CLIMATE LEADERS GREENHOUSE GAS INVENTORY PROTOCOL 

OFFSET PROJECT METHODOLOGY 

for 

Project Type: Industrial Boiler Efficiency 

(Industrial Process Applications) 

Climate Protection Partnerships Division/Climate Change Division 

Office of Atmospheric Programs 

U.S. Environmental Protection Agency 

August 2008 

Version 1.3
Climate Leaders August 2008 

Industrial Boiler Efficiency - 2 - 

Table of Contents

Introduction 3

Description of Project Type 3

Regulatory Eligibility 7

Determining Additionality – Applying the Performance Threshold 9

Quantifying Emission Reductions 11

Monitoring 15

Appendix I. Development of the Performance Threshold – Data Set 18

Appendix II. Tables for Estimating and Calculating Emissions 25
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Industrial Boiler Efficiency - 3 - 

Climate Leaders is an EPA industry-government partnership that works with companies to develop 

comprehensive climate change strategies. Partner companies commit to reducing their impact on the global 

environment by setting aggressive greenhouse gas reduction goals and annually reporting their progress to 

EPA.

Introduction 

An important objective of the Climate Leaders program is to focus corporate attention on 

achieving cost-effective greenhouse gas (GHG) reductions within the boundary of the 

organization (i.e., internal projects and reductions). Partners may also use reductions 

and/or removals which occur outside their organizational boundary (i.e., external 

reductions or “offsets”) to help them achieve their goals. To ensure that the GHG emission 

reductions from offsets are credible, Partners must ensure that the reductions meet four 

key accounting principles: 

• Real: The quantified GHG reductions must represent actual emission reductions that 

have already occurred. 

• Additional: The GHG reductions must be surplus to regulation and beyond what 

would have happened in the absence of the project or in a business-as-usual 

scenario based on a performance standard methodology. 

• Permanent: The GHG reductions must be permanent or have guarantees to ensure 

that any losses are replaced in the future. 

• Verifiable: The GHG reductions must result from projects whose performance can 

be readily and accurately quantified, monitored and verified. 

This guidance provides a performance standard (accounting methodology) for greenhouse 

gas (GHG) offset projects that introduce more efficient (i.e., lower GHG emitting) boiler 

technology for industrial process applications.1 The accounting methodology presented in 

this paper addresses the eligibility of industrial boiler efficiency projects as GHG offset 

projects and provides measurement and monitoring guidance. Program design issues (e.g., 

project lifetime, project start date) are not within the scope of this guidance and are 

addressed in the Climate Leaders offset program overview document: Using Offsets to Help 

Climate Leaders Achieve Their GHG Reduction Goals.2

Description of Project Type 

Industrial boiler systems are used for heating with hot water or steam in industrial process 

applications. There are approximately 43,000 industrial boilers in the United States.3 A 

majority of these (71%) are located at facilities in the food, paper, chemicals, refining, and 

 

1

 There is no precise regulatory definition for an industrial boiler. An industrial boiler is typically defined by its common 

function – a boiler that provides heat in the form of hot water or steam for co-located industrial process applications. The 

industrial boiler category does not include utility boilers or commercial boilers as these do not provide the same service 

as industrial boilers and are separately defined in Federal regulations. 

2

 Please visit http://www.epa.gov/climateleaders/resources/optional-module.html to download the overview document. 

3

 Oak Ridge National Laboratory, Characterization of the U.S. Industrial Commercial Boiler Population, May 2005 
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Industrial Boiler Efficiency - 4 - 

primary metals industries. The major source of GHG emissions from a boiler system is 

carbon dioxide (CO2) from the combustion of fossil fuels in the boiler. Other minor sources 

of GHGs can include methane (CH4) from leaks in the natural gas distribution system and 

CH4 and nitrous oxide (N2O) as byproducts of combustion processes. 

This section provides information on the general parameters that the proposed boiler 

project must match to use this performance standard.

Technology/Practice Introduced. This guidance document addresses the improved 

efficiency of industrial boilers used for heat for industrial process applications by adding 

advanced technologies (such as advanced heat recovery, controls and burners) to the 

boiler system. These technology-based efficiency improvements can be achieved when 

retrofitting or replacing an existing boiler with new technology, when purchasing a natural 

gas boiler to meet new demand, and/or when switching from a fuel oil, coal or electricitybased boiler to a natural gas boiler. 

The performance standard is applicable to retrofits of existing industrial boilers using any 

market fuel (e.g., coal, diesel, fuel oil, natural gas, LPG/LNG) and new capacity or early 

replacement boilers using natural gas only. Retrofit projects are defined as those that add 

technological components to an existing boiler unit to improve overall efficiency. Projects 

that involve replacement of the boiler itself are considered new capacity or early 

replacement projects. 

Projects improving the efficiency of an existing, electricity-fired boiler or introducing new 

boilers using coal, diesel, fuel oil or electricity cannot use the same standard. Also 

excluded are boilers fired or co-fired with by-product fuels generated by on-site processes 

(i.e., pulp liquor, wood chips, refinery gas, residual oil, coke oven gas, and blast furnace 

gas) and boilers that are used for electricity generation (i.e., utility boilers) or building 

space and water heating. 

GHG emission reductions can also be achieved through energy efficiency improvements in 

the steam/hot water distribution system, the boiler auxiliaries, or in process efficiency 

improvements. This performance standard is not applicable for projects where these are 

the primary reason for undertaking the project, or for the decommissioning of boilers. Any 

secondary emission increases or decreases resulting from energy efficiency or process 

efficiency improvements of the boiler auxiliaries should be accounted for per guidance in 

the section on “Physical Boundary.” 

Project Size/Output. This performance standard may be used for industrial boilers of 

any size, including large boilers (often classified as water-tube and fire-tube boilers that 

have a capacity greater than 10 million Btu per hour (MMBtu/hour))4 and are regulated by 

the Federal Clean Air Act (CAA) and smaller industrial boilers (less than 10 MMBtu/hour) 

 

4

 Oak Ridge National Laboratory, Characterization of the U.S. Industrial Commercial Boiler Population, May 2005. 
Climate Leaders August 2008 

Industrial Boiler Efficiency - 5 - 

that are exempt from CAA regulations. As a practical matter, the technologies for boiler 

efficiency improvement are typically installed on larger water tube boilers greater than 10 

MMBtu/hour since the fuel reductions are greater and better support project economics. 

However, smaller industrial boiler projects are also eligible to use this performance 

standard, provided they meet the specified performance threshold. 

Project Boundary. This section provides guidance on which physical components and 

associated greenhouse gases must be included in the project boundary for an industrial 

boiler project.

Physical Boundary. The physical boundary of the project includes any component 

of the industrial boiler that will change between the baseline conditions and 

implementation of the project. In most cases, the physical boundary should be 

limited to the boiler unit which includes the boiler, burner, flue stack and 

economizer (see Figure 1) as the rated thermal efficiency of the boiler unit will 

depend on the interaction of these components. 

 Upstream or downstream adjustments to the physical boundary must be made, 

however, to incorporate emissions changes in the following special cases: 

 - projects where the new boiler results in emissions changes in the 

 steam distribution system; 

- projects where the electricity use associated with the boiler auxiliaries 

(e.g., fans, pumps, conveyors) changes as a result of the new boiler. 

In this case, the equipment causing the changes in emissions from 

electricity should be included in the physical boundary, either as direct 

emissions or indirect emissions (if generated off-site); and, 

- changes in CH4 leakage from the natural gas distribution system, for 

example, from a switch from fuel oil to natural gas in the boiler. A 

small section of new natural gas distribution line from a nearby 

distribution main line will typically be installed and the leakage from 

this incremental section should be accounted for. 

Figure 1. Physical Boundary for Industrial Boiler Projects 
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Greenhouse Gas Accounting Boundary. The GHG accounting boundary for an 

industrial boiler efficiency project includes primarily the CO2 emissions from the 

combustion of fossil fuels. Other minor sources of GHGs may be CH4 from leaks in 

the natural gas distribution system (generally small), and CH4 and N2O as 

byproducts of combustion. The GHG accounting boundary for industrial boiler 

projects should, therefore, include all CO2, CH4 and N2O emissions. Appendix II, 

Table IId provides default emission factors for combustion-related CH4 and N2O. 

Appendix II, Table IIf provides default factors for CH4 leaks from natural gas 

distribution. 

Temporal Boundary. An annual accounting boundary should be used for 

industrial boiler projects. Emissions from an industrial boiler can fluctuate over the 

course of a year due to changing activity schedules and seasonal climate patterns. 

An annual accounting boundary will account for these fluctuations. 
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Leakage. Leakage is an increase in GHG emissions or decrease in sequestration caused 

by the project but not accounted for within the project boundary. The underlying concept 

is that a particular project can produce offsetting effects outside of the physical boundary 

that fully or partially negate the benefits of the project. Although there are other forms of 

leakage, for this performance standard, leakage is limited to activity shifting – the 

displacement of activities and their associated GHG emissions outside of the project 

boundary. 

Potential sources of leakage from a boiler project could result from an increase in GHG 

emissions at another site, if the existing higher emitting boiler is retired early before the 

end of its useful life and used elsewhere in the facility, or resold for use in another 

application. If the old boiler is sold to replace another boiler at the end of its life instead of 

buying a more efficient boiler (defined as a boiler with a performance equal to, or better 

than, the performance threshold), the difference in GHG emissions between the 

replacement boiler and the performance threshold are considered leakage and must be 

quantified and subtracted from the emission reductions of the project. 

If it is determined that significant emissions that are reasonably attributable to the project 

occur outside the project boundary, these emissions must be quantified and included in the 

calculation of reductions. No specific quantification methodology is required. All 

associated activities determined to contribute to leakage should be monitored.

Regulatory Eligibility 

The performance standard subjects greenhouse gas offset projects to a regulatory “screen” 

to ensure that the emission reductions achieved would not have occurred in the absence of 

the project due to federal, state or local regulations. In order to be eligible as a GHG offset 

project, GHG emissions must be reduced below the level effectively required by any 

existing federal, state, or local policies, guidance, or regulations. This may also apply to 

consent decrees, other legal agreements, or federal and state programs that compensate 

voluntary action. 

Federal Regulations. There are no federal standards that require any specific 

efficiency or GHG limitations at industrial boilers. The Federal Clean Air Act (CAA) 

includes emissions standards, however, for large industrial boilers (i.e., steam 

generating units with design heat input capacity of more than 10 MMBtu/hour for 

which construction, modification, or reconstruction commenced after June 9, 1989) 

which should be reviewed by the project developer as they influence the individual 

design characteristics of the boiler. The CAA regulations do not apply to units with 

less than 10 MMBtu/hour rated input capacity. 

The following CAA Titles are pertinent to an industrial boiler and should be 

reviewed: 
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- Title I, excluding Section 112: Attainment/Maintenance of 

National Ambient Air Quality Standards (NAAQS) – An industrial 

boiler may be subject to the New Source Performance Standards 

(NSPS), which fall within this section and are codified in 40 CFR Part 

60, subparts Db and Dc.5 Under the NSPS, EPA regulates sulfur 

dioxide (SO2), particulate matter (PM), and nitrogen oxide (NOX) 

emissions from new boilers (steam generating units). Depending on 

the fuel type, throughput, and operational requirements of the boiler, 

NSPS may apply, and a control, such as a low-NOx burner, may be 

required. Applicable regulations are implemented by the state or local 

body and would be covered in the permit process.6

- Title I, Section 112: Hazardous Air Pollutants (HAP) – An 

industrial boiler may be subject to one or more National Emission 

Standards for Hazardous Air Pollutants (NESHAP), for example for 

mercury, organic, or total selected metals. NESHAP applies to all 

boiler units (existing and new) and fuel types (solid, gaseous, and 

liquid), although the requirements differ for each boiler category. 

Existing natural gas boilers have only a carbon monoxide (CO) 

limitation while new natural gas boilers have no limitations. New and 

existing coal (solid fuel) and oil (liquid fuel) units have several 

standards that must be met. In its final rule, codified in 40 CFR Part 

63, EPA requires industrial boilers to meet HAP emission standards 

reflecting the application of the maximum achievable control 

technology (MACT).7 The States are required to implement the 

Federal rule by evaluating each facility’s compliance with MACT, which 

is a component of the State Title V CAA permit program for stationary 

sources. To comply with NESHAP, the purchaser of a new industrial 

boiler must receive a guarantee from the boiler manufacturer that the 

unit is in compliance. After the new unit is installed and operating, the 

facility must demonstrate compliance by a stack test. Compliance and 

reporting details would be covered in the Title V permit. 

- Title V: Operating Permits – A large industrial boiler is a major 

source that would require a Title V permit. All applicable CAA 

regulations, including NSPS and NESHAP, would be covered by the 

permit process. Facilities with plans to install a new boiler or furnace 

for heat or process steam, or to update an existing boiler or furnace 

 

5

 40 CFR Part 60/63 FR 49442, Revision of Standards of Performance for Nitrogen Oxide Emissions From New FossilFuel Fired Steam Generating Units, http://www.epa.gov/ttn/atw/combust/boiler/fr0998.txt 

6

40 CFR Part 60/70 FR 9705, Standards of Performance for Electric Utility Steam Generating Units for Which 

Construction Is Commenced After September 18, 1978; Standards of Performance for Industrial-CommercialInstitutional Steam Generating Units; and Standards of Performance for Small Industrial-Commercial-Institutional Steam 

Generating Units; Proposed Rule http://www.epa.gov/ttn/atw/combust/boiler/fr28fe05.html 

7

 40 CFR Part 63, National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and 

Institutional Boilers and Process Heaters. 
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Industrial Boiler Efficiency - 9 - 

(e.g., to increase capacity or improve performance) may be required to 

file an application for an air pollution construction permit with the 

State or local air board. Although there is an exemption for small 

boilers, large industrial boilers exceed the maximum heat input 

capacity exemption threshold. 

To pass the regulatory screen, the project proponent must demonstrate that the 

proposed project is not being undertaken to come into compliance with any 

mandatory requirements contained in these federal programs. In circumstances 

where a proposed project is being undertaken to comply with regulations, but GHG 

emission reductions are achieved beyond what would reasonably be expected from 

technologies/practices used to meet the regulation, the project could pass the 

regulatory screen and the incremental GHG emission reductions may be considered 

as the project. 

State and Local Regulations. States develop regulations to implement the 

Federal CAA requirements that the EPA delegates to the States. State air emission 

standards must be as stringent as the Federal CAA rules. States have the option to 

echo the federal code, to incorporate them by reference into state law, or states 

may establish regulations that are more stringent than the federal standards, as is 

often the case in California. Some states and local governments have additional 

efficiency standards, require periodic audits, or encourage the purchase of certain 

types of boilers. The project developer should review any such state and local 

standards. 

GHG emission reductions resulting from compliance with any federal, state or local 

regulations are not eligible as GHG offsets. 

Determining Additionality – Applying the Performance Threshold 

This section describes the performance threshold (additionality determination) which an 

industrial boiler project must meet or exceed in order to be considered as a GHG project 

offset. 

Additionality Determination. The additionality determination represents a level of 

performance that, with respect to emission reductions or removals, or technologies or 

practices, is significantly better than average compared with recently undertaken practices 

or activities in a relevant geographic area. Any project that meets or exceeds the 

performance threshold is considered “additional” or beyond that which would be expected 

under a “business-as-usual” scenario. 

The type of performance threshold used for an industrial boiler project is a technologybased standard. The threshold represents a level of performance (technology) that is 

beyond that expected of a typical industrial boiler and is based on the suite of current 
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technologies available for improving the efficiency of a boiler. The technology-based 

threshold was selected because the efficiencies of industrial boiler applications fall within a 

range that is dictated by operational and emission requirements making no single 

efficiency/emissions performance value applicable for a particular set of industrial boilers. 

The performance threshold is defined as the fuel-specific boiler design that meets the 

engineer’s specifications with a non-condensing economizer integrated into the system. 

This combination is already considered standard on industrial boilers and additional 

“options” would have to be added to the boiler system to achieve superior efficiency/CO2

emissions performance. To generate reductions, a project developer would have to add at 

least one of the other technologies listed below to the boiler system in order to pass the 

performance threshold and make the project additional: 

- Non-condensing economizer (conventional stack heat recovery) 

- Condensing economizer (condensate heat recovery) 

- Combustion air pre-heaters 

- Blowdown waste heat recovery 

- Turbulators 

The engineer’s specification to establish the new “nominal thermal efficiency” for the boiler 

should include the following performance information, and will depend on whether the 

boiler uses coal, fuel oil, or natural gas: 

- Nominal output capacity 

- Fuel 

- Steam delivery pressure 

- Steam delivery temperature 

- NOX limitations 

An example of the process is presented in Table 1 where the technology threshold results 

in a thermal efficiency of 85% (nominal boiler (80%) with non-condensing economizer 

(+5%)). With the advanced burner and controls (+1%), condensing economizer (+1%), 

combustion pre-heater (+1%) and blowdown heat recovery (+1%) the efficiency is 

increased to 89%. Note that the condensing economizer replaces the non-condensing one 

with a marginal increase in efficiency of 1%. 
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Table 1. Industrial Boiler Efficiency and Emissions with Optional Components 

Industrial Boiler and Optional 

Components 

Efficiency Range 

and Incremental 

Improvement* (%) 

Manufacturer 

Specified Efficiency 

Value* 

(%) 

Resulting Overall 

Efficiency* 

(%) 

Nominal Boiler Efficiency 75 – 83 80 80 

Non-Condensing Economizer 1 – 7 5 85 

Advanced Burner and Controls 1 – 2 1 86 

Condensing Economizer 1 – 2 1 87 

Combustion Pre-heater 1 – 2 1 88 

Blowdown Heat Recovery 1 1 89 

* Thermal Efficiency 

Additional information on the derivation of the performance threshold and other efficiency 

improvement options can be found in Appendix I. 

Quantifying Emission Reductions 

Quantifying emission reductions from an industrial boiler project encompasses four steps: 

two are pre-project implementation (selecting the emissions baseline and estimating 

project emission reductions) and two are post-project implementation (monitoring and 

calculating actual project reductions).

Selecting and Setting an Emission Baseline: The emissions baseline for an industrial 

boiler project depends on whether the project involves the retrofit of an existing boiler or 

new construction. The emission baselines are presented below:

1. Retrofit or Early Replacement. For projects involving the retrofit of a 

coal, fuel oil or natural gas boiler or the early replacement of a coal or fuel oil boiler 

with natural gas, the baseline should be equal to the average annual emissions of 

the existing boiler (i.e., the boiler prior to retrofit) in KgCO2 equivalent. 

In cases where a retrofit project also expands capacity, the portion of the project 

that is above the baseline fuel consumption should be treated as new capacity. In 

this case, the project developer must assume that the additional baseline fuel would 

have been natural gas. 

2. New Capacity. For projects involving procurement of a natural gas boiler to 

meet new capacity, or the replacement of a boiler at the end of its lifetime with a 

new natural gas boiler, the thermal efficiency of the technology threshold (i.e., 
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Industrial Boiler Efficiency - 12 - 

efficiency of the nominal boiler that meets the engineer’s specifications with the 

non-condensing economizer) is used as the baseline. Boiler efficiency can be 

converted to project CO2, CH4 and N2O emissions using the EPA emission factors 

referenced in Appendix II. The first step in converting to emissions involves 

determining the annual quantity of heat required for the specific process in MMBtu. 

This is the heat output requirement of the boiler, and is usually calculated through 

engineering analysis. CO2 emissions can then be calculated by multiplying the 

annual heat output value by the CO2 emission factor in Table IIa (Appendix II) that 

corresponds to the efficiency of the boiler system in place. In order to calculate CH4

and N2O emissions, the heat output value must first be converted to a heat input 

value. This is done by dividing the heat output value by the thermal efficiency of 

the boiler (i.e., required heat output / thermal efficiency = required heat input). 

Once this has been done, the project developer should use the appropriate emission 

factor in Table IId (Appendix II) to calculate CH4 and N2O emissions. 

It is important to note that the performance threshold is based on thermal 

efficiency, and thus the direct CO2, CH4, and N2O emissions from fuel combusted by 

the boiler. When developing the baseline for new construction, indirect emissions 

from electricity must be added to the direct emissions in order to estimate total CO2

equivalent emissions. 

In cases where special adjustments were made to the physical boundary, to address fuel, 

pipeline leakage and or electricity changes upstream or downstream from the boiler itself, 

the project developer must also include these in the baseline. 

Estimating Project Emission Reductions. To estimate the potential GHG emission 

reductions from the offset project, the project proponent must compare emissions of the 

baseline with the emissions of the proposed project. 

Estimating baseline emissions: Separate equations are presented for estimating 

baseline emissions from retrofit projects (Equations A,B,C) and new capacity 

(Equations D,E). Carbon content coefficients for natural gas, industrial coal and 

residual and distillate fuel oils are provided in Table IIc (Appendix II). 

Retrofits 

Equation A. 

Baseline CO2 emissions retrofits = (Fi * CCi) + (EL * EFel ) 

Where: 

i= fuel type 
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Fi= fuel consumption, MMBtu (use the average annual fuel consumption for 

the past three years) 

EFi= emission factor of fuel type i, kg CO2/MMBtu 

EL= quantity of electricity consumed, MWh (use the average annual 

consumption for the past three years) 

EFel = emission factor for electricity, kg CO2/MWh. If the emissions intensity 

of the electricity being purchased is known (for example, through contacting 

the local power supplier), the corresponding emission factor should be used. 

Where the specific emissions profile of the purchased electricity is not known, 

the project developer should use the relevant regional electric power 

generation emission factors for the electricity component of their emissions 

Equation B. 

Baseline CH4 and N2O emissions Retrofits= (Fi * EFCH4) + (Fi * EFN20) + (EL * 

EFel, CH4) + (EL * EFel, N2O) 

Where: 

 i= fuel type 

F= fuel consumption, MMBtu (use the average annual fuel consumption from 

the boiler during the past three years) 

EFCH4, EFN20, = fuel-related CH4 and N2O emission factors, respectively, 

kgCO2e/MMBtu (see Appendix II, Table IId) 

EL= quantity of electricity consumed, MWh (use the average annual 

consumption for the past three years) 

EFel,CH4, EF el, N20= Electricity-related CH4 and N2O emission factors, 

respectively, kgCO2e/MWh. If the emissions intensity of the electricity being 

purchased is known (for example, through contacting the local power 

supplier), the corresponding emission factor should be used. Where the 

specific emissions profile of the purchased electricity is not known, the 

applicant should use default values. 

Equation C. 

Total Baseline GHG Emissions Retrofits = Equation A + Equation B. 
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New Capacity 

Total CO2 equivalent emissions also must be calculated when estimating baseline 

emissions from new construction. Baseline CO2 emissions for new construction are 

based on the technology-specific efficiency threshold for the project fuel type 

(Equation D). In order to derive CO2 emissions from the efficiency threshold, it is 

necessary to first multiply the efficiency value of the boiler project by a carbon 

content coefficient for natural gas, and then by the carbon dioxide-to-carbon weight 

ratio (44/12). Because CO2 emissions are calculated differently from non-CO2 

emissions, the calculation of CO2 emissions is prepared first (Equation D) and CH4

and N2O emissions are provided separately in Equation E. The calculation for nonCO2 emissions follows Equation B above, but uses estimates for project-level fuel 

and electricity consumption. 

Equation D. 

Baseline CO2 Emissions New Construction = 1/PT * 14.47 * 44/12 * Hi 

Where: 

PT = performance threshold for the natural gas boiler (efficiency of the 

nominal boiler with condenser, as a percentage) 

14.47 = carbon content coefficient of natural gas (kg C/MMBtu) 

44/12 = conversion from C to CO2 

Hi = estimated annual heat output requirement for project, in MMBtu 

Equation E. 

Total Baseline GHG Emissions New Construction = Equation B + Equation D 

Estimating project emissions: Project-related emissions are estimated using the 

same Equations above. Similar to the baseline calculations outlined above, the 

estimated annual fuel consumption of the project boilers is multiplied by the 

applicable CO2, CH4 and N2O emission factors. Emissions from purchased electricity 

also are included to estimate total project-related CO2 equivalent emissions. 

Estimating project-related emission reductions: Emission reductions are 

estimated using Equation F. 

Equation F. 
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Industrial Boiler Efficiency - 15 - 

Reductions project = Emissions baseline – Emissions project

Monitoring 

Four monitoring options are available for monitoring of emissions from boiler systems: (1) 

direct fuel volume measurement; (2) steam flow measurement; (3) direct stack CO2

measurement; and (4) dealer certified fuel volume measurement.8 The project developer 

should, taking into account their specific circumstances, select the most appropriate option. 

The project developer should also take into account that monitoring options (1), (2), and 

(4) can be used to calculate CH4 and N2O emissions as well as CO2. The default factors for 

CH4 and N20 can be applied as long as fuel volume or heating value (MMBtu) is known. 

Option (3) cannot normally be used to directly determine N2O and CH4 emissions as 

continuous emissions monitoring (CEM) equipment to measure these gases is not 

commercially available. 

Direct Fuel Volume Measurement Approach. This method uses a volume meter 

positioned in the fuel line leading directly to the boiler to measure the volume of fuel 

burned in the boiler. At the end of each year, or some other designated period, the total 

volume of fuel burned is read from the meter and used in Equation G to estimate the 

emissions of CO2 from the boiler over that period. For natural gas-fired boilers, the method 

also requires that temperature and pressure gauges be inserted in the fuel line to measure 

the temperature and pressure of the fuel gas. The average gas pressure and temperature 

over the measurement period is used in the equation to compensate for changes in gas 

density due to these two factors. Fuel oil is relatively incompressible and its density does 

not change appreciably over the year due to temperature and pressure fluctuations.

Equation G. 

Actual CO2 Emissions monitored = V x CF x (44/12) x CE x 520/T x P/14.7 

Where: 

V = volume of fuel combusted (mscf/yr or mgal/yr) 

CF = carbon factor (ton/mscf or ton/mgal) 

44/12 = ratio of the weight of CO2 to carbon 

CE = combustion efficiency (assume 0.99) 

520/T = ratio of standard temperature to temperature of fuel (oR) 

 

8

 Clinton E. Burklin, Rick Lafleur, and Steve Erickson. “Measurement Methods for Commercial and Institutional Gasand Oil-Fired Boilers,” U.S. Environmental Protection Agency, December 30, 2004. 
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Industrial Boiler Efficiency - 16 - 

P/14.7 = ratio of fuel pressure to standard pressure (psia) 

Steam Flow Measurement Approach. The steam flow measurement method uses the 

quantity of steam produced by the boiler and engineering data to calculate the CO2

emissions from the boiler. This method is applicable to boilers fired with natural gas and 

fuel oil. In this method, the steam produced by the boiler is measured in the steam line 

just after it exits the boiler. At the end of a year, or some other designated period, the 

quantity of steam produced by the boiler is used to calculate the CO2 emissions for the 

period using Equation H. In addition to the annual steam production, Equation H also 

requires the boiler owner to contact the boiler manufacturer to obtain the heat rate of the 

boiler, which is usually expressed in terms of million Btu of fuel required to produce a 

million Btu of steam. The heat rate is also called the overall thermal efficiency of the 

boiler. 

Equation H. 

Actual CO2 Emissions monitored = Q x HR x 1/HV x CF x (44/12) x CE 

Where: 

 

 Q = quantity of steam produced (MMBtu/yr) 

 HR = heat rate of the boiler (MMBtu of fuel/MMBtu of steam) 

 HV = heating value of the fuel (MMBtu/mgal or MMBtu/mscf) 

 CF = carbon factor (ton/mscf or ton/mgal) 

 44/12 = ratio of the weight of CO2 to carbon 

 CE = combustion efficiency (assume 0.99) 

An orifice meter and an associated digital flow totalizer are used to provide a continuous 

digital display of the current steam flow rate and accumulated steam flow. These totalizers 

can be programmed to output values in any desired unit, which for this method should be 

million Btu of steam flow. The orifice meter is placed in the steam line as it exits the 

boiler. The orifice meter is factory calibrated, but should be re-calibrated annually. 

Temperature and pressure sensors are used by the totalizer to determine the quantity of 

heat conveyed by a unit of steam. These sensors are located in the steam line, adjacent to 

the orifice meter. The sensors are factory calibrated and do not require further calibration. 
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Industrial Boiler Efficiency - 17 - 

Direct Stack CO2 Measurement Approach. The direct stack CO2 measurement 

methodology uses a set of three instruments to directly measure the CO2 emissions from 

the boiler stack. A gas analyzer is used to measure the concentration of CO2 in the boiler 

stack. A flow rate meter is used to measure the flow rate of the flue gases in the boiler 

stack. And a data integrator is used to integrate the CO2 concentration and the flue gas 

flow rate over a given time period, such as a year, to calculate an annual CO2 emission rate 

from the natural gas boiler. 

Dealer Certified Fuel Volume Measurement Approach. An alternative to the direct 

fuel volume measurement method is to allow the use of dealer certified fuel volume 

measurements that are provided by the fuel dealer as part of their billing records. 

Although there is no national standard for the accuracy of retail fuel deliveries, all but one 

state (North Dakota) has adopted the guidelines set by the National Conference on 

Weights and Measures (NCWM), known as Handbook 44.

9

 Under this method, the boiler 

owner would not be required to install and maintain any fuel metering instrumentation. 

The natural gas retail dealers, however, would be required to maintain fuel delivery meters 

that meet the accuracy requirements of Handbook 44 and provide documentation that 

reported sales volumes comply with these requirements. If there are multiple boilers, the 

retail fuel dealer must provide separate fuel use records for each boiler.

To estimate CO2 emissions, the boiler owner would obtain a certified record of annual fuel 

use from the fuel retailer. The owner would use this fuel volume in Equation 1 (Section 

6.1) to calculate the tons per year of CO2 emissions. Equation 1 requires natural gas boiler 

owners to obtain the temperature and pressure for which the certified natural gas volume 

has been adjusted from the fuel delivery company. 

Calculating Actual Project Reductions. Quantifying project GHG emissions reductions 

occurs after the project has been implemented and monitored. To quantify project 

reductions, apply the equations presented in the section on estimating project emission 

reductions, using actual monitored project data rather than estimates, and adjust for any 

leakage (Equation I). 

Equation I. 

Reductions project = Emissions baseline – Emissions monitored (+/- leakage 

adjustments) 

 

9 The National Conference on Weights and Measures (NCWM) developed the “Specifications, Tolerances, and Other 

Technical Requirements for Weighting and Measuring Devices” in partnership with the Office of Weights and Measures 

of the National Institute of Standards and Technology (NIST). This set of guidelines is also known as Handbook 44. 

http://ts.nist.gov/ts/htdocs/230/235/h130 04/PDF/h130 04all.pdf
Climate Leaders August 2008 

Industrial Boiler Efficiency - 18 - 

Appendix I. Development of the Performance Threshold – Data Set

The data sources used for developing these performance thresholds include the California 

Energy Commission’s Non Residential Market Share Tracking Study published in April 2005, 

the U.S. Energy Information Administration’s (EIA) Manufacturing Energy Consumption 

Survey (MECS) last updated in 2002, and Oak Ridge National Laboratory’s (ORNL) 

Characterization of the U.S. Industrial Commercial Boiler Population published in May 2005. 

In addition, information on current engineering practices concerning industrial boilers were 

used, focusing on boilers installed in New York, Wisconsin, and California. 

The service provided by the industrial boiler is heat to assist a specific industrial process. 

Each process has its own desired steam pressure and temperature requirements. This heat 

can, in theory, be obtained from the combustion of various types of fuel, or from 

electricity. Table 1a is based on the MECS 2002 survey and includes data on all market 

fuels and electricity used by industrial boilers, but excludes by-product fuels. The Table 

shows that in 2002 natural gas was the predominant fuel regardless of region or location, 

representing 78% of the total fuel consumed by industrial boilers. Coal made up another 

15% and fuel oil about 6%. 

Table Ia. End Uses of Fuel Consumption, 2002 (Trillion Btu.) 

End Use 

Net 

Demand 

for 

Electricity

Residual 

Fuel Oil 

Distillate 

Fuel Oil 

and 

Diesel 

Fuel 

Natural 

Gas 

LPG 

and 

NGL 

Coal 

(Excl. 

Coke 

and 

Breeze) Total 

 

TOTAL FUEL 

CONSUMPTION 3,297 208 141 5,794 103 1,182 10,725

Indirect Uses-Boiler Fuel 23 127 35 2,162 8 776 3,131

 Conventional Boiler Use 11 76 25 1,306 8 255 1,681

 (% of total fuel use) 0.65 4.52 1.49 77.69 0.48 15.17 N/A

 CHP and/or Cogeneration 

Process 12 51 10 857 * 521 1,451

Direct Uses-Total Process 2,624 60 43 2,986 64 381 6,158

 Process Heating 355 58 24 2,742 60 368 3,607

 Process Cooling and 

Refrigeration 213 * 2 45 * * 260

 Machine Drive 1,746 2 16 109 4 5 1,882

 Electro-Chemical Processes 295 N/A N/A N/A N/A N/A 295

 Other Process Use 15 * 1 90 * 7 113

Direct Uses-Total 

Nonprocess 551 4 50 513 24 19 1,161

 Facility HVAC (e) 280 3 5 417 5 5 715

 Facility Lighting 212 N/A N/A N/A N/A N/A 212

 Other Facility Support 51 * 1 30 * * 82
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Industrial Boiler Efficiency - 19 - 

 Onsite Transportation 4 N/A 35 2 18 N/A 59

 Conventional Electricity 

Generation N/A 1 Q 55 * 14 70

 Other Nonprocess Use 4 * Q 10 * 0 14

End Use Not Reported 112 17 12 132 6 6 285

 Northeast Census Region 

 

 Conventional Boiler Use 1 30 7 117 * 10 165

 (% of total fuel use) 0.6 18.3 4.3 71.3 0.0 6.1 N/A

 Midwest Census Region 

 

 Conventional Boiler Use 3 8 3 358 2 139 513

 (% of total fuel use) 0.6 1.6 0.6 70.2 0.4 27.3 N/A

 South Census Region 

 

 Conventional Boiler Use 6 33 13 660 3 97 812

 (% of total fuel use) 0.7 4.1 1.6 81.9 0.4 12.0 N/A

 West Census Region 

 

 Conventional Boiler Use 1 6 2 171 4 8 192

 (% of total fuel use) 0.5 3.1 1.0 89.5 2.1 4.2 N/A

Notes: * = < 0.5%; Q = number is withheld because the relative standard error is > 50%. 

Source: Energy Information Administration, 2002 Manufacturing Energy Consumption Survey. 

Recent engineering practices in states such as California, Wisconsin, and New York indicate 

that use of natural gas is even more prevalent in industrial boilers that have been installed 

within the past 5 years. This is because industry has switched to natural gas in new boilers 

to meet the CAA and NESHAP regulations and the associated NOx, SO2, and PM standards. 

For example, the CEC Non Residential Market Share Tracking Study shows that 100% of 

new industrial boiler applications installed in the years 2000-2002 used natural gas as the 

primary fuel, although they often had dual fuel burners to burn diesel in the event of a 

natural gas supply disruption.10

Certain industries (paper, refining, chemicals, primary metals) also use by-product fuels 

generated by on-site processes. For these industries, by-product use in boilers exceeds that 

of natural gas. The decision whether to use these by-products is based on different 

parameters than those for using a market fuel. The by-product fuels are typically required 

to be combusted, recycled or disposed in an environmentally approved manner and for 

 

10 California Energy Commission, Non Residential Market Share Tracking Study, CEC 400-2005-013, 

April 2005. 
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Industrial Boiler Efficiency - 20 - 

specific environmental or financial reasons. Their use in a boiler is, therefore, a separate 

decision than what market fuel to use. 

Cogeneration applications can also provide process heat at the desired rates and quality. 

Because they also provide electricity, however, they offer an additional service that is not 

relevant for the industrial boilers addressed in this methodology. 

There is no known data set describing the various efficiencies of industrial boilers in the 

United States. General engineering practices, however, indicate that industrial boilers are 

very similar in design efficiency and generate steam within a narrow range of efficiency. 

Differences in actual operating efficiency occur as a result of desired load, steam pressure, 

temperature requirements, and local emission thresholds which depend on site-specific 

parameters. Although there are no “standard” or “high” efficiency industrial boilers, there 

is a range of technology modifications, which can increase the operational thermal 

efficiency of the boiler’s steam production process, once it is designed or after it is 

installed. Combinations of these modifications can increase boiler thermal efficiency to 

approximately 90%. 

Using industry surveys and general engineering practices, a number of potential technology 

options for modifying and improving the efficiency of industrial boilers were identified. 

These options are described further in Table Ib. Among the technology options available 

for improving the efficiency of industrial boilers, non-condensing economizers and 

electronic ignitions are considered standard practices. The other options are not commonly 

used and could potentially be used for a GHG offset project. The list of technologies in 

Table Ib is not exhaustive and other emerging technologies are potentially eligible as well. 

Table 1b. Function and Efficiency of Optional Industrial Boiler Components 

Technology Option Description Manufacturer 

Specified 

Thermal 

Efficiency 

Value 

Efficiency 

Range and 

Incremental 

Improvement

Common 

Practice 

Non-condensing 

Economizer 

(Conventional stack 

heat recovery) 

Recovers heat from the boiler exhaust and is 

used to pre-heat the boiler feed water. This 

reduces the load on the boiler as the 

temperature differential of the feed water in the 

boiler is reduced. 11,12,13

5% 1-7% Yes 

Condensing 

Economizer 

(Condensate heat 

recovery) 

Performs same function as the non-condensing 

economizer but it extracts more heat from the 

exhaust stream thereby providing for a higher 

inlet feed water temperature. By cooling the 

1%15 1-2% No 

 

11 U.S. Department of Energy Federal Energy Management Program. “Boiler Checklist” 

http://www.eere.energy.gov/femp/operations_maintenance/technologies/boilers/checklist.cfm Accessed January 26, 

2007 

12 Interview – December 20, 2005: Aaron Sink, Engineering Support, Cleaver Brooks (402) 434-2017 

13 Nebraska Boiler “Boiler Efficiency Impact” http://www.neboiler.com/Economizer.asp. Accessed January 26, 2007 
Climate Leaders August 2008 

Industrial Boiler Efficiency - 21 - 

exhaust air to the point of condensation, the 

latent heat of exhaust is captured. 14

Combustion Air Preheaters 

(Recuperators) 

Preheats the incoming combustion air. This 

reduces the load on the boiler by reducing the 

energy needed to heat the air from ambient. 

1% 1-2%, No 

Blowdown Waste 

Heat Recovery 

Heat is recovered from boiler blowdown through 

a heat exchanger and a flash tank. Typically 

used to pre-heat boiler make-up water and the 

flash tank recovery can be used in the 

deaeration or other heating process. 

1%16 1-2%. No 

Turbulators (Example 

of Advanced Burner) 

Pieces of metal inserted in the tubes of fire-tube 

boilers, causing hot gases to travel more slowly 

and with more turbulence, resulting in better 

heat transfer to the water. 

1% 1-2% No 

Oxygen Trim Controls 

(Example of 

Advanced 

Combustion Control) 

These controls measure stack gas oxygen 

concentration and automatically adjust the inlet 

air at the burner for optimum efficiency. 

1% 1% No 

The CEC 2003 Non-residential Market Share Tracking Study confirms the findings from 

Table Ib.17 The purpose of the tracking study was to collect data on market shares, 

quantities, and prices of energy-efficient versus standard-efficiency technologies in 

California. Data collection involved 560 on-site surveys at manufacturing facilities and 

telephone interviews with 104 upstream market entities (manufacturers, distributors, 

dealers, installers, and designers). Table Ic shows that the boiler efficiency improvement 

options with the greatest overall penetration in the California market are electronic 

ignitions (31.1%) followed by conventional (non-condensing) stack heat recovery (22.2%). 

Both of these features are considered standard practice in new applications. The overall 

penetration of condensate heat recovery (20.9%) is higher than expected, but could be the 

result of special incentive programs during the 1980s and 1990s in California. 

The second part of Table Ic shows common retrofit items in the three-year period from 

2000-2002. The most common retrofits were system energy efficiency changes involving 

reduced steam pressure and improved insulation. Steam pressure and pipe insulation 

improvements are system changes outside of the defined project boundary for industrial 

boiler improvements. The next most common retrofits were electronic ignitions and noncondensing stack heat recovery. The rest of the boiler improvement options (condensate 

heat recovery, other heat recovery (e.g., blow down), O2 trim control, advanced burners) 

were performed infrequently and back up the determination that these are not standard 

practices. 

 

14 U.S. Department of Energy, Energy Efficiency and Renewable Energy. “Improving Steam System Performance. 

http://www1.eere.energy.gov/industry/bestpractices/pdfs/steamsourcebook.pdf. Accessed January 26, 2007 

15 Alliant Energy. “HVAC Systems: Boilers” 

http://www.alliantenergy.com/docs/groups/public/documents/pub/p012392.hcsp#P19_1151. Accessed January 26, 2007. 

16 Energy. “HVAC Systems: Boilers” 

http://www.alliantenergy.com/docs/groups/public/documents/pub/p012392.hcsp#P19_1151. Accessed January 26, 2007. 

17 California Energy Commission, Non Residential Market Share Tracking Study, April 2005, 

CEC 400-2005-013 
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Industrial Boiler Efficiency - 22 - 

Table Ic. Industrial Gas Boiler Energy Efficiency Measures in California, 2003 

SICs 21-34, 37-39 

Measures on Existing Boilers Percent (%)

Stack heat recovery 22.2 

Condensate heat recovery 20.9 

Other heat recovery 7.5 

Automated tuning (O2 trim control) 13.8 

Electronic ignition 31.1 

Turbulators for firetube boilers 9.9 

Boiler and System Retrofits in Prior 3 Years (2000-2002)

Stack heat recovery 10.7 

Condensate heat recovery 3.0 

Other heat recovery 0.0 

Automated tuning (O2 trim control) 1.9 

Electronic ignition 11.8 

Turbulators for firetube boilers 0.7 

Increased pipe and jacket insulation (system EE) 22.1 

Reduced boiler blow-down cycle (system EE) 3.6 

Reduced steam pressure (system EE) 37.6 

Variable speed drives on fans (system EE) 2.4 

Automatic flue damper (system EE) 4.3 

Smaller boiler for low load conditions (system EE) 0.7 

Other 0.2 

Source: California Energy Commission, Non Residential Market Share Tracking Study, CEC 400-2005-013, 

April 2005. 

Note: EE = energy efficiency 

Spatial Area. A national spatial area was used to develop the performance threshold for 

retrofit and new capacity industrial boiler efficiency projects. Engineering parameters for 

industrial boiler technology designs are constant and do not vary for geographic reasons. 

At least 12 states have developed appliance energy efficiency standards using American 

Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE) standards,18 but 

in all reviewed cases, these do not impose any specific requirements on industrial boilers. 

Therefore, a performance threshold based on a technology standard is not expected to 

vary regionally for any mandatory reasons. 

Voluntary initiatives such as rebates and tax credits do have an influence on the choice of 

equipment used. Utility rebate programs for high efficiency industrial boilers are available 

in California, Minnesota, Iowa, New York, and some New England States and can amount 

to 25% or more of the installed cost. These are voluntary programs, however, and any 

differences in technology implementation in these areas are not used as the basis for a 

more stringent threshold in these states. 

Temporal Range. The temporal range for the performance threshold is based on the 

CEC Non Residential Market Share Tracking Study, ORNL’s Characterization of the U.S. 

 

18 http://www.ase.org/content/article/detail/2600 
Climate Leaders August 2008 

Industrial Boiler Efficiency - 23 - 

Industrial Commercial Boiler Population, and current engineering practices and trends 

concerning industrial boilers experienced in several states, including New York, Wisconsin, 

and California. 

Figures 1a and 1b, which are based on the ORNL study, indicate that sales of industrial 

boilers have decreased between 1964 and 2003. This slowing rate of inventory turn-over 

could mean that a longer temporal range would be appropriate. Decisions related to 

efficiency improvements and fuel switching are, however, to a great extent, based on fuel 

prices and economics. Fuel costs began their sharp rise in late 1999 and surged higher 

again in 2005 thus providing the basis for more rapid payouts for energy efficiency projects 

and thus an increasing number of such activities. Moreover, the CEC Non Residential 

Market Share Tracking Study and engineering practices in New Jersey, New York and 

Wisconsin indicate that, recently, industry has mostly invested in natural gas-fired boilers 

rather than coal or fuel oil boilers. Therefore, a temporal range using current engineering 

practices (during the past 5 years) is appropriate. 

Figure Ia. Sales of Boilers > 10 MMBtu/Hour 1964-2003 

Source: Oak Ridge National Laboratory, Characterization of the U.S. Industrial Commercial 

Boiler Population, May 2005. 
Climate Leaders August 2008 

Industrial Boiler Efficiency - 24 - 

Figure Ib. Sales of Boilers > 100 MMBtu/hour 1964-2003 

Source: Oak Ridge National Laboratory, Characterization of the U.S. Industrial Commercial 

Boiler Population, May 2005. 
Climate Leaders August 2008 

Industrial Boiler Efficiency - 25 - 

Appendix II. Tables for Estimating and Calculating Emissions 

Tables IIa – IIf provide default values that may be used by the project developer for 

estimating or calculating GHG emissions where project specific data are not available. 

Table IIa. Relationship Between Boiler Thermal Efficiency and CO2 Emissions 

Boiler Thermal Emissions per Heat Output (KgCO2/MMBtu) 

Efficiency Natural Gas Distillate Fuel Oil Residual Fuel Oil Coal 

80% 66.3 91.4 98.5 117.5 

81% 65.5 90.3 97.3 116.0 

82% 64.7 89.2 96.1 114.6 

83% 63.9 88.1 94.9 113.2 

84% 63.2 87.1 93.8 111.9 

85% 62.4 86.1 92.7 110.6 

86% 61.7 85.1 91.6 109.3 

87% 61.0 84.1 90.6 108.0 

88% 60.3 83.1 89.5 106.8 

89% 59.6 82.2 88.5 105.6 

90% 59.0 81.3 87.6 104.4 

91% 58.3 80.4 86.6 103.3 

92% 57.7 79.5 85.7 102.2 

93% 57.1 78.7 84.7 101.1 

94% 56.4 77.8 83.8 100.0 

Note: The efficiencies were converted to emissions based on the EPA carbon content coefficients 

provided in Table IIc. 

Table IIb. CO2 Emission Factors for Various Fuels 

Fuel Type kg CO2/MMBtu 

Natural Gas 53.06 

Distillate Fuel Oil 73.15 

Residual Fuel Oil 78.80 

Coal 93.98 

Note: Industrial coal value based on Year 2006 “Industrial Other Coal” value. 

Source: Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2006, April 2008. U.S. 

Environmental Protection Agency. 
Climate Leaders August 2008 

Industrial Boiler Efficiency - 26 - 

Table IIc. Default CH4 and N2O Emission Factors for Natural Gas, and Fuel Oil, 

Coal 

Source: Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2006. U.S. 

Environmental Protection Agency, April 2008. 

Table IId. Default CH4 and N2O Emission Factors for Electricity 

Note: Electricity emissions of CH4 and N2O relate to the fuel used to produce the electricity. 

Information on fuel type will be needed to estimate CH4 and N2O. 

Source: Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2006. U.S. 

Environmental Protection Agency, April 2008. 

Table IIe. Emission Factors for Electricity Use by Project Equipment by eGRID 

Subregion (2004)

eGRID Subregion 

States included in 

eGRID Subregion 

NERC 

Region 

Emission factor 

for electricity 

used by project 

equipment (kg 

CO2/kWh) 

AKGD* (Alaska Grid) AK ASCC 0.604 

AKMS (Alaska Miscellaneous) AK ASCC 0.630 

AZNM (WECC- Southwest) AZ, CA, NM, NV, TX WECC 0.634 

CAMX (WECC- California) CA, NV, UT WECC 0.572 

ERCT (Texas) TX ERCOT 0.600 

Fuel Type Greenhouse Gas Emissions per Unit of Fuel Input 

(kg CO2e/MMBtu) 

CH4 0.105 Natural Gas N2O 0.031 

CH4 0.231 Petroleum (Commercial sector) N2O 0.186 

CH4 0.063 Petroleum (Industrial sector) 

N2O 0.186 

CH4 0.231 Coal N2O 0.496 

Fuel Type Greenhouse Gas Emissions per Unit of Fuel Input 

(kg CO2e/MMbtu) 

CH4 0.021 Natural Gas N2O 0.031 

CH4 0.063 Petroleum N2O 0.031 

CH4 0.021 Coal 

N2O 0.496 
Climate Leaders August 2008 

Industrial Boiler Efficiency - 27 - 

FRCC (Florida) FL FRCC 0.612 

HIMS (Hawaii- Miscellaneous) HI HICC 0.738 

HIOA* (Hawaii- Oahu) HI HICC 0.783 

MORE (Midwest- East) MI, WI MRO 1.005 

MROW (Midwest- West) 

IA, IL, MI, MN, MT, ND, NE, 

SD, WI, WY MRO 1.050 

NEWE (New England) CT, MA, ME, NH, NY, RI, VT NPCC 0.641 

NWPP (WECC- Northwest) 

CA, CO, ID, MT, NV, OR, 

UT, WA, WY WECC 0.770 

NYCW (New York- NYC, Westchester) NY NPCC 0.788 

NYLI (New York- Long Island) NY NPCC 0.686 

NYUP (New York- Upstate) NJ, NY, PA NPCC 0.821 

RFCE (RFC- East) DC, DE, MD, NJ, PA, VA RFC 0.800 

RFCM (RFC- Michigan) MI RFC 0.880 

RFCW (RFC- West) 

IL, IN, KY, MD, MI, OH, PA, 

TN, VA, WI, WV RFC 0.951 

RMPA (WECC- Rocky Mountains) 

AZ, CO, NE, NM, SD, UT, 

WY WECC 0.778 

SPNO (SPP- North) KS, MO SPP 1.007 

SPSO (SPP- South) 

AR, KS, LA, MO, NM, OK, 

TX SPP 0.699 

SRMV (SERC- Mississippi Valley) AR, LA, MO, MS, TX SERC 0.634 

SRMW (SERC- Midwest) IA, IL, MO, OK SERC 0.979 

SRSO (SERC- South) AL, FL, GA, MS SERC 0.847 

SRTV (SERC- Tennessee Valley) AL, GA, KY, MS, NC, TN SERC 0.941 

SRVC (SERC- Virginia/Carolina) GA, NC, SC, VA, WV SERC 0.890 

Note: The emission factors in Table II.e reflect variations in electricity use by project equipment 

across regions and load type (i.e., base versus non-baseload). Coincident peak demand factors 

from a 2007 ACEEE study were combined with EPA’s eGRID emission factors for baseload and nonbaseload power to derive the emission factors presented in this table.19,20

Table IIf. Default Fugitive CH4 Emission Factors for Natural Gas Distribution 

Systems 

Pipeline Leaks 2004 

 Distribution Mains - Cast Iron Mscf/mile-yr 238.70 

 Distribution Mains - Unprotected steel Mscf/mile-yr 110.19 

 Distribution Mains - Protected steel Mscf/mile-yr 3.07 

 Distribution Mains - Plastic Mscf/mile-yr 9.91 

 Services- Unprotected Steel Mscf/service 1.70 

 Services- Protected Steel Mscf/service 0.18 

 

19 York, D. Kushler, M. Witte, P. “Examining the Peak Demand Impacts of Energy Efficiency: A Review of Program 

Experience and Industry Practice.” American Council for and Energy-Efficient Economy (ACEEE). February 2007. 

http://www.aceee.org/pubs/u071.htm. 

20 The Emissions & Generation Resource Integrated Database (eGRID) is a comprehensive inventory of environmental 

attributes of electric power systems, available at http://www.epa.gov/cleanenergy/energy-resources/egrid/index.html. 
Climate Leaders August 2008 

Industrial Boiler Efficiency - 28 - 

 Services- Plastic Mscf/service 0.01 

 Services- Copper Mscf/service 0.25 

Source: U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks 1990-2006, April 2008. 
Climate Leaders August 2008 

Industrial Boiler Efficiency - 29 - 

Office of Air and Radiation (6202J) 

EPA400-S-08-001 

August 2008 

www.epa.gov/climateleaders