LFGcost-Web Version 3.3
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Landfill Gas Energy Cost Model
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U.S. Environmental Protection Agency
Landfill Methane Outreach Program (LMOP)
CONTINUE
Version 3.3
August 2019
3SlE.cE
LANDFILL METHANE
OUTREACH PROGRAM
User s Manual
Landfill Methane Outreach Program (LMOP)
U.S. Environmental Protection Agency
Washington, DC
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LFGcost-Web User's Manual
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Table of Contents
Section Page
Introduction 1
Using LFGcost-Web 2
Summary of Revisions 2
General Instructions and Guidelines 2
Inputs 2
Outputs 3
Calculators 3
Summary Reports 3
Software Requirements 4
Cost Basis 4
Cost Scope 5
Cost Uncertainty 5
Evaluating Economic Benefits and Job Creation 7
Further Assistance 7
Technical Basis of LFGcost-Web 8
INST: General Instructions and Guidelines 9
INP-OUT: Inputs/ Outputs 10
WASTE: Waste Calculator/Disposal History 17
REGIONAL PRICING: Regional Electricity Pricing 18
CURVE: Landfill Gas Curve 19
AVOIDED CO2 - ELEC: Regional Grid Carbon Dioxide Avoided Emission Factors 20
ENV: Environmental Benefits 21
FLOW: Landfill Gas Flow Rate Calculations 24
C&F: Collection and Flaring System 26
DIR: Direct-Use System 27
BLR: Boiler Retrofit 28
HBTU: High Btu Processing Plant 29
CNG: Onsite CNG Production and Fueling Station 30
LCH: Leachate Evaporator 31
TUR: Standard Turbine-Generator Set 32
ENG: Standard Reciprocating Engine-Generator Set 33
MTUR: Microturbine-Generator Set 34
SENG: Small Reciprocating Engine-Generator Set 35
CHPE: CHP Reciprocating Engine-Generator Set 36
CHPT: CHP Turbine-Generator Set 37
CHPM: CHP Microturbine-Generator Set 38
ECN: Economic Analysis 39
BUDGET-ENG: Allocation of Recip. Engine Costs for Economic Benefits3 42
BUDGET-DIR: Allocation of Direct-Use Project Costs for Economic Benefits3 44
ECON-BEN SUMMARY: Economic Benefits and Job Creation Summary3 46
Appendix A: Default Value Documentation A-l
Appendix B: Common Abbreviations B-l
Appendix C: Evaluating Projects with Multiple Equipment and/or Start Dates C-l
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Appendix D: Evaluating Local Government-Owned Projects D-l
Appendix E: Evaluating Boiler Retrofit Projects E-l
Appendix F: Economic Multipliers for Economic Benefits and Job Creation Analysis F-l
Appendix G: Ranking Analysis for Economic Multipliers G-l
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List of Tables
Table 1. Worksheet Names and Functions in LFGcost-Web 8
Table 2. LFG Energy Project Types and Recommended Sizes 9
Table D-l. Recommended Default Assumptions for Local Government-Owned Projects D-l
List of Figures
Figure 1. Example of LFG generation, collection, and utilization curve in LFGcost-Web 19
Figure C-l. Example of a project with multiple equipment and start dates C-2
Figure C-l A. Example of an LFG generation, collection, and utilization curve for project
component A C-3
Figure C-1B. Example of an LFG generation, collection, and utilization curve for project
component B C-4
Figure C-1C. Example of an LFG generation, collection, and utilization curve for project
component C C-5
Background on the Model
LFGcost was initially developed in 2002 to help stakeholders estimate the costs of an LFG
energy project. Since then, LMOP has routinely updated the tool to reflect changes in the LFG
energy industry. In 2015, LMOP undertook a peer review of LFGcost-Web, Version 3.0. For
more information on the peer review, see the Emission Guidelines and Compliance Times for
Municipal Solid Waste Landfills rule docket (Docket ID# EPA-HQ-OAR-2014-0451-0210).
Based on the results of the peer review as well as other updates, LMOP revised certain elements
of the model, replacing it with LFGcost-Web, Version 3.1 in 2016. In May 2017, LMOP released
Version 3.2 and in August 2019, LMOP released Version 3.3.
The LFGcost-Web, Version 3.3, model and user's manual were prepared for EPA's Landfill
Methane Outreach Program (LMOP) by Eastern Research Group, Inc. (ERG) with assistance and
data contributions from Cornerstone Environmental Group, LLC and Smith Gardner, Inc. and
data contributions from CPL Systems, Inc.
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Introduction
The Landfill Gas Energy Cost Model, LFGcost-Web, is a software tool developed for EPA's
Landfill Methane Outreach Program (LMOP) to conduct initial economic analyses of prospective
landfill gas (LFG) energy recovery projects in the United States. Analyses performed using
LFGcost-Web are considered estimates and should be used for guidance only. A detailed
final feasibility assessment should be conducted by qualified LFG professionals prior to
preparing a system design, initiating construction, purchasing materials, or entering into
agreements to provide or purchase energy from an LFG energy project.
The software was created in Microsoft® Excel to make the computations transparent and to allow
for the model to be efficiently updated as the economics of LFG energy projects mature. This
document describes how to use the LFGcost-Web spreadsheet tool and presents the technical basis
underlying the software methodology.
The various LFG energy project types that can be analyzed in LFGcost-Web include:
~ New LFG collection and flaring systems (not expansion of existing systems);
~ Direct-use (boiler, greenhouse, etc.);
~ Boiler retrofit;
~ High Btu processing plant;
~ Onsite compressed natural gas (CNG) production and fueling station;
~ Leachate evaporators;
~ Seven different electricity generation project types:
o Standard turbine-generator sets;
o Standard reciprocating engine-generator sets;
o Microturbine-generator sets;
o Small reciprocating engine-generator sets;
o Combined heat and power (CHP) reciprocating engine-generator sets;
o CHP turbine-generator sets; and
o CHP microturbine-generator sets.
LFGcost-Web is an LFG energy project cost estimating tool developed for EPA's LMOP.
LFGcost-Web estimates LFG generation rates using a first-order decay equation. This
equation is used to estimate generation potential but cannot be considered an absolute
predictor of the rate of LFG generation. Variations in the rate and types of incoming waste,
site operating conditions, and moisture and temperature conditions may provide
substantial variations in the actual rates of generation.
The default inputs and costs estimated by LFGcost-Web are based on typical project designs
and for typical landfill situations. While the model allows a user to adjust certain inputs to
site- and project-specific conditions, the equations within the model are locked to maintain
the integrity of the model. The model attempts to include all equipment, site work, permits,
operating activities, and maintenance that would normally be required for constructing
and operating a typical project. However, individual landfills may require unique design
modifications which would add to the cost estimated by LFGcost-Web.
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Using LFGcost-Web
LFGcost-Web, Version 3.3, replaces Version 3.2. Significant revisions between Version 3.3 and
Version 3.2 of LFGcost-Web included:
~ Updated reference sources for calculating electricity prices and avoided CO2 grid factors
based on 2019 Annual Energy Outlook (AEO) regional electricity grids.
~ Updated default user inputs in Appendix A.
The most significant revision between Version 3.2 and Version 3.1 of LFGcost-Web was:
~ Added ability to estimate job creation and regional economic ripple effects for the
following two project types: electricity generation with standard reciprocating engine-
generator sets and direct-use. Economic and job creation benefits are estimates only
and are not guaranteed.
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The first worksheet within LFGcost-Web (see INST worksheet) provides important instructions
on the proper use of LFGcost-Web. These instructions include the size ranges over which
LFGcost-Web is expected to be most accurate for a given project type. Within these size ranges
LFGcost-Web is estimated to have an accuracy of ± 30 to 50 percent. Using LFGcost-Web to
evaluate projects outside of these recommended ranges will likely provide cost estimates with a
greater uncertainty. The INST worksheet also provides definitions of input and output parameters,
outlines the organization of LFGcost-Web, and summarizes important notes described below
regarding the model and its functionality.
Detailed information about running the model for unique project scenarios is contained in
Appendices C, D, and E. Appendix C provides guidance for evaluating projects with multiple
equipment and/or start dates, Appendix D outlines the suggested inputs for local government-
owned projects, and Appendix E explains how to set up and interpret results for boiler retrofit
projects.
Inputs
The second worksheet of LFGcost-Web (see INP-OUT worksheet) is where users enter the
required input data for evaluating an LFG energy project. In this worksheet, the Required User
Inputs table allows users to enter the minimum input parameters required for conducting an
economic analysis. The Optional User Inputs table gives users the option to adjust the default
input parameters used by LFGcost-Web. If these optional input parameters are not known for the
project being evaluated, the default parameters should provide a reasonable economic evaluation
of the project.
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The INP-OUT worksheet summarizes the results of the economic and environmental analysis
performed by LFGcost-Web in the Outputs table. This table has been arranged so users of
LFGcost-Web are able to change the project design and immediately see the resulting change in
economic analysis, without having to switch to another worksheet in LFGcost-Web. Most users of
LFGcost-Web will not need to look at other worksheets in LFGcost-Web when conducting a
routine economic analysis.
ulators
LFGcost-Web provides two calculators to assist model users. The Waste Acceptance Rate
Calculator in the WASTE worksheet calculates the average annual waste acceptance rate based
on the amount of waste-in-place and the year representing the time required to accumulate this
waste. Model users who do not know the average annual waste acceptance rate for a particular
landfill can use this calculator to estimate this rate.
The Financial Goals Calculator, located below the Outputs table in the INP-OUT worksheet,
calculates the initial product price that would be required for the project to achieve its financial
goals. It is assumed that financial goals are achieved when the internal rate of return (IRR) equals
the discount rate and the net present value is equal to $0. If a given economic analysis does not
achieve its financial goals or greatly exceeds the goals, model users can use this calculator to
determine the initial product price that is required to pay back the investment within the lifetime
of the project.
Model users must select "Enable Macros" or "Enable Content" when prompted (immediately after
opening the file) to allow the LFGcost-Web software to use the embedded macros that control the
operation of the Financial Goals Calculator. Enabling macros is discussed further in the
"Software Requirements" section below. The Financial Goals Calculator can be used ONLY
when macros are enabled and the Solver Add-in has been installed and loaded within Microsoft®
Excel. Please see the instructions below the Calculate Initial Product Price button in the INP-
OUT worksheet to load the Solver Add-in. This functionality is not compatible with Mac
computers.
Summary Reports
The first summary report (see REPORT worksheet) presents input, output, and curve information
similar to data found in the INP-OUT and CURVE worksheets. The printout will be labeled with
the landfill name or identifier that has been entered at the top of the INP-OUT worksheet as well
as the file name and current date. The appropriate initial product price needed to achieve financial
goals must be determined for each LFG energy project scenario using the Financial Goals
Calculator in order for the correct financial goal prices to appear in the report.
The second summary report (see RPT-CASHFLOW worksheet) presents a detailed summary of
the project cash flow analysis using data similar to data found in the ECN worksheet. Given the
detailed nature of this spreadsheet, it may be appropriate to include only for certain scenarios.
The third summary report (see ECON-BEN SUMMARY worksheet) presents the regional
economic benefits and job creation estimates for the following two project types: electricity
generation with standard reciprocating engines and direct-use.
An Adobe Portable Document Format (PDF) of the summary reports can be created from the
REPORT, RPT-CASHFLOW, and/or ECON-BEN SUMMARY worksheets in order to save or
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distribute read-only electronic copies. In order to create a PDF of the reports users must have a
printer driver installed on their computer that has the capability to convert files to this format (for
example, PDF995 or Adobe Acrobat). With this PDF printer driver installed, users can follow the
steps listed below to create a PDF of the summary reports.
1. Select the worksheet tab(s) you are interested in printing.
2. Select Print from the menu.
3. Select the PDF printer driver (e.g., PDF995) from the Printer drop-down menu and click
OK.
4. Once the PDF dialog box appears in a new window, users can preview the report and save
it to a file location of their choice. If using Adobe Acrobat, users can also specify which
worksheets to include in the .pdf file.
More information about downloading and purchasing PDF printer drivers can be obtained at
http://www.pdf995.com/ or https://www.adobe.com.
Software Requirements
LFGcost-Web has been specified as a "Read-Only" file. The "Read-Only" restriction is intended
to protect the original file from being accidentally over-written by users. You need to save a copy
of the LFGcost-Web file under a new file name when running each economic analysis.
The LFGcost-Web model was created in Microsoft® Excel and must be operated in a Microsoft®
Excel 2007, 2010, 2013, 2016, or Office 365 environment. Earlier versions of Microsoft® Excel
are not able to properly run the model due to embedded macros. Several functions operate slowly
when running LFGcost-Web on computers that have a processor speed of 333 MHz or less. This
model was tested on a PC. The Solver functionality does not work on a Mac.
Model users must "Enable Macros" or "Enable Content" when prompted (immediately after
opening the file) to allow the LFGcost-Web software to use the embedded macros.
Microsoft® Excel 2007, 2010, 2013, 2016, and Office 365 users must set their Macro Security
Level to "Disable all macros with notification" (menu select Developer ...Macro Security). [If the
Developer menu is not displayed in Excel 2007, click the Microsoft Office Button, select Excel
Options, and then in the Popular category, under Top options for working with Excel, select Show
Developer tab in the Ribbon. If the Developer menu is not displayed in Excel 2010, 2013, 2016,
Office 365 on the File menu, select Options, and then in the Customize Ribbon category,
under Customize the Ribbon, check the Developer box.] Then, upon opening LFGcost-Web, users
must select "Enable this content" from the Security Warning- Options... box that appears beneath
the menu.
The costs and economic parameters, such as net present value (NPV), are based on actual or
"nominal" rates and include the effects of inflation. For example, if a project was constructed in
2013 and began operation in 2014, then installed capital costs in the year of construction are in
2013 dollars, operating costs for the initial year of operation are in 2014 dollars, and NPV at year
of construction is in 2013 dollars. Within the structure of the various cost estimating worksheets
in LFGcost-Web, the costs for any given year in the life of the project are presented in that specific
year's dollars.
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The cost estimates produced by LFGcost-Web include all direct and indirect costs associated with
the project. In addition to the direct costs for equipment and installation, LFGcost-Web includes
indirect costs associated with:
~ Engineering, design, and administration;
~ Site surveys and preparation;
~ Permits, right-of-ways, and fees; and
~ Mobilization/demobilization of construction equipment.
Since these costs are estimated for an average project site in the United States, individual sites will
experience variations to these costs due to unique site conditions.
The uncertainty in the cost estimates produced by LFGcost-Web is estimated to be + 30 to
50 percent. As detailed in the list below, this uncertainty is a composite of uncertainties related to
LFG generation rates, future economic conditions, and unique site characteristics.
The uncertainty of + 30 to 50 percent is estimated based on the following:
~ Equipment used in the actual LFG energy project may need to be purchased at a larger size
than what is estimated by LFGcost-Web, because the standard equipment sizes vary from
one manufacturer to another. This may result in an underestimate of the actual costs.
~ Unusual site conditions may limit the type of LFG energy project that could be selected or
require additional site preparation and equipment. This may result in an underestimate of
the actual costs.
~ Environmental or permitting constraints may lead to higher costs. This can vary from
additional air pollution controls to increased equipment maintenance. This may result in an
underestimate of the actual costs.
~ Regional construction cost differences within the United States may result in either an
overestimate or an underestimate of the actual costs, depending on the region where the
landfill is located.
More specifically, the uncertainty of various project components can vary based on site-specific
or project-specific needs. Below is a summary of factors affecting the gas collection and control
system components, electricity-generating project components, and direct-use project
components:
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Gas Collection and Control Systems (GCCS) Components and Cost Factors
Component / Attribute
Key Site-Specific Factors
Gas collection wells or connectors
• Area and depth of waste
• Spacing of wells or connectors
Gas piping
• LFG flow rate
• Length of piping required
Condensation knockout drum
• Volume of drum required
Blower
• Size of blower required (a function of LFG flow
rate)
Flare
• Type of flare (open, ground, or elevated)
• Size of flare (a function of LFG flow rate)
Instrumentation and control system
• Types of controls required
Electricity-Generating Project Components and Cost Factors
Component / Attribute
Key Site-Specific Factors
Engine size
• Flow rate (gas curve)
• Electricity rate structures
• Minimum electricity generation requirements
(contract obligations)
Capacity to expand
• Maximum flow rate
• LFG flow rate over time (gas curve)
Gas compression and treatment
equipment
• Quality of the LFG (methane content)
• Contaminants (e.g., siloxane, hydrogen sulfide)
Interconnection equipment
• Project size
• Local utility requirements and policies
Direct-Use Project Components and Cost Factors
Component / Attribute
Key Site-Specific Factors
End use of the LFG
• Type of equipment (e.g., boiler, process heater, kiln
furnace)
• LFG flow rate over time
• Requirements to modify existing equipment to use
LFG
Gas compression and treatment
equipment
• Quality of the LFG (methane content)
• Contaminants and moisture removal requirements
• Filtration requirements
Gas pipeline
• Length (distance to the end use)
• Obstacles along the pipeline route
• LFG flow rate
Condensate management system
• Length of the gas pipeline
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LFG energy projects generate benefits for the communities and states in which they are located,
as well as for the United States as a whole. These benefits include new jobs and expenditures
directly impacting the local and state-wide economies as a result of the construction and operation
of an LFG energy project. In addition, there are indirect economic benefits when the direct
expenditures for an LFG energy project flow through the economy resulting in increased overall
economic production and economic activity within the local, state, and national economies.
While in the construction phase, an LFG energy project provides a one-time boost to the local and
state economies whereas the operation and maintenance (O&M) of the project generates ongoing
economic activity throughout the lifetime of the project. The annual impacts use the estimated
expenditures during the first year of the project's operation to estimate the annual economic
benefits during the O&M phase.
The LFGcost-Web model allocates the estimated capital and O&M costs for reciprocating engine
and direct-use projects to various wholesale trade and industrial manufacturing sectors in order to
estimate the regional economic benefits of the project. Here, the "region" is defined to be the state
where the project is constructed and so its output will include any benefit to the local and state
economies resulting from LFG energy project expenditures. The cost of large or specialized
components, or specialized engineering and design labor likely to be manufactured or hired outside
of the state, is not included in the state-wide impacts estimates. A specific description of how
project costs are allocated to each industry multiplier is presented in the BUDGET-DIR and
BUDGET-ENG sections of this user's manual.
The model allows the user to select a specific state in the BUDGET-DIR and BUDGET-ENG
worksheets to represent where the project is constructed. Alternatively, if you leave the state blank
and want to know the general economic benefits resulting from an LFG energy project, regardless
of the state, you can review the outputs provided for states representing the median (Oregon) and
upper (Indiana) and lower (Iowa) quartiles for both employment and economic output in the
ECON-BEN SUMMARY sheet. A summary of the multipliers and how the multipliers were
ranked according to their employment and economic output is shown in Appendices F and G.
The Bureau of Economic Analysis (BEA) does not endorse any resulting estimates and/or
conclusions about the economic impact of a proposed change on an area.
Farther Assistance
If you would like assistance using LFGcost-Web, please contact LMOP through the website at
https://www.epa.gov/lmop/forms/contact-us-about-landfill-methane-outreach-program.
Analyses performed using LFGcost-Web are considered estimates and should be used for
guidance only. A detailed final feasibility assessment should be conducted by qualified LFG
professionals prior to preparing a system design, initiating construction, purchasing
materials, or entering into agreements to provide or purchase energy from an LFG energy
project.
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Technical Basis of LFGcost-Web
Table 1 lists the worksheets that comprise the LFGcost-Web spreadsheet model. The following
sections document the design and technical basis of the contents of these worksheets.
Table 1. Worksheet Names and Functions in LFGcost-Web
Worksheet Name
Function
INST
General instructions and guidelines
INP-OUT
Required and optional user inputs and model output results
WASTE
Optional user inputs for annual waste acceptance data
REGIONAL PRICING
Regional power grid price reference
REPORT
Summary report of user inputs, model outputs, and curve
RPT-CASHFLOW
Detailed summary of 15-year cash flow analysis
CURVE
Landfill gas generation, collection, and utilization curve
AVOIDED C02-
ELEC
Regional power grid emission factors reference
ENV
Environmental benefits calculations
FLOW
Landfill gas generation, collection, and utilization calculations
C&F
Design and costing of new collection and flaring system
DIR.
Design and costing of direct-use of landfill gas
BLR
Design and costing of boiler retrofit
HBTU
Design and costing of high Btu processing plant
CNG
Design and costing of onsite CNG production and fueling station
LCH
Design and costing of leachate evaporator
TUR
Design and costing of standard turbine-generator set
ENG
Design and costing of standard reciprocating engine-generator set
MTUR
Design and costing of microturbine-generator set
SENG
Design and costing of small reciprocating engine-generator set
CHPE
Design and costing of CHP reciprocating engine-generator set
CHPT
Design and costing of CHP turbine-generator set
CHPM
Design and costing of CHP microturbine-generator set
ECN
Economic analysis (cash flow) calculations
BUDGET-ENG
Allocates recip. engine project costs to calculate economic benefits
BUDGET-DIR
Allocates direct-use project costs to calculate economic benefits
ECON-BEN
SUMMARY
Summary of economic benefits and job creation analysis
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INST: General Instructions and Guidelines
~ Glossary of Input and Output Parameters - The definitions contained within these two tables
in the model are provided in the "INP-OUT: Inputs/Outputs" section below.
~ LFG Energy Project Types and Recommended Sizes - This table outlines the 12 LFG energy
project types included in LFGcost-Web, as shown in Table 2 below. In addition, project sizes
are recommended for each type of LFG energy project, with units varying by project type as
follows:
- Direct-use, boiler retrofit, high Btu, and CNG projects - cubic feet per minute (ft3/min) of LFG.
- Leachate evaporator projects - gallons of leachate evaporated per day.
- Projects generating electricity (engines, turbines, and microturbines) - amount of electricity
generated in kilowatts (kW) or megawatts (MW).
LFGcost-Web is designed to accommodate the recommended size ranges given for each type of LFG
energy project. Model output results may not be valid for project sizes outside of the recommended
project size ranges.
~ Workbook Design - This table summarizes the name and function for each of the
27 worksheets contained in LFGcost-Web, as shown in Table 1 above.
~ Important Notes - The items listed under Important Notes in the model are described in more
detail in the "Using LFGcost-Web" section above.
Table 2. LFG Energy Project Types and Recommended Sizes
LFG Energy Project Type
Recommended Project Size
Direct-use (Boiler, Greenhouse, etc.)
400 to 3,000 ft3/min LFG
Boiler Retrofit
Less than or equal to 3,000 ft3/min LFG
High Btu Processing Plant
1,000 to 10,000 ftVmin LFG
Onsite CNG Production and Fueling Station
50 to 600 ftVmin LFG
Leachate Evaporators
5,000 gallons leachate per day and greater
Standard Turbine-Generator Sets
Greater than 3 MW
Standard Reciprocating Engine-Generator Sets
800 kW and greater
Microturbine-Generator Sets
30 to 750 kW
Small Reciprocating Engine-Generator Sets
100 kW to 1 MW
CHP Reciprocating Engine-Generator Sets
800 kW and greater
CHP Turbine-Generator Sets
Greater than 3 MW
CHP Microturbine-Generator Sets
30 to 300 kW
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INP-OUT: Inputs / Outputs
~ Required User Inputs - These inputs MUST be entered in order to properly characterize the
landfill and project parameters. Defaults are not provided for the required inputs because they are
unique for each landfill and project.
- Year landfill opened - Four-digit year that the landfill opened or is planning to open.
- Year of landfill closure - Four-digit year that the landfill closed or is expected to close.
- Area of LFG wellfield to supply project - Acreage of the landfill that contains waste and generates
LFG to be collected and utilized by the LFG energy project. The model assumes one well per acre to
determine vertical gas well, wellhead, pipe gathering system, and other costs for the collection and
flaring system. Acreage should represent area of landfill for gas collection to feed project, not total
landfill area. Gas collection and flaring cost estimates represent a complete new system (costs for
expansion of an existing system will be higher); inaccurate cost estimates may result for smaller landfill
areas (<10 acres) due to economic infeasibility of designing and installing an entire new collection and
flaring system.
- Method for entering waste acceptance data - Unless a project size is selected to be 'Defined by user"
in the optional user inputs section, the user must choose one of the three methods listed to represent
average or actual tonnage of municipal solid waste (MSW) accepted each year the landfill is open. The
waste data are used to calculate flow rate for projects that are not user-specified sizes.
Average annual waste acceptance rate - Average annual tons of MSW accepted each year the
landfill is open. This method should be used if actual yearly waste acceptance data are unknown.
Waste acceptance rate calculator - see "WASTE: Waste Calculator/Disposal History" section
below.
Annual waste disposal history - see "WASTE: Waste Calculator/Disposal History" section below.
- LFG energy project type - Pick list to choose one of the 12 LFG energy project types you want to
analyze. Table 2 (above) contains a list of project types to use for selecting the project type appropriate
for the size of your project.
- Will LFG energy project cost include collection and flaring costs? - Determines if costs for new
vertical well collection and flaring equipment (not expansion of existing equipment) are included in
the total LFG energy project cost.
Select Y (for yes) if the landfill does NOT have collection and flaring equipment installed and you
want to include collection and flaring costs in the total project cost.
Select N (for no) if the landfill already contains a collection and flaring system or you do not want
to include collection and flaring costs in the total project cost.
Collection and flaring costs cannot be included if boiler retrofit costs are not combined with direct-use
project costs.
- For Leachate Evaporator projects: Amount of leachate collected - Gallons of landfill leachate that
is collected and treated annually.
- For Boiler Retrofits: Will boiler retrofit costs be combined with direct-use project costs? -
Determines if direct-use project costs are included in the total LFG energy project cost.
Select Y (for yes) if boiler retrofit costs are to be combined with other direct-use project costs (i.e.,
developer incurs all costs).
Select N (for no) if boiler retrofit costs are kept separate (i.e., end user incurs boiler retrofit costs
only).
This input is discussed in further detail in Appendix E (Evaluating Boiler Retrofit Projects). Collection
and flaring costs cannot be included if N is entered or input cell is left blank.
- For Boiler Retrofits: Distance between end user's property boundary and boiler - Number of
miles between the end user's property boundary and the boiler.
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INP-OUT: Inputs / Outputs
Required User Inputs (continued)
- For Direct-use, High Btu, and CHP projects: Distance between landfill and end use, pipeline, or
CHP unit
For direct-use projects, the number of miles between the landfill and the end user of the LFG. When
costs are combined for direct-use and boiler retrofit projects, this input is the distance from the landfill
to the end user's property boundary.
For high Btu projects, the number of miles between the landfill and the natural gas pipeline or the end
user of the high Btu gas.
For CHP projects, the number of miles between the landfill and the CHP engine, turbine, or
microturbine.
To maintain integrity of the cost estimates, this distance should be limited to 10 miles or less.
- For CHP projects: Distance between CHP unit and hot water/steam user - Number of miles between
the CHP engine, turbine, or microturbine and the end user of the hot water/steam. To maintain integrity
of the cost estimates, this distance should be limited to 1 mile or less. The CHP unit and the hot
water/steam user are typically co-located, which would be a distance of zero (0) miles.
- Year LFG energy project begins operation - Four-digit year that the LFG energy project installation
will be complete and begin operating. The model requires the year to be between 2010 and 2025.
- Will model calculate avoided CO2 from energy generation at electricity projects? - Determines if
avoided CO2 emissions will be calculated by the model for electricity projects.
Select Y (for yes) if you prefer the model to calculate these emissions. Then go to the AVOIDED
C02- ELEC worksheet to select the appropriate grid factor, using AEO 2019 data, or follow the
instructions in the AVOIDED C02- ELEC worksheet to select the grid factor for another year of AEO
data.
Select N (for no) if you do not want to calculate the avoided emissions for electricity projects.
Note: avoided emissions for non-electricity generating projects will be calculated, regardless of selection.
~ Optional User Inputs - These inputs are initially set to the suggested defaults provided. To edit the
optional inputs, enter the requested input in the Optional User Input Data column. (Note: Data in
the Suggested Default Data column are protected and cannot be edited.)
- LFG energy project size - Pick list to choose LFG flow rate over the project life used to design the LFG
energy project - Minimum, Average, Maximum, or Defined by user. When 'Defined by user" is selected,
an LFG design flow rate MUST be entered in the input box below the LFG energy project size selection.
The default is for minimum LFG generation. However, the optimum project size will vary for different
project types. You are encouraged to try multiple size options to determine the optimum size for your
project conditions.
For direct-use projects, the optimum size is often based on the maximum gas flow.
The optimum size for electricity generation projects (including CHP) is often based on the average
flow.
- For user-defined project size only: Design flow rate - The design LFG flow rate, in cubic feet per
minute, entered for projects sized manually by users. 'Defined by user" MUST be selected for LFG energy
project size to indicate the project size is user-defined. A user-defined project size can be entered without
waste data. Since waste data are used to calculate flowrate, you will receive a warning message indicating
that the user-defined project size exceeds the maximum calculated LFG flowrate in cell AG28 of the
FLOW worksheet. Further, if you are using waste data to estimate flowrate, this warning message is
indicating that the landfill may not have enough gas available for this project.
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INP-OUT: Inputs / Outputs
Optional User Inputs (continued)
- Methane generation rate constant, k - The methane generation constant (k) used to determine the
amount of LFG generated generally varies depending on the climate of the area surrounding the landfill.
There are three k values to choose from: 0.04 per year for areas that receive 25 inches or more of rain
annually; 0.02 per year for drier (arid) areas that receive less than 25 inches of rain annually; or 0.1 per
year for bioreactors. The suggested default is 0.04 per year for typical climates. The k value entered should
equal one of these suggested values unless site-specific data are available, k values are discussed further
in the "FLOW: Landfill Gas Flow Rate Calculations" section below.
- Potential methane generation capacity of waste, Lo - The potential methane generation capacity of the
waste (Lo) in cubic feet per ton. This parameter primarily depends on the type of waste in the landfill. The
default of 3,204 cubic feet per ton should be used to represent MSW unless site-specific data are available.
Lo values are discussed further in the "FLOW: Landfill Gas Flow Rate Calculations" section below.
- Methane content of landfill gas - The methane content of LFG generally ranges between 45 and
60 percent. This parameter is used to calculate environmental benefits and normalize LFG production.
The default of 50 percent should be used unless site-specific data are available.
- Average depth of landfill waste - The average depth of the landfill waste (in feet) is used to estimate
costs of the vertical gas wells for the new collection and flaring system (not expansion of existing system).
The suggested default is 65 feet, but this should be changed if site-specific average waste depth is known
for the landfill.
- Landfill gas collection efficiency - The equipment used to collect LFG normally operates at efficiencies
between 70 and 95 percent. The suggested default is 85 percent.
- Utilization of CHP hot water/steam potential - For CHP projects, the percent of hot water/steam used
by the end user, out of the potential hot water/steam generated by the CHP unit. The range for the
utilization is between 0 and 100 percent. The suggested default is 100 percent.
- Expected LFG energy project lifetime - Estimated number of years that the LFG energy project will be
operating. The default project lifetime is 15 years, but the model sets the lifetime to 10 years for
microturbines (non-CHP applications). The project lifetime for all other project types should be greater
than or equal to 10 years, but cannot exceed 15 years.
Generally, 15 years is considered the average lifetime for the equipment installed in LFG energy projects
and thus, the longest period over which to evaluate project economics. In addition, LFGcost-Web uses the
project lifetime for determining the tax-based capital depreciation rate. In Section 179 of the 2001 Federal
Tax Code, the IRS recommends using 15 years for the depreciation of electricity and fuel pipeline projects
that are analogous to LFG energy projects. For these reasons, the default project lifetime is 15 years and
it is recommended not to use a value of less than 10 years or more than 15 years. However, microturbine
projects (non-CHP applications) should be set to a project lifetime of 10 years to match their expected life
of 10 years, as observed by manufacturers of LFG microturbines.
- Operating schedule - For all projects except leachate evaporators, the LFG may be used seasonally (e.g.,
for space heating six months out of the year). This parameter allows users to specify how many hours of
the day, days of the week, and weeks of the year the project will be requiring LFG. The suggested defaults
are 24 hours per day, 7 days per week, and 52.14 weeks per year to result in the maximum operating
schedule of 8,760 hours per year.
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INP-OUT: Inputs / Outputs
Optional User Inputs (continued)
- Global warming potential (GWP) of methane - The suggested default GWP of methane is 25 to reflect
the Fourth Assessment Report (AR4) of the Intergovernmental Panel on Climate Change (IPCC). This
parameter is used to calculate environmental benefits and direct methane reductions for greenhouse gas
reduction credits. This default is consistent with the use of IPCC AR4 GWP values by the annual national
U.S. GHG inventory submitted to the UNFCCC and emissions reported by large facilities and industrial
suppliers to EPA's Greenhouse Gas Reporting Program. Users may enter an alternate GWP value, if
desired.
- Will cost of metering station that serves as custody transfer point be borne by end user? - For boiler
retrofit projects, determines if the cost to install a metering station will be incurred by the end user
because it will serve as a custody transfer point.
- Select Y (for yes) if metering station costs will be included.
- Select N (for no) if metering station costs will not be included.
The suggested default is Y, to include metering station costs.
- Loan lifetime - The period over which the project loan will be repaid. The loan lifetime is assumed to
begin during the year of project design and construction. It is common for project loan periods to be
limited to half or two-thirds of the equipment lifetime to assure that the loan is repaid before the project
ends. Since much of the equipment used in LFG energy projects has a projected lifetime of 15 years, the
default loan lifetime is set to 10 years. However, loan lifetime should not exceed the project lifetime,
because it is not practical to assume that project financing would exceed the expected life of the project
equipment and revenues. See Appendix A for additional information.
- Interest rate - The actual or ""nominal" interest rate of the project loan. The suggested default is 6 percent
based on recent Moody Corporate AAA and BAA bond rates published by the Federal Reserve. See
Appendix A for additional information.
- General inflation rate - The inflation rate applied to operation and maintenance (O&M) costs. The
suggested default is 2.5 percent based on recent Consumer Price Indexes. See Appendix A for additional
information.
- Equipment inflation rate - The inflation rate applied to project equipment (capital) costs. The suggested
default is 2 percent based on recent plant construction cost indices. See Appendix A for additional
information.
- Marginal tax rate - The tax rate used to estimate tax payments; this item is not applicable to projects
funded and developed by local governments. For publicly owned projects, see Appendix D (Evaluating
Local Government-Owned Projects). The suggested default tax rate is 35 percent for projects funded and
developed by private entities, which is based on recent LFG energy project experience with commercial
projects. See Appendix A for additional information.
- Discount rate - The discount rate, or hurdle rate, is used to determine the present value of future cash
flows. This rate represents the internal time-value of money (on an actual or ""nominal" basis) used by
companies to evaluate projects. The suggested default is 8 percent based on recent LFG energy project
experience with commercial projects. See Appendix A for additional information.
- Down payment - The down payment on the project loan. The suggested default is 20 percent based on
recent LFG energy project experience with commercial projects. See Appendix A for additional
information.
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INP-OUT: Inputs / Outputs
Optional User Inputs (continued)
- Energy tax credits - Energy tax credits may be available for LFG utilization projects in select areas.
These energy tax credits include LFG or high Btu utilization ($/million Btu) and electricity generation
($/kWh). Municipalities installing LFG energy projects are generally tax exempt and are not directly
eligible for tax credits. In these instances, the values for the tax credits should be entered as zero.
However, a municipality may arrange to sell the tax credits to a third party. In this situation, only the
third-party payment to the municipality, provided in return for the tax credit, should be entered as energy
tax credits in LFGcost-Web. All of the default values are initialized to zero.
- Direct credits - Other credits can be evaluated for special situations. All of the default values are
initialized to zero.
Greenhouse gas reduction credit ($/MTCOiE) - for direct methane reductions from the landfill and
avoided carbon dioxide generated from displacing fossil fuels (in units of $ per metric ton of carbon
dioxide equivalents). Direct methane reductions (i.e., methane collected and either flared or utilized
in an LFG energy project) may contribute to this credit if the landfill is not required to collect and
combust LFG (e.g., complying with the NSPS/EG). You have the option of including (Y for yes) or
excluding (N for No) direct methane reductions. The suggested default is Y, to include direct methane
reductions.
Renewable electricity credit ($/kWh) - represents tradable renewable certificates (TRCs) or "green
tags" that are created when a renewable energy facility generates electricity (in units of $ per
kilowatt-hour). Each unique certificate represents all of the environmental benefits of a specific
quantity of renewable electricity generation, namely the benefits received when fossil fuels are
displaced.
Renewable fuel credit (S gallon I - for alternative vehicle fuel (CNG) projects, including projects
with Renewable Identification Numbers (RINs) where a gallon of renewable fuel produced in or
imported into the United States receives a credit.
Avoided leachate disposal (S gallon) - for leachate disposal costs previously incurred for leachate
evaporator projects.
Construction grant ($) - a government cash grant for project capital costs.
- Royalty payment for landfill gas utilization - Project developers that do not own the LFG may be
required to pay the landfill owner a royalty for the amount of gas utilized (in units of $ per million Btu).
The default is initialized to zero.
- Initial year product price - Initial year product prices are suggested for the sale of energy from the
project. These prices represent the initial year of project operation. See Appendix A for additional
information and documentation of the review of current product prices used to determine the following
suggested default prices:
Landfill gas production - $2.14/million Btu
Electricity generation - $0.062/kWh
CHP hot water/steam production - $3,83/million Btu
High Btu gas production - $2.14/million Btu
CNG production - $2.10/gasoline gallon equivalent (GGE) [to determine $/diesel gallon equivalent
(DGE), divide $/GGE by 0.866]
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INP-OUT: Inputs / Outputs
Optional User Inputs (continued)
- Annual product price escalation rate - The initial year product price will be escalated by this annual
value in the future years of the project. The suggested default for electricity prices is -2.9 percent, for
CNG prices is -2 percent, and for direct-use or high Btu prices is 1.3 percent. This rate represents an
escalation in real prices as discussed in Appendix A.
- Electricity purchase price for projects NOT generating electricity - The price for electricity
purchased by projects that do not generate their own electricity, such as direct-use projects. The suggested
default is $0,089 per kWh, as discussed in Appendix A.
- Annual electricity purchase price escalation rate - The annual escalation rate applied to purchased
electricity. The suggested default is -1.5 percent, as discussed in Appendix A.
~ Outputs - Results of the economic analysis and environmental benefits. Economic outputs are
discussed further in the "ECN: Economic Analysis" section below.
Economic Analysis (Individual project costs can vary by +30-50% due to situational factors):
- Design project size - For all projects except leachate evaporators, the amount of LFG (in cubic feet per
minute) used to determine the design flow rate of the project.
- Generating capacity for projects generating electricity - For electricity generation projects, the
generation capacity (in kilowatts) of the power producing equipment.
- Average project size for projects NOT generating electricity - For direct-use, boiler retrofit, high Btu,
CNG, and leachate evaporator projects, average project size represents the average amount of actual LFG
utilized over the lifetime of the LFG energy project. This output is presented in units of million cubic
feet per year and cubic feet per minute.
- Average project size for projects generating electricity - For engine, turbine, microturbine, and CHP
projects, average project size represents average annual kilowatt-hours of electricity generated (net).
- Average project size for CHP projects producing hot water/steam - For CHP projects, average
project size represents the average annual amount of hot water/steam produced in units of million Btu
per year.
- Total installed capital cost for year of construction - Total capital cost of the installed LFG energy
project.
- Annual costs for initial year of operation - Equipment operating and maintenance (O&M) cost for the
initial year of the LFG energy project.
- Internal rate of return - Return on investment based on the total revenue from the project and
construction grants, minus down payment (i.e., cash flow). More simply, the rate that balances the overall
costs of the project with the revenue earned over the lifetime of the project such that the net present value
of the investment is equal to zero.
- Net present value at year of construction - First year monetary value that is equivalent to the various
cash flows, based on the discount rate (which is defaulted to 8 percent, as discussed in Appendix A). In
other words, the NPV is calculated as the present value of a stream of current and future benefits minus
the present value of a stream of current and future costs.
- Years to breakeven - Years required for the total present value to exceed zero. An output of "None"
means there is no return on investment or no payback in the LFG energy project lifetime.
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INP-OUT: Inputs / Outputs
Outputs: Economic Analysis (continued)
Environmental Benefits:
- Total lifetime amount of methane collected and destroyed - Total million cubic feet of methane that
is collected and either destroyed by the flare (assuming 100 percent destruction efficiency) or utilized by
the LFG energy project.
- Average annual amount of methane collected and destroyed - Average annual million cubic feet of
methane that is collected and either destroyed by the flare (assuming 100 percent destruction efficiency)
or utilized by the LFG energy project on a yearly basis.
- GHG value of total lifetime amount of methane utilized in energy project* - Total million metric
tons of methane (represented by carbon dioxide equivalents, or MMTCO2E) that is utilized by the LFG
energy project. This output takes into account the operating schedule and gross capacity factor of the
project. Flared gas is not included in this value.
- GHG value of average annual amount of methane utilized in energy project* - Average annual
million metric tons of methane (represented by carbon dioxide equivalents per year, or MMTCO2E per
year) that is utilized by the LFG energy project on a yearly basis. This output takes into account the
operating schedule and gross capacity factor of the project. Flared gas is not included in this value.
- Total lifetime carbon dioxide from avoided energy generation* - Total emissions that are avoided
because LFG is utilized instead of combusting fossil fuels. This output is presented in units of million
metric tons of carbon dioxide equivalents. For direct-use, boiler retrofit, and high Btu projects, LFG is
assumed to offset the combustion of natural gas. For CNG projects, LFG is assumed to offset the
combustion of diesel fuel. For projects that generate electricity (turbines, engines, and microturbines),
electricity produced is assumed to offset the emissions from the local electricity market module region
where the project is located. See the Avoided C02- ELEC page for additional discussion on how to
estimate these values.
Average annual carbon dioxide from avoided energy generation* - Average annual emissions that are
avoided because LFG is utilized instead of combusting fossil fuels. This output is presented in units of million
metric tons of carbon dioxide equivalents per year. For direct-use, boiler retrofit, and high Btu projects, LFG
is assumed to offset the combustion of natural gas. For CNG projects, LFG is assumed to offset the
combustion of diesel fuel. For projects that generate electricity (turbines, engines, and microturbines),
electricity produced is assumed to offset the emissions from the local electricity market module region where
the project is located. See the Avoided C02- ELEC page for additional discussion on how to estimate these
values.
*Note: These output values are presented in scientific notation. This format is used because these outputs are
smaller values, typically less than 0.1. An output value of 1.23E-02 is equivalent to 1.23 x 10 2 or 0.0123.
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WASTE: Waste Calculator / Disposal History
~ Waste Acceptance Rate Calculator - calculates the average annual waste acceptance rate in tons
per year based upon the amount of waste-in-place and the year representing the time required to
accumulate this amount of MSW. This calculator is meant to be used when average or year-to-
year annual acceptance rates are unknown.
- Waste-in-place - total tons of MSW accepted and placed in the landfill.
- Year representing waste-in-place - four-digit year that corresponds to the waste-in-place tonnage.
-OR-
~ Annual Waste Disposal History - this table allows users to enter yearly waste acceptance rate
data in tons per year for up to 75 years. The waste disposal history should be used only when
year-to-year waste acceptance is known for each year that the landfill operates. In other words,
the annual waste acceptance column must be completed for all years beginning with the landfill
open year and ending with the landfill closure year. The Year and Waste-In-Place columns
within the table are protected and cannot be edited.
- Year - four-digit year with Year 0 being the open year of the landfill.
- Annual waste acceptance - tons of MSW accepted per year for the corresponding year.
- Waste-in-place - a cumulative total of the tonnage of MSW accepted for previous years.
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REGIONAL PRICING: Regional Electricity Pricing
~ A lookup table for 2018 electricity prices for each electricity market module is available for
users that want to reference a more regional price basis for selling LFG electricity or purchasing
electricity to run a gas collection and control system. These reference prices can be used to
replace the national average default values in cell D59 or cell D65 of the INP-OUT worksheet.
~ The basis of the prices in the lookup table is the Annual Energy Outlook 2019 published by the
U.S. Energy Information Administration (EIA).
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CURVE: Landfill Gas Curve
~ The graph presented on the CURVE worksheet displays the LFG generation, collection, and
utilization in average standard cubic feet per minute from the year the project begins
operations to 25 years beyond start-up.
- Hie LFG generation curve is represented by a thick solid line and shows the estimated amount
of gas that the landfill is capable of producing. The gas generation does not take into account the
fact that not all of the gas is recoverable.
- The LFG collection curve is represented by a thin solid line and provides an estimate for the
amount of gas collected. The gas collection rate is estimated by multiplying the gas generation
rate by the collection efficiency. For more information about collection efficiency, please see
the "INP-OUT: Inputs/Outputs" section above.
- The LFG utilization curve is shown as a dashed line and represents the amount of gas utilized
by the project for the years the project is operating. Collection efficiency, project size, operating
schedule, gross capacity factor, and parasitic loss efficiency are taken into account when
calculating the LFG utilization. An example of the LFG generation, collection, and utilization
curve is shown in Figure 2 for a 15-year project beginning operation in 2015.
Landfill Gas Generation, Collection, and Utilization Curve
2.000
1.800
E
h
re
(£.
5
o
(fl
RS
O
T3
C
re
c
c
<
a>
>
<
.600
1.400
1.200
1.000
2039
¦Gas Generation
- Gas Collection
¦Gas Utilization
Figure 1. Example of LFG generation, collection, and utilization curve in LFGcost-
Web
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AVOIDED CO2 - ELEC: Regional Grid Carbon Dioxide Avoided Emission
Factors
~ A lookup table for 2019 through 2028 projected CO2 emission factors for each electricity market
module is available for users that want to estimate avoided CO2 emissions from an LFG
electricity-generating project. A user must select the factor of interest and enter it in cell CIO of
the ENV worksheet. In addition, the user must indicate "Y" in cell C21 of the INP-OUT
worksheet to indicate a preference to estimate avoided CO2 emissions.
~ The basis of the prices in the lookup table is the Annual Energy Outlook 2019 published by EIA.
~ Below the lookup table is a hyperlink to the generic Annual Energy Outlook website and
instructions to allow users to re-calculate avoided CO2 emission factors as new datasets are
released by EIA.
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ENV: Environmental Benefits
~ Environmental benefits are determined for each year of the LFG energy proj ect. The benefits
are calculated separately for projects that DO NOT generate electricity and projects that DO
generate electricity. The four primary calculations that occur for each type of project are
listed below:
- Methane collected and destroyed - total annual amount of methane (in cubic feet per year,
fit3/yr) that is collected and either destroyed by the flare or utilized by the LFG energy project.
CMethane collected ^ ^
and destroyed
(ft3 /yr)
Annual gas
collection
(ft31 yr)
\
(% methane ^
in LFG
- Direct methane reduced - total annual amount of methane (in million metric tons carbon
dioxide equivalents per year, MMTCC^E/yr) that is collected and either destroyed by the flare
or utilized by the LFG energy project.
( Direct methane \ (Methane collected"
reduced
(MMTC02EI yr)
(
and destroyed
{ft'I yr)
0.9072MT
short ton
^ 0.0423 lbs methane ^
ft3 methane
^ short Ion ^
v 2,000 lbs j
V
fGWPop
*
( MMT ^
J
methane j
[lO6 MT J
— Methane utilized by project - annual million metric tons of methane (in MMTCC^E/yr) that
is utilized by the LFG energy project.
(Methane utilized^
(MMTC02E/yr)y
f Actual gas
utilization
{ft' I yr)
r% methane^ f 0.0423 lbs methane 1f short ton ^
in LFG
ft3 methane
v 2,000 lbs j
f 0.9072M7^
*
(GWPop
*
f MMT \
short ton j
methane j
^106 MT J
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ENV: Environmental Benefits
Environmental Benefits (continued)
- Avoided carbon dioxide emissions - annual carbon dioxide emissions avoided because LFG is
utilized instead of combusting fossil fuels (MMTCC^E/yr). Avoided carbon dioxide emissions are
not estimated for leachate evaporator projects.
For direct-use, boiler retrofit, and high Btu projects, carbon dioxide emissions typically offset
the combustion of natural gas. The emission factor of 0.12037 pounds carbon dioxide per cubic
foot natural gas (conversion from kg CO2 per million Btu) is referenced in Table C-l of "2013
Revisions to the Greenhouse Gas Reporting Rule" (Nov. 2013),
https://www.gpo.gov/fdsvs/pkg/FR-2013-11 -29/pdf/2013 -27996 .pdf.
For CNG projects, carbon dioxide emissions typically offset the combustion of diesel fuel. The
emission factor of 161 pounds carbon dioxide per million Btu (conversion from kg CO2 per
million Btu for Distillate Fuel Oil) is referenced in Table C-l of "2013 Revisions to the
Greenhouse Gas Reporting Rule" (Nov. 2013). https://www.gpo.gov/fdsvs/pkg/FR-2013-l 1-
29/pdf/2013 -27996. pdf.
For projects that generate electricity (turbines, engines, and microturbines, including CHP), carbon
dioxide emissions offset the combustion of fossil fuels. The emission factor will vary by region in
which the project is located. The AVOIDED C02-_ELEC worksheet contains the grid-specific
emission factors, in units of pounds carbon dioxide per kilowatt-hour, for 2019 through 2028, based
on the AEO 2019. The user must select the appropriate factor for the model to compute an estimate.
CHP avoided carbon dioxide emissions are determined using the same natural gas emission factor
as direct-use projects, as described above.
Direct-use and boiler retrofit projects:
f Direct - use avoided^
carbon dioxide
emissions
{MMTC02E /yr) j
(Actual gas]
utilization
Cft3 /yr)
f%CH^
yin LFG j
1,012 Btu
ft3 methane
\ ( ^3
*
ft3natural gas
1,050 Btu
0.12037 lbs CO2
ft1 natural gas
A
*
' short ton N
*
y
v 2,000 lbs j
V
0.9072MT
short ton
\
MMT
v10 6MT j
High Btu projects:
^ HighBtu crmidedN
carbon dioxide
emissions
(MMTC02E / yr)
f Actual gas^
utilization
(ft3 /yr)
%CH4
in LFG
f ft3natural gas
1,050 Btu
(
( ono,
90% Conversion Efficiency LFG CH4
High Btu CH4
1,012 Btu
ft3 methane
0.12037 lbs CO,
ft3natural gas
*
short ton
*
f 0.9072M7^
*
f MMT \
/
{ 2,000 lbs j
short ton j
[lO6 MT)
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ENV: Environmental Benefits
Environmental Benefits (continued)
CNG projects:
( CNG avoided \
carbon dioxide
emissions
(MMTC02E / yr)
C Actual gas^
utilization
(ft3 / yr)
161 lbs CO,
r%CH4^| (65% Conversion EfficiencyLFGCH4Y 1,0125ft/ ^
inLFGy CNGCEI4 ft1 methane
millionBtu
Non-CHP electricity generation projects:
\ x f millionBtu ^ ^
' short ton ^
*
f 0.9072MT^
*
f MMT \
J I 106 Btu J
v 2,000/fo j
short ton j
[lO6 MT)
'Electricity generation x
avoided carbon
dioxide emissions
(MMTC.O:E / yr)
grid - specific lbs CO
kWh
2_ *
' Net electricity
produced
(kWh / yr)
(
short ton
\
v 2,000 lbs j
(
0.9012MT
\
v short ton y
MMT
106 MT
CHP electricity generation projects:
f CHP \
avoided carbon
dioxide emissions
(MMTC02E / yr)
grid - specific lbs CO
fNet electricity^ . .
produced
(kWh / yr)
2,000 lbs .
0.9072 MT
MMT
v short ton y
10 MT
MMT
(million Btu yr)
ft" (natural gas)
v 2,000lbs
. short ton ,
v10 "MT
' 10" Bin
ft natural gas
,million Btu y
i.050Btu
r( Hot water steam produced") J 0.12037 lbs CO,"] J short tonY 0.9012 Ml'"' (
0 .^(efficiency of hot water steam boiler)
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FLOW: Landfill Gas Flow Rate Calculations
~ The first-order decay equation is commonly used to estimate LFG generation from MSW
landfills. LFG production is normalized for actual methane content entered in the Optional
User Inputs table of the INP-OUT worksheet. The LFG generation equations used in LFGcost-
Web vary slightly depending on the type of waste acceptance rate data used (see the "INP-
OUT: Inputs/Outputs" section above). The two first-order decay equations used in LFGcost-
Web to determine LFG generation are as follows:
First-Order Decay Equation for Average Annual Waste Acceptance Rate:
Qt = (1/(CH4/100)) * Lo * R * [e( kc) - e( kt)]
Where,
Qt =
landfill gas generation rate at time t (ft3/year)
ch4 =
methane content of landfill gas (%)
Lo =
potential methane generation capacity of waste (ft3/ton)
R
average annual waste acceptance rate during active life (tons)
k
methane generation rate constant (1/year)
c =
time since landfill closure (years)
t =
time since the initial waste placement (years)
First-Order Decay Equation for Waste Disposal History (vear-to-vear acceptance rate):
Qt = I, [(1/(CH4/100)) * k * Lo * Mi * e( ktl)]
Where,
Qt =
landfill gas generation rate at time t (ft3/year)
ch4 =
methane content of landfill gas (%)
k
methane generation rate constant (1/year)
Lo =
potential methane generation capacity of waste (ft3/ton)
Mi =
waste acceptance rate in the ith section (tons)
ti =
age of the ith section (years)
~ The suggested default potential methane generation capacity (L0) is 3,204 cubic feet per ton
(100 cubic meters per megagram). This default L0 value comes from EPA's "Compilation of
Air Pollutant Emission Factors", commonly known as "AP-42", and is appropriate for most
landfills. Estimation of L0 is generally treated as a function of the moisture and organic content
of the waste. Therefore, it is recommended that users utilize L0 values that differ from these
defaults only when site-specific data are available to reasonably estimate the potential methane
generation capacity for a particular landfill.
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FLOW: Landfill Gas Flow Rate Calculations
Landfill Gas Flow Rate Calculations (continued)
~ Estimation of the methane generation rate constant (k) is a function of a variety of factors,
including moisture, pH, temperature, and landfill operating conditions. The constant k can vary
from less than 0.02 per year to more than 0.285 per year, depending on these site-specific
factors. EPA's AP-42 recommends that areas receiving 25 inches or more of rain per year use
a default k of 0.04 per year, and drier (arid) areas receiving less than 25 inches of rain per year
use a default k of 0.02 per year. A default k value of 0.1 per year is commonly accepted for
bioreactors or wet landfills (yet values >0.1 per year are common). It is recommended that
users utilize k values that differ from these defaults only when site-specific data are available
to reasonably estimate the methane generation constant for a particular landfill.
~ LFG flow rates are determined for each year of the LFG energy project. The eight primary
calculations that occur are listed below:
- Annual gas generation - cubic feet of LFG generated per year.
- Gas generation flow rate - cubic feet of LFG generated per minute.
- Annual gas collection - cubic feet of LFG collected per year.
- Gas collection flow rate - cubic feet of LFG collected per minute.
- Annual project gas utilization - cubic feet of LFG per year available for use by the LFG
energy project, which depends on the project size chosen. This calculation does not account for
operating schedule, gross capacity factor, or parasitic loss efficiency.
- Project gas utilization flow rate - cubic feet of LFG per minute available for use by the LFG
energy project, which depends on the project size chosen. This calculation does not account for
take operating schedule, gross capacity factor, or parasitic loss efficiency.
- Annual actual gas utilization - actual cubic feet of LFG utilized per year by the LFG energy
project. Based on user input and the type of project chosen, this calculation accounts for project
size, operating schedule, gross capacity factor, and parasitic loss efficiency.
- Actual gas utilization flow rate - actual cubic feet of LFG utilized per minute by the LFG
energy project, on an average annual basis. Based on user input and the type of project chosen,
this calculation accounts for project size, operating schedule, gross capacity factor, and
parasitic loss efficiency.
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C&F: Collection and Flaring System
Typical components include
~ Engineering, permitting, and administration;
~ Wells and wellheads;
~ Pipe gathering system (includes additional
fittings/installations);
~ Condensate knockout system;
~ Blowers;
~ Instrument controls;
~ Flare; and
~ Site survey, preparation, and utilities.
Drilling and pipe crew mobilization
$20,000
Installed capital cost of vertical gas extraction
wells
f average waste ^
-10ft * $85/ft = $X/well,
^ depth (ft) J
($4,675 * number of wells) for default average waste
depth of 65 feet
Installed capital cost of wellheads and pipe
gathering system
$17,000 * number of wells
Installed capital cost of knockout, blower, and flare
system
(ft3/min)0'61 * $4,600
Engineering, permitting, and surveying
$700 * number of wells
Annual O&M cost (excluding energy costs)*
($2,600 * number of wells) + $5,100 for flare
Electricity usage by blowers
0.002 kWh / ft3
vfote: Raw cost data arc in 2013$'s.
* Annual O&M for wells include the cost for monthly wellhead monitoring for gas quality and wellhead
adjustment purposes as well as the cost to maintain each well.
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DIR: Direct-Use System
Typical components include
~ Engineering, permitting, and
administration;
~ Skid-mounted filter, compressor, and
dehydration unit;
~ Pipeline to convey gas to project (includes
below-grade HDPE piping, condensate
removal system, and pipe fittings); and
~ Site survey, preparation, and utilities.
(Cost does not include payments for right-of-way
easements which may or may not be required.)
Installed capital cost of skid-mounted filter,
compressor, and dehydration unit
($360 * ft3/min) + $830,000
Installed capital cost of pipeline
For flow rates <1,000 ff/'min (8"piping):
($80* feet of pipeline) + $178,000
For flow rates 1,001 - 3,000 ff /'min (12" piping):
($106 * feet of pipeline) + $207,000
Annual O&M cost (excluding electricity)
$57,000* fft /mml
t 700 J
Electricity usage
For pipeline distances of 5 miles or less:
0.002 kWh/ft3
For pipeline distances where
(miles * (ft3 /min)2 ^
yj- — >120:
I 10 J
0.003 kWh/ft3
Gross capacity factor*
Assume 90%
vfote: Raw cost data arc in 2013$'s.
Gross capacity factor accounts for loss of energy production due to problems in the gas collection
system, problems with project equipment, weather related interruptions of the local utilities, and
shut-downs at the energy consumer end of the system.
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BLR: Boiler Retrofit
Typical components include
~ Pipeline delivery from end user's property boundary
to boiler (includes below-grade HDPE piping,
condensate removal system and pipe fittings,
engineering, permitting, and administration);
~ Metering station (includes LFG analyzer and flow
meter and moisture analyzer); and
~ Boiler conversion for seamless controls (includes fuel
delivery system, burner modifications, and control
modifications). Raw cost data for boiler conversion
provided by CPL Systems, Inc.
Installed capital cost of pipeline delivery from
end user's property boundary to boiler
For flow rates <1,000 ft5'Vmin (8" piping) :
$75 * (feet of pipeline) + $88,000
For flow rates 1,001 - 3,000ff Vmin (12" piping) :
$100 * (feet of pipeline) + $105,500
Installed capital cost of metering station
For flow rates <1,000 ft3Vmin:
$79,000
For flow rates 1,001 - 3,000 ft3Vmin:
$89,000
Installed capital cost of boiler conversion for
seamless controls
($113 *ft3/min) +$84,143
Gross capacity factor**
Assume 90%
^a\\ cost data are in 201 OS's.
Boiler conversion costs for manual controls are significantly less than seamless controls, but it is
becoming increasingly common for boiler owners with manual controls to upgrade to seamless controls
due to increased optimization. Conversion costs for multi-burner boilers, typically located at
petrochemical plants & refineries, are significantly higher than seamless controls due to inherent
complexities at facilities where these types of boilers are often found. Cost does NOT include boiler
re-certification, which may be necessary due to state/local regulations or insurance requirements.
Gross capacity factor accounts for loss of energy production due to problems in the gas collection
system, problems with project equipment, weather related interruptions of the local utilities, and
shut-downs at the energy consumer end of the system.
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HBTU: High Btu Processing Plant
Typical components include
~ Compressor;
~ Gas separators;
~ Gas dryers;
~ Pipeline to convey gas to project site or
natural gas pipeline; and
~ Site work, building construction, utilities, and
total facility engineering, design, and
permitting.
(Includes all equipment downstream of collection
and flaring system.)
Installed capital cost of compressor, gas separators,
and dryers for pipeline quality gas
/ ^ # x0.63
( /mm | * $8,400,000
^ 2,000 J
Installed capital cost of pipeline
$330,000 * miles of pipeline
Annual O&M cost (excluding electricity)
l. 1.000 J
Electricity usage
0.009 kWh/ft3
High Btu production
[(1,012 Btu/ft3 CH4) * (% CH4 in LFG) *
(90% conversion efficiency) * (million Btu/106
Btu)] = 0.0005 million Btu/ft3 LFG with default
50% CH4 in LFG
Gross capacity factor*
Assume 93%
vfote: Raw cost data are in 2008$'s.
Gross capacity factor accounts for loss of energy production due to problems in the gas collection
system, problems with project equipment, weather related interruptions of the local utilities, and
shut-downs at the energy consumer end of the system.
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CNG: Onsite CNG Production and Fueling Station
Typical components include
~ LFG-to-CNG conversion and conditioning unit;
~ Fueling station equipment (includes compressors,
dispensers, and storage tanks for all fill types ~ fast,
slow, combo fast/slow);
~ Winterization equipment, if needed (includes heat
tracing and insulation of hydrogen sulfide vessel and
heated and insulated structure over other
equipment);
~ Engineering and project management (includes site
design, layout, and permitting); and
~ Installation of all equipment, startup, and training.
(Includes all equipment downstream of collection and
flaring system.)
Installed capital cost
$95,000 * (ft3/min)0'6
Annual O&M cost for media and equipment
replacement and parasitic load
• *
$1.00/gasoline gallon equivalent (GGE)
CNG production
[(1,012 Btu/ft3 CH4) * (% CH4 in LFG) *
(65% conversion efficiency)] /II 1,200 Btu/GGE
= 0.0030 GGE/ft3 LFG with default 50% CH4 in LFG
Gross capacity factor**
Assume 93%
Mote: Raw cost data arc in 2013$'s.
To determine $/diesel gallon equivalent (DGE), divide $/GGE by 0.866.
Gross capacity factor accounts for loss of energy production due to problems in the gas collection
system, problems with project equipment, and weather related interruptions of the local utilities.
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LCH: Leachate Evaporator
Typical components include
~ Leachate evaporation unit;
~ Leachate surge tank;
~ Process control instruments; and
~ Site work, housings, utilities, and total facility
engineering, design, and permitting.
Annualized capital and O&M costs*
$320,000- fgallonsevaporated/yrV"
^ 3,467,500 J
Fuel use rate
80 Btu/gallon evaporated
Electricity usage
0.055 kWh/gallon evaporated
Leachate evaporation limit
No more than 95% of the available leachate can be
evaporated
vfote: Raw cost data are in 2008$'s.
Competitive rental costs were found for leachate evaporation, and were used to develop a combined
capital and operating cost.
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TUR: Standard Turbine-Generator Set
Typical components include
~ Gas compression and treatment (includes
dehydration equipment, siloxane adsorbers, and
filtration);
~ Turbine and generator (includes exhaust
silencers and all wiring and plumbing);
~ Electrical interconnect equipment; and
~ Site work, housings, utilities, and total facility
engineering, design, and permitting.
(Includes all equipment downstream of collection
and flaring system.)
Installed capital cost
For most situations:
[($2,340 * kW capacity) - (0.103 * (kW capacity)2)]
+ $250,000 for interconnect
For [$2,340- (0.103 * kW capacity)] < 1015:
($1,015 * kW capacity) + $250,000 for interconnect
Annual O&M cost (excluding energy)
$0.0144 * kWh generated/yr
(before parasitic uses)
Parasitic loss efficiency
88% of capacity due to parasitic electrical needs of
compression and treatment
Fuel use rate
13,000 Btu/kWh generated (HHV)
(before parasitic uses)
Gross capacity factor*
Assume 93%
vfote: Raw cost data are in 2008$'s.
Gross capacity factor accounts for loss of energy production due to problems in the gas collection
system, problems with project equipment, weather related interruptions of the local utilities, and
shut-downs at the energy consumer end of the system.
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ENG: Standard Reciprocal
ting Engine-Generator Set
Typical components include
~ Gas compression and treatment (includes
dehydration equipment and filtration);
~ Reciprocating engine and generator (includes
motor controls, switch-gear, radiators, exhaust
silencers, and all wiring and plumbing);
~ Electrical interconnect equipment; and
~ Site work, housings, utilities, and total facility
engineering, design, and permitting.
(Includes all equipment downstream of collection
and flaring system.)
Installed capital cost
[($1,300 * kW capacity) + $1,100,000] +
$250,000 for interconnect
Annual O&M cost (excluding energy)
$0,025 * kWh generated/yr
(before parasitic uses)
Parasitic loss efficiency
93% of capacity due to parasitic electrical needs of
compression and treatment
Fuel use rate
11,250 Btu/kWh generated (HHV)
(before parasitic uses)
Gross capacity factor*
Assume 93%
Mote: Raw cost data arc in 2013$'s.
Gross capacity factor accounts for loss of energy production due to problems in the gas collection
system, problems with project equipment, weather related interruptions of the local utilities, and
shut-downs at the energy consumer end of the system.
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MTUR: Microturbine-Generator Set
Typical components include
~ Gas compression and treatment (includes dehydration
equipment, siloxane adsorbers, and filtration);
~ Microturbine and generator (includes exhaust silencers
and all wiring and plumbing);
~ Electrical interconnect equipment; and
~ Site work, housings, utilities, and total facility
engineering, design, and permitting.
(Includes all equipment downstream of collection and
flaring system.)
Installed capital cost
$19,278 * (kW capacity)" 6207
Annual O&M cost (excluding energy)
($0.0736 - (0.0094 * ln(kW capacity))) * kWh
generated/yr
(before parasitic uses), includes gas cleanup system O&M
and microturbine overhauls
Parasitic loss efficiency
83% of rated capacity due to parasitic electrical needs of
boost compressor and cooling water pumps, fans, and
dryer system
Fuel use rate
14,000 Btu/kWh generated (HHV)
(before parasitic uses)
Gross capacity factor*
Assume 93%
Mote: Raw cost data are in 2006$'s.
Gross capacity factor accounts for loss of energy production due to problems in the gas collection
system, problems with project equipment, weather related interruptions of the local utilities, and
shut-downs at the energy consumer end of the system.
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SENG: Small Reciprocating Engine-Generator Set
Typical components include
~ Gas compression and treatment (includes
dehydration equipment and filtration);
~ Reciprocating engine and generator (includes
motor controls, switch-gear, radiators, exhaust
silencers, and all wiring and plumbing;
~ Electrical interconnect equipment; and
~ Site work, housings, utilities, and total facility
engineering, design, and permitting.
(Includes all equipment downstream of collection
and flaring system.)
Installed capital cost
$2,300 * kW capacity
Annual O&M cost (excluding energy)
$0,024 * kWh generated/yr
(before parasitic uses)
Parasitic loss efficiency
92% of capacity due to parasitic electrical needs of
compression and treatment
Fuel use rate
36 ft3/kWh generated (before parasitic uses)
Gross capacity factor*
Assume 93%
vfote: Raw cost data are in 2008$'s.
Gross capacity factor accounts for loss of energy production due to problems in the gas collection
system, problems with project equipment, weather related interruptions of the local utilities, and
shut-downs at the energy consumer end of the system.
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CHPE: CHP Reciprocating Engine-Generator Set
Typical components include
~ Gas compression and treatment (includes dehydration equipment
and filtration);
~ Heat recovery exchangers;
~ Reciprocating engine and generator (includes motor controls,
switch-gear, radiators, exhaust silencers, and all wiring and
plumbing);
~ Electrical interconnect equipment;
~ Site work, housings, utilities, and total facility engineering,
design, and permitting;
~ Gas pipeline from compressor to engine;
~ Water pipelines from engine to hot water user (assumes 2 lines for
supply and return); and
~ Circulation pump for water pipelines.
(Includes all equipment downstream of collection and flaring system.)
Installed capital cost
($1,900 * kW capacity) + ($250,000 for interconnect) +
($63 * ft of gas pipeline) + ($106 * ft of trench for water pipelines) +
($12,000 for circulation pump)
Annual O&M cost
(excluding energy)
$0.02 * kWh generated/yr (parasitic)
Parasitic loss efficiency
93% of capacity due to parasitic electrical needs of compression and
treatment
Fuel use rate
11,250 Btu/kWh generated (HHV)
(before parasitic uses)
Gross capacity factor*
Assume 93%
Hot water production
3,800 Btu/kWh (net) * % utilization of hot water potential
Note: Raw cost data are in 2008$'s.
Gross capacity factor accounts for loss of energy production due to problems in the gas collection
system, problems with project equipment, weather related interruptions of the local utilities, and
shut-downs at the energy consumer end of the system.
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CHPT: CHP Turbine-Generator Set
Typical components include
~ Gas compression and treatment (includes dehydration equipment, siloxane
adsorbers, and filtration);
~ Heat recovery exchangers;
~ Turbine and generator (includes exhaust silencers and all wiring and
plumbing);
~ Electrical interconnect equipment;
~ Site work, housings, utilities, and total facility engineering, design, and
permitting;
~ Gas pipeline from compressor to turbine;
~ Steam pipelines from turbine to steam user (assumes 2 lines for supply and
return); and
~ Circulation pump for steam pipelines.
(Includes all equipment downstream of collection and flaring system.)
Installed capital cost
For most situations:
[($2,340 * kW capacity) - (0.103 * (kW capacity)2)] + ($250,000 for
interconnect) + ($355 * kW capacity, for heat recovery exchangers) + ($63 * ft
of gas pipeline) + ($106 * ft of trench for steam pipelines) + ($12,000 for
circulation pump)
For [$2,340 - (0.103 * kW capacity)] < 1,370:
($1,370 * kW capacity) + ($250,000 for interconnect) + ($355 * kW capacity,
for heat exchangers) + ($63 * ft of gas pipeline) + ($106 * ft of trench for steam
pipelines) + ($12,000 for circulation pump)
Annual O&M cost
(excluding energy)
$0.0144 * kWh generated/yr
(before parasitic uses)
Parasitic loss efficiency
88% of capacity due to parasitic electrical needs of compression and treatment
Fuel use rate
13,000 Btu/kWh generated (HHV)
(before parasitic uses)
Gross capacity factor*
Assume 93%
Steam production
5,500 Btu/kWh (net) * % utilization of steam potential
vfote: Raw cost data are in 20085
S's.
Gross capacity factor accounts for loss of energy production due to problems in the gas collection
system, problems with project equipment, weather related interruptions of the local utilities, and
shut-downs at the energy consumer end of the system.
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CHP1
VI: CHP Microturbine-Generator Set
Typical components include
~ Gas compression and treatment (includes dehydration equipment,
siloxane adsorbers, and filtration);
~ Heat recovery exchangers;
~ Microturbine and generator (includes exhaust silencers and all wiring
and plumbing);
~ Electrical interconnect equipment;
~ Site work, housings, utilities, and total facility engineering, design, and
permitting;
~ Gas pipeline from compressor to microturbine;
~ Water pipelines from microturbine to hot water user (assumes 2 lines
for supply and return); and
~ Circulation pump for water pipelines.
(Includes all equipment downstream of collection and flaring system.)
Installed capital cost
($20,057* (kW capacity)0 6207 )+ [($20,057* (kW capacity)06207 ) *(0.06,
for heat recovery exchangers)] + ($63 * ft of gas pipeline) + ($106 * ft of
trench for water pipelines) + ($12,000 for circulation pump)
Annual O&M cost
(excluding energy)
$0.0773 - 0.00987* ln(kW capacity)
Parasitic loss efficiency
83% of rated capacity due to parasitic electrical needs of boost compressor
and cooling water pumps, fans, and dryer system
Fuel use rate
14,000 Btu/kWh generated (HHV)
(before parasitic uses)
Gross capacity factor*
Assume 93%
Hot water production
5,800 Btu/kWh (net) * % utilization of hot water potential
vfote: Raw cost data are in 2008$'s.
Gross capacity factor accounts for loss of energy production due to problems in the gas collection
system, problems with project equipment, weather related interruptions of the local utilities, and
shut-downs at the energy consumer end of the system.
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ECN: Economic Analysis
Economic Inputs:
Rows 4-25
These data are user-specified inputs that are retrieved from the INP-OUT worksheet.
Row 28
Initial IRR estimate used by Microsoft®) Excel"s IRR calculation function.
Row 29
LFG heat content calculated using user-specified methane heat content.
Inputs Calculated from Other Worksheets:
Rows 33-43 These data are the results calculated on other worksheets and brought to the ECN worksheet
for use in the economic analysis.
Economic
Analysis (Rows 46 to 92):
Row 46
Year of operation
The chronological year in the life of the project. The zero
year is the year of construction and year 1 is the first year of
operation.
Row 47
Revenue
The revenues from selling gas, electricity, CNG, or CHP hot
water/steam.
Row 48
Direct-use or Hish Btu Gas sales
For Direct-use: (ft3 LFG sold)*(Btu/ft3)*(million Btu/106
Btu)*($/million Btu)*(price escalation equation3);
For High Btu: (High Btu gas produced (million
Btu)*($/million Btu)*(price escalation equation3)
Row 49
Electricitv sales
(kWh electricity produced)*($/kWh)*(price escalation
equation3)
Row 50
CNG sales
(GGE produced)* ($/GGE)*(price escalation equation3)
Row 51
CHP hot water/steam sales
(million Btu water/steam produced)*($/million Btu)*(price
escalation equation3)
Row 52
Operating cost
The operating and maintenance costs for the project,
calculated on the various technology worksheets.
Row 53
Greenhouse sas credit
(avoided CO2 emissions-MTCO2E)*($/MTCO2E)*(106
MTCO2E/ MMTCO2E)
This credit can include direct methane emissions as well if
indicated in the Optional User Inputs table of the INP-OUT
worksheet.
Row 54
Renewable electricitv credit
(kWh electricity sold)*($/kWh)
Provides credits to LFG electricity projects that utilize
tradable renewable energy certificates (TRCs) or "green
tags."
Row 55
Renewable fuel credit
(GGE produced) *($/gal)
Provides credits to CNG projects including projects that use
Renewable Identification Numbers (RINs) where a gallon of
renewable fuel produced in or imported into the United
States receives a credit.
Row 56
Leachate credit
Gallons leachate evaporated)*(avoided $/gallon)*(general
escalation equation3)
The avoided cost for not treating the leachate when using a
leachate evaporator.
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ECN: Economic Analysis
Economic Analysis (continued)
Row 57
Gas rovaltv
(ft3 LFG utilized)*(Btu/ft3)*(million Btu/106 Btu)*(royalty
$/million Btu)
A royalty paid to landfill for use of LFG.
Row 59
Down Davment
Portion of capital cost not financed,
(total capital cost)*(% down payment)
Row 60
Construction grant
A government cash grant towards project capital costs.
Row 61
Loan (principal)
The levelized annual loan payment - calculated using
Microsoft® Excel"s payment function, based on interest rate,
loan period, and amount borrowed.
Row 62
Loan (interest)
Annual interest on remaining loan balance (principle),
(total capital cost - down payment)*(% interest rate)
Row 63
Eauitv oavment
Amount of annual loan payment applied to principle,
(annual loan payment) - (annual interest)
Row 64
Principal remaining
Unpaid loan principle.
(previous year principle) - (previous year equity payment)
Row 65
Depreciation
The straight line depreciation of capital cost for tax
purposes.
(total capital cost) / (project life-years)
Row 67
Tax liability
Sum of revenues minus expenses.
(direct or high Btu gas sales) + (electricity sales) + (CHP
hot water/steam sales) + (greenhouse gas credit) +
(renewable electricity credit) + (leachate credit) - (operating
cost) - (gas royalty) - (interest) - (depreciation)
Row 68
Tax before credit
Estimation of base tax before energy credits,
(tax liability)*(marginal tax rate)
Row 69
Tax credit
Sum of energy credits.
(LFG utilization credit) + (electricity generation credit) +
(High Btu production credit)
Row 70
Net tax
Sum of taxes minus tax credits,
(tax before credit) - (tax credit)
Row 72
Net income
Sum of revenues less operating costs.
(direct or high Btu gas sales) + (electricity sales) + (CHP
hot water/steam sales) + (greenhouse gas credit) +
(renewable electricity credit) + (leachate credit) - (operating
cost) - (gas royalty) - (interest) - (depreciation) - (net tax)
Row 75
Cash flow
Sum of annual cash flows.
(net income) - (down payment) + (construction grant) +
(depreciation) - (equity payment)
Row 77
Internal rate of return
The return on investment based on cash flow.
(calculated using Microsoft® Excel"s IRR' function based
on cash flow)
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ECN: Economic Analysis
Economic Analysis (continued)
Row 79 Cumulative cash flow
Row 81 Simple payback (years)
Row 84 Present value of cash flow
Row 87 NPV
Row 90 Cumulative present value
Row 92 Years to breakeven
The sum of cash flows to-date.
(previous year's cumulative cash flow) + (present year cash
flow)
The years of operation required for the cumulative cash
flow to become a positive value, based on an evaluation of
values in Row 79. This parameter is used only as an
error-checking tool.
Present value (PV) of the year's cash flow based on
discount rate.
(cumulative cash flow) / (compounded discount rate)
The net present value (NPV) or initial monetary value that is
equivalent to the sum of the cash flows, based on the
discount rate. This value is determined from the cumulative
PV (Row 90) at the end of the project life.
The sum of the PVs of cash flow to-date.
(previous year's cumulative PV) + (present year PV)
The years of operation that are required for the cumulative
PV to become a positive value, based on an evaluation of
values in Row 90.
Optimization for Calculating Initial Product Price Needed to Achieve Financial Goals:
Rows 96-151 These data are used to calculate the initial product price required to achieve the financial
goals of the project. The equations in rows 105-151 duplicate the structure of Rows 46-92
and are used to test various initial product prices for the purpose of converging on a net
present value of $0.
Other Economic Assumptions:
Salvage Value and Decommissioning Cost
For simplicity, LFGcost-Web does not consider the salvage value of the equipment nor the costs to recover
the site, at the end of the project life. Due to the nature of LFG energy projects, these costs are mutually
off-setting and generally result in a minimal impact to the overall economic evaluation of the typical LFG
energy project.
Escalation equations use a formula of [1 + ((% escalation after year l)/100)](year 01 calculatlon 11
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BUDGET-ENG: Allocation of Recip. Engine Costs for Economic Benefits3
This worksheet assigns the typical components of a reciprocating engine project (excluding costs of gas collection
and control system infrastructure) from the ENG worksheet to one of six categories: state/local labor, labor from
outside the state, state/locally manufactured materials, materials manufactured outside the state, state/local
distributor fees, or fees paid to distributors outside of the state. The list below shows how the reciprocating engine
project costs were assigned to these six categories.
Construction Phase (one-time costs)
Gas cleanup/compression unit purchase costs - 10% of overall combined engine/generator/skid costs
94% national manufacturer revenue
6% national distributor fee
Engine-generator unit purchase costs - 50% of overall combined engine/generator/skid costs
89% national manufacturer revenue
11% state-wide distributor fee
Installation costs for clean-up skid and Engine-Generator - 40% of overall combined
engine/generator/skid costs
5.4% national engineering and management labor for clean-up skid ($150/hr)
62.5% state-wide installation labor (6.1% for skid materials and 56.4% for engine/generator materials)
($125/hr)
32% state-wide installation materials (28% for engine/generator materials and 4% for skid materials)
Electrical interconnect costs
75% skid unit capital cost
64% national manufactured materials
11% state-wide distributor fee
25% installation cost
17% state-wide engineering, management, installation labor
8% state-wide manufactured installation materials
Annual Operating Costs
5% national proprietary materials (skid components)
45% common O&M materials (oil filters, lubricants, wiring)
34% national manufacturer materials
11% state-wide distributor fee on materials
50% state-wide labor (tuning wellfields and O&M of project equipment)
This worksheet then assigns labor and purchased materials to the Bureau of Economic Analysis 2015 RIMS II
multipliers that are most representative of the materials used in the construction of an LFG energy project. A
complete list of multipliers is shown in Appendix F.
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BUDGET-ENG: Allocation of Recip. Engine Costs for Economic Benefits
Allocation of Recip. Engine Costs for Economic Benefits (continued)
For evaluating the state and local economic benefits of reciprocating engine projects, the multipliers were
assigned as follows:
Construction Phase
Gas clean-up skid installation materials consist of electrical connections to connect the skid to a source of
energy to power the compressor system. These are assigned to the Electrical Equipment and Appliance
Manufacturing multiplier.
Local labor is assigned to the Households multiplier.
Distributor fees are assigned to the Wholesale Trade multiplier.
Operation and Maintenance Phase
Distributor fees are assigned to the Wholesale Trade multiplier.
Local labor is assigned to the Households multiplier.
This worksheet also estimates the number of state-wide direct jobs created from the design and installation
(cell Fll), or operation (cell F34) of an LFG energy project. The number of jobs, in terms of full-time
equivalents (FTE), is estimated using loaded earnings most typical for staff used directly in LFG energy
projects. State-wide labor rates ranged from $80 to $150 per hour, depending on whether the labor was for
engineers, site operators, or equipment installation. This analysis assumes 1,850 billable hours per year,
equating to 1 job per $148,000 to $277,500 of loaded earnings in 2016$. Labor rates were escalated using the
general inflation rate supplied in cell D44 of the INP-OUT sheet.
a The economic and job benefits for reciprocating engine projects are limited to the energy recovery
portion of the project and exclude the economic and job benefits associated with the construction and
operation of a gas collection system.
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BUDGET-DIR: Allocation of Direct-Use Project Costs for Economic Benefits3
Similar to the BUDGET-ENG worksheet, this worksheet assigns the typical components of a direct-use project
(excluding costs of gas collection and control system infrastructure) from the DIR worksheet to one of six
categories: state/local labor, labor from outside the state, state/locally manufactured materials, materials
manufactured outside the state, state/local distributor fees, or fees paid to distributors outside of the state. The
list below shows how the direct-use project costs were assigned to these six categories.
Construction Phase (one-time costs)
Gas cleanup/compression unit costs
75% skid unit capital cost
69% nationally manufactured materials
6% national distributor fee
25% installation cost
8% state-wide manufactured materials
8% national engineering and management labor ($150/hr)
9% state-wide installation labor ($85/hr)
Pipeline costs
25% pipeline capital cost
21% national manufactured materials
4% state-wide distributor fee for materials
75% installation cost
7% state-wide manufactured materials
11% national engineering and management labor
57% state-wide installation labor ($87/hr)
Annual Operating Costs
Materials and Labor
5% national proprietary manufactured materials (skid components)
45% common O&M materials (oil filters, lubricants, wiring)
34% national manufactured materials
11% state-wide distributor fee
50% state-wide labor (tuning wellfields and O&M of project equipment, $80/hr)
Utilities (electricity to operate compression skid)
100% purchased state-wide electricity
This worksheet then assigns labor and purchased materials to the Bureau of Economic Analysis 2015 RIMS
II multipliers that are most representative of the materials used in an LFG energy project. A complete list of
multipliers is shown in Appendix F.
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BUDGET-DIR: Allocation of Direct-Use Project Costs for Economic Benefits3
Allocation of Direct-Use Project Costs for Economic Benefits (continued)
For evaluating the state and local economic benefits of direct-use projects, the multipliers were assigned as
follows:
Construction Phase
Gas clean-up skid installation materials consist of electrical connections to connect the skid to a source of
energy to power the compressor system. These are assigned to the Electrical Equipment and Appliance
Manufacturing multiplier.
Distributor fees are assigned to the Wholesale Trade multiplier.
Local labor is assigned to the Households multiplier.
Pipeline installation materials include soil aggregate materials needed to properly line and re-surface the
trench. These are assigned to the Other Nonmetallic Mineral Mining and Quarrying multiplier.
Operation and Maintenance Phase
Distributor fees are assigned to the Wholesale Trade multiplier.
Local labor is assigned to the Households multiplier.
Electricity purchased is assigned to the Electric Power Generation, Transmission, and Distribution multiplier.
This worksheet also estimates the number of state-wide direct jobs created from the design and installation
(cell F16), or operation (cell F31) of an LFG energy project. The number of jobs, in terms of FTE, is estimated
using loaded earnings most typical for staff used directly in LFG energy projects. State-wide labor rates ranged
from $80 to $87 per hour, depending on whether the labor was for engineers, site operators, or equipment
installation. This analysis assumes 1,850 billable hours per year, equating to 1 job per $148,000 to $160,950
of loaded earnings in 2016$. Labor rates were escalated using the general inflation rate supplied in cell D44
of the INP-OUT sheet.
a The economic and job benefits for direct-use projects are limited to the energy recovery portion of the
project and exclude the economic and job benefits associated with the construction and operation of a gas
collection system.
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ECON-BEN SUMMARY: Economic Benefits and Job Creation Summary3
This worksheet summarizes the jobs, earnings, and expenditures that result from a direct-use or reciprocating
engine LFG energy project.
The first set of tables (rows 7-15) summarize the total economic benefits resulting from a direct-use or
reciprocating engine project (depending upon which type of project the user is evaluating), excluding any
benefits from the construction and operation of the gas collection and control system infrastructure). The left
table presents benefits during the project construction phase (a one-time economic benefit), and the right table
presents annual benefits from the operation and maintenance of a project.
Total economic benefits have three components: direct, indirect, and induced.
• Direct effects result from onsite jobs and new purchases from state and local businesses that are required
to build and operate the project.
• Indirect effects occur as those state and local businesses spend their new revenue on supplies or to pay
their employees.
• Induced effects result when employees spend their paychecks and, for larger projects, when people
migrate to the area.
Each layer of spending generates new income to firms and families in the region and to the overall national
economy. The first set of tables show the benefits for a specific state in which the project was constructed, if
the user selected a state on the BUDGET-DIR or BUDGET-ENG sheet. It also shows the benefits for states
representing a low, median, and high range of output and job creation.
The second set of tables (rows 20-30) provide a detailed summary of the relative contributions of direct
economic benefits compared to economic "ripple effects" benefits.
Estimates are based on Bureau of Economic Analysis (BEA) 2015 RIMS II multipliers that are most
representative of the materials used in an LFG energy project. BEA does not endorse any resulting estimates
and/or conclusions about the economic impact of a proposed change on an area.
a The economic and job benefits for direct-use and reciprocating engine projects are limited to the energy
recovery portion of the project and exclude the economic and job benefits associated with the
construction and operation of a gas collection system.
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Appendix A:
Default Value Documentation
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Appendix A: Default Value Documentation
The loan lifetime is assumed to begin during the year of project design and construction. It is
common for project loan periods to be limited to half or two-thirds of the equipment lifetime to
assure that the loan is repaid before the project ends. Since much of the equipment used in LFG
energy projects has a projected lifetime of 15 years, the default loan lifetime is set to 10 years.
See Table D-l of Appendix D (Evaluating Local Government-Owned Projects) for recommended
default assumptions for municipalities using budgeted funds or public bonds to finance projects.
Interest rates fluctuate with economic conditions and many unforeseen factors, making them very
difficult to forecast. The default interest rate is based on the 5-year average value of the Moody
Corporate AAA and BAA bond rates published by the Federal Reserve. The 5-year average rate
of 5.6% for 2008-2012 is rounded to 6% for the default rate.
For projects owned by municipalities, the recommended interest rate is based on the 5-year average
value of the State & Local Bond Rates published by the Federal Reserve. The 5-year average rate
of 4.4% for 2008-2012 is rounded to 5% for the recommended rate shown in Table D-l of
Appendix D (Evaluating Local Government-Owned Projects).
Users can obtain up-to-date interest rates from the Federal Reserve at
https://www.federalreserve.gov/releases/hl5/.
The general inflation rate fluctuates with economic conditions and many unforeseen factors,
making it very difficult to forecast. The default inflation rate is based on the 5-year average annual
increase in the Consumer Price Index (CPI). The 5-year average annual CPI rate increase of 2.1%
for 2008-2012 is rounded to 2.5% for the default rate. Users can obtain up-to-date CPI rates from
the U.S. Department of Labor at https://www.bls.gov/cpi/.
The Chemical Engineering (CE) Plant Cost Index was used to determine the default equipment
inflation rate. The average annual cost increase for the 5-year period of 2008-2012 was 2.4%. This
rate was rounded to 2% for the LFGcost-Web default equipment inflation rate. Users can obtain
up-to-date CE plant cost indices from the Chemical Engineering magazine published by Chemical
Week Publishing, LLC at http://www.chemengonline.com/.
The default parameters for corporate tax rate, discount rate, and down-payment of 35%, 8%, and
20%, respectively, are based on recent LFG energy project experience with commercial projects.
Corporate discount rates are commonly 2% to 3% higher than interest rates and 7% to 8% higher
than inflation rates.
Projects owned by municipalities will generally experience different values for these parameters.
Municipal tax rates are generally zero percent and municipalities may use a discount rate of zero
percent for municipal projects. Municipalities tend to fund a project from municipal revenue,
resulting in a down payment of 100%. See Table D-l of Appendix D (Evaluating Local
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Government-Owned Projects) for recommended default assumptions for municipalities using
budgeted funds or public bonds to finance projects.
LMOP reviewed the EIA Annual Energy Outlook 2019, which forecasted a 2019-2020 average
Henry Hub natural gas price of $3.06 per million Btu. The current natural gas price is depressed
as a result of abundant domestic supply and efficient methods of production. Based on Smith
Gardner's experience with LFG energy contracts, LFG pricing can be discounted between 15 and
30 percent, or more, from the Henry Hub natural gas delivery price (or other appropriate index
based on the location of the project), with a defined price floor and ceiling. The default value for
LFG is estimated to be $2.14 per million Btu. Users can obtain current Annual Energy Outlook
prices at https://www.eia.gov/outlooks/aeo/data/browser/.
The Annual Energy Outlook 2019 forecasted electricity generation prices to be 6.2 cents per kWh
in 2019. This default price represents the base electricity price, excluding any incentives. A list of
regional generation prices from Annual Energy Outlook 2019 by electricity market module, is
available in the REGIONAL PRICING worksheet. The forecasted regional prices for 2019 range
from 3.1 to 9.0 cents per kWh, should users want to select a regional generation price instead of
the national average default value. Users may also have more precise pricing estimates from their
local grid operators.
The average market price for hot water/steam sold by LFG energy CHP projects is estimated to be
$3.83 per million Btu. This price is estimated from the $3.06 per million Btu natural gas price
divided by a boiler efficiency of 80%.
LMOP based the high Btu gas price on the Annual Energy Outlook 2019. As stated above, the
report forecasts a 2019-2020 average natural gas price of $3.06 per million Btu. Based on Smith
Gardner's experience with LFG energy contracts, LFG pricing of high Btu is typically pegged to
70-85% of natural gas prices. The default value is set at a value of $2.14 per million Btu for
compressed and conditioned LFG. If you would like to incorporate fuel credits from the EPA
Renewable Fuel Standard or the California Low Carbon Fuel Standard, those credits can be added
to the high Btu production price.
According to the U.S. DOE Alternative Fuels Data Center, the average CNG price between 2012
and 2018 was $2.12 per gasoline gallon equivalent (GGE). LFGcost-Web uses a default price of
$2.10 per GGE, which represents the base CNG purchase price, excluding any incentives. Users
can obtain up-to-date CNG prices from U.S. DOE at
http: //www, afdc. energy. gov/fuel s/pri ces. html.
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El^imMPMFsMase^Prims
The default price paid by landfills for electricity, when they do not produce their own electricity,
is assumed to be 8.9 cents per kWh. The 2019 average national electricity price paid by industrial
and commercial consumers as forecasted in the Annual Energy Outlook 2019, is 7.1 and 10.7 cents
per kWh, respectively. The average of these two prices is 8.9 cents per kWh. A list of average
regional purchase prices, by electricity market module, is available in the REGIONAL PRICING
worksheet should users want to select a regional purchase price instead of the national average
default value. Users may also have more precise pricing estimates from their current electricity
bills.
In the Annual Energy Outlook 2019, EIA predicted prices for electricity generation will decrease
by 2.9% in years 2019-2022. The average escalation rate of real energy prices for electricity
products sold by landfills was assumed to be -2.9%.
For direct-use, boiler retrofit and high Btu projects, EIA predicted that commercial natural gas
prices will rise by an average rate of 1.3% in years 2019-2022, which was used as the basis for the
escalation rate for these project types.
EIA predicted that natural gas for transportation prices will decrease by 2.0% in years 2019-2022,
which was used as the basis for a -2.0% escalation rate for CNG product prices.
For electricity purchased by landfills, the EIA predicted commercial electricity prices will
decrease by 1.2% and industrial electricity prices will decrease by 1.8% in years 2019-2022. The
average decrease of these products is -1.5%, which was used as the basis for the escalation rate
for purchased electricity.
In the Annual Energy Outlook 2019, EIA noted that the combination of declining natural gas
prices and increasing volume of renewable electricity has resulted in lower wholesale electricity
prices.1 EIA predicted that electricity generation costs will decline due to recovery of investment
costs and fuel and operating costs and average electricity prices will fall at least through 2022.2
EIA projections show that during the 15-year period from 2018 through 2033, electricity prices
are relatively flat with some years showing a negative rate of change compared to the preceding
year while others show a slightly positive rate of change.3
EIA predicted in the Annual Energy Outlook 2019 that natural gas will experience a large
increase in production over the projection period, which will support an increasing consumption
by the industrial and electric power sectors.4 EIA projections show that during the 15-year period
1 U.S. Energy Information Administration. Annual Energy Outlook 2019. January 24, 2019. Page 22.
https://www.eia.gov/outlooks/aeo/pdf/aeo2019.pdf.
2 U.S. Energy Information Administration. Annual Energy Outlook 2019. January 24, 2019. Page 98.
https://www.eia. gov/outlooks/aeo/pdf/aeo2019.pdf.
3 U.S. Energy Information Administration. Annual Energy Outlook 2019. Electric Power Projections by Electricity
Market Module Region. Accessed April 11, 2019. https://www.eia. gov/outlooks/aeo/data/browser/#/?id=62-
AE02019®ion=3-0&cases=ref2019&start=2017&end=2050&f=A&linechart=ref2019-dlll618a.5-62-
AEQ2019.3 -0&sourcekev=0.
4 U.S. Energy Information Administration. Annual Energy Outlook 2019. January 24, 2019. Page 69.
https://www.eia.gov/outlooks/aeo/pdf/aeo2019.pdf.
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from 2018 through 2033, natural gas delivery prices for gas used in the transportation sector will
decline.5
5 U.S. Energy Information Administration. Annual Energy Outlook 2019. Natural Gas Supply, Disposition, and
Prices. Accessed May 9, 2019. https://www.eia.gov/outlooks/aeo/data/browser/#/?id=13-
AEQ2019&cases=rel2019&sourcekev=0.
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Appendix B:
Common Abbreviations
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Appendix B:
AP-42
AEO
Btu
CE
CHP
CNG
C02
CPI
EIA
EPA
ft
ft3
gal
GHG
GWP
HDPE
HHV
hr
IRR
k
kW
kWh
L0
lb
LFG
LMOP
MHz
mi
min
MTCO2E
MMTCO2E
Common Abbreviations
EPA's Compilation of Air Pollutant Emission Factors
Annual Energy Outlook
British thermal units
Chemical Engineering
combined heat and power
compressed natural gas
carbon dioxide
Consumer Price Index
U.S. Energy Information Administration
U.S. Environmental Protection Agency
feet
cubic foot / cubic feet
gallon
greenhouse gas
global warming potential
high density polyethylene
higher heating value
hour
internal rate of return
methane generation rate constant
kilowatt
kilowatt-hour
potential methane generation capacity of waste
pound
landfill gas
Landfill Methane Outreach Program
megahertz
mile
minute
metric tons of carbon dioxide equivalents
million metric tons of carbon dioxide equivalents
Version 3.3
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MSW municipal solid waste
MT metric ton
MW megawatt
NPV net present value
NSPS/EG New Source Performance Standards/Emission Guidelines for MSW
Landfills
O&M operation and maintenance
PV present value
TRCs tradable renewable certificates
yr year
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Appendix C:
Evaluating Projects with
Multiple Equipment and/or Start Dates
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Appendix C: Evaluating Projects with Multiple Equipment and/or Start
Dates
LFG energy projects with multiple equipment and/or start dates can also be evaluated using
LFGcost-Web. These complex LFG energy projects may include: dual projects (i.e., combining
an engine with a direct-use project), staggered projects (e.g., installing an engine early in the life
of the landfill and adding additional engines as the gas volume increases), and back-to-back
projects (e.g., replacing an engine at the end of its 15-year life with a new engine). The general
approach to evaluating these types of complex LFG energy projects is to evaluate each project
component individually. If each project component, such as one engine, has a positive NPV then
the overall project will also have a positive NPV. The following discussion addresses how to set
up the individual component evaluations in LFGcost-Web and how to interpret the results
produced by LFGcost-Web.
Required User Inputs - When entering landfill information into the Required User Inputs table,
enter the standard landfill information that applies to the entire landfill. For the project information
inputs (e.g., LFG energy project type, Year LFG energy project begins operation), enter the
information that applies only to the specific project component that is being evaluated. For
example, staggered and back-to-back project components will each have a different project start
year. Model users should generally decline the required input to "include collection and flaring
costs" in the evaluation. If users want to include the collection and flaring costs, this option should
be selected only for the first project component to be installed. The evaluations of all subsequent
components should decline to include the collection and flaring costs.
Optional User Inputs - All inputs in this section should be specific to the project component being
evaluated. When entering the LFG energy project size, users must select the user-defined option,
"Defined by user". On the next line, users must enter the Design flow rate for the project
component being evaluated. The optional input data relating to the landfill itself (e.g., Average
depth of landfill waste and Landfill gas collection efficiency) should apply to the overall landfill,
and therefore should remain the same for each project component. All other information entered
in this data input section should apply only to the project component being evaluated.
Outputs - After completing the required and optional user inputs, the economic evaluation of the
project component appears in the Outputs table. The output values Total lifetime amount of
methane collected and destroyed and Average annual amount of methane collected and destroyed
apply to the entire landfill. All other output values, such as GHG value of total lifetime amount of
methane utilized in energy project or Internal rate of return, apply only to the project component
being evaluated. It is important to note that Total installed capital cost for year of construction and
Net present value at year of construction are presented in terms of the construction year's actual
dollars, and Annual costs for initial year of operation are presented in terms of actual dollars for
the year the LFG energy project begins operation. Therefore, the NPV of multiple project
components will be in terms of different years' dollars and cannot be summed to obtain an accurate
total project NPV.
Checking the integrity of the complex project component evaluation - After an LFGcost-Web
evaluation has been conducted for each project component, a check must be made to ensure that
the net capacity for the project components does not exceed the capacity of the landfill. This
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integrity check can be conducted easily using LFGcost-Web's graphical output in the CURVE
worksheet. Model users should compile the graphs generated by LFGcost-Web for each
component to confirm that the net gas use in any given year does not exceed the gas output of the
landfill. Figure C-l illustrates how graphs from three LFG energy project components can be
manually compiled by users to confirm that the components do not exceed the LFG generation
capacity. Figures C-1A, C-1B, and C-1C are the curves generated by LFGcost-Web for each
individual project component - A, B, and C, respectively - compiled in Figure C-l. In this
example, the size of project components B and/or C might be increased by as much as 50 percent
and not exceed the gas generation potential of the landfill.
450 i
| 400
%
jf 350
a
on
| 300
U-
tn
$ 250
1 200
cs
-i
§ 150
c
c
O 100
o>
n
| 50
<
0
2000 2005 2010 2015 2020 2025 2030 2035 2040 2045
Year
Figure C-l. Example of a project with multiple equipment and start dates
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Landfill Gas Generation, Collection, and Utilization Curve
o
IS
cc
&
o
300
250
ns
O
0 -I i i i i i i i i i i i i i i i i i i i i i i i
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031
Year
T3
£
ro
200
150
100
50
Gas Generation Gas Collection Gas Utilization
Figure C-1A. Example of an LFG generation, collection, and utilization curve for
project component A
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Landfill Gas Generation, Collection, and Utilization Curve
450
ro
150
<
ra 100
>
<
50
(2 300
250
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036
Year
-Gas Generation Gas Collection Gas Utilization
Figure C-1B. Example of an LFG generation, collection, and utilization curve for
project component B
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Landfill Gas Generation, Collection, and Utilization Curve
450
g 150
C
<
ra 100
50
K 300
w 250
ns
(!)
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036
Year
¦ Gas Generation ¦
¦ Gas Collection Gas Utilization
Figure C-1C. Example of an LFG generation, collection, and utilization curve for
project component C
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Appendix D:
Evaluating Local Government-Owned Projects
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Appendix D: Evaluating Local Government-Owned Projects
Projects owned by local governments and other public entities should be evaluated under a
different set of economic assumptions than the default values recommended in the LFGcost-Web
model. These entities are normally exempt from taxes, are subject to lower discount rates, and use
different approaches than private corporations to finance projects. They may finance smaller
projects directly from budgeted funds, and choose to fund larger projects through the use of
low-interest public bonds. Table D-l presents default assumptions for use with two types of local
government-owned projects.
Table D-l. Recommended Default Assumptions for Local Government-Owned
Projects
Parameter
Budget Financed
Bond Financed
Loan lifetime (yrs)
0
10-15 [varies by project
lifetime]
Interest rate (%)
0
5
Marginal tax rate (%)
0
0
Discount rate (%)
5
5
Down payment (%)
100
0
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Appendix E:
Evaluating Boiler Retrofit Projects
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Appendix E: Evaluating Boiler Retrofit Projects
For boiler retrofit projects, there is a required input for users to indicate whether the boiler retrofit
costs will be standalone (i.e., evaluated from the perspective of the end user) or combined with
direct-use project costs (i.e., evaluated from the perspective of a developer that is responsible for
all costs). The outputs of the economic analysis will vary depending on which perspective is used
to evaluate the boiler retrofit costs. Specifically, IRR, NPV, and Years to breakeven will vary
based on the appropriate prices (in $/million Btu) entered for the LFG product price and royalty
payment in the Optional User Inputs table. The following discussion addresses how to set up
boiler retrofit scenarios in LFGcost-Web and how to interpret the results produced by LFGcost-
Web.
Boiler retrofit costs kept separate from direct-use project costs - For evaluating the cost of only
the boiler retrofit from the perspective of the end user, the following optional inputs are used:
~ Initial year product price: landfill gas production ($/million Btu) should be set to the price
that the end user is currently paying for natural gas.
~ Royalty payment for landfill gas utilization ($/million Btu) should be set to the price that
the end user will pay the pipeline owner for delivery of LFG to the end user's property
boundary.
~ Economic parameters such as loan lifetime, Interest rate, Discount rate, Marginal tax rate,
and Down payment should be the parameters used by the end user.
The difference between the royalty payment and the LFG production price is the revenue used to
justify the cost of the boiler retrofit. All economic outputs for this scenario such as IRR, NPV, and
Years to breakeven are for the end user paying for the boiler retrofit, not the developer of the
overall project.
Boiler retrofit costs combined with direct-use project costs - For evaluating projects from the
perspective of a developer that will pay for LFG treatment (skid-mounted filter, compressor and
dehydration unit), pipeline delivery from the landfill to the end user's boiler, and conversion of
the boiler, the following optional inputs are used:
~ Initial year product price: landfill gas production ($/million Btu) should be set to the price
that the developer will sell LFG to the end user.
~ Royalty payment for landfill gas utilization ($/million Btu) should be set to the price that
the developer will pay the landfill owner for raw LFG.
~ Economic parameters such as loan lifetime, Interest rate, Discount rate, Marginal tax rate,
and Down payment should be the parameters applying to the developer.
The difference between the royalty payment and the LFG production price is the revenue used to
justify the cost of LFG treatment, the pipeline, and the boiler retrofit. All economic outputs for this
scenario such as IRR, NPV, and Years to breakeven are for the developer paying for the overall
project.
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Appendix F:
Economic Multipliers for
Economic Benefits and Job Creation Analysis
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Appendix F: Economic Multipliers for Economic Benefits and Job Creation Analysis
Series: 2007 U.S. Benchmark l-O data and 2015 Regional Data (Type II Multipliers: Direct + Indirect + Induced)
Private Households (H00000)
Wholesale Trade (420000)
Other Nonmetallic Mineral Mining and
Quarrying (2123A0)
Electrical Equipment and Appliance
Manufacturing (14)
Electric Power Generation, Trans, and
Dist (2211AO)
State
All-industry
(total) final-
demand
multiplier for
output
All-industry
(total) final-
demand
multiplier for
earnings
All-industry
(total) final-
demand
multiplier for
employment
All-industry
(total) final-
demand
multiplier for
output
All-industry
(total) final-
demand
multiplier for
earnings
All-industry
(total) final-
demand
multiplier for
employment
All-industry
(total) final-
demand
multiplier for
output
All-industry
(total) final-
demand
multiplier for
earnings
All-industry
(total) final-
demand
multiplier for
employment
All-industry
(total) final-
demand
multiplier for
output
All-industry
(total) final-
demand
multiplier for
earnings
All-industry
(total) final-
demand
multiplier for
employment
All-industry
(total) final-
demand
multiplier for
output
All-industry
(total) final-
demand
multiplier for
earnings
All-industry
(total) final-
demand
multiplier for
employment
Alabama
1.0523
0.3209
9.9670
1.7127
0.5346
11.6968
1.6966
0.3789
9.6015
2.0130
0.4142
9.0147
1.5976
0.3235
5.9901
Alaska
0.8729
0.2718
7.3322
1.5563
0.4926
9.7084
1.5663
0.3364
8.8989
1.3507
0.3131
7.8019
1.5956
0.3158
4.8566
Arizona
1.2503
0.3839
11.0384
1.8764
0.5926
11.9208
1.6619
0.3808
7.9999
1.7224
0.3954
8.5006
1.5995
0.3375
6.1136
Arkansas
0.9316
0.2833
8.4485
1.6698
0.5185
10.5705
1.6485
0.3460
9.4530
1.8665
0.3820
8.2126
1.5450
0.3030
5.3909
California
1.2679
0.3793
9.2432
1.9501
0.6145
11.1177
1.7855
0.4122
8.3625
1.8539
0.4302
7.8921
1.7084
0.3610
5.5764
Colorado
1.3269
0.4010
11.3772
1.9879
0.6280
12.1805
1.8374
0.4284
11.0776
1.8084
0.4258
9.3285
1.7995
0.3841
6.7171
Connecticut
1.0128
0.2957
7.0289
1.7663
0.5221
8.5863
1.5930
0.3488
6.3261
1.9030
0.4122
7.0689
1.4687
0.2858
4.0620
Delaware
0.9517
0.2423
7.0369
1.5539
0.3501
6.3544
1.5554
0.2926
8.0064
1.4277
0.2047
3.6867
1.4811
0.2477
3.7838
Florida
1.2471
0.3848
11.6885
1.9027
0.6055
12.7751
1.6570
0.3866
10.9222
1.6750
0.3878
8.9019
1.5789
0.3372
6.1363
Georgia
1.3617
0.4044
12.0582
2.0459
0.6370
12.9025
1.8002
0.4196
8.0738
1.9015
0.4220
8.7772
1.6276
0.3431
6.4976
Hawaii
1.1013
0.3340
9.2139
1.7084
0.5410
11.0638
1.6023
0.3595
6.3640
1.4400
0.3258
8.4877
1.5084
0.3052
5.0793
Idaho
0.9228
0.2869
9.1736
1.6071
0.5076
11.0496
1.5166
0.3262
6.2051
1.5355
0.3451
8.0277
1.4289
0.2849
5.2152
Illinois
1.3969
0.4047
9.7476
2.0534
0.6240
10.8411
1.9247
0.4350
7.3904
2.2041
0.5011
8.9761
1.7689
0.3649
5.6971
Indiana
1.1900
0.3480
9.5987
1.8145
0.5537
11.0980
1.7340
0.3698
8.1243
2.0861
0.4516
9.3564
1.6088
0.3154
5.3946
Iowa
0.9425
0.2841
8.7365
1.6536
0.5065
10.5615
1.5527
0.3282
7.6453
1.7756
0.3518
7.7513
1.4042
0.2611
4.6478
Kansas
1.0553
0.2944
8.7230
1.7449
0.4872
9.7356
1.7652
0.3723
8.5653
1.6733
0.3330
7.0730
1.6292
0.3084
5.4696
Kentucky
1.0921
0.3124
9.2190
1.7434
0.5081
10.7850
1.6931
0.3566
8.4510
2.0526
0.3907
7.7585
1.6097
0.3058
5.5916
Louisiana
1.0267
0.3213
9.4337
1.7029
0.5414
10.9279
1.7254
0.3796
10.1124
1.6762
0.3704
7.7156
1.7142
0.3544
6.1201
Maine
1.0112
0.3232
9.6895
1.6980
0.5427
11.6237
1.5230
0.3460
9.8654
1.5884
0.3581
7.7166
1.4399
0.2930
5.3416
Maryland
1.1249
0.3200
8.1770
1.7756
0.5178
9.2682
1.5764
0.3290
6.6562
1.5163
0.2959
5.7477
1.4865
0.2843
4.3578
Massachusetts
1.0908
0.3180
8.0023
1.7898
0.5242
8.9932
1.6170
0.3562
8.1807
1.8766
0.3972
6.9556
1.4891
0.2904
4.3484
Michigan
1.1245
0.3481
9.8401
1.8338
0.5841
11.0903
1.7142
0.3954
8.5929
2.1028
0.4895
9.5448
1.5285
0.3144
5.3456
Minnesota
1.2991
0.3788
9.9779
1.9497
0.5963
10.8106
1.8168
0.4121
7.3091
1.9443
0.4399
8.4529
1.6493
0.3346
5.5533
Mississippi
0.9718
0.2917
9.2014
1.6301
0.4989
10.8131
1.6461
0.3492
9.8093
1.7802
0.3650
8.3174
1.6036
0.3148
5.7761
Missouri
1.2367
0.3469
9.9658
1.8713
0.5359
10.3826
1.7156
0.3719
7.7675
1.8544
0.3840
7.9986
1.5883
0.3012
5.3718
Montana
0.8892
0.2832
9.0676
1.5745
0.5044
10.9021
1.6069
0.3326
6.8701
1.4556
0.3313
8.3590
1.6237
0.3241
5.8798
Nebraska
0.9537
0.2935
8.7039
1.7057
0.5260
9.7534
1.6068
0.3607
8.6938
1.6931
0.3734
7.6421
1.4564
0.2814
4.7125
Nevada
1.0196
0.3103
9.2978
1.7467
0.5464
11.3320
1.5810
0.3587
7.7111
1.5965
0.3597
7.2807
1.4641
0.2947
5.0389
New Hampshire
1.0161
0.2971
8.0200
1.7098
0.5062
9.0064
1.5481
0.3243
8.7053
1.9766
0.3869
7.2476
1.3999
0.2540
4.0810
New Jersey
1.2716
0.3551
8.6850
1.9272
0.5448
9.4077
1.7669
0.3894
6.4943
1.9114
0.4013
7.2666
1.6247
0.3149
4.8148
New Mexico
0.9343
0.2915
9.2762
1.5731
0.5002
10.7935
1.5859
0.3351
6.5637
1.5107
0.3256
7.7432
1.6278
0.3207
5.8447
New York
1.0597
0.2880
7.0031
1.7673
0.4977
8.2350
1.5965
0.3356
7.2278
1.7163
0.3730
6.9033
1.4832
0.2728
3.9316
North Carolina
1.2263
0.3696
10.6553
1.8938
0.5890
11.9571
1.6826
0.3845
10.5467
2.0398
0.4510
9.1324
1.5329
0.3112
5.5570
North Dakota
0.8711
0.2503
6.9708
1.5473
0.4426
8.0335
1.6223
0.3375
6.2884
1.4586
0.2731
6.3994
1.6333
0.3066
4.8888
Estimates are based on Bureau of Economic Analysis (BEA) 2015 RIMS II multipliers most representative of the materials used in an LFG energy project.
F-l
-------
Appendix F: Economic Multipliers for Economic Benefits and Job Creation Analysis
Series: 2007 U.S. Benchmark l-O data and 2015 Regional Data (Type II Multipliers: Direct + Indirect + Induced)
Private Households (H00000)
Wholesale Trade (420000)
Other Nonmetallic Mineral Mining and
Quarrying (2123A0)
Electrical Equipment and Appliance
Manufacturing (14)
Electric Power Generation, Trans, and
Dist (2211AO)
State
All-industry
(total) final-
demand
multiplier for
output
All-industry
(total) final-
demand
multiplier for
earnings
All-industry
(total) final-
demand
multiplier for
employment
All-industry
(total) final-
demand
multiplier for
output
All-industry
(total) final-
demand
multiplier for
earnings
All-industry
(total) final-
demand
multiplier for
employment
All-industry
(total) final-
demand
multiplier for
output
All-industry
(total) final-
demand
multiplier for
earnings
All-industry
(total) final-
demand
multiplier for
employment
All-industry
(total) final-
demand
multiplier for
output
All-industry
(total) final-
demand
multiplier for
earnings
All-industry
(total) final-
demand
multiplier for
employment
All-industry
(total) final-
demand
multiplier for
output
All-industry
(total) final-
demand
multiplier for
earnings
All-industry
(total) final-
demand
multiplier for
employment
Ohio
1.2835
0.3801
10.8732
1.9300
0.5918
11.7997
1.8345
0.4085
7.5637
2.2241
0.5073
10.2329
1.6733
0.3363
5.9293
Oklahoma
1.0951
0.3399
9.7666
1.7713
0.5631
11.6947
1.7816
0.4029
7.4146
1.7591
0.3840
8.4899
1.7384
0.3646
6.5046
Oregon
1.0665
0.3192
9.3372
1.7624
0.5270
10.5945
1.6221
0.3601
9.9131
1.7624
0.3914
8.1283
1.4912
0.2851
5.0145
Pennsylvania
1.2647
0.3683
9.5415
1.9153
0.5767
10.4790
1.8588
0.4021
10.0823
2.1513
0.4810
9.1573
1.7486
0.3527
5.7101
Rhode Island
0.9951
0.2771
7.8205
1.6494
0.4486
8.1565
1.5408
0.3297
9.0998
1.7564
0.3307
6.3690
1.3920
0.2340
3.9608
South Carolina
1.1809
0.3514
10.7596
1.8111
0.5571
12.1800
1.6825
0.3787
9.4989
2.0263
0.4330
9.2463
1.5252
0.2962
5.6460
South Dakota
0.9028
0.2810
8.1950
1.6049
0.4962
9.9582
1.5185
0.3334
8.4671
1.5351
0.3658
8.3472
1.4041
0.2745
4.6715
Tennessee
1.3458
0.3922
10.3680
1.9524
0.5863
11.5365
1.7824
0.3940
7.2320
2.1366
0.4531
9.5979
1.6130
0.3247
5.7601
Texas
1.4694
0.4362
11.0390
2.0653
0.6440
11.7439
2.0019
0.4618
8.5233
2.1845
0.4995
9.4016
1.9465
0.4194
6.9859
Utah
1.2833
0.3866
11.6697
1.9442
0.6132
13.1901
1.8441
0.4248
11.6895
1.8857
0.4259
9.1813
1.8033
0.3822
7.1230
Vermont
0.8899
0.2724
8.3345
1.5653
0.4783
10.1044
1.4571
0.3142
7.7929
1.6337
0.3291
7.1627
1.3487
0.2344
3.9297
Virginia
1.1303
0.3221
9.0301
1.8319
0.5462
10.1523
1.6252
0.3488
6.8456
1.6778
0.3634
7.3300
1.5794
0.3097
5.1114
Washington
1.1458
0.3428
8.9012
1.7960
0.5611
10.2657
1.6817
0.3761
6.4480
1.7617
0.4462
8.7868
1.5748
0.3187
5.2431
West Virginia
0.8417
0.2466
7.7712
1.5316
0.4568
9.6199
1.5789
0.3162
6.3670
1.6786
0.3114
6.5970
1.5745
0.2843
4.9316
Wisconsin
1.0595
0.3306
9.3866
1.7612
0.5536
11.1330
1.6372
0.3690
8.0456
1.9254
0.4566
8.9204
1.4835
0.3000
5.0816
Wyoming
0.7094
0.2212
6.7786
1.4485
0.4558
8.0092
1.5190
0.3161
5.4617
1.4049
0.2796
5.6211
1.5437
0.2940
4.8020
High
Indiana
Median
Oregon
Low
Iowa
Disclaimer: BEA does not endorse any resulting estimates and/or conclusions about the economic impact of a proposed change on an
area.
Estimates are based on Bureau of Economic Analysis (BEA) 2015 RIMS II multipliers most representative of the materials used in an LFG energy project.
F-2
-------
LFGcost-Web User's Manual
Version 3.3
Appendix G:
Ranking Analysis for
Economic Multipliers
-------
Appendix G: Ranking Analysis for Economic Multipliers
Output Ranking Table
Other
Electric Power
Nonmetallic
Electrical
Generation,
Private
Mineral Mining
Equipment and
Transmission,
Households
Wholesale
and Quarrying
Appliance
and Distribution
Overall
State
(H00000)
Trade (420000)
(2123A0)
Manufacturing (14)
(2211 AO)
Average
Std Dev
Range
Rank
Texas
1.4
0.8944272
2
1
Illinois
2
2
2
2
4
2.4
0.8944272
2
2
Ohio
7
9
6
1
9
6.4
3.2863353
8
3
Pennsylvania
11
11
3
4
5
6.8
3.8987177
8
4
Colorado
5
4
5
23
3
8
8.4261498
20
5
Utah
8
8
4
18
2
8
6.164414
16
5
Tennessee
4
5
10
5
17
8.2
5.4497706
13
7
Minnesota
6
7
7
13
10
8.6
2.8809721
7
8
Georgia
3
3
8
17
14
9
6.363961
14
9
California
10
6
9
22
8
11
6.3245553
16
10
New Jersey
9
10
12
15
15
12.2
2.7748874
6
11
Indiana
16
18
14
7
19
14.8
4.7644517
12
12
North Carolina
15
13
20
9
31
17.6
8.4734881
22
13
Missouri
14
15
16
21
24
18
4.3011626
10
14
Oklahoma
23
23
11
28
6
18.2
9.2574294
22
15
Michigan
21
16
17
6
32
18.4
9.396808
26
16
Kentucky
24
30
19
8
18
19.8
8.1363382
22
17
South Carolina
17
19
21
10
33
20
8.3666003
23
18
Arizona
12
14
23
30
21
20
7.2456884
18
18
Florida
13
12
24
36
26
22.2
9.9599197
24
20
Alabama
30
31
18
11
22
22.4
8.3845095
20
21
Washington
18
20
22
27
27
22.8
4.0865633
9
22
Kansas
29
29
13
37
12
24
11
25
23
Virginia
19
17
28
34
25
24.6
6.8774995
17
24
Louisiana
31
35
15
35
7
24.6
12.837445
28
24
Massachusetts
25
21
31
19
36
26.4
7.0569115
17
26
Wisconsin
28
27
27
14
38
26.8
8.5264295
24
27
Oregon
26
26
30
26
35
28.6
3.9749214
9
28
Mississippi
37
40
26
24
20
29.4
8.6486993
20
29
Connecticut
34
25
36
16
41
30.4
9.9146356
25
30
Arkansas
42
37
25
20
29
30.6
8.9050547
22
31
New York
27
24
35
31
39
31.2
6.0166436
15
32
Maryland
20
22
40
43
37
32.4
10.644247
23
33
New Hampshire
33
32
44
12
48
33.8
14.007141
36
34
Hawaii
22
33
34
47
34
34
8.8600226
25
35
New Mexico
41
44
37
44
13
35.8
13.065221
31
36
Nevada
32
28
38
39
42
35.8
5.6745044
14
36
Nebraska
38
34
33
32
43
36
4.5276926
11
38
North Dakota
48
48
29
45
11
36.2
16.146207
37
39
Montana
46
43
32
46
16
36.6
12.876335
30
40
Iowa
40
38
43
25
46
38.4
8.0808415
21
41
Rhode Island
36
39
45
29
49
39.6
7.7974355
20
42
West Virginia
49
49
39
33
28
39.6
9.4233752
21
42
Maine
35
36
46
40
44
40.2
4.8166378
11
44
Alaska
47
46
41
50
23
41.4
10.784248
27
45
Delaware
39
47
42
48
40
43.2
4.0865633
9
46
Idaho
43
41
49
41
45
43.8
3.3466401
8
47
South Dakota
44
42
48
42
47
44.6
2.792848
6
48
Wyoming
50
50
47
49
30
45.2
8.5848704
20
49
Vermont
45
45
50
38
50
45.6
4.929503
12
50
Estimates are based on Bureau of Economic
Analysis (BEA) 2015 RIMS II multipliers most
representative of the materials used in an LFG
energy project
-------
Appendix G: Ranking Analysis for Economic Multipliers
Employment Ranking Table
Other
Electric Power
Nonmetallic
Electrical
Generation,
Private
Mineral Mining
Equipment and
Transmission,
Households
Wholesale
and Quarrying
Appliance
and Distribution
Overall
State
(H00000)
Trade (420000)
(2123A0)
Manufacturing (14)
(2211 AO)
Average
Std Dev
Range
Rank
Utah
3
1
1
8
1
2.8
3.0331502
7
1
Colorado
4
4
2
6
3
3.8
1.4832397
4
2
Florida
2
3
3
14
6
5.6
4.929503
12
3
Texas
5
9
19
4
2
7.8
6.7601775
17
4
South Carolina
8
5
11
7
17
9.6
4.669047
12
5
North Carolina
9
6
4
10
20
9.8
6.1806149
16
6
Georgia
1
2
25
16
5
9.8
10.377861
24
6
Alabama
12
10
10
11
9
10.4
1.1401754
3
8
Ohio
7
8
33
1
10
11.8
12.316655
32
9
Arizona
6
7
28
17
8
13.2
9.3648278
22
10
Tennessee
10
13
37
2
14
15.2
13.065221
35
11
Michigan
14
18
17
3
26
15.6
8.3246622
23
12
Pennsylvania
19
31
6
9
15
16
9.797959
25
13
Oklahoma
15
11
34
18
4
16.4
11.148991
30
14
Indiana
18
17
24
5
23
17.4
7.5696763
19
15
Louisiana
20
21
5
34
7
17.4
11.802542
29
15
Maine
17
12
8
33
27
19.4
10.406729
25
17
Mississippi
28
24
9
23
13
19.4
8.0187281
19
17
Illinois
16
23
35
12
16
20.4
9.0719347
23
19
Wisconsin
21
15
26
13
31
21.2
7.4966659
18
20
California
25
16
22
28
19
22
4.7434165
12
21
Minnesota
11
25
36
20
21
22.6
9.0719347
25
22
Oregon
22
28
7
25
34
23.2
10.084642
27
23
Kentucky
26
27
21
30
18
24.4
4.8270074
12
24
Montana
30
22
39
21
11
24.6
10.502381
28
25
Arkansas
37
29
12
24
24
25.2
9.093954
25
26
Missouri
13
32
30
27
25
25.4
7.436397
19
27
New Mexico
24
26
42
32
12
27.2
11.009087
30
28
Nevada
23
14
31
37
33
27.6
9.154234
23
29
Hawaii
27
19
46
19
32
28.6
11.193748
27
30
Washington
32
33
44
15
28
30.4
10.454664
29
31
Idaho
29
20
49
26
29
30.6
10.922454
29
32
Kansas
34
38
18
41
22
30.6
10.089599
23
32
South Dakota
39
36
20
22
41
31.6
9.8640762
21
34
Nebraska
35
37
16
35
40
32.6
9.5026312
24
35
Alaska
45
39
14
29
37
32.8
11.96662
31
36
Iowa
33
30
32
31
42
33.6
4.8270074
12
37
Virginia
31
34
40
36
30
34.2
4.0249224
10
38
New Hampshire
41
43
15
39
45
36.6
12.280065
30
39
Vermont
38
35
29
40
49
38.2
7.3280284
20
40
New Jersey
36
41
43
38
38
39.2
2.7748874
7
41
Massachusetts
42
44
23
43
44
39.2
9.093954
21
41
Rhode Island
43
47
13
47
47
39.4
14.85934
34
43
West Virginia
44
40
45
45
35
41.8
4.3243497
10
44
Maryland
40
42
41
48
43
42.8
3.1144823
8
45
Delaware
46
50
27
50
50
44.6
9.989995
23
46
New York
48
46
38
44
48
44.8
4.1472883
10
47
North Dakota
49
48
48
46
36
45.4
5.3665631
13
48
Connecticut
47
45
47
42
46
45.4
2.0736441
5
48
Wyoming
50
49
50
49
39
47.4
4.7222876
11
50
Estimates are based on Bureau of Economic
Analysis (BEA) 2015 RIMS II multipliers most
representative of the materials used in an LFG
energy project
-------
Appendix G: Ranking Analysis for Economic Multipliers
High
Indiana
Median
Oregon
Low
Iowa
Notes on Ranking Analysis:
High Multiplier: 25th percentile. Looked for states with an overall rank between 9 and 15 for both
employment and output after averaging the rank of the five regional multipliers. Indiana output rank
= 12, employment rank = 15 (yellow highlight). Oklahoma is the only other state in yellow for this
grouping; however, it is toward the lower end for both output and employement (further from 12-13
ranking than Indiana).
Median: 50th percentile. Looked for states with an overall rank between 23 and 28 for both
employment and output after averaging the rank of the five regional multipliers (blue highlight).
Oregon is the only state in the middle for both output and employment.
Low Multiplier: 75th percentile. Looked for states with an overall rank between 36 and 43 for
both employment and output after averaging the rank of the five regional multipliers (pink
highlight). Iowa is the only state in this grouping for both output and employment.
Disclaimer: BEA does not endorse any resulting estimates and/or conclusions about the economic impact
of a proposed change on an area.
Estimates are based on Bureau of Economic
Analysis (BEA) 2015 RIMS II multipliers most
representative of the materials used in an LFG
energy project
------- |