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 Li fecycle Analysis Assumptions and Calculations for Biofuels Produced from Landfill Biogas

This memorandum provides additional support for EP A’s determination that all of the renewable fuel produced from landfill biogas should be classifi ed as cellulosic biofuel. It also provides information on the key input assumptions used fo r the lifecycle analysis of biofuels produced from landfill biogas. Assumptions include on-si te emissions from landfills, efficiencies of electricity generation, use and distribution, a nd co-product emissions. Data sources are presented to promote transparency for our lifecy cle analysis. This memorandum also describes the calculations made for the lifecycle analysis of the fuels produced from landfill biogas and discusses in depth the ch oice 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, su gars and other organic materials (Table 1). 1 

### The average volatile solids compos ition 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 th e landfill. For this reason, we are only concerned with the volatile solid (e.g. degr adable organics) porti on of the MSW. On average, 90% of the volatile solids were composed of cellulose , hemicellulose and lignin. However, MSW composition varies considerably (see standard de viations 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 si gnificant changes in the types of materials deposited in landfills. Despite th ese changes, it is not clear from these studies that the percent of
volatile solids in landfills that are cellul osic has changed during this time, although the comparative study did not explic itly 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 de gradation experiment a nd 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 0 a

Protein 3 ± 1 4 n.d. 8
Volatile Solids 69 ± 16 79 n.d. 100 Average % "Cellulosic" b 90 ± 30 c 100 d 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 uncertainties3 

### 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 que stion. In this study, the authors
incubated a number of containers of MSW in the lab for up to 111 days, analyzing different containers periodically. Thei r results are outlined in Table 1 and Figure 1. The authors found that methane did not appear until day 41, indica ting that the initial decomposition was aerobic, involving loss of sugars to carbon di oxide 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 r eactors became anaerobic and methane production began (Fig. 1), and any remaining sugars were fermented to carboxylic ac ids. Large amounts of
both cellulose and hemicellulose we re lost during this period (Fig. 1 top), and lignin accumulated in the residue (Fig. 1 bottom). Overall, 71% of the cellulose a nd 77% of the hemicellulose were lost during the reaction, roughly ha lf aerobically and half anaerobi cally, 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 methan e 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 co mponents. 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 decompos ition 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 me thane 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 f ound that more than 90% of the biogas came from cellulosic components. While this numbe r may vary from location to location depending on the composition of the MSW, th e volatile solids in MSW appear to always contain a large proportion of cellulosic materials which should yield a large propor tion 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 100Cumulative methane production (L/dry kg) 

### other

lignin

hemicellulose

cellulose methane p

r od u ction



### 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. Methan e first appeared (at very low concentration) on day 41. Bottom: percent composition of MS W 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 cumulati ve production of methane in the reaction containers.5 

### Assumptions used in the Lifecycle Analysis

Table 2 outlines key assumptions used in dete rmining 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 An alysis of Biofuels produced from Landfill Biogas

Category Assumption Source Notes

On

‐ Site Emissions from Combustion of Biogas (considers CH 4 and N 2 O only)

Emissions from Flaring 1004 g CO 2 ‐ eq/

mmBtu biogas

GREET1_2011 4 Value given is for
Renewable Natural Gas

Emissions from Stationary Reciprocating Engines 9634 g CO 2 ‐ eq/

mmBtu biogas Value given is for Biogas

Emissions from Turbines 554 g CO 2 ‐ 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 CO 2 ‐ 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 Projects 5 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 CO 2 ‐ eq/

mmBtu biogas Calculated from
data referenced in
this table

Upstream Emissions

U.S. Average Electricity
Production 219,823 g CO 2 ‐ eq/

mmBtu electricity RFS Final Rule 66 

### Table 2, continued

Renewable Electricity Generation Efficiency of Electricity
Generation from Biogas 11,700 Btu biogas/kWh EPA LMOP LFGE Benefits Calculator 7 Weighted average of gas

‐ to

‐ energy projects
Electricity

‐ Ethanol Conversion 22.6 kW

‐ h/gal
ethanol RFS Final Rule 6

Parasitic Loss Efficiencies for Reciprocating Engine

‐ Generator Sets 93%

EPA LMOP Data 8 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/ft 3 For flaring and gas

‐ to

‐ energy projects

U.S. Average Transmission
and Distribution Losses 6.6% U.S. EIA State Electricity Profiles 9

Wax Co

‐ Product Emissions

Extraction Emissions for
Petroleum Wax 34,829 g CO 2 ‐ eq/ bbl wax

DOE NETL
Petroleum Baseline Study 10 Transport Emissions for
Petroleum Wax 7482 g CO 2 ‐ eq/
bbl wax
Refining Emissions for
Petroleum Wax 69,048 g CO 2 ‐ eq/ bbl wax
Lifecycle GHG Emissions for
Petroleum Wax 778 g CO 2 ‐ 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 CO 2 ‐ eq/

mmBtu GREET1_2011 4 Transportation/Distribution

Emissions for F

‐ T Naphtha 1678 g CO 2 ‐ eq/

mmBtu

Tailpipe Emissions (CH 4 and

N 2 O only) for F

‐ T Diesel 700 g CO 2 ‐ eq/

mmBtu

RFS Final Rule 6 CO 2 emissions are ignored
because these are biogenic Tailpipe Emissions (CH 4 and

N 2 O only) for F

‐ T Naphtha 1726 g CO 2 ‐ eq/

mmBtu The value is for Petroleum Gasoline; Naphtha is
assumed to have the

same emissions7 

### Calculations for the Lifecycle Analysis of Renewable Electricity Produced from Landfill Biogas

The proposed lifecycle analysis of renewabl e 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 bioga s originates from municipal solid waste. Similarly, there are no emissions associated with transportation of the renewable electricity (although losses are accounted for), and no tail pipe 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 accord ing to the generation technology used (engines, turbines, combined cycle turbines) using the % of total capac ity values given above. We used the parasitic loss efficiency values for engines and turbines (above) to de termine the size of the parasitic losses for each category of electricity generation and subtracted these values from the generation values above. We then summed th e 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 woul d be used to power the blowers used to collect the biogas from the landfill. We also calculated ho w much of the electricity leaving the facility would be lost during transmi ssion and distribution using data from EIA (see Table 2) and
subtracted this amount from the total electricit y. 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 electr icity production and biogas combus tion, the emissions factor for flaring, and the weighted average emissions factor for gas-to-ener gy projects listed above (Table 2), we determined the amount by which on-site emi ssions at the landfill would change. We used the value for the U.S. average GHG emissions fr om electricity producti on 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 installa tion 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 CO 2 

### -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 emissi ons taking this improved efficiency into8 

### account. For these calculations, we determined the GHG emissions for each lifecycle stage per mmBtu of a “fuel equivalent”, assuming that it w ould 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 CO 2 

### -eq/mmBtu fuel equivalent, or a 96% reduction in GHG emissions from the petrol eum 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 th e detailed calculations associated with the analysis. In this section, we explain how we did these calculati ons and what assumptions we made for this analysis. For these fuels, as for the renewabl e electricity discussed above, we assumed there were no emissions associated with feedstock pro duction 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 model 4 

### and the RFS
March 2010 rule 6 

### 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 emissi ons associated with electricity used by the facility, and a co-product cred it for the co-produced wax. Th e 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 yi eld 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 th e 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 info rmation, 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 calculat e 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/cm 3 

### . We then assumed that the F-T wa x produced would displace petroleum wax and used the calculated emissions value for pe troleum 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 CO 2 

### -eq/mmBtu fuel (Table V.B.-3). The total lifecycle GHG emissions for these fuels, includ ing emissions from transportation and distribution of the fuel and tailpipe emissions of methane and nitrous oxide, shown above, are 47 kg CO 2 

### -eq/mmBtu renewable diesel and 48 kg CO 2 

### -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 doe s 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 qua lify 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 thre shold. The difference between this value and the original value correspon ds 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 atmos phere, collection and flar ing, and collection with use in a gas-to-energy project. When c onducting 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 baseline s and discuss why we propose to use flaring as the baseline.

Historical uses for landfill biogas

Figure 2, below, shows how the uses of landf ill 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 remain ed mostly constant since then. This large reduction in methane emissions is due prim arily 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 proj ects over the same time period (Figure 2). From 1990 to 2000, flaring and ga s-to-energy projects in creased more or less in tandem, but from about 2000 to 2005, gas-to-e nergy projects stabilized whereas flaring projects continued to increase. Leading up to 2010, the importance of flaring projects declined slightly whereas gas-to-energy pr ojects increased subs tantially, such that in 2010, the amounts of methane destroyed by each type of project were a lmost 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 captu re 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 2010Methane(Gg/yr)



### Year 

## Usage of methane

Generated

Emitted

Flared

Energy11 

### Figure 2. Amounts of methane generated at, em itted 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 an alysis 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 ex isting gas-to-electricity projects. Here, we examine in detail the possible use of th ese 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 th e venting scenario, the landfill would be releasing la rge amounts of methane, a pot ent greenhouse gas, to the atmosphere, so that collecting the methane to use in a gas-to-ene rgy project would be accompanied by reductions in GHG emi ssions at the landfill of 1959 kgCO 2 

### -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 f actor 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 la ndfill with a gas-toelectricity project. Consideration of the improve d efficiency of electric vehicles results in a
765% reduction in GHG emissions relative to the ba seline (Table 3). This demonstrates that renewable electricity would easily qualify as a cell ulosic biofuel if we used landfills that vented (did not treat) their biogas as the baseline for comparison.

Table 3. Comparison of total life cycle greenhouse gas emissions (kg CO 2 

### -eq/mmBtu electricity or gasoline) for renewable electrici ty produced from landfill biogas using three different baselines. Numbers in parentheses show values calculated per mmBtu fuel equivalent, which considers the greater efficien cy 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 scenar io, installation of electr icity generators would
result in increased on-site emissions due to less e fficient combustion of generators versus flares. The other factor in this lifecycl e analysis is reduced upstream emi ssions from grid electricity that was used to collect the biogas under a flaring scenario but would be replaced by renewable electricity upon installation of ga s-to-electricity capability. Ov erall emissions using a flaring baseline were 12 kg CO 2 

### /mmBtu electricity, correspondi ng 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 require s additional electricity to be produced to replace that diverted for use in the transportation sect or, and this new electricity is accompanied by additional GHG emissions of 220 kg CO 2 

### -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 gr id. Electricity from the grid is then withdrawn for a variety of uses. The transportation sector is completely se parate 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 re newable fuels to those of the petroleum (gasoline or diesel) fuel baseline, which means th at 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, th e net result is that additional el ectricity 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 bala nce of inputs and outputs from the grid box in Figure 3 must remain constant), wh ich requires that the el ectricity diverted to transportation uses must be replaced with electricity from other s ources. This electricity comes with additional GHG emissions of 220 kg CO 2 

### -eq/mmBtu electricity (Tab le 3) and results in a 124% increase in GHG emissions compared with the gasoline baseline, such that renewable13 

### electricity using a gas-to-ener gy baseline would not qualify as a renewable fuel under the RFS program. Consideration of the increased efficien cy of electric vehicles reduces these emissions to a 25% decrease versus the baseline, which would allow the electric ity 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 a re relevant under both scenarios, red arrows represent fluxes that are importan t only when electricity is di rected to transportation use, and blue arrows are fluxes that decrease when electricity is directed to transportation uses.

However, in reality, the availability of a dditional renewable electri city 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 scen ario 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 a nd would not result in any net ch ange 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 in to the shared grid, there would be no change in GHG emissions. The electricity would not replace gasoline, ther e would be a 0% change from the petroleum baseline, and renewable electric ity 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 lif ecycle analysis for the resulting renewable electricity. However, renewable electricity does not quali fy as a renewable fuel under ei ther scenario using a gas-toenergy baseline, so these different ways of consid ering 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 bigg est changes were in the on-site emissions. As discussed in the Preamble, usi ng a flaring baseline, fuel produ ction emissions derived from onCO 2 landfill CH 4 CO 2

grid

various

uses gasoline CO 2

landfill CH 4 CO 2

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 CO 2 

### /mmBtu fuel, with emissions of 1-2 kg CO 2 

### /mmBtu for fuel transport and tailpipe emissions, for total GHG emissions of 47 kg CO 2 

### /mmBtu renewable diesel and 48 kg CO 2 

### /mmBtu naphta. These values correspond to 52% for renewable diesel a nd 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) us ing a venting baseline because of the large reduction of methane emissions upon capture of bi ogas at the facility. On-site emissions were slightly lower when converting from a gas-to-electri city 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 sm all but significant emi ssions, outlined in Table 2 above for three classes of generators. Additio nally, when using a gas-to-electricity baseline,
we must add in a term for emissions from the ne w electricity generation fro m the grid required to replace the lost electricity producti on. This electricity is lost when the biogas is diverted to production of liquid fuels instead of being used to generate electr icity. The other factors in the analysis, emissions from purchased electricity us ed 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 fu els as cellulosic, with the values driven by large reductions in methane emissions from the la ndfill. Use of a gas-to-energy baseline greatly
increases GHG emissions for renewable diesel and naphtha relative to th e petroleum baselines, due primarily to the need to replace the electricity generation that once occu rred 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 di esel and naphtha pathways. As discussed in the Preamble, we do not consider landfi lls 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 cap ture and treat their biogas. Accordingly, we expect that most of these landf ills would not generate enough el ectricity 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 projec ts. 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 unlikel y to draw biogas from the small, unregulated landfills that currently vent their biogas. LMOP is currently worki ng with some of the larger of
these landfills to facili tate the installation of gas-to-ener gy projects, so such conversions are

b As discussed above, if facilities produ ce 15% of the electricity used on-sit e, they reach the 60% GHG emissions
reduction threshold.15 

### economically feasible for at least a subset of these landf ills. 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 a nd naphtha would qualify as cellulo sic fuels, not just advanced fuels). In both cases, the fuel produced fr om landfill biogas qualifies for the RFS program.

In contrast with the use of a venting baseli ne, if we used landfills with existing gas-toelectricity projects as a baseline, these landfill biog as-based biofuels would all fail to qualify for the RFS program. It is therefore especially impor tant to consider which of these baselines is most appropriate. If we use a flaring baseli ne and qualify renewable electricity under the RFS program, it is possible that landfi lls with existing gas-to-energy pr ojects may be contracted with to provide renewable electricity for transporta tion purposes. In these cases, the renewable electricity would already be produc ed and added to the grid so there would be no actual change at the landfill. Additionally, Figure 2 shows th at gas-to-energy projects have been expanding since 2003, which suggests that other incentives ar e already promoting in stallation 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 elec tricity from landfill biogas would qualify for the RFS program. The use of this baseline would, therefore, exclude rene wable 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 th is to be an appr opriate baseline.

One option to deal with the discrepancy in lif ecycle results between fac ilities that used to flare their biogas and those with existing gas-to-e nergy projects would be to qualify electricity produced from these different types of facilities di fferently. In this case, renewable electricity produced from landfills that installed new gas-to-ele ctricity 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 und er the RFS program. One problem with such a tiered approach is that landfills with existing ga s-to-energy projects previously made the decision to install the gas-to-energy equipm ent 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 electric ity 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-e nergy capabilities, discri minating between existing and new gas-to-energy projects seems arbitrary in this light. Additionally, the RFS program does not discriminate against facilitie s that are already producing rene wable fuels, and in fact, the program grandfathers many existi ng facilities into the program. It would therefore appear inconsistent with the RFS program to discrimina te between facilities th at are already creating renewable electricity and those that convert from flaring to ga s-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 benef its from sale of the electricity to utilities and customers. Therefore, we do not expect any la ndfills 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 contract s 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 deci ding on a baseline and be lieve 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 a nd is thus consistent with the qualified pathways that have been approved to date under the RFS program. As discussed above, most venting landf ills are unlikely to install ga s-to-energy or gas-to-liquids projects because of their small size, thus venti ng is an inappropriate ba seline. Likewise, using existing gas-to-energy projects as a baseline is also inappropriate because this would exclude projects with legitimate GHG emissions reduction s (e.g., those that are currently venting or flaring) from qualifying. Use of landfills that fl are their biogas as a baseline is appropriate because flaring is the main alte rnative to electricity generation or liquid fuel production at large landfills, and all existing and future gas-to-energ y or gas-to-liquids projects chose or will choose to generate electricity or liqui d 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 electri city 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 municipa l 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

2 

### Barlaz, M.A., R.K. Ham, and D.M. Schaefer. (1989) Mass-balance analys is of anaerobically decomposed refuse. Journal of E nvironmental Engineering, 15(6) 1088-1102.

3 

### Eleazer, William E., William S. Odle, III, Yu-Sheng Wang, and Morton A. Barlaz (1997) Biodegradability of municipal solid wast e components in laboratory-scale landfills. Environmental Science & Technology, 31, 911-917.17 4 

### Argonne National Laboratory (2011) Greenhouse Gases, Regulat ed Emissions, and Energy Use in Tranportation Model (GREET), Vers ion 1 2011, http://g reet.es.anl.gov/

5 

### Environmental Protection Agency (EPA), Landfill Methane Outreach Program (LMOP), 2011. Spreadsheet of Operational LFG energy pr ojects – Electricity , Accessed 12/29/2011, http://epa.gov/lmop/projects-ca ndidates/operational.html

6 

### Regulation of Fuels and Fuel Additives: Cha nges to Renewable Fuel Standard Program; Final Rule, 75 FR 14670, 14904 (March 26, 2010).

7 

### EPA LMOP (2012) LFG Energy Benefits Ca lculator. http://epa.gov/lmop/projectscandidates/lfge-calculator.html

8 

### EPA LMOP Data.

9 

### Energy Information Agency (EIA). 2011. Unite d States Electricity Profile 2009 – Table 10: Supply and Disposition of Electricit y, 1990 Through 2009 (Million Kilowatthours), Accessed 12/29/2011, http://www.eia.gov/electr icity/state/uniteds tates/index.cfm

10 

### Department of Energy: National Energy T echnology Laboratory. ( 2009) NETL: PetroleumBased Fuels Life Cycle Greenhouse Ga s Analysis - 2005 Baseline Model. www.netl.doe.gov/energy-analyses.

11 

### EPA. 2012. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010, Annex 3: Methodological Descriptions for Additional Source or Sink Categories. http://epa.gov/climatechange/emi ssions/usinventoryreport.html

12 

### Standards of Performance for New Stationary Sources and Guidelines for Control of Existing Sources: Municipal Solid Waste Landfills, 61 FR 9905, 9944 (March 12, 1996).

13 

### EPA LMOP webpage, www.epa.gov/lmop

14 

### EPA. 1998. AP-42 Compilation of Air Pollutio n Emission Factors, Fi fth Edition. Volume 1, Chapter 2, Section 2.4: Municipal Solid Waste Landfills, 2.4-6. http://www.epa.gov/ttn/chief/ap42/ch02/final/c02s04.pdf