Source: https://www.federalregister.gov/articles/2012/01/05/2011-31580/regulation-of-fuels-and-fuel-additives-identification-of-additional-qualifying-renewable-fuel
Timestamp: 2015-09-02 14:52:32
Document Index: 2948773

Matched Legal Cases: ['§ 40', '§ 80', '§ 80', '§ 80', '§ 80', '§ 80', '§ 80', '§ 80', '§ 80', '§ 80', '§ 80', '§ 40', '§ 40', '§ 40', '§ 40', '§ 40', '§ 80', '§ 80', '§ 80', '§ 80', '§ 80']

Federal Register | Regulation of Fuels and Fuel Additives: Identification of Additional Qualifying Renewable Fuel Pathways Under the Renewable Fuel Standard Program
-727 (29 pages)
Document Number: 2011-31580
Shorter URL: https://federalregister.gov/a/2011-31580 Related Topics
Addition of New Fuel Pathways Under the Renewable Fuel Standard (RFS2) Program 5 actions from January 29th, 2008 to February 6th, 2012
Final Rule for 60th ITC List
77 FR 700
Direct Final Action Comment Period End
Table 5—Fuel Production Lifecycle GHG Emissions (kgCO2 e/mmBtu)34
Table 14—Excerpts of Existing Fuel Pathways From § 40 CFR 80.1426
Table 15—Ranges of FFA in Biodiesel Feedstocks 63 64
Fax:[Insert fax number].
In the “Proposed Rules” section of today's Federal Register, we are publishing a separate document that will serve as the proposed rule to update Table 1 of § 80.1426 to add any additional renewable fuel production pathways or regulatory provisions which may be withdrawn from the direct final rule. We will not institute a second comment period on this action. Any parties interested in commenting must do so at this time. For further information about commenting on this rule, see the ADDRESSES section of this document. We will address all public comments in any subsequent final rule based on the proposed rule.
NAICS1Codes
SIC2Codes
1North American Industry Classification System (NAICS)
2Standard Industrial Classification (SIC) system code.
Ethyl alcohol manufacturing.
Other basic organic chemical manufacturing.
IV. Identification of additional qualifying renewable fuel pathways under the renewable fuel standard (RFS) program Back to Top
Biodiesel and renewable diesel (including jet fuel and heating oil) —qualifying as biomass-based diesel and advanced biofuel
Naphtha and liquefied petroleum gas (LPG) —qualifying as advanced biofuel
Ethanol, renewable diesel (including renewable jet fuel and heating oil), and naphtha —qualifying as cellulosic biofuel
Using the following processes — all utilizing natural gas, biogas, and/or biomass as the only process energy sources —qualifying as cellulosic biofuel:
This direct final rule adds these pathways to Table 1 to § 80.1426 and assigns each pathway one or more D-Codes. This final rule allows producers or importers of fuel produced under these pathways to generate Renewable Identification Numbers (RINs) in accordance with the RFS regulations, providing that the fuel meets other definitional criteria for renewable fuel.
Camelina sativa (camelina) is an oilseed crop within the flowering plant family Brassicaceae that is native to Northern Europe and Central Asia. Camelina's suitability to northern climates and low moisture requirements allows it to be grown in areas that are unsuitable for other major oilseed crops such as soybeans, sunflower, and canola/rapeseed. Camelina also requires the use of little to no tillage.
Compared to many other oilseeds, camelina has a relatively short growing season (less than 100 days), and can be grown either as a spring annual or in the winter in milder climates.
Camelina can also be used to break the continuous planting cycle of certain grains, effectively reducing the disease, insect, and weed pressure in fields planted with such grains (like wheat) in the following year.
Although camelina has been cultivated in Europe in the past for use as food, medicine, and as a source for lamp oil, commercial production using modern agricultural techniques has been limited.
In addition to being used as a renewable fuel feedstock, small quantities of camelina (less than 5% of total U.S. camelina production) are currently used as a dietary supplement and in the cosmetics industry. Approximately 95% of current US production of camelina has been used for testing purposes to evaluate its use as a feedstock to produce primarily jet fuel.
The FDA has not approved camelina for food uses, although it has approved the inclusion of certain quantities of camelina meal in commercial feed.
Camelina is currently being grown on approximately 50,000 acres of land in the U.S., primarily in Montana, eastern Washington, and the Dakotas.
USDA does not systematically collect camelina production information; therefore data on historical acreage is limited. However, available information indicates that camelina has been grown on trial plots in 12 U.S. states.
Current market conditions indicate that camelina will most likely be grown in rotation with wheat on dryland wheat acres replacing a period that they would otherwise be left fallow.
In areas with lower precipitation, dryland wheat farmers currently leave acres fallow once every three to four years to allow additional moisture and nutrients to accumulate and to control pests. Current research indicates that camelina could be introduced into this rotation in certain areas without adversely impacting moisture or nutrient accumulation (see Figure 1). Because camelina has shallow roots with drought resistant characteristics, the land can be returned to wheat cultivation the following year with moisture and soil nutrients intact quantitatively similar to a fallow year.
In addition, camelina uses the same equipment for harvesting as wheat; therefore, farmers would not need to invest in new equipment to add camelina to the rotation with wheat.
USDA estimates that there are approximately 60 million acres of wheat in the U.S.
USDA and wheat state cooperative extension reports through 2008 indicate that 83% of U.S. wheat production is under non-irrigated, dryland conditions. Of the approximately 50 million non-irrigated acres, at least 45% are estimated to follow a wheat/fallow rotation. Thus, approximately 22 million acres are potentially suitable for camelina production. However, according to industry projections, only about 9 million of these wheat/fallow acres have the appropriate climate, soil profile, and market access for camelina production.
Based on these projections of land availability, EPA estimates that at current yields (approximately 800 pounds per acre), approximately 100 million gallons (MG) of camelina-based renewable fuels could be produced with camelina grown in rotation with existing crop acres without having direct land use change impacts. Also, since camelina will likely be grown on fallow land and thus not displace any other crop and since camelina currently does not have other significant markets, expanding production and use of camelina for biofuel purposes is not likely to have other agricultural market impacts and therefore, would not result in any significant indirect land use impacts.
This assessment is based on a three year rotation cycle in which only one third of the 9 million available acres would be fallow in any given year. Yields of camelina are expected to approach the yields of similar oilseed crops over the next few years, as experience with growing camelina improves cultivation practices and the application of existing technologies are more widely adopted.
Yields of 1650 pounds per acre have been achieved on test plots, and are in line with expected yields of other oilseeds such as canola/rapeseed. Assuming average US yields of 1650 pounds per acre,
approximately 200 MG of camelina-based renewable fuels could be produced on existing wheat/fallow acres. Finally, if investment in new seed technology allows yields to increase to levels assumed by Shonnard et al (3000 pounds per acre), approximately 400 MG of camelina-based renewable fuels could be produced on existing acres.
Depending on future crop yields, we project that roughly 100 MG to 400 MG of camelina-based biofuels could be produced on currently fallow land with no impacts on land use.
Although wheat can in some cases be grown in rotation with other crops such as lentils, flax, peas, garbanzo, and millet, cost and benefit analysis indicate that camelina is most likely to be planted on soil with lower moisture and nutrients where other rotation crops are not viable.
Because expected returns on camelina are relatively uncertain, farmers are not expected to grow camelina on land that would otherwise be used to grow cash crops with well established prices and markets. Instead, farmers are most likely to grow camelina on land that would otherwise be left fallow for a season. The opportunity cost of growing camelina on this type of land is much lower. As previously discussed, this type of land represents the 9 million acres currently being targeted for camelina production. Current returns on camelina are relatively low ($13.24 per acre), given average yields of approximately 800 pounds per acre and the current contract price of $0.145 per pound.
See Table 1. For comparison purposes, the USDA projections for wheat returns are between $88-$105 per acre between 2010 and 2020. Over time, advancements in seed technology, improvements in planting and harvesting techniques, and higher input usage could significantly increase future camelina yields and returns.
Table 1—Camelina Costs and Returns Back to Top
2010 Camelina22
2022 Camelina23
2030 Camelina24
Glysophate (Fall)
16 oz. ( $0.39/oz)
Glysophate (Spring)
12 oz ( $0.67/oz)
$5.76 (4 lbs/acre)
$7.20 (5 lbs/acre)
$7.20 (5 lbs/acre).
$1/pd
$25.00 (25 lb/acre)
$40.00 (40 lb/acre)
$75 (75 lbs/acre).
$15.00 (15 lb/acre)
$15 (15 lb/acre).
$119.20.
Planting Trip
$154.20.
Total Revenue at avg prod/pricing
$115.80.
While replacing the fallow period in a wheat rotation is expected to be the primary means by which the majority of all domestic camelina is commercially harvested in the short- to medium- term, in the long term camelina may expand to other regions and growing methods.
For example, if camelina production expanded beyond the 9 million acres assumed available from wheat fallow land, it could impact other crops. However, as discussed above this is not likely to happen in the near term due to uncertainties in camelina financial returns. Camelina production could also occur in areas where wheat is not commonly grown. For example, testing of camelina production has occurred in Florida in rotation with kanaf, peanuts, cotton, and corn. However, only 200 acres of camelina were harvested in 2010 in Florida. While Florida acres of camelina are expected to be higher in 2011, very little research has been done on growing camelina in Florida. For example, little is known about potential seedling disease in Florida or how camelina may be affected differently than in colder climates.
We also looked at the seed crushing and oil extraction process and compared the lifecycle GHG emissions from this stage for soybean oil and camelina oil. As discussed above, camelina seeds produce more oil per pound than soybeans. As a result, the lifecycle GHG emissions associated with crushing and oil extraction are lower for camelina than soybeans, per pound of vegetable oil produced. Table 3 summarizes data on inputs, outputs and estimated lifecycle GHG emissions from crushing and oil extraction. The data on soybean crushing comes from the RFS2 final rule, based on a process model developed by USDA-ARS.
Table 3—Comparison of Camelina and Soybean Crushing and Oil Extraction Back to Top
Natural Gas & Steam
gCO2e/lb refined oil.
The same feedstocks currently used for biodiesel production can also be used in a hydrotreating process to produce a slate of products, including diesel fuel, heating oil (defined as No. 1 or No. 2 diesel), jet fuel, naphtha, LPG, and propane. Since the term renewable diesel is defined to include the products diesel fuel, jet fuel and heating oil, the following discussion uses the term renewable diesel to also include diesel fuel, jet fuel and heating oil. The yield of renewable diesel is relatively insensitive to feedstock source.
To account for the case where RINs are generated for the jet fuel, naphtha and LPG in addition to the diesel replacement fuel produced, we would not give the diesel replacement fuel a displacement credit for these co-products. Instead, the lifecycle GHG emissions from the fuel production processes would be allocated to each of the RIN-generating products on an energy content basis. This has the effect of tending to increase the fuel production lifecycle GHG emissions associated with the diesel replacement fuel because there are less co-product displacement credits to assign than would be the case if RINs were not generated for the co-products.
We have evaluated information about the lifecycle GHG emissions associated with the hydrotreating process which can be maximized for jet fuel or diesel replacement fuel production. Our evaluation considers information published in peer-reviewed journal articles and publicly available literature (Kalnes et al, 2010, Pearlson, M., N., 2011,
Stratton et al., 2010, Huo et al., 2008).
Our analysis of GHG emissions from the hydrotreating process is based on the mass and energy balance data in Pearlson (2011) which analyzes a hydrotreating process maximized for diesel replacement fuel production and a hydrotreating process maximized for jet fuel production.
Maximized for diesel fuel
Hydrotreating Maximized for Diesel
Diesel Jet Fuel.
Hydrotreating Maximized for Jet Fuel
Jet Fuel Diesel.
As discussedabove, for a process that produces more than one RIN-generating output (e.g., the hydrotreating process summarized in Table 5 which produces diesel replacement fuel, jet fuel, and naphtha) we allocate lifecycle GHG emissions to the RIN generating products on an energy equivalent basis. We then normalize the allocated lifecycle GHG emissions per mmBtu of each fuel product. Therefore, each RIN-generating product from the same process will be assigned equal lifecycle GHG emissions per mmBtu from fuel processing. For example, based on the lifecycle GHG estimates in Table 5 for the hydrotreating process maximized to produce jet fuel, the jet fuel and the naphtha both have lifecycle GHG emissions of 14 kgCO 2 e/mmBtu. For the same reasons, the lifecycle GHG emissions from the jet fuel and naphtha will stay equivalent if we consider upstream GHG emissions, such as emissions associated with camelina cultivation and harvesting. Lifecycle GHG emissions from fuel distribution and use could be somewhat different for the jet fuel and naphtha, but since these stages produce a relatively small share of the emissions related to the full fuel lifecycle, the overall difference will be quite small.
§ 80.1401 of the RFS regulations currently defines non-ester renewable diesel as a fuel that is not a mono-alkyl ester and which can be used in an engine designed to operate on conventional diesel fuel or be heating oil or jet fuel. The reference to jet fuel in this definition was added by direct final rule dated May 10, 2010. Table 1 to § 80.1426 identifies approved fuel pathways by fuel type, feedstock source and fuel production processes. The table, which was largely adopted as part of the March 26, 2010 RFS2 final rule, identifies jet fuel and renewable diesel as separate fuel types. Accordingly, in light of the revised definition of renewable diesel enacted after the RFS2 rule, there is ambiguity regarding the extent to which references in Table 1 to “renewable diesel” include jet fuel.
In cases where there are no pathways for generating RINs for the co-products from the hydrotreating process it would be appropriate to use the displacement method for capturing the credits of co-products produced. This is the case for most of the original feedstocks included in Table 1 to § 80.1426.
As was discussed previously, if the displacement approach is used when jet fuel is the primary product produced it results in lower emissions then the production maximized for diesel fuel production. Therefore, since the hydrotreating process maximized for diesel fuel meets the 50% lifecycle GHG threshold for the feedstocks in question, the process maximized for jet fuel would also qualify.
For this rulemaking, EPA considered the lifecycle GHG impacts of three new types of high-yielding perennial grasses similar in cellulosic composition to switchgrass and comparable in status as an emerging energy crop. Energy cane (related to sugarcane), giant reed (Arundo donax), and napiergrass (pennisetum purpureum), also known as elephant grass. In the proposed and final RFS2 rule, EPA analyzed the lifecycle GHG impacts of producing and using cellulosic ethanol and cellulosic Fischer-Tropsch diesel from switchgrass. The midpoint of the range of switchgrass results showed a 110% GHG reduction (range of 102%-117%) for cellulosic ethanol (biochemical process), a 72% (range of −64% to −79%) reduction for cellulosic ethanol (thermochemical process), and a 71% (range of −62% to −77%) reduction for cellulosic diesel (F-T process) compared to the petroleum baseline. In the RFS2 final rule, we indicated that some feedstock sources can be determined to be similar enough to those modeled that the modeled results could reasonably be extended to these similar feedstock types. For instance, information on miscanthus indicated that this perennial grass will yield more feedstock per acre than the modeled switchgrass feedstock without additional inputs with GHG implications (such as fertilizer). Therefore in the final rule EPA concluded that since biofuel made from the cellulosic biomass in switchgrass was found to satisfy the 60% GHG reduction threshold for cellulosic biofuel, biofuel produced form the cellulosic biomass in miscanthus would also comply. In the final rule we included cellulosic biomass from switchgrass and miscanthus as eligible feedstocks for the cellulosic biofuel pathways included in Table 1 to § 80.1426.
We did not include other perennial grasses such as energy cane, giant reed, or napiergrass as feedstocks for the cellulosic biofuel pathways in Table 1 at that time, since we did not have sufficient time to adequately consider them. Based in part on additional information received through the petition process for EPA approval of energy cane, giant reed, and napiergrass pathways, EPA has evaluated these feedstocks and is now including the cellulose, hemicelluloses and lignin portions of renewable biomass from energy cane, giant reed, and napiergrass in Table 1 to § 80.1426 as approved feedstocks for cellulosic biofuel pathways.
Giant reed refers to the perennial grass Arundo donax of the Gramineae family. Giant reed thrives in subtropical and warm-temperate areas and is grown throughout Asia, southern Europe, Africa, the Middle East, and warmer U.S. states for multiple uses such as paper and pulp, musical instruments, rayon, particle boards, erosion control, and ornamental purposes. 36 37
Based in part on discussions with industry, EPA anticipates continued development of giant reed as an energy crop particularly in the Mediterranean region and warmer U.S. states.
Napiergrass is a tall bunch-type grass that has traditionally been grown as a high-yielding forage crop across the wet tropics. There is a considerable body of agronomic research on the production of napiergrass as a forage crop. More recently, researchers have investigated ways to maximize traits desirable in bioenergy crops. Practices have been developed by USDA and other researchers to lower fertilization rates and increase biomass production. Based in part on discussions with industry, EPA anticipates continued development of napiergrass as an energy crop particularly in Gulf Coast Region of the United States (more specifically the growing region includes Florida and southern portions of Texas, Louisiana, Georgia, Alabama and Mississippi).
For the purposes of analyzing the GHG emissions from energy cane, giant reed, and napiergrass production, EPA examined crop yields and production inputs in relation to switchgrass to assess the relative GHG impacts. Current national yields for switchgrass are approximately 4.5 to 5 dry tons per acre. Average energy cane yields exceed switchgrass yields in both unfertilized and fertilized trails conducted in the southern United States. Unfertilized yields are around 7.3 dry tons per acre while fertilized trials show energy cane yields range from approximately 11 to 20 dry tons per acre.
Until recently there have been few efforts to improve energy cane yields, but several energy cane development programs are now underway to further increase its biomass productivity. Giant reed field trials conducted in Alabama over a 9-year period showed an average yield of 15 dry tons per acre with no nitrogen fertilizer applied after the first year.
Fertilized field trials have shown yields around 13 to 28 dry tons per acre in Spain, and 12 dry tons per acre in Italy (based on annual yields of 3, 14, 17, 16, and 12).
High yields have been demonstrated with unimproved giant reed populations, and therefore there is potential for increased biomass productivity through improved growing methods and breeding efforts.
Napiergrass field trials have produced dry biomass yields exceeding 20 tons per acre per year in north-central Florida. Using currently available technology, average yields for full-season napiergrass should range from 14 to 18 tons per acre with future improvements expected. Yield depends greatly on the type of cultivar and the amount and distribution of rainfall and fertilization rates. There is potential for increased biomass productivity through improved growing methods and breeding efforts.
In general, the yields for all three of the energy grasses considered here will have higher yields than switchgrass, so from a crop yield perspective, the switchgrass analysis would be a conservative estimate when comparing against the energy cane, napier grass, and giant reed pathways.
Furthermore, EPA's analysis of switchgrass for the RFS2 rulemaking assumed a 2% annual increase in yield that would result in an average national yield of 6.6 dry tons per acre in 2022. EPA anticipates a similar yield improvement for energy cane, giant reed, and napiergrass due to their similarity as perennial grasses and their comparable status as energy crops in their early stages of development. Given this, our analysis assumes an average energy cane yield of 19 dry tons per acre in the southern United States by 2022; an average giant reed yield of approximately 18 dry tons per acre by 2022; and an average napiergrass yield of approximately 20 dry tons per acre by 2022.
The ethanol yield for all of the grasses is approximately the same so the higher crop yields for energy cane, napiergrass, and giant reed result directly in greater ethanol production compared to switchgrass per acre of production.
Applying the GHG emission factors used in the RFS2 final rule, energy cane production results in slightly higher GHG emissions relative to switchgrass production (an increase of approximately 4 kg CO 2 eq/mmbtu). Giant reed production results in slightly lower GHG emissions relative to switchgrass production (a decrease of approximately 2 kg CO 2 eq/mmbtu). Napiergrass production results in slightly higher GHG emissions relative to switchgrass production (an increase of approximately 6 kg CO 2 eq/mmbtu).
Table 6—Production Inputs and GHG Emissions for Switchgrass, Energy Cane, Giant Reed, and Napiergrass (Biochemical Ethanol), 2022 Back to Top
3,29 kgCO 2 e/ton of nitrogen
3.6 kgCO 2 e
2 kgCO 2 e
1 kgCO 2 e
2.4 kgCO 2 e.
7.6 kgCO 2 e
5.9 kgCO 2 e
4.8 kgCO 2 e
7.6 kgCO 2 e.
1,12 kgCO 2 e/ton of phosphate
0.5 kgCO 2 e
0.3 kgCO 2 e
0.6 kgCO 2 e
0.1 kgCO 2 e.
743 kgCO 2 e/ton of potassium
0.2 kgCO 2 e
0.4 kgCO 2 e
0.2 kgCO 2 e.
23,45 kgCO 2 e/tons of herbicide
0.003 kgCO 2 e
1.8 kgCO 2 e
0.03 kgCO 2 e
0.6 kgCO 2 e.
Insecticide (average across regions)
27,22 kgCO 2 e/tons of pesticide
0.04 kgCO 2 e
0 kgCO 2 e
0 kgCO 2 e.
408 kgCO 2 e/ton of lime
3.1 kgCO 2 e
2.9 kgCO 2 e.
97 kgCO 2 e/mmBtu diesel
0.8 kgCO 2 e
2.4 kgCO 2 e
2.5 kgCO 2 e
2.2 kgCO 2 e.
Electricity (irrigation)
220 kgCO 2 e/mmBtu
1.6 kgCO 2 e
2.7 kgCO 2 e.
13 kgCO 2 e/mmBtu
17 kgCO 2 e/mmBtu
11 kgCO 2 e/mmBtu
19 kgCO 2 e/mmBtu.
Energy cane, giant reed, and napiergrass are suitable for the same conversion processes as other cellulosic feedstocks, such as switchgrass and corn stover. Currently available information on energy cane, giant reed, and napiergrass composition shows that their hemicellulose, cellulose, and lignin content are comparable to other crops that qualify under the RFS regulations as feedstocks for the production of cellulosic biofuels. Based on this similar composition as well as conversion yield data provided by industry, we applied the same production processes that were modeled for switchgrass in the final RFS2 rule (biochemical ethanol, thermochemical ethanol, and Fischer-Tropsch (F-T) diesel
) to energy cane, giant reed, and napiergrass. We assumed the GHG emissions associated with producing biofuels from energy cane, giant reed, and napiergrass are similar to what we estimated for switchgrass and other cellulosic feedstocks. EPA also assumes that the distribution and use of biofuel made from energy cane, giant reed, and napiergrass will not differ significantly from similar biofuel produced from other cellulosic sources. As was done for the switchgrass case, this analysis assumes energy grasses grown in the United States for production purposes. If crops were grown internationally, used for biofuel production, and the fuel was shipped to the U.S., shipping the finished fuel to the U.S. could increase transport emissions. However, considering the increased transport emissions associated with sugarcane ethanol distribution to the U.S., this would at most add 1-2% to the overall lifecycle GHG impacts of the energy grasses.
In this rule, EPA is also adding pathways to Table 1 to § 80.1426 for the production of renewable gasoline and renewable gasoline blendstock using specified feedstocks, fuel production processes, and process energy sources. The feedstocks we considered are generally considered waste feedstocks such as crop residues or cellulosic components of separated yard waste. These feedstocks have been identified by the industry as the most likely feedstocks for use in making renewable gasoline or renewable gasoline blendstock in the near term due to their availability and low cost. Additionally, these feedstocks have already been analyzed by EPA as part of the RFS2 rulemaking for the production of other fuel types. Consequently, no new modeling is required and we rely on earlier assessments of feedstock production and distribution for assessing the likely lifecycle impact on renewable gasoline and renewable gasoline blendstock. We have also relied on the petroleum gasoline baseline assessment from the RFS2 rule for estimating the fuel distribution and use GHG emissions impacts for renewable gasoline and renewable gasoline blendstock. Consequently, the only new analysis required is of the technologies for turning the feedstock into renewable gasoline and renewable gasoline blendstock.
EPA has evaluated renewable gasoline and renewable gasoline blendstock pathways that utilize cellulosic feedstocks currently included in Table 1 to § 80.1426 of the regulations. The following feedstocks were evaluated:
We based our process yields and heating values for renewable gasoline and renewable gasoline blendstock on several process technologies representative of technologies anticipated to be used in producing these fuels. As discussed later in this section, there are four main types of fuel production technologies available for producing renewable gasoline. These four processes can be characterized as (1) thermochemical gasification, (2) catalytic pyrolysis and upgrading to renewable gasoline or renewable gaoline blendstock (“catalytic pyrolysis”), (3) biochemical fermentation with upgrading to renewable gasoline or renewable gasoline blendstock via carboxylic acid (“fermentation and upgrading”), and (4) direct biochemical fermentation to renewable gasoline and renewable gasoline blendstock (“direct fermentation”). The thermochemical gasification process was modeled as part of the RFS2 final rule, included as producing naptha via the F-T process. Our analysis of the catalytic pyrolysis process was based on the modeling work completed by the National Renewable Energy Laboratory (NREL) for this rule for a process to make renewable gasoline blendstock.
The fermentation and upgrading process was modeled based on confidential business information (CBI) from industry for a unique process which uses biochemical conversion of cellulose to renewable gasoline via a carboxylic acid route. In addition, we have qualitatively assessed the direct fermentation to renewable gasoline process based on similarities to the biochemical ethanol process already analyzed as part of the RFS2 rulemaking. The fuel production section below provides further discussion on extending the GHG emissions results of the biochemical ethanol fermentation process to a biochemical renewable gasoline or renewable gasoline blendstock fermentation process. In some cases, the available data sources included process yields for renewable gasoline or renewable gasoline blendstock produced from wood chips rather than corn stover which was specifically modeled as a feedstock in the RFS2 final rule. We believe that the process yields are not significantly impacted by the source of cellulosic material whether the cellulosic material comes from residue such as corn stover or wood material such as from tree residues. We made the simplifying assumption that one dry ton of wood feedstock produces the same volume of renewable gasoline or renewable gasoline blendstock as one dry ton of corn stover. We believe this is reasonable considering that the RFS2 rulemaking analyses for biochemical ethanol and thermochemical F-T diesel processes showed limited variation in process yields between different feedstocks for a given process technology.
In addition, since the renewable gasoline and renewable gasoline blendstock pathways include feedstocks that were already considered as part of the RFS2 final rule, the existing feedstock lifecycle GHG impacts for distribution of corn stover were also applied to this analysis.
Table 7—Feedstock Production Emissions for Renewable Gasoline and Renewable Gasoline Blendstock Pathways Using Corn Stover Back to Top
Catalytic pyrolysis to renewable gasoline blendstock (g CO 2-eq./mmBtu)
Biochemical fermentation to renewable gasoline via carboxylic acid (g CO 2-eq./mmBtu)
Direct biochemical fermentation process to renewable gasoline and renewable gasoline blendstock (g CO 2-eq./mmBtu)
∼ 9,086
Domestic Farm Inputs and Fertilizer N 2 O
∼ 1,660
Domestic Rice Methane
∼ 434
Domestic Land Use Change
−9,124
−8,076
∼ −10,820
International Farm Inputs and Fertilizer N 2 O
International Rice Methane
Total Feedstock Production Emissions
∼ 361
A petroleum gasoline baseline was developed as part of the RFS2 final rule which estimated the tailpipe emissions from fuel combustion. Since renewable gasoline and renewable gasoline blendstock are similar to petroleum gasoline, the non-CO 2 combustion emissions calculated as part of the RFS2 final rule for petroleum gasoline were applied to our analysis of the renewable gasoline and renewable gasoline blendstock pathways. Only non-CO 2 emissions were included since carbon fluxes from land use change are accounted for as part of the biomass feedstock production.
The thermochemical gasification process to diesel fuel (via F-T synthesis) also produces a smaller portion of naphtha, a gasoline blendstock. In the final RFS2 rule, naphtha produced with specified cellulosic feedstocks by a F-T process was included as exceeding the 60% lifecycle GHG threshold, with an applicable D-Code of 3, in Table 1 to § 80.1426.
Since the final RFS2 rule was released, EPA has received several petitions and inquiries that suggest that renewable gasoline or renewable gasoline blendstock produced using processes other than the F-T process could also qualify for a similar D-Code of 3.
Several routes have been identified as available for the production of renewable gasoline and renewable gasoline blendstock from renewable biomass. These include catalytic pyrolysis and upgrading to renewable gasoline or renewable gasoline blendstock (“catalytic pyrolysis”), biochemical fermentation with upgrading to renewable gasoline or renewable gasoline blendstock via carboxylic acid (“fermentation and upgrading”), and direct biochemical fermentation to renewable gasoline and renewable gasoline blendstock (“direct fermentation”). 51 52
The first production process we investigated for this rule is a catalytic fast pyrolysis route to bio-oils with upgrading to a renewable gasoline or a renewable gasoline blendstock. We utilized process modeling results from the National Renewable Energy Laboratory (NREL). Information provided by industry and claimed as CBI are based on similar processing methods and suggest similar results than those reported by NREL. Details on the NREL modeling are described further in a technical report available through the docket.
Catalytic pyrolysis involves the rapid heating of biomass to about 500°C at slightly above atmospheric pressure. The rapid heating thermally decomposes biomass, converting it into pyrolysis vapor, which is condensed into a liquid bio-oil. The liquid bio-oil can then be upgraded using conventional hydroprocessing technology and further separated into gasoline and diesel blendstock streams (cellulosic diesel from catalytic pyrolysis is already included as an acceptable pathway in the RFS2 program). Some industry sources also expect to produce smaller fractions of heating oil in addition to gasoline and diesel blendstocks. Excess electricity from the process is also accounted for in our modeling as a co-product credit in which any excess displaces U.S. average grid electricity. Excess electricity is generated from the use of co-product coke/char and product gases and is available because internal electricity demands are fully met. The estimated energy inputs and electricity credits shown in Table 8, below, utilize the data provided by the NREL process modeling. However, Industry sources also identified potential areas for improvements in energy use, such as the use of biomass fired dryers instead of natural gas fired dryers for drying incoming wet feedstocks and increased turbine efficiencies for electricity production which may result in lower energy consumption than estimated by NREL and thus improve GHG performance compared to our estimates here.
Table 8—2022 Energy Use at Cellulosic Biofuel Facilities Back to Top
The major factors influencing the emissions from the fuel production stage of the catalytic pyrolysis pathway are the use of natural gas (mainly due to hydrogen production for hydroprocessing) and the co-products available for additional heat and power generation.
Table 9—Fuel Production Emissions for Catalytic Pyrolysis to Renewable Gasoline Blendstock Using Corn Stover Back to Top
Only non-CO 2 combustion emissions from biomass.
On-Site & Upstream Emissions (Natural Gas & Biomass*)
Total Fuel Production Emissions:
The process requires the use of natural gas and hydrogen inputs.
Table 10—2022 Energy Use at Cellulosic Facility Back to Top
Biochemical Fermentation to Renewable Gasoline or Renewable Gasoline Blendstock via Carboxylic Acid
Table 11—Fuel Production Emissions for Biochemical Fermentation to Renewable Gasoline or Renewable Gasoline Blendstock via Carboxylic Acid Using Corn Stover Back to Top
GHG Emissions (g CO 2-eq./mmBtu)
*Only non-CO 2 combustion emissions from biomass
The third production process we investigated involves the use of microorganisms to ferment sugars hydrolyzed from cellulose directly into hydrocarbons which could be either a complete fuel as renewable gasoline or a renewable gasoline blendstock. The process is similar to the biochemical fermentation to ethanol pathway modeled for the final RFS2 rule with the major difference being the end fuel product, hydrocarbons instead of ethanol. Researchers believe that this new technology could achieve improvements over classical fermentation approaches because hydrocarbons separate spontaneously from the aqueous phase, thereby avoiding poisoning of microbes by the accumulated products and facilitating separation/collection of alkanes from the reaction medium.
In other words, some energy savings may result because fewer separation unit operations could be required for separating the final product from other reactants and there may be better conversion yields as the fermentation microorganisms are not poisoned when interacting with accumulated products. We also expect that the lignin/byproduct portions of the biomass from the fermentation to hydrocarbon process could be converted into heat and electricity for internal demands or for export, similar to the biochemical fermentation to ethanol pathway.
Table 12—Fuel Production Emissions for RFS2 Cellulosic Biochemical Ethanol Compared to Direct Biochemical Fermentation to Renewable Gasoline or Renewable Gasoline Blendstock Using Corn Stover Back to Top
RFS2 Cellulosic biochemical ethanol emissions (g CO 2-eq./mmBtu)
Direct biochemical fermentation to renewable gasoline and renewable gasoline blendstock emissions (g CO 2-eq./mmBtu)
On-Site Emissions & Upstream (biomass)
< or = 3,000
= −35,000
Total Fuel Production Emissions57
< or = −33,000
Table13 below breaks down by stage the lifecycle GHG emissions for the renewable gasoline and renewable gasoline blendstock pathways using corn stover and the 2005 petroleum baseline. The table demonstrates the contribution of each stage in the fuel pathway and its relative significance in terms of GHG emissions. These results are also presented in graphical form in a supplemental memorandum to the docket.
As noted above, these analyses assume natural gas as the process energy when needed; using biogas or biomass as process energy would result in an even better lifecycle GHG impact.
Table 13—Lifecycle GHG Emissions for Renewable Gasoline and Renewable Gasoline Blendstock Pathways Using Corn Stover, 2022 Back to Top
[kg CO 2-eq./mmBtu]
* Emissions included in fuel production stage.
Net Domestic Agriculture (w/o land use change)
∼ −11
< or = −33
Fuel and Feedstock Transport
< or = −29
−129%
As was the case in our earlier rulemaking, a couple reasons in particular support extending our modeling results to other production process producing renewable gasoline or renewable gasoline blendstock from cellulosic feedstock. Under this rule we analyzed the core technologies most likely available through 2022 for production of renewable gasoline and renewable gasoline blendstock routes from cellulosic feedstock as shown in literature.
The two primary routes for renewable gasoline and renewable gasoline blendstock production from cellulosic feedstock can be classified as either thermochemical or biological. Each of these two major categories has two subcategories. The processes under the thermochemical category include:
Furthermore, industry has identified other areas for energy improvements which our current pathway analyses do not include. Therefore, the results we have come up with for the individual pathway types represent conservative estimates and any variations in the pathways considered are likely to result in greater GHG reductions that what is considered here. For example, the variation of the catalytic pyrolysis route considered here resulted in a 67% reduction in lifecycle GHG emissions compared to the petroleum baseline. However, as was mentioned this was based on data from our NREL modeling and industry CBI data indicated more efficient energy performance which, if realized, would improve GHG performance. Another area for improvement in this pathway could be the use of anaerobic digestion to treat organics in waste water. If the anaerobic digestion is on-site, then enough biogas could potentially be produced to replace all of the fossil natural gas used as fuel and about half the natural gas fed for hydrogen production.
The F-T gasification technology route considered as part of the RFS2 final rule resulted in an approximately 91% reduction in lifecycle GHG emissions compared to the petroleum baseline. This could be considered a conservative estimate as the process did not assume any excess electricity production, which as mentioned above could lead to additional GHG reductions. The F-T process involves gasifying biomass into syngas (mix of H 2 and CO) and then converting the syngas through a catalytic process into a hydrocarbon mix that is further refined into finished product. The F-T process considered was based on producing both gasoline and diesel fuel so that it was not optimized for renewable gasoline production. A process for producing primarily renewable gasoline rather than diesel from a gasification route should not result in a significantly worse GHG impacts compared to the mixed fuel process analyzed. Furthermore, as the lifecycle GHG reduction from the F-T process considered was around 91%, there is considerable room for variations in this route to still meet the 60% lifecycle GHG reduction threshold for cellulosic fuels. Therefore, in addition to the F-T process orginially analyzed for producing naphtha, we can extend the results based on the above analyses to include all variations of the gasification route which use natural gas, biogas or biomass for production energy for producing renewable gasoline or renewable gasoline blendstock. These variations include for example different catalysts and different refining processes to produce different mixes of final fuel product. While the current Table 1 entry in the regulations does not specify process energy sources, we are adding these specific eligible energy sources since we have not analyzed other energy sources (e.g. coal) as also allowing the pathway to meet the GHG performance threshold.
Table 14, shown below, includes pathways for biodiesel using specified feedstocks and the production process transesterification. Transesterification is the most commonly used method to produce biodiesel (i.e., methyl esters) by reacting triglycerides with methanol typically under the presence of a base catalyst, see the simplified form in Equation 1.
Table 14—Excerpts of Existing Fuel Pathways From § 40 CFR 80.1426 Back to Top
Soy bean oil; Oil from annual covercrops; Algal oil; Biogenic waste oils/fats/greases; Non-food grade corn oil
One of the following: Trans-Esterification Hydrotreating Excluding processes that co-process renewable biomass and petroleum
4 (Biomass-Based Diesel).
One of the following: Trans-Esterification Hydrotreating Includes only processes that co-process renewable biomass and petroleum
5 (Advanced Biofuel).
Under the RFS2 final rule, biodiesel from biogenic waste oils/fats/greases qualifies for D-Codes 4 and 5 using a “transesterification” process. This conclusion was based on the analysis of yellow grease as a feedstock in a process where there was an acid “pretreatment” or “esterification” process to treat the FFAs contained in the feedstock. In fact, one of the material inputs assumed in the modeling for the final RFS2 rule yellow grease pathway is sulfuric acid, which is the catalyst commonly used for acid esterification. However, we had not stipulated “esterification” as a qualified production process in Table 1 to § 40 CFR 80.1426. We believe this ambiguity could unnecessarily cause confusion as to whether esterification can also be used for the production of biodiesel under the currently approved pathways.
Since the biodiesel modeling completed for the final RFS2 rule actually includes esterification upstream of the transesterification process, we find it appropriate to clarify Table 1 to § 40 CFR 80.1426 to include “esterification” as a qualified process in which to produce biodiesel. As the modeling for yellow grease met an 86% GHG reduction emissions level, and yellow grease is typically 15% FFA content, it is reasonable to conclude that esterification and subsequent transesterification with a yellow grease feedstock containing FFAs at the very least up to 15% can meet the GHG reduction threshold for biomass-based diesel and advanced biofuel of 50%.
The National Biodiesel Board (NBB) has conducted a comprehensive survey of the actual energy used by commercial biodiesel production plants in the U.S.
The survey depicts the amount of energy and incidental process materials such as acids used to produce a gallon of biodiesel. The survey data returned represents 37% of the surveyed 230 NBB biodiesel members in 2008 and includes producers using a variety of virgin oils and recycled or reclaimed fats and oils. While there is no specific data on the FFA content of the feedstocks used, the feedstocks did include reclaimed greases which represent the feedstocks which typically have the highest FFA content. As the data is partially aggregated, we used the maximum surveyed electricity and natural gas used at the facilities and a high estimate of “materials used” based on a sum of industry averages for all process materials for calculating potential GHG emissions. Even though some of the facilities might be processing feedstocks with relatively low FFA content, we believe that using these maximum observed inputs for energy used plus a high estimate for process materials used will estimate the highest GHG emissions profile for biodiesel production GHG emissions. When combined with the feedstock GHG emissions impact (see discussion below), the results still predict a GHG emissions reduction comfortably exceeding 50% as compared to the petroleum fuel it displaces. Therefore, there is little risk in predicting that any facility that utilizes esterification and feedstock over the range of likely FFA content can meet the 50% biomass-based diesel and advanced biofuel threshold.
According to the survey, the maximum electricity use for a producer reached as high as 3,071 Btu per gallon biodiesel. This is about 5 times higher than the industry average. The maximum natural gas usage for a producer reached as high as 12,324 Btu per gallon biodiesel, which is about 3.5 times higher than the industry average. For “materials used” only an industry average for each material was provided in the survey. Therefore, as a conservative estimate, we totaled all the average material inputs to equal 0.51 kg/gal biodiesel.
We believe that this is conservative because not all facilities are likely to use each and every one of the process materials listed in the survey (e.g., we totaled all the acids used even though a facility is not likely to use each different acid). Thus, our estimate of materials used will estimate a level of maximum usage of materials at a given facility. In addition, we did not include a glycerin co-product credit when calculating emissions since the esterification reaction does not produce glycerin (see Equation 2). Using the same methodology as was used for the yellow grease modeling under RFS2, but using the high energy and materials use assumptions per the above discussion and omitting the glycerin co-product credit, we estimate the emissions from biodiesel processing at 23,708 gCO 2 eq per mmBtu of biodiesel. The estimated GHG emissions reduction for the entire process is −71%. Since the GHG threshold is at −50% for biomass-based diesel and advanced biofuel, we believe that there is a large enough margin in the results to reasonably conclude that biodiesel using esterification of specified feedstocks with any level of FFA content meets the biomass-based diesel and advanced biofuel 50% lifecycle GHG reduction threshold. Therefore, we are including the process “esterification” as an approved biodiesel production process in Table 1 to § 40 CFR 80.1426. In addition, consistent with the modeling conducted for RFS2, we interpret the RFS regulations as they existed prior to today's rule as including a direct esterification process as part of the biodiesel pathways for which only “trans-esterification” was specifically referenced in Table 1 to § 40 CFR 80.1426.
V. Additional Changes to Listing of Available Pathways in Table 1 of 80.1426 Back to Top
On September 28, 2010, EPA published a “Supplemental Determination for Renewable Fuels Produced Under the Final RFS2 Program from Canola Oil” (FR Vol. 75, No. 187, pg 59622-59634). In the July 1, 2011 NPRM (76 FR 38844) we proposed to clarify two aspects of the supplemental determination. First we proposed to amend the regulatory language in Table 1 to § 80.1426 to clarify that the currently-approved pathway for canola also applies more generally to rapeseed. While “canola” was specifically described as the feedstock evaluated in the supplemental determination, we had not intended the supplemental determination to cover just those varieties or sources of rapeseed that are identified as canola, but to all rapeseed. As described in the July 1, 2011 NPRM, we currently interpret the reference to “canola” in Table 1 to § 80.1426 to include any rapeseed. To eliminate ambiguity caused by the current language, however, we proposed to replace the term “canola” in that table with the term “canola/rapeseed”. Canola is a type of rapeseed. While the term “canola” is often used in the American continent and in Australia, the term “rapeseed” is often used in Europe and other countries to describe the same crop. We received no adverse comments on our proposal, and thus are finalizing it as proposed. This change will enhance the clarity of the regulations regarding the feedstocks that qualify under the approved canola biodiesel pathway.
VII. Statutory Provisions and Legal Authority Back to Top
2.Section 80.1401 is amended by addition of the following definitions of “Renewable Gasoline” and “Renewable Gasoline Blendstock” in alphabetical order to read as follows: § 80.1401 Definitions.
3.Section 80.1426 is amended by revising Table 1 in paragraph (f)(1) to read as follows: § 80.1426 How are RINs generated and assigned to batches of renewable fuel by renewable fuel producers or importers?
Table 1 to § 80.1426—Applicable D Codes for Each Fuel Pathway for Use in Generating RINs Back to Top
All of the following: Dry mill process, using natural gas, biomass, or biogas for process energy and at least two advanced technologies from Table 2 to this section
All of the following: Dry mill process, using natural gas, biomass, or biogas for process energy and at least one of the advanced technologies from Table 2 to this section plus drying no more than 65% of the distillers grains with solubles it markets annually
CEthanol
All of the following: Dry mill process, using natural gas, biomass, or biogas for process energy and drying no more than 50% of the distillers grains with solubles it markets annually
FBiodiesel, renewable diesel, jet fuel and heating oil
Soy bean oil; Oil from annual covercrops; Algal oil; Biogenic waste oils/fats/greases; Non-food grade corn oil; Camelina oil
One of the following: Trans-Esterification, Esterification Hydrotreating Excluding processes that co-process renewable biomass and petroleum
GBiodiesel, heating oil
HBiodiesel, renewable diesel, jet fuel and heating oil
Soy bean oil; Oil from annual covercrops; Algal oil; Biogenic waste oils/fats/greases; Non-food grade corn oil Camelina oil
One of the following: Trans-Esterification, Esterification Hydrotreating Includes only processes that co-process renewable biomass and petroleum
INaphtha, LPG
JEthanol
Cellulosic Biomass from crop residue, slash, pre-commercial thinnings and tree residue, annual covercrops, switchgrass, miscanthus, napiergrass, giant reed, and energy cane; cellulosic components of separated yard waste; cellulosic components of separated food waste; and cellulosic components of separated MSW
LCellulosic Diesel, jet fuel and heating oil
Cellulosic Biomass from crop residue, slash, pre-commercial thinnings and tree residue, annual covercrops, switchgrass, miscanthus, napiergrass, giant reed and energy cane; cellulosic components of separated yard waste; cellulosic components of separated food waste; and cellulosic components of separated MSW
MRenewable Gasoline and Renewable Gasoline Blendstock
Cellulosic Biomass from crop residue, slash, pre-commercial thinnings, tree residue, annual cover crops; cellulosic components of separated yard waste; cellulosic components of separated food waste; and cellulosic components of separated MSW
Catalytic Pyrolysis, Gasification and Upgrading, Direct Fermentation, Fermentation and Upgrading, all utilizing natural gas, biogas, and/or biomass as the only process energy sources. Any process utilizing biogas and/or biomass as the only process energy sources
OEthanol, renewable diesel, jet fuel, heating oil, and naphtha
PBiogas
3. McVay, K.A., and P.F. Lamb. 2008. Camelina production in Montana. MSU Ext. MT200701AG (revised). http://msuextension.org/publica&not;tions/AgandNaturalResources/MT200701AG.pdf.
37. See Lewandowski, I., Scurlock, J.M.O., Lindvall, E., Christou, M. (2003). The development and current status of perennial rhizomatous grassesas energy crops in the US and Europe. Biomass and Bioenergy 25, 335-361.
62. Commonly used base catalysts include sodium hydroxide (NaOH), potassium hydroxide (KOH) and sodium methoxide (NaOCH 3).