1

MEMORANDUM

TO: Air and Radiation Docket EPA-HQ-OAR-2012-0401

FROM: EPA Office of Transportation and Air Quality

DATE: May 30, 2014

SUBJECT: Support for Classification of Biofuel Produced from Waste Derived

Biogas as Cellulosic Biofuel and Summary of Lifecycle Analysis 

Assumptions and Calculations for Electricity Produced from Waste 

Derived Biogas

This memorandum provides additional support for EPA’s determination that renewable fuel 

produced using biogas from landfills, MSW digesters, wastewater treatment facility digesters, 

and agricultural digesters should be classified as cellulosic biofuel. It also provides information 

on the key input assumptions used for the lifecycle analysis of electricity produced from waste 

derived biogas. Assumptions include on-site emissions of biogas collection as well as

efficiencies of electricity generation, use and distribution. Data sources are presented to promote 

transparency for our lifecycle analysis. This memorandum also describes the calculations made 

for the lifecycle analysis of electricity produced from waste derived biogas and discusses, in 

depth, the choice of baseline used in the lifecycle analysis.
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I. Summary

In the June 14, 2013 Notice of Proposed Rulemaking (NPRM), EPA proposed to allow 

compressed natural gas (CNG), liquefied natural gas (LNG) and renewable electricity from 

landfill biogas to qualify for cellulosic renewable identification numbers (RINs), and requested 

comment on whether fuel derived from other sources of biogas should also be allowed to qualify

for cellulosic RINs. The proposal to treat landfill biogas as a cellulosic biofuel feedstock was 

based on available data and was supported by a memo to the docket (EPA-HQ-2012-0401). This 

document expands upon the original memo to the docket and provides a summary of additional 

information provided through the public comment process or developed in response to comments 

received. Through the comment process, and additional EPA research, EPA has identified 

additional data that supports a finding that fuel derived from biogas from MSW digesters, 

municipal wastewater treatment facility digesters, and agricultural digesters is also 

predominantly derived from cellulosic components. 

II. Determination of the Cellulosic Content of Waste Derived Biogas

A. Biogas from Landfills

For the purposes of this memorandum, the terms “cellulosic” or “cellulosic content” are 

intended to refer to the sum of the cellulose, hemicellulose, and lignin components of a 

feedstock.

a

 However, when calculating the “adjusted cellulosic content” of a feedstock, which is 

a percentage value, the cellulosic content is divided by the volatile organic fraction because only 

this portion is reactive and can contribute to the production of biogas. For municipal solid waste 

(MSW) in landfills, the non-organic fraction is composed of metal, cement and other inorganic 

materials that will not yield methane in the landfill. Review and analysis of available data 

characterizing MSW landfill material and its associated biogas indicate that the organic fraction 

of MSW is predominately cellulosic and the biogas generated from MSW is predominantly

derived from the cellulosic components. 

The Barlaz research cited in the June 2013 NPRM most directly attempts to answer the 

question of what percent of the MSW landfill biogas is derived from the cellulosic components 

of the MSW. Results from this study are outlined in Table 1 and Figures 1 and 2, and show that 

methane does not appear until day 41, indicating that the initial decomposition was aerobic, 

involving loss of sugars to carbon dioxide and water. During this time period, about 20% of the 

MSW was lost, including fractions of cellulose and hemicellulose (Fig. 1 top). Once the 

originally present oxygen was consumed, the reactors became anaerobic and methane production 

began (Fig. 1). Large amounts of both cellulose and hemicellulose were converted during this 

period (Fig. 1 top), and lignin accumulated in the residue (Fig. 1 bottom). Overall, 71% of the 

 

a

This is based on the definition of “cellulosic biofuel” in Clean Air Act Section 211(o)(1)(E). 
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cellulose and 77% of the hemicellulose were converted during the reaction, roughly half 

aerobically and half anaerobically (Table 1). These data show that a substantial fraction of the 

cellulosic content of MSW is converted. In fact, based on the abundance of different 

biochemicals in the MSW and theoretical methane potentials for the different components (e.g., 

cellulose, proteins), the authors determined that 91% of the total methane in this sample was 

derived from cellulosic components. This research indicates that a predominant portion of the 

biogas from MSW landfills comes from anaerobic digestion of the cellulosic content of MSW, 

namely cellulose and hemicellulose. 

Table 1 – Chemical composition of municipal solid waste (MSW) from different studies, the 

percent of each type of compound lost in a degradation experiment and the percent of total 

methane potential from the different components.

Barlaz et al. (1989)1

% Composition 

(average of 14 

studies)

% Composition % Lost during 

decomposition

% of total 

methane 

potential

Cellulose 38 ± 14 51 71 74

Hemicellulose 8 ± 2 12 77 15

Lignin 16 ± 6 15 8 0

*

Protein 3 ± 1 4 n.d. 8

Volatile Solids 69 ± 16 79 n.d. 100

Average % "Cellulosic"** 90 ± 30*** 100**** 91b

*

The authors assumed that lignin had a methane potential of zero because lignin is known to react very slowly 

under anaerobic conditions.

**Calculated relative to the measured concentration of volatile solids.

***Standard error calculated by propagation of error.

****Note that this value is artificially high due to measurement uncertainties

 

b

91% represents the portion of the biogas derived from cellulose and hemicellulose, and is calculated by dividing 

the sum of their methane potential fractions by the total methane potential fraction for cellulose, hemicellulose, 

and protein. As calculated by Barlaz et al., there may be slight differences in numbers due to rounding. 
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Figure 1 – Chemical Composition of degrading MSW versus time:

2 % of original mass 

remaining for total mass, cellulose, hemicelluloses and lignin, with cumulative methane 

yield plotted on the right axis. Methane first appeared (at very low concentration) on day 

41.
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Figure 2 – Chemical Composition of degrading MSW versus time: percent composition of 

MSW over time, with the area between curves corresponding to the percent of total mass in 

that component. The “other” material (white) includes metals, plastics and cement, as well 

as organic materials such as proteins and starches. The circles show the cumulative 

production of methane in the reaction containers.

Recent studies have also confirmed that the organic fraction of MSW is still 

predominantly comprised of cellulose, hemicellulose, and lignin2c. Moreover, there is a strong

and direct correlation between the amount of cellulosic materials present in the MSW and the 

amount of biogas that can be produced – demonstrating that anaerobic digestion is converting

cellulosic biomass to biogas.

3

 Based on the average of 14 studies, MSW contains 38% 

cellulose, 8% hemicellulose and 16% lignin, with smaller amounts of proteins, sugars and other 

organic materials (Table 1).4 Since the average organic fraction of the MSW is 69%, the average 

adjusted cellulosic content of the landfill MSW is 90%.

MSW composition varies considerably depending on, for example, the amount of yard 

waste versus food waste versus metal waste deposited. It is worth noting that the studies

examined were published over 27 years (1982 to 2009), during a time period in which recycling 

expanded considerably, leading to substantial changes in the types of materials deposited in 

landfills. Despite these changes, the cellulosic content of the organic fraction of MSW, the 

portion capable of contributing to biogas production, has not changed substantially during this 

time.

1 However, the data reviewed by EPA indicates that the vast majority of volatile solids in 

landfills are composed of cellulosic components1.

Eleazer et al. (1997)5analyzed the decomposition of a variety of components of MSW, 

including leaves, paper, food and MSW itself. They found a correlation between the percent of 

cellulose and hemicellulose in the MSW and the yield of methane from the different samples,

with methane yield increasing as the cellulose and hemicellulose increased. This study

demonstrated that biogas can be produced from the cellulosic portions of MSW and supports the

conclusion that landfill biogas is predominately derived from cellulosic components.

While the fraction of the biogas being generated from cellulosic components may vary

slightly from location to location depending on the composition of the MSW, the volatile solids 

in MSW appear to always contain a large proportion of cellulosic materialsd, and a large 

proportion of the biogas generated will be derived from cellulose and hemicellulose. Therefore, 

we conclude that biogas derived fuel is predominantly cellulosic, and that all volumes of fuel 

made from landfill biogas qualify for cellulosic biofuel RINs. 

 

c

This study compared data collected to other available data.

d

Barlaz et. al. (1989) and Eleazer et. al. (1997)
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B. Biogas from Separated MSW Digesters, Agricultural Digesters, and Municipal Wastewater 

Treatment Facility Digesters

For the reasons described below, EPA is extending its assessment that biogas derived 

from MSW landfills is predominantly cellulosic to include biogas from MSW digesters, 

municipal wastewater treatment facility digesters, and agricultural digesters. 

Organic wastes in the United States that may be available for, and susceptible to, 

anaerobic decomposition to produce biogas can be generally characterized as falling into one of 

four categories. The first includes the organic fraction of municipal solid waste (OFMSW), the 

second is biosolids from municipal wastewater treatment facilities, the third is agriculture waste

(including animal manure), and the fourth is wastes that do not fall into any of the first three

categories. Almost all of the organic wastes anaerobically digested in the U.S. fall into one of the 

first three categoriese, and their adjusted cellulosic content is on average above 75%. (Table 4). 

Given our understanding of anaerobic digestion in MSW landfills, described above, we are 

confident that anaerobic digesters processing predominantly cellulosic materials, including 

materials from any of these first three general waste categories described above, would produce 

biogas that is predominantly cellulosic in origin. For our final rule we have identified three 

digester types that we believe will process wastes that are predominantly cellulosic: separated 

MSW digesters, municipal wastewater treatment facility digesters and agricultural digesters. 

Digesters processing the fourth category of organic wastes described above may accept large 

quantities of non-cellulosic materials, such as waste fats, oils and greases or industrial food 

wastes (e.g., food and beverage production wastes that are primarily composed of sugar or 

starch). While the materials comprising the fourth category may meet EPA’s definition of 

renewable biomass, we do not have enough information at this time to determine that the biogas 

from these materials would be derived from predominantly cellulosic components. Therefore, 

biogas digesters primarily processing non-cellulosic materials such as those listed in the fourth 

category are considered non-cellulosic, and transportation fuel derived from biogas produced at 

these digesters may qualify for advanced biofuel RINs. 

Finally, determinations regarding the cellulosic content of various types of organic wastes

discussed in this memo apply only in the context of production of biogas through anaerobic 

digestion. Our determination that fuel derived from certain feedstocks that are anaerobically 

digested to produce biogas should be considered of cellulosic origin does not apply to fuels 

produced from the same organic wastes that are converted to fuel using a biomass conversion 

process other than anaerobic digestion. One of the reasons for this limitation is that the anaerobic 

digestion process is known to convert cellulosic components of organic wastes to biogas, and 

this cannot be extended to all biomass treatments. 

1. Separated MSW Digesters

 

e

“Municipal Solid Waste Generation, Recycle, and Disposal in the United States: Facts and Figures for 2012”. U.S. 

Environmental Protection Agency: http://www.epa.gov/osw/nonhaz/municipal/msw99.htm
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Separated MSW may be processed in a separated MSW digester to produce biogas and 

biogas-derived transportation fuels. As discussed in the March 2010 rule, the organic fraction of 

MSW generally consists of yard waste and heterogeneous post-consumer food waste.f The 

biochemical conversion processes by which organic material is converted to biogas, known as 

anaerobic digestion, are thermodynamically identical in both landfills and anaerobic digesters. 

The only differences between the anaerobic conversion processes in these systems are kinetic 

(reaction rate). While the environmental conditions in landfill systems favor the anaerobic 

digestion of organic matter thermodynamically, the conversion process is not optimized 

kinetically. In fact, landfills can be viewed as anaerobic digesters that have not been optimized 

for efficient reaction kinetics, and are therefore only capable of passively generating biogas over 

long periods of time. Waste digesters, by contrast, actively perform the anaerobic biochemical 

processes that landfills allow passively because they are designed to optimize system kinetics. 

Therefore, waste digesters more rapidly and efficiently convert biomass to biogas. For example, 

while processing the same amount of identical biomass, a waste digester system would generate 

more useable biogas on a substantially shorter time-scale than a landfill system. However, 

despite kinetic differences, the bioconversion processes occurring in landfills and waste digesters 

are essentially identical. Therefore, EPA finds that fuels made from biogas derived from 

digesters processing separated MSW are predominantly cellulosic in origin and, therefore that 

the entire volume of fuel made from such biogas qualifies for cellulosic biofuel RINs. 

EPA notes that the CAA requires that renewable fuel be produced from “renewable 

biomass” as that term is defined in CAA 211(o)(1)(I). MSW is not identified in the statute as 

renewable biomass. However, EPA determined that “separated MSW” as defined in 40 CFR 

80.1426(f)(5)(i)(C), qualifies as renewable biomass for purposes of renewable fuel production 

provided that it is collected according to a plan submitted and approved by EPA pursuant to 40 

CFR 80.1426(5)(ii). Material that could have been disposed of in a MSW landfill, but was 

diverted from it, does not automatically qualify on that basis as separated MSW. Rather, such 

waste must qualify as a different type of renewable biomass, such as animal waste, separated 

food waste, or separated yard waste to be an eligible feedstock for renewable fuel production. A 

“separated MSW digester” for purposes of today’s rule is a digester processing separated MSW 

as defined in EPA regulations pursuant to an anaerobic digestion process, and refers to the 

renewable biomass fraction of MSW, which is essentially a mixture of yard wastes and post 

consumer food wastes. 

2. Agricultural Digesters

There are approximately 250 agricultural digester projects in the U.S. Of these 

agricultural digesters about 40% are co-digesters processing a mixture of animal manure, onfarm crop residues, and small amounts of other biogenic wastes. There are no consistent data to 

 

f

U.S. EPA’s waste characterization trends show that post-consumer food scraps and yard waste account for more 

than 86% of the OFMSW. 
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portray the exact mixture of material being digested in individual digesters on a continuous basis

because both the material composition and relative proportions of digested material varies over 

time. However, in aggregate, over 90% of the material processed in agricultural digesters is 

animal manure, and the remaining portion consists mainly of plant residues and other on-farm 

wastes that are predominately cellulosic in origin such as crop residues and separated yard 

waste.

g

This section provides information on both animal manure and on-farm crop residues –

the main components processed in agricultural digesters. 

Data used to estimate the aggregate composition of animal manure were obtained from a 

comprehensive review published by the Pacific Northwest National Laboratory covering four 

typically digested categories of animal manure (dairy, cattle, swine, and poultry)

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. Although 

these studies reported the cellulose, hemicelluloses, and lignin on a total solids basis, they did not 

calculate an adjusted cellulosic content based on the fraction of the material that could be 

converted to biogas. To obtain an adjusted cellulosic content, we normalized the reported values 

based on the volatile organic fraction. When possible (e.g., if the studies analyzed the same 

categories of manure) and if comparable (e.g., provided the breakdown of cellulosic components 

in the same way), differing data were averaged. A weighted average based on the type and 

volume of animal manure digested, based on data from AgSTAR was used to estimate the 

cellulosic content for animal manure in aggregate. The adjusted cellulosic content was 

calculated by summing the cellulosic fractions (cellulose, hemicellulose, and lignin) and dividing 

by the volatile fraction capable of contributing to biogas production. The volatile fraction 

capable of contributing to biogas was assumed to be the volatile solids minus the organic 

nitrogen which would be converted to nitrogen gas or other inorganic nitrogen species rather 

than methane or carbon dioxide. 

 

g

U.S. EPA AgSTAR’s digester project information, overall digester biogas data and a representative sample codigester inputs were used to estimate the aggregate digester material. Some of these data are available at 

AgSTAR’s online database: http://www.epa.gov/agstar/projects/index.html#database.
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Table 2 – Data used to assess the cellulosic content of animal manure 

Animal Manure

Cattle

(%)

Poultry

(%)

Swine

(%)

% of treated 

animal manure

Sourceh

Cellulose 25 22 22 25

Hemicellulose 23 12 14 21 (1)

Lignin 19 7 7 17

Volatile Solids

Organic Nitrogen

84

3

62

3

76

3

82

3

(2)

Treated Volume 79 1 20 -- (3)

Adjusted Cellulosic % 80

The aggregate cellulosic content of animal manure (highlighted in green in Table 2) was 

found to be 25% cellulose, 21% hemicellulose, and 17% lignin, which means the cellulosic 

components equal 63%. The volatile solids and organic nitrogen were found to be 82% and 3% 

respectively, which results in a volatile fraction of 79% capable of contributing to biogas 

production. Based on these values, the average adjusted cellulosic content of the biomass treated 

in animal manure digesters is estimated to be 80%. While this estimate assumes that the digester 

material would be exclusively animal manure, it is common practice to co-digest mixtures of 

animal wastes, farm/crop residues and other wastes. As described in a separate memo to the 

docketi, materials that we have determined meet the RFS regulatory definition of “crop residue” 

have on average an adjusted cellulosic content of 84%. The addition of such crop residues 

would therefore typically increase the overall cellulosic content of the biomass being treated in 

manure digesters. Similarly, EPA has determined that “separated yard waste”, as that term is 

defined in 40 CFR 80.1426(5)(i), should be deemed to be composed entirely of cellulosic 

materials. See 40 CFR 80.1426(5)(i)(A). Such materials may also be added to waste digesters in 

an agricultural setting, perhaps in combination with manure and/or crop residues. We have 

defined the term “agricultural waste digester” as those digesters processing animal manure, crop 

residue and separated yard waste, and we have specified in Table 1 to 80.1426 that fuel produced 

from biogas collected at such digesters qualifies as cellulosic biofuel for which cellulosic RINs 

may be generated for the entire volume. EPA understands that incidental de minimis quantities 

 

h

(1) Value added Chemicals from Animal Manure. Chen et. al.. Pacific Northwest National Laboratory (2003):

http://www.pnl.gov/main/publications/external/technical_reports/PNNL-14495.pdf; (2)[Animal] Manure 

Production and Nutrient Content. Chastain et. al.. Clemson University, Swine –

http://www.clemson.edu/extension/livestock/camm/camm_files/swine/sch3a_03.pdf, Dairy –

https://www.clemson.edu/extension/livestock/camm/camm_files/dairy/dch3a_04.pdf, Poultry – 

http://www.clemson.edu/extension/livestock/camm/camm_files/poultry/pch3b_00.pdf; (3) AgSTAR Digester 

Database. U.S. Environmental Protection Agency: http://www.epa.gov/agstar/projects/

i

See “Cellulosic Content of Various Feedstocks: 2014 Update” placed in docket EPA-HQ-OAR-2012-0401.
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of non-cellulosic materials, or materials that are not renewable biomass, may be introduced into 

agricultural digesters. This practice would not disqualify the resulting fuel from qualifying as 

renewable fuel under the RFS program providing that such incidental de minimis feedstock 

contaminants are either impractical to remove or are related to customary feedstock production 

and transport. See 40 CFR 18.1426(f)(1). 

3. Municipal Wastewater Treatment Facility Digesters

Municipal wastewater treatment facility (MWTF) digesters are anaerobic digesters that 

process the sludge, undissolved solids, and biosolids derived from municipal wastewater whether 

or not the facility is owned by a municipality. The composition of wastes processed in MWTF 

tend to be heterogeneous, but are generally composed of human wastes and highly fibrous tissue 

products. Wastes that are processed in municipal wastewater treatment facilities are often 

treated aerobically, but more and more are being configured to employ anaerobic digestion as 

part of the facility’s primary treatment system, allowing biogas to be produced. 

The data used to assess the cellulosic content of wastewater solids is presented in Table 3. 

Table 3 – Data used to assess the cellulosic content of wastewater solids

 

j

Primary sludge refers to the untreated wastewater solids whereas activated sludge (AS) and biosolids refer to 

solids separated from wastewater following treatment at the wastewater facility.

Characteristics of Wastewater Solids 

Wastewater 

Typej % C % H % L

% Convertible 

Solids % AC % AH % AL Source

Primary 29.3 72.9 40.2 Champagne, 

20097

Primary 11.5 26.5 74.1 15.5 35.8 Cheung, 

19978

Primary 17 9 62.6 27.2 14.4 Wang, 

20089

AS 13.8 78.7 17.5 Champagne, 

20094

AS 9 16 13 49.3 18.3 32.5 26.4 Wang,

20086

Biosolids 14 19 8 49.0 28.6 38.8 16.3 Wang,

20086

Averages

% AC % AH % AL % ACC

Average of AS and Biosolids Data 22 36 21 79
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C =; cellulose; H = hemicellulose; L = Lignin; AC = adjusted cellulose; AH = adjusted 

hemicellulose; AL = adjusted lignin; AS =activated sludge; ACC = adjusted cellulosic content

While there are substantial data characterizing the solids composition of municipal 

wastewater, there are somewhat less data characterizing the composition of materials entering 

the digesters specifically. We chose to use the subset of peer-reviewed data highlighted in green 

in Table 3) that analyzes the activated sludge and biosolids for the purposes of calculating the 

average adjusted cellulosic content of materials that would be expected to enter wastewater 

treatment facility digesters. This is because the broader data set did not include data for the 

fraction of hemicellulose in primary sludge and it does not adequately represent the material 

entering the digester. As will be discussed forthwith, the material entering a digester is better 

represented by activated sludge and biosolids.

The wastewater treatment process is designed to oxidize dissolved organics, remove 

nutrients such as aqueous nitrogen and phosphorus species, and separate suspended solids. A 

typical process will involve several steps as part of three broader systems: the primary treatment

system (pretreatment, primary clarification and anaerobic digestion), the secondary treatment

system (aeration, clarification, internal sludge recycle, and disinfection) and the tertiary

treatment system (nutrient removal and solids handling). Anaerobic digestion at wastewater 

treatment facilities typically occurs as part of the process’ primary treatment; however data 

characterizing primary sludge does not adequately represent the material entering the digesters 

because the primary sludge is separated from the wastewater and partially treated prior to 

entering the digester. 

The material that enters the digester includes the undissolved solids that are recovered 

from the primary clarification tank and the solids that are allowed to settle out in a secondary

clarification tank. Therefore, the data for activated sludge and biosolids are more likely to 

represent the material entering the wastewater facility digesters. In addition, the data related to 

activated sludge and biosolids is more consistent and comparable, and therefore provide a more 

robust estimate of the cellulosic content. 

The data considered (in green shaded area in Table 3) offered consistent and comparable 

data, including values for cellulose, hemicellulose, and lignin individually, and the volatile solids 

representing the organic fraction of the wastewater solids that can be converted via anaerobic 

digestion was reported in each of these studies. The average adjusted cellulosic content was 

obtained by dividing the reported cellulosic fraction by the volatile organic fraction that can be 

converted to methane. Based on the data for activated sludge and biosolids, the material

entering the digesters is determined to be on average composed of 13% cellulose, 22% 

hemicellulose, and 13% lignin, for a total of 48% cellulosic components. The volatile solids and 

organic nitrogen were found to be 64% and 3% respectively, which results in a convertible 

organic fraction of 61%. When the cellulosic component is divided by the organic fraction that 

can be converted to methane, the average adjusted cellulosic content of the material used to 
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generate the biogas through anaerobic digestion from wastewater treatment facilities is, on 

average, 79% (Table 4). Therefore, we have determined that fuels made from biogas collected at 

MWTF digesters is predominantly cellulosic, such that the entire volume of fuel produced 

qualifies for cellulosic biofuel RINs. 

Table 4 – Estimated average composition of anaerobically digested cellulosic biomass in the 

United States

Source: This table represents the aggregate data from Table 1, Table 2, and Table 3k.

III. Lifecycle Analysis of Biogas-Derived Electricity Pathways

Under anaerobic conditions, organic wastes naturally decompose to produce biogas, and 

controlled management of organic waste digestion can reduce GHG emissions that would have 

occurred alternatively. The following sections describe the assumptions, analytical methods and 

conclusions regarding the lifecycle GHG emissions associated with electricity produced from 

waste derived biogas. 

A. Assumptions used in the Lifecycle Analysis

Table 5 outlines key assumptions used in determining the lifecycle GHG emissions associated 

with electricity produced from waste derived biogas. EPA used these values in our lifecycle 

analysis as described in the subsequent sections.

Table 5 –Key Assumptions for the Lifecycle Analysis of Electricity produced from Waste 

Derived Biogas

Category Assumption Source Notes

 

k

Table 1 – Barlaz et. al. (1989); Table 2 – see footnote j; Table 3 – Champagne et. al. (2009) and Wang (2008)

Aggregate Composition of Digested Biomass 

% OFMSW % wastewater biosolids % animal manure

Cellulose 38 13 25

Hemicellulose 8 22 21

Lignin 16 13 17

Volatile Solids

Organic Nitrogen

69

--

64

3

82

3

Adjusted Cellulosic 

Content 90 79 80
13

On-Site Emissions from Combustion of Biogas (considers CH4 and N2O only)

Emissions from Flaring 1004 g CO2-eq/ 

mmBtu biogas

GREET1_201110

Value given is for 

Renewable Natural Gas

Emissions from Stationary 

Reciprocating Engines

9634 g CO2-eq/ 

mmBtu biogas

Value given is for 

Biogas

Emissions from Turbines 554 g CO2-eq/ 

mmBtu biogas

Value given is for 

Natural Gas; Emissions 

are assumed to be the 

same for Biogas

Emissions from Combined Cycle 

Gas Turbines

554 g CO2-eq/ 

mmBtu biogas

Value given is for 

Natural Gas; Emissions 

are assumed to be the 

same for Biogas

% of Gas-to-Energy Projects 

using Reciprocating Engines

70.6% of total 

capacity (in MW)

EPA LMOP 

Database of 

Operational 

Projects11

Percentages exclude 

microturbines, which 

are used in 0.3% of 

projects

% of Gas-to-Energy Projects 

using Turbines

23.8% of total 

capacity (in MW)

Includes both gas and 

steam turbines; 

excludes microturbines

% of Gas-to-Energy Projects 

using Combined Cycle Gas 

Turbines

5.6% of total 

capacity (in MW)

Weighted Average Emissions for 

Gas-to-Energy Projects

6965 g CO2-eq/ 

mmBtu biogas

Calculated from 

data referenced in 

this table

Upstream Emissions

U.S. Average Electricity 

Production

219,823 g CO2-eq/

mmBtu electricity RFS Final Rule12

Table 5, continued

Renewable Electricity Generation

Efficiency of Electricity 

Generation from Biogas

11,700 Btu 

biogas/kWh

EPA LMOP LFGE 

Benefits 

Calculator13

Weighted average of gasto-energy projects

Electricity-Ethanol Conversion 22.6 kW-h/gal 

ethanol RFS Final Rule6
14

Parasitic Loss Efficiencies for 

Reciprocating EngineGenerator Sets

93%

EPA LMOP Data14 Parasitic Loss Efficiencies for 

Turbine-Generator Sets

88% Use this value for 

Combined Cycle Gas 

Turbines as well

Electricity Demand for Biogas 

Collection Blowers

0.002 kWh/ft3For flaring and gas-toenergy projects

U.S. Average Transmission 

and Distribution Losses

6.6% U.S. EIA State 

Electricity Profiles15
15

B. Calculations for the Lifecycle Analysis of Renewable Electricity Produced from Waste 

Derived Biogasl.

The lifecycle analysis of renewable electricity produced from waste derived biogas 

focused on emissions associated with production of the fuel. We did not consider any emissions 

associated with transportation of the renewable electricity (although losses are accounted for), 

and no tailpipe emissions, so the only significant GHG emissions are derived from fuel 

production.

The first step in determining the lifecycle GHG emissions associated with production of 

renewable electricity from waste derived biogas was to determine how much electricity (in 

mmBtu) could be produced from a given amount of biogas (in mmBtu) based on values for the 

efficiency of typical electricity generation at landfills or waste digesters provided by EPA’s 

Landfill Methane Outreach Program (LMOP; Table 5) Table V.B.-1 in the Preamble outlines this 

calculation. We then apportioned the electricity generation proportionately according to the 

generation technology used (engines, turbines, combined cycle turbines) using the % of total 

capacity values given above. We used the parasitic loss efficiency values for engines and 

turbines (above) to determine the size of the parasitic losses for each category of electricity

generation and subtracted these values from the generation values above. We then summed the 

amounts of electricity remaining after these losses to determine the net amount of electricity 

produced from the biogas after parasitic losses. We subtracted the amount of this energy that 

would be used to power the biogas collection system. We also calculated how much of the 

electricity leaving the facility would be lost during transmission and distribution using data from 

EIA (see Table 5) and subtracted this amount from the total electricity. In the end, we 

determined that 0.236 mmBtu electricity would be delivered to the consumer for each mmBtu 

biogas combusted.

There were two components of electricity production that figured in the lifecycle 

analysis: on-site emissions and upstream emissions (Table V.B.-2 in the Preamble). Based on 

the relationship between electricity production and biogas combustion, the emissions factor for 

flaring, and the weighted average emissions factor for gas-to-energy projects listed above (Table 

5), we determined the amount by which on-site emissions at the biogas source would change. 

We used the value for the U.S. average GHG emissions from electricity production to calculate 

the amount of emissions in the flaring baseline scenario that are due to the grid electricity used to 

power the biogas collection system. This amount was assigned as a credit, since these emissions 

would be eliminated upon installation of a gas-to-energy project because renewable electricity 

would power the biogas collection system. Adding together the values for on-site and upstream 

emissions yields lifecycle GHG emissions of 12 kg CO2-eq/mmBtu electricity, which is an 87% 

 

l

The analysis was performed for biogas generated at a landfill offering a conservative estimate, as digester 

performance and biogas recovery is greater than landfill systems. Landfills lose approximately 20% of the total 

biomass to aerobic oxidation and as much as 30% to fugitive emissions.
16

reduction in emissions from the petroleum gasoline baseline (Table V.B.-2 in the Preamble). 

Because the drivetrains of electric vehicles are roughly 3 times as efficient as those of traditional 

internal combustion cars, we also calculated GHG emissions taking this improved efficiency into 

account. For these calculations, we determined the GHG emissions for each lifecycle stage per 

mmBtu of a “fuel equivalent”, assuming that it would take three times the energy of a liquid fuel 

to drive a car as far as a given amount of electricity. The lifecycle GHG emissions from 

electricity produced from waste derived biogas considering this factor are 4 kg CO2-eq/mmBtu 

fuel equivalent, or a 96% reduction in GHG emissions from the petroleum baselinem. According 

to both of these calculations, renewable electricity produced from waste derived biogas could 

qualify as either cellulosic or advanced biofuel.

C. Choice of Baseline for Waste Derived Biogas Treatment

When conducting a lifecycle analysis of greenhouse gas emissions for biofuels produced 

from waste derived biogas, it is important to choose an appropriate baseline for comparison. The 

baseline assumption is important because, as per the approach outlined in the March 2010 RFS 

rule,6the lifecycle calculations are based on a scenario approach. The results are determined 

based on a comparison of the biogas-based biofuel scenario to a baseline scenario that would 

have happened if the biogas was not used to produce transportation fuels. There are two main 

components of the baseline to consider, how use of waste-derived biogas for transportation fuels 

would impact waste disposal, and how it would impact the current or alternative treatment of the 

biogas. 

If waste management methods were impacted by use of biogas for transportation fuel, 

there could be indirect GHG emissions impacts. However, waste management policies are 

typically controlled by state and local governments, and there are many unique factors that 

influence these decisions. We have not seen any evidence or data to suggest that the RFS in 

general has had or will have a substantial impact on existing waste disposal practices across the 

U.S., and therefore we believe that there will not be significant GHG impacts associated with the 

biogas-based pathways adopted in this rule. Therefore no GHG impacts from waste disposal 

changes are included in the GHG analysis. This is consistent with the March 2010 RFS final rule

which concluded that municipal solid waste has no agricultural or land use change GHG 

emissions associated with its production. 

Biogas can be handled and/or processed in one of three primary ways: venting to the 

atmosphere, collection and flaring, and collection with use in a gas-to-energy or gas-to-fuel

project. Theoretically, any of the above scenarios could serve as a baseline scenario for our 

lifecycle analysis since all three occur at biogas source sites in the U.S. We first examine how 

the prevalence of flaring and gas-to-energy projects at landfills has changed over time and what 

 

m

The analysis was performed for biogas generated in a landfill system offering a conservative estimate, as digester 

performance and biogas recovery from digesters is greater than landfill systems.
17

impacts this has had on total methane emissions from landfills. We then outline the implications 

of using other possible baselines and discuss why we propose to use flaring as the baseline.

Historical uses for landfill biogas

Figure 3, below, shows how the uses of landfill biogas in the U.S. changed over a 20-year 

period from 1990 to 2010 based on data from the Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990-2010.16 During this time period, the amount of methane produced in landfills 

increased by 50%, however, the amount of methane released from these same landfills decreased 

by roughly 25% between 1990 and 2000 and has remained mostly constant since then. This 

large reduction in methane emissions is due primarily to the institution of EPA regulations, 

finalized in 1996, requiring large landfills to capture and treat their biogas.17 In parallel, the 

Landfill Methane Outreach Program (LMOP) has facilitated the development of an array of 

projects to collect and beneficially use landfill biogas, particularly from smaller, unregulated 

landfills.18 These emissions reductions were achieved via a 12-fold increase in the amount of 

methane that was flared from 1990 to 2010 and a 6-fold increase in the amount of methane used 

in gas-to-energy projects over the same time period (Figure 3). From 1990 to 2000, flaring and 

gas-to-energy projects increased more or less in tandem, but from about 2000 to 2005, gas-toenergy projects stabilized whereas flaring projects continued to increase. Leading up to 2010, 

the importance of flaring projects declined slightly whereas gas-to-energy projects increased 

substantially, such that in 2010, the amounts of methane destroyed by each type of project were

almost equivalent. Today, most of the methane that is still emitted derives from small landfills 

that are not required to capture and treat their biogas. Smaller proportions derive from leakage at 

landfills that do capture their biogas; EPA’s Compilation of Air Pollution Emission Factors (AP42) estimates collection efficiencies at such landfills typically range from 60% to 85%, with an 

average of 75% capture efficiency most commonly assumed.

19
18

Figure 3 – Amounts of methane generated at, emitted from, flared at, and used in gas-toenergy projects at landfills in the U.S. from 1990-2010.8

Possible alternative baseline scenarios

The results of our landfill biogas lifecycle analysis would have been very different if, 

instead of landfills that flare their biogas, we had chosen as a baseline either landfills that do not 

capture and treat (e.g., that vent) their biogas or those with existing gas-to-electricity projects. 

Here, we examine in detail the possible use of these three baselines for the renewable electricity

pathway.

Renewable Electricity Pathway. Table 5 below shows the results of lifecycle analyses for the 

renewable electricity pathway calculated using each of these three baseline scenarios. For the 

scenario involving conversion of a landfill that is venting its methane to a gas-to-energy project, 

the primary change is in the on-site emissions at the landfill. Under the venting scenario, the 

landfill would be releasing large amounts of methane, a potent greenhouse gas, to the 

atmosphere, so that collecting the methane to use in a gas-to-energy project would be 

accompanied by reductions in GHG emissions at the landfill of 1959 kgCO2-eq/mmBtu 

electricity (Table 6). Another, smaller change relative to the flaring baseline is that because 

venting landfills do not collect their biogas, they would not have been using any electricity to 

power blowers for gas collection, so this is not a factor in this scenario. The large reduction in 

methane emissions from the landfill results in a 2099% reduction in GHG emissions relative to 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

1990 1995 2000 2005 2010

M

eth

a

n

e (G

g

/

yr)

Year

Usage of methane

Generated

Emitted

Flared

Energy
19

the gasoline baseline upon conversion from a venting landfill to a landfill with a gas-toelectricity project. Consideration of the improved efficiency of electric vehicles results in a 

765% reduction in GHG emissions relative to the baseline (Table 6). This demonstrates that 

renewable electricity would easily qualify as a cellulosic biofuel if we used landfills that vented 

(did not treat) their biogas as the baseline for comparison.

Table 6 – Comparison of total lifecycle greenhouse gas emissions (kg CO2-eq/mmBtu 

electricity or gasoline) for renewable electricity produced from landfill biogas using three 

different baselines. Numbers in parentheses show values calculated per mmBtu fuel 

equivalent, which considers the greater efficiency of electric vehicles compared to gasoline 

vehicles.

Lifecycle Stage

From Landfills that 

Vented Biogas

From Landfills 

that Flared 

Biogas

From Landfills 

that Converted 

Biogas to 

Electricity

2005 

Gasoline 

Baseline

On-site emissions -1959 (-653) 25 (8)

Upstream (electricity 

production for 

blowers) -13 (-4)

New electricity 

generation 220 (73)

Total Emissions: -1959 (-653) 12 (4) 220 (73) 98

% Change from 

Gasoline Baseline -2099% (-765%) -87% (-96%) 124% (-25%)

The use of landfills that flare their biogas was discussed in the Preamble. Under this 

scenario, installation of electricity generators would result in increased on-site emissions due to 

less efficient combustion of generators versus flares. The other factor in this lifecycle analysis is 

reduced upstream emissions from grid electricity that was used to collect the biogas under a 

flaring scenario but would be replaced by renewable electricity upon installation of gas-toelectricity capability. Overall emissions using a flaring baseline were 12 kg CO2/mmBtu 

electricity, corresponding to an 87% reduction in GHG emissions versus the gasoline baseline. 

These reductions increase to 96% upon consideration of the increased efficiency of electric 

vehicles.

In contrast, if our baseline is landfills that already capture their biogas and use it to 

generate electricity, there are no physical changes at the landfill, and the only change is that this 

renewable electricity is tracked to transportation uses. In this case, the lifecycle GHG emissions 

increase relative to gasoline, as shown in Table 6. Because there is no physical change at the 

landfill, neither on-site emissions nor upstream electrical production to power gas collection 
20

blowers changes. However, this scenario could require additional electricity to be produced to 

replace that diverted for use in the transportation sector, and this new electricity, which we 

assume is derived from the grid, is accompanied by additional GHG emissions of 220 kg CO2-

eq/mmBtu electricity. The possible need for this additional electricity can be best understood by 

stepping through Figure 4 below. The left side of the figure shows the baseline situation in 

which combustion of biogas at a landfill generates electricity that is added to the shared electrical 

grid. Electricity from the grid is then withdrawn for a variety of uses. The transportation sector 

is completely separate from these sectors. However, if the electricity is directed to the 

transportation sector, as shown on the right side of the figure, all of these sectors are connected. 

EPA is required by the Energy Independence and Security Act of 2007 (EISA) to compare the 

GHG emissions of renewable fuels to those of the petroleum (gasoline or diesel) fuel baseline, 

which means that in order to link the transportation sector to the electrical sector, we compare 

electricity used in electrical vehicles (EVs) to gasoline vehicles. As shown in Figure 4, the net 

result is that additional electricity is withdrawn from the shared grid to power EVs (that replace 

gasoline vehicles). However, the demand for electricity for other uses would not change in this 

scenario (i.e., the balance of inputs and outputs from the grid box in Figure 4 must remain 

constant), which requires that the electricity diverted to transportation uses must be replaced with 

electricity from other sources. This electricity comes with additional GHG emissions of 220 kg 

CO2-eq/mmBtu electricity (Table 6) and results in a 124% increase in GHG emissions compared 

with the gasoline baseline, such that renewable electricity using a gas-to-energy baseline would 

not qualify as a renewable fuel under the RFS program. Consideration of the increased 

efficiency of electric vehicles reduces these emissions to a 25% decrease versus the baseline, 

which would allow the electricity to qualify as a renewable fuel but not as an advanced or

cellulosic biofuel.

Figure 4 – Comparison of scenarios used for evaluating the renewable electricity pathway 

when using an existing gas-to-energy project as a baseline. Black arrows represent fluxes 

of greenhouse gases or electricity that are relevant under both scenarios, red arrows 

represent fluxes that are important only when electricity is directed to transportation use,

and blue arrows are fluxes that decrease when electricity is directed to transportation uses.

However, in reality, the availability of additional renewable electricity would not have a 

direct impact on the numbers of EVs on the road and thus would not directly replace gasoline as 

a fuel. Instead, the renewable electricity would replace other sources of electricity (e.g. from 
21

coal- or natural gas-fired power plants) as power for EVs. This scenario would represent a 

diversion of renewable electricity from general uses to EVs, and a diversion of grid electricity

from general and EV uses to more general uses. This is effectively an exchange in the uses for 

the two types of electricity and would not result in any net change in GHG emissions from the 

baseline scenario. Thus, if we compare the GHG emissions of a gas-to-energy project used for 

transportation to one directed into the shared grid, there would be no change in GHG emissions. 

The electricity would not replace gasoline, there would be a 0% change from the petroleum 

baseline, and renewable electricity would still not qualify as a renewable fuel under the RFS

program. As stated above, EPA is required by statute to compare to a petroleum fuel baseline, 

resulting in a very different lifecycle analysis for the resulting renewable electricity. However, 

renewable electricity does not qualify as a renewable fuel under either scenario using a gas-toenergy baseline, so these different ways of considering this question lead to the same end result.

Justification for the choice of a flaring baseline scenario

Of these three possible baseline scenarios, we believe a flaring baseline is the most 

logical for the renewable electricity pathway. First, flaring is a possible scenario at all waste 

digesters. Second, assuming that the biogas is flared generally provides a worst case baseline as 

compared to a venting baseline. If sources that are using flaring will achieve a 60% GHG 

reduction when converting to electricity production, sources that are venting their methane or 

portions of their methane will certainly do so as well. As discussed in the Preamble, we do not 

consider landfills that vent their biogas to be a realistic baseline for any of these pathways, and 

the flaring baseline is the more conservative baseline compared to venting. Moreover, venting

landfills must be small in size and generate a relatively small amount of biogas, otherwise they

would be required to capture and treat their biogas. Accordingly, we expect that these landfills 

would not typically generate enough electricity from their biogas to justify the capital costs to 

install generators, so we expect that few of these landfills would convert to gas-to-energy

projects Therefore, these facilities are extremely unlikely to draw biogas from the small, 

unregulated landfills that currently vent their biogas. LMOP is currently working with some of 

the larger of these landfills to facilitate the installation of gas-to-energy projects, so such 

conversions are economically feasible for at least a subset of these landfills. However, use of 

venting landfills as a baseline would result in the same classification as would use of flaring 

landfills as a baseline. In both cases, the fuel produced from landfill biogas qualifies for the RFS 

program.

In contrast with the use of a venting baseline, if we used landfills with existing gas-toelectricity projects as a baseline, these landfill biogas-based biofuels would all fail to qualify for 

the RFS program. It is therefore especially important to consider which of these baselines is 

most appropriate. If we use a flaring baseline and qualify renewable electricity under the RFS 

program, it is possible that landfills with existing gas-to-energy projects may divert their 

renewable electricity for use as a transportation fuel. In these cases, the renewable electricity 
22

would already be produced and added to the grid so there would be no actual change at the 

landfill. Additionally, Figure 3 shows that gas-to-energy projects have been expanding since 

2003, which suggests that other incentives are already promoting installation of gas-to-energy

projects at landfills. In contrast, if we used facilities with existing gas-to-energy projects as the 

baseline for comparison, no renewable electricity from landfill biogas would qualify for the RFS

program. The use of this baseline would, therefore, exclude renewable electricity from facilities 

that converted from flaring (or even venting) from qualifying under RFS, even though these 

projects would be accompanied by real, large reductions in GHG emissions. Because of this 

result, we have determined that use of existing gas-to-energy projects as a baseline would not be 

appropriate. EPA believes that the Act should be interpreted and implemented to promote the 

growth in use of renewable fuels for transportation purposes, and to achieve GHG emissions 

reductions as a consequence. EPA believes that use of a flaring baseline best accomplishes these 

objectives. 

One option to deal with the discrepancy in lifecycle results between facilities that used to 

flare their biogas and those with existing gas-to-energy projects would be to qualify electricity 

produced from these different types of facilities differently. In this case, renewable electricity 

produced from landfills that installed new gas-to-electricity projects would qualify as a cellulosic 

biofuel whereas renewable electricity produced from landfills with existing gas-to-electricity 

projects would not qualify as renewable fuel under the RFS program. One problem with such a 

tiered approach is that landfills with existing gas-to-energy projects previously made the decision 

to install the gas-to-energy equipment either to replace flaring or instead of installing flares and 

thus are already best-performers. Likewise, under such a system, electricity from all new gas-toenergy facilities would qualify as cellulosic biofuels, but electricity from existing facilities would 

not. However, many of the new facilities may have installed gas-to-energy projects regardless of 

the RFS program, driven by the same incentives that motivated the existing facilities. Given the 

existence of other incentives to install gas-to-energy capabilities, discriminating between existing 

and new gas-to-energy projects seems arbitrary in this light. Additionally, the RFS program does 

not discriminate against facilities that are already producing renewable fuels, and in fact, the 

program grandfathers many existing facilities into the program. It would therefore appear 

inconsistent with the RFS program to discriminate between facilities that are already creating 

renewable electricity and those that convert from flaring to gas-to-energy projects.

We considered all of these factors in deciding on a baseline and believe that a flaring 

baseline is most appropriate. The choice of a single baseline for all renewable fuels produced 

from waste-derived biogas does not discriminate based on prior use of the biogas and is thus 

consistent with the qualified pathways that have been approved to date under the RFS program. 

As discussed above, most venting landfills are unlikely to install gas-to-energy projects because 

of their small size, thus venting is an inappropriate baseline. Likewise, using existing gas-toenergy projects as a baseline is also inappropriate because this would exclude projects with 

legitimate GHG emissions reductions (e.g., those that are currently venting or flaring) from 
23

qualifying. Use of landfills that flare their biogas as a baseline is appropriate because flaring is 

the main alternative to electricity generation or liquid fuel production at large landfills, and all 

existing and future gas-to-energy projects chose or will choose to generate electricity instead of 

simply flaring. Using this baseline, all renewable electricity generated from landfill biogas 

would qualify as cellulosic biofuel. Allowing renewable fuels produced from landfill biogas to 

generate RINs will provide an additional financial incentive for landfills to convert from flaring 

or venting to gas-to-energy projects and may thus help accelerate the adoption of this technology

and lead to additional GHG emissions reductions. 

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24

 

14 EPA LMOP Data.

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