1

Date May 20, 2013 

MEMORANDUM 

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

SUBJECT: Support for Classification of Biofuel Produced from Landfill Biogas as 

Cellulosic Biofuel and Summary of Lifecycle Analysis Assumptions and 

Calculations for Biofuels Produced from Landfill Biogas 

This memorandum provides additional support for EPA’s determination that all of the renewable 

fuel produced from landfill biogas should be classified as cellulosic biofuel. It also provides 

information on the key input assumptions used for the lifecycle analysis of biofuels produced 

from landfill biogas. Assumptions include on-site emissions from landfills, efficiencies of 

electricity generation, use and distribution, and co-product emissions. Data sources are 

presented to promote transparency for our lifecycle analysis. This memorandum also describes 

the calculations made for the lifecycle analysis of the fuels produced from landfill biogas and 

discusses in depth the choice of baseline used in the lifecycle analysis. 

 
2

Determination of the Cellulosic Composition of Landfill Biogas 

 In order to determine the cellulosic composition of the materials that are the source of 

landfill biogas, we consulted several scientific papers that investigated this topic. A number of 

studies determined the chemical composition of municipal solid waste (MSW), which is the 

source of the biogas in landfills. The average composition of MSW, determined by averaging 

the composition measured in 14 different studies, contains 38% cellulose, 8% hemicellulose and 

16% lignin, with smaller amounts of proteins, sugars and other organic materials (Table 1).1

 The 

average volatile solids composition was 69%. Measurement of volatile solids provides an 

estimate of the reactive portion of the MSW, with the remainder composed of metal, cement and 

other materials that will not yield methane in the landfill. For this reason, we are only concerned 

with the volatile solid (e.g. degradable organics) portion of the MSW. On average, 90% of the 

volatile solids were composed of cellulose, hemicellulose and lignin. However, MSW 

composition varies considerably (see standard deviations in Table 1), depending on, for example, 

the amount of yard waste versus food waste versus metal waste deposited. It is worth noting that 

these studies were published over 25 years (1982 to 2007), during a time period in which 

recycling expanded considerably, leading to significant changes in the types of materials 

deposited in landfills. Despite these changes, it is not clear from these studies that the percent of 

volatile solids in landfills that are cellulosic has changed during this time, although the 

comparative study did not explicitly explore this question.1 Overall, it is clear that the vast 

majority of volatile solids in landfills are cellulosic. 

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)2    

% Composition

(average of 14

studies)1

% 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 0a

Protein 3 ± 1 4 n.d. 8

Volatile Solids 69 ± 16 79 n.d. 100

Average % "Cellulosic"b 90 ± 30c 100d

     91 a

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

under anaerobic conditions. b

Calculated relative to the measured concentration of volatile solids. c

Standard error calculated by propagation of error. d

Note that this value is artificially high due to measurement uncertainties
3

However, the most important question for EPA’s purposes is what fraction of the landfill 

biogas comes from cellulosic components, rather than the percent of the MSW that is cellulosic. 

A study by Barlaz et al. (1989)2

 most directly addresses this question. In this study, the authors 

incubated a number of containers of MSW in the lab for up to 111 days, analyzing different 

containers periodically. Their results are outlined in Table 1 and Figure 1. The authors found 

that methane did 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 hemicelluloses (Fig. 1 top). Once the 

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

began (Fig. 1), and any remaining sugars were fermented to carboxylic acids. Large amounts of 

both cellulose and hemicellulose were lost during this period (Fig. 1 top), and lignin accumulated 

in the residue (Fig. 1 bottom). Overall, 71% of the cellulose and 77% of the hemicellulose were 

lost during the reaction, roughly half aerobically and half anaerobically, whereas a much smaller 

proportion of the lignin was lost (Table 1). Based on the abundance of the different 

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

cellulose and proteins), the authors determined that 91% of the total methane potential in this 

MSW sample was from cellulosic components. This indicates that almost all of the biogas from 

landfills comes from cellulosic components, namely cellulose and hemicellulose. 

 In another, related study, Eleazer et al. (1997)3

 studied the decomposition of a variety of 

components of MSW, including leaves, paper, food and MSW itself. They found a rough 

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 finding supports our conclusion that almost all of the biogas from 

a landfill comes from cellulosic components. 

 Overall, a study of one sample of MSW found that more than 90% of the biogas came 

from cellulosic components. While this number may vary 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 materials which should yield a large proportion of biogas from cellulose 

and hemicellulose. 

   
4

Time (days)

0 20 40 60 80 100

% of Total Dry Mass

0

20

40

60

80

100

0

20

40

60

80

100

Cumulative methane production (L/dry kg)

other

lignin

hemicellulose

cellulose

methane production

Figure 1. Chemical Composition of degrading MSW versus time.2 Top: % 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. Bottom: 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. 
5

Assumptions used in the Lifecycle Analysis 

Table 2 outlines key assumptions used in determining the lifecycle GHG emissions associated 

with biofuels produces from landfill biogas. EPA used these values in our lifecycle analysis as 

described in the subsequent sections. 

Table 2. Key Assumptions for the Lifecycle Analysis of Biofuels produced from Landfill 

Biogas 

Category Assumption Source Notes

     

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

Emissions from Flaring 1004 g CO2‐eq/

mmBtu biogas

GREET1_20114

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

Projects5

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 Rule6

  

   
6

Table 2, continued 

Renewable Electricity Generation      

Efficiency of Electricity

Generation from Biogas

11,700 Btu

biogas/kWh

EPA LMOP LFGE

Benefits Calculator7

Weighted average of gas‐

to‐energy projects

Electricity‐Ethanol Conversion 22.6 kW‐h/gal

ethanol RFS Final Rule6   

Parasitic Loss Efficiencies for

Reciprocating Engine‐

Generator Sets

93%

EPA LMOP Data8

  

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/ft3 For flaring and gas‐to‐

energy projects

U.S. Average Transmission

and Distribution Losses

6.6% U.S. EIA State

Electricity Profiles9

  

           

Wax Co‐Product Emissions         

Extraction Emissions for

Petroleum Wax

34,829 g CO2‐

eq/ bbl wax

DOE NETL

Petroleum Baseline

Study10

  

Transport Emissions for

Petroleum Wax

7482 g CO2‐eq/    

bbl wax

  

Refining Emissions for

Petroleum Wax

69,048 g CO2‐

eq/ bbl wax

  

Lifecycle GHG Emissions for

Petroleum Wax

778 g CO2‐eq/

kg wax

Calculated this

study

  

           

Transportation/Distribution and Tailpipe Emissions for Renewable Diesel and Naphtha

Transportation/Distribution

Emissions for F‐T Diesel

1468 g CO2‐eq/

mmBtu

GREET1_20114

  

Transportation/Distribution

Emissions for F‐T Naphtha

1678 g CO2‐eq/

mmBtu

  

Tailpipe Emissions (CH4 and

N2O only) for F‐T Diesel

700 g CO2‐eq/

mmBtu

RFS Final Rule6

CO2 emissions are ignored

because these are

biogenic

Tailpipe Emissions (CH4 and

N2O only) for F‐T Naphtha

1726 g CO2‐eq/

mmBtu

The value is for Petroleum

Gasoline; Naphtha is

assumed to have the

same emissions

 
7

Calculations for the Lifecycle Analysis of Renewable Electricity Produced from Landfill 

Biogas 

 The proposed lifecycle analysis of renewable electricity produced from landfill biogas 

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

from production of the feedstock because the biogas originates from municipal solid waste. 

Similarly, there are no 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 landfill 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 electricity generation from landfills provided by EPA’s Landfill Methane Outreach Program 

(LMOP; Table 2). 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 blowers used to collect 

the biogas from the landfill. We also calculated how much of the electricity leaving the facility 

would be lost during transmission and distribution using data from EIA (see Table 2) 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 

2), we determined the amount by which on-site emissions at the landfill 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 blowers at the landfill. 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 blowers. 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% 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 
8

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 landfill biogas considering this factor are 4 kg CO2-eq/mmBtu fuel 

equivalent, or a 96% reduction in GHG emissions from the petroleum baseline. According to 

both of these calculations, renewable electricity produced from landfill biogas would qualify as a 

cellulosic biofuel. 

Calculations for the Lifecycle Analysis of Renewable Diesel and Naphtha Produced from 

Landfill Biogas

 The lifecycle analysis of renewable diesel and naphtha produced from landfill biogas was 

based on confidential business information (CBI) submitted by the petitioning company, WM 

GTL. We therefore cannot show the detailed calculations associated with the analysis. In this 

section, we explain how we did these calculations and what assumptions we made for this 

analysis. For these fuels, as for the renewable electricity discussed above, we assumed there 

were no emissions associated with feedstock production since landfill biogas is derived from a 

waste. However, renewable diesel and naphtha do have emissions associated with fuel transport 

and tailpipe emissions, and we used emissions factors from the GREET model4

 and the RFS 

March 2010 rule6

 for Fischer-Tropsch diesel and naphtha to model these emissions (Table 2). 

 GHG emissions from production of these fuels broke down into three areas: changes in 

on-site emissions at the landfill, upstream emissions associated with electricity used by the 

facility, and a co-product credit for the co-produced wax. The petitioning company, WM GTL, 

Inc, submitted CBI detailing the input of biogas to the facility and the output of wax, renewable 

diesel and renewable naphtha from the facility, as well as the electricity usage of the facility. 

Based on this information, we calculated the yield of fuel per input of biogas (mmBtu 

fuel/mmBtu biogas). By combining these values with the emissions factor for flaring (the 

baseline scenario; Table 2), we calculated the amount by which on-site GHG emissions at the 

landfill would change upon installation of a gas-to-liquids facility. As discussed in the Preamble, 

based on several studies, we assumed there were no significant fugitive GHG emissions at the 

Fischer-Tropsch facility. We also used this information, along with the emissions factor for U.S. 

average electricity production (Table 2) to determine the upstream GHG emissions due to 

electricity usage at the facility. To calculate the size of the credit assigned for the wax coproduct, we first calculated the total emissions per kg of petroleum wax by summing the 

emissions due to extraction, transportation and refining of petroleum products based on data 

from the DOE NETL Petroleum Baseline Study (Table 2). We assumed that the density of the 

wax was 0.9 g/cm3. We then assumed that the F-T wax produced would displace petroleum wax 

and used the calculated emissions value for petroleum wax and the wax output per unit time of 

the facility to estimate the emissions displaced by this substitution. 
9

 Adding the emissions attributable to all three areas of production yields total fuel 

production emissions of 44 kg CO2-eq/mmBtu fuel (Table V.B.-3). The total lifecycle GHG 

emissions for these fuels, including emissions from transportation and distribution of the fuel and 

tailpipe emissions of methane and nitrous oxide, shown above, are 47 kg CO2-eq/mmBtu 

renewable diesel and 48 kg CO2-eq/mmBtu naphtha. These correspond to emissions reductions 

of 52% for renewable diesel and 51% for naphtha compared with the petroleum baseline (Table 

V.B.-3) assuming the facility does not produce electricity on-site. 

 In order to determine how much process electricity the facility would need to produce onsite in order to make the 60% threshold to qualify as a “cellulosic” fuel, we first multiplied the 

lifecycle GHG emissions of petroleum-based diesel and gasoline fuels by 0.4 to calculate the size 

of this 60% reduction in GHG emissions. This is the maximum lifecycle GHG emissions that 

would allow a biofuel to meet the cellulosic threshold. The difference between this value and the 

original value corresponds to the reduction in GHG emissions due to decreased use of grid 

electricity needed to meet the 60% threshold. We found that facilities must reduce their grid 

electricity usage by roughly 15%, with this electricity replaced by on-site electricity production, 

to meet the cellulosic threshold.a

Choice of Baseline for Landfill Biogas Treatment 

 As described in the Preamble, biogas from landfills 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 project. When conducting a lifecycle analysis of greenhouse gas 

emissions for biofuels produced from landfill 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,6

 the lifecycle calculations are based on a scenario 

approach. The results are determined based on a comparison of the landfill biogas-based biofuel 

scenario to a baseline scenario that would have happened if the landfill biogas was not used to 

produce transportation fuels. Theoretically, any of the above scenarios could serve as a baseline 

scenario for our lifecycle analysis since all three practices are currently in use in landfills in the 

U.S. In this section, we first examine how the prevalence of flaring and gas-to-energy projects 

has changed over time and what 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 2, 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 

                                                           

a Note that EPA is proposing a slightly more conservative requirement that facilities must generate at least 20% of

their electricity production on site, as discussed in the Preamble.
10

and Sinks: 1990-2010.11 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.12 In parallel, LMOP 

has facilitated the development of an array of projects to collect and beneficially use landfill 

biogas, particularly from smaller, unregulated landfills.13 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 2). From 1990 to 2000, flaring and gas-to-energy projects increased more or less 

in tandem, but from about 2000 to 2005, gas-to-energy 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 (AP-42) estimates collection efficiencies at such 

landfills typically range from 60% to 85%, with an average of 75% capture efficiency most 

commonly assumed.14

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

1990 1995 2000 2005 2010

Methane (Gg/yr)

Year

Usage of methane

Generated

Emitted

Flared

Energy
11

Figure 2. 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 before looking at the possible use of these baselines for the renewable diesel and 

naphtha pathways. 

Renewable Electricity Pathway. Table 2 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 3). 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 

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 3). 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 3. 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) 
12

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 detail in the Preamble, so we 

only provide an overview here. 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-to-electricity 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 3. Because there is no physical change at the 

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

blowers changes. However, this scenario requires additional electricity to be produced to replace 

that diverted for use in the transportation sector, and this new electricity is accompanied by 

additional GHG emissions of 220 kg CO2-eq/mmBtu electricity. The need for this additional 

electricity can be best understood by stepping through Figure 3 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 must consider that new electrical vehicles (EVs) replace gasoline 

vehicles. As shown in Figure 3, 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 3 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 3) and results in a 

124% increase in GHG emissions compared with the gasoline baseline, such that renewable 
13

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 a cellulosic biofuel.

Figure 3. 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 

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. 

Renewable Diesel and Naptha Pathways. As with renewable electricity, the lifecycle analyses 

for renewable diesel and naphtha made from landfill biogas would be very different using a 

baseline of landfills that vented their biogas or already had gas-to-energy projects, as opposed to 

the flaring baseline we used. The fuel production emissions were calculated using CBI 

submitted by the petitioning company, so we cannot show the breakdown of this calculation. 

However, as with renewable electricity, the biggest changes were in the on-site emissions. As 

discussed in the Preamble, using a flaring baseline, fuel production emissions derived from onCO2

landfill CH4

CO2

grid

various

uses

gasoline

CO2

landfill CH4

CO2

grid

EV various

uses

gasoline

Gas‐to‐Electricity baseline scenario: With electricity directed to transportation uses:
14

site emissions and upstream emissions due to use of grid electricity, with a co-product credit for 

wax produced at the facility. Total fuel production emissions were 44 kg CO2/mmBtu fuel, with 

emissions of 1-2 kg CO2/mmBtu for fuel transport and tailpipe emissions, for total GHG 

emissions of 47 kg CO2/mmBtu renewable diesel and 48 kg CO2/mmBtu naphta. These values 

correspond to 52% for renewable diesel and 51% for naphtha lifecycle GHG emissions 

reductions versus the petroleum baselines (Table V.B.-3 in the Preamble), qualifying these fuels 

as advanced biofuels.b Compared with calculations using a flaring baseline, on-site emissions 

were much lower (a large negative number) using a venting baseline because of the large 

reduction of methane emissions upon capture of biogas at the facility. On-site emissions were 

slightly lower when converting from a gas-to-electricity project to a gas-to-liquids project. This 

is because we assume minimal fugitive losses from the gas-to-liquids facility, as discussed in the 

Preamble, whereas electricity generators have small but significant emissions, outlined in Table 

2 above for three classes of generators. Additionally, when using a gas-to-electricity baseline, 

we must add in a term for emissions from the new electricity generation from the grid required to 

replace the lost electricity production. This electricity is lost when the biogas is diverted to 

production of liquid fuels instead of being used to generate electricity. The other factors in the 

analysis, emissions from purchased electricity used to power the facility and for the co-product 

credit, do not change under the different baseline scenarios. Overall, using a venting baseline, 

GHG emissions would be reduced by more than 1000% versus the petroleum baseline for both 

renewable diesel and naphtha, easily qualifying the fuels as cellulosic, with the values driven by 

large reductions in methane emissions from the landfill. Use of a gas-to-energy baseline greatly 

increases GHG emissions for renewable diesel and naphtha relative to the petroleum baselines, 

due primarily to the need to replace the electricity generation that once occurred at the facility. 

Under this baseline, these fuels would not qualify for the RFS2 program. 

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, renewable diesel and naphtha pathways. As discussed in the 

Preamble, we do not consider landfills that vent their biogas to be a realistic baseline for any of 

these pathways. These 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 most of these landfills would not 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. Similarly, gas-to-liquids projects require large capital 

expenditures and are only economically feasible given large, consistent sources of biogas. 

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 

                                                           

b As discussed above, if facilities produce 15% of the electricity used on-site, they reach the 60% GHG emissions 

reduction threshold. 
15

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 

(except that renewable diesel and naphtha would qualify as cellulosic fuels, not just advanced 

fuels). 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 be contracted with 

to provide renewable electricity for transportation purposes. In these cases, the renewable 

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

at the landfill. Additionally, Figure 2 shows that gas-to-energy projects have been expanding 

since 2003, which suggests that other incentives are already promoting installation of gas-toenergy 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 exclusion, we do not consider this to be an appropriate baseline. 

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. 
16

In addition to these considerations, there is an additional factor to consider for GTL 

projects. It requires significant capital expense to install a gas-to-electricity system at a landfill, 

and once the system is installed, the facility benefits from sale of the electricity to utilities and 

customers. Therefore, we do not expect any landfills that currently generate electricity from 

their biogas to discontinue their gas-to-electricity project in order to install a gas-to-liquids 

facility until their current contracts expire or the useful life of the electric generating equipment 

is over. For these reasons, flaring appears to be the only realistic baseline for renewable diesel 

and naphtha produced from landfill biogas. 

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 landfill 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 or gas-to-liquids 

projects because of their small size, thus venting is an inappropriate baseline. Likewise, using 

existing gas-to-energy 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 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 or gas-to-liquids projects chose or will choose 

to generate electricity or liquid biofuels instead of simply flaring. Using this baseline, all 

renewable electricity generated from landfill biogas would qualify as cellulosic biofuel. 

Similarly, renewable diesel or naphtha produced from landfill biogas would qualify as advanced 

or cellulosic, depending on whether the facility generated process electricity on-site. 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 or gas-toliquids projects and may thus help accelerate the adoption of this technology and lead to 

additional GHG emissions reductions. 

References 

                                                           

1 Lamborn, J. (2009) Characterisation of municipal solid waste composition into model inputs. 

Third International Workshop “Hydro-Physico-Mechanics of Landfills”, Braunschweig, 

Germany, 10-13 March 2009. http://www.lwi.tubs.de/hpm/docs/paper/11%20paper%20Lamborn.pdf

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 Barlaz, M.A., R.K. Ham, and D.M. Schaefer. (1989) Mass-balance analysis of anaerobically 

decomposed refuse. Journal of Environmental Engineering, 15(6) 1088-1102. 

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 Eleazer, William E., William S. Odle, III, Yu-Sheng Wang, and Morton A. Barlaz (1997) 

Biodegradability of municipal solid waste components in laboratory-scale landfills. 

Environmental Science & Technology, 31, 911-917. 
17

                                                                                                                                                                                                4

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Rule, 75 FR 14670, 14904 (March 26, 2010). 

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8

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9

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12 Standards of Performance for New Stationary Sources and Guidelines for Control of Existing 

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Chapter 2, Section 2.4: Municipal Solid Waste Landfills, 2.4-6. 

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