
WA, OR, ID,
AK
Regional
Contact
John Dale
Patricia
Bowlin
John
Keenan
Phone
303-312-6934
415-744-1188
206-553-1817
Fax
303-312-6064
415-744-1076
206-553-0110
-------
APPENDIX C
EXECUTIVE SUMMARY OF A POWER PURCHASE
AGREEMENT
-------
Page Intentionally Left Blank
-------
DRAFT North Czrolma. Vsziabh Rate QF Contracts Only! DRAFT
Ptrrehaied Power Agreemmi Dui* l*a»u Company aad (Supplier Noa)
1 EXECUTIVE SUMMARY
1 OF
3 PURCHASED POWER AGREEMENT
4
5 Supplier VaTne
6
7
8 This Executive Summary describes the principal terras and conditions of an agreement (the
9 "Agreement") between Duke Power Company ("Duke") and the owner/operator ("Supplier") of an
10 electric generating facility which is a qualified facility ("QF") under the Public Utilities Regulatory
1J Policies Act of 1978 ("PURPA"). In the event of an inconsistency or conflict between the
12 Agreement and this Executive Summary the terms of the Agreement sb?U apply.
13
14 ARTICLE 1 (Service Requirements) sets forth basic information about Supplier's facility (the
15 "Facility") including, among other things, its nameplate capacity, location of the delivery point
16 where Supplier will deliver energy to Duke, and the Supplier's "Capacity Commitment" (the
17 average capacity in kilowatts Supplier commits to deliver to Duke during On-Peak Hours).
18 Articles 1.6 and 1.7 set forth metering and fuel cost information requirements. Article 1.9 states
19 that back-up and maintenance power for the Facility's auxiliary electrical requirements shall be
20 purchased from Duke pursuant to a separate electric service agreement on an appropriate rate
schedule.
22
23 ARTICLE 2 (Service Regulations and Regulatory Approval) states that the Agreement is
24 contingent upon the Supplier obtaining and maintaining approval from all applicable regulatory
25 bodies. Article 22 states that the provisions of the Agreement are subject to review by the North
26 Carolina Utilities Commission (the "Commission"), and Article 2.3 provides that the sale, delivery,
27 receipt and use of electric power under the Agreement is governed by Duke's Service Regulations
28 as filed with the Commission, and that changes to said regulations upon order of the Commission,
29 which changes are in conflict with the provisions of this Agreement, «:halj control over such
30 provisions. However, Article 2.4 states that to the extent this Agreement is exphaty approved by
31 an order of the Commission, Article 2J2 shall not apply, and the Agreement *baH control over any
32 changes to the Service Regulations except those which relate to extra facilities and metering,
33 Article 2.5 states that whether or not the Agreement is explicity approved by the Commission, it
34 is thereafter subject ro review in a general rate case or by complaint proceeding.
35
36 According to ARTICLE 3 (Term), the term of the Agreement begins on tile date of execution and
37 shall continue for years from the Commercial Operations Date, which is defined in Article
3.4 as the date of the first regular meter reading following receipt by Duke of written notice from
39 the Supplier declaring the Facility to be in Commercial Operation, after the Facility has passed
FOR.M SCNEC.FRM
-------
DRAFT North Carolina Variable Rate QF Contracts OnJy.' DRAFT
Puiebaaod Powr Agreement Duke Power Company and (Supplier N«ae»
1 acceptance testing. The Anticipated Commercial Operations Date is , 199
1 but Supplier may revise the Anticipated Commercial Operations Date one tirng during the first six
3 months following execution of the Agreement, to a date not later than twelve months after the
4 originally specified date.
5
6 Article 32 provides that the Supplier shall notify Duke of the date of the commencement of
7 construction of the Facility, commencement of construction being defined therein.
8
9 Article 3.3 provides that the Tniriai Delivery Date shall be the first date upon which energy is
10 generated by the Facility and delivered to and metered by Duke. The Anticipated Tmnai Delivery
11 Date is . The Supplier may change the Anticipated TnkjaJ Delivery Date on
12 written notice to Duke at least one year prior to the revised date, but in no event may the Tmtial
13 Delivery Date be earlier than .
14
15 Article 3.5 sets forth a procedure to determine the disposition of power produced by the plant after
16 the expiration of this Agreement. Between 45 and 60 months prior to the expiration of this
17 Agreement, Supplier must notify Duke as to whether it wishes to continue to generate electricity
18 at the Facility. If it does, Duks must then, within six months of Supplier's notice, respond by
' notifying Supplier as to whether Duke wishes to continue to purchase energy and capacity. If Duke
20 does wish to continue such purchases, the parties will then enter into good-faith negotiations to
21 conclude a new purchased power agreement. The rates for the new agreement will be determined
22 based upon Duke's then-current projections of avoided capacity and energy costs and other
23 relevant factors. If Duke notifies Supplier that it does not wish to continue to purchase energy and
24 capacity, or if the parties cannot reach a new agreement, then they are to negotiate the disposition
25 of power to be generated at the Facility, provided that Duke is not to be obligated to transmit
26 power from the Facility directly to any ultimate consumers of electricity.
27
28 ARTICLE 4 (Rate Schedule) provides that energy and capacity payments to the Supplier will be
29 determined using the rates or rate formulas set forth in Appendix A, applying the energy credit
30 rates to the KWH delivered to Duke during the On-Peak Hours and Off-Peak Hours (as defined
31 therein) of each month, and applying the capacity credit rates to the K.WH delivered, to Duke
32 during the On-Peak Hours of each month, up to a maximum of 110 percent of the then-applicable^-'
33 Capacity Commitment. Article 4.6 sets forth a mechanism for adjusting the energy in the event
34 the average monthly power factor is less than 90 percent or greater than 97 percent.
35
Article 4.7 provides that payments to be made to the Supplier are conditioned on recovery by Duke
37 of all of said payments from its customers. If Duke is denied such recovery. Duke may reduce
FOR.M SCNEC.FRM (li'31/921 U
-------
DRAFT North Carolina. Variable Rate QF Contracts Only! DRAFT
Pmct»j«L Power Agnemou Duke Power Company *ad (Supplier Name)
1 payments to Supplier to the highest level allowed by the Commission or other regulatory body.
\ If Duke initially recovers payments, but recovery is subsequently disallowed and charged back to
3 Duke, Duke may offset subsequent payments due from Duke to Supplier, or -may require
4 repayment by Supplier.
5
6 ARTICLE 5 (Capacity Commitment) states that Supplier shall operate its generating facilities so
7 as to meet its Capacity Commitment as designated in Article 1.5(b) in each On-Peak Month,
8 Article 5.1(a)-(d) sets forth the definitions of "Capacity Commitment"; "Average On-Peak
9 Capacity"; "Monthly Capacity Ratio" and "Annual Capacity Ratio" -aad the methodologies for
10 calculating them. Article 5.1(e) states that reductions in capacity resulting from Service
1 1 Interruptions (as defined in Article 8), changes in steam sales requirements or for reasons other
12 than Force Majeure that occur during the On-Peak Hours of the On-Peak Months are not
13 excluded from the calculations of the Average On-Peak Capacity and the Capacity Ratios. Article.
14 5. 1 (f) sets forth the circumstances under which On-Peak Months during which performance has
15 been affected by conditions or events of Force Majeure «foan be excluded from or included in the
16 calculation of rhe Annual Capacity Ratio.
17
18 Article 5.2 states that when the Annual Capacity Ratio is less than 90 percent for two consecutive
months, the Capacity Commiiment will automatically be reduced. The revised Capacity
20 Commitment is calculated by multiplying the previous Capacity Commitment by the Annual
21 Capacity Ratio existing at the end of the two-month period. In the event of an automatic Capacity
22 Commitment reduction, pursuant to Article 5.2(a), or an agreed-upon Capacity Commitment
23 reduction pursuant to Article 5.2(b), the costs and damages provisions of Paragraph 11.1
24 apply, according to Article 5.4.
25
26 ARTICLE 6 (Interconnection Facilities) states that Duke will furnish, own and
27 appropriate interconnection facilities in order to serve the Supplier. Supplier shall, upon
28 completion of installation of the Interconnection Facilities, pay a monthly charge totaling, as a
29 preliminary estimate, S _ , which is 1.7 percent of the installed cost. The final costs
30 and charges shall be calculated no earlier than 12 months prior to the installation of the
3 1 Interconnection Facilities. Duke reserves the right to install additional facilities, and to adjust the
32 Interconnection Facilities Charge for such additional facilities or to reflect Commission-approved
33 changes in the Extra Facilities provisions of Duke's Service Regulations.
34
35 ARTICLE 7 (Payments) sea forth billing and paymen; procedures. Duke reserves the right to set
off any amounts due to it from Supplier against any amounts due from Duke to Supplier.
37
FORM SCNEG.FR.M (ll'Jl ?:i ill
-------
DRAFT North Carolina. Variable Rate QF Contracts Only! DRAFT
Purchij«dPo»gAgncn«at Duke Po»g Coaptay ud (Supplier Name*
1 ARTICLE 8 (Service Interruptions) states that, while the parties shall use reasonable diligence to
! provide satisfactory service, they do not guarantee continuous service. Article 8.2 lists conditions
3 or events which are denned as "Service Interruptions." Pursuant to Article 8.3, neither party -sb^H
4 be liable for any loss or damagf! resulting from Service Interruptions, except that Supplier shall be
5 liable to Duke for costs and damages as set forth in Article 11.1 if the occurrence of Service
6 Interruptions results in a capacity reduction.
7
8 ARTICLE 9 (Force Majeure) defines certain circumstances which are "beyond the reasonable
9 control" of the parties as "conditions or events of Force Majeure", and also lists certain events and
10 circumstances which are excluded from that definition. Pursuant to Article 9.3, if certain
11 conditions are met, then the parties are not responsible for any delay or failure of performance due
12 solely to force majeure (except for the requirement for Supplier to begin commercial operation as
13 set forth in Article 3.4). However, notwithstanding Article 9.3, Article 9.4 states that such failures
14 of performance may be excused by force majeure for periods of no longer tfran one year and not
15 beyond the term of the Agreement. Thus, delays or failures of performance, even if excused by
16 force majeure, become defaults one year from the date that the affected party notifies the other
17 party of the condition or event of Force Majeure.- At such ri™. the other party may terminate the
18 Agreement or may, in its sole discretion, extend the period for which the delay or failure in
performance is excused. If, under such circumstances, Duke does not terminate the Agreement,
20 and the condition or event of Force Majeure results in a capacity reduction, then the provisions
21 of Article 5.1(f), which relate to the inclusion or exclusion of months for calculation of the Annual
22 Capacity Ratio, apply. Pursuant to Article 9.5, if the parties anticipate that any condition or event
23 of Force Majeure will cause a capacity reduction, the parties may thereafter agree to reduce the
24 Capacity Commitment, pursuant to Article 5.2(b), with the Supplier paying costs and damages to
25 Duke for such reduction pursuant to Article 11.1.
26
27 ARTICLE 10 (Default) sets forth procedures to be followed in the event of default. Unless the
28 default arises out of a condition or event of Force Majeure, in which event the provisions of Article
29 9 shall apply, the defaulting party is given 60 days to cure the default (except that if it cannot be
30 cured within 60 days with the exercise of due diligence, the defaulting party may submit a plan for
31 the other parry's approval which will correct the default within a reasonable period of time not to
32 exceed six months). If the defaulting parry fails to submit such a plan, or if the other party Herfrr^
33 to approve it, or if the defaulting parry fails to cure the default in conformance with the plaruthen
34 the other party may exercise its rights and remedies as set forth in Article 10. Article 10.2 lists a
35 variety of specific circumstances and events which constitute a default by Supplier,
37
FORM SrVEC.FR.Vl U2/31/921 IV
-------
DRAFT North Carolina. Variable Rats QF Contracts Only! DRAFT
PmchiMd Power Agreement Duke Power Company tad (Supplier Name)
I ARTICLE 11 (Costs and Damages) sets forth certain damages which Supplier may be required to
2 pay to Duke upon occurrence of: each capacity reduction (including agreed upon capacity
3 reductions pursuant to Articles 5.2(b) or 9.5); termination by Duke due to Supplier's default;
4 default by Supplier pursuant to Article 10 which does not result in a termination or reduction in
5 capacity: or termination pursuant to Article 9.4. The costs and damages include: unpaid charges
6 due to Duke including Interconnection Facilities charges; costs associated with the removal of
7 Interconnection Facih'ties; loss due to early retirement of the Interconnection Facilities; and, in the
8 event of a termination or capacity reduction, liquidated damages to compensate Duke for the
9 detrimental effect on Duke's cost of power. The liquidated damages sfriU be calculated pursuant
10 to the formulas in Appendix B. Also, in the event of a default by Supplier which does not result
11 in a termination or capacity reduction, any actual damag^ incurred by Duke shall be paid by
12 Supplier.
13
14 ARTICLE 12 (Operation of the Generating Facilities) sets forth certain responsibilities of the
15 Supplier in its operation of the Facility. These include: Supplier is responsible for providing
16 devices on its equipment to assure that there is no disturbance to Duke's facilities or other
17 customers, and to protect Supplier's equipment from damage; Supplier agrees to operate and
1 g maintain the Facility "in accordance with applicable electric utility industry standards and good
i engineering practices" and in a prudent manner which will produce the mayimnm electric energy
20 output consistent with the Agreement's dispatch and Capacity Commitment provisions; and
21 Supplier shall coordinate its schedule for routine maintenance so that scheduled outages and
22 capacity reductions occur during Off-Peak Hours or Off-Peak Months, with scheduled
23 maintenance resulting in outages or capacity reductions restricted to 45 days per year. Article 12.3
24 includes a chart which sets forth the required minimum advance notice to Duke of scheduled
25 outages according to the duration of the outage. Article 12.4 states that in the event of an
26 emergency condition on Duke's system, Supplier shall increase or decrease the output of the
27 Facility upon Duke's request, within the design limits of the facility.
28
29 ARTICLE 13 (Liability and Indemnity) sets forth liability and indemnity provisions for the
30 Agreeraent. Tae indemnifying parry agrees to be responsible for damages to persons or property
31 arising out of the indemnifying parry's negligent or tom'ous acts, errors or omissions, whether such
32 persons or property are affiliated with the indemnifying parry, the other parry or third parties.
33 Indirect and consequential damages are excluded.
34
35 ARTICLE 14 (Security) sets forth Supplier's obligation to provide security under the Purchased
• Power Agreement ror its performance, including its obligation to pay costs and damages pursuant
37 to Article 11.1. Such Security must be in place within 60 days after the Agreement is approved or
FORM SCNEG.F'LM iliil/9a V
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DRAFT North CaroSna. Variable Rate QF Contracts Ooly! DRAFT
Purebued Po««r Aciccaat Duke Po««r Company and (Supplier Ntrn*)
1 accepted by filing by the Commission, and shall be maintained through the tenn of the Agreement.
1 Article 142 sets forth the formula which shall be used annually to detennine the amount of security
3 required, and provides that the Security may be reduced by 50 percent from the commencement
4 of construction of the Facility until 15 days prior to the Commercial Operations Date. Article 14.3
5 specifies the form of security, which may be an irrevocable standby letter of credit, a performance
6 bond or cash. Articles 14.4 and 14.5 contain provisions designed to ensure that the security
7 remains in force continuously during the term of the Agreement.
8
9 ARTICLE 15 (Communications) sets forth procedures for communications and notices between
10 the parties.
11
12 ARTICLE 16 (Assignability) requires the Supplier to advise Duke and the Commission of any
13 plans to sell, transfer or assign the Facility, and restricts the rights of the parties to assign or
14 subcontract the Agreement and its rights and duties. In most cases consent of the other party
15 (which shall not be unreasonably withheld) is required prior to assignment or subcontracting.
16 However, such consent is not required prior to an aga'gnmgm by Duke to a parent, subsidiary or
17 affiliated corporation, or by Supplier to a trustee or mortgagee pursuant to a financing agreement.
18 In the case of any assignment, with or without prior consent, prior notice must be given to the
"* other parry, the assignee gb^n expressly assnmg the assignor's obligations (but no such
20 shall relieve the assignor of its obligations to perform in the event the assignee fails to perform),
21 the assignment shall not impair any security given by Seller, and the contemplated assign^? must
22 obtain any necessary regulatory approvals including that of the Commission.
23
24 ARTICLE 17 (Miscellaneous) contains various contractual provisions. Supplier should review all
25 of the provisions of Article 17.
26
27 APPENDICES:
28 APPENDIX A sets forth the rate or rate formulas.
29
30 APPE" HDDC B sets forth the formula for calculating liquidated damages.
31
32 APPENDIX C sets forth the estimated Interconnection Facilities charges.
33
34 APPENDIX D sets forth the formulas for calculating the power factor adjustment,
35
APPENDIX E includes Duke's Service Regulations in effect as of the date cf execution of this
37 Agreement.
FORM SCNEG.FRM C.l'Jt«:» VI
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APPENDIX D
SAMPLE REQUEST FOR PROPOSALS FOR LANDFILL
GAS ENERGY PROJECT DEVELOPER
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Page Intentionally Left Blank
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Department of Solid Waste
REQUEST FOR PROPOSALS - LANDFILL GAS
15 July 94
The City is soliciting proposals from environmental or energy management
organizations, user industries, turnkey system providers and environmental
engineering firms for the beneficial use of landfill gas (LFG).
BACKGROUND
The City owns and operates a 200+ acre Solid Waste Management Center
(SWMC) which is managed by the Solid Waste Department. The SWMC
contains a recently closed landfill having a footprint of approximately 52 acres.
That landfill, the focus of this RFP, was originally placed on glacial till and is
now capped with materials in compliance with New York's Part 360
regulations.
The cap design includes a membrane and a series of vent structures.
Underneath the membrane is a permeable layer of natural materials which also
contains a series of collection pipes, all linked to two header pipes emerging
from under the cap at opposite points along the landfill's perimeter. A gravity
leachate interception system has also been constructed beneath the perimeter of
the landfill, leading to a single discharge point wherein any flowing condensate
and residual LFG may be intercepted.
The design principle was to allow for conversion from a passive to an active
LFG system by sealing the vents and activating a pumping system at one or
both of the headers.
Initial measurements suggest natural production of approximately 975,000
cubic feet of LFG each day. This was based on a composite of low pressure
measurements at 53 vent stacks. There are six other emission points were not
measured at the time. Qualitative data is attached, as measured on a Landtec
Gem 500. Data and observations suggest that the entire regime is currently
sensitive to ambient air pressure differentials induced by wind.
Other features within the SWMC include:
1) a separate new active landfill with a present 10 acre footprint
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and a loading rate of approximately 34,000 tons per year, which
began operations in Sept. '92,
2) a 4,000 s.f. maintenance building for department vehicles and
equipment,
3) overhead electric transmission lines with various voltages,
4) underground natural gas (high pressure) pipelines,
5) a 650,000 gallon glass lined steel open top storage tank for
leachate (emergency use only), and
6) an improved roadway system between features.
Planned or contemplated improvements within or immediately adjacent to the
SWMC include:
a) a compost processing area for vegetative waste materials,
b) artificial wetlands for partial or full treatment of landfill
leachate,
c) a major structure for processing recyclable materials, possibly
linked with a privately operated manufacturing enterprise
utilizing recycled materials as feedstock(s), and
d) a new central garage facility within the SWMC for City owned
vehicles.
Adjacent to the SWMC is an industrial park, including a major facility for the
manufacture of air conditioning equipment and several other manufactures.
Approximately 50 acres remain available for development. The Park is
entirely within a NYS Economic Development Zone ("EDZ").
Nearby is a wastewater treatment plant which is owned and operated by the
City (land linked). It contains a sludge incinerator and numerous pumps.
The City's Utilities Department operates two hydroelectric generation plants
(combined 1.2 MW) and has plans for at least one additional plant in the near
future.
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Major intercepting sewer system components are located within contiguous
City-owned rights of way.
RESPONDENTS SHOULD TAKE INTO CONSIDERATION THAT IT IS
THE CITY'S INTENT TO MAXIMIZE THE USE AND BENEFIT OF ALL
AVAILABLE CITY RESOURCES AND INFRASTRUCTURE IN THE
MOST COST-EFFECTIVE MANNER POSSIBLE.
REQUEST FOR PROPOSALS
The City views the LFG at the SWMC as an untapped resource whose
collection system is installed. Primary interest is in LFG utilization with
maximum benefit to the City as a return on the substantial investment made in
the SWMC to data. This benefit may take the form of one or more of the
following:
• simplified sale of the LFG "as is, where is",
• royalties based on LFG utilization by others,
• direct earnings after additional investment in enterprise by the
City, and
• realized savings from avoided costs (to obtain other conventional
fuels).
The City and/or its agents are willing to consider conventional contracts,
"Performance Based" contracts, partnerships, joint ventures, management
agreements, and other appropriate mechanisms respondents may propose.
REQUIRED COMPONENTS OF RESPONSES
1) A basic component of all responsive proposals must be the provision of
sufficient professional engineering services to accurately and
responsibly portray technical issues regarding the complex medium of
landfill gas, and do so gracefully within the arena of environmental
regulations as they are administered by the New York State DEC and
the federal EPA. As a minimum, flaring or any alternative backup
methodology is to be included in order to avoid reversion to a passive
venting system except under significant emergency conditions. A
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permanent and adequate LFG monitoring system is to be included in
this component.
2) Additional components should address one or more means by which the
energy represented in combustible gas can be harnessed, either by
direct combustion of LFG or subsequent to refinement. Proposals
incorporating utilization of byproduct gas (from refinement) are
encouraged.
3) Since LFG production is presumed to remain relatively constant
throughout the year, additional components should also address
levelizing consumption or incorporating storage if necessary or
beneficial.
4) Any necessary design or structural adjustments to the existing LFG
collection system must be clearly stated.
5) Proposals incorporating electrical energy distribution beyond a local
regulated system should also address matters relating to wheeling.
6) Respondents are encouraged to incorporated design and
operations procedures adjustments for the currently operating
landfill (also within the SWMC) in order to capitalize on
increasing amounts of LFG being generated therein.
7) Proposals should clearly state the nature of the initial working
relationship between the City and the proposer. It should also state any
proprietary interest the proposer has in other proposed or operating
LFG utilization systems.
8) If proposers include subordinated or collaborative roles by other
organizations, those roles should be clearly stated.
ILLUSTRATIONS OF POTENTIAL RELATIONSHIPS WITH AUBURN
1) As consultant, providing professional engineering or management
services - with the City fully responsible for fiscal implementation with
or without contracted operations services.
2) As turnkey provider of a designed, permitted and constructed facility
with all user/sales agreements in place.
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3) As wellhead purchaser of LFG with or without lease/purchase of real
estate within the SWMC and/or industrial park.
4) As equity partner in the development and operation of a LFG system
and/or related enterprise, utilizing subordinated engineering services.
5) As long term contractor for inclusion of LFG as part of more extensive
solid waste management services.
6) As federal/state research and development agency, sharing an equity
role.
Proposers are invited to counsel the City regarding the technical and business
merits of as many LFG utilization options as appear to be practical for the
City to independently or mutually pursue toward the goals of increasing
revenue and/or avoiding costs: and, leveraging this resource as a development
incentive for new enterprises. They may also be direct action proposals.
It is not the intent of this RFP to emphasize the need for further detailed
quantitative or qualitative analysis of LFG presently generated within the
SWMC.
Most aspects of proposals are considered to be public domain. Those aspects
considered to be proprietary should be identified and bound separately,
thereupon they will honored as such. Until such time as formal negotiations
begin with a selected proposer, it is suggested that cost and/or investment
information be stated in ranges. Cost and/or investment information will be
kept confidential during negotiations, but final agreements will be public
domain.
PROPOSAL TIMETABLE
The City is actively pursuing construction projects which may benefit from the
use of LFG. It is also mindful of the value lost while passive ventilation of
LFG takes place. Due to the potential complexity of different proposals, only
a target date of 1 Aug 94 has been established. Following an initial response
of interest (together with any generic qualification information), the City will
schedule a preproposal conference, during which time all available information
regarding the SWMC, the neighboring industrial park, and potentially related
City projects can be reviewed. Field orientation will also be provided.
Potential proposers will be canvassed regarding preparation time before a final
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proposal date is established.
TENTATIVE SCHEDULE
RFP available/mailed to prospective respondents 15 July 94
Initial expression of interest to City by 27 July 94
Preproposal conference, incl. site visit wk of 1 Aug 94
Repeat preproposal conf., as needed 3rd wk of August
Proposal Submission Date: 15 Sept 94
CITY'S PROPOSAL EVALUATION TEAM
The team will consist of the City Manager, the Utilities Director, the
Solid Waste Director, the Corporation Counsel, and a member of the City
Council. The same team will later guide formal agreements to conclusion.
PROPOSAL EVALUATION CRITERIA
Proposals will be evaluated in terms of:
• comprehensiveness 20%
• creativity 10%
• earnings potential for City 50%
• recognition of solid waste priorities 10%
• recognition of environmental concerns 10%
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BRIEF SOLID WASTE HISTORY IN AUBURN
Since it's founding over 200 years ago, the City gradually became involved in
waste disposal, first as provider of various dumps, then as collector. Burning
dumps finally became a thing of the past in the 1950's with the most recent
one being along the edge of North Division St. - at the entrance to the
SWMC.
Collection services for garbage and trash became more precise as interest grew
in recycling. At about the same time the State regulations were strengthening
with regard to land disposal.
Disposal operations continued on the large site at the extreme Northwest
corner of the City, but now as a sanitary landfill. Burning practices stopped.
A new section of the site was utilized, but liner systems had not yet entered
the regulatory regime. Wastes came in from many areas of Cayuga County,
and even portions of neighboring Onondaga County.
Between the 1950's and 1980's many on Auburn's older structures were
demolished as the economic base shifted away from a wide variety of
manufacturing, which had origins along the waterway running through the
center of the City. Remains of several factories and related structures ended
up in the (common) landfill, which was extended laterally over the relatively
tightly compacted natural ground. The entire site has a complex geologic
history due in part to glacial movements.
As solid waste matters came more into focus, New York's plans and
regulations evolved into some of the most sophisticated in the nation. It
became a common objective to switch away from unlined landfills to lined
ones.
Auburn's 50 acre+ landfill was one slated for closure. The City was destined
by plan to continue providing and disposal capacity for the entire county. A
replacement landfill was built on lands partly within the City and partly on
lands acquired by the City and later annexed.
New York's regulatory standards for closure of all landfills continued to
strengthen, and Auburn suddenly faced a multi million dollar closure
investment toward the end of the landfill's permitted life. To meet those
costs, the City worked out a Consent Order with the NYSDEC to continue
operating in the then existing landfill, (known as Landfill No. 1), while
constructing a new lined Landfill No. 2. During this window of opportunity
for raising closure capital, the City allowed importation of large quantities of
waste from distant sources, which was allowable since no lateral expansion of
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the footprint was necessary.
Hence, during the final two years of its operation (ending 15 Sept 92), Landfill
No. 1 commonly received up to 2,500 tons of waste per day, up from the
routine amount by a factor of at least 10. All of those wastes were added to
the relatively low and spread out landfill as it had evolved prior to
importation. For that short period of time, the operation was more similar to
those of larger metropolitan systems.
Landfill's No. 1's closure included some regarding, the placement of a more
rational means to intercept remaining leachate, and a circumfrential roadway.
Capping was begun on a North Slope even while filling continued to the
South. The first detailed engineering work was done by C&S Engineers, and
construction was by the Haseley Trucking Co.
After Landfill No. 2 opened, waste importation ceased. Tonnage abruptly
returned to more "normal" levels. At that time, the South Slope closure work
was begun with Steams & Whaler providing engineering services and the Tug
Hill Construction company doing the improvements. With winter shutdowns,
it took just under two years to complete closure construction at an overall cost
approaching $10 million. Coordination of side by side engineering and
construction was provided by the Department, with a welcomed role played by
the Regional Office of the NYSDEC.
The City has developed an entrepreneurial approach to fiscal integrity. The
SWMC will continue to play a strong role in providing revenue to the general
fund. This will likely take several forms, as more and more management
strategies are developed! particular components of the solid waste stream. The
City considers it prudent to only landfill those materials which cannot be
managed within higher priority methodologies.
The benefit, as such, from large scale recent waste intake is now the natural
production of an energy source. It is the City's objective to harness that
energy to the benefit of the city as a whole, and/or the direct benefit to higher
priority management of those wastes which do not have to be landfilled.
In its present configuration, the SWMC will continue to meet the needs of the
Local Planning Unit (Cayuga County) for decades to come.
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APPENDIX E
EPA MEMORANDUM ON POLLUTION CONTROL
PROJECTS AND NEW SOURCE REVIEW (NSR)
APPLICABILITY
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Page Intentionally Left Blank
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK. NC 27711
Of
AIR QUALITY PLANNING
AND STANCAftOS
JUL I 1994
MEMORANDUM
SUBJECT: Pollution Control Projects and New S$irc\e Review (NSR)
Applicability
S. Seitz, Directoi
Office of Air Quality pl/hning/axid Standards (MD-10)
U
TO: Director, Air, Pesticides and Toxics
Management Division, Regions I and IV
Director, Air and Waste Management Division,
Region II
Director, Air, Radiation and Toxics Division,
Region III
Director, Air and Radiation Division,
Region V
Director, Air, Pest:^ides and Toxics Division,
Region VI
Director, Air and Toxics Division,
Regions VII, VIII, IX and X
This memorandum and attachment address issues involving the
Environmental Protection Agency's (EPA's) NSR rules and guidance
concerning the exclusion from major NSR of pollution control
projects at existing sources. The attachment provides a full
discussion of the issues and this policy, including illustrative
examples.
For several years, EPA has had a policy of excluding certain
pollution control projects from the NSR requirements of parts C
and D of title I of the Clean Air Act (Act) on a case-by-case
basis. In 1992, EPA adopted an explicit pollution control
project exclusion for electric utility generating units [see
57 PR 32314 (the "WEPCO rule" or the "WEPCO ruleaaking")]. At
the time, EPA indicated that it would, in a subsequent
rulemaking, consider adopting a formal pollution control project
exclusion for other source categories [see 57 PR 32332]. In the
interim, EPA stated that individual pollution control projects
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involving source categories other than utilities could continue
to be excluded from NSR by permitting authorities on a case-by-
case basis [see 57 FR at 32320]. At this time, EPA expects to
complete a rulemaking on a pollution control project exclusion
for other source categories in early 1996. This memorandum and
attachment provide interim guidance for permitting authorities on
the approvability of these projects pending EPA's final action on
a formal regulatory exclusion.
The attachment to this memorandum outlines in greater detail
the type of projects that nay qualify for a conditional exclusion
from NSR as a pollution control project, the safeguards that are
to be met, and the procedural steps that permitting authorities
should follow in issuing an exclusion. Projects that do not meet
these safeguards and procedural steps do not qualify for an
exclusion from NSR under this policy. Pollution control projects
potentially eligible for an exclusion (provided all applicable
safeguards are net) include the installation of conventional or
innovative emissions control equipment and projects undertaken to
accommodate switching to an inherently less-polluting fuel, such
as natural gas. Under this guidance, States may also exclude as
pollution control projects some material and process changes
(e.g., the switch to a less polluting coating, solvent, or
refrigerant) and some other types of pollution prevention
projects undertaken to reduce emissions of air pollutants subject
to regulation under the Act.
The replacement of an existing emissions unit with a newer
or different one (albeit more efficient and less polluting) or
the reconstruction of an existing emissions unit does not qualify
as a pollution control project. Furthermore, this guidance only
applies to physical or operational changes whose primary function
is the reduction of air pollutants subject to regulation under
the Act at existing major sources. This policy does not apply to
air pollution controls and emissions associated with a proposed
new source. Similarly, the fabrication, manufacture or
production of pollution control/prevention equipment and
inherently less-polluting fuels or raw materials are not
pollution control projects under this policy (e.g., a physical or
operational change for the purpose of producing reformulated
gasoline at a refinery is not a pollution control project).
It is EPA's experience that many bona fide pollution control
projects are not subject to major NSR requirements for the simple
reason that they result in a reduction in annual emissions at the
source. In this way, these pollution control projects are
outside major NSR coverage in accordance with the general rules
for determining applicability of NSR to modifications at existing
sources. However, some pollution control projects could result
in significant potential or actual increases of some pollutants.
These latter projects comprise the subcategory of pollution
control projects that can benefit from this guidance.
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A pollution control project must be, on balance,
"environmentally beneficial" to be eligible for an exclusion.
Further, an environmentally-beneficial pollution control project
may be excluded from otherwise applicable major NSR requirements
only under conditions that ensure that the project will not cause
or contribute to a violation of a national ambient air quality
standard (NAAQS), prevention of significant deterioration (PSD)
increment, or adversely affect visibility or other air quality
related value (AQRV). In order to assure that air quality
concerns with these projects are adequately addressed, there are
two substantive and two procedural safeguards which are to be
followed by permitting authorities reviewing projects proposed
for exclusion.
First, the permitting authority must determine that the
proposed pollution control project, after consideration of the
reduction in the targeted pollutant and any collateral effects,
will be environmentally beneficial. Second, nothing in this
guidance authorizes any pollution control project which would
cause or contribute to a violation of a NAAQS, or PSD increment,
or adversely impact an AQRV in a class I area. Consequently, in
addition to this "environmentally-beneficial" standard, the
permitting authority must ensure that adverse collateral
environmental impacts from the project are identified, minimized,
and, where appropriate, mitigated. For example, the source or
the State must secure offsetting reductions in the case of a
project which will result in a significant increase in a
nonattainment pollutant. Where a significant collateral increase
in actual emissions is expected to result from a pollution
control project, the permitting authority must also assess
whether the increase could adversely affect any national ambient
air quality standard, PSD increment, or class I AQRV.
In addition to these substantive safeguards, EPA is
specifying two procedural safeguards which are to be followed.
First, since the exclusion under this interim guidance is only
available on a case-by-case basis, sources seeking exclusion from
major NSR requirements prior to the forthcoming EPA rulemaking on
a pollution control project exclusion must, before beginning
construction, obtain a determination by the permitting authority
that a proposed project qualifies for an exclusion from major NSR
requirements as a pollution control project. Second, in
considering this request, the permitting authority must afford
the public an opportunity to review and comment on the source's
application for this exclusion. It is also important to note
that any project excluded from major new source review as a
pollution control project must still comply with all otherwise
applicable requirements under the Act and the State
implementation plan (SIP), including minor source permitting.
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This guidance document does not supersede existing Federal
or State regulations or approved SIP's. The policies set out in
this memorandum and attachment are intended as guidance to be
applied only prospectively (including those projects currently
under evaluation for an exclusion) during the interim period
until EPA takes action to revise its NSR rules, and do not
represent final Agency action. This policy statement is not ripe
for judicial review. Moreover, it is not intended, nor can it be
relied upon, to create any rights enforceable by any party in
litigation with the United States. Agency officials may decide
to follow the guidance provided in this memorandum, or to act at
variance with the guidance, based on an analysis of specific
circumstances. The EPA also may change this guidance at any time
without public notice. The EPA presently intends to address the
matters discussed in this document in a forthcoming NSR
rulemaking regarding proposed changes to the program resulting
from the NSR Reform process and will take comment on these
matters as part of that rulemaking.
As noted above, a detailed discussion of the types of
projects potentially eligible for an exclusion from major NSR as
a pollution control project, as well as the safeguards such
projects must meet to qualify for the exclusion, is contained in
the attachment to this memorandum. The Regional Offices should
send this memorandum with the attachment to States within their
jurisdiction* Questions concerning specific issues and cases
should be directed to the appropriate EPA -Regional Office.
Regional Office staff may contact David Solomon, Chief, New
Source Review Section, at (919) 541-5375, if they have any
questions.
Attachment
cc: Air Branch Chief, Regions I-X
NSR Reform Subcommittee Members
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Attachment
GUIDANCE ON EXCLUDING POLLUTION CONTROL PROJECTS
FROM MAJOR NEW SOURCE REVIEW (NSR)
I. Purpose
The Environmental Protection Agency (EPA) presently expects
to complete a rulemaking on an exclusion from major NSR for
pollution control projects by early 1996. in the interim,
certain types of projects (involving source categories other than
utilities) may qualify on a case-by-case basis for an exclusion
from major NSR as pollution control projects. Prior to EPA's
final action on a regulatory exclusion, this attachment provides
interim guidance for permitting authorities on the types of
projects that may qualify on a case-by-case basis from major NSR
as pollution control projects, including the substantive and
procedural safeguards which apply.
II. Background
The NSR provisions of part C [prevention of significant
deterioration (PSD) ] and part D (nonattainment requirements) of
title I of the Clean Air Act (Act) apply to both the construction
of major new sources and the modification of existing major
sources.1 The modification provisions of the NSR programs in
parts C and D are based on the broad definition of modification
in section 111(a)(4) of the Act. That section contemplates a
two-step test for determining whether activities at an existing
major facility constitute a modification subject to new source
requirements. In the first step, the reviewing authority
determines whether a physical or operational change will occur.
In the second step, the question is whether the physical or
operational change will result in any increase in emissions of
any regulated pollutant.
The definition of physical or operational change in
section 111(a)(4) could, standing alone, encompass the most
mundane activities at an industrial facility (even the repair or
replacement of a single leaky pipe, or a insignificant change in
the way that pipe is utilized). However, EPA has recognized that
Congress did not intend to make every activity at a source
subject to new source requirements under parts C and D. As a
result, EPA has by regulation limited the reach of the
modification provisions of parts C and D to only major
modifications. Under NSR, a "major modification" is generally a
physical change or change in the method of operation of a major
stationary source which would result in a significant net
emissions increase in the emissions of any regulated pollutant
*The EPA's NSR regulations for nonattainnent areas are set
forth at 40 CFR 51.165, 52.24 and part 51, Appendix S. The PSD
program is set forth in 40 CFR 52.21 and 51.166.
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[see, e.g., 40 CFR 52.21(b)(2)(i)]. A "net emissions increase"
is defined as the increase in "actual emissions" from the
particular physical or operational change together with any oth^r
contemporaneous increases or decreases in actual emissions rsee"
e.g., 40 CFR 52.21(b) (3) (i)]. In order to trigger maj-or new
source review, the net emissions increase must exceed specified
"significance" levels [see, e.g., 40 CFR 52.21(b)(2)(i) and 40
CFR 52.21(b)(23)]. The EPA has also adopted common-sense
3°e "Physical or operational change" component of
the definition of "ma}or modification." For example EPA's
regulations contain exclusions for routine maintenance reoair
and replacement; for certain increases in the hours of'operation
or in the production rate; and for certain types of fuel switch**
[see, e.g., 40 CFR 52.21(b)(2)(iii)]. switches
In the 1992 "WEPCO" rulemaking [57 FR 32314], EPA amended
its PSD and nonattainment NSR regulations as they pertain to
utilities by adding certain pollution control projects to the
list of activities excluded from the definition of physical or
operational changes. In talcing that action, EPA stated it was
largely formalizing an existing policy under which it had been
excluding individual pollution control projects where it was
found that the project "would be environmentally beneficial
taking into account ambient air quality" [57 FR at 32320; see
also id., n. 15].2
The EPA has provided exclusions for pollution control
projects in the fora of "no action assurances" prior to
November 15, 1990 and nonapplicability determinations based on
Act changes as of November 15, 1990 (1990 Amendments).
Generally, these exclusions addressed clean coal technology
projects and fuel switches at electric utilities.
Because the WEPCO rulemaking was directed at the utility
industry which faced "massive industry-wide undertakings of
pollution control projects" to comply with the acid rain
provisions of the Act [57 FR 32314], EPA limited the types of
projects eligible for the exclusion to add-on controls and fuel
switches at utilities. Thus, pollution control projects under
the WEPCO rule are defined as:
any activity or project undertaken at an
existing electric utility steam generating
unit for purposes of reducing emissions from
such unit. Such activities or projects are
limited to;
guidance pertains only to source categories other than
electric utilities, and EPA does not intend for this guidance to
affect the WEPCO rulemaking in any way.
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(A) The installation of conventional or
innovative pollution control technology,
including but not limited to advanced flue
gas desulfurization, sorbent injection for
sulfur dioxide (SO2) and nitrogen oxides (-NOX)
controls and electrostatic precipitators;
(B) An activity or project to accommodate
switching to a fuel which is less polluting
than the fuel in use prior to the activity or
project . . .
[40 CFR 51.165(a)(1)(xxv) (emphasis added)].
The definition also includes certain clean coal technology
demonstration projects. Id.
The EPA built two safeguards into the exclusion in the
rulemaking. First, a project that meets the definition of
pollution control project will not qualify for the exclusion
where the "reviewing authority determines that (the proposed
project) renders the unit less environmentally beneficial ..."
[see, e.g., 51.165(a)(1)(v)(C)(8)]. In the WEPCO rule, EPA did
not provide any specific definition of the environmentally-
beneficial standard, although it did indicate that the pollution
control project provision "provides for a case-by-case assessment
of the pollution control project's net emissions and overall
impact on the environment" [57 FR 32321]. This provision is
buttressed by a second safeguard that directs permitting
authorities to evaluate the air quality impacts of pollution
control projects that could—through collateral emissions
increases or changes in utilization patterns—adversely impact
local air quality [see 57 FR 32322]. This provision generally
authorizes, as appropriate, a permitting authority to require
modelling of emissions increases associated with a pollution
control project. Id. More fundamentally, it explicitly states
that no pollution control project under any circumstances may
cause or contribute to violation of a national ambient air
quality standard (NAAQS), PSD increment, or air quality related
value (AQRV) in a class I area. Id.3
3The WEPCO rule refers specifically to "visibility
limitation" rather than "air quality related values." However,
EPA clearly stated in the preamble to the final rule that
permitting agencies have the authority to "solicit the views of
others in taking any other appropriate remedial steps deemed
necessary to protect class I areas.... The EPA emphasizes that
all environmental impacts, including those on class I areas, can
be considered. . .." [57 FR 32322]. Further, the statutory
protections in section 165(d) plainly are intended to protect
against any "adverse impact on the AQRV of such [class I] lands
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As noted, the WEPCO rulemaJcing was expressly limited to
existing electric utility steam generating units [see, eg 40
CFR 51.165 (a) (1) (v) (C) (8) and 51.165(a) (1) (xx) ]. The EPA United
the rulemaking to utilities because of the impending acid rain
requirements under title IV of the Act, EPA's extensive
experience with new source applicability issues for electric
utilities, the general similarity of equipment, and the public
availability of utility operating projections. The EPA indicated
it would consider adopting a formal NSR pollution control project
exclusion for other source categories as part of a separate NSR
rulemaking. The rulemaJcing in question is now expected to be
finalized by early 1996. On the other hand, the WEPCO rulemaJcing
also noted that EPA's existing policy was, and would continue to
be, to allow permitting authorities to exclude pollution control
projects in other source categories on a case-by-case basis.
III. Case-By-Case Pollution control Project Determinations
The following sections describe the type of projects that
may be considered by permitting authorities for exclusion from
major NSR as pollution control projects and two safeguards that
permitting authorities are to use in evaluating such projects—
the environmentally-beneficial test and an air quality impact
assessment. To a large extent, these requirements are drawn from
the WEPCO rulemaJcing. However, because the WEPCO rule was
designed for a single source category, electric utilities, it
cannot and does not serve as a complete template for this
guidance. Therefore, the following descriptions expand upon the
WEPCO rule in the scope of qualifying projects and in the
specific elements inherent in the safeguards. These changes
reflect the far more complicated task of evaluating pollution
control projects at a wide variety of sources facing a myriad of
Federal, State, and local clean air requirements.
Since the safeguards are an integral component of the
exclusion, States must have the authority to impose the
safeguards in approving an exclusion from major NSR under this
policy. Thus, State or local permitting authorities in order to
use this policy should provide statements to EPA describing and
affirming the basis for its authority to impose these safeguards
absent major NSR. Sources that obtain exclusions from permitting
authorities that have not provided this affirmation of authority
are at risk in seeking to rely on the exclusion issued by the
(including visibility)." Based on this statutory provision, EPA
believes that the proper focus of any air quality assessment for
a pollution control project should be on visibility and any other
relevant AQRV's for any class I areas that may be affected by the
proposed project. Permitting authorities should notify Federal
Land Managers where appropriate concerning pollution control
projects which may adversely affect AQKV's in class I areas.
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permitting agency, because EPA may subsequently determine that
the project does not qualify as a pollution control project under
this policy.
A. Types of Projects Covered
1. Add-On Controls and Fuel Switches
In the WEPCO rulemaking, EPA found that both add-on
emissions control projects and fuel switches to less-polluting
fuels could be considered to be pollution control projects. For
the purposes of today's guidance, EPA affirms that these types of
projects are appropriate candidates for a case-by-case exclusion
as well. These types of projects include:
- the installation of conventional and advanced flue gas
desulfurization and sorbent injection for SO,;
- electrostatic precipitators, baghouses, high efficiency
multiclones, and scrubbers irsr particulate or other
pollutants;
- flue gas recirculation, low-NO, burners, selective non-
catalytic reduction and selective catalytic reduction for
NOS; and
- regenerative thermal oxidizers (RTO), catalytic
oxidizers, condensers/ thermal incinerators, flares and
carbon adsorbers for volatile organic compounds (VOC)
and toxic air pollutants.
Projects undertaken to accommodate switching to an
inherently less-polluting fuel such as natural gas can also
qualify for the exclusion. Any activity that is necessary to
accommodate switching to a inherently less-polluting fuel is
considered to be part of the pollution control project. In some
instances, where the emissions unit's capability would otherwise
be impaired as a result of the fuel switch, this may involve
certain necessary changes to the pollution generating equipment
(e.g., boiler) in order to maintain the normal operating
capability of the unit at the time of the project.
2. Pollution Prevention Projects
It is EPA's policy to promote pollution prevention
approaches and to remove regulatory barriers to sources seeking
to develop and implement pollution prevention solutions to the
extent allowed under the Act. For this reason, permitting
authorities may also apply this exclusion to switches to
inherently less-polluting raw materials and processes and certain
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other types of "pollution prevention" projects.4 For instance,
many VOC users will be making switches to water-based or powder-
paint application systems as a strategy for meeting reasonably
available control technology (RACT) or switching to a non-toxic
VOC to comply with maximum achievable control technology (MACT)
requirements.
Accordingly, under today's guidance, permitting authorities
may consider excluding raw material substitutions, process
changes and other pollution prevention strategies where the
pollution control aspects of the project are clearly evident and
will result in substantial emissions reductions per unit of
output for one or more pollutants, in judging whether a
pollution prevention project can be considered for exclusion as a
pollution control project, permitting authorities may also
consider as a relevant factor whether a project is being
undertaken to bring a source into compliance with a MACT, RACT,
or other Act requirement.
Although EPA is supportive of pollution control and
prevention projects and strategies, special care must be taken in
classifying a project -as a pollution control project and in
evaluating a project under a pollution control project exclusion.
Virtually every modernization or upgrade project at an existing
industrial facility which reduces inputs and lowers unit costs
has the concurrent effect of lowering an emissions rate per unit
of fuel, raw material or output. Nevertheless, it is clear that
these major capital investments in industrial equipment are the
very types of projects that Congress intended to address in the
new source modification provisions [see Wisconsin Electric Power
Co. v. Reillv. 893 F.2d 901, 907-10 (7th Cir. 1990) (rejecting
contention that utility life extension project was not a physical
or operational change); Puerto Rican Cement Co.. Inc. v. EPA. 889
F.2d 292, 296-98 (1st Cir. 1989) (HSR applies to modernization
project that decreases emissions per unit of output, but
increases economic efficiency such that utilization may increase
and result in net increase in actual emissions) ]. Likewise, the
replacement of an existing emissions unit with a newer or
different one (albeit more efficient and less polluting) or the
4For purposes of this guidance, pollution prevention means
any activity that through process changes, product reformulation
or redesign, or substitution of less polluting raw materials,
eliminates or reduces the release of air pollutants and other
pollutants to the environment (including fugitive emissions)
prior to recycling, treatment, or disposal; it does not mean
recycling (other than certain "in-process recycling" practices),
energy recovery, treatment, or disposal [see Pollution Prevention
Act of 1990 section 6602(b) and section 6603(5)(A) and (B); see
also "EPA Definition of 'Pollution Prevention,'" memorandum from
F. Henry Habicht II, May 28, 1992].
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reconstruction of an existing emissions unit would not qualify as
a pollution control project. Adopting a policy that
automatically excludes from NSR any project that, while lowering
operating costs or improving performance, coincidentally lowers a
unit's emissions rate, would improperly exclude almost all
modifications to existing emissions units, including those that
are likely to increase utilization and therefore result in
overall higher levels of emissions.
In order to limit this exclusion to the subset of pollution
prevention projects that will in fact lower annual emissions at a
source, permitting authorities should not exclude as pollution
control projects any pollution prevention project that can be
reasonably expected to result in an increase in the utilization
of the affected emissions unit(s). For example, projects which
significantly increase capacity, decrease production costs, or
improve product marketability can be expected to affect
utilization patterns. With these changes, the environment may or
may not see a reduction in overall source emissions; it depends
on the source's operations after the change, which cannot be
predicted with any certainty.3 This is not to say that these
types of projects are necessarily subject to major NSR
requirements, only that they should not be excluded as pollution
control projects under this guidance. The EPA may consider
different approaches to excluding pollution prevention projects
from major NSR requirements in the upcoming NSR rulemaking.
Under this guidance, however, permitting authorities should
carefully review proposed pollution prevention projects to
evaluate whether utilization of the source will increase as a
result of the project.
Furthermore, permitting authorities should have the
authority to monitor utilization of an affected emissions unit or
source for a reasonable period of time subsequent to the project
to verify what effect, if any, the project has on utilization.
In cases where the project has clearly caused an increase in
utilization, the permitting authority may need to reevaluate the
basis for the original exclusion to verify that an exclusion is
still appropriate and to ensure that all applicable safeguards
are being met.
5This is in marked contrast to the addition of pollution
control equipment which typically does not, in EPA's experience,
result in any increase in the source's utilization of the
emission unit in question. In the fev instances where this
presumption is not true, the safeguards discussed in the next
section should provide adequate environmental protections for
these additions of pollution control equipment.
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8
B. Safeguards
The following safeguards are necessary to assure that
projects being considered for an exclusion qualify as
environmentally beneficial pollution control projects and do not
have air quality impacts which would preclude the exclusion.
Consequently, a project that does not meet these safeguards does
not qualify for an exclusion under this policy.
1. Environmentally-Beneficial Test
Projects that meet the definition of a pollution control
project outlined above may nonetheless cause collateral emissions
increases or have other adverse impacts. For instance, a large
VOC incinerator, while substantially eliminating VOC emissions,
may generate sizeable NO, emissions veil in excess of
significance levels. To protect against these sorts of problems,
EPA in the WEPCO rule provided for an assessment of the overall
environmental impact of a project and the specific impact, if
any, on air quality. The EPA believes that this safeguard is
appropriate in this policy as well.
Unless information regarding a specific case indicates
otherwise, the types of pollution control projects listed in
III. A. 1. above can be presumed, by their nature, to be
environmentally beneficial. This presumption arises from EPA's
experience that historically these are the very types of
pollution controls applied to new and modified emissions units.
The presumption does not apply, however, where there is reason to
believe that 1) the controls will not be designed, operated or
maintained in a manner consistent with standard and reasonable
practices; or 2) collateral emissions increases have not been
adequately addressed as discussed below.
In making a determination as to whether a project is
environmentally beneficial, the permitting authority must
consider the types and quantity of air pollutants emitted before
and after the project, as well as other relevant environmental
factors. While because of the case-by-case nature of projects
it is not possible to list all factors which should be considered
in any particular case, several concerns can be noted.
First, pollution control projects which result in an
increase in non-targeted pollutants should be reviewed to
determine that the collateral increase has been minimized and
will not result in environmental harm. Minimization here does
not mean that the permitting agency should conduct a BACT-type
review or necessarily prescribe add-on control equipment to
treat the collateral increase. Rather, minimization means that,
within the physical configuration and operational standards
usually associated with such a control device or strategy, the
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source has taken reasonable measures to keep any collateral
increase to a minimum. For instance, the permitting authority
could require that a low-NO^ burner project be subject to
temperature and other appropriate combustion standards so that
carbon monoxide (CO) emissions are kept to a minimum, but would
not review the project for a CO catalyst or other add-on type
options. In addition, a state's RACT or MACT rule may have
explicitly considered measures for minimizing a collateral
increase for a class or category of pollution control projects
and requires a standard of best practices to minimize such
collateral increases. In such cases, the need to minimize
collateral increase from the covered class or category of
pollution control projects can be presumed to have been
adequately addressed in the rule.
In addition, a project which would result in an unacceptable
increased risk due to the release of air toxics should not be
considered environmentally beneficial. It is EPA's experience,
however, that most projects undertaken to reduce emissions,
especially add-on controls and fuel switches, result in
concurrent reductions in air toxics. The EPA expects that many
pollution control projects seeking an exclusion under this
guidance will be for the purpose of complying with MACT
requirements for reductions in air toxics. Consequently, unless
there is reason to believe otherwise, permitting agencies may
presume that such projects by their nature will result in reduced
risks from air toxics.
2. Additional Air Quality Impacts Assessments
(a) General
Nothing in the Act or EPA's implementing regulations would
allow a permitting authority to approve a pollution control
project resulting in an emissions increase that would cause or
contribute to a violation of a NAAQS or PSD increment, or
adversely impact visibility or other AQRV in a class I area [see,
e.g., Act sections 110(a)(2)fC), 165, 169A(b), 173].
Accordingly, this guidance is not intended to allow any project
to violate any of these air quality standards.
As discussed above, it is possible that a pollution control
project—either through an increase in an emissions rate of a
collateral pollutant or through a change in utilization—will
cause an increase in actual emissions, which in turn could cause
or contribute to a violation of a NAAQS or increment or
adversely impact AQRV's. For this reason, in the WEPCO rule the
EPA required sources to address whenever 1) the proposed change
would result in a significant net increase in actual emissions of
any criteria pollutant over levels used for that source in the
most recent air quality impact analysis; and 2) the permitting
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10
authority has reason to believe that such an increase would cause
or contribute to a violation of a NAAQS, increment or visibility
limitation. If an air quality impact analysis indicates that the
increase in emissions will cause or contribute to a violation of
any ambient standard, PSD increment, or AQRV, the pollution
control exclusion does not apply.
The EPA believes that this safeguard needs to be applied
here as well. Thus, where a pollution control project will
result in a significant increase in emissions and that increased
level has not been previously analyzed for its air quality impact
and raises the possibility of a NAAQS, increment, or AQRV
violation, the permitting authority is to require the source to
provide an air quality analysis sufficient to demonstrate the
impact of the project. The EPA will not necessarily require that
the increase be modeled, but the source must provide sufficient
data to satisfy the permitting authority that the new levels of
emissions will not cause a NAAQS or increment violation and will
not adversely impact the AQRV's of nearby potentially affected
class I areas.
In the case of nonattainment areas, the state or the source
must provide offsetting emissions reductions for any significant
increase in a nonattainment pollutant from the pollution control
project. In other words, if a significant collateral increase of
a nonattainment pollutant resulting from a pollution control
project is not offset on at least a one-to-one ratio then the
pollution control project would not qualify as environmentally
beneficial.6 However, rather than having to apply offsets on a
case-by-case basis, States may consider adopting (as part of
their attainment plans) specific control measures or strategies
for the purpose of generating offsets to mitigate the projected
collateral emissions increases from a class or category of
pollution control projects.
(b) Determination of Increase in Emissions
The question of whether a proposed project will result in an
emissions increase over pre-modification levels of actual
emissions is both complicated and contentious. It is a question
that has been debated by the New Source Review Reform
Subcommittee of the Clean Air Act Advisory Committee and is
expected to be revisited by EPA in the same upcoming rulemaJcing
that will consider adopting a pollution control project
exclusion. In the interim, EPA is adopting a simplified approach
'Regardless of the severity of the classification of the
nonattainment area, a one-to-one offset ratio will be considered
sufficient under this policy to mitigate a collateral increase
from a pollution control project. States may, however, require
offset ratios that are greater than one-to-one.
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11
to determining whether a pollution control project will result in
increased emissions.
The approach in this policy is premised on the fact that EPA
does not expect the vast majority of these pollution control
projects to change established utilization patterns at the
source. As discussed in the previous section, it is EPA's
experience that add-on controls do not impact utilization, and
pollution prevention projects that could increase utilization may
not be excluded under this guidance. Therefore, in most cases it
will be very easy to calculate the emissions after the change:
the product of the new emissions rate times the existing
utilization rate. In the case of a pollution control project
that collaterally increases a non-targeted pollutant, the actual
increase (calculated using the new emissions rate and current
utilization pattern) would need to be analyzed to determine its
air quality impact.
The permitting authority may presume that projects meeting
the definition outlined in section III(A)(1) will not change
utilization patterns. However, the permitting authority is to
reject this presumption where there is reason to believe that the
project will result in debottlenecking, loadshifting to take
advantage of the control equipment, or other meaningful increase
in the use of the unit above current levels. Where the project
will increase utilization and emissions, the associated emissions
increases are calculated based on the post-modification potential
to emit of the unit considering the application of the proposed
controls. In such cases the permitting agency should consider
the projected increase in emissions as collateral to the project
and determine whether, notwithstanding the emissions increases,
the project is still environmentally beneficial and meets all
applicable safeguards.
In certain limited circumstances, a permitting agency may
take action to impose federally-enforceable limits on the
magnitude of a projected collateral emissions increase to ensure
that all safeguards are met. For example, where the data used to
assess a projected collateral emissions increase is questionable
and there is reason to believe that emissions in excess of the
projected increase would violate an applicable air quality
standard or significantly exceed the quantity of offsets
provided, restrictions on the magnitude of the collateral
increase may be necessary to ensure compliance with the
applicable safeguards.
IV. Procedural Safeguards
Because EPA has not yet promulgated regulations governing a
generally applicable pollution control project 'exclusion from
major NSR (other than for electric utilities), permitting
authorities must consider and approve requests for an exclusion
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12
on a case-by-case basis, and the exclusion is not self-executing
Instead, sources must receive case-by-case approval from the
permitting authority pursuant to a minor NSR permitting process,
State nonapplicability determination or similar process.
[Nothing in this guidance voids or creates an exclusion from any
applicable minor source preconstruction review requirement in any
SIP that has been approved pursuant to section 110(a)(2)(C) and
40 CFR 51.160-164.] This process should also provide that the
application for the exclusion and the permitting agency's
proposed decision thereon be subject to public notice and the
opportunity for public and EPA written comment, in those limited
cases where the applicable SIP already exempts a class or
category of pollution controls project from the minor source
permitting public notice and comment requirements, and where no
collateral increases are expected (e.g., the installation of a
baghouse) and all otherwise applicable environmental safeguards
are complied with, public notice and comment need not be provided
for such projects. However, even in such circumstances, the
permitting agency should provide advance notice to EPA when it
applies this policy to provide an exclusion. For standard-vide
applications to groups of sources (e.g., RACT or MACT), the
notice may be provided to EPA at the time the permitting
authority intends to issue a pollution control exclusion for the
class or category of sources and thereafter notice need not be
given to EPA on an individual basis for sources within the
noticed group.
V. Emission Reduction Credits
In general, certain pollution control projects which have
been approved for an exclusion from major NSR may- result in
emission reductions which can serve as NSR offsets or netting
credits. All or part of the emission reductions equal to the
difference between the pre-modification actual and post-
modification potential emissions for the decreased pollutant may
serve as credits provided that 1) the project will not result in
a significant collateral increase in actual emissions of any
criteria pollutant, 2) the project is still considered
environmentally beneficial, and 3) all otherwise applicable
criteria for the crediting of such reductions are met (e.g.,
quantifiable, surplus, permanent, and enforceable). Where an
excluded pollution control project results in a significant
collateral increase of a criteria pollutant, emissions reduction
credits from the pollution control project for the controlled
pollutant may still be granted provided, in addition to 2) and 3)
above, the actual collateral increase is reduced below the
applicable significance level, either through contemporaneous
reductions at the source or external offsets. However, neither
the exclusion from major NSR nor any credit (full or partial) for
emission reductions should be granted by the permitting authority
where the type or amount of the emissions increase which would
result from the use of such credits would lessen the
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13
environmental benefit associated with the polluti n control
project to the point where the project would not h ve initially
qualified for an exclusion.
IV. Illustrative Examples
The following examples illustrate some of the guiding
principles and safeguards discussed above in reviewing proposed
pollution control projects for an exclusion from major NSR.
Example 1
PROJECT DESCRIPTION: A chemical manufacturing facility in
an attainment area for all pollutants is proposing to install a
RTO to reduce VOC emissions (including emissions of some
hazardous pollutants) at the plant by about 3000 tons per year
(tpy). The emissions reductions from the RTO are currently
voluntary/ but may be necessary in the future for title III MACT
compliance. Although the RTO has been designed to minimize NO,
emissions, it will produce 200 tpy of new NO, emissions due to
the unique composition of the emissions stream. There is no
information about the project to rebut a presumption that the
project will not change utilization of the source. Aside from
the NOX increase there are no other environmental impacts known
to be associated with the project.
EVALUATION: As a qualifying add-on control device, the
project may be considered a pollution control project and may be
considered for an exclusion. The permitting agency should:
1) verify that the NO, increase has been minimized to the extent
practicable, 2) confirm (through modeling or other appropriate
means) that the actual significant increase in NO, emissions does
not violate the applicable NAAQS,7 PSD increment, or adversely
impact any Class I area AQRV, and 3) apply all otherwise
applicable SIP and minor source permitting requirements,
including opportunity for public notice and comment.
Example 2
PROJECT DESCRIPTION: A source proposes to replace an
existing coal-fired boiler with a gas-fired turbine as part of a
cogeneration project. The new turbine is an exact replacement
for the energy needs supplied by the existing boiler and will
emit less of each pollutant on an hourly basis than the boiler
did.
7If the source were located in an area in which
nonattainment NSR applied to NO, emissions increases, 200
tons of NOX offset credits would be required for the project
to be eligible for an exclusion.
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14
EVALUATION: The replacement of an existing emissions unit
with a new unit (albeit more efficient and less polluting) does
not qualify for an exclusion as a pollution control project Th-
company can, however, use any otherwise applicable netting "
credits from the removal of the existing boiler to seek to net
the new unit out of major NSR.
Example 3
PROJECT DESCRIPTION: A source plans to physically renovate
and upgrade an existing process line by making certain changes to
the existing process/ including extensive modifications to
emissions units. Following the changes, the source wi.ll expand
production and manufacture and market a new product line. The
project will cause an increase in the economic efficiency of the
line. The renovated line will also be less polluting on a per-
product basis than the original configuration.
EVALUATION: The change is not eligible for an exclusion as
a pollution control project. On balance/ the project does not
have clearly evident pollution control aspects/ and the resultant
decrease in the per-product emissions rate (or factor) is
incidental to the project. The project is a physical change or
change in the method of operation that will increase efficiency
and productivity.
Example 4
PROJECT DESCRIPTION: In response to the phaseout of
chlorofluorocarbons (CFC) under title VI of the Act, a major
source is proposing to substitute a less ozone-depleting
substance (e.g., HCFO141b) for one it currently uses that has a
greater ozone depleting potential (e.g., CFC-11). A larger
amount of the less-ozone depleting substance will have to be
used. No other changes are proposed.
EVALUATION: The project may be considered a pollution
control project and may be considered for an exclusion. The
permitting agency should verify that 1) actual annual emissions
of HCFC-141b after the proposed switch will cause less
stratospheric ozone depletion than current annual emissions of
CFC-ll; 2) the proposed switch will not change utilization
patterns or increase emissions of any other pollutant which would
impact a NAAQS, PSD increment, or AQRV and will not cause any
cross-media harm, including any unacceptable increased risk
associated with toxic air pollutants; and 3) apply all otherwise
applicable SIP and minor source permitting requirements,
including opportunity for public notice and comment.
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13
Example 5
PROJECT DESCRIPTION: An existing landfill proposes to
install either flares or energy recovery equipment [i.e.,
turbines or internal combustion (1C) engines]. The reductions
from the project are estimated at over 1000 tpy of voc and are
currently not necessary to meet Act requirements, but may be
necessary some time in the future. In case A the project is t,ie
replacement of an existing flare or energy system and no increase
in NOX emissions will occur. In case B, the equipment is a first
time installation and will result in a 100 tpy increase in NOX.
In case C, the equipment is an addition to existing equipment*
which will accommodate additional landfill gas (resulting from
increased gas generation and/or capture consistent with the
current permitted limits for growth at the landfill) and will
result in a 50 tpy increase in NOX.
EVALUATION: Projects A, B, and C may be considered
pollution control projects and may be considered for an
exclusion; however, in cases B and C, if the landfill is located
in an area required to satisfy nonattainment NSR for NOX
emissions, the source would be required to obtain NOX offsets at
a ratio of at least 1:1 for the project to be considered for an
exclusion. [NOTE: VOC-NOX netting and trading for NSR purposes
may be discussed in the upcoming NSR rulemaking, but it is beyond
the scope of this guidance. ] Although neither turbines or 1C
engines are listed in section III.A.I as add-on control devices
and would normally not be considered pollution control projects,
in this specific application they serve the same function as a
flare, namely to reduce VOC emissions at the landfill with the
added incidental benefit of producing useful energy in the
process.*
The permitting agency should: 1) verify that the NOX
increase has been minimized to the extent practicable; 2) confirm
(through modeling or other appropriate means) that the actual
significant increase in NOX emissions will not violate the
*The production of energy here is incidental to the project
and is not a factor in qualifying the project for an exclusion as
a pollution control project. In addition, any supplemental or
co-firing of non-landfill gas fuels (e.g., natural gas, oil)
would disqualify the project from being considered a pollution
control project. The fuels would be used to maximize any
economic benefit from the project and not for the purpose of
pollution control at the landfill. However, the use of an
alternative fuel solely as .a backup fuel to be used only during
brief and infrequent start-up or emergency situations would not
necessarily disqualify an energy recovery project from being
considered a pollution control project.
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16
applicable NAAQS, PSD increment, or adverselv ,•»«,„«.
and 3) apply all otherwise applicable SIP 1% i*P Ct any AQRV;
as noted above, in cases B and C ensues%££ To offs^s* Md'
provided in an area in which nonattainment review /rfrf^l ?*
emissions increases, permitting requirement! inclSiia N°'
opportunity for public notice and comment lnclud:LJ19
-------
APPENDIX F
MAP AND LISTING OF NONATTAINMENT AREAS
-------
Page Intentionally Left Blank
-------
Areas Designated Nonattainment for Ozone
Classification
I Ex/nemo & Severe
I Serious
I Moderate
Marginal
Designated Nonattainment Areas as of September 1004
Note: Unclassified areas are not shown.
-------
Page Intentionally Left Blank
-------
Table 1. Ozone Nonattalnment Areas - Air Quality Update, 1991-93
State Nonattainment Area Name
AL Birmingham NA Area
AZ Phoenix
CA Los Angeles South Coast Air Basin
CA Monterey Bay Unified NA Area
CA Sacramento Metro NA Area
CA San Diego NA Area
CA San Francisco-Bay NA Area
CA San Joaquin Valley NA Area
CA Santa Barbara-Santa Maria-Lompoc
CA Southeast Desert Modified AQMD
CA Ventura Co NA Area
CT Greater Connecticut NA Area
DC-MD-VA Washington NA Area
DB Sussex Co NA Area
FL Miami-Fort Lauderdale-W. Palm Beach
FL Tampa-St. Petersburg-Clearwater
GA Atlanta NA Area
IL-IN Chicago-Gary-Lake County NA Area
IL Jersey Co NA Area
IN Evansville NA Area
IN Indianapolis NA Area
IN South Bend-Elkhart NA Area
KY Edmonson Co NA Area
KY-WV Huntington-Ashland NA Area
KY Lexington-Fayette NA Area
KY-IN Louisville NA Area
KY Owensboro NA Area
KY Paducah NA Area
LA Baton Rouge NA Area
LA Lake Charles NA Area
MA-NH Boston-Lawrence-Worcester NA Area
MA Springfield (W. Mass) NA Area
MD Baltimore NA Area
MO Kent County and Queen Anne's County
MB Hancock Co and Waldo Co NA Area
MB Knox Co and Lincoln Co NA Area
MB Lewiston - Auburn NA Area
ME Portland NA Area
MI Detroit-Ann Arbor NA Area
Clean Air Act
Classification
Marginal
Moderate
Extreme
Moderate
Serious
Severe 15
Moderate
Serious
Moderate
Severe 17
Severe 15
Serious
Serious
Marginal
Moderate
Marginal
Serious
Severe 17
Marginal
Marginal
Marginal
Marginal
Marginal
Moderate
Marginal
Moderate
Marginal
Marginal
Serious
Marginal
Serious
Serious
Severe 15
Marginal
Marginal
Moderate
Moderate
Moderate
Moderate
1991-93 Update
A.Q.
Value
0.124
0.147
0.300
0.108
0.150
0.150
0.120
0.159
0.123
0.200
0.150
0.158
0.137
0.118
0.106
0.110
0.149
0.145
0.112
0.110
0.104
0.103
0.091
0.122
0.100
0.130
0.104
0.106
0.135
0.132
0.137
0.141
0.150
0.133
0.112
0.134
0.106
0.147
0.122
Average
Eat. Exi
0.7
4.0
104.3
0.4
9.7
11.8
0.7
18.9
1.0
59.3
15.9
7.5
1.4
1.0
0.0
0.0
4.2
4.7
0.7
0.0
0.0
0.0
0.0
1.0
0.0
2.2
0.0
0.0
1.8
1.3
3.1
4.6
4.8
2.8
1.3
2.3
0.3
11.8
1.0
(#4)
(#5)
(#6)
(#7)
1993
2nd Daily
Max 1-hr
0.125
0.126
0.250
0.104
0.150
0.159
0.130
0.159
0.114
0.180
0.144
0.153
0.132
0.115
0.122
0.100
0.162
0.125
0.127
0.110
0.104
0.096
0.092
0.122
0.103
0.140
0.106
0.112
0.127
0.108
0.155 .
0.133
0.146
0.128
0.094
0.122
0.096
0.125
0.122
1993
Estimated
Exceedancea
2.0
2.0
97.6
0.0
3.6
4.0
2.0
27.5
0.0
72.6
9.0
6.0
3.1
0.0
1.0
0.0
4.3
2.4
2.0
0.0
0.0
0.0
0.0
1.0
0.0
2.0
0.0
0.0
3.0
0.0
4.0
6.2
6.2
2.0
0.0
1.2
0.0
3.8
1.0
-------
Table 1. Ozone Nonattalnment Areas - Air Quality Update, 1991-93, continued
State
MI
MI
MO-KS
MO-IL
NC
NC
NC
NH
NH
NJ
NV
NY
NY
NY
NY
NY-NJ-CT
NY
OH
OH-KY
OH
OH
OH
OH
OH-PA
OR
PA-NJ
PA
PA
PA
PA
PA
PA-NJ-DE-MD
PA
PA
PA
PA
Nonattainment Area Name
Grands Rapids NA Area.
Muskegon NA Area
Kansas City NA Area
St. Louis NA Area
Charlotte-Gastonia NA Area
Greensboro-Winston-Salem-High Point
Raleigh-Durham NA Area
Manchester NA Area
Portsmouth-Dover-Rochester, NH
Atlantic City NA Area
Reno
Albany-Schenectady-Troy NA Area
Buffalo-Niagara Falls NA Area
Essex Co NA Area
Jefferson Co NA Area
New York-N. New Jersey-Long Island
Poughkeepsie NA Area
Canton NA Area
Cincinnati-Hamilton NA Area
Cleveland-Akron-Lorain NA Area
Columbus NA Area
Dayton-Springfield NA Area
Toledo NA Area
Youngstown-Warren-Sharon NA Area
Portland-Vancouver AQMA NA Area
Allentown-Bethlehem-Baston NA Area
Altoona NA Area
Erie NA Area
HarriBburg-Lebanon-Carlisle NA
Johnstown NA Area
Lancaster NA Area
Philadelphia-Wilmington-Trenton
Pittsburgh-Beaver Valley NA Area
Reading NA Area
Scranton-Wilkes-Barre NA Area
York NA Area
Clean Air Act
Classification
Moderate
Moderate
Attainment
Moderate
Moderate
Attainment
Attainment
Marginal
Serious
Moderate
Marginal
Marginal
Marginal
Marginal
Marginal
Severe 17
Marginal
Marginal
Moderate
Moderate
Marginal
Moderate
Moderate
Marginal
Marginal
Marginal
Marginal
Marginal
Marginal
Marginal
Marginal
Severe 15
Moderate
Moderate
Marginal
Marginal
1991-93 Update
A.Q.
Value
0.146
0.141
0.114
0.132
0.119
0.113
0.11B
0.087
0.143
0.122
0.089
0.104
0.106
0.116
0.110
0.158
0.126
0.109
0.125
0.125
0.118
0.112
0.120
0.113
0.108
0.115
0.105
0.110
0.111
0.107
0.118
0.156
0.119
0.118
0.117
0.113
Average
Eat. Ex
3.4
2.3
0.3
1.7
0.7
0.3
0.7
0.0
2.2
1.0
0.0
0.0
0.0
0.0
0.0
6.1
1.4
0.3
1.3
1.7
0.3
0.0
0.3
0.3
0.7
0.0
0.0
0.0
0.0
0.0
0.3
10.3
0.7
0.3
0.4
0.0
(#8)
(#9)
0.
0.
1993
2nd Daily
Max 1-hr
0.094
0.104
0.114
,126
137
0.121
0.128
0.086
0.107
0.115
0.089
0.106
0.090
0.100
0.092
0.165
0.139
0.109
,121
117
0.105
0.120
0.121
0.120
0.103
0.110
0.100
0.107
0.118
0.099
0.118
0.147
0.124
0.110
0.112
0.112
1993
Estimated
Exceedances
0.
0.
1
1
1
2,
2,
1.
2.
0.0
1.1
0.0
0.0
0.0
0.0
0.0
0.0
6.0
2.0
0.0
1.0
0.0
0.0
o.p
o.b
0.0
0.0
0.0
0.0
1.0
5.2
0.0
0.0
0.0
0.0
-------
Table 1. Ozone Nonattainment Areas - Air Quality Update, 1991-93, continued
State
RI
SC
TN
TN
TN
TX
TX
TX
TX
OT
VA
VA
VA
WA
HI
HI
HI
HI
HI
HI
HV
HV
HV
Nonattainment Area Name
Providence (all of RI) NA Area
Cherokee Co NA Area
Knoxvllle NA Area
Memphis NA Area
Nashville NA Area
Beaumont-Port Arthur NA Area
Dallas-Fort Horth NA Area
El Paso NA Area
Houston-Galveston-Brazorla NA
Salt Lake City-Ogden NA Area
Norfolk-Virginia Beach-Newport News
Richmond-Petersburg NA Area
Smyth County NA Area
Seattle - Tacoma NA Area
Door Co NA Area
Kewaunee Co NA Area
Manitowoc Co NA Area
Milwaukee-Racine NA Area
Sheboygan NA Area
Halworth Co NA Area
Charleston NA Area
Greenbrler NA Area
Parkersburg NA Area
Clean Air Act
Classification
Serious
Attainment
Attainment
Marginal
Moderate
Serious
Moderate
Serious
Severe 17
Moderate
Marginal
Moderate
Marginal
Marginal
Marginal
Moderate
Moderate
Severe 17
Moderate
Marginal
Attainment
Marginal
Attainment
1991-93
A.Q.
Value
0.152
0.105
0.118
0.115
0.124
0.130
0.141
0.136
0.200
0.106
0.131
0.128
ND
0.105
0.125
0.107
0.132
0.148
0.139
0.120
0.106
0.101
0.118
Uodate
Average
Eat. Exc.
4.0
0.3
0.0
0.3
1.1
2.7
2.0
3.7
6.3
0.0
1.7
1.4
NO (#10)
0.0
1.6
0.8
2.0
3.9
2.6 (#11)
0.3
0.3
0.4
0.0
1993
2nd Daily
Max 1-hr
0.117
0.108
0.120
0.119
0.126
0.122
0.140
0.135
0.197
0.104
0.131
0.132
ND
0.100
0.098
0.095
0.095
0.125
0.095
0.093
0.075
0.090
0.104
1993
Estimated
Exceedances
1.4
0.0
0.0
1.0
2.1
0.0
2.3
4.1
10.4
0.0
3.0
3.1
ND
0.0
0.0
0.0
0.0
2.4
0.0
0.0
0.0
0.0
0.0
91 Nonattainment Areas
SOURCE:
NOTES:
EPA'e air quality data system, the Aerometric Information Retrieval System (AIRS), with supplemental data from
EPA Regional Offices.
1. Designations and classifications for ozone nonattainment areas as published in the Federal Register,
40 CFR Part 81. Unclassified and transitional nonattainment areas are not included in this listing.
2. The updated air quality value is estimated for the 1991-93 period using EPA guidance for calculating design
values (Laxton Memorandum, June 18, 1990). Generally, the fourth highest monitored value with 3 complete years of data is
-------
selected as the updated air quality value because the standard allows one exceedance for each year. It is important to note
that the 1990 Clean Air Act Amendments required that O3 nonattainment areas be classified on the basis of the design value
at the time the Amendments were passed, generally the 1987-89 period was used.
3. The National Ambient Air Quality standard for ozone is 0.12 parts per million (ppm) daily maximum 1-hour average
not to be exceeded more than once per year on average. The average estimated number of exceedances column shows the number
of days the 0.12 ppm standard was exceeded on average at the site recording the highest updated air quality value. This
is done after adjustment for incomplete, or missing days, during the 3-year period, 1991-93. The last two columns contain
data from the site recording the highest second daily maximum 1-hour concentration in 1993. The last column shows the
estimated exceedances for 1993 at the site recording the highest second maximum 1-hour concentration listed in the previous
column.
4. Special purpose monitoring (SPM) operating during the ozone monitoring season.
5. The nonattainment/updatad air quality value site for the Chicago NA Area is in Kenosha County, WI.
6. The Regional Office is reviewing the status of the area based on data through 1994.
7. Incomplete data reported in 1991.
8. Calculation of the updated air quality value and estimated exceedances adjusted to account for start-up of a LMOS
Study site with data only in 1991.
9. Data from a monitoring site located at the water treatment plant not used due to localized interference.
10. The site was located atop Whitetop Mountain, VA as part of the Mountain Cloud Study. Site elevation is 5520
feet. No data reported after 1988. This is a rural transport area. The nonattainment area is that portion of Whitetop
Mountain above 4500 feet elevation.
11. Calculation of estimated exceedances adjusted for Wisconsin ozone season not yet reflected in AIRS.
-------
Region I
Table 1. Ozone Nonattainment Areas - Air Quality Update, 1991-93
State Nonattainment Area Name
CT Greater Connecticut NA Area
MA-NH Boston-Lawrence-Worcester NA Area
MA Springfield (W. Mass) NA Area
ME Hancock Co and Waldo Co NA Area
MB Knox Co and Lincoln Co NA Area
ME Lewiston - Auburn NA Area
ME Portland NA Area
NH Manchester NA Area
NH Portsmouth-Dover-Rochester, NH
NY-NJ-CT New York-N. New Jersey-Long Island
RI Providence (all of RI) NA Area
Clean Air Act
Classification
Serious
Serious
Serious
Marginal
Moderate
Moderate
Moderate
Marginal
Serious
Severe 17
Serious
1991-93 Update
A.Q.
Value
0.158
0.137
0.141
0.112
0.134
0.106
0.147
0.087
0.143
0.158
0.152
Average
Eat. EK
7.5
3.1
4.6
1.3
2.3
0.3
11.8
0.0
2.2
6.1
4.0
(#7)
1993
2nd Daily
Max 1-hr
0.153
0.155
0.133
0.094
0.122
0.096
0.125
0.086
0.107
0.165
0.117
1993
Estimated
Exceedances
6.0
4.0
6.2
0.0
1.2
0.0
3.8
0.0
1.1
6.0
1.4
-------
Region II
Table 1. Ozone Nonattalnment Areas - Air Quality Update, 1991-93
State Nonattalnment Area Name
NJ Atlantic City NA Area
NY Albany-Schenectady-Troy NA Area
NY Buffalo-Niagara Falls NA Area
NY Essex Co NA Area
NY Jefferson Co NA Area
NY-NJ-CT New York-N. New Jersey-Long Island
NY Poughkeepsie NA Area
PA-NJ Allentown-Bethlehem-Easton NA Area
PA-NJ-DE-MD Phlladelphla-Wilmington-Trenton
Clean Air Act
Classification
Moderate
Marginal
Marginal
Marginal
Marginal
Severe 17
Marginal
Marginal
Severe 15
1991-93
A.Q.
Value
0.122
0.104
0.106
0.116
0.110
0.158
0.126
0.115
0.156
Uodate
Average
Est. Exc.
1.0
0.0
0.0
0.0
0.0
6.1
1.4
0.0
10.3
1993
2nd Daily
Max 1-hr
0.115
0.106
0.090
0.100
0.092
0.165
0.139
0.110
0.147
1993
Estimated
Exceedances
0.0
0.0
0.0
0.0
0.0
6.0
2.0
0.0
5.2
-------
Region III
Table 1. Ozone Nonattainment Areas - Air Quality Update, 1991-93
State Nonattainment Area Name
DC-MD-VA Washington NA Area
DE Sussex Co NA Area
MD Baltimore NA Area
MO Kent County and Queen Anne'a County
OH-PA Youngstown-Narren-Sharon NA Area
PA-NJ Allentown-Bethlehem-Easton NA Area
PA Altoona NA Area
PA Brie NA Area
PA Harriaburg-Lebanon-Carlisle NA
PA Johnstown NA Area
PA Lancaster NA Area
PA-NJ-DE-MD Philadelphia-Wilmington-Trenton
PA Pittsburgh-Beaver Valley NA Area
PA Reading NA Area
PA Scranton-Wilkes-Barre NA Area
PA York NA Area
WV Charleston NA Area
WV oreenbrier NA Area
WV Parkersburg NA Area
VA Norfolk-Virginia Beach-Newport News
VA Richmond-Petersburg NA Area
VA Smyth County NA Area
Clean Air Act
Classification
Serious
Marginal
Severe 15
Marginal
Marginal
Marginal.
Marginal
Marginal
Marginal
Marginal
Marginal
Severe 15
Moderate
Moderate
Marginal
Marginal
Moderate
Marginal
Moderate
Marginal
Moderate
Marginal
1991-93 Update
A.Q.
Value
0.137
0.118
0.150
0.133
0.113
0.115
0.105
0.110
0.111
0.107
0.118
0.156
0.119
0.118
0.117
0.113
0.106
0.101
0.118
0.131
0.128
ND
Average
Eat. Ex
1.4
1.0
4.8
2.8
0.3
0.0
0.0
0.0
0.0
0.0
0.3
10.3
0.7
0.3
0.4
0.0
0.3
0.4
0.0
1.7
1.4
ND
(#10)
1993
2nd Daily
Max 1-hr
0.132
0.115
0.146
0.128
0.120
0.110
0.100
0.107
0.118
0.099
0.118
0.147
0.124
0.110
0.112
0.112
0.075
0.090
0.104
0.131
0.132
ND
1993
Estimated
Bxoeedances
3.1
0.0
6.2
2.0
1.0
0.0
0.0
0.0
0.0
0.0
1.0
5.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3.0
3.1
ND
-------
Region IV
Table 1. Ozone Nonattalnment Areas - Air Quality Update, 1991-93
State
Nonattaiiunent Area Name
Birmingham NA Area
Miami-Fort Lauderdale-W. Palm Beach
Tampa-St. Petersburg-Clearwater
Atlanta NA Area
Edmonson Co NA Area
Huntington-Aahland NA Area
Lexington-Fayette NA Area
Louisville NA Area
Owensboro NA Area
Paducah NA Area
Charlotte-Gastonia NA Area
Greensboro-Winston~Salem-High Point
Raleigh-Durham NA Area
Cincinnati-Hamilton NA Area
Cherokee Co NA Area
Knoxville NA Area
Memphis NA Area
Nashville NA Area
Clean Air Act
Classification
Marginal
Moderate
Marginal
Serious
Marginal
Moderate
Marginal
Moderate
Marginal
Marginal
Moderate
Attainment
Attainment
Moderate
Attainment
Attainment
Marginal
Moderate
1991-93 Utodata
A.Q.
Value
0.124
0.106
0.110
0.149
0.091
0.122
0.100
0.130
0.104
0.106
0.119
0.113
0.118
0.12S
0.105
0.118
0.115
0.124
Average
Bat. EXI
0.7
0.0
0.0
4.2
0.0
1.0
0.0
2.2
0.0
0.0
0.7
0.3
0.7
1.3
0.3
0.0
0.3
1.1
1993
2nd Daily
Max 1-hr
0.125
0.122
0.100
0.162
0.092
0.122
0.103
0.140
0.106
0.112
0.137
0.121
0.128
0.121
0.108
0.120
0.119
0.126
1993
Estimated
Bxcaedances
2.0
1.0
0.0
4.3
0.0
1.0
0.0
2.0
0.0
0.0
2.1
1.0
2.1
1.0
0.0
0.0
1.0
2.1
-------
Region V
Table 1. Ozone Nonattalnment Areas - Air Quality Update, 1991-93
State Nonattainment Area Name
IL-IN Chicago-Gary-Lake County NA Area
IL Jersey Co NA Area
IN EvansvLlle NA Area
IN Indianapolis NA Area
IN South Bend-Elkhart NA Area
MI Detroit-Ann Arbor NA Area
MI Grands Rapids NA Area
MI Muskegon NA Area
OH Canton NA Area
OH-KY Cincinnati-Hamilton NA Area
OH Cleveland-Akron-Lorain NA Area
OH Columbus NA Area
OH Dayton-Springfield NA Area
OH Toledo NA Area
OH-PA Youngstown-Warren-Sharon NA Area
HI Door Co NA Area
HI ' Kewaunee Co NA Area
WI Manitowoc Co NA Area
WI Milwaukee-Racine NA Area
HI Sheboygan NA Area
WI Waiworth Co NA Area
Clean Air Act
Classification
Severe 17
Marginal
Marginal
Marginal
Marginal
Moderate
Moderate
Moderate
Marginal
Moderate
Moderate
Marginal
Moderate
Moderate
Marginal
Marginal
Moderate
Moderate
Severe 17
Moderate
Marginal
1991-93
A.Q.
Value
0.145
0.112
0.110
0.104
0.103
0.122
0.146
0.141
0.109
0.125
0.125
0.118
0.112
0.120
0.113
0.125
0.107
0.132
0.148
0.139
0.120
Uodate
Average
Est. Exc.
4.7 (#5)
0.7
0.0
0.0
0.0
1.0
3.4 (#8)
2.3
0.3
1.3
1.7 (#9)
0.3
0.0
0.3
0.3
1.6
0.8
2.0
3.9
2.6 (#11)
0.3
1993
2nd Daily
Max 1-hr
0.125
0.127
0.110
0.104
0.096
0.122
0.094
0.104
0.109
0.121
0.117
0.105
0.120
0.121
0.120
0.098
0.095
0.095
0.125
0.095
0.093
1993
Estimated
Exoeedances
2.4
2.0
0.0
0.0
0.0
1.0
1.0
1.0
0.0
1.0
0.0
0.0
0.0
0.0
0.0
2.4
0.0
0.0
-------
Region VI
Table 1. Ozone Nonattalnment Areas - Air Quality Update, 1991-93
State
LA
LA
TX
TX
TX
TX
Nohattainment Area Name
Baton Rouge NA Area
Lake Charles NA Area
Beaumont-Port Arthur NA Area
Dallas-Fort Worth NA Area
El Paso NA Area
Houston-Oalveston-Brazoria NA
Clean Air Act
Classification
Serious
Marginal
Serious
Moderate
Serious
Severe 17
1991-93 Update
A.Q. Average
Value Est. Exo.
0.135
0.132
0.130
0.141
0.136
0.200
1.8
1.3
2.7
2.0
3.7
6.3
(#6)
1993
2nd Daily
Max 1-hr
0.127
0.108
0.122
0.140
0.135
0.197
1993
Estimated
Exceedances
3.0
0.0
0.0
2.3
4.1
10.4
-------
Region VII
Table 1. Ozone Nonattainment Areas - Air Quality Update, 1991-93
State Nonattainment Area Name
MO-KS Kansas City NA Area
MO-IL St. Louis NA Area
Clean Air Act
Classification
Attainment
Moderate
1991-93 Update
A.Q. Average
Value Est. Exc.
0.114
0.132
0.3
1.7
1993
2nd Daily
Max 1-hr
0.114
0.126
1993
Estimated
Exceedances
1.0
2.1
-------
Region VIII
Table 1. Ozone Nonattalnment Areas - Air Quality Update, 1991-93
State
UT
Nonattainment Area Name
Salt Lake City-Ogden NA Area
Clean Air Act
Classification
Moderate
1991-93 Update
A.Q. Average
Value Eat. Exc.
0.106
0.0
1993
2nd Daily
Max 1-hr
0.104
1993
Estimated
Exceedances
0.0
-------
Region IX
Table 1. Ozone Nonattalnment Areas - Air Quality Update, 1991-93
State
AZ
CA
CA
CA
CA
CA
CA
CA
CA
CA
NV
Nonattainment Area Name
Phoenix
Los Angeles South Coast Air Basin
Monterey Bay Unified NA Area
Sacramento Metro NA Area
San Diego NA Area
San Francisco-Bay NA Area
San Joaguin Valley NA Area
Santa Barbara-Santa Maria-Lompoc
Southeast Desert Modified AQMD
Ventura Co NA Area
Reno
Clean Air Act
Classification
Moderate
Extreme
Moderate
Serious
Severe 15
Moderate
Serious
Moderate
Severe 17
Severe 15
Marginal
1991-93 Update
A.Q.
Value
0.147
0.300
0.108
0.150
0.150
0.120
0.160
0.123
0.200
0.150
0.089
Average
Est. Ex
4.0
104.3
0.4
9.7
11.8
0.7
18.9
1.0
59.3
15.9
0.0
(#4)
1993
2nd Daily
Max 1-hr
0.126
0.250
0.104
0.150
0.160
0.130
0.160
0.114
0.180
0.144
0.089
1993
Estimated
Exoeedances
2.0
97.6
0.0
3.6
4.0
2.0
27.5
0.0
72.6
9.0
0.0
-------
Region X
Table 1. Ozone Nonattainment Areas - Air Quality Update, 1991-93
1991-93 Update 1993 1993
Clean Air Act A.Q. Average 2nd Daily Estimated
State Nonattainment Area Name Classification Value Eat. Exc. Max 1-hr Exceedances
OR Portland-Vancouver AQMA NA Area Marginal 0.108 0.7 0.103 0.0
WA Seattle - Tacoma NA Area Marginal 0.105 0.0 0.100 0.0
-------
SOURCE: EPA's air quality data system, the Aerometric Information Retrieval System (AIRS), with supplemental data from
EPA Regional Offices.
NOTES:
1. Designations and classifications for ozone nonattainment areas as published in the Federal Register,
40 CPR Part 81. Unclassified and transitional nonattainment areas are not included in this listing.
2. The updated air quality value is estimated for the 1991-93 period using EPA guidance for calculating design
values (Laxton Memorandum, June IB, 1990). Generally, the fourth highest monitored value with 3 complete years of data is
selected as the updated air quality value because the standard allows one exceedance for each year. It is important to note
that the 1990 Clean Air Act Amendments required that O, nonattainment areas be classified on the basis of the design value
at the time the Amendments were passed, generally the 1987-89 period was used.
3. The National Ambient Air Quality standard for ozone is 0.12 parts per million (ppm) daily maximum 1-hour average
not to be exceeded more than once per year on average. The average estimated number of exceedances column shows the number
of days the 0.12 ppm standard was exceeded on average at the site recording the highest updated air quality value. This
is done after adjustment for incomplete, or missing days, during the 3-year period/ 1991-93. The last two columns contain
data from the site recording the highest second daily maximum 1-hour concentration in 1993. The last column shows the
estimated exceedances for 1993 at the site recording the highest second maximum 1-hour concentration listed in the previous
column.
4. Special purpose monitoring (SPM) operating during the ozone monitoring season.
5. The nonattainment/updated air quality value site for the Chicago NA Area is in Kenosha County, WI.
6. The Regional office is reviewing the status of the area based on data through 1994.
7. Incomplete data reported in 1991.
8. Calculation of the updated air quality value and estimated exceedances adjusted to account for start-up of a LMOS
Study site with data only in 1991.
9. Data from a monitoring site located at the water treatment plant not used due to localized Interference.
10. The site was located atop Hhitetop Mountain, VA as part of the Mountain Cloud Study. Site elevation is 5520
feet. No data reported after 1988. This is a rural transport area. The nonattainment area ie that portion of Nhltetop
Mountain above 4500 feet elevation.
11. Calculation of estimated exceedances adjusted for Wisconsin ozone season not yet reflected in AIRS.
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APPENDIX G
LISTING OF MUNICIPAL SOLID WASTE LANDFILL
ORGANIZATIONS AND RELATED SERVICE PROVIDERS
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-------
Listing of Municipal Solid Waste Landfill Organizations
and Related Service Providers
Solid Waste Association of North America
(SWANA)
P.O. Box7219
Silver Spring, MD 20910-7219
Contact: Michael Ohlsen
Phone: (301) 585-2989
Fax: (301) 585-7068
Environmental Industry Associations (EIA)/
National Solid Wastes Management
Association (NSWMA)
4301 Connecticut Avenue, NW
Suite 300
Washington, DC 20008
Contact: Ed Repa
Phone: (202) 244-4700
Fax: (202) 966-4818
Association of State and Territorial Solid
Waste Management Officials (ASTSWMO)
Hall of States
Suite 343
444 North Capitol Street, NW
Washington, DC 20001
Phone: (202) 624-5828
Fax: (202) 624-7875
National Business Industries Association
122 C Street, NW
Fourth Floor
Washington, DC 20001
Phone: (202) 383-2540
Fax: (202) 383-2670
Department of Energy Regional Biomass.
Energy Program
Office of National Programs
U.S. Department of Energy
1000 Independence Avenue, S.W.
Washington, D.C. 20585
Contact: N. Michael Voorhies,
National Coordinator
Phone: (202)586-9104
American Public Works Association
1301 Pennsylvania Avenue, NW
Suite 501
Washington, DC 20004
Contact: Sarah Layton
Phone: (202) 347-0612
Fax: (202) 737-9153
Regional Biomass Energy Programs:
Northeast Region
Richard Handley, Program Manager
CONEG Policy Research Center,
Inc.
400 North Capitol Street, NW
Suite 382
Washington, DC 20001
Phone: (202) 624-8454
Fax: (202) 624-8463
Northwest Region
Jeff James, Program Manager
U.S. Department of Energy
Seattle Regional Support Office
905 NE 11th Avenue
Portland, OR 97232
Phone: (503) 230-3449
Fax: (503) 230-4973
September 1996
-------
Regional Biomass Energy Programs
(continued):
Great Lakes Region
Frederick J. Kuzel
Council of Great Lakes Governors
35 East Wacker Drive #1850
Chicago, IL 60601
Phone: (312) 407-0177
Fax: (312) 407-0038
Southeast Region
Philip Badger, Program Manager
Tennessee Valley Authority
435 Chemical Engineering Building
Muscle Shoals, AL 35660
Phone: (205) 386-3086
Fax: (205) 386-2963
Western Region
Dave Swanson
Western Area Power Authority
1627 Cole Boulevard
P.O. Box 3402
Golden, CO 80401
Phone: (303)231-1615
Fax: (303) 231 -1632
September 1996
-------
APPENDIX H
LIST OF REFERENCES
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References
Anderson, C.E., "Selecting Electrical Generating Equipment for Use with Landfill
Gas." Rust Environment and Infrastructure, Naperville, Illinois.
Augenstein, D., Pacey, J. Landfill Gas Energy Utilization: Technology Options
and Case Studies. EPA-600/R-92-116. Research Triangle Park, North Carolina:
Air and Energy Engineering Research Laboratory, U.S. EPA, June 1992.
Author unlisted. "50-MW Steam Powerplant Burns Landfill Gas," Power. February
1987, p. 62.
Author unlisted. "Regulatory Barriers to Landfill Gas Recovery Projects," pp. 66-88.
Berenyi, E.B., and Gould, R.N. 1994-95 Methane Recovery From Landfill
Yearbook. Governmental Advisory Associates, Inc. 1994, New York, NY.
Bonny, Alan E. "Commercialization of Landfill Gas Based Methanol Production
Facilities," SWANA 18th Annual Landfill Gas Symposium Proceedings. New
Orleans, March 1995, pp. 183-190.
DeHaan, Thomas E. "Ohio Plant Taps Local Landfill Methane in Co-Firing
Scheme," Power. April 1994, pp. 100-101.
Easterly, J., Lowenstein, M. Coqeneration from Biofuels: A Technical Guidebook.
TV-67207A. TVA Biomass Program, Southeastern Regional Biomass Energy
Program, U.S. DOE, October 1986.
Electric Power Daily. "CL&P, Groton To Test Fuel Cell That Runs on Land-Fill
Methane," McGraw Hill's Electric Power Daily. July 21, 1995. p. 3.
Energy Information Administration (EIA). Monthly Energy Review Tables (available
via electronic bulletin board), March 1995, Tables 9.9 and 9.11.
Eppich, J.D., Cosulich, J.P. "Collecting and Using Landfill Gas As A Boiler Fuel,"
Solid Waste & Power. Vol. VII, No. 4. July/August 1993, pp. 27-34.
Fuel Cell Commercialization Group (FCCG). Fuel Cell Planning Fact Sheet.
931105.4. 1993.
Gas Research Institute (GRI). The Opportunity for Medium and Heavy Duty NGVs.
GRI. May 1995.
ICF, Incorporated (ICF). Summary of Information on Factors Affecting the
Development of Landfill Gas Projects. ICF. March 1994.
-------
Jansen, G.R. "The Economics of Landfill Gas Projects in the United States."
Presented at the Symposium on Landfill Gas Applications and Opportunities,
Melbourne, Australia, February 27, 1992.
Knapp, George. "Ownership Options, Financing Structures, and Regulatory
Considerations Affecting the Choice Between Independent Power Production and
Qualifying Facility Projects." McDermott, Will & Emery, Washington, DC. 1990.
Kulakowski, Walter. 'Tapping the Tax-Free Municipal Market." Proceedings of the
Ninth Annual Cogeneration and Independent Power Market Conference. New
Orleans, March 9, 1994.
Mahin, Dean B. "Landfill Gas Powers Southeastern Plants," World Wastes.
September 1991, pp. 52-53.
Martin, Keith. "IRS Explains How Royalty Payments Affect Section 29 Tax Credits."
Chadbourne & Parke, Washington, DC. July 19, 1994.
Martin, Keith. Tax-Exempt Financing," Independent Energy. Vol. 23, No. 9,
November 1993, pp. 20-24.
Martin, Keith, Zahren, Bernard J., McGuigan, Michael J. 'Tax Issues and
Economic Incentives for LFG Utilization Projects." SWANA18th Annual Landfill Gas
Symposium Proceedings. New Orleans, March 1995, pp. 132-143.
Maxwell, Greg. "Will Gas-to-Energy Work at Your Landfill?" Solid Waste & Power.
June 1990, pp. 44-50.
McCord, Tom. "Landfill Gas Readies the Trash the Competition," Gas Daily's NG.
April/May 1994, pp. 54-55.
Mumford, E. Bruce, Lacher, Blake J. "The Equity Stake," Independent Energy.
March 1993, pp. 8-16.
Nardelli, Ray. "The Wide World of Landfill Gas Flares," SWANA Conference . Los
Angeles, 1993.
Pacey, J.G., Doom, M.R.J., and Thorneloe, S.A. "Landfill Gas Utilization - Technical
and Non-Technical Considerations." Presented at the Solid Waste Association of
North America's Seventeenth Annual International Landfill Gas Symposium, Long
Beach, California, March 22-24, 1994.
Public Technology, inc.(PTI), Landfill Methane Gas Recovery and Utilization: A
Handbook for Local Governments. EPA-CX-818726. Regional Operations Staff,
Office of Science, Planning, and Regulatory Evaluation/Office of Research and
Development, U.S. EPA, 1994.
-------
Public Utility District No. 1 of Snohomish County, Washington (Snohomish).
Request for Proposals for Power Supply Resources and Attachments. Pre-Bid
Conference, Everett, Washington. February 15, 1994.
Public Utility Reports (PUR). "IRS Tax Credit Rates," PUR Utility Weekly. Letter No.
3150, May 13, 1994, p. 1.
R.F. Webb Corporation (Webb). The Energy Policy Act of 1992: A Report on the
Alternative Transportation Fuel and Alternative Fuel Vehicle Provisions of the Act.
October 1992.
Research Institute of America, Inc. (RIA). RIA Federal Tax Handbook. 1993
Edition. RIA, New York, NY. 1992, pp. 320-321.
Rice, Frederick. "Monitoring and Managing Landfill Gas."
SCS Engineers. Implementation Guide for Landfill Gas Recovery Projects in the
Northeast. Prepared for the Coalition of Northeastern Governors Policy Research
Center, Inc. June 23, 1994.
Schleifer, R. "Easy Landfill Gas Profits," Waste Age. March 1988, pp. 105-106.
Strait, R., Doom, M., and Roe, S. Emerging Technologies for the Utilization of
Landfill Gas. Prepared for the Office of Research and Development of the U.S.
EPA. April 1995.
Swanekamp, Robert. "Ridge station eases Florida's waste-disposal problems,"
Power. October 1994, pp. 84-85.
Swanekamp, Robert. "Fuel Cells Inch Towards Mainstream Power Duties," Power.
June 1995, pp. 82-90.
Thorneloe, Susan. "Landfill Gas Utilization - Options, Benefits, and Barriers."
Presented at the Second United States Conference on Municipal Solid Waste
Management, Arlington, VA, June 3-5, 1992.
Thorneloe, S.A., Pacey, J.G. "Landfill Gas Utilization - Database of North American
Projects." Presented at the Solid Waste Association of North America's
Seventeenth Annual International Landfill Gas Symposium, Long Beach, California,
March 22-24, 1994.
U.S. Congress, Office of Technology Assessment, Facing America's Trash: What
Next for Municipal Solid Waste, OTA-0-424 (Washington, DC: U.S. Government
Printing Office, October 1989).
U.S. Congress, House of Representatives, Clean Air Act Amendments of 1990
Conference Report, (Washington, DC: U.S. Government Printing Office, 1990).
-------
U.S. EPA (EPA). Opportunities to Reduce Anthropogenic Methane Emissions in
the United States. Report to Congress. EPA430-R-93-012. Air and Radiation, U.S.
EPA. October 1993.
U.S. National Archives and Records Administration, Office of the Federal Register,
40 CFR Parts 190 to 259. (Washington, DC: U.S. Government Printing Office, July
1993).
U.S. National Archives and Records Administration, Office of the Federal Register,
10 CFR Part 451. (Washington, DC: U.S. Government Printing Office, July 1995).
U.S. National Archives and Records Administration, Office of the Federal Register,
18 CFR Part 292. (Washington, DC: U.S. Government Printing Office, April 1991).
Valenti, Michael. 'Tapping Landfills for Energy," Mechanical Engineering. January
1992, pp. 44-47.
Wallace, Ian. "Landfill Gas-Fired Power Plant Pays Cost of Operating Landfill,"
Power Engineering. January 1991, pp. 27-29.
Walsh, J.J, and Hamilton, S.M. "Application of Emission Analyses Results Under
the Proposed Clean Air Act Landfill Gas Rule." Presented at the Environmental
Industry Associations National Solid Wastes Management Association WasteExpo
'94, Dallas, Texas, May 5, 1994.
Waste Management of North America, Inc. (WMNA). "Landfill Gas Recovery
Projects." Presented at the Solid Waste Association of North America's Fifteenth
Annual Landfill Gas Symposium, Arlington, VA, March 24-26, 1992.
Wheless, E., Thalenberg, S., Wong, M.M. "Making Landfill Gas Into A Clean
Vehicle Fuel," Solid Waste Technologies. December 1993.
Wolfe, B., and Maxwell, G. "Commercial Landfill Gas Recovery Operations -
Technology and Economics." Waste Management of North America, Inc. Oak
Brook, Illinois.
Zack, M., Minott, D. "New Federal Controls on Landfill Gas Emissions and the
Economics of Landfill Gas Recovery," pp. 1119-1144.
Technical Reference Section
Proceedings of Technical Conferences
SWANA. The Solid Waste Association of North America, Solid Waste Information
Clearing House (SWICH) (301) 585-2898. Proceedings of SWANA Annual
Landfill Gas Symposia and Proceedings of SWANA Annual International Solid
Waste Exposition (WASTECON).
-------
NSWMA. The National Solid Wastes Management Association, (800) 424-2869.
Proceedings of Annual Landfill Conferences
Other Technical References
Anderson, Charles, E. "The Impact of New Source Performance Standards Upon
the Development of Landfill Gas-To-Energy Projects." Presented at the Joint
ASME/IEEE Power Generation Conference, Kansas City, Kansas, October 17-22,
1993.
Bogner, J.E., 1990. Energy Potential of Modern Landfills. Proceedings Illinois
Energy Conference, Chicago, Illinois, October 29-30, 1990.
Bogner, J.E., M. Vogt and R. Piorkowski, 1989, Landfill Gas Generation and
Migration: Review of Current Research II. Proceedings Anaerobic Digestion
Review Meeting, Jan. 25-26, 1989, Golden, Colorado, Solar Energy Research
Institute. Available: NTIS, PC A03/MFA01, CONF-8901100-2. DE89009821/XAB.
1989.
Campbell, D., D. Eperson, L Davis, R. Peer, and W. Gray. Analysis of Factors
Affecting Methane Gas Recovery from Six Landfills. EPA-600/2-91-055 (NTIS
PB92-101351). September 1991.
CISA. The Environmental Sanitary Engineering Center (CISA), Cagliari, Italy:
Proceedings of Annual International Landfill Symposia, held in Sardinia, Italy.
Doom, M., J. Pacey and D. Augenstein. Landfill Gas Energy Utilization
Experience: Discussion of Technical and Non-Technical Issues. Solutions, and
Trends. U.S. EPA/AEERL, Research Triangle Park, NC. AEERL-835. 1994.
EMCON Associates. Methane Generation and Recovery From Landfills. Second
Edition, Ann Arbor Science. Ann Arbor, Ml. 1982.
Gendebien, A., M. Pauwels, M. Constant, M.J. Ledrut-Damanet, EJ. Nyns, H.C.
Willumsen, J. Butson, R. Fabry, and G.L. Ferrero. Landfill Gas From Environment
to Energy. Directorate-General for Energy, Commission of the European
Communities, Brussels, EUR 140017/1 EN. 1992.
U.K. Department of Energy. Harwell Laboratories, Oxfordshire. Landfill Gas and
Anaerobic Digestion of Solid Waste. 1988.
USEPA. Anthropogenic Methane Emissions In the United States: Estimates for
1990. Report to Congress. Office of Air and Radiation (6202J). EPA 430-R-93-
003. April 1993.
Valenti, Michael. 'Tapping Landfill for Energy." Mechanical Engineering January
1992, pp. 44-47.
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Interviews/Personal Communications
Nancy Adkins, Natural Gas Vehicle Coalition. Telephone interview. August 9,
1995.
Alan Bonny, TeraMeth. Personal Communication at Washington State Landfill
Methane Outreach Program Workshop, June 20, 1996.
Dick Brown, Coen Company. Telephone interview. August 11,1995.
Alan Epstein, CEO, Gas Resources Corp. Telephone interview. June 30, 1994.
Raymond DePrinzio, Credit Suisse. Telephone interview. May 1, 1995.
Paul Hewitt, Perry Equipment. Telephone interview. Oct. 13, 1994.
William Merry, Monterey Regional Waste Management District (Marina Landfill).
Telephone interview. June 27, 1994.
Jim Morefield, National Park Service, Kenilworth Park Landfill. Telephone
interview. June 24, 1994.
Bill Owens, Michigan Cogeneration Systems. Personal interview at I-95 Landfill,
Lorton, VA. July 12, 1994.
Gar Seifullin, Heller Financial. Telephone interview. May 1, 1995.
Jeff Smithberger, Deputy Director, Fairfax County Division of Solid Waste Disposal
& Resource Recovery (I-95 Landfill). Personal interview at I-95 Landfill, Lorton, VA.
July 12, 1994.
Ed Wheless, Los Angeles County Sanitation Districts. Telephone interview. June
27, 1994.
Robert Wilson, Environmental Protection Manager, Montgomery County, MD
(Gude Southlawn Sanitary Landfill). Telephone interview. June 23, 1994.
Kurt Kiunder, U.S. Department of Energy, Office of Energy Efficiency and
Renewable Energy. Telephone communication. September 12, 1995.
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APPENDIX I
ACID RAIN FACT SHEET
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Page Intentionally Left Blank
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United States
Environmental Protection
Agency
Air and
Radiation
(6204-J)
EPA430-K-94-014
November 1994
Landfill Methane and
Clean Air Act Opportunities
Incentives from the Acid Rain Program
Photo courtesy of New England Electric
System
The environmental benefits of generating electricity from landfill
methane now have an added, quantifiable value. Through an innovative
system oftradeable emission allowances. Title IV of the Clean Air Act
has increased the value of electricity generated from landfill methane.
ACIDRAIN
PROGRAM
Reeyded/ftaeyetable M Newsprint • Printed with Vegetable OS Based Inks on 100% Recycled Paper (50% Postconsumer)
-------
Methane gas emissions from our country's growing landfill sites are a serious
threat to greenhouse gas stabilization. Capturing methane from landfill sites for
electrical generation serves both economic and environmental goals. Landfill
methane is already a cost-effective energy resource in many areas of the country.
The Clean Air Act incentives will further enhance the cost-effectiveness of land fill
methane energy projects.
The Clean Air Act Incentives
The 1990 Clean Air Act Amendments
call for a 10 million ton annual reduction
in national S02 emissions from 1980
levels. This program creates a new
tradeable commodity, the SO2 emission
allowance. Each allowance represents
an authorization to emit one ton of SO2
(i.e., a unit that emits 5,000 tons of S02
must hold at least 5,000 allowances that
are usable that year). By avoiding the
emission of SO2 with landfill methane
systems, utilities will both earn and save
tradeable emission allowances. And
these emission allowances have a real
market value.
To promote pollution prevention, Title IV
of the Clean Air Act includes two
incentives for energy efficiency and
renewable energy. These incentives
are:
1. Avoided emissions
2. Conservation and Renewable Energy
Reserve
Avoided emissions is perhaps the most
lucrative of the incentives; each ton of
S02 avoided through the generation of
electricity from landfill methane saves
one emission allowance. Allowances
are saved at the utility's own rate of
emissions. The avoided emissions
incentive is automatic; there are no
application or verification requirements.
The Sonoma County, CaKfomia landfill gas-to-energy
facility. Photo courtesy of Landfill Energy Systems.
The Conservation and Renewable Energy
Reserve is a special bonus pool of
300,000 allowances set aside to reward
new initiatives in technologies such as
landfill methane. For every 500 MWh of
electricity generated through landfill
methane systems, a utility earns one
allowance from the Reserve.
For more information on these incentives,
see Energy Efficiency and Renewable
Energy: Opportunities from Title IV of
the Clean Air ActS
1. US EPA, Energy Efficiency and Renewable Energy: Opportunities from Title IV of trie Clean Air Act. Document no. EPA
430-R-94-O01, February 1994. To obtain a copy, contact the Acid Rain Hotline at (202) 233-9620.
-------
Valuing the Incentives
In general, the value of the Clean Air Act
incentives will be the number of
allowances earned or saved by the landfill
methane installation multiplied by the
market price of an S02 emission
allowance. The hypothetical example
below illustrates the potential savings
from the Clean Air Act incentives.2
The market for tradeable emission
allowances is continuing to evolve. A
recent report issued by the Electric Power
Research Institute (EPRI) indicates that
prices could rise from $250 per allowance
in 1995 to $480 per allowance in 2007.3
Price signals are also being provided by
private trades and trading exchanges.
Example
Cumulative Value of the S02 Incentives
IBM 1M M02 ZX» 2010 SOU
In 1994, a utffity installs 7 MW of capacity from landfill
methane sites. The utility will enter the Add Rain Program
in the year 2000, and thus is eligible to earn Reserve
allowances untB 2000. Assuming 9 typical capacity factor
of O.8S, the value of the Reserve allowances is calculated as
follows:
7 MW x 8,760 nours/yr x 0.85 = 52,122 MWh/yr
52,122 MWh/yr + 500 MWh/aBowance = 1 (Mallow./yr
$250/allowance x 1O4 allowances/yr - $26,000/yr
Thus, for the six years from 1994 through 1999, the utility
could earn $ 156,000 from the Reserve alone. However,
landfill methane will continue to add value in the year 2000
and beyond through the avoided emissions incentive. And
the benefits from avoided emissions will be even greater than
those from the Reserve.
Assuming the utility's marginal rate of SO, emissions is 1.2 Ibs/mmBtu (the emission limit for the Acid Rain
Program) and a typical heat rate of 10,000 Btu/kWh, the value of avoided emissions in the year 2000 is:
1.2 Ibs/mmBtu x 10,000 Btu/kWh x mmBtu/1,000,000 Btu = 0.012 Ibs/kWh
52,122,000 kWhx 0.012 Ibs/kWhxl ton/2000 IDS = 313 tons = 313 allowances
313 allowances x $34O/aliowance = $106,420
Assuming a 20 year project Hfe and a 6% discount factor, the net present value of the Clean Air Act
incentives for this landfill methane project is $980,000.
Since landfill methane is a local resource, transmission losses are reduced and thus further improve the
project's cost-effectiveness.
2. For a more detailed explanation of the calculations in this example, contact the Acid Rain Hotline at (202) 233-9620 and
ask for the Landfill Methane example.
3. EPRI, IntegratedAnalysis of fuel. Technology and Emission Allowance Markets: Electric Utility Responses to the Clean
Air Act Amendments of 1990, Report no. TR-102510, August 1993, p. 1-20.
1995 2000 2003 2007
Price <$/ton) $250 $340 $400 $480
-------
UffityAtBes: Tapping the Potential of Landfai Methane
igeneca^ fn^liandiffl.!^
laductions ini'localianrpoHuti
source, p
dtvei^se^and kxafrescwBr tase.
has created Hie tantfrai Methane Outreacn Program.
|J»A
To becomea Utility ABy in this program, a utility agrees to
take ad vantage of the best opporomitiesforobialniQgpower
from tendSI gas. In torn, EPA recognizes ^and^pufaGcizes «be
utility^s' vFforts * and-11 can '--assist "«in -'the - iwaluatiofi < -ancl
fts customers, and a win for the environment and the
economy.
EPA
.that over 700 Jandfffls across the US could
OUTOEACH PROGRAM
instaU econom^ty«raaEUe:fer^^ yet only about 1 15 facffities are
01 ptace. The EPA LandfiH Methane Outreach Piogfarii is working to overcome the informational,
regulatory, and other barriers that prevent these otherwise economical projects from going
forward.
For more information on how your utility can become a Utility Ally, please contact EPA's LandftH
Methane Program at (202) 233-3042.
Complying Cost-Effectively
Landfill methane resources can be cost-
effective components to an integrated
compliance strategy by:
• Complementing or offsetting the use
of other compliance strategies such
as fuel-switching;
• Delaying or eliminating the need for
expensive alternative strategies such
as scrubbing;
• Helping to avoid the noncompliance
penalty of $2,000 per ton of SO2; and
• Increasing revenues through the sale
of extra allowances.
The extent to which the Clean Air Act
incentives affect the financial outlook of
landfill methane systems will depend
upon each utility's own circumstances.
Utilities that currently emit high levels of
SO2 can benefit significantly from the
incentives. However, even utilities
already in compliance can benefit from
the revenues generated from extra
allowances.
-------
Benefiting the Environment
Emissions from fossil fuel generation
harm waters and forests, endanger animal
species, accelerate the decay of buildings
and monuments, and impair public health.
In many sensitive lakes and streams
acidification has completely eradicated
fish species.
Research has pointed to the increased
health risks from paniculate matter, which
includes sulfates and other pollutants
emitted during the combustion of fossil
fuels. A recent study by Harvard
University's School of Public Health linked
these emissions to higher mortality rates
and lung dysfunction in children and
other sensitive populations.4
Emissions from fossil-fuel sources have damaged
many forests.
Electricity generated from landfill methane
helps combat not only acid rain, but
other environmental harms as well,
including global climate change. Landfill
methane systems avoid emissions of
S02, toxics, and particulates, as well as
the production of ash and scrubber
sludge.
Electricity generated from landfill methane
will also help minimize emissions affecting
global climate change. Not only does
this resource offset emissions from fossil
fuel energy generation, but it also
prevents the escape of methane gas, a
greenhouse gas that is over 20 times
more potent than carbon dioxide. Every
10,000 kilowatt hours of electricity
generated from landfill methane is
equivalent to:5
Planting 23,680 Trees per Year, or
Eliminating 360 Barrels of Crude Oil
Landfill methane systems can be cost-
effective solutions for simultaneously
eliminating multiple pollutants. Rather
than installing costly controls for each
pollutant, landfill methane technology
can be a solution for many pollutants.
Landfill methane systems also provide
insurance against the risk of future
environmental regulations, including
regulations on greenhouse gas emissions.
The real, quantifiable value of the Clean
Air Act incentives can maximize a utility's
overall cost-effectiveness in serving its
customers and protecting the
environment.
4. Dockery, Douglas W., et al., An Association between Air Pollution and Mortality in Six US Cities, The New England Journal
of Medicine, vol. 329, no. 24. December 9, 1993, p. 1753-9.
5. Based on the 1990 average CO emission rate for US utility generation.
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Landfill Methane Recovery Process
GAS ENGINE &
ALTERNATOR
NETWORK
PROCESS V
DISTRICT
HEAT
GAS COLLECTION
NETWORK
BOILER
Landfill gas is generated naturally through the bacterial decomposition of organic matter deposited in a sanitary
landfill. Gas collection systems pull the gas from a series of wells to a central processing facility, land fill gas '•
Is typically a medium Btu gas that has a number of energy applications, fh$ most prevalent useWprtcfticM ;
of electricity for sale to the local utility. The gas may also be employed directly tor use as boiler fuel and Industrial
process heat or converted for use as compressed natural gas for vehicle fuel.
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Utfffty Profile: Detroit Edison Company
As trie landfill gas recovew^ "
in-developing Michigan's first landfill gas-fired combustron turtme ^et^rating stae60n.
The 6,6-megawatt facility has safely and reliably operated :at more than 85 percent
capacity since achieving commercial operation in 1988. .,
Sited on a landfill owned by the City of Rivenrew, 20 iriBessouth of .Detroit, the smaft
power production facility uses enough methane gas to .generate electricity for about
6,000 homes. Morethan ,100 gas welts on the 150-acre site collect about 4.3-milBon
cubic feet of. landfill: gas daily to .
generate the power, which is sold
to Detroit Edison.
While the project's 225,000
megawatt-hours of electricity is a
smafl portion of Detroit Edison's
overall power production, the
environmental significance is
impressive. By capturing more
than 8 million cubic feet of landfill
gas, this project has prevented
more than 1,200 tons of sulfur
dioxide emissions which would
have been produced by fossil-fueled
power generation. Each day the
project di rectly destroys m ore than 2 million cubic feet of methane, a potent greenhouse
gas.
Detroit Edison's involvement with 120-acre Sonoma Central landfill in California is
relatively new. Through a subsidiary, landfill gas is collected, cleaned, compressed and
delivered as fuel to a plant producing 3.2 megawatts. Sonoma County, owner of the
facility, has been selling the electricity since May 1993. The facility uses about 1,200
cubic feet per minute of landfill gas to produce its power.
The Riverview and Sonoma facilities are licensed to operate well into the 21st century.
Their success has prompted Detroit Edison to pursue similar ventures in Florida, Illinois,
Texas, Ohio, and elsewhere in Michigan.
Riverview, Michigan landfffl gas-to-energy faciT/ty
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For More Information
Writeto:
US Enwir^^
Energy 'Efficiency and Renewable Energy
Section . . . ' '•.
4OYM Street, SW
Washington, DC 20460
sjf you^havefiSritfierqiw^onsOT would like toTeceive
jcalt the Acid Rain
Hotiine at i202> 233-9620. An Energy eficiency
and Jteriewifal^ ^Energy staff member w^ return
your call within 24 hours.
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APPENDIX J
GLOSSARY OF TERMS
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Glossary of Terms
AFFECTED LANDFILL: Landfills that meet criteria set by the EPA under
authority of Title I of the Clean Air Act for capacity, age, and emission rates;
affected landfills are required to collect and combust their landfill gas
ATTAINMENT AREA: A geographic region that meets National Ambient Air
Quality Standards (NAAQS) for specific air pollutants
AVOIDED COST: The cost a utility would incur to generate the next increment
of electric capacity using its own resources; many landfill gas projects'
buyback rates are based on avoided costs
BASELOAD: A term referring to the energy use of a facility that has a
consistent, year-round need for energy; baseload can also refer to the
minimum amount of electricity supplied to a facility on a continuous basis
BEST AVAILABLE CONTROL TECHNOLOGY (BACT): The most stringent
technology available for controlling emissions; major sources are required to
use BACT, unless it can be demonstrated that it is not feasible due to energy,
environmental, or economic reasons
BUYBACK RATE: The price a utility will pay a third party supplier for electricity
or gas
CAPACITY FACTOR: The ratio of the energy produced by a piece of
equipment during a given time period to the energy the unit could have
produced if it had been operating at its full rated capacity
CAPACITY PRICE: The fixed price in $/kW a utility pays a third party supplier
for a guaranteed availability of generating capacity; capacity price is based on
the capital costs of a generating unit
CAPITAL CHARGE RATE: A number used to convert the installed cost of a
power project into a levelized capital cost that can be charged to the project in
each year of the project life
CAPITAL COST: The total installed cost of equipment, emissions control,
interconnections, gas compression, engineering, soft costs, etc. for landfill gas
projects
COGENERATION: The consecutive generation of useful thermal energy and
electric energy from the same fuel source
September 1996
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COMBINED-CYCLE: Technology in which waste heat from a gas turbine is
used to produce steam in a waste-heat boiler; the steam is then used to
generate electricity in a steam turbine/generator
CONDENSATE: Liquid formed when warm landfill gas cools as it
travels through the collection system
COST OF CAPITAL: The cost to a company of acquiring funds to finance the
company's capital investments and operations
DEBT COVERAGE RATIO: Ratio of operating income to debt service
requirement, usually calculated on an annual basis
DEBT SERVICE REQUIREMENT: Monthly requirement to meet the principal
and interest amounts of a loan
DISPLACEMENT SAVINGS: Savings realized by displacing purchases of
natural gas or electricity from a local utility by using landfill gas
EPC FIRM: A company that provides engineering, procurement, and
construction services
FLARE: A device used to combust excess landfill gas that is not used in
energy recovery; flares may be open or enclosed
GREENHOUSE GAS: A gas, such as carbon dioxide or methane, which
contributes to global warming
GROSS POWER GENERATION POTENTIAL: The installed power generation
capacity that landfill gas flows can support
HEAT RATE: A measure of generating unit thermal efficiency, expressed in
units of Btu/kWh
LOWEST ACHIEVABLE EMISSIONS RATE (LAER): The most stringent
technology available for controlling emissions; major sources are required to
use LAER (cost is not a consideration in determining the LAER technology)
MAJOR SOURCE: New emissions sources or modifications to existing
emissions sources that exceed NAAQS emission levels
METHANE (CH^: The major component of natural gas and landfill gas;
produced in landfills when organic matter in waste decomposes
September 1996
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METRIC TON: Measurement of mass; one metric ton equals one megagram
(Mg)
MINOR SOURCE: New emissions sources or modifications to existing
emission sources that do not exceed NAAQS emission levels
NATIONAL AMBIENT AIR QUALITY STANDARDS (NAAQS): Air quality
standards, established by the Clean Air Act, for six criteria pollutants
NET PRESENT VALUE (NPV): The amount of money, that if invested today at
a given rate of return, would be equivalent to a fixed amount to be received at
a specified future time
NEW SOURCE REVIEW (NSR): Process by which an air quality regulatory
agency evaluates an application for a permit to construct a new generating
facility
NONATTAINMENT AREA: A geographic region designated by the EPA that
exceeds NAAQS for one or more criteria pollutants
NON-METHANE ORGANIC COMPOUNDS (NMOCs): Compounds found in
landfill gas which affect human health and vegetation; NMOCs include several
compounds that are known carcinogens to humans
PARASITIC LOAD: The electric load required to run generation equipment;
contributes to the difference between gross and net output
PREVENTION OF SIGNIFICANT DETERIORATION (PSD): Regulations
designed to limit the increase of criteria air pollutants in attainment areas
PRO FORMA: A computer model of project cash flows over the life of the
project, usually containing several standard items
PROJECT FINANCE: A method for obtaining commercial debt financing for the
construction of a facility where lenders look to the creditworthiness of the
facility to ensure debt repayment, rather than to the assets of the project
developer
PUMP TEST: A procedure used to determine the gas generation rate of a
landfill; it involves drilling test wells and installing pressure probes
PUBLIC UTILITIES REGULATORY POLICIES ACT (PURPA): Act that requires
utilities to purchase the electric output from QFs at the utility's avoided cost
September 1996
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QUALIFYING FACILITY (QF): A cogenerator or small power producer, as
defined by PURPA, that is entitled to special regulatory treatment; utilities are
required to purchase the electrical output from QFs at the utility's avoided cost
RATE OF RETURN (ROR) ON EQUITY: Financial measurement used to judge
the percent of return on equity capital used in business
RENEWABLE ENERGY PRODUCTION INCENTIVE (REPI): Incentive
established by the Energy Policy Act, that is available to renewable energy
power projects owned by a state or local government or nonprofit electric
cooperative
REQUEST FOR PROPOSALS (RFP): A solicitation by a utility for project
proposals
ROYALTIES: Compensation given to a landfill owner for gas rights
SENIOR DEBT LENDER: Institution or person who lends money with the
intention that the debt will be repaid before project earnings get distributed to
equity investors
SOFT COSTS: Transaction and legal costs, escalation during construction,
interest during construction, and contingency costs associated with a project
STANDARD OFFER: A power purchase agreement, sanctioned by the state
utility commission, that is typically based on avoided costs
SUBORDINATED DEBT: Money that is repaid after any senior debt lenders
are paid and before equity investors are paid
VOLATILE ORGANIC CHEMICALS (VOCs): Chemicals found in landfill gas that
are contributors to smog
WHEELING: The transmission of electricity owned by one entity using the
facilities owned by another entity (usually a utility)
September 1996
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United States
Environmental Protection Agency
(6202J)
Washington, DC 20460
Official Business
Penalty for Private Use
$300
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