Regulation of Fuels and Fuel Additives: Identification of Additional Qualifying Renewable Fuel Pathways Under the Renewable Fuel Standard Program, 14190-14217 [2013-04929]

Download as PDF 14190 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations p.m. on the Thursday before Memorial Day (observed), and, if necessary due to inclement weather, from 2 p.m. through 7 p.m. on the Thursday following Memorial Day (observed). ACTION: SUMMARY: EPA is issuing a final rule identifying additional fuel pathways that EPA has determined meet the biomass-based diesel, advanced biofuel or cellulosic biofuel lifecycle greenhouse gas (GHG) reduction requirements specified in Clean Air Act section 211(o), the Renewable Fuel Standard (RFS) Program, as amended by the Energy Independence and Security Act of 2007 (EISA). This final rule describes EPA’s evaluation of biofuels produced from camelina (Camelina sativa) oil and energy cane; it also includes an evaluation of renewable gasoline and renewable gasoline blendstocks, and clarifies our definition of renewable diesel. The inclusion of these pathways creates additional opportunity and flexibility for regulated parties to comply with the advanced and cellulosic requirements of EISA and provides the certainty necessary for investments to bring these biofuels into commercial production from these new feedstocks. We are not finalizing at this time determinations on biofuels produced Dated: February 21, 2013. Kevin C. Kiefer, Captain, U.S. Coast Guard, Captain of the Port Baltimore. [FR Doc. 2013–05076 Filed 3–4–13; 8:45 am] BILLING CODE 9110–04–P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 80 [EPA–HQ–OAR–2011–0542; FRL–9686–3] RIN 2060–AR07 Regulation of Fuels and Fuel Additives: Identification of Additional Qualifying Renewable Fuel Pathways Under the Renewable Fuel Standard Program Environmental Protection Agency (EPA). AGENCY: NAICS 1 Codes Category Industry Industry Industry Industry Industry Industry Industry 1 North ............................................ ............................................ ............................................ ............................................ ............................................ ............................................ ............................................ Final rule. SIC 2 Codes 324110 325193 325199 424690 424710 424720 454319 2911 2869 2869 5169 5171 5172 5989 from giant reed (Arundo donax) or napier grass (Pennisetum purpureum) or biodiesel produced from esterification. We continue to consider the issues concerning these proposals, and will make a final decision on them at a later time. DATES: This rule is effective on May 6, 2013. FOR FURTHER INFORMATION CONTACT: Vincent Camobreco, Office of Transportation and Air Quality (MC6401A), Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 564–9043; fax number: (202) 564–1686; email address: camobreco.vincent@epa.gov. SUPPLEMENTARY INFORMATION: Does this action apply to me? Entities potentially affected by this action are those involved with the production, distribution, and sale of transportation fuels, including gasoline and diesel fuel or renewable fuels such as ethanol and biodiesel. Regulated categories and entities affected by this action include: Examples of potentially regulated entities Petroleum Refineries. Ethyl alcohol manufacturing. Other basic organic chemical manufacturing. Chemical and allied products merchant wholesalers. Petroleum bulk stations and terminals. Petroleum and petroleum products merchant wholesalers. Other fuel dealers. American Industry Classification System (NAICS). Industrial Classification (SIC) system code. emcdonald on DSK67QTVN1PROD with RULES 2 Standard This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that EPA is now aware could be potentially regulated by this action. Other types of entities not listed in the table could also be regulated. To determine whether your entity is regulated by this action, you should carefully examine the applicability criteria of Part 80, subparts D, E and F of title 40 of the Code of Federal Regulations. If you have any question regarding applicability of this action to a particular entity, consult the person in the preceding FOR FURTHER INFORMATION CONTACT section above. Outline of This Preamble I. Executive Summary A. Purpose of the Regulatory Action B. Summary of the Major Provisions of the Regulatory Action In Question VerDate Mar<15>2010 17:51 Mar 04, 2013 Jkt 229001 II. Identification of Additional Qualifying Renewable Fuel Pathways Under the Renewable Fuel Standard (RFS) Program A. Analysis of Lifecycle Greenhouse Gas Emissions for Biodiesel, Renewable Diesel, Jet Fuel, Heating Oil, Naphtha, and Liquefied Petroleum Gas (LPG) Produced From Camelina Oil B. Lifecycle Greenhouse Gas Emissions Analysis for Ethanol, Diesel, Jet Fuel, Heating Oil, and Naphtha Produced From Energy Cane C. Lifecycle Greenhouse Gas Emissions Analysis for Certain Renewable Gasoline and Renewable Gasoline Blendstocks Pathways D. Esterification Production Process Inclusion for Specified Feedstocks Producing Biodiesel III. Additional Changes to Listing of Available Pathways in Table 1 of 80.1426 IV. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review B. Paperwork Reduction Act PO 00000 Frm 00036 Fmt 4700 Sfmt 4700 C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act E. Executive Order 13132 (Federalism) F. Executive Order 13175 (Consultation and Coordination With Indian Tribal Governments) G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations K. Congressional Review Act V. Statutory Provisions and Legal Authority I. Executive Summary A. Purpose of This Regulatory Action In this rulemaking, EPA is taking final action to identify additional fuel E:\FR\FM\05MRR1.SGM 05MRR1 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations pathways that we have determined meet the greenhouse gas (GHG) reduction requirements under the Renewable Fuel Standard (RFS) program. This final rule describes EPA’s evaluation of biofuels produced from camelina (Camelina sativa) oil, which qualify as biomassbased diesel or advanced biofuel, as well as biofuels from energy cane which qualify as cellulosic biofuel. This final rule also qualifies renewable gasoline and renewable gasoline blendstock made from certain qualifying feedstocks as cellulosic biofuel. Finally, this rule clarifies the definition of renewable diesel to explicitly include jet fuel. EPA is taking this action as a result of changes to the RFS program in Clean Air Act (‘‘CAA’’) Section 211(o) required by the Energy Independence and Security Act of 2007 (‘‘EISA’’). This rulemaking modifies the RFS regulations published at 40 CFR § 80.1400 et seq. The RFS program regulations specify the types of renewable fuels eligible to participate in the RFS program and the procedures by which renewable fuel producers and importers may generate Renewable Identification Numbers (‘‘RINs’’) for the qualifying renewable fuels they produce through approved fuel pathways. See 75 FR 14670 (March 26, 2010); 75 FR 26026 (May 10, 2010); 75 FR 37733 (June 30, 2010); 75 FR 59622 (September 28, 2010); 75 FR 76790 (December 9, 2010); 75 FR 79964 (December 21, 2010); 77 FR 1320 (January 9, 2012); and 77 FR 74592 (December 17, 2012). By qualifying these new fuel pathways, this rule provides opportunities to increase the volume of advanced, low-GHG renewable fuels— such as cellulosic biofuels—under the RFS program. EPA’s comprehensive analyses show significant lifecycle GHG emission reductions from these fuel types, as compared to the baseline gasoline or diesel fuel that they replace. emcdonald on DSK67QTVN1PROD with RULES B. Summary of the Major Provisions of the Regulatory Action In Question This final rule describes EPA’s evaluation of: Camelina (Camelina sativa) oil (new feedstock) • Biodiesel, and renewable diesel, (including jet fuel, and heating oil)— qualifying to generate biomass-based diesel and advanced biofuel RINs • Naphtha and liquefied petroleum gas (LPG)—qualifying to generate advanced biofuel RINs Energy cane cellulosic biomass (new feedstock) • Ethanol, renewable diesel (including renewable jet fuel and heating oil), and renewable gasoline VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 blendstock—qualifying to generate cellulosic biofuel RINs Renewable gasoline and renewable gasoline blendstock (new fuel types) • Produced from crop residue, slash, pre-commercial thinnings, tree residue, annual cover crops, and cellulosic components of separated yard waste, separated food waste, and separated municipal solid waste (MSW) • Using the following processes—all utilizing natural gas, biogas, and/or biomass as the only process energy sources—qualifying to generate cellulosic biofuel RINs: Æ Thermochemical pyrolysis Æ Thermochemical gasification Æ Biochemical direct fermentation Æ Biochemical fermentation with catalytic upgrading Æ Any other process that uses biogas and/or biomass as the only process energy sources This final rule adds these pathways to Table 1 to § 80.1426. This final rule allows producers or importers of fuel produced under these pathways to generate RINs in accordance with the RFS regulations, providing that the fuel meets other definitional criteria for renewable fuel. The inclusion of these pathways creates additional opportunity and flexibility for regulated parties to comply with the requirements of EISA. Substantial investment has been made to commercialize these new feedstocks, and the cellulosic biofuel industry in the United States continues to make significant advances in its progress towards large scale commercial production. Approval of these new feedstocks will help further the Congressional intent to expand the volumes of cellulosic and advanced biofuels. We are also finalizing two changes to Table 1 to 80.1426 that were proposed on July 1, 2011(76 FR 38844). The first change adds ID letters to pathways to facilitate references to specific pathways. The second change adds ‘‘rapeseed’’ to the existing pathway for renewable fuel made from canola oil. II. Identification of Additional Qualifying Renewable Fuel Pathways Under the Renewable Fuel Standard (RFS) Program This rule was originally published in the Federal Register at 77 FR 462, January 5, 2012 as a direct final rule, with a parallel publication of a proposed rule. A limited number of relevant adverse comments were received, and EPA published a withdrawal notice of the direct final rule on March 5, 2012 (77 FR 13009). A second comment period was not issued, since the simultaneous publication of PO 00000 Frm 00037 Fmt 4700 Sfmt 4700 14191 the proposed rule provided an adequate notice and comment process. EPA is finalizing several of the proposed actions in this final rule, but continues to consider determinations on biofuels produced from giant reed (Arundo donax) or napier grass (Pennisetum purpureum) or biodiesel produced from esterification. EPA will make a final decision on theses elements of the proposal at a later time. In this action, EPA is issuing a final rule to identify in the RFS regulations additional renewable fuel production pathways that we have determined meet the greenhouse gas (GHG) reduction requirements of the RFS program. There are three critical components of a renewable fuel pathway: (1) Fuel type, (2) feedstock, and (3) production process. Each specific combination of the three components, or fuel pathway, is assigned a D code which is used to designate the type of biofuel and its compliance category under the RFS program. This final rule describes EPA’s lifecycle GHG evaluation of camelina oil and energy cane. Determining whether a fuel pathway satisfies the CAA’s lifecycle GHG reduction thresholds for renewable fuels requires a comprehensive evaluation of the lifecycle GHG emissions of the renewable fuel as compared to the lifecycle GHG emissions of the baseline gasoline or diesel fuel that it replaces. As mandated by CAA section 211(o), the GHG emissions assessments must evaluate the aggregate quantity of GHG emissions (including direct emissions and significant indirect emissions such as significant emissions from land use changes) related to the full fuel lifecycle, including all stages of fuel and feedstock production, distribution, and use by the ultimate consumer. In examining the full lifecycle GHG impacts of renewable fuels for the RFS program, EPA considers the following: • Feedstock production—based on agricultural sector models that include direct and indirect impacts of feedstock production. • Fuel production—including process energy requirements, impacts of any raw materials used in the process, and benefits from co-products produced. • Fuel and feedstock distribution— including impacts of transporting feedstock from production to use, and transport of the final fuel to the consumer. • Use of the fuel—including combustion emissions from use of the fuel in a vehicle. Many of the pathways evaluated in this rulemaking rely on a comparison to the lifecycle GHG analysis work that was done as part of the Renewable Fuel E:\FR\FM\05MRR1.SGM 05MRR1 14192 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations Standard Program Final Rule, published March 26, 2010 (75 FR 14670) (March 2010 RFS). The evaluations here rely on comparisons to the existing analyses presented in the March 2010 final rule. EPA plans to periodically review and revise the methodology and assumptions associated with calculating the GHG emissions from all renewable fuel pathways. A. Analysis of Lifecycle Greenhouse Gas Emissions for Biodiesel, Renewable Diesel, Jet Fuel, Heating Oil, Naphtha, and Liquefied Petroleum Gas (LPG) Produced From Camelina Oil The following sections describe EPA’s evaluation of camelina (Camelina sativa) as a biofuel feedstock under the RFS program. As discussed previously, this analysis relies on a comparison to the lifecycle GHG analysis work that was done as part of the Renewable Fuel Standard Program (RFS) Final Rule, published March 26, 2010 for soybean oil biofuels. 1. Feedstock Production emcdonald on DSK67QTVN1PROD with RULES 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.1 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.2 3 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.4 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 1 Putnam, D.H., J.T. Budin, L.A. Field, and W.M. Breene. 1993. Camelina: A promising low-input oilseed. p. 314–322. In: J. Janick and J.E. Simon (eds.), New crops. Wiley, New York. 2 Moser, B.R., Vaughn, S.F. 2010. Evaluation of Alkyl Esters from Camelina Sativa Oil as Biodiesel and as Blend Components in Ultra Low Sulfur Diesel Fuel. Bioresource Technology. 101:646–653. 3 McVay, K.A., and P.F. Lamb. 2008. Camelina production in Montana. MSU Ext. MT200701AG (revised). https://msuextension.org/publications/ AgandNaturalResources/MT200701AG.pdf. 4 Putnam et al., 1993. VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 been limited.5 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.6 The FDA has not approved camelina for food uses, although it has approved the inclusion of certain quantities of camelina meal in commercial feed.7 In response to the proposed rule, EPA received comments highlighting the concern that by approving certain new feedstock types under the RFS program, EPA would be encouraging their introduction or expanded planting without considering their potential impact as invasive species.8 The degree of concern expressed by the commenters depended somewhat on the feedstock. As pointed out by the commenters, camelina and energy cane are not ‘‘native species,’’ defined as ‘‘a species that, other than as a result of an introduction, historically occurred or currently occurs in that ecosystem.’’ The commenters asserted that there is a ‘‘potential risk posed by the non-native species camelina and energy cane.’’ In contrast, comments stated that giant reed (Arundo donax) or napier grass (Pennisetum purpureum) have been identified as invasive species in certain parts of the country. These commenters asserted that the Arundo donax and napier grass pose a ‘‘clear risk of invasion.’’ Commenters stated that EPA should not approve the proposed feedstocks until EPA has conducted an invasive species analysis, as required under Executive Order (EO) 13112.9 The information before us does not raise significant concerns about the threat of invasiveness and related GHG emissions for camelina. For example, camelina is not listed on the Federal Noxious Weed List,10 nor is it listed on 5 Lafferty, Ryan M., Charlie Rife and Gus Foster. 2009. Spring camelina production guide for the Central High Plains. Blue Sun Biodiesel special publication. Blue Sun Agriculture Research & Development, Golden, CO. https:// www.gobluesun.com/upload/Spring%20Camelina%20Production%20Guide%202009.pdf. 6 Telephone conversation with Scott Johnson, Sustainable Oils, January 11, 2011. 7 See https://agr.mt.gov/camelina/FDAletter1109.pdf. 8 Comment submitted by Jonathan Lewis, Senior Counsel, Climate Policy, Clean Air Task Force et al., dated February 6, 2012. Document ID # EPA–HQ– OAR–2011–0542–0118. 9 https://www.gpo.gov/fdsys/pkg/FR-1999-02-08/ pdf/99-3184.pdf. 10 However, this list is not exhaustive and is generally limited to species that are not currently PO 00000 Frm 00038 Fmt 4700 Sfmt 4700 any state invasive species or noxious weed list. We believe that the production of camelina is unlikely to spread beyond the intended borders in which it is grown, which is consistent with the assumption in EPA’s lifecycle analysis that significant expenditures of energy or other sources of GHGs will not be required to remediate the spread of this feedstock from the specific locations where it is grown as a renewable fuel feedstock for the RFS program. Therefore, we are finalizing the camelina pathway in this rule based on our lifecycle analysis discussed below.11 Camelina is currently being grown on approximately 50,000 acres of land in the U.S., primarily in Montana, eastern Washington, and the Dakotas.12 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.13 In response to the proposed rule, two commenters were supportive of the use of renewable feedstocks such as camelina oil to produce biofuels for aviation. One commenter noted that aviation is unique in its complete dependency upon liquid fuel—today and into the foreseeable future. Another commenter noted that development of additional feedstocks and production pathways should increase supply and ultimately move us closer to the day when renewable jet fuels are pricecompetitive with legacy fossil fuels and help cut our dependence on foreign oil. EPA also received comment regarding a concern that EPA did not adequately establish that camelina would only be grown on fallow land and therefore would not have a land use impact and that EPA overestimated the likely yields in growing camelina and therefore underestimated the land requirements. In terms of the comment on camelina not being grown on fallow land, for the purposes of analyzing the lifecycle GHG emissions of camelina, EPA has considered the likely production pattern for camelina grown for biofuel production. Given the information currently available, camelina is in the U.S. or are incipient to the U.S. See https:// plants.usda.gov/java/ noxious?rptType=Federal&statefips=&sort=sc. Accessed on March 28, 2012. 11 EPA continues to evaluate Arundo donax and napier grass as feedstock for a renewable fuel pathway, and will make a final decision on these pathways at a later time. 12 McCormick, Margaret. ‘‘Oral Comments of Targeted Growth, Incorporated’’ Submitted to the EPA on June 9, 2009. 13 See https://www.camelinacompany.com/ Marketing/PressRelease.aspx?Id=25. E:\FR\FM\05MRR1.SGM 05MRR1 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations expected to be primarily planted in the U.S. as a rotation crop on acres that would otherwise remain fallow.14 Because camelina has not yet been established as a commercial crop with significant monetary value, farmers are unlikely to dedicate acres for camelina production that could otherwise be used to produce other cash crops. Since camelina would therefore not be expected to displace another crop but rather maximize the value of the land through planting camelina in rotation, EPA does not believe new acres would need to be brought into agricultural use to increase camelina production. In addition, camelina currently has only limited high-value niche markets for uses other than renewable fuels. Unlike commercial crops that are tracked by USDA, camelina does not have a wellestablished, internationally traded market that would be significantly affected by an increase in the use of camelina to produce biofuels. For these reasons, which are described in more detail below, EPA has determined that production of camelina-based biofuels is not expected to result in significant GHG emissions related to direct land use change since it is expected to be grown on fallow land. Furthermore, due to the limited non-biofuel uses for camelina, production of camelina-based biofuels is not expected to have a significant impact on other agricultural crop production or commodity markets (either camelina or other crop markets) and consequently would not result in significant GHG emissions related to indirect land use change. To the extent camelina-based biofuel production emcdonald on DSK67QTVN1PROD with RULES 14 Fallow land here refers to cropland that is periodically not cultivated. VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 decreases the demand for alternative biofuels, some with higher GHG emissions, this biofuel could have some beneficial GHG impact. However, it is uncertain which mix of biofuel sources the market will demand so this potential GHG impact cannot be quantified. Commenters stated that EPA failed to justify why camelina would be grown on fallow land and thus result in no land use change. In the proposed rule, EPA provided a detailed description of the economics indicating why producers are most likely to grow camelina on land that would otherwise remain fallow. This analysis formed the basis for why it was reasonable and logical for camelina to be grown on acres that would otherwise remain fallow. Comments also indicated that EPA’s economic basis for assuming camelina would most likely be grown on fallow land was inadequate, especially if production of camelina was scaled up. However, the comment did not indicate any specific point of error in our economically based analysis. As we described in the proposed rule and discuss below, camelina is currently not a commercially raised crop in the United States, therefore the returns on camelina are expected to be low compared to wheat and other crops with established, commercially traded markets.15 Therefore, EPA expects that initial production of camelina for biofuel production will be on land with the lowest opportunity cost. Based on this logic, EPA believes camelina will be grown as a rotation crop, as discussed 15 See Shonnard, D. R., Williams, L., & Kalnes, T. N. 2010. Camelina-Derived Jet Fuel and Diesel: Sustainable Advanced Biodiesel. Environmental Progress & Sustainable Energy, 382–392. PO 00000 Frm 00039 Fmt 4700 Sfmt 4700 14193 below, on dryland wheat acres replacing a period that the land would otherwise be left fallow. In the semi-arid regions of the Northern Great Plains, dryland wheat farmers currently leave acres fallow once every three to four years to allow additional moisture and nutrients to accumulate (see Figure 1). Recent research indicates that introducing cool season oilseed crops such as camelina can provide benefits by reducing soil erosion, increasing soil organic matter, and disrupting pest cycles. Although long-term data on the effects of replacing wheat/fallow growing patterns with wheat/oilseed rotations is limited, there is some data that growing oilseeds in drier semi-arid regions year after year can lead to reduced wheat yields.16 However, the diversification and intensification of wheat-fallow cropping systems can improve the long term economic productivity of wheat acres by increasing soil nitrogen and soil organic carbon pools.17 In addition, selective breeding is expected to reduce the potential negative impacts on wheat yields.18 Additional research in this area is needed and if significant negative impacts on crop rotations are determined from camelina grown on fallow acres EPA would take that into account in future analysis. 16 Personal communication with Andrew Lenssen, Department of Agronomy, Iowa State University, April 17, 2012. See also https:// www.ars.usda.gov/is/pr/2010/100413.htm. 17 See Sainju, U.M., T. Caesar-Tonthat, A.W. Lenssen, R.G. Evans, and R. Kohlberg. 2007. Longterm tillage and cropping sequence effects on dryland residue and soil carbon fractions. Soil Science Society of America Journal 71: 1730–1739. 18 See Shonnard et al., 2010; Lafferty et al., 2009. E:\FR\FM\05MRR1.SGM 05MRR1 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations As pointed out by commenters, in the future camelina production could VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 expand beyond what is currently assumed in this analysis. However, PO 00000 Frm 00040 Fmt 4700 Sfmt 4700 camelina would most likely not be able to compete with other uses of land until E:\FR\FM\05MRR1.SGM 05MRR1 ER05MR13.014</GPH> emcdonald on DSK67QTVN1PROD with RULES 14194 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations it becomes a commercial crop with a well-established market value. EPA once again reiterates that we will continue to monitor the growing patterns associated with camelina to determine whether actual production is consistent with the assumptions used in this analysis. Monitoring will be done by tracking the amount of RIN generating camelina fuel produced through the EPA Moderated Transaction System (EMTS). We can compare the amount of RIN generating fuel against expected volumes from fallow acres in conjunction with USDA. Consistent with EPA’s approach to all RFS feedstock pathway analyses, we will periodically reevaluate whether our assessment of GHG impacts will need to be updated in the future based on the potential for significant changes in our analyses. emcdonald on DSK67QTVN1PROD with RULES a. Land Availability USDA estimates that there are approximately 60 million acres of wheat in the U.S.19 USDA and wheat state cooperative extension reports through 2008 indicate that 83% of US 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.20 Therefore, our analysis uses the estimate that only 9 million wheat/fallow acres are available for camelina production. One commenter stated that EPA assumed more than 8 million acres would be used to produce camelina, even though a recent paper stated that only 5 million acres would have the potential to grow camelina in a sustainable manner in a way that would not impact the food supply. This commenter misinterpreted EPA’s assumptions. EPA’s 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. In other words, EPA assumed only 3 million acres would be planted with camelina in any given year. This number is less than the 5 million acres the Shonnard et. al. paper states would 19 2009 USDA Baseline. See https:// www.ers.usda.gov/publications/oce091/. 20 Johnson, S. and McCormick, M., Camelina: an Annual Cover Crop Under 40 CFR Part 80 Subpart M, Memorandum, dated November 5, 2010. VerDate Mar<15>2010 16:43 Mar 04, 2013 Jkt 229001 be available annually for camelina planting. b. Projected Volumes 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.21 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.22 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,23 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 camelinabased renewable fuels could be produced on existing acres.24 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.25 We also received comments that we overestimated long term camelina yields. The commentors stated that reaching yields of 3000 pounds per acre 21 Wheeler, P. and Guillen-Portal F. 2007. Camelina Production in Montana: A survey study sponsored by Targeted Growth, Inc. and Barkley Ag. Enterprises, LLP. 22 See Hunter, J and G. Roth. 2010. Camelina Production and Potential in Pennsylvania, Penn State University Agronomy Facts 72. See https:// pubs.cas.psu.edu/freepubs/pdfs/uc212.pdf. 23 Ehrensing, D.T. and S.O. Guy. 2008. Oilseed Crops—Camelina. Oregon State Univ. Ext. Serv. EM8953–E. See https://extension.oregonstate.edu/ catalog/pdf/em/em8953-e.pdf; McVay & Lamb, 2008. 24 See Shonnard et al., 2010. 25 This assumes no significant adverse climate impacts on world agricultural yields over the analytical timeframe. PO 00000 Frm 00041 Fmt 4700 Sfmt 4700 14195 may be attainable, but previous trials do not suggest that yields could reach this level in ten years. As a point of clarification, we did not assume that yields would need to be 3000 pounds per acre for biodiesel produced from camelina oil to qualify as an advanced biofuel. In the analysis presented below, EPA assumed yields of camelina would be 1650 pounds per acre. Since the use of camelina as a biofuel feedstock in the U.S. is in its infancy, it is reasonable to consider how yields will change over time. Furthermore, jet fuel contracts and the BCAP programs play a very important part in determining the amount of camelina planted, and therefore interest in increasing yields. As the commenter noted, this yield assumption is within the range of potential yields of 330–2400 pounds per acre found in the current literature. c. Indirect Impacts 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.26 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.27 See Table 1. For comparison purposes, the USDA projections for wheat returns are between $133–$159 per acre between 2010 and 2020.28 Over time, advancements in seed technology, improvements in planting and harvesting techniques, and higher input usage could significantly increase future camelina yields and returns. 26 See Lafferty et al, 2009; Shonnard et al, 2010; Sustainable Oils Memo dated November 5, 2010. 27 Wheeler & Guillen-Portal, 2007. 28 See https://www.ers.usda.gov/media/273343/ oce121_2_.pdf. E:\FR\FM\05MRR1.SGM 05MRR1 14196 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations TABLE 1—CAMELINA COSTS AND RETURNS 2010 Camelina 29 2022 Camelina 30 2030 Camelina 31 Inputs Rates Herbicides: Glysophate (Fall) .............................................................. Glysophate (Spring) ......................................................... Post .................................................................................. Seed: Camelina seed ................................................................. 16 oz. ( $0.39/oz) .................. 16 oz. ( $0.39/oz) .................. 12 oz ( $0.67/oz) ................... $7.00 $7.00 $8.00 $7.00 $7.00 $8.00 $7.00 $7.00 $8.00 $1.44/lb .................................. $5.76 (4 lbs/acre) $7.20 (5 lbs/acre) $7.20 (5 lbs/acre) Fertilizer: Nitrogen Fertilizer ............................................................. $1/pd ...................................... Phosphate Fertilizer ......................................................... $1/pd ...................................... Sub-Total ................................................................... Logistics: Planting Trip ..................................................................... Harvest & Hauling ............................................................ Total Cost ..................................................................... Yields ................................................................................ Price ................................................................................. Total Revenue at avg prod/pricing ........................... Returns ............................................................................. ................................................ $25.00 (25 lb/acre) $15.00 (15 lb/acre) $67.76 $40.00 (40 lb/acre) $15.00 (15 lb/acre) $84.20 $75 (75 lbs/acre) $15 (15 lb/acre) $119.20 ................................................ ................................................ ................................................ lb/acre .................................... $/lb ......................................... ................................................ ................................................ $10.00 $25.00 $102.76 800 $0.145 $116.00 $13.24 $10.00 $25.00 $119.20 1650 $0.120 $198 $78.80 $10.00 $25.00 $154.20 3000 $0.090 $270 $115.80 emcdonald on DSK67QTVN1PROD with RULES 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.32 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 29 See Sustainable Oils Memo dated November 5, 2010. 30 Based on yields technically feasible. See McVey and Lamb, 2008; Ehrenson & Guy, 2008. 31 Adapted from Shonnard et al, 2010. 32 See Sustainable Oils Memo dated November 5, 2010 for a map of the regions of the country where camelina is likely to be grown in wheat fallow conditions. VerDate Mar<15>2010 16:43 Mar 04, 2013 Jkt 229001 camelina may be affected differently than in colder climates.33 Therefore, camelina grown outside of a wheat fallow situation was not considered as part of this analysis. The determination in this final rule is based on our projection that camelina is likely to be produced on what would otherwise be fallow land. However, the rule applies to all camelina regardless of where it is grown. EPA does not expect that significant camelina would be grown on non-fallow land, and small quantities that may be grown elsewhere and used for biofuel production will not significantly impact our analysis. Furthermore, although we expect most camelina used as a feedstock for renewable fuel production that would qualify in the RFS program would be grown in the U.S., today’s rule would apply to qualifying renewable fuel made from camelina grown in any country. For the same reasons that pertain to U.S. production of camelina, we expect that camelina grown in other countries would also be produced on land that would otherwise be fallow and would therefore have no significant land use change impacts. The renewable biomass provisions under the Energy Independence and Security Act would prohibit direct land conversion into new agricultural land for camelina 33 Wright PO 00000 & Marois, 2011. Frm 00042 Fmt 4700 Sfmt 4700 production for biofuel internationally. Additionally, any camelina production on existing cropland internationally would not be expected to have land use impacts beyond what was considered for international soybean production (soybean oil is the expected major feedstock source for US biodiesel fuel production and thus the feedstock of reference for the camelina evaluation). Because of these factors along with the small amounts of fuel potentially coming from other countries, we believe that incorporating fuels produced in other countries will not impact our threshold analysis for camelina-based biofuels. d. Crop Inputs For comparison purposes, Table 2 shows the inputs required for camelina production compared to the FASOM agricultural input assumptions for soybeans. Since yields and input assumptions vary by region, a range of values for soybean production are shown in Table 2. The camelina input values in Table 2 represent average values, camelina input values will also vary by region, however, less data is available comparing actual practices by region due to limited camelina production. More information on camelina inputs is available in materials provided in the docket. E:\FR\FM\05MRR1.SGM 05MRR1 14197 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations TABLE 2—INPUTS FOR CAMELINA AND SOYBEAN PRODUCTION Camelina Soybeans (varies by region) Inputs (per acre) N2O ...................................... Nitrogen Fertilizer ................. Phosphorous Fertilizer ......... Potassium Fertilizer .............. Herbicide .............................. Pesticide ............................... Diesel ................................... Gasoline ............................... Total ..................................... Emissions (per mmBtu fuel) Inputs (per acre) Emissions (per mmBtu fuel) N/A ....................................... 40 lbs ................................... 15 lbs ................................... 10 lbs ................................... 2.75 lbs ................................ 0 lbs ..................................... 3.5 gal .................................. 0 gal ..................................... .............................................. 22 kg CO2-eq ....................... 7 kg CO2-eq ......................... 1 kg CO2-eq ......................... 0 kg CO2-eq ......................... 3 kg CO2-eq ......................... 0 kg CO2-eq ......................... 5 kg CO2-eq ......................... 0 kg CO2-eq ......................... 39 kg CO2-eq ....................... N/A ....................................... 3.5–8.2 lbs ........................... 5.4–21.4 lbs ......................... 3.1–24.3 lbs ......................... 0.0–1.3 lbs ........................... 0.1–0.8 lbs ........................... 3.8–8.9 gal ........................... 1.6–3.0 gal ........................... .............................................. 9–12 kg CO2-eq. 1–3 kg CO2-eq. 0–2 kg CO2-eq. 0–2 kg CO2-eq. 0–2 kg CO2-eq. 0–2 kg CO2-eq. 7–20 kg CO2-eq. 3–5 kg CO2-eq. 21–47 kg CO2-eq. Regarding crop inputs per acre, it should be noted that camelina has a higher percentage of oil per pound of seed than soybeans. Soybeans are approximately 18% oil, therefore crushing one pound of soybeans yields 0.18 pounds of oil. In comparison, camelina is approximately 36% oil, therefore crushing one pound of camelina yields 0.36 pounds of oil. The difference in oil yield is taken into account when calculating the emissions per mmBTU included in Table 2. As shown in Table 2, GHG emissions from feedstock production for camelina and soybeans are relatively similar when factoring in variations in oil yields per acre and fertilizer, herbicide, pesticide, and petroleum use. In summary, EPA concludes that the agricultural inputs for growing camelina are similar to those for growing soy beans, direct land use change impacts are expected to be negligible due to planting on land that would be otherwise fallow, and the limited production and use of camelina indicates no expected impacts on other crops and therefore no indirect land use impacts. e. Crushing and Oil Extraction 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 March 2010 RFS final rule, based on a process model developed by USDA–ARS.34 The data on camelina crushing is from Shonnard et al. (2010). TABLE 3—COMPARISON OF CAMELINA AND SOYBEAN CRUSHING AND OIL EXTRACTION Item Soybeans emcdonald on DSK67QTVN1PROD with RULES Material Inputs: Beans or Seeds ........................................................................................................ Energy Inputs: Electricity .................................................................................................................. Natural Gas & Steam ............................................................................................... Outputs: Refined vegetable oil ................................................................................................ Meal .......................................................................................................................... GHG Emissions ........................................................................................................ 2. Feedstock Distribution, Fuel Distribution, and Fuel Use For this analysis, EPA projects that the feedstock distribution emissions will be the same for camelina and soybean oil. To the extent that camelina contains more oil per pound of seed, as discussed above, the energy needed to move the camelina would be lower than soybeans per gallon of fuel produced. To the extent that camelina is grown on more disperse fallow land than soybean and would need to be transported further, the energy needed to move the camelina could be higher than soybean. We believe the assumption to use the same distribution impacts for camelina as soybean is a reasonable estimate of the GHG emissions from camelina feedstock distribution. In addition, the final fuel produced from camelina is also expected to be similar in composition to the comparable fuel produced from soybeans, therefore we are assuming GHG emissions from the distribution and use of fuels made from camelina will be the same as emissions of fuel produced from soybeans. 34 A. Pradhan, D.S. Shrestha, A. McAloon, W. Yee, M. Haas, J.A. Duffield, H. Shapouri, September 2009, ‘‘Energy Life-Cycle Assessment of Soybean Biodiesel’’, United States Department of Agriculture, Office of the Chief Economist, Office of VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 3. Fuel Production There are two main fuel production processes used to convert camelina oil PO 00000 Frm 00043 Fmt 4700 Sfmt 4700 Camelina Units 5.38 2.90 Lbs. 374 1,912 47 780 Btu. Btu. 1.00 4.08 213 1.00 1.85 64 Lbs. Lbs. gCO2e/lb refined oil. into fuel. The trans-esterification process produces biodiesel and a glycerin co-product. The hydrotreating process can be configured to produce renewable diesel either primarily as diesel fuel (including heating oil) or primarily as jet fuel. Possible additional products from hydrotreating include naphtha LPG, and propane. Both processes and the fuels produced are described in the following sections. Both processes use camelina oil as a feedstock and camelina crushing is also included in the analysis. Energy Policy and New Uses, Agricultural Economic Report Number 845. E:\FR\FM\05MRR1.SGM 05MRR1 emcdonald on DSK67QTVN1PROD with RULES 14198 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations a. Biodiesel For this analysis, we assumed the same biodiesel production facility designs and conversion efficiencies as modeled for biodiesel produced from soybean oil and canola/rapeseed oil. Camelina oil biodiesel is produced using the same methods as soybean oil biodiesel, therefore plant designs are assumed to not significantly differ between fuels made from these feedstocks. As was the case for soybean oil biodiesel, we have not projected in our assessment of camelina oil biodiesel any significant improvements in plant technology. Unanticipated energy saving improvements would further improve GHG performance of the fuel pathway. The glycerin produced from camelina biodiesel production is chemically equivalent to the glycerin produced from the existing biodiesel pathways (e.g., based on soy oil) that were analyzed as part of the March 2010 RFS final rule. Therefore the same coproduct credit would apply to glycerin from camelina biodiesel as glycerin produced in the biodiesel pathways modeled for the March 2010 RFS final rule. The assumption is that the GHG reductions associated with the replacement of residual oil with glycerin on an energy equivalent basis represents an appropriate midrange coproduct credit of biodiesel produced glycerin. As part of our RFS2 proposal, we assumed the glycerin would have no value and would effectively receive no co-product credits in the soy biodiesel pathway. We received numerous comments, however, asserting that the glycerin would have a beneficial use and should generate co-product benefits. Therefore, the biodiesel glycerin co-product determination made as part of the March 2010 RFS final rule took into consideration the possible range of co-product credit results. The actual co-product benefit will be based on what products are replaced by the glycerin and what new uses develop for the co-product glycerin. The total amount of glycerin produced from the biodiesel industry will actually be used across a number of different markets with different GHG impacts. This could include for example, replacing petroleum glycerin, replacing fuel products (residual oil, diesel fuel, natural gas, etc.), or being used in new products that don’t have a direct replacement, but may nevertheless have indirect effects on the extent to which existing competing products are used. The more immediate GHG reduction credits from glycerin co-product use VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 could range from fairly high reduction credits if petroleum glycerin is replaced to lower reduction credits if it is used in new markets that have no direct replacement product, and therefore no replaced emissions. EPA does not have sufficient information (and received no relevant comments as part of the March 2010 RFS rule) on which to allocate glycerin use across the range of likely uses. Therefore, EPA believes that the approach used in the RFS of picking a surrogate use for modeling purposes in the mid-range of likely glycerin uses, and the GHG emissions results tied to such use, is reasonable. The replacement of an energy equivalent amount of residual oil is a simplifying assumption determined by EPA to reflect the mid-range of possible glycerin uses in terms of GHG credits. EPA believes that it is appropriately representative of GHG reduction credit across the possible range without necessarily biasing the results toward high or low GHG impact. Given the fundamental difficulty of predicting possible glycerin uses and impacts of those uses many years into the future under evolving market conditions, EPA believes it is reasonable to use the more simplified approach to calculating coproduct GHG benefits associated with glycerin production at this time. EPA will continue to evaluate the co-product credit associated with glycerine production in future rulemakings. Given the fact that GHG emissions from camelina-based biodiesel would be similar to the GHG emissions from soybean-based biodiesel at all stages of the lifecycle but would not result in land use changes as was the case for soy oil used as a feedstock, we believe biodiesel from camelina oil will also meet the 50% GHG emissions reduction threshold to qualify as a biomass based diesel and an advanced fuel. Therefore, EPA is including biodiesel produced from camelina oil under the same pathways for which biodiesel made from soybean oil qualifies under the March 2010 RFS final rule. b. Renewable Diesel (Including Jet Fuel and Heating Oil), Naphtha, and LPG 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 PO 00000 Frm 00044 Fmt 4700 Sfmt 4700 of renewable diesel is relatively insensitive to feedstock source.35 While any propane produced as part of the hydrotreating process will most likely be combusted within the facility for process energy, the other co-products that can be produced (i.e., renewable diesel, naphtha, LPG) are higher value products that could be used as transportation fuels or, in the case of naphtha, a blendstock for production of transportation fuel. The hydrotreating process maximized for producing a diesel fuel replacement as the primary fuel product requires more overall material and energy inputs than transesterification to produce biodiesel, but it also results in a greater amount of other valuable co-products as listed above. The hydrotreating process can also be maximized for jet fuel production which requires even more process energy than the process optimized for producing a diesel fuel replacement, and produces a greater amount of co-products per barrel of feedstock, especially naphtha. Producers of renewable diesel from camelina have expressed interest in generating RINs under the RFS program for the slate of products resulting from the hydrotreating process. Our lifecycle analysis accounts for the various uses of the co-products. There are two main approaches to accounting for the coproducts produced, the allocation approach, and the displacement approach. In the allocation approach all the emissions from the hydrotreating process are allocated across all the different co-products. There are a number of ways to do this but since the main use of the co-products would be to generate RINs as a fuel product we allocate based on the energy content of the co-products produced. In this case, emissions from the process would be allocated equally to all the Btus produced. Therefore, on a per Btu basis all co-products would have the same emissions. The displacement approach would attribute all of the emissions of the hydrotreating process to one main product and then account for the emission reductions from the other coproducts displacing alternative product production. For example, if the hydrotreating process is configured to maximize diesel fuel replacement production, all of the emissions from the process would be attributed to diesel fuel, but we would then assume the other co-products were displacing 35 Kalnes, T., N., McCall, M., M., Shonnard, D., R., 2010. Renewable Diesel and Jet-Fuel Production from Fats and Oils. Thermochemical Conversion of Biomass to Liquid Fuels and Chemicals, Chapter 18, p. 475. E:\FR\FM\05MRR1.SGM 05MRR1 14199 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations alternative products, for example, naphtha would displace gasoline, LPG would displace natural gas, etc. This assumes the other alternative products are not produced or used, so we would subtract the emissions of gasoline production and use, natural gas production and use, etc. This would show up as a GHG emission credit associated with the production of diesel fuel replacement. 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 coproducts. 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.36 On the other hand, the upstream lifecycle GHG emissions associated with producing and transporting the plant oil feedstocks will be distributed over a larger group of RIN-generating products. Assuming each product (except propane) produced via the camelina oil hydrotreating process will generate RINs results in higher lifecycle GHG emissions for diesel fuel replacement as compared to the case where the co-products are not used to generate RINs. This general principle is also true when the hydrotreating process is maximized for jet fuel production. As a result, the worst GHG performance (i.e., greatest lifecycle GHG emissions) for diesel replacement fuel and jet fuel produced from camelina oil via hydrotreating will occur when all of the co-products are RIN-generating (we assume propane will be used for process energy). Thus, if these fuels meet the 50% GHG reduction threshold for biomass based diesel or advanced biofuel when coproducts are RIN-generating, they will also do so in the case when RINs are not generated for 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., 2011,37 Stratton et al., 2010, Huo et al., 2008 38). 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.39 This data is summarized in Table 4. TABLE 4—HYDROTREATING PROCESSES TO CONVERT CAMELINA OIL INTO DIESEL REPLACEMENT FUEL AND JET FUEL40 Maximized for diesel fuel production Inputs: Refined camelina oil ........................................................................................................... Hydrogen ............................................................................................................................. Electricity ............................................................................................................................. Natural Gas ......................................................................................................................... Outputs: Diesel Fuel .......................................................................................................................... Jet fuel ................................................................................................................................ Naphtha ............................................................................................................................... LPG ..................................................................................................................................... Propane ............................................................................................................................... 9.56 0.04 652 23,247 123,136 23,197 3,306 3,084 7,454 Maximized for jet fuel production 12.84 0.08 865 38,519 55,845 118,669 17,042 15,528 9,881 Units (per gallon of fuel produced) Lbs. Lbs. Btu. Btu. Btu. Btu. Btu. Btu. Btu. emcdonald on DSK67QTVN1PROD with RULES Table 5 compares lifecycle GHG emissions from oil extraction and fuel production for soybean oil biodiesel and for camelina-based diesel and jet fuel. The lifecycle GHG estimates for camelina oil diesel and jet fuel are based on the input/output data summarized in Table 3 (for oil extraction) and Table 4 (for fuel production). We assume that the propane co-product does not generate RINs; instead, it is used for process energy displacing natural gas. We also assume that the naphtha is used as blendstock for production of transportation fuel to generate RINs. In this case we assume that RINs are generated for the use of LPG in a way that meets the EISA definition of transportation fuel, for example it could be used in a nonroad vehicle. The lifecycle GHG results in Table 5 represent the worst case scenario (i.e., highest GHG emissions) because all of the eligible co-products are used to generate RINs. This is because, as discussed above, lifecycle GHG emissions per Btu of diesel or jet fuel would be lower if the naphtha or LPG is not used to generate RINs and is instead used for process energy displacing fossil fuel such as natural gas. Supporting information for the values in Table 5, including key assumptions and data, is provided through the docket.41 The key assumptions and data discussed in the docket include the emissions factors for natural gas, hydrogen and grid average electricity, and the energy allocation and displacement credits given to coproducts. These data and assumptions are based on the approach taken in the March 2010 RFS rule, as explained further below. 36 For a similar discussion see page 46 of Stratton, R.W., Wong, H.M., Hileman, J.I. 2010. Lifecycle Greenhouse Gas Emissions from Alternative Jet Fuels. PARTNER Project 28 report. Version 1.1. PARTNER–COE–2010–001. June 2010, https:// web.mit.edu/aeroastro/partner/reports/proj28/ partner-proj28-2010-001.pdf. 37 Pearlson, M., N. 2011. A Techno-Economic and Environmental Assessment of Hydroprocessed Renewable Distillate Fuels. 38 Huo, H., Wang., M., Bloyd, C., Putsche, V., 2008. Life-Cycle Assessment of Energy and Greenhouse Gas Effects of Soybean-Derived Biodiesel and Renewable Fuels. Argonne National Laboratory. Energy Systems Division. ANL/ESD/08– 2. March 12, 2008. 39 We have also considered data submitted by companies involved in the hydrotreating industry which is claimed as confidential business information (CBI). The conclusions using the CBI data are consistent with the analysis presented here. 40 Based on Pearlson (2011), Table 3.1 and Table 3.2. 41 See for example the spreadsheet with lifecycle GHG emissions calculations titled ‘‘Final Camelina Calculations for Docket’’ with document number EPA–HQ–OAR–2011–0542–0046. VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 PO 00000 Frm 00045 Fmt 4700 Sfmt 4700 E:\FR\FM\05MRR1.SGM 05MRR1 14200 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations TABLE 5—FUEL PRODUCTION LIFECYCLE GHG EMISSIONS [kgCO2e/mmBtu) 42 Production process RIN-Generating products Other co-products Soybean Oil ............... Camelina Oil .............. Camelina Oil .............. Trans-Esterification ... Trans-Esterification ... Hydrotreating Maximized for Diesel. 14 4 4 (1) (1) 8 13 3 12 Hydrotreating Maximized for Jet Fuel. Biodiesel ................... Biodiesel ................... Diesel ........................ Jet Fuel. Naphtha. LPG. Diesel Fuel ................ Jet Fuel. Naphtha. LPG. Glycerin ..................... Glycerin ..................... Propane .................... Camelina Oil .............. emcdonald on DSK67QTVN1PROD with RULES Feedstock Propane .................... 4 11 14 As discussed above, 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 RINgenerating 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 kgCO2e/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. Given that GHG emissions from camelina oil would be similar to the GHG emissions from soybean oil at all stages of the lifecycle but would not result in land use change emissions (soy oil feedstock did have a significant land use change impact but still met a 50% GHG reduction threshold), and considering differences in process emissions between soybean biodiesel and camelina-based renewable diesel, 42 Lifecycle GHG emissions are normalized per mmBtu of RIN-generating fuel produced. Totals may not be the sum of the rows due to rounding error. Parentheses indicate negative numbers. Process emissions for biodiesel production are negative because they include the glycerin offset credit. VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 we conclude that renewable diesel from camelina oil will also meet the 50% GHG emissions reduction threshold to qualify as biomass based diesel and advanced fuel. Although some of the potential configurations result in fuel production GHG emissions that are higher than fuel production GHG emissions for soybean oil biodiesel, land use change emissions account for approximately 80% of the soybean oil to biodiesel lifecycle GHGs. Since camelina is assumed not to have land use change emissions, our analysis shows that camelina renewable diesel will qualify for advanced renewable fuel and biomass-based diesel RINs even for the cases with the highest lifecycle GHGs (e.g., when all of the co-products are used to generate RINs.) Because the lifecycle GHG emissions for RINgenerating co-products are very similar, we can also conclude renewable gasoline blendstock and LPG produced from camelina oil will also meet the 50% GHG emissions reduction threshold. If the facility does not actually generate RINs for one or more of these co-products, we estimate that the lifecycle GHG emissions related to the RIN-generating products would be lower, thus renewable diesel (which includes diesel fuel, jet fuel, and heating oil) from camelina would still meet the 50% emission reduction threshold. 4. Summary Current information suggests that camelina will be produced on land that would otherwise remain fallow. Therefore, increased production of camelina-based renewable fuel is not expected to result in significant land use change emissions; however, the agency will continue to monitor volumes through EMTS to verify this assumption. For the purposes of this analysis, EPA is projecting there will be no land use emissions associated with camelina production for use as a renewable fuel feedstock. PO 00000 Frm 00046 Fmt 4700 Sfmt 4700 Oil extraction Processing Total However, while production of camelina on acres that would otherwise remain fallow is expected to be the primary means by which the majority of all camelina is commercially harvested in the short- to medium- term, in the long term camelina may expand to other growing methods and lands if demand increases substantially beyond what EPA is currently predicting. While the impacts are uncertain, there are some indications demand could increase significantly. For example, camelina is included under USDA’s Biomass Crop Assistance Program (BCAP) and there is growing support for the use of camelina oil in producing drop-in alternative aviation fuels. EPA plans to monitor, through EMTS and in collaboration with USDA, the expansion of camelina production to verify whether camelina is primarily grown on existing acres once camelina is produced at largerscale volumes. Similarly, we will consider market impacts if alternative uses for camelina expand significantly beyond what was described in the above analysis. Just as EPA plans to periodically review and revise the methodology and assumptions associated with calculating the GHG emissions from all renewable fuel feedstocks, EPA expects to review and revise as necessary the analysis of camelina in the future. Taking into account the assumption of no land use change emissions when camelina is used to produce renewable fuel, and considering that other sources of GHG emissions related to camelina biodiesel or renewable diesel production have comparable GHG emissions to biodiesel from soybean oil, we have determined that camelinabased biodiesel and renewable diesel should be treated in the same manner as soy-based biodiesel and renewable diesel in qualifying as biomass-based diesel and advanced biofuel for purposes of RIN generation, since the GHG emission performance of the E:\FR\FM\05MRR1.SGM 05MRR1 emcdonald on DSK67QTVN1PROD with RULES Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations camelina-based fuels will be at least as good and in some respects better than that modeled for fuels made from soybean oil. EPA found as part of the Renewable Fuel Standard final rulemaking that soybean biodiesel resulted in a 57% reduction in GHG emissions compared to the baseline petroleum diesel fuel. Furthermore, approximately 80% of the lifecycle impacts from soybean biodiesel were from land use change emissions which are assumed to be not significant for the camelina pathway considered. Thus, EPA is including camelina oil as a potential feedstock under the same biodiesel and renewable diesel (which includes diesel fuel, jet fuel, and heating oil) pathways for which soybean oil currently qualifies. We are also including a pathway for naphtha and LPG produced from camelina oil through hydrotreating. This is based on the fact that our analysis shows that even when all of the co-products are used to generate RINs the lifecycle GHG emissions for RIN-generating coproducts including diesel replacement fuel, jet fuel, naphtha and LPG produced from camelina oil will all meet the 50% GHG emissions reduction threshold. We are also clarifying that two existing pathways for RIN generation in the RFS regulations that list ‘‘renewable diesel’’ as a fuel product produced through a hydrotreating process include jet fuel. This applies to two pathways in Table 1 to § 80.1426 of the RFS regulations which both list renewable diesel made from soy bean oil, oil from annual covercrops, algal oil, biogenic waste oils/fats/greases, or non-food grade corn oil using hydrotreating as a process. If parties produce jet fuel from the hydrotreating process and coprocess renewable biomass and petroleum they can generate advanced biofuel RINs (D code 5) for the jet fuel produced. If they do not co-process renewable biomass and petroleum they can generate biomass-based diesel RINs (D code 4) for the jet fuel produced. § 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 RFS final rule, identifies jet fuel and renewable diesel as separate fuel types. Accordingly, in VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 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. The original lifecycle analysis for the renewable diesel from hydrotreating pathways listed in Table 1 to § 80.1426 was not based on producing jet fuel but rather other transportation diesel fuel products, namely a diesel fuel replacement. As discussed above, the hydrotreating process can produce a mix of products including jet fuel, diesel, naphtha, LPG and propane. Also, as discussed, there are differences in the process configured for maximum jet fuel production vs. the process maximized for diesel fuel production and the lifecycle results vary depending on what approach is used to consider coproducts (i.e., the allocation or displacement approach). 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 coproducts produced. This is the case for most of the original feedstocks included in Table 1 to § 80.1426.43 As was discussed previously, if the displacement approach is used when jet fuel is the primary product produced it results in lower emissions than 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. Thus, we are interpreting the references to ‘‘renewable diesel’’ in Table 1 to include jet fuel, consistent with our regulatory definition of ‘‘nonester renewable diesel,’’ since doing so clarifies the existing regulations while ensuring that Table 1 to § 80.1426 appropriately identifies fuel pathways that meet the GHG reduction thresholds associated with each pathway. We note that although the definition of renewable diesel includes jet fuel and heating oil, we have also listed in Table 1 of section 80.1426 of the RFS regulations jet fuel and heating oil as specific co-products in addition to listing renewable diesel to assure clarity. This clarification also pertains to all the feedstocks already included in Table 1 for renewable diesel. 43 The exception is renewable gasoline blendstock produced from waste categories, but these would pass the lifecycle thresholds regardless of the allocation approach used given their low feedstock GHG impacts. PO 00000 Frm 00047 Fmt 4700 Sfmt 4700 14201 B. Lifecycle Greenhouse Gas Emissions Analysis for Ethanol, Diesel, Jet Fuel, Heating Oil, and Naphtha Produced From Energy Cane For this rulemaking, EPA considered the lifecycle GHG impacts of a new type of high-yielding perennial grass similar in cellulosic composition to switchgrass and comparable in status as an emerging energy crop. The grass considered in this rulemaking is energy cane, which is defined as a complex hybrid in the Saccharum genus that has been bred to maximize cellulosic rather than sugar content. As discussed above, in response to the proposed rule, EPA received comments highlighting the concern that by approving certain new feedstock types under the RFS program, EPA would be encouraging their introduction or expanded planting without considering their potential impact as invasive species.44 As described in the previous section on camelina, the information before us does not raise significant concerns about the threat of invasiveness and related GHG emissions for energy cane. Energy cane is generally a hybrid of Saccharum officinarum and Saccharum spontaneum, though other species such as Saccharum barberi and Saccharum sinense have been used in the development of new cultivars.45 Given the fact that S. spontaneum is listed on the Federal Noxious Weed List, this rulemaking does not allow for the inclusion of S. spontaneum in the definition of energy cane. However, hybrids derived from S. spontaneum that have been developed and publicly released by USDA are included in this definition of the energy cane feedstock. USDA’s Agricultural Research Service has developed strains of energy cane that strive to maximize fiber content and minimize invasive traits. Therefore, we believe that the production of cultivars of energy cane that were developed by USDA are unlikely to spread beyond the intended borders in which it is grown, which is consistent with the assumption in EPA’s lifecycle analysis that significant expenditures of energy or other sources of GHGs will not be required to remediate the spread of this feedstock from the specific locations where it is grown as a renewable fuel 44 Comment submitted by Jonathan Lewis, Senior Counsel, Climate Policy, Clean Air Task Force et al., dated February 6, 2012. Document ID # EPA–HQ– OAR–2011–0542–0118. 45 See https://www.crops.org/publications/jpr/ abstracts/2/3/211?access=0&view=pdf and https:// www.cpact.embrapa.br/eventos/2010/ simposio_agroenergia/palestras/10_terca/Tarde/ USA/4%20%20%208-102010%20Cold%20Tolerance.pdf. E:\FR\FM\05MRR1.SGM 05MRR1 emcdonald on DSK67QTVN1PROD with RULES 14202 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations feedstock for the RFS program. Therefore, we are finalizing the energy cane pathway in this rule based on our lifecycle analysis discussed below. In the proposed and final RFS 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 RFS 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 from 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 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 the energy cane pathway, EPA has evaluated energy cane and is now including it as a feedstock in Table 1 to § 80.1426 as approved pathways for cellulosic biofuel pathways. As described in detail in the following sections of this preamble, because of the similarity of energy cane to switchgrass and miscanthus, and because crop production input emissions (e.g., diesel and pesticide emissions) are generally a small fraction of the overall lifecycle GHG emissions (representing approximately 1% of total emissions for switchgrass), EPA believes that new agricultural sector modeling is not needed to analyze energy cane. We have instead relied upon the switchgrass VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 analysis to assess the relative GHG impacts of biofuel produced from energy cane. As with the switchgrass analysis, we have attributed all land use impacts and resource inputs from use of these feedstocks to the portion of the fuel produced that is derived from the cellulosic components of the feedstocks. Based on this analysis and currently available information, we conclude that biofuel (ethanol, cellulosic diesel, jet fuel, heating oil and naphtha) produced from the cellulosic biomass of energy cane has similar lifecycle GHG impacts to switchgrass biofuel and meets the 60% GHG reduction threshold required for cellulosic biofuel. 1. Feedstock Production and Distribution For the purposes of this rulemaking, energy cane refers to varieties of perennial grasses in the Saccharum genus which are intentionally bred for high cellulosic biomass productivity but have characteristically low sugar content making them less suitable as a primary source of sugar as compared to other varieties of grasses commonly known as ‘‘sugarcane’’ in the Saccharum genus. Energy cane varieties developed to date have low tolerance for cold temperatures but grow well in warm, humid climates. Energy cane originated from efforts to improve disease resistance and hardiness of commercial sugarcane by crossbreeding commercial and wild sugarcane strains. Certain higher fiber, lower sugar varieties that resulted were not suitable for commercial sugar production, and are now being developed as a high-biomass energy crop. There is currently no commercial production of energy cane. Current plantings are mainly limited to research field trials and small demonstrations for bioenergy purposes. However, based in part on discussions with industry, EPA anticipates continued development of energy cane particularly in the south-central and southeastern United States due to its high yields in these regions. a. Crop Yields For the purposes of analyzing the GHG emissions from energy cane 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 PO 00000 Frm 00048 Fmt 4700 Sfmt 4700 from approximately 11 to 20 dry tons per acre.46 47 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. In general, energy cane 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 pathway. Furthermore, EPA’s analysis of switchgrass for the RFS 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 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 2022.48 The ethanol yield for all of the grasses is approximately the same so the higher crop yields for energy cane result directly in greater ethanol production compared to switchgrass per acre of production. Based on these yield assumptions, in areas with suitable growing conditions, energy cane would require approximately 26% to 47% of the land area required by switchgrass to produce the same amount of biomass due to higher yields. Even without yield growth assumptions, the currently higher crop yield rates means the land use required for energy cane would be lower than for switchgrass. Therefore less crop area would be converted and displaced resulting in smaller land-use change GHG impacts than that assumed for switchgrass to produce the same amount of fuel. Furthermore, we believe energy cane will have a similar impact on international markets as assumed for switchgrass. Like switchgrass, energy cane is not expected to be traded internationally and its impacts on other crops are expected to be limited. b. Land Use In EPA’s March 2010 RFS analysis, switchgrass plantings displaced primarily soybeans and wheat, and to a lesser extent hay, rice, sorghum, and cotton. Energy cane, with production focused in the southern United States, is 46 See Bischoff, K.P., Gravois, K.A., Reagan, T.E., Hoy, J.W., Kimbeng, C.A., LaBorde, C.M., Hawkins, G.L. Plant Regis. 2008, 2, 211–217. 47 See Hale, A.L. Sugar Bulletin, 2010, 88, 28–29. 48 These yields assume no significant adverse climate impacts on world agricultural yields over the analytical timeframe. E:\FR\FM\05MRR1.SGM 05MRR1 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations emcdonald on DSK67QTVN1PROD with RULES likely to be grown on land once used for pasture, rice, commercial sod, cotton or alfalfa, which would likely have less of an international indirect impact than switchgrass because some of those commodities are not as widely traded as soybeans or wheat. Given that energy cane will likely displace the least productive land first, EPA concludes that the land use GHG impact for energy cane per gallon should be no greater and likely less than estimated for switchgrass. Considering the total land potentially impacted by all the new feedstocks included in this rulemaking would not impact these conclusions (including the camelina discussed in the previous section and energy cane considered here). As discussed previously, the camelina is expected to be grown on fallow land in the Northwest, while energy cane is expected to be grown mainly in the south on existing cropland or pastureland. In the switchgrass ethanol scenario done for the Renewable Fuel Standard final rulemaking, total cropland acres increases by 4.2 million acres, including an increase of 12.5 million acres of switchgrass, a decrease of 4.3 million acres of soybeans, a 1.4 million acre decrease of wheat acres, a decrease of 1 million acres of hay, as well as decreases in a variety of other crops. Given the higher yields of the energy cane considered here compared to switchgrass, there would be ample land available for production without having VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 any adverse impacts beyond what was considered for switchgrass production. This analysis took into account the economic conditions such as input costs and commodity prices when evaluating the GHG and land use change impacts of switchgrass. One commenter stated that by assuming no land use change for energy cane and other feedstocks, the Agency may have underestimated the increase in GHG emissions that could result from breaking new land. According to the commenter, EPA assumed that these feedstocks will be grown on the least productive land without citing any specific models or studies. The commenter appears to have misinterpreted EPA’s analysis. EPA did not assume these crops would be grown on fallow acres, nor did EPA assume that switchgrass would only be produced on the least productive lands. EPA assumed these crops would be grown on acres similar to switchgrass, and therefore applied the land use change impacts of switchgrass analyzed in the final RFS rule. In the final RFS, EPA provided detailed information on the types of crops (e.g., wheat) that would be displaced by dedicated switchgrass. This analysis took into account the economic conditions such as input costs and commodity prices when evaluating the GHG and land use change impacts of switchgrass.49 49 See Final Regulatory Impact Analysis Chapter 2, February 2010. PO 00000 Frm 00049 Fmt 4700 Sfmt 4700 14203 c. Crop Inputs and Feedstock Transport EPA also assessed the GHG impacts associated with planting, harvesting, and transporting energy cane in comparison to switchgrass. Table 6 shows the assumed 2022 commercialscale production inputs for switchgrass (used in the RFS rulemaking analysis), average energy cane production inputs (USDA projections and industry data) and the associated GHG emissions. Available data gathered by EPA suggest that energy cane requires on average less nitrogen, phosphorous, potassium, and pesticide than switchgrass per dry ton of biomass, but more herbicide, lime, diesel, and electricity per unit of biomass. This assessment assumes production of energy cane uses electricity for irrigation given that growers will likely irrigate when possible to improve yields. Irrigation rates will vary depending on the timing and amount of rainfall, but for the purpose of estimating GHG impacts of electricity use for irrigation, we assumed a rate similar to what we assumed for other irrigated crops in the Southwest, South Central, and Southeast as shown in Table 6. Applying the GHG emission factors used in the March 2010 RFS final rule, energy cane production results in slightly higher GHG emissions relative to switchgrass production (an increase of approximately 4 kg CO2eq/mmbtu). E:\FR\FM\05MRR1.SGM 05MRR1 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations GHG emissions associated with distributing energy cane are expected to VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 be similar to EPA’s estimates for switchgrass feedstock because they are PO 00000 Frm 00050 Fmt 4700 Sfmt 4700 all herbaceous agricultural crops requiring similar transport, loading, E:\FR\FM\05MRR1.SGM 05MRR1 ER05MR13.015</GPH> emcdonald on DSK67QTVN1PROD with RULES 14204 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations unloading, and storage regimes. Our analysis therefore assumes the same GHG impact for feedstock distribution as we assumed for switchgrass, although distributing energy cane could be less GHG intensive because higher yields could translate to shorter overall hauling distances to storage or biofuel production facilities per gallon or Btu of final fuel produced. emcdonald on DSK67QTVN1PROD with RULES 2. Fuel Production, Distribution, and Use Energy cane is suitable for the same conversion processes as other cellulosic feedstocks, such as switchgrass and corn stover. Currently available information on energy cane composition shows that 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 RFS rule (biochemical ethanol, thermochemical ethanol, and FischerTropsch (F–T) diesel 50) to energy cane. We assumed the GHG emissions associated with producing biofuels from energy cane 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 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, based on analysis of the increased transport emissions associated with sugarcane ethanol distribution to the U.S. considered for the 2010 final rule, this would at most add 1–2% to the overall lifecycle GHG impacts of the energy grasses. 3. Summary Based on our comparison to switchgrass, EPA believes that cellulosic biofuel produced from the cellulose, hemicellulose and lignin portions of energy cane has similar or better lifecycle GHG impacts than biofuel produced from the cellulosic biomass from switchgrass. Our analysis suggests that energy cane has GHG impacts associated with growing and harvesting 50 The F–T diesel process modeled applies to cellulosic diesel, jet fuel, heating oil, and naphtha. VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 the feedstock that are similar to switchgrass. Emissions from growing and harvesting energy cane are approximately 4 kg CO2eq/mmBtu higher than switchgrass. These are small changes in the overall lifecycle, representing at most a 6% change in the energy grass lifecycle impacts in comparison to the petroleum fuel baseline. Furthermore, energy cane is expected to have similar or lower GHG emissions than switchgrass associated with other components of the biofuel lifecycle. Under a hypothetical worst case, if the calculated increases in growing and harvesting the new feedstocks are incorporated into the lifecycle GHG emissions calculated for switchgrass, and other lifecycle components are projected as having similar GHG impacts to switchgrass (including land use change associated with switchgrass production), the overall lifecycle GHG reductions for biofuel produced from energy cane still meet the 60% reduction threshold for cellulosic biofuel. We believe these are conservative estimates, as use of energy cane as a feedstock is expected to have smaller land-use GHG impacts than switchgrass, due to higher yields. The docket for this rule provides additional detail on the analysis of energy cane as a biofuel feedstock. Although this analysis assumes energy cane biofuels produced for sale and use in the United States will most likely come from domestically produced feedstock, we also intend for the approved pathways to cover energy cane from other countries. We do not expect incidental amounts of biofuels from feedstocks produced in other nations to impact our assessment that the average GHG emissions reductions will meet the threshold for qualifying as a cellulosic biofuel pathway. Moreover, those countries most likely to be exporting energy cane or biofuels produced from energy cane are likely to be major producers which typically use similar cultivars and farming techniques. Therefore, GHG emissions from producing biofuels with energy cane grown in other countries should be similar to the GHG emissions we estimated for U.S. energy cane, though they could be slightly higher or lower. For example, the renewable biomass provisions under the Energy Independence and Security Act as outlined in the March 2010 RFS final rule regulations, would preclude use of a crop as a feedstock for renewable fuel if it was gown on land that was a direct conversion of previously unfarmed land in other countries into cropland for energy grass-based renewable fuel PO 00000 Frm 00051 Fmt 4700 Sfmt 4700 14205 production. Furthermore, any energy grass production on existing cropland internationally would not be expected to have land use impacts beyond what was considered for switchgrass production. Even if there were unexpected larger differences, EPA believes the small amounts of feedstock or fuel potentially coming from other countries will not impact our threshold analysis. Based on our assessment of switchgrass in the March 2010 RFS final rule and this comparison of GHG emissions from switchgrass and energy cane, we do not expect variations to be large enough to bring the overall GHG impact of fuel made from energy cane to come close to the 60% threshold for cellulosic biofuel. Therefore, EPA is including cellulosic biofuel produced from the cellulose, hemicelluloses and lignin portions of energy cane under the same pathways for which cellulosic biomass from switchgrass qualifies under the RFS final rule. C. Lifecycle Greenhouse Gas Emissions Analysis for Certain Renewable Gasoline and Renewable Gasoline Blendstocks Pathways 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 RFS 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 March 2010 RFS 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. E:\FR\FM\05MRR1.SGM 05MRR1 14206 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations emcdonald on DSK67QTVN1PROD with RULES 1. Feedstock Production and Distribution 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: • Cellulosic biomass from crop residue, slash, pre-commercial thinnings and tree residue, annual cover crops; • Cellulosic components of separated yard waste; • Cellulosic components of separated food waste; and • Cellulosic components of separated MSW The FASOM and FAPRI models were used to analyze the GHG impacts of the feedstock production portion of a fuel’s lifecycle. In the March 2010 RFS rulemaking, FASOM and FAPRI modeling was performed to analyze the emissions impact of using corn stover as a biofuel feedstock and this modeling was extended to some additional feedstock sources considered similar to corn stover. This approach was used for crop residues, slash, pre-commercial thinnings, tree residue and cellulosic components of separated yard, food, and MSW. These feedstocks are all excess materials and thus, like corn stover, were determined to have little or no land use change GHG impacts. Their GHG emission impacts are mainly associated with collection, transport, and processing into biofuel. See the RFS rulemaking preamble for further discussion. We used the results of the corn stover modeling in this analysis to estimate the upper bound of agricultural sector impacts from the production of the various cellulosic feedstocks noted above. The agriculture sector modeling results for corn stover represents all of the direct and significant indirect emissions in the agriculture sector (feedstock production emissions) for a certain quantity of corn stover produced. For the March 2010 RFS rulemaking, this was roughly 62 million dry tons of corn stover to produce 5.7 billion gallons of ethanol assuming biochemical fermentation to ethanol processing. We have calculated GHG emissions from feedstock production for that amount of corn stover. The GHG emissions were then divided by the total heating value of the fuel to get feedstock production emissions per mmBtu of fuel. In addition to the biochemical ethanol process, a similar analysis was completed for thermochemical ethanol and F–T diesel pathways as part of the RFS rulemaking. VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 In this rulemaking we are analyzing renewable gasoline and renewable gasoline blendstock produced from corn stover (and, by extension, other waste feedstocks). The number of gallons of fuel produced from a ton of corn stover (modeled process yields) is specific to the process used to produce renewable fuel. EPA has adjusted the results of the earlier corn stover modeling to reflect the different process yields and heating value of renewable gasoline or renewable gasoline blendstock product. The results of this calculation are shown below in Table 7. 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 gasoline blendstock (‘‘catalytic pyrolysis and upgrading’’), (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 March 2010 RFS 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.51 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 March 2010 RFS rulemaking. The fuel production section below provides further discussion on extending the GHG emissions results of the biochemical ethanol fermentation 51 Kinchin, Christopher. Catalytic Fast Pyrolysis with Upgrading to Gasoline and Diesel Blendstocks. National Renewable Energy Laboratory (NREL). 2011. PO 00000 Frm 00052 Fmt 4700 Sfmt 4700 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 RFS 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 RFS 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.52 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.53 Feedstock production emissions are shown in Table 7 below for corn stover. Corn stover feedstock production emissions are mainly a result of corn stover removal increasing the profitability of corn production (resulting in shifts in cropland and thus slight emission impacts) and also the need for additional fertilizer inputs to replace the nutrients lost when corn stover is removed. However, corn stover removal also has an emissions benefit as it encourages the use of no-till farming which results in the lowering of domestic land use change emissions. This change to no-till farming results in a negative value for domestic land use change emission impacts (see also Table 13 below). For other waste feedstocks (e.g., tree residues and cellulosic components of separate yard, food, and MSW), the feedstock production emissions are even lower than the values shown for corn stover since the 52 Aden, Andy. Feedstock Considerations and Impacts on Biorefining. National Renewable Energy Laboratory (NREL). December 2009. The report indicates that woody biomass feedstocks generally have higher yields than crop residues or herbaceous grasses (∼6% higher yields). However the same lower yield was assumed for all as a conservatively low estimate. 53 Results for feedstock distribution are aggregated along with fuel distribution and are reported in a later section, see conclusion section. E:\FR\FM\05MRR1.SGM 05MRR1 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations use of such feedstocks does not require land use changes or additional agricultural inputs. Therefore, we conclude that if the use of corn stover as a feedstock in the production of renewable gasoline and renewable gasoline blendstock yields lifecycle GHG emissions results for the resulting fuel that qualify it as cellulosic biofuel (i.e., it has at least a 60% lifecycle GHG reduction as compared to conventional fuel), then the use of other waste feedstocks with little or no land use change emissions will also result in renewable gasoline or renewable gasoline blendstock that qualifies as cellulosic biofuel. One commenter stated that the Agency assumed that using the corn stover for biofuels production would result in additional no-till farming without any evidence that the stover would actually be removed from notilled acres. This commenter feels that with recent increased profitability from corn production, farmers may actually increase tillage to reap high corn prices. This commenter urged the EPA to consider changes to soil carbon from the removal of corn stover as they may have an impact on the GHG score of this new biofuel pathway. This commenter further urged the Agency to not simply assume that additional no-till practices will be adopted with residue extraction. The analysis the EPA conducted to evaluate the GHG impacts associated with corn stover removal as part of the March 2010 RFS final rule did not assume that the corn stover had to be removed from no-till corn production. The models used to evaluate the impacts of stover removal included the option for farmers to switch to no-till practices and therefore have the option for more stover removal. As the demand for stover increased in the case where stover is used for biofuel production, the relative costs associated with no-till factored in the impact of lost corn yield as well as higher yield for corn stover. The model optimized the rate of returns for the farmers such that no-till practices were applied until the increased returns for greater stover removal on no-till acres were balanced by lost profits from lower corn yields. Therefore, the comment that we assumed stover had to come from no-till acres or that the economics would drive more intensive tillage practices is not accurate, as described in more detail in the March 2010 RFS final rule. Furthermore, there is an annual soil carbon penalty applied to crops with residue removal in our models. Thus, as one shifts from conventional corn to residue corn, an annual soil carbon 14207 penalty factor is applied. If residue removal is combined with switching to conservation tillage or no-till, then the net soil C effect would be the sum of the till change effect and the ‘‘crop change’’ effect. For the March 2010 RFS rulemaking, EPA conducted an in-depth literature review of corn stover removal practices and consulted with numerous experts in the field. In the FRM, EPA recognized that sustainable stover removal practices vary significantly based on local differences in soil and erosion conditions, soil type, landscape (slope), tillage practices, crop rotation managements, and the use of cover crops. EPA, in consultation with USDA, based its impacts on corn stover from reduced till and no till acres based on agronomical practices, nutrient requirements, and erosion considerations. EPA does not believe that the commentor has provided new information that would substantially change our analysis of the GHG emissions associated with corn stover. However, EPA will continue to monitor actual practices and based on new data will consider reviewing and revising the methodology and assumptions associated with calculating the GHG emissions from all renewable fuel feedstocks. TABLE 7—FEEDSTOCK PRODUCTION EMISSIONS FOR RENEWABLE GASOLINE AND RENEWABLE GASOLINE BLENDSTOCK PATHWAYS USING CORN STOVER Catalytic pyrolysis and upgrading to renewable gasoline and renewable gasoline blendstock (g CO2-eq./mmBtu) Biochemical fermentation and upgrading to renewable gasoline and renewable gasoline blendstock via carboxylic acid (g CO2-eq./mmBtu) Direct biochemical fermentation process to renewable gasoline and renewable gasoline blendstock (g CO2-eq./ mmBtu) Domestic Livestock ...................................................................... Domestic Farm Inputs and Fertilizer N2O ................................... Domestic Rice Methane .............................................................. Domestic Land Use Change ....................................................... International Livestock ................................................................. International Farm Inputs and Fertilizer N2O .............................. International Rice Methane .......................................................... International Land Use Change ................................................... 7,648 1,397 366 ¥9,124 0 0 0 0 6,770 1,237 324 ¥8,076 0 0 0 0 ∼ 9,086 ∼ 1,660 ∼ 434 ∼¥10,820 0 0 0 0 Total Feedstock Production Emissions: ............................... Assumed yield (gal/ton of biomass) ............................................ 287 64.5 254 75 ∼ 361 92.3 emcdonald on DSK67QTVN1PROD with RULES Feedstock production emission sources The results in Table 7 differ for the different pathways considered because of the different amounts of corn stover used to produce the same amount of fuel in each case. Table 7 only considers the feedstock production impacts associated with the renewable gasoline or renewable gasoline blendstocks pathways, other aspects of the lifecycle are discussed in the following sections. VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 2. Fuel Distribution A petroleum gasoline baseline was developed as part of the RFS final rule which included estimates for fuel distribution emissions. Since renewable gasoline and renewable gasoline blendstocks when blended into gasoline are similar to petroleum gasoline, it is reasonable to assume similar fuel distribution emissions. Therefore, the existing fuel distribution lifecycle GHG PO 00000 Frm 00053 Fmt 4700 Sfmt 4700 impacts of the petroleum gasoline baseline from the RFS final rule were applied to this analysis. 3. Use of the Fuel A petroleum gasoline baseline was developed as part of the RFS final rule which estimated the tailpipe emissions from fuel combustion. Since renewable gasoline and renewable gasoline blendstock are similar to petroleum gasoline in energy and hydrocarbon E:\FR\FM\05MRR1.SGM 05MRR1 14208 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations content, the non-CO2 combustion emissions calculated as part of the RFS final rule for petroleum gasoline were applied to our analysis of the renewable gasoline and renewable gasoline blendstock pathways. Only non-CO2 emissions were included since carbon fluxes from land use change are accounted for as part of the biomass feedstock production. 4. Fuel Production In the March 2010 RFS rulemaking, EPA analyzed several of the main cellulosic biofuel pathways: a biochemical fermentation process to ethanol and two thermochemical gasification processes, one producing mixed alcohols (primarily ethanol) and the other one producing mixed hydrocarbons (primarily diesel fuel). These pathways all exceeded the 60% lifecycle GHG threshold requirements for cellulosic biofuel using the specified feedstocks. Refer to the preamble and regulatory impact analysis (RIA) from the final rule for more details. From these analyses, it was determined that ethanol and diesel fuel produced from the specified cellulosic feedstocks and processes would be eligible for cellulosic and advanced biofuel RINs. The thermochemical gasification process to diesel fuel (via F–T synthesis) also produces a smaller portion of renewable gasoline blendstock. In the final 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. In this rule, we are changing the reference to F–T as the process technology to the more correct reference as gasification technology since F–T reactions are only part of the process technology. Since the final March 2010 RFS 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 3.54 For the reasons described below, we have decided to authorize the generation of RINs with a D code of 3 for renewable gasoline and renewable gasoline blendstock produced using specified cellulosic feedstocks for the processes considered here. 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 and upgrading’’), 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’’) and other thermocatalytic hydrodeoxygenation routes with upgrading such as aqueous phase processing.55 56 Similar to how we analyzed several of the main routes for cellulosic ethanol and cellulosic diesel for the final March 2010 RFS rule, we have chosen to analyze the main renewable gasoline and renewable gasoline blendstock pathways in order to estimate the potential GHG reduction profile for renewable gasoline and renewable gasoline blendstock across a range of other production technologies for which we are confident will have at least as great of GHG emission reductions as those specifically analyzed. a. Catalytic Pyrolysis With Upgrading to Renewable Gasoline and Renewable Gasoline Blendstock 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.57 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 renewable gasoline, renewable gasoline blendstock and renewable diesel streams (cellulosic diesel from catalytic pyrolysis is already included as an acceptable pathway in the RFS 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 biogas 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 [Btu/gal] Biomass use Natural gas use Purchased electricity Sold electricity Catalytic Pyrolysis to Renewable Gasoline or Renewable Gasoline Blendstock .................................................................................................... emcdonald on DSK67QTVN1PROD with RULES Technology 136,000 51,000 0 ¥2,000 54 See https://www.epa.gov/otaq/fuels/ renewablefuels/compliancehelp/rfs2-lcapathways.htm for list of petitions received by EPA. 55 Regalbuto, John. ‘‘An NSF perspective on next generation hydrocarbon biorefineries,’’ Computers VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 and Chemical Engineering 34 (2010) 1393–1396. February 2010. 56 Serrano-Ruiz, J., Dumesic, James. ‘‘Catalytic routes for the conversion of biomass into liquid hydrocarbon transportation fuels,’’ Energy Environmental Science (2011) 4, 83–99. PO 00000 Frm 00054 Fmt 4700 Sfmt 4700 57 Kinchin, Christopher. Catalytic Fast Pyrolysis with Upgrading to Gasoline and Diesel Blendstocks. National Renewable Energy Laboratory (NREL). 2011. E:\FR\FM\05MRR1.SGM 05MRR1 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations The emissions from energy inputs were calculated by multiplying the amount of energy by emission factors for fuel production and combustion, based on the same method and factors used in the March 2010 RFS final rulemaking. The emission factors for the different fuel types are from GREET and were based on assumed carbon contents of the different process fuels. The emissions from producing electricity in the U.S. were also taken from GREET and represent average U.S. grid electricity production emissions. The major factors influencing the emissions from the fuel production 14209 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.58 See Table 9 for a summary of emissions from fuel production. TABLE 9—FUEL PRODUCTION EMISSIONS FOR CATALYTIC PYROLYSIS AND UPGRADING TO RENEWABLE GASOLINE OR RENEWABLE GASOLINE BLENDSTOCK USING CORN STOVER Catalytic pyrolysis to renewable gasoline or renewable gasoline blendstock (g CO2-eq./mmBtu) Lifecycle stage On-Site & Upstream Emissions (Natural Gas & Biomass*) ................................................................................................ Electricity Co-Product Credit ............................................................................................................................................... 31,000 ¥3,000 Total Fuel Production Emissions: ................................................................................................................................. 28,000 * Only non-CO2 combustion emissions from biomass b. Catalytic Upgrading of Biochemically Derived Intermediates to Renewable Gasoline and Renewable Gasoline Blendstock The second production process we investigated is a biochemical fermentation process to intermediate, such as carboxylic acids with catalytic upgrading to renewable gasoline or renewable gasoline blendstock. This process involves the fermentation of biomass using microorganisms that produce a variety of carboxylic acids. If the feedstock has high lignin content, then the biomass is pretreated to enhance digestibility. The acids are then neutralized to carboxylate salts and further converted to ketones and alcohols for refining into gasoline, diesel, and jet fuel. The process requires the use of natural gas and hydrogen inputs.59 No purchased electricity is required as lignin is projected to be used to meet all facility demands as well as provide excess electricity to the grid. EPA used the estimated energy and material inputs along with emission factors to estimate the GHG emissions from this process. The energy inputs and electricity credits are shown in Table 10, below. These inputs are based on Confidential Business Information (CBI), rounded to the nearest 1000 units, provided by industry as part of the petition process for new fuel pathways. TABLE 10—2022 ENERGY USE AT CELLULOSIC FACILITY [Btu/gal] Technology Biomass use Biochemical Fermentation to Renewable Gasoline or Renewable Gasoline Blendstock via Carboxylic Acid .................................................................... The process also uses a small amount of buffer material as neutralizer which was not included in the GHG lifecycle 49,000 results due to its likely negligible emissions impact. The GHG emissions Natural gas use Purchased electricity 59,000 Sold electricity 0 ¥2,000 estimates from the fuel production stage are seen in Table 11. TABLE 11—FUEL PRODUCTION EMISSIONS FOR BIOCHEMICAL FERMENTATION TO RENEWABLE GASOLINE OR RENEWABLE GASOLINE BLENDSTOCK VIA CARBOXYLIC ACID USING CORN STOVER GHG Emissions (g CO2-eq./mmBtu) Lifecycle stage On-Site & Upstream Emissions (Natural Gas & Biomass*) ................................................................................................ Electricity Co-Product Credit ............................................................................................................................................... Total Fuel Production Emissions: ........................................................................................................................................ 33,000 ¥3,000 30,000 emcdonald on DSK67QTVN1PROD with RULES * Only non-CO2 combustion emissions from biomass 58 A steam methane reformer (SMR) is used to produce the hydrogen necessary for hydroprocessing. In the U.S. over 95% of hydrogen is currently produced via steam reforming (DOE, 2002 ‘‘A National Vision of America’s Transition to a Hydrogen Economy to 2030 and Beyond’’). Other VerDate Mar<15>2010 18:47 Mar 04, 2013 Jkt 229001 alternatives are available, such as renewable or nuclear resources used to extract hydrogen from water or the use of biomass to produces hydrogen. These alternative methods, however, are currently not as efficient or cost effective as the use of fossil fuels and therefore we conservatively estimate PO 00000 Frm 00055 Fmt 4700 Sfmt 4700 emissions from hydrogen production using the more commonly used SMR technology. 59 Hydrogen emissions are modeled as natural gas and electricity demands. E:\FR\FM\05MRR1.SGM 05MRR1 14210 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations c. Biological Conversion to Renewable Gasoline and Renewable Gasoline Blendstock The third production process we investigated involves the use of microorganisms to biologically convert 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 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 generally separate spontaneously from the aqueous phase, thereby avoiding poisoning of microbes by the accumulated products and facilitating separation/collection of hydrocarbons 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. Therefore, we can conservatively extend our final March 2010 RFS rule biochemical fermentation to ethanol process results to a similar (but likely slightly improved) process that instead produces hydrocarbons. Since the final rule cellulosic ethanol GHG results were well above the 60% GHG reduction threshold for cellulosic biofuels, if actual emissions from other necessary changes to the direct biochemical fermentation to hydrocarbons process represent some small increment in GHG emissions, the pathway would still likely meet the threshold. Table 12 is our qualitative assessment of the potential emissions reductions from a process using biochemical fermentation to cellulosic hydrocarbons assuming similarities to the biochemical fermentation to cellulosic ethanol route from the final rule. TABLE 12—FUEL PRODUCTION EMISSIONS FOR MARCH 2010 RFS CELLULOSIC BIOCHEMICAL ETHANOL COMPARED TO DIRECT BIOCHEMICAL FERMENTATION TO RENEWABLE GASOLINE OR RENEWABLE GASOLINE BLENDSTOCK USING CORN STOVER Cellulosic biochemical ethanol emissions (g CO2-eq./mmBtu) Lifecycle stage On-Site Emissions & Upstream (biomass) .............................................................................. Electricity Co-Product Credit ................................................................................................... Total Fuel Production Emissions 60: ........................................................................................ Table 13 below breaks down by stage the lifecycle GHG emissionsfor the renewable gasoline and renewable gasoline blendstock pathways using corn stover and the 2005 petroleum baseline. The table demonstrates the Direct biochemical fermentation to renewable gasoline and renewable gasoline blendstock emissions (g CO2-eq./mmBtu) 3,000 ¥35,000 ¥33,000 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.61 As noted above, these analyses < or = 3,000 = ¥35,000 < or = ¥33,000 assume natural gas as the process energy when needed; using biogas 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 [kg CO2-eq./mmBtu] emcdonald on DSK67QTVN1PROD with RULES Fuel type Catalytic pyrolysis and upgrade to renewable gasoline and renewable gasoline blendstock Biochemical fermentation to renewable gasoline and renewable gasoline blendstock via carboxylic acid Direct biochemical fermentation to renewable gasoline and renewable gasoline blendstock 2005 gasoline baseline Net Domestic Agriculture (w/o land use change) ............................................ Net International Agriculture (w/o land use change) ....................................... Domestic Land Use Change ........................................................................... International Land Use Change ....................................................................... Fuel Production ................................................................................................ Fuel and Feedstock Transport ........................................................................ Tailpipe Emissions ........................................................................................... 9 ........................ ¥9 ........................ 28 2 2 8 ........................ ¥8 ........................ 30 2 2 ∼ 11 ........................ ∼ ¥11 ........................ < or = ¥33 ∼2 ∼1 ........................ ........................ ........................ ........................ 19 * 79 Total Emissions ........................................................................................ 32 34 < or = ¥29 98 60 Numbers do not add up due to rounding. VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 61 Memorandum to the Air and Radiation Docket EPA–HQ–OAR–2011–0542 ‘‘Supplemental Information for Renewable Gasoline and Renewable PO 00000 Frm 00056 Fmt 4700 Sfmt 4700 Gasoline Blendstock Pathways Under the Renewable Fuel Standard (RFS2) Program’’. E:\FR\FM\05MRR1.SGM 05MRR1 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14211 TABLE 13—LIFECYCLE GHG EMISSIONS FOR RENEWABLE GASOLINE AND RENEWABLE GASOLINE BLENDSTOCK PATHWAYS USING CORN STOVER, 2022—Continued [kg CO2-eq./mmBtu] Catalytic pyrolysis and upgrade to renewable gasoline and renewable gasoline blendstock Fuel type % Change from Baseline ................................................................................. ¥67% Biochemical fermentation to renewable gasoline and renewable gasoline blendstock via carboxylic acid ¥65% Direct biochemical fermentation to renewable gasoline and renewable gasoline blendstock ¥129% 2005 gasoline baseline ........................ * Emissions included in fuel production stage. emcdonald on DSK67QTVN1PROD with RULES d. Extension of Modeling Results to Other Production Processes Producing Renewable Gasoline or Renewable Gasoline Blendstock In the March 2010 RFS rulemaking, we modeled the GHG emissions results from the biochemical fermentation process to ethanol, thermochemical gasification processes to mixed alcohols (primarily ethanol) and mixed hydrocarbons (primarily diesel fuel). We extended these modeled process results to apply when the biofuel was produced from ‘‘any’’ process. We determined that since we modeled multiple cellulosic biofuel processes and all were shown to exceed the 60% lifecycle GHG threshold requirements for cellulosic biofuel using the specified feedstocks its was reasonable to extend to other processes (e.g. additional thermo-catalytic hydrodeoxygenation routes with upgrading similar to pyrolysis and aqueous phase processing) that might develop as these would likely represent improvements over existing processes as the industry works to improve the economics of cellulosic biofuel production by, for example, reducing energy consumption and improving process yields. Similarly, this rule assesses multiple processes for the production of renewable gasoline and renewable gasoline blendstocks and all were shown to exceed the 60% lifecycle GHG threshold requirements for cellulosic biofuel using specified feedstocks. 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 VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 literature. 62 63 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: • Pyrolysis and Upgrading—in which cellulosic biomass is decomposed with temperature to bio-oils and requires further catalytic processing to produce a finished fuel • Gasification—in which cellulosic biomass is decomposed to syngas with further catalytic processing of methanol to gasoline or through Fischer-Tropsch (F–T) synthesis to gasoline The processes under the biochemical category include: • Biological conversion to hydrocarbons—requires the release of sugars from biomass and microorganisms to biologically convert sugars straight into hydrocarbons instead of alcohols • Catalytic upgrading of biochemically produced intermediates—requires the release of sugars from biomass and aqueous- or liquid-phase processing of sugars or biochemically produced intermediate products into hydrocarbons using solid catalysts, As part of the modeling effort here, as well as for the March 2010 RFS final rule, we have considered the lifecycle GHG impacts of the four possible production technologies mentioned above. The pyrolysis and upgrading, direct biological conversion, and catalytic upgrading of biochemically produced intermediates are considered in this rule and the gasification route was already included in the March 2010 62 Regalbuto, John. ‘‘An NSF perspective on next generation hydrocarbon biorefineries,’’ Computers and Chemical Engineering 34 (2010) 1393–1396. February 2010. 63 Serrano-Ruiz, J., Dumesic, James. ‘‘Catalytic routes for the conversion of biomass into liquid hydrocarbon transportation fuels,’’ Energy Environmental Science (2011) 4, 83–99. PO 00000 Frm 00057 Fmt 4700 Sfmt 4700 final rule. In all cases, the processes that we have considered meet the 60% lifecycle GHG reduction required for cellulosic biofuels. Furthermore, we believe that the results from our modeling would cover all the likely variations within these potential routes for producing renewable gasoline and renewable gasoline blendstock which also use natural gas, biogas or biomass 64 for process energy and that all such production variations would also meet the 60% lifecycle threshold.65 The main reason for this is that we believe that our energy input assumptions are reasonable at this time but probably in some cases are conservatively high for commercial scale cellulosic facilities. The cellulosic industry is in its early stages of development and many of the estimates of process technology GHG impacts is based on pre-commercial scale assessments and demonstration programs. Commercial scale cellulosic facilities will continue to make efficiency improvements over time to maximize their fuel products/coproducts and minimize wastes. For cellulosic facilities, such improvements include increasing conversion yields and fully utilizing the biomass input for valuable products. An example of increasing the amount of biomass utilized is the combustion of undigested or unconverted biomass for heat and power. The three routes that we analyzed for the production of renewable gasoline and renewable gasoline blendstock in today’s rule assume an electricity production credit from the economically-driven use of lignin or waste byproducts; we also ran 64 Our lifecycle analysis assumes that producers would use the same type of biomass as both the feedstock and the process energy. 65 One commenter wanted clarification of the term ‘‘process energy’’ as it applies to the production of renewable gasoline. The EPA did not intend for the term, ‘‘process energy’’, to include other energy sources, such as electricity to provide power for ancillary processes, such as lights, small pumps, computers, and other small support equipment. E:\FR\FM\05MRR1.SGM 05MRR1 emcdonald on DSK67QTVN1PROD with RULES 14212 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations a sensitivity case where no electricity credit was given. We found that all of the routes analyzed would still pass the GHG threshold without an electricity credit, providing confidence that over the range of technology options, these process technologies will surely allow the cellulosic biofuel produced to exceed the threshold for cellulosic biofuel GHG performance. Without excess electricity production the catalytic pyrolysis pathway results in a 65% lifecycle GHG reduction, the biochemical fermentation via carboxylic acid pathway results in a 62% lifecycle GHG reduction, and the direct biochemical fermentation pathway results in a 93% reduction in lifecycle GHG emissions compared to the petroleum fuel baseline. Additionally, while the final results reported in this rule include an electricity credit, this electricity credit is based on current technology for generating electricity; it is possible that over the next decade as cellulosic biofuel production matures, the efficiency with which electricity is generated at these facilities will also improve. Such efficiency improvements will tend to improve the GHG performance for cellulosic biofuel technologies in general including those used to produce renewable gasoline. 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 than 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.66 Thus, fossil natural gas consumption could be further minimized under certain 66 Kinchin, Christopher. Catalytic Fast Pyrolysis with Upgrading to Gasoline and Diesel Blendstocks. National Renewable Energy Laboratory (NREL). 2011. VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 scenarios. We believe that as commercial scale cellulosic facilities develop, more of these improvements will be made to maximize the use of all the biomass and waste byproducts available to bring the facility closer to energy self-sufficiency. These improvements could help to increase the economic profitability for cellulosic facilities where fossil energy inputs become costly to purchase. Therefore we can extend the modeling results for our pyrolysis route to all variations of this production technology which use natural gas, biogas or biomass for production energy for producing renewable gasoline or renewable gasoline blendstock. The F–T gasification technology route considered as part of the March 2010 RFS final rule resulted in an approximately 91% reduction in lifecycle GHG emissions compared to the petroleum baseline. This could be considered a conservatively high 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 H2 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 originally 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 PO 00000 Frm 00058 Fmt 4700 Sfmt 4700 allowing the pathway to meet the GHG performance threshold. There is an even wider gap between the results modeled for the direct fermentation route and the cellulosic lifecycle GHG threshold. The variation we considered for the direct fermentation process resulted in an approximately 129% reduction in lifecycle GHG emissions compared to the petroleum baseline. This process did consider production of electricity as part of the process but as mentioned even if this was not the case the pathway would still easily fall below the 60% lifecycle threshold for cellulosic biofuels. If actual emissions from other necessary changes to the direct biochemical fermentation to hydrocarbons process represent some small increment in GHG emissions, the pathway would still likely meet the threshold. Therefore, we can extend the results to all variations of the direct biochemical route for renewable gasoline or renewable gasoline blendstock production which use natural gas, biogas or biomass for production energy. The biochemical with catalytic upgrading route that we evaluated resulted in a 65% reduction in GHG emissions compared to the petroleum baseline. However, this can be considered a conservatively high estimate. For instance, the biochemical fermentation to gasoline via carboxylic acid route considered did not include the potential for generating steam from the combustion of undigested biomass and then using this steam for process energy. If this had been included, natural gas consumption could potentially be decreased which would lower the potential GHG emissions estimated from the process. Therefore, the scenario analyzed could be considered conservative in estimating actual natural gas usage. As was the case with the pyrolysis route considered, we believe that as commercial scale cellulosic facilities develop, improvements will be made to maximize the use of all the biomass and waste byproducts available to bring the facility closer to energy self-sufficiency. These improvements help to increase the economic profitability for cellulosic facilities where fossil energy inputs become costly to purchase. The processes we analyzed for this rulemaking utilized a mix of natural gas and biomass for process energy, with biogas replacing natural gas providing improved GHG performance. We have not analyzed other fuel types (e.g., coal) and are therefore not approving processes that utilized other fuel sources at this point. Therefore, we are E:\FR\FM\05MRR1.SGM 05MRR1 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations emcdonald on DSK67QTVN1PROD with RULES extending our results to include all variations of the biochemical with catalytic upgrading process utilizing natural gas, biogas or biomass for process energy. While actual cellulosic facilities may show some modifications to the process scenarios we have already analyzed, our results give a good indication of the range of emissions we could expect from processes producing renewable gasoline and renewable gasoline blendstock from cellulosic feedstock, all of which meet the 60% cellulosic biofuel threshold (assuming they are utilizing natural gas, biogas or biomass for process energy). Technology changes in the future are likely to increase efficiency to maximize profits, while also lowering lifecycle GHG emissions. Therefore, we have concluded that since all of the renewable gasoline or renewable gasoline blendstock fuel processing methods we have analyzed exceed the 60% threshold using specific cellulosic feedstock types, we can conclude that processes producing renewable gasoline or renewable gasoline blendstock that fit within the categories of process analyzed here and are produced from the same feedstock types and using natural gas, biogas or biomass for process energy use will also meet the 60% GHG reduction threshold. In addition, while other technologies may develop, we expect that they will only become commercially competitive if they have better yields (more gallons per ton of feedstock) or lower production costs due to lower energy consumption. Both of these factors would suggest better GHG performance. This would certainly be the case if such processes also relied upon using biogas and/or biomass as the primary energy source. Therefore based on our review of the existing primary cellulosic biofuel production processes, likely GHG emission improvements for existing or new technologies, and consideration of the positive GHG emissions benefits associated with using biogas and/or biomass for process energy, we are approving for cellulosic RIN generation any process for renewable gasoline and renewable gasoline blendstock production using specified cellulosic biomass feedstocks as long as the process utilizes biogas and/or biomass for all process energy. 5. Summary Three renewable gasoline and renewable gasoline blendstock pathways were compared to baseline petroleum gasoline, using the same value for baseline gasoline as in the March 2010 RFS final rule analysis. The results of the analysis indicate that the VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 renewable gasoline and renewable gasoline blendstock pathways result in a GHG emissions reduction of 65–129% or better compared to the gasoline fuel it would replace using corn stover as a feedstock. The renewable gasoline and renewable gasoline blendstock pathways which use corn stover as a feedstock all exceed the 60% lifecycle GHG threshold requirements for cellulosic biofuel, these pathways capture the likely current technologies, and future technology improvements are likely to increase efficiency and lower GHG emissions. Therefore we have determined that all processes producing renewable gasoline or renewable gasoline blendstock from corn stover can qualify if they fall in the following process characterizations: • Catalytic pyrolysis and upgrading utilizing natural gas, biogas, and/or biomass as the only process energy sources • Gasification and upgrading utilizing natural gas, biogas, and/or biomass as the only process energy sources • Thermo-catalytic hydrodeoxygenation processes such as aqueous phase processing with upgrading sufficiently similar to pyrolysis and gasification • Direct fermentation utilizing natural gas, biogas, and/or biomass as the only process energy sources • Fermentation and upgrading 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. As was the case for extending corn stover results to other feedstocks in the March 2010 RFS final rule, these results are also reasonably extended to feedstocks with similar or lower GHG emissions profiles, including the following feedstocks: • Cellulosic biomass from crop residue, slash, pre-commercial thinnings and tree residue, annual cover crops; • Cellulosic components of separated yard waste; • Cellulosic components of separated food waste; and • Cellulosic components of separated MSW For more information on the reasoning for extension to these other feedstocks refer to the feedstock production and distribution section or the March 2010 RFS rulemaking (75 FR 14670). Based on these results, today’s rule includes pathways for the generation of cellulosic biofuel RINs for renewable gasoline or renewable gasoline PO 00000 Frm 00059 Fmt 4700 Sfmt 4700 14213 blendstock produced by catalytic pyrolysis and upgrading, gasification and upgrading, other similar thermocatalytic hydrodeoxygenation routes with upgrading, direct fermentation, fermentation and upgrading, all utilizing natural gas, biogas, and/or biomass as the only process energy sources or any process utilizing biogas and/or biomass as the only energy sources, and using corn stover as a feedstock or the feedstocks noted above. In order to qualify for RIN generation, the fuel must meet the other definitional criteria for renewable fuel (e.g., produced from renewable biomass, and used to reduce or replace petroleumbased transportation fuel, heating oil or jet fuel) specified in the Clean Air Act and the RFS regulations. A manufacturer of a renewable motor vehicle gasoline (including parties using a renewable blendstock obtained from another party), must satisfy EPA motor vehicle registration requirements in 40 CFR part 79 for the fuel to be used as a transportation fuel. Per 40 CFR 79.56(e)(3)(i), a renewable motor vehicle gasoline would be in the Non-Baseline Gasoline category or the Atypical Gasoline category (depending on its properties) since it is not derived only from conventional petroleum, heavy oil deposits, coal, tar sands and/or oil sands (40 CFR 79.56(e)(3)(i)(5)). In either case, the Tier 1 requirements at 40 CFR 79.52 (emissions characterization) and the Tier 2 requirements at 40 CFR 79.53 (animal exposure) are conditions for registration unless the manufacturer qualifies for a small business provision at 40 CFR 79.58(d). For a non-baseline gasoline, a manufacturer under $50 million in annual revenue is exempt from Tier 1 and Tier 2. For an atypical gasoline there is no exemption from Tier 1, but a manufacturer under $10 million in annual revenue is exempt from Tier 2. Registration for a motor vehicle gasoline at 40 CFR 79 is via EPA Form 3520–12, Fuel Manufacturer Notification for Motor Vehicle Fuel, available at: https://www.epa.gov/otaq/ regs/fuels/ffarsfrms.htm. D. Esterification Production Process Inclusion for Specified Feedstocks Producing Biodiesel The Agency is not taking final action at this time on its proposed inclusion of the process ‘‘esterification’’ as an approved biodiesel production process in Table 1 to § 40 CFR 80.1426. See 77 FR 465. We continue to evaluate the issue and anticipate issuing a final determination as part of a subsequent rulemaking. E:\FR\FM\05MRR1.SGM 05MRR1 emcdonald on DSK67QTVN1PROD with RULES 14214 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations III. Additional Changes to Listing of Available Pathways in Table 1 of 80.1426 We are also finalizing two changes to Table 1 to 80.1426 that were proposed on July 1, 2011(76 FR 38844). The first change adds ID letters to pathways to facilitate references to specific pathways. The second change adds ‘‘rapeseed’’ to the existing pathway for renewable fuel made from canola oil. On September 28, 2010, EPA published a ‘‘Supplemental Determination for Renewable Fuels Produced Under the Final RFS2 Program from Canola Oil’’ (75 FR 59622). 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 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. Second, we wish to clarify that although the GHG emissions of producing fuels from canola feedstock grown in the U.S. and Canada was specifically modeled as the most likely source of canola (or rapeseed) oil used for biodiesel produced for sale and use in the U.S., we also intended that the approved pathway cover canola/ rapeseed oil from other countries, and we interpret our regulations in that manner. We expect the vast majority of biodiesel used in the U.S. and produced from canola/rapeseed oil will come from U.S. and Canadian crops. Incidental amounts from crops produced in other nations will not impact our average VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 GHG emissions for two reasons. First, our analyses considered world-wide impacts and thus considered canola/ rapeseed crop production in other countries. Second, other countries most likely to be exporting canola/rapeseed or biodiesel product from canola/ rapeseed are likely to be major producers which typically use similar cultivars and farming techniques. Therefore, GHG emissions from producing biodiesel with canola/ rapeseed grown in other countries should be very similar to the GHG emissions we modeled for Canadian and U.S. canola, though they could be slightly (and insignificantly) higher or lower. At any rate, even if there were unexpected larger differences, EPA believes the small amounts of feedstock or fuel potentially coming from other countries will not impact our threshold analysis. Therefore, EPA interprets the approved canola pathway as covering canola/rapeseed regardless of country of origin. We are also correcting an inadvertent omission to the proposal which incorrectly did not include a pathway for producing naphtha from switchgrass and miscanthus; this pathway was included in the original March 2010 RFS final rule. This pathway also incorporates the additional energy grass feedstock sources being added today, namely energy cane. IV. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is a ‘‘significant regulatory action.’’ Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in response to OMB recommendations have been documented in the docket for this action. B. Paperwork Reduction Act This action does not impose any new information collection burden. The corrections, clarifications, and modifications to the final March 2010 RFS regulations contained in this rule are within the scope of the information collection requirements submitted to the Office of Management and Budget (OMB) for the final March 2010 RFS regulations. OMB has approved the information collection requirements contained in the PO 00000 Frm 00060 Fmt 4700 Sfmt 4700 existing regulations at 40 CFR part 80, subpart M under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060– 0637 and 2060– 0640. The OMB control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR part 9. C. Regulatory Flexibility Act The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of today’s rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration’s (SBA) regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field. After considering the economic impacts of this action on small entities, I certify that this rule will not have a significant economic impact on a substantial number of small entities. This rule will not impose any new requirements on small entities. The relatively minor corrections and modifications this rule makes to the final March 2010 RFS regulations do not impact small entities. D. Unfunded Mandates Reform Act This rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year. We have determined that this action will not result in expenditures of $100 million or more for the above parties and thus, this rule is not subject to the requirements of sections 202 or 205 of UMRA. This rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. It only applies to gasoline, diesel, and renewable fuel producers, importers, distributors and marketers and makes E:\FR\FM\05MRR1.SGM 05MRR1 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations relatively minor corrections and modifications to the RFS regulations. E. Executive Order 13132 (Federalism) This action does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. This action only applies to gasoline, diesel, and renewable fuel producers, importers, distributors and marketers and makes relatively minor corrections and modifications to the RFS regulations. Thus, Executive Order 13132 does not apply to this action. F. Executive Order 13175 (Consultation and Coordination With Indian Tribal Governments) This rule does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). It applies to gasoline, diesel, and renewable fuel producers, importers, distributors and marketers. This action makes relatively minor corrections and modifications to the RFS regulations, and does not impose any enforceable duties on communities of Indian tribal governments. Thus, Executive Order 13175 does not apply to this action. emcdonald on DSK67QTVN1PROD with RULES G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5–501 of the EO has the potential to influence the regulation. This action is not subject to EO 13045 because it does not establish an environmental standard intended to mitigate health or safety risks. H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This action is not a ‘‘significant energy action’’ as defined in Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. This rulemaking does not change any programmatic structural component of the RFS regulatory requirements. This rulemaking does not add any new requirements for obligated parties under the program or mandate the use of any of the new pathways contained in the rule. This rulemaking only makes a VerDate Mar<15>2010 13:43 Mar 04, 2013 Jkt 229001 determination to qualify new fuel pathways under the RFS regulations, creating further opportunity and flexibility for compliance with the Energy Independence and Security Act of 2007 (EISA) mandates. I. National Technology Transfer and Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (‘‘NTTAA’’), Public Law 104–113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards. This action does not involve technical standards. Therefore, EPA did not consider the use of any voluntary consensus standards. J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes Federal executive policy on environmental justice. Its main provision directs Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States. EPA has determined that this rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it does not affect the level of protection provided to human health or the environment. These amendments would not relax the control measures on sources regulated by the RFS regulations and therefore would not cause emissions increases from these sources. K. Congressional Review Act The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides PO 00000 Frm 00061 Fmt 4700 Sfmt 4700 14215 that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. A major rule cannot take effect until 60 days after it is published in the Federal Register. EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule the Federal Register. This action is not a ‘‘major rule’’ as defined by 5 U.S.C. 804(2). V. Statutory Provisions and Legal Authority Statutory authority for the rule finalized today can be found in section 211 of the Clean Air Act, 42 U.S.C. 7545. Additional support for today’s rule comes from Section 301(a) of the Clean Air Act, 42 U.S.C. 7414, 7542, and 7601(a). List of Subjects in 40 CFR Part 80 Environmental protection, Administrative practice and procedure, Agriculture, Air pollution control, Confidential business information, Diesel Fuel, Energy, Forest and Forest Products, Fuel additives, Gasoline, Imports, Labeling, Motor vehicle pollution, Penalties, Petroleum, Reporting and recordkeeping requirements. Dated: February 22, 2013. Bob Perciasepe, Acting Administrator. For the reasons set forth in the preamble, 40 CFR part 80 is amended as follows: PART 80—REGULATION OF FUELS AND FUEL ADDITIVES 1. The authority citation for part 80 continues to read as follows: ■ Authority: 42 U.S.C. 7414, 7521(1), 7545 and 7601(a). 2. Section 80.1401 is amended by adding definitions of ‘‘Energy cane,’’ ‘‘Renewable gasoline’’ and ‘‘Renewable gasoline blendstock’’ in alphabetical order to read as follows: ■ § 80.1401 Definitions. * * * * * Energy cane means a complex hybrid in the Saccharum genus that has been bred to maximize cellulosic rather than sugar content. For the purposes of this section, energy cane excludes the species Saccharum spontaneum, but includes hybrids derived from S. E:\FR\FM\05MRR1.SGM 05MRR1 14216 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations spontaneum that have been developed and publicly released by USDA. * * * * * Renewable gasoline means renewable fuel made from renewable biomass that is composed of only hydrocarbons and which meets the definition of gasoline in § 80.2(c). Renewable gasoline blendstock means a blendstock made from renewable biomass that is composed of only hydrocarbons and which meets the definition of gasoline blendstock in § 80.2(s). * * * * * 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? * * * (f) * * * (1) * * * * * TABLE 1 TO § 80.1426—APPLICABLE D CODES FOR EACH FUEL PATHWAY FOR USE IN GENERATING RINS Fuel type Feedstock Production process requirements A ....... Ethanol .................. Corn starch .......................................................... B ....... Ethanol .................. Corn starch .......................................................... C ....... Ethanol .................. Corn starch .......................................................... D ....... Ethanol .................. Corn starch .......................................................... E ....... Ethanol .................. F ....... Biodiesel, renewable diesel, jet fuel and heating oil. Biodiesel, heating oil. Biodiesel, renewable diesel, jet fuel and heating oil. Naphtha, LPG ....... Ethanol .................. Ethanol .................. Starches from crop residue and annual covercrops. Soy bean oil; Oil from annual covercrops; Algal oil; Biogenic waste oils/fats/greases; Non-food grade corn oil Camelina sativa oil. 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. 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. Wet mill process using biomass or biogas for process energy. Fermentation using natural gas, biomass, or biogas for process energy. One of the following: Trans-Esterification Hydrotreating Excluding processes that coprocess renewable biomass and petroleum. G ...... H ....... I ........ J ....... K ....... Cellulosic diesel, jet fuel and heating oil. M ...... emcdonald on DSK67QTVN1PROD with RULES L ....... Renewable gasoline and renewable gasoline blendstock. N ....... Naphtha ................ O ...... Butanol .................. VerDate Mar<15>2010 13:43 Mar 04, 2013 Canola/Rapeseed oil ........................................... Soy bean oil; Oil from annual covercrops; Algal oil; Biogenic waste oils/fats/greases; Non-food grade corn oil Camelina sativa oil. Camelina sativa oil .............................................. Sugarcane ........................................................... Cellulosic Biomass from crop residue, slash, pre-commercial thinnings and tree residue, annual covercrops, switchgrass, miscanthus, and energy cane; cellulosic components of separated yard waste; cellulosic components of separated food waste; and cellulosic components of separated MSW. Cellulosic Biomass from crop residue, slash, pre-commercial thinnings and tree residue, annual covercrops, switchgrass, miscanthus, and energy cane; cellulosic components of separated yard waste; cellulosic components of separated food waste; and cellulosic components of separated MSW. 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. Cellulosic biomass from switchgrass, miscanthus, and energy cane. Corn starch .......................................................... Jkt 229001 PO 00000 Frm 00062 Fmt 4700 D–Code 6 6 6 6 6 4 Trans-Esterification using natural gas or biomass for process energy. One of the following: Trans-Esterification Hydrotreating Includes only processes that co-process renewable biomass and petroleum. 4 Hydrotreating ....................................................... Fermentation ........................................................ Any ....................................................................... 5 5 3 Any ....................................................................... 7 Catalytic Pyrolysis and Upgrading, Gasification and Upgrading, Thermo-Catalytic Hydrodeoxygenation and Upgrading, Direct Biological Conversion, Biological Conversion 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. Gasification and upgrading .................................. 3 Fermentation; dry mill using natural gas, biomass, or biogas for process energy. 6 Sfmt 4700 E:\FR\FM\05MRR1.SGM 05MRR1 5 3 Federal Register / Vol. 78, No. 43 / Tuesday, March 5, 2013 / Rules and Regulations 14217 TABLE 1 TO § 80.1426—APPLICABLE D CODES FOR EACH FUEL PATHWAY FOR USE IN GENERATING RINS—Continued Fuel type Feedstock Production process requirements The non-cellulosic portions of separated food waste. Any ....................................................................... 5 Q ...... Ethanol, renewable diesel, jet fuel, heating oil, and naphtha. Biogas ................... Any ....................................................................... 5 R ....... Ethanol .................. Landfills, sewage waste treatment plants, manure digesters. Grain Sorghum .................................................... 6 S ....... Ethanol .................. Grain Sorghum .................................................... Dry mill process using biogas from landfills, waste treatment plants, and/or waste digesters, and/or natural gas, for process energy. Dry mill process, using only biogas from landfills, waste treatment plants, and/or waste digesters for process energy and for on-site production of all electricity used at the site other than up to 0.15 kWh of electricity from the grid per gallon of ethanol produced, calculated on a per batch basis. P ....... * * * * * BILLING CODE 6560–50–P DEPARTMENT OF TRANSPORTATION Federal Railroad Administration 49 CFR Part 219 [Docket No. FRA–2010–0155] RIN 2130–AC24 Control of Alcohol and Drug Use: Addition of Post-Accident Toxicological Testing for NonControlled Substances Federal Railroad Administration (FRA), Department of Transportation (DOT). ACTION: Final rule. emcdonald on DSK67QTVN1PROD with RULES AGENCY: SUMMARY: In 1985, FRA implemented a post-accident toxicological testing (postaccident testing) program to test railroad employees who had been involved in serious train accidents for alcohol and certain controlled substances (marijuana, cocaine, phencyclidine (PCP), and selected opiates, amphetamines, barbiturates, and benzodiazepines). This final rule adds certain non-controlled substances with potentially impairing side effects to its standard post-accident testing panel. The non-controlled substances include tramadol and sedating antihistamines. This final rule makes clear that FRA intends to keep the post-accident test results for these non-controlled substances confidential while it continues to obtain and analyze data on the extent to which prescription and over-the-counter (OTC) drug use by railroad employees potentially affects rail safety. VerDate Mar<15>2010 13:43 Mar 04, 2013 This rule is effective on May 6, 2013. Petitions for reconsideration must be received on or before May 6, 2013. Petitions for reconsideration will be posted in the docket for this proceeding. Comments on any submitted petition for reconsideration must be received on or before June 18, 2013. ADDRESSES: Petitions for reconsideration or comments on such petitions: Any petitions and any comments to petitions related to Docket No. FRA–2010–0155, may be submitted by any of the following methods: • Online: Comments should be filed at the Federal eRulemaking Portal, https://www.regulations.gov. Follow the online instructions for submitting comments. • Fax: 202–493–2251. • Mail: Docket Management Facility, U.S. DOT, 1200 New Jersey Avenue SE., W12–140, Washington, DC 20590. • Hand Delivery: Room W12–140 on the Ground level of the West Building, 1200 New Jersey Avenue SE., Washington, DC between 9 a.m. and 5 p.m. Monday through Friday, except federal holidays. Instructions: All submissions must include the agency name and docket number or Regulatory Identification Number (RIN) for this rulemaking. All petitions and comments received will be posted without change to https:// www.regulations.gov; this includes any personal information. Please see the Privacy Act heading in the ‘‘Supplementary Information’’ section of this document for Privacy Act information related to any submitted petitions or materials. Docket: For access to the docket to read background documents or comments received, go to https:// www.regulations.gov at any time or to Room W12–140 on the Ground level of the West Building, 1200 New Jersey DATES: [FR Doc. 2013–04929 Filed 3–4–13; 8:45 am] Jkt 229001 PO 00000 Frm 00063 Fmt 4700 Sfmt 4700 D–Code 5 Avenue SE, Washington, DC between 9 a.m. and 5 p.m. Monday through Friday, except Federal holidays. FOR FURTHER INFORMATION CONTACT: Patricia V. Sun, Trial Attorney, Office of Chief Counsel, Mail Stop 10, FRA, 1200 New Jersey Avenue SE. Washington, DC 20590 (telephone 202–493–6060), patricia.sun@dot.gov. SUPPLEMENTARY INFORMATION: The NPRM In 1985, to further its accident investigation program, FRA began conducting alcohol and drug tests on railroad employees who had been involved in serious train accidents that met its specified criteria for postaccident testing (see 49 CFR 219.201). Since the program’s inception, FRA has routinely conducted post-accident tests for alcohol and for certain drugs classified by the Drug Enforcement Administration (DEA) as controlled substances because of their potential for abuse or addiction. See the Controlled Substances Act (CSA), Title II of the Comprehensive Drug Abuse Prevention Substances Act of 1970 (CSA, 21 U.S.C. 801 et seq.). As noted in the NPRM, FRA has historically conducted post-accident tests for alcohol and marijuana, cocaine, phencyclidine (PCP), and certain opiates, amphetamines, barbiturates, and benzodiazepines. The purpose of these tests is to determine if alcohol misuse or drug abuse played a role in the occurrence or severity of an accident. On May 17, 2012, FRA proposed to add routine post-accident tests for certain non-controlled substances with potentially impairing side effects (77 FR 29307). As discussed in the NPRM, studies have shown a significant increase in the daily use of prescription drugs, OTC drugs, vitamins, and herbal E:\FR\FM\05MRR1.SGM 05MRR1

Agencies

ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 78, Number 43 (Tuesday, March 5, 2013)]
[Rules and Regulations]
[Pages 14190-14217]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-04929]

=======================================================================
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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2011-0542; FRL-9686-3]
RIN 2060-AR07

Regulation of Fuels and Fuel Additives: Identification of
Additional Qualifying Renewable Fuel Pathways Under the Renewable Fuel
Standard Program

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: EPA is issuing a final rule identifying additional fuel
pathways that EPA has determined meet the biomass-based diesel,
advanced biofuel or cellulosic biofuel lifecycle greenhouse gas (GHG)
reduction requirements specified in Clean Air Act section 211(o), the
Renewable Fuel Standard (RFS) Program, as amended by the Energy
Independence and Security Act of 2007 (EISA). This final rule describes
EPA's evaluation of biofuels produced from camelina (Camelina sativa)
oil and energy cane; it also includes an evaluation of renewable
gasoline and renewable gasoline blendstocks, and clarifies our
definition of renewable diesel. The inclusion of these pathways creates
additional opportunity and flexibility for regulated parties to comply
with the advanced and cellulosic requirements of EISA and provides the
certainty necessary for investments to bring these biofuels into
commercial production from these new feedstocks.
We are not finalizing at this time determinations on biofuels
produced from giant reed (Arundo donax) or napier grass (Pennisetum
purpureum) or biodiesel produced from esterification. We continue to
consider the issues concerning these proposals, and will make a final
decision on them at a later time.

DATES: This rule is effective on May 6, 2013.

FOR FURTHER INFORMATION CONTACT: Vincent Camobreco, Office of
Transportation and Air Quality (MC6401A), Environmental Protection
Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone
number: (202) 564-9043; fax number: (202) 564-1686; email address:
camobreco.vincent@epa.gov.

SUPPLEMENTARY INFORMATION:

Does this action apply to me?

Entities potentially affected by this action are those involved
with the production, distribution, and sale of transportation fuels,
including gasoline and diesel fuel or renewable fuels such as ethanol
and biodiesel. Regulated categories and entities affected by this
action include:

----------------------------------------------------------------------------------------------------------------
NAICS \1\ Examples of potentially regulated
Category Codes SIC \2\ Codes entities
----------------------------------------------------------------------------------------------------------------
Industry................................... 324110 2911 Petroleum Refineries.
Industry................................... 325193 2869 Ethyl alcohol manufacturing.
Industry................................... 325199 2869 Other basic organic chemical
manufacturing.
Industry................................... 424690 5169 Chemical and allied products
merchant wholesalers.
Industry................................... 424710 5171 Petroleum bulk stations and
terminals.
Industry................................... 424720 5172 Petroleum and petroleum products
merchant wholesalers.
Industry................................... 454319 5989 Other fuel dealers.
----------------------------------------------------------------------------------------------------------------
\1\ North American Industry Classification System (NAICS).
\2\ Standard Industrial Classification (SIC) system code.

This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists the types of entities that EPA is now aware
could be potentially regulated by this action. Other types of entities
not listed in the table could also be regulated. To determine whether
your entity is regulated by this action, you should carefully examine
the applicability criteria of Part 80, subparts D, E and F of title 40
of the Code of Federal Regulations. If you have any question regarding
applicability of this action to a particular entity, consult the person
in the preceding FOR FURTHER INFORMATION CONTACT section above.

Outline of This Preamble

I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Major Provisions of the Regulatory Action In
Question
II. Identification of Additional Qualifying Renewable Fuel Pathways
Under the Renewable Fuel Standard (RFS) Program
A. Analysis of Lifecycle Greenhouse Gas Emissions for Biodiesel,
Renewable Diesel, Jet Fuel, Heating Oil, Naphtha, and Liquefied
Petroleum Gas (LPG) Produced From Camelina Oil
B. Lifecycle Greenhouse Gas Emissions Analysis for Ethanol,
Diesel, Jet Fuel, Heating Oil, and Naphtha Produced From Energy Cane
C. Lifecycle Greenhouse Gas Emissions Analysis for Certain
Renewable Gasoline and Renewable Gasoline Blendstocks Pathways
D. Esterification Production Process Inclusion for Specified
Feedstocks Producing Biodiesel
III. Additional Changes to Listing of Available Pathways in Table 1
of 80.1426
IV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132 (Federalism)
F. Executive Order 13175 (Consultation and Coordination With
Indian Tribal Governments)
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act
V. Statutory Provisions and Legal Authority

I. Executive Summary

A. Purpose of This Regulatory Action

In this rulemaking, EPA is taking final action to identify
additional fuel

[[Page 14191]]

pathways that we have determined meet the greenhouse gas (GHG)
reduction requirements under the Renewable Fuel Standard (RFS) program.
This final rule describes EPA's evaluation of biofuels produced from
camelina (Camelina sativa) oil, which qualify as biomass-based diesel
or advanced biofuel, as well as biofuels from energy cane which qualify
as cellulosic biofuel. This final rule also qualifies renewable
gasoline and renewable gasoline blendstock made from certain qualifying
feedstocks as cellulosic biofuel. Finally, this rule clarifies the
definition of renewable diesel to explicitly include jet fuel.
EPA is taking this action as a result of changes to the RFS program
in Clean Air Act (``CAA'') Section 211(o) required by the Energy
Independence and Security Act of 2007 (``EISA''). This rulemaking
modifies the RFS regulations published at 40 CFR Sec. 80.1400 et seq.
The RFS program regulations specify the types of renewable fuels
eligible to participate in the RFS program and the procedures by which
renewable fuel producers and importers may generate Renewable
Identification Numbers (``RINs'') for the qualifying renewable fuels
they produce through approved fuel pathways. See 75 FR 14670 (March 26,
2010); 75 FR 26026 (May 10, 2010); 75 FR 37733 (June 30, 2010); 75 FR
59622 (September 28, 2010); 75 FR 76790 (December 9, 2010); 75 FR 79964
(December 21, 2010); 77 FR 1320 (January 9, 2012); and 77 FR 74592
(December 17, 2012).
By qualifying these new fuel pathways, this rule provides
opportunities to increase the volume of advanced, low-GHG renewable
fuels--such as cellulosic biofuels--under the RFS program. EPA's
comprehensive analyses show significant lifecycle GHG emission
reductions from these fuel types, as compared to the baseline gasoline
or diesel fuel that they replace.

B. Summary of the Major Provisions of the Regulatory Action In Question

This final rule describes EPA's evaluation of:
Camelina (Camelina sativa) oil (new feedstock)
Biodiesel, and renewable diesel, (including jet fuel, and
heating oil)--qualifying to generate biomass-based diesel and advanced
biofuel RINs
Naphtha and liquefied petroleum gas (LPG)--qualifying to
generate advanced biofuel RINs
Energy cane cellulosic biomass (new feedstock)
Ethanol, renewable diesel (including renewable jet fuel
and heating oil), and renewable gasoline blendstock--qualifying to
generate cellulosic biofuel RINs
Renewable gasoline and renewable gasoline blendstock (new fuel
types)
Produced from crop residue, slash, pre-commercial
thinnings, tree residue, annual cover crops, and cellulosic components
of separated yard waste, separated food waste, and separated municipal
solid waste (MSW)
Using the following processes--all utilizing natural gas,
biogas, and/or biomass as the only process energy sources--qualifying
to generate cellulosic biofuel RINs:
[cir] Thermochemical pyrolysis
[cir] Thermochemical gasification
[cir] Biochemical direct fermentation
[cir] Biochemical fermentation with catalytic upgrading
[cir] Any other process that uses biogas and/or biomass as the only
process energy sources
This final rule adds these pathways to Table 1 to Sec. 80.1426.
This final rule allows producers or importers of fuel produced under
these pathways to generate RINs in accordance with the RFS regulations,
providing that the fuel meets other definitional criteria for renewable
fuel. The inclusion of these pathways creates additional opportunity
and flexibility for regulated parties to comply with the requirements
of EISA. Substantial investment has been made to commercialize these
new feedstocks, and the cellulosic biofuel industry in the United
States continues to make significant advances in its progress towards
large scale commercial production. Approval of these new feedstocks
will help further the Congressional intent to expand the volumes of
cellulosic and advanced biofuels.
We are also finalizing two changes to Table 1 to 80.1426 that were
proposed on July 1, 2011(76 FR 38844). The first change adds ID letters
to pathways to facilitate references to specific pathways. The second
change adds ``rapeseed'' to the existing pathway for renewable fuel
made from canola oil.

II. Identification of Additional Qualifying Renewable Fuel Pathways
Under the Renewable Fuel Standard (RFS) Program

This rule was originally published in the Federal Register at 77 FR
462, January 5, 2012 as a direct final rule, with a parallel
publication of a proposed rule. A limited number of relevant adverse
comments were received, and EPA published a withdrawal notice of the
direct final rule on March 5, 2012 (77 FR 13009). A second comment
period was not issued, since the simultaneous publication of the
proposed rule provided an adequate notice and comment process. EPA is
finalizing several of the proposed actions in this final rule, but
continues to consider determinations on biofuels produced from giant
reed (Arundo donax) or napier grass (Pennisetum purpureum) or biodiesel
produced from esterification. EPA will make a final decision on theses
elements of the proposal at a later time.
In this action, EPA is issuing a final rule to identify in the RFS
regulations additional renewable fuel production pathways that we have
determined meet the greenhouse gas (GHG) reduction requirements of the
RFS program. There are three critical components of a renewable fuel
pathway: (1) Fuel type, (2) feedstock, and (3) production process. Each
specific combination of the three components, or fuel pathway, is
assigned a D code which is used to designate the type of biofuel and
its compliance category under the RFS program. This final rule
describes EPA's lifecycle GHG evaluation of camelina oil and energy
cane.
Determining whether a fuel pathway satisfies the CAA's lifecycle
GHG reduction thresholds for renewable fuels requires a comprehensive
evaluation of the lifecycle GHG emissions of the renewable fuel as
compared to the lifecycle GHG emissions of the baseline gasoline or
diesel fuel that it replaces. As mandated by CAA section 211(o), the
GHG emissions assessments must evaluate the aggregate quantity of GHG
emissions (including direct emissions and significant indirect
emissions such as significant emissions from land use changes) related
to the full fuel lifecycle, including all stages of fuel and feedstock
production, distribution, and use by the ultimate consumer.
In examining the full lifecycle GHG impacts of renewable fuels for
the RFS program, EPA considers the following:
Feedstock production--based on agricultural sector models
that include direct and indirect impacts of feedstock production.
Fuel production--including process energy requirements,
impacts of any raw materials used in the process, and benefits from co-
products produced.
Fuel and feedstock distribution--including impacts of
transporting feedstock from production to use, and transport of the
final fuel to the consumer.
Use of the fuel--including combustion emissions from use
of the fuel in a vehicle.
Many of the pathways evaluated in this rulemaking rely on a
comparison to the lifecycle GHG analysis work that was done as part of
the Renewable Fuel

[[Page 14192]]

Standard Program Final Rule, published March 26, 2010 (75 FR 14670)
(March 2010 RFS). The evaluations here rely on comparisons to the
existing analyses presented in the March 2010 final rule. EPA plans to
periodically review and revise the methodology and assumptions
associated with calculating the GHG emissions from all renewable fuel
pathways.

A. Analysis of Lifecycle Greenhouse Gas Emissions for Biodiesel,
Renewable Diesel, Jet Fuel, Heating Oil, Naphtha, and Liquefied
Petroleum Gas (LPG) Produced From Camelina Oil

The following sections describe EPA's evaluation of camelina
(Camelina sativa) as a biofuel feedstock under the RFS program. As
discussed previously, this analysis relies on a comparison to the
lifecycle GHG analysis work that was done as part of the Renewable Fuel
Standard Program (RFS) Final Rule, published March 26, 2010 for soybean
oil biofuels.
1. Feedstock Production
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.\1\
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.^{2 3}
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.\4\
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\1\ Putnam, D.H., J.T. Budin, L.A. Field, and W.M. Breene. 1993.
Camelina: A promising low-input oilseed. p. 314-322. In: J. Janick
and J.E. Simon (eds.), New crops. Wiley, New York.
\2\ Moser, B.R., Vaughn, S.F. 2010. Evaluation of Alkyl Esters
from Camelina Sativa Oil as Biodiesel and as Blend Components in
Ultra Low Sulfur Diesel Fuel. Bioresource Technology. 101:646-653.
\3\ McVay, K.A., and P.F. Lamb. 2008. Camelina production in
Montana. MSU Ext. MT200701AG (revised). https://msuextension.org/publications/AgandNaturalResources/MT200701AG.pdf.
\4\ Putnam et al., 1993.
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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.\5\ 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.\6\ The FDA has not approved camelina for food uses,
although it has approved the inclusion of certain quantities of
camelina meal in commercial feed.\7\
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\5\ Lafferty, Ryan M., Charlie Rife and Gus Foster. 2009. Spring
camelina production guide for the Central High Plains. Blue Sun
Biodiesel special publication. Blue Sun Agriculture Research &
Development, Golden, CO. https://www.gobluesun.com/upload/Spring%20Cam-elina%20Production%20Guide%202009.pdf.
\6\ Telephone conversation with Scott Johnson, Sustainable Oils,
January 11, 2011.
\7\ See https://agr.mt.gov/camelina/FDAletter11-09.pdf.
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In response to the proposed rule, EPA received comments
highlighting the concern that by approving certain new feedstock types
under the RFS program, EPA would be encouraging their introduction or
expanded planting without considering their potential impact as
invasive species.\8\ The degree of concern expressed by the commenters
depended somewhat on the feedstock. As pointed out by the commenters,
camelina and energy cane are not ``native species,'' defined as ``a
species that, other than as a result of an introduction, historically
occurred or currently occurs in that ecosystem.'' The commenters
asserted that there is a ``potential risk posed by the non-native
species camelina and energy cane.'' In contrast, comments stated that
giant reed (Arundo donax) or napier grass (Pennisetum purpureum) have
been identified as invasive species in certain parts of the country.
These commenters asserted that the Arundo donax and napier grass pose a
``clear risk of invasion.'' Commenters stated that EPA should not
approve the proposed feedstocks until EPA has conducted an invasive
species analysis, as required under Executive Order (EO) 13112.\9\
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\8\ Comment submitted by Jonathan Lewis, Senior Counsel, Climate
Policy, Clean Air Task Force et al., dated February 6, 2012.
Document ID EPA-HQ-OAR-2011-0542-0118.
\9\ https://www.gpo.gov/fdsys/pkg/FR-1999-02-08/pdf/99-3184.pdf.
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The information before us does not raise significant concerns about
the threat of invasiveness and related GHG emissions for camelina. For
example, camelina is not listed on the Federal Noxious Weed List,\10\
nor is it listed on any state invasive species or noxious weed list. We
believe that the production of camelina is unlikely to spread beyond
the intended borders in which it is grown, which is consistent with the
assumption in EPA's lifecycle analysis that significant expenditures of
energy or other sources of GHGs will not be required to remediate the
spread of this feedstock from the specific locations where it is grown
as a renewable fuel feedstock for the RFS program. Therefore, we are
finalizing the camelina pathway in this rule based on our lifecycle
analysis discussed below.\11\
Camelina is currently being grown on approximately 50,000 acres of
land in the U.S., primarily in Montana, eastern Washington, and the
Dakotas.\12\ 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.\13\
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\10\ However, this list is not exhaustive and is generally
limited to species that are not currently in the U.S. or are
incipient to the U.S. See http:[sol][sol]plants.usda.gov/java/
noxious?rptType=Federal&statefips=&sort=sc. Accessed on March 28,
2012.
\11\ EPA continues to evaluate Arundo donax and napier grass as
feedstock for a renewable fuel pathway, and will make a final
decision on these pathways at a later time.
\12\ McCormick, Margaret. ``Oral Comments of Targeted Growth,
Incorporated'' Submitted to the EPA on June 9, 2009.
\13\ See https:[sol][sol]www.camelinacompany.com/Marketing/
PressRelease.aspx?Id=25.
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In response to the proposed rule, two commenters were supportive of
the use of renewable feedstocks such as camelina oil to produce
biofuels for aviation. One commenter noted that aviation is unique in
its complete dependency upon liquid fuel--today and into the
foreseeable future. Another commenter noted that development of
additional feedstocks and production pathways should increase supply
and ultimately move us closer to the day when renewable jet fuels are
price-competitive with legacy fossil fuels and help cut our dependence
on foreign oil. EPA also received comment regarding a concern that EPA
did not adequately establish that camelina would only be grown on
fallow land and therefore would not have a land use impact and that EPA
overestimated the likely yields in growing camelina and therefore
underestimated the land requirements.
In terms of the comment on camelina not being grown on fallow land,
for the purposes of analyzing the lifecycle GHG emissions of camelina,
EPA has considered the likely production pattern for camelina grown for
biofuel production. Given the information currently available, camelina
is

[[Page 14193]]

expected to be primarily planted in the U.S. as a rotation crop on
acres that would otherwise remain fallow.\14\ Because camelina has not
yet been established as a commercial crop with significant monetary
value, farmers are unlikely to dedicate acres for camelina production
that could otherwise be used to produce other cash crops. Since
camelina would therefore not be expected to displace another crop but
rather maximize the value of the land through planting camelina in
rotation, EPA does not believe new acres would need to be brought into
agricultural use to increase camelina production. In addition, camelina
currently has only limited high-value niche markets for uses other than
renewable fuels. Unlike commercial crops that are tracked by USDA,
camelina does not have a well-established, internationally traded
market that would be significantly affected by an increase in the use
of camelina to produce biofuels. For these reasons, which are described
in more detail below, EPA has determined that production of camelina-
based biofuels is not expected to result in significant GHG emissions
related to direct land use change since it is expected to be grown on
fallow land. Furthermore, due to the limited non-biofuel uses for
camelina, production of camelina-based biofuels is not expected to have
a significant impact on other agricultural crop production or commodity
markets (either camelina or other crop markets) and consequently would
not result in significant GHG emissions related to indirect land use
change. To the extent camelina-based biofuel production decreases the
demand for alternative biofuels, some with higher GHG emissions, this
biofuel could have some beneficial GHG impact. However, it is uncertain
which mix of biofuel sources the market will demand so this potential
GHG impact cannot be quantified.
---------------------------------------------------------------------------

\14\ Fallow land here refers to cropland that is periodically
not cultivated.
---------------------------------------------------------------------------

Commenters stated that EPA failed to justify why camelina would be
grown on fallow land and thus result in no land use change. In the
proposed rule, EPA provided a detailed description of the economics
indicating why producers are most likely to grow camelina on land that
would otherwise remain fallow. This analysis formed the basis for why
it was reasonable and logical for camelina to be grown on acres that
would otherwise remain fallow. Comments also indicated that EPA's
economic basis for assuming camelina would most likely be grown on
fallow land was inadequate, especially if production of camelina was
scaled up. However, the comment did not indicate any specific point of
error in our economically based analysis. As we described in the
proposed rule and discuss below, camelina is currently not a
commercially raised crop in the United States, therefore the returns on
camelina are expected to be low compared to wheat and other crops with
established, commercially traded markets.\15\ Therefore, EPA expects
that initial production of camelina for biofuel production will be on
land with the lowest opportunity cost. Based on this logic, EPA
believes camelina will be grown as a rotation crop, as discussed below,
on dryland wheat acres replacing a period that the land would otherwise
be left fallow.
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\15\ See Shonnard, D. R., Williams, L., & Kalnes, T. N. 2010.
Camelina-Derived Jet Fuel and Diesel: Sustainable Advanced
Biodiesel. Environmental Progress & Sustainable Energy, 382-392.
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In the semi-arid regions of the Northern Great Plains, dryland
wheat farmers currently leave acres fallow once every three to four
years to allow additional moisture and nutrients to accumulate (see
Figure 1). Recent research indicates that introducing cool season
oilseed crops such as camelina can provide benefits by reducing soil
erosion, increasing soil organic matter, and disrupting pest cycles.
Although long-term data on the effects of replacing wheat/fallow
growing patterns with wheat/oilseed rotations is limited, there is some
data that growing oilseeds in drier semi-arid regions year after year
can lead to reduced wheat yields.\16\ However, the diversification and
intensification of wheat-fallow cropping systems can improve the long
term economic productivity of wheat acres by increasing soil nitrogen
and soil organic carbon pools.\17\ In addition, selective breeding is
expected to reduce the potential negative impacts on wheat yields.\18\
Additional research in this area is needed and if significant negative
impacts on crop rotations are determined from camelina grown on fallow
acres EPA would take that into account in future analysis.
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\16\ Personal communication with Andrew Lenssen, Department of
Agronomy, Iowa State University, April 17, 2012. See also https://www.ars.usda.gov/is/pr/2010/100413.htm.
\17\ See Sainju, U.M., T. Caesar-Tonthat, A.W. Lenssen, R.G.
Evans, and R. Kohlberg. 2007. Long-term tillage and cropping
sequence effects on dryland residue and soil carbon fractions. Soil
Science Society of America Journal 71: 1730-1739.
\18\ See Shonnard et al., 2010; Lafferty et al., 2009.

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[[Page 14194]]

[GRAPHIC] [TIFF OMITTED] TR05MR13.014

As pointed out by commenters, in the future camelina production
could expand beyond what is currently assumed in this analysis.
However, camelina would most likely not be able to compete with other
uses of land until

[[Page 14195]]

it becomes a commercial crop with a well-established market value. EPA
once again reiterates that we will continue to monitor the growing
patterns associated with camelina to determine whether actual
production is consistent with the assumptions used in this analysis.
Monitoring will be done by tracking the amount of RIN generating
camelina fuel produced through the EPA Moderated Transaction System
(EMTS). We can compare the amount of RIN generating fuel against
expected volumes from fallow acres in conjunction with USDA. Consistent
with EPA's approach to all RFS feedstock pathway analyses, we will
periodically reevaluate whether our assessment of GHG impacts will need
to be updated in the future based on the potential for significant
changes in our analyses.
a. Land Availability
USDA estimates that there are approximately 60 million acres of
wheat in the U.S.\19\ USDA and wheat state cooperative extension
reports through 2008 indicate that 83% of US 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.\20\
Therefore, our analysis uses the estimate that only 9 million wheat/
fallow acres are available for camelina production.
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\19\ 2009 USDA Baseline. See https://www.ers.usda.gov/publications/oce091/.
\20\ Johnson, S. and McCormick, M., Camelina: an Annual Cover
Crop Under 40 CFR Part 80 Subpart M, Memorandum, dated November 5,
2010.
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One commenter stated that EPA assumed more than 8 million acres
would be used to produce camelina, even though a recent paper stated
that only 5 million acres would have the potential to grow camelina in
a sustainable manner in a way that would not impact the food supply.
This commenter misinterpreted EPA's assumptions. EPA's 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. In other
words, EPA assumed only 3 million acres would be planted with camelina
in any given year. This number is less than the 5 million acres the
Shonnard et. al. paper states would be available annually for camelina
planting.
b. Projected Volumes
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.\21\
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.\22\ 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,\23\ 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.\24\ 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.\25\
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\21\ Wheeler, P. and Guillen-Portal F. 2007. Camelina Production
in Montana: A survey study sponsored by Targeted Growth, Inc. and
Barkley Ag. Enterprises, LLP.
\22\ See Hunter, J and G. Roth. 2010. Camelina Production and
Potential in Pennsylvania, Penn State University Agronomy Facts 72.
See https://pubs.cas.psu.edu/freepubs/pdfs/uc212.pdf.
\23\ Ehrensing, D.T. and S.O. Guy. 2008. Oilseed Crops--
Camelina. Oregon State Univ. Ext. Serv. EM8953-E. See https://extension.oregonstate.edu/catalog/pdf/em/em8953-e.pdf; McVay & Lamb,
2008.
\24\ See Shonnard et al., 2010.
\25\ This assumes no significant adverse climate impacts on
world agricultural yields over the analytical timeframe.
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We also received comments that we overestimated long term camelina
yields. The commentors stated that reaching yields of 3000 pounds per
acre may be attainable, but previous trials do not suggest that yields
could reach this level in ten years. As a point of clarification, we
did not assume that yields would need to be 3000 pounds per acre for
biodiesel produced from camelina oil to qualify as an advanced biofuel.
In the analysis presented below, EPA assumed yields of camelina would
be 1650 pounds per acre. Since the use of camelina as a biofuel
feedstock in the U.S. is in its infancy, it is reasonable to consider
how yields will change over time. Furthermore, jet fuel contracts and
the BCAP programs play a very important part in determining the amount
of camelina planted, and therefore interest in increasing yields. As
the commenter noted, this yield assumption is within the range of
potential yields of 330-2400 pounds per acre found in the current
literature.
c. Indirect Impacts
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.\26\ 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.\27\ See Table 1. For comparison purposes, the USDA projections
for wheat returns are between $133-$159 per acre between 2010 and
2020.\28\ Over time, advancements in seed technology, improvements in
planting and harvesting techniques, and higher input usage could
significantly increase future camelina yields and returns.
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\26\ See Lafferty et al, 2009; Shonnard et al, 2010; Sustainable
Oils Memo dated November 5, 2010.
\27\ Wheeler & Guillen-Portal, 2007.
\28\ See https://www.ers.usda.gov/media/273343/oce121_2_.pdf.

[[Page 14196]]

Table 1--Camelina Costs and Returns
----------------------------------------------------------------------------------------------------------------
2010 Camelina 2022 Camelina 2030 Camelina
Inputs Rates \29\ \30\ \31\
----------------------------------------------------------------------------------------------------------------
Herbicides:
Glysophate (Fall)................. 16 oz. ( $0.39/oz)...... $7.00 $7.00 $7.00
Glysophate (Spring)............... 16 oz. ( $0.39/oz)...... $7.00 $7.00 $7.00
Post.............................. 12 oz ( $0.67/oz)....... $8.00 $8.00 $8.00
Seed:
Camelina seed..................... $1.44/lb................ $5.76 $7.20 $7.20
(4 lbs/acre) (5 lbs/acre) (5 lbs/acre)
Fertilizer:
Nitrogen Fertilizer............... $1/pd................... $25.00 $40.00 $75
(25 lb/acre) (40 lb/acre) (75 lbs/acre)
Phosphate Fertilizer.............. $1/pd................... $15.00 $15.00 $15
(15 lb/acre) (15 lb/acre) (15 lb/acre)
Sub-Total..................... ........................ $67.76 $84.20 $119.20
Logistics:
Planting Trip..................... ........................ $10.00 $10.00 $10.00
Harvest & Hauling................. ........................ $25.00 $25.00 $25.00
Total Cost...................... ........................ $102.76 $119.20 $154.20
Yields............................ lb/acre................. 800 1650 3000
Price............................. $/lb.................... $0.145 $0.120 $0.090
Total Revenue at avg prod/ ........................ $116.00 $198 $270
pricing.
Returns........................... ........................ $13.24 $78.80 $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.\32\ 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.\33\ Therefore, camelina
grown outside of a wheat fallow situation was not considered as part of
this analysis.
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\29\ See Sustainable Oils Memo dated November 5, 2010.
\30\ Based on yields technically feasible. See McVey and Lamb,
2008; Ehrenson & Guy, 2008.
\31\ Adapted from Shonnard et al, 2010.
\32\ See Sustainable Oils Memo dated November 5, 2010 for a map
of the regions of the country where camelina is likely to be grown
in wheat fallow conditions.
\33\ Wright & Marois, 2011.
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The determination in this final rule is based on our projection
that camelina is likely to be produced on what would otherwise be
fallow land. However, the rule applies to all camelina regardless of
where it is grown. EPA does not expect that significant camelina would
be grown on non-fallow land, and small quantities that may be grown
elsewhere and used for biofuel production will not significantly impact
our analysis.
Furthermore, although we expect most camelina used as a feedstock
for renewable fuel production that would qualify in the RFS program
would be grown in the U.S., today's rule would apply to qualifying
renewable fuel made from camelina grown in any country. For the same
reasons that pertain to U.S. production of camelina, we expect that
camelina grown in other countries would also be produced on land that
would otherwise be fallow and would therefore have no significant land
use change impacts. The renewable biomass provisions under the Energy
Independence and Security Act would prohibit direct land conversion
into new agricultural land for camelina production for biofuel
internationally. Additionally, any camelina production on existing
cropland internationally would not be expected to have land use impacts
beyond what was considered for international soybean production
(soybean oil is the expected major feedstock source for US biodiesel
fuel production and thus the feedstock of reference for the camelina
evaluation). Because of these factors along with the small amounts of
fuel potentially coming from other countries, we believe that
incorporating fuels produced in other countries will not impact our
threshold analysis for camelina-based biofuels.
d. Crop Inputs
For comparison purposes, Table 2 shows the inputs required for
camelina production compared to the FASOM agricultural input
assumptions for soybeans. Since yields and input assumptions vary by
region, a range of values for soybean production are shown in Table 2.
The camelina input values in Table 2 represent average values, camelina
input values will also vary by region, however, less data is available
comparing actual practices by region due to limited camelina
production. More information on camelina inputs is available in
materials provided in the docket.

[[Page 14197]]

Table 2--Inputs for Camelina and Soybean Production
----------------------------------------------------------------------------------------------------------------
Camelina Soybeans (varies by region)
---------------------------------------------------------------------------------
Emissions (per Inputs (per Emissions (per mmBtu
Inputs (per acre) mmBtu fuel) acre) fuel)
----------------------------------------------------------------------------------------------------------------
N2O........................... N/A.............. 22 kg CO2-eq..... N/A............. 9-12 kg CO2-eq.
Nitrogen Fertilizer........... 40 lbs........... 7 kg CO2-eq...... 3.5-8.2 lbs..... 1-3 kg CO2-eq.
Phosphorous Fertilizer........ 15 lbs........... 1 kg CO2-eq...... 5.4-21.4 lbs.... 0-2 kg CO2-eq.
Potassium Fertilizer.......... 10 lbs........... 0 kg CO2-eq...... 3.1-24.3 lbs.... 0-2 kg CO2-eq.
Herbicide..................... 2.75 lbs......... 3 kg CO2-eq...... 0.0-1.3 lbs..... 0-2 kg CO2-eq.
Pesticide..................... 0 lbs............ 0 kg CO2-eq...... 0.1-0.8 lbs..... 0-2 kg CO2-eq.
Diesel........................ 3.5 gal.......... 5 kg CO2-eq...... 3.8-8.9 gal..... 7-20 kg CO2-eq.
Gasoline...................... 0 gal............ 0 kg CO2-eq...... 1.6-3.0 gal..... 3-5 kg CO2-eq.
Total......................... ................. 39 kg CO2-eq..... ................ 21-47 kg CO2-eq.
----------------------------------------------------------------------------------------------------------------

Regarding crop inputs per acre, it should be noted that camelina
has a higher percentage of oil per pound of seed than soybeans.
Soybeans are approximately 18% oil, therefore crushing one pound of
soybeans yields 0.18 pounds of oil. In comparison, camelina is
approximately 36% oil, therefore crushing one pound of camelina yields
0.36 pounds of oil. The difference in oil yield is taken into account
when calculating the emissions per mmBTU included in Table 2. As shown
in Table 2, GHG emissions from feedstock production for camelina and
soybeans are relatively similar when factoring in variations in oil
yields per acre and fertilizer, herbicide, pesticide, and petroleum
use.
In summary, EPA concludes that the agricultural inputs for growing
camelina are similar to those for growing soy beans, direct land use
change impacts are expected to be negligible due to planting on land
that would be otherwise fallow, and the limited production and use of
camelina indicates no expected impacts on other crops and therefore no
indirect land use impacts.
e. Crushing and Oil Extraction
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 March
2010 RFS final rule, based on a process model developed by USDA-
ARS.\34\ The data on camelina crushing is from Shonnard et al. (2010).
---------------------------------------------------------------------------

\34\ A. Pradhan, D.S. Shrestha, A. McAloon, W. Yee, M. Haas,
J.A. Duffield, H. Shapouri, September 2009, ``Energy Life-Cycle
Assessment of Soybean Biodiesel'', United States Department of
Agriculture, Office of the Chief Economist, Office of Energy Policy
and New Uses, Agricultural Economic Report Number 845.

Table 3--Comparison of Camelina and Soybean Crushing and Oil Extraction
----------------------------------------------------------------------------------------------------------------
Item Soybeans Camelina Units
----------------------------------------------------------------------------------------------------------------
Material Inputs:
Beans or Seeds...................... 5.38 2.90 Lbs.
Energy Inputs:
Electricity......................... 374 47 Btu.
Natural Gas & Steam................. 1,912 780 Btu.
Outputs:
Refined vegetable oil............... 1.00 1.00 Lbs.
Meal................................ 4.08 1.85 Lbs.
GHG Emissions....................... 213 64 gCO2e/lb refined oil.
----------------------------------------------------------------------------------------------------------------

2. Feedstock Distribution, Fuel Distribution, and Fuel Use
For this analysis, EPA projects that the feedstock distribution
emissions will be the same for camelina and soybean oil. To the extent
that camelina contains more oil per pound of seed, as discussed above,
the energy needed to move the camelina would be lower than soybeans per
gallon of fuel produced. To the extent that camelina is grown on more
disperse fallow land than soybean and would need to be transported
further, the energy needed to move the camelina could be higher than
soybean. We believe the assumption to use the same distribution impacts
for camelina as soybean is a reasonable estimate of the GHG emissions
from camelina feedstock distribution. In addition, the final fuel
produced from camelina is also expected to be similar in composition to
the comparable fuel produced from soybeans, therefore we are assuming
GHG emissions from the distribution and use of fuels made from camelina
will be the same as emissions of fuel produced from soybeans.
3. Fuel Production
There are two main fuel production processes used to convert
camelina oil into fuel. The trans-esterification process produces
biodiesel and a glycerin co-product. The hydrotreating process can be
configured to produce renewable diesel either primarily as diesel fuel
(including heating oil) or primarily as jet fuel. Possible additional
products from hydrotreating include naphtha LPG, and propane. Both
processes and the fuels produced are described in the following
sections. Both processes use camelina oil as a feedstock and camelina
crushing is also included in the analysis.

[[Page 14198]]

a. Biodiesel
For this analysis, we assumed the same biodiesel production
facility designs and conversion efficiencies as modeled for biodiesel
produced from soybean oil and canola/rapeseed oil. Camelina oil
biodiesel is produced using the same methods as soybean oil biodiesel,
therefore plant designs are assumed to not significantly differ between
fuels made from these feedstocks. As was the case for soybean oil
biodiesel, we have not projected in our assessment of camelina oil
biodiesel any significant improvements in plant technology.
Unanticipated energy saving improvements would further improve GHG
performance of the fuel pathway.
The glycerin produced from camelina biodiesel production is
chemically equivalent to the glycerin produced from the existing
biodiesel pathways (e.g., based on soy oil) that were analyzed as part
of the March 2010 RFS final rule. Therefore the same co-product credit
would apply to glycerin from camelina biodiesel as glycerin produced in
the biodiesel pathways modeled for the March 2010 RFS final rule. The
assumption is that the GHG reductions associated with the replacement
of residual oil with glycerin on an energy equivalent basis represents
an appropriate midrange co-product credit of biodiesel produced
glycerin.
As part of our RFS2 proposal, we assumed the glycerin would have no
value and would effectively receive no co-product credits in the soy
biodiesel pathway. We received numerous comments, however, asserting
that the glycerin would have a beneficial use and should generate co-
product benefits. Therefore, the biodiesel glycerin co-product
determination made as part of the March 2010 RFS final rule took into
consideration the possible range of co-product credit results. The
actual co-product benefit will be based on what products are replaced
by the glycerin and what new uses develop for the co-product glycerin.
The total amount of glycerin produced from the biodiesel industry will
actually be used across a number of different markets with different
GHG impacts. This could include for example, replacing petroleum
glycerin, replacing fuel products (residual oil, diesel fuel, natural
gas, etc.), or being used in new products that don't have a direct
replacement, but may nevertheless have indirect effects on the extent
to which existing competing products are used. The more immediate GHG
reduction credits from glycerin co-product use could range from fairly
high reduction credits if petroleum glycerin is replaced to lower
reduction credits if it is used in new markets that have no direct
replacement product, and therefore no replaced emissions.
EPA does not have sufficient information (and received no relevant
comments as part of the March 2010 RFS rule) on which to allocate
glycerin use across the range of likely uses. Therefore, EPA believes
that the approach used in the RFS of picking a surrogate use for
modeling purposes in the mid-range of likely glycerin uses, and the GHG
emissions results tied to such use, is reasonable. The replacement of
an energy equivalent amount of residual oil is a simplifying assumption
determined by EPA to reflect the mid-range of possible glycerin uses in
terms of GHG credits. EPA believes that it is appropriately
representative of GHG reduction credit across the possible range
without necessarily biasing the results toward high or low GHG impact.
Given the fundamental difficulty of predicting possible glycerin uses
and impacts of those uses many years into the future under evolving
market conditions, EPA believes it is reasonable to use the more
simplified approach to calculating co-product GHG benefits associated
with glycerin production at this time. EPA will continue to evaluate
the co-product credit associated with glycerine production in future
rulemakings.
Given the fact that GHG emissions from camelina-based biodiesel
would be similar to the GHG emissions from soybean-based biodiesel at
all stages of the lifecycle but would not result in land use changes as
was the case for soy oil used as a feedstock, we believe biodiesel from
camelina oil will also meet the 50% GHG emissions reduction threshold
to qualify as a biomass based diesel and an advanced fuel. Therefore,
EPA is including biodiesel produced from camelina oil under the same
pathways for which biodiesel made from soybean oil qualifies under the
March 2010 RFS final rule.
b. Renewable Diesel (Including Jet Fuel and Heating Oil), Naphtha, and
LPG
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.\35\ While any propane
produced as part of the hydrotreating process will most likely be
combusted within the facility for process energy, the other co-products
that can be produced (i.e., renewable diesel, naphtha, LPG) are higher
value products that could be used as transportation fuels or, in the
case of naphtha, a blendstock for production of transportation fuel.
The hydrotreating process maximized for producing a diesel fuel
replacement as the primary fuel product requires more overall material
and energy inputs than transesterification to produce biodiesel, but it
also results in a greater amount of other valuable co-products as
listed above. The hydrotreating process can also be maximized for jet
fuel production which requires even more process energy than the
process optimized for producing a diesel fuel replacement, and produces
a greater amount of co-products per barrel of feedstock, especially
naphtha.
---------------------------------------------------------------------------

\35\ Kalnes, T., N., McCall, M., M., Shonnard, D., R., 2010.
Renewable Diesel and Jet-Fuel Production from Fats and Oils.
Thermochemical Conversion of Biomass to Liquid Fuels and Chemicals,
Chapter 18, p. 475.
---------------------------------------------------------------------------

Producers of renewable diesel from camelina have expressed interest
in generating RINs under the RFS program for the slate of products
resulting from the hydrotreating process. Our lifecycle analysis
accounts for the various uses of the co-products. There are two main
approaches to accounting for the co-products produced, the allocation
approach, and the displacement approach. In the allocation approach all
the emissions from the hydrotreating process are allocated across all
the different co-products. There are a number of ways to do this but
since the main use of the co-products would be to generate RINs as a
fuel product we allocate based on the energy content of the co-products
produced. In this case, emissions from the process would be allocated
equally to all the Btus produced. Therefore, on a per Btu basis all co-
products would have the same emissions. The displacement approach would
attribute all of the emissions of the hydrotreating process to one main
product and then account for the emission reductions from the other co-
products displacing alternative product production. For example, if the
hydrotreating process is configured to maximize diesel fuel replacement
production, all of the emissions from the process would be attributed
to diesel fuel, but we would then assume the other co-products were
displacing

[[Page 14199]]

alternative products, for example, naphtha would displace gasoline, LPG
would displace natural gas, etc. This assumes the other alternative
products are not produced or used, so we would subtract the emissions
of gasoline production and use, natural gas production and use, etc.
This would show up as a GHG emission credit associated with the
production of diesel fuel replacement.
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.\36\ On the other hand, the upstream
lifecycle GHG emissions associated with producing and transporting the
plant oil feedstocks will be distributed over a larger group of RIN-
generating products. Assuming each product (except propane) produced
via the camelina oil hydrotreating process will generate RINs results
in higher lifecycle GHG emissions for diesel fuel replacement as
compared to the case where the co-products are not used to generate
RINs. This general principle is also true when the hydrotreating
process is maximized for jet fuel production. As a result, the worst
GHG performance (i.e., greatest lifecycle GHG emissions) for diesel
replacement fuel and jet fuel produced from camelina oil via
hydrotreating will occur when all of the co-products are RIN-generating
(we assume propane will be used for process energy). Thus, if these
fuels meet the 50% GHG reduction threshold for biomass based diesel or
advanced biofuel when co-products are RIN-generating, they will also do
so in the case when RINs are not generated for co-products.
---------------------------------------------------------------------------

\36\ For a similar discussion see page 46 of Stratton, R.W.,
Wong, H.M., Hileman, J.I. 2010. Lifecycle Greenhouse Gas Emissions
from Alternative Jet Fuels. PARTNER Project 28 report. Version 1.1.
PARTNER-COE-2010-001. June 2010, https://web.mit.edu/aeroastro/partner/reports/proj28/partner-proj28-2010-001.pdf.
---------------------------------------------------------------------------

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,\37\ Stratton et al., 2010, Huo et al., 2008 \38\). 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.\39\ This
data is summarized in Table 4.
---------------------------------------------------------------------------

\37\ Pearlson, M., N. 2011. A Techno-Economic and Environmental
Assessment of Hydroprocessed Renewable Distillate Fuels.
\38\ Huo, H., Wang., M., Bloyd, C., Putsche, V., 2008. Life-
Cycle Assessment of Energy and Greenhouse Gas Effects of Soybean-
Derived Biodiesel and Renewable Fuels. Argonne National Laboratory.
Energy Systems Division. ANL/ESD/08-2. March 12, 2008.
\39\ We have also considered data submitted by companies
involved in the hydrotreating industry which is claimed as
confidential business information (CBI). The conclusions using the
CBI data are consistent with the analysis presented here.
\40\ Based on Pearlson (2011), Table 3.1 and Table 3.2.

Table 4--Hydrotreating Processes To Convert Camelina Oil Into Diesel Replacement Fuel and Jet Fuel\40\
----------------------------------------------------------------------------------------------------------------
Maximized for Maximized for
diesel fuel jet fuel Units (per gallon of fuel
production production produced)
----------------------------------------------------------------------------------------------------------------
Inputs:
Refined camelina oil..................... 9.56 12.84 Lbs.
Hydrogen................................. 0.04 0.08 Lbs.
Electricity.............................. 652 865 Btu.
Natural Gas.............................. 23,247 38,519 Btu.
Outputs:
Diesel Fuel.............................. 123,136 55,845 Btu.
Jet fuel................................. 23,197 118,669 Btu.
Naphtha.................................. 3,306 17,042 Btu.
LPG...................................... 3,084 15,528 Btu.
Propane.................................. 7,454 9,881 Btu.
----------------------------------------------------------------------------------------------------------------

Table 5 compares lifecycle GHG emissions from oil extraction and
fuel production for soybean oil biodiesel and for camelina-based diesel
and jet fuel. The lifecycle GHG estimates for camelina oil diesel and
jet fuel are based on the input/output data summarized in Table 3 (for
oil extraction) and Table 4 (for fuel production). We assume that the
propane co-product does not generate RINs; instead, it is used for
process energy displacing natural gas. We also assume that the naphtha
is used as blendstock for production of transportation fuel to generate
RINs. In this case we assume that RINs are generated for the use of LPG
in a way that meets the EISA definition of transportation fuel, for
example it could be used in a nonroad vehicle. The lifecycle GHG
results in Table 5 represent the worst case scenario (i.e., highest GHG
emissions) because all of the eligible co-products are used to generate
RINs. This is because, as discussed above, lifecycle GHG emissions per
Btu of diesel or jet fuel would be lower if the naphtha or LPG is not
used to generate RINs and is instead used for process energy displacing
fossil fuel such as natural gas. Supporting information for the values
in Table 5, including key assumptions and data, is provided through the
docket.\41\ The key assumptions and data discussed in the docket
include the emissions factors for natural gas, hydrogen and grid
average electricity, and the energy allocation and displacement credits
given to co-products. These data and assumptions are based on the
approach taken in the March 2010 RFS rule, as explained further below.
---------------------------------------------------------------------------

\41\ See for example the spreadsheet with lifecycle GHG
emissions calculations titled ``Final Camelina Calculations for
Docket'' with document number EPA-HQ-OAR-2011-0542-0046.

[[Page 14200]]

Table 5--Fuel Production Lifecycle GHG Emissions
[kgCO2e/mmBtu) \42\
--------------------------------------------------------------------------------------------------------------------------------------------------------
RIN-Generating Oil
Feedstock Production process products Other co-products extraction Processing Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Soybean Oil........................ Trans-Esterification.. Biodiesel............. Glycerin.............. 14 (1) 13
Camelina Oil....................... Trans-Esterification.. Biodiesel............. Glycerin.............. 4 (1) 3
Camelina Oil....................... Hydrotreating Diesel................ Propane............... 4 8 12
Maximized for Diesel. Jet Fuel..............
Naphtha...............
LPG.
Camelina Oil....................... Hydrotreating Diesel Fuel........... Propane............... 4 11 14
Maximized for Jet Jet Fuel..............
Fuel. Naphtha...............
LPG.
--------------------------------------------------------------------------------------------------------------------------------------------------------

---------------------------------------------------------------------------

\42\ Lifecycle GHG emissions are normalized per mmBtu of RIN-
generating fuel produced. Totals may not be the sum of the rows due
to rounding error. Parentheses indicate negative numbers. Process
emissions for biodiesel production are negative because they include
the glycerin offset credit.
---------------------------------------------------------------------------

As discussed above, 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 kgCO2e/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.
Given that GHG emissions from camelina oil would be similar to the
GHG emissions from soybean oil at all stages of the lifecycle but would
not result in land use change emissions (soy oil feedstock did have a
significant land use change impact but still met a 50% GHG reduction
threshold), and considering differences in process emissions between
soybean biodiesel and camelina-based renewable diesel, we conclude that
renewable diesel from camelina oil will also meet the 50% GHG emissions
reduction threshold to qualify as biomass based diesel and advanced
fuel. Although some of the potential configurations result in fuel
production GHG emissions that are higher than fuel production GHG
emissions for soybean oil biodiesel, land use change emissions account
for approximately 80% of the soybean oil to biodiesel lifecycle GHGs.
Since camelina is assumed not to have land use change emissions, our
analysis shows that camelina renewable diesel will qualify for advanced
renewable fuel and biomass-based diesel RINs even for the cases with
the highest lifecycle GHGs (e.g., when all of the co-products are used
to generate RINs.) Because the lifecycle GHG emissions for RIN-
generating co-products are very similar, we can also conclude renewable
gasoline blendstock and LPG produced from camelina oil will also meet
the 50% GHG emissions reduction threshold. If the facility does not
actually generate RINs for one or more of these co-products, we
estimate that the lifecycle GHG emissions related to the RIN-generating
products would be lower, thus renewable diesel (which includes diesel
fuel, jet fuel, and heating oil) from camelina would still meet the 50%
emission reduction threshold.
4. Summary
Current information suggests that camelina will be produced on land
that would otherwise remain fallow. Therefore, increased production of
camelina-based renewable fuel is not expected to result in significant
land use change emissions; however, the agency will continue to monitor
volumes through EMTS to verify this assumption. For the purposes of
this analysis, EPA is projecting there will be no land use emissions
associated with camelina production for use as a renewable fuel
feedstock.
However, while production of camelina on acres that would otherwise
remain fallow is expected to be the primary means by which the majority
of all camelina is commercially harvested in the short- to medium-
term, in the long term camelina may expand to other growing methods and
lands if demand increases substantially beyond what EPA is currently
predicting. While the impacts are uncertain, there are some indications
demand could increase significantly. For example, camelina is included
under USDA's Biomass Crop Assistance Program (BCAP) and there is
growing support for the use of camelina oil in producing drop-in
alternative aviation fuels. EPA plans to monitor, through EMTS and in
collaboration with USDA, the expansion of camelina production to verify
whether camelina is primarily grown on existing acres once camelina is
produced at larger-scale volumes. Similarly, we will consider market
impacts if alternative uses for camelina expand significantly beyond
what was described in the above analysis. Just as EPA plans to
periodically review and revise the methodology and assumptions
associated with calculating the GHG emissions from all renewable fuel
feedstocks, EPA expects to review and revise as necessary the analysis
of camelina in the future.
Taking into account the assumption of no land use change emissions
when camelina is used to produce renewable fuel, and considering that
other sources of GHG emissions related to camelina biodiesel or
renewable diesel production have comparable GHG emissions to biodiesel
from soybean oil, we have determined that camelina-based biodiesel and
renewable diesel should be treated in the same manner as soy-based
biodiesel and renewable diesel in qualifying as biomass-based diesel
and advanced biofuel for purposes of RIN generation, since the GHG
emission performance of the

[[Page 14201]]

camelina-based fuels will be at least as good and in some respects
better than that modeled for fuels made from soybean oil. EPA found as
part of the Renewable Fuel Standard final rulemaking that soybean
biodiesel resulted in a 57% reduction in GHG emissions compared to the
baseline petroleum diesel fuel. Furthermore, approximately 80% of the
lifecycle impacts from soybean biodiesel were from land use change
emissions which are assumed to be not significant for the camelina
pathway considered. Thus, EPA is including camelina oil as a potential
feedstock under the same biodiesel and renewable diesel (which includes
diesel fuel, jet fuel, and heating oil) pathways for which soybean oil
currently qualifies. We are also including a pathway for naphtha and
LPG produced from camelina oil through hydrotreating. This is based on
the fact that our analysis shows that even when all of the co-products
are used to generate RINs the lifecycle GHG emissions for RIN-
generating co-products including diesel replacement fuel, jet fuel,
naphtha and LPG produced from camelina oil will all meet the 50% GHG
emissions reduction threshold.
We are also clarifying that two existing pathways for RIN
generation in the RFS regulations that list ``renewable diesel'' as a
fuel product produced through a hydrotreating process include jet fuel.
This applies to two pathways in Table 1 to Sec. 80.1426 of the RFS
regulations which both list renewable diesel made from soy bean oil,
oil from annual covercrops, algal oil, biogenic waste oils/fats/
greases, or non-food grade corn oil using hydrotreating as a process.
If parties produce jet fuel from the hydrotreating process and co-
process renewable biomass and petroleum they can generate advanced
biofuel RINs (D code 5) for the jet fuel produced. If they do not co-
process renewable biomass and petroleum they can generate biomass-based
diesel RINs (D code 4) for the jet fuel produced.
Sec. 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 Sec. 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 RFS 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.
The original lifecycle analysis for the renewable diesel from
hydrotreating pathways listed in Table 1 to Sec. 80.1426 was not based
on producing jet fuel but rather other transportation diesel fuel
products, namely a diesel fuel replacement. As discussed above, the
hydrotreating process can produce a mix of products including jet fuel,
diesel, naphtha, LPG and propane. Also, as discussed, there are
differences in the process configured for maximum jet fuel production
vs. the process maximized for diesel fuel production and the lifecycle
results vary depending on what approach is used to consider co-products
(i.e., the allocation or displacement approach).
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 Sec. 80.1426.\43\ As was discussed previously, if the
displacement approach is used when jet fuel is the primary product
produced it results in lower emissions than 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.
---------------------------------------------------------------------------

\43\ The exception is renewable gasoline blendstock produced
from waste categories, but these would pass the lifecycle thresholds
regardless of the allocation approach used given their low feedstock
GHG impacts.
---------------------------------------------------------------------------

Thus, we are interpreting the references to ``renewable diesel'' in
Table 1 to include jet fuel, consistent with our regulatory definition
of ``non-ester renewable diesel,'' since doing so clarifies the
existing regulations while ensuring that Table 1 to Sec. 80.1426
appropriately identifies fuel pathways that meet the GHG reduction
thresholds associated with each pathway.
We note that although the definition of renewable diesel includes
jet fuel and heating oil, we have also listed in Table 1 of section
80.1426 of the RFS regulations jet fuel and heating oil as specific co-
products in addition to listing renewable diesel to assure clarity.
This clarification also pertains to all the feedstocks already included
in Table 1 for renewable diesel.

B. Lifecycle Greenhouse Gas Emissions Analysis for Ethanol, Diesel, Jet
Fuel, Heating Oil, and Naphtha Produced From Energy Cane

For this rulemaking, EPA considered the lifecycle GHG impacts of a
new type of high-yielding perennial grass similar in cellulosic
composition to switchgrass and comparable in status as an emerging
energy crop. The grass considered in this rulemaking is energy cane,
which is defined as a complex hybrid in the Saccharum genus that has
been bred to maximize cellulosic rather than sugar content.
As discussed above, in response to the proposed rule, EPA received
comments highlighting the concern that by approving certain new
feedstock types under the RFS program, EPA would be encouraging their
introduction or expanded planting without considering their potential
impact as invasive species.\44\
---------------------------------------------------------------------------

\44\ Comment submitted by Jonathan Lewis, Senior Counsel,
Climate Policy, Clean Air Task Force et al., dated February 6, 2012.
Document ID EPA-HQ-OAR-2011-0542-0118.
---------------------------------------------------------------------------

As described in the previous section on camelina, the information
before us does not raise significant concerns about the threat of
invasiveness and related GHG emissions for energy cane. Energy cane is
generally a hybrid of Saccharum officinarum and Saccharum spontaneum,
though other species such as Saccharum barberi and Saccharum sinense
have been used in the development of new cultivars.\45\ Given the fact
that S. spontaneum is listed on the Federal Noxious Weed List, this
rulemaking does not allow for the inclusion of S. spontaneum in the
definition of energy cane. However, hybrids derived from S. spontaneum
that have been developed and publicly released by USDA are included in
this definition of the energy cane feedstock. USDA's Agricultural
Research Service has developed strains of energy cane that strive to
maximize fiber content and minimize invasive traits. Therefore, we
believe that the production of cultivars of energy cane that were
developed by USDA are unlikely to spread beyond the intended borders in
which it is grown, which is consistent with the assumption in EPA's
lifecycle analysis that significant expenditures of energy or other
sources of GHGs will not be required to remediate the spread of this
feedstock from the specific locations where it is grown as a renewable
fuel

[[Page 14202]]

feedstock for the RFS program. Therefore, we are finalizing the energy
cane pathway in this rule based on our lifecycle analysis discussed
below.
---------------------------------------------------------------------------

\45\ See https://www.crops.org/publications/jpr/abstracts/2/3/211?access=0&view=pdf and https://www.cpact.embrapa.br/eventos/2010/simposio_agroenergia/palestras/10_terca/Tarde/USA/4%20%20%208-10-2010%20Cold%20Tolerance.pdf.
---------------------------------------------------------------------------

In the proposed and final RFS 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 RFS 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 from 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 Sec. 80.1426.
We did not include other perennial grasses such as energy cane 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 the energy cane pathway, EPA has evaluated
energy cane and is now including it as a feedstock in Table 1 to Sec.
80.1426 as approved pathways for cellulosic biofuel pathways.
As described in detail in the following sections of this preamble,
because of the similarity of energy cane to switchgrass and miscanthus,
and because crop production input emissions (e.g., diesel and pesticide
emissions) are generally a small fraction of the overall lifecycle GHG
emissions (representing approximately 1% of total emissions for
switchgrass), EPA believes that new agricultural sector modeling is not
needed to analyze energy cane. We have instead relied upon the
switchgrass analysis to assess the relative GHG impacts of biofuel
produced from energy cane. As with the switchgrass analysis, we have
attributed all land use impacts and resource inputs from use of these
feedstocks to the portion of the fuel produced that is derived from the
cellulosic components of the feedstocks. Based on this analysis and
currently available information, we conclude that biofuel (ethanol,
cellulosic diesel, jet fuel, heating oil and naphtha) produced from the
cellulosic biomass of energy cane has similar lifecycle GHG impacts to
switchgrass biofuel and meets the 60% GHG reduction threshold required
for cellulosic biofuel.
1. Feedstock Production and Distribution
For the purposes of this rulemaking, energy cane refers to
varieties of perennial grasses in the Saccharum genus which are
intentionally bred for high cellulosic biomass productivity but have
characteristically low sugar content making them less suitable as a
primary source of sugar as compared to other varieties of grasses
commonly known as ``sugarcane'' in the Saccharum genus. Energy cane
varieties developed to date have low tolerance for cold temperatures
but grow well in warm, humid climates. Energy cane originated from
efforts to improve disease resistance and hardiness of commercial
sugarcane by crossbreeding commercial and wild sugarcane strains.
Certain higher fiber, lower sugar varieties that resulted were not
suitable for commercial sugar production, and are now being developed
as a high-biomass energy crop. There is currently no commercial
production of energy cane. Current plantings are mainly limited to
research field trials and small demonstrations for bioenergy purposes.
However, based in part on discussions with industry, EPA anticipates
continued development of energy cane particularly in the south-central
and southeastern United States due to its high yields in these regions.
a. Crop Yields
For the purposes of analyzing the GHG emissions from energy cane
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.^{46 47} 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. In general, energy cane 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
pathway.
---------------------------------------------------------------------------

\46\ See Bischoff, K.P., Gravois, K.A., Reagan, T.E., Hoy, J.W.,
Kimbeng, C.A., LaBorde, C.M., Hawkins, G.L. Plant Regis. 2008, 2,
211-217.
\47\ See Hale, A.L. Sugar Bulletin, 2010, 88, 28-29.
---------------------------------------------------------------------------

Furthermore, EPA's analysis of switchgrass for the RFS 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 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.\48\ The ethanol yield for all of the grasses is
approximately the same so the higher crop yields for energy cane result
directly in greater ethanol production compared to switchgrass per acre
of production.
---------------------------------------------------------------------------

\48\ These yields assume no significant adverse climate impacts
on world agricultural yields over the analytical timeframe.
---------------------------------------------------------------------------

Based on these yield assumptions, in areas with suitable growing
conditions, energy cane would require approximately 26% to 47% of the
land area required by switchgrass to produce the same amount of biomass
due to higher yields. Even without yield growth assumptions, the
currently higher crop yield rates means the land use required for
energy cane would be lower than for switchgrass. Therefore less crop
area would be converted and displaced resulting in smaller land-use
change GHG impacts than that assumed for switchgrass to produce the
same amount of fuel. Furthermore, we believe energy cane will have a
similar impact on international markets as assumed for switchgrass.
Like switchgrass, energy cane is not expected to be traded
internationally and its impacts on other crops are expected to be
limited.
b. Land Use
In EPA's March 2010 RFS analysis, switchgrass plantings displaced
primarily soybeans and wheat, and to a lesser extent hay, rice,
sorghum, and cotton. Energy cane, with production focused in the
southern United States, is

[[Page 14203]]

likely to be grown on land once used for pasture, rice, commercial sod,
cotton or alfalfa, which would likely have less of an international
indirect impact than switchgrass because some of those commodities are
not as widely traded as soybeans or wheat. Given that energy cane will
likely displace the least productive land first, EPA concludes that the
land use GHG impact for energy cane per gallon should be no greater and
likely less than estimated for switchgrass.
Considering the total land potentially impacted by all the new
feedstocks included in this rulemaking would not impact these
conclusions (including the camelina discussed in the previous section
and energy cane considered here). As discussed previously, the camelina
is expected to be grown on fallow land in the Northwest, while energy
cane is expected to be grown mainly in the south on existing cropland
or pastureland. In the switchgrass ethanol scenario done for the
Renewable Fuel Standard final rulemaking, total cropland acres
increases by 4.2 million acres, including an increase of 12.5 million
acres of switchgrass, a decrease of 4.3 million acres of soybeans, a
1.4 million acre decrease of wheat acres, a decrease of 1 million acres
of hay, as well as decreases in a variety of other crops. Given the
higher yields of the energy cane considered here compared to
switchgrass, there would be ample land available for production without
having any adverse impacts beyond what was considered for switchgrass
production. This analysis took into account the economic conditions
such as input costs and commodity prices when evaluating the GHG and
land use change impacts of switchgrass.
One commenter stated that by assuming no land use change for energy
cane and other feedstocks, the Agency may have underestimated the
increase in GHG emissions that could result from breaking new land.
According to the commenter, EPA assumed that these feedstocks will be
grown on the least productive land without citing any specific models
or studies.
The commenter appears to have misinterpreted EPA's analysis. EPA
did not assume these crops would be grown on fallow acres, nor did EPA
assume that switchgrass would only be produced on the least productive
lands. EPA assumed these crops would be grown on acres similar to
switchgrass, and therefore applied the land use change impacts of
switchgrass analyzed in the final RFS rule. In the final RFS, EPA
provided detailed information on the types of crops (e.g., wheat) that
would be displaced by dedicated switchgrass. This analysis took into
account the economic conditions such as input costs and commodity
prices when evaluating the GHG and land use change impacts of
switchgrass.\49\
---------------------------------------------------------------------------

\49\ See Final Regulatory Impact Analysis Chapter 2, February
2010.
---------------------------------------------------------------------------

c. Crop Inputs and Feedstock Transport
EPA also assessed the GHG impacts associated with planting,
harvesting, and transporting energy cane in comparison to switchgrass.
Table 6 shows the assumed 2022 commercial-scale production inputs for
switchgrass (used in the RFS rulemaking analysis), average energy cane
production inputs (USDA projections and industry data) and the
associated GHG emissions.
Available data gathered by EPA suggest that energy cane requires on
average less nitrogen, phosphorous, potassium, and pesticide than
switchgrass per dry ton of biomass, but more herbicide, lime, diesel,
and electricity per unit of biomass.
This assessment assumes production of energy cane uses electricity
for irrigation given that growers will likely irrigate when possible to
improve yields. Irrigation rates will vary depending on the timing and
amount of rainfall, but for the purpose of estimating GHG impacts of
electricity use for irrigation, we assumed a rate similar to what we
assumed for other irrigated crops in the Southwest, South Central, and
Southeast as shown in Table 6.
Applying the GHG emission factors used in the March 2010 RFS final
rule, energy cane production results in slightly higher GHG emissions
relative to switchgrass production (an increase of approximately 4 kg
CO2eq/mmbtu).

[[Page 14204]]

[GRAPHIC] [TIFF OMITTED] TR05MR13.015

GHG emissions associated with distributing energy cane are expected
to be similar to EPA's estimates for switchgrass feedstock because they
are all herbaceous agricultural crops requiring similar transport,
loading,

[[Page 14205]]

unloading, and storage regimes. Our analysis therefore assumes the same
GHG impact for feedstock distribution as we assumed for switchgrass,
although distributing energy cane could be less GHG intensive because
higher yields could translate to shorter overall hauling distances to
storage or biofuel production facilities per gallon or Btu of final
fuel produced.
2. Fuel Production, Distribution, and Use
Energy cane is suitable for the same conversion processes as other
cellulosic feedstocks, such as switchgrass and corn stover. Currently
available information on energy cane composition shows that
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 RFS
rule (biochemical ethanol, thermochemical ethanol, and Fischer-Tropsch
(F-T) diesel \50\) to energy cane. We assumed the GHG emissions
associated with producing biofuels from energy cane 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
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, based on
analysis of the increased transport emissions associated with sugarcane
ethanol distribution to the U.S. considered for the 2010 final rule,
this would at most add 1-2% to the overall lifecycle GHG impacts of the
energy grasses.
---------------------------------------------------------------------------

\50\ The F-T diesel process modeled applies to cellulosic
diesel, jet fuel, heating oil, and naphtha.
---------------------------------------------------------------------------

3. Summary
Based on our comparison to switchgrass, EPA believes that
cellulosic biofuel produced from the cellulose, hemicellulose and
lignin portions of energy cane has similar or better lifecycle GHG
impacts than biofuel produced from the cellulosic biomass from
switchgrass. Our analysis suggests that energy cane has GHG impacts
associated with growing and harvesting the feedstock that are similar
to switchgrass. Emissions from growing and harvesting energy cane are
approximately 4 kg CO2eq/mmBtu higher than switchgrass.
These are small changes in the overall lifecycle, representing at most
a 6% change in the energy grass lifecycle impacts in comparison to the
petroleum fuel baseline. Furthermore, energy cane is expected to have
similar or lower GHG emissions than switchgrass associated with other
components of the biofuel lifecycle.
Under a hypothetical worst case, if the calculated increases in
growing and harvesting the new feedstocks are incorporated into the
lifecycle GHG emissions calculated for switchgrass, and other lifecycle
components are projected as having similar GHG impacts to switchgrass
(including land use change associated with switchgrass production), the
overall lifecycle GHG reductions for biofuel produced from energy cane
still meet the 60% reduction threshold for cellulosic biofuel. We
believe these are conservative estimates, as use of energy cane as a
feedstock is expected to have smaller land-use GHG impacts than
switchgrass, due to higher yields. The docket for this rule provides
additional detail on the analysis of energy cane as a biofuel
feedstock.
Although this analysis assumes energy cane biofuels produced for
sale and use in the United States will most likely come from
domestically produced feedstock, we also intend for the approved
pathways to cover energy cane from other countries. We do not expect
incidental amounts of biofuels from feedstocks produced in other
nations to impact our assessment that the average GHG emissions
reductions will meet the threshold for qualifying as a cellulosic
biofuel pathway. Moreover, those countries most likely to be exporting
energy cane or biofuels produced from energy cane are likely to be
major producers which typically use similar cultivars and farming
techniques. Therefore, GHG emissions from producing biofuels with
energy cane grown in other countries should be similar to the GHG
emissions we estimated for U.S. energy cane, though they could be
slightly higher or lower. For example, the renewable biomass provisions
under the Energy Independence and Security Act as outlined in the March
2010 RFS final rule regulations, would preclude use of a crop as a
feedstock for renewable fuel if it was gown on land that was a direct
conversion of previously unfarmed land in other countries into cropland
for energy grass-based renewable fuel production. Furthermore, any
energy grass production on existing cropland internationally would not
be expected to have land use impacts beyond what was considered for
switchgrass production. Even if there were unexpected larger
differences, EPA believes the small amounts of feedstock or fuel
potentially coming from other countries will not impact our threshold
analysis.
Based on our assessment of switchgrass in the March 2010 RFS final
rule and this comparison of GHG emissions from switchgrass and energy
cane, we do not expect variations to be large enough to bring the
overall GHG impact of fuel made from energy cane to come close to the
60% threshold for cellulosic biofuel. Therefore, EPA is including
cellulosic biofuel produced from the cellulose, hemicelluloses and
lignin portions of energy cane under the same pathways for which
cellulosic biomass from switchgrass qualifies under the RFS final rule.

C. Lifecycle Greenhouse Gas Emissions Analysis for Certain Renewable
Gasoline and Renewable Gasoline Blendstocks Pathways

In this rule, EPA is also adding pathways to Table 1 to Sec.
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 RFS
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 March
2010 RFS 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.

[[Page 14206]]

1. Feedstock Production and Distribution
EPA has evaluated renewable gasoline and renewable gasoline
blendstock pathways that utilize cellulosic feedstocks currently
included in Table 1 to Sec. 80.1426 of the regulations. The following
feedstocks were evaluated:
Cellulosic biomass from crop residue, slash, pre-
commercial thinnings and tree residue, annual cover crops;
Cellulosic components of separated yard waste;
Cellulosic components of separated food waste; and
Cellulosic components of separated MSW
The FASOM and FAPRI models were used to analyze the GHG impacts of
the feedstock production portion of a fuel's lifecycle. In the March
2010 RFS rulemaking, FASOM and FAPRI modeling was performed to analyze
the emissions impact of using corn stover as a biofuel feedstock and
this modeling was extended to some additional feedstock sources
considered similar to corn stover. This approach was used for crop
residues, slash, pre-commercial thinnings, tree residue and cellulosic
components of separated yard, food, and MSW. These feedstocks are all
excess materials and thus, like corn stover, were determined to have
little or no land use change GHG impacts. Their GHG emission impacts
are mainly associated with collection, transport, and processing into
biofuel. See the RFS rulemaking preamble for further discussion. We
used the results of the corn stover modeling in this analysis to
estimate the upper bound of agricultural sector impacts from the
production of the various cellulosic feedstocks noted above.
The agriculture sector modeling results for corn stover represents
all of the direct and significant indirect emissions in the agriculture
sector (feedstock production emissions) for a certain quantity of corn
stover produced. For the March 2010 RFS rulemaking, this was roughly 62
million dry tons of corn stover to produce 5.7 billion gallons of
ethanol assuming biochemical fermentation to ethanol processing. We
have calculated GHG emissions from feedstock production for that amount
of corn stover. The GHG emissions were then divided by the total
heating value of the fuel to get feedstock production emissions per
mmBtu of fuel. In addition to the biochemical ethanol process, a
similar analysis was completed for thermochemical ethanol and F-T
diesel pathways as part of the RFS rulemaking.
In this rulemaking we are analyzing renewable gasoline and
renewable gasoline blendstock produced from corn stover (and, by
extension, other waste feedstocks). The number of gallons of fuel
produced from a ton of corn stover (modeled process yields) is specific
to the process used to produce renewable fuel. EPA has adjusted the
results of the earlier corn stover modeling to reflect the different
process yields and heating value of renewable gasoline or renewable
gasoline blendstock product. The results of this calculation are shown
below in Table 7.
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 gasoline blendstock (``catalytic
pyrolysis and upgrading''), (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 March 2010 RFS 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.\51\ 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 March 2010 RFS
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 RFS
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 RFS 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.\52\ 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.\53\
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\51\ Kinchin, Christopher. Catalytic Fast Pyrolysis with
Upgrading to Gasoline and Diesel Blendstocks. National Renewable
Energy Laboratory (NREL). 2011.
\52\ Aden, Andy. Feedstock Considerations and Impacts on
Biorefining. National Renewable Energy Laboratory (NREL). December
2009. The report indicates that woody biomass feedstocks generally
have higher yields than crop residues or herbaceous grasses (~6%
higher yields). However the same lower yield was assumed for all as
a conservatively low estimate.
\53\ Results for feedstock distribution are aggregated along
with fuel distribution and are reported in a later section, see
conclusion section.
---------------------------------------------------------------------------

Feedstock production emissions are shown in Table 7 below for corn
stover. Corn stover feedstock production emissions are mainly a result
of corn stover removal increasing the profitability of corn production
(resulting in shifts in cropland and thus slight emission impacts) and
also the need for additional fertilizer inputs to replace the nutrients
lost when corn stover is removed. However, corn stover removal also has
an emissions benefit as it encourages the use of no-till farming which
results in the lowering of domestic land use change emissions. This
change to no-till farming results in a negative value for domestic land
use change emission impacts (see also Table 13 below). For other waste
feedstocks (e.g., tree residues and cellulosic components of separate
yard, food, and MSW), the feedstock production emissions are even lower
than the values shown for corn stover since the

[[Page 14207]]

use of such feedstocks does not require land use changes or additional
agricultural inputs. Therefore, we conclude that if the use of corn
stover as a feedstock in the production of renewable gasoline and
renewable gasoline blendstock yields lifecycle GHG emissions results
for the resulting fuel that qualify it as cellulosic biofuel (i.e., it
has at least a 60% lifecycle GHG reduction as compared to conventional
fuel), then the use of other waste feedstocks with little or no land
use change emissions will also result in renewable gasoline or
renewable gasoline blendstock that qualifies as cellulosic biofuel.
One commenter stated that the Agency assumed that using the corn
stover for biofuels production would result in additional no-till
farming without any evidence that the stover would actually be removed
from no-tilled acres. This commenter feels that with recent increased
profitability from corn production, farmers may actually increase
tillage to reap high corn prices. This commenter urged the EPA to
consider changes to soil carbon from the removal of corn stover as they
may have an impact on the GHG score of this new biofuel pathway. This
commenter further urged the Agency to not simply assume that additional
no-till practices will be adopted with residue extraction.
The analysis the EPA conducted to evaluate the GHG impacts
associated with corn stover removal as part of the March 2010 RFS final
rule did not assume that the corn stover had to be removed from no-till
corn production. The models used to evaluate the impacts of stover
removal included the option for farmers to switch to no-till practices
and therefore have the option for more stover removal. As the demand
for stover increased in the case where stover is used for biofuel
production, the relative costs associated with no-till factored in the
impact of lost corn yield as well as higher yield for corn stover. The
model optimized the rate of returns for the farmers such that no-till
practices were applied until the increased returns for greater stover
removal on no-till acres were balanced by lost profits from lower corn
yields. Therefore, the comment that we assumed stover had to come from
no-till acres or that the economics would drive more intensive tillage
practices is not accurate, as described in more detail in the March
2010 RFS final rule.
Furthermore, there is an annual soil carbon penalty applied to
crops with residue removal in our models. Thus, as one shifts from
conventional corn to residue corn, an annual soil carbon penalty factor
is applied. If residue removal is combined with switching to
conservation tillage or no-till, then the net soil C effect would be
the sum of the till change effect and the ``crop change'' effect.
For the March 2010 RFS rulemaking, EPA conducted an in-depth
literature review of corn stover removal practices and consulted with
numerous experts in the field. In the FRM, EPA recognized that
sustainable stover removal practices vary significantly based on local
differences in soil and erosion conditions, soil type, landscape
(slope), tillage practices, crop rotation managements, and the use of
cover crops. EPA, in consultation with USDA, based its impacts on corn
stover from reduced till and no till acres based on agronomical
practices, nutrient requirements, and erosion considerations. EPA does
not believe that the commentor has provided new information that would
substantially change our analysis of the GHG emissions associated with
corn stover. However, EPA will continue to monitor actual practices and
based on new data will consider reviewing and revising the methodology
and assumptions associated with calculating the GHG emissions from all
renewable fuel feedstocks.

Table 7--Feedstock Production Emissions for Renewable Gasoline and Renewable Gasoline Blendstock Pathways Using
Corn Stover
----------------------------------------------------------------------------------------------------------------
Biochemical
Catalytic pyrolysis and fermentation and Direct biochemical
upgrading to renewable upgrading to renewable fermentation process to
Feedstock production emission gasoline and renewable gasoline and renewable renewable gasoline and
sources gasoline blendstock (g gasoline blendstock via renewable gasoline
CO2-eq./mmBtu) carboxylic acid (g CO2- blendstock (g CO2-eq./
eq./mmBtu) mmBtu)
----------------------------------------------------------------------------------------------------------------
Domestic Livestock................... 7,648 6,770 ~ 9,086
Domestic Farm Inputs and Fertilizer 1,397 1,237 ~ 1,660
N2O.................................
Domestic Rice Methane................ 366 324 ~ 434
Domestic Land Use Change............. -9,124 -8,076 ~-10,820
International Livestock.............. 0 0 0
International Farm Inputs and 0 0 0
Fertilizer N2O......................
International Rice Methane........... 0 0 0
International Land Use Change........ 0 0 0
--------------------------------------------------------------------------
Total Feedstock Production 287 254 ~ 361
Emissions:......................
Assumed yield (gal/ton of biomass)... 64.5 75 92.3
----------------------------------------------------------------------------------------------------------------

The results in Table 7 differ for the different pathways considered
because of the different amounts of corn stover used to produce the
same amount of fuel in each case. Table 7 only considers the feedstock
production impacts associated with the renewable gasoline or renewable
gasoline blendstocks pathways, other aspects of the lifecycle are
discussed in the following sections.
2. Fuel Distribution
A petroleum gasoline baseline was developed as part of the RFS
final rule which included estimates for fuel distribution emissions.
Since renewable gasoline and renewable gasoline blendstocks when
blended into gasoline are similar to petroleum gasoline, it is
reasonable to assume similar fuel distribution emissions. Therefore,
the existing fuel distribution lifecycle GHG impacts of the petroleum
gasoline baseline from the RFS final rule were applied to this
analysis.
3. Use of the Fuel
A petroleum gasoline baseline was developed as part of the RFS
final rule which estimated the tailpipe emissions from fuel combustion.
Since renewable gasoline and renewable gasoline blendstock are similar
to petroleum gasoline in energy and hydrocarbon

[[Page 14208]]

content, the non-CO2 combustion emissions calculated as part
of the RFS final rule for petroleum gasoline were applied to our
analysis of the renewable gasoline and renewable gasoline blendstock
pathways. Only non-CO2 emissions were included since carbon
fluxes from land use change are accounted for as part of the biomass
feedstock production.
4. Fuel Production
In the March 2010 RFS rulemaking, EPA analyzed several of the main
cellulosic biofuel pathways: a biochemical fermentation process to
ethanol and two thermochemical gasification processes, one producing
mixed alcohols (primarily ethanol) and the other one producing mixed
hydrocarbons (primarily diesel fuel). These pathways all exceeded the
60% lifecycle GHG threshold requirements for cellulosic biofuel using
the specified feedstocks. Refer to the preamble and regulatory impact
analysis (RIA) from the final rule for more details. From these
analyses, it was determined that ethanol and diesel fuel produced from
the specified cellulosic feedstocks and processes would be eligible for
cellulosic and advanced biofuel RINs.
The thermochemical gasification process to diesel fuel (via F-T
synthesis) also produces a smaller portion of renewable gasoline
blendstock. In the final 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 Sec. 80.1426. In this rule, we are changing the reference to F-T as
the process technology to the more correct reference as gasification
technology since F-T reactions are only part of the process technology.
Since the final March 2010 RFS 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.\54\ For the
reasons described below, we have decided to authorize the generation of
RINs with a D code of 3 for renewable gasoline and renewable gasoline
blendstock produced using specified cellulosic feedstocks for the
processes considered here.
---------------------------------------------------------------------------

\54\ See https://www.epa.gov/otaq/fuels/renewablefuels/compliancehelp/rfs2-lca-pathways.htm for list of petitions received
by EPA.
---------------------------------------------------------------------------

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 and
upgrading''), 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'') and other thermo-catalytic hydrodeoxygenation routes
with upgrading such as aqueous phase processing.^{55 56}
---------------------------------------------------------------------------

\55\ Regalbuto, John. ``An NSF perspective on next generation
hydrocarbon biorefineries,'' Computers and Chemical Engineering 34
(2010) 1393-1396. February 2010.
\56\ Serrano-Ruiz, J., Dumesic, James. ``Catalytic routes for
the conversion of biomass into liquid hydrocarbon transportation
fuels,'' Energy Environmental Science (2011) 4, 83-99.
---------------------------------------------------------------------------

Similar to how we analyzed several of the main routes for
cellulosic ethanol and cellulosic diesel for the final March 2010 RFS
rule, we have chosen to analyze the main renewable gasoline and
renewable gasoline blendstock pathways in order to estimate the
potential GHG reduction profile for renewable gasoline and renewable
gasoline blendstock across a range of other production technologies for
which we are confident will have at least as great of GHG emission
reductions as those specifically analyzed.
a. Catalytic Pyrolysis With Upgrading to Renewable Gasoline and
Renewable Gasoline Blendstock
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.\57\ Catalytic
pyrolysis involves the rapid heating of biomass to about 500[deg]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 renewable gasoline, renewable gasoline blendstock and
renewable diesel streams (cellulosic diesel from catalytic pyrolysis is
already included as an acceptable pathway in the RFS 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 biogas 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.
---------------------------------------------------------------------------

\57\ Kinchin, Christopher. Catalytic Fast Pyrolysis with
Upgrading to Gasoline and Diesel Blendstocks. National Renewable
Energy Laboratory (NREL). 2011.

Table 8--2022 Energy Use at Cellulosic Biofuel Facilities
[Btu/gal]
----------------------------------------------------------------------------------------------------------------
Purchased Sold
Technology Biomass use Natural gas use electricity electricity
----------------------------------------------------------------------------------------------------------------
Catalytic Pyrolysis to Renewable Gasoline or 136,000 51,000 0 -2,000
Renewable Gasoline Blendstock..............
----------------------------------------------------------------------------------------------------------------

[[Page 14209]]

The emissions from energy inputs were calculated by multiplying the
amount of energy by emission factors for fuel production and
combustion, based on the same method and factors used in the March 2010
RFS final rulemaking. The emission factors for the different fuel types
are from GREET and were based on assumed carbon contents of the
different process fuels. The emissions from producing electricity in
the U.S. were also taken from GREET and represent average U.S. grid
electricity production emissions.
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.\58\
See Table 9 for a summary of emissions from fuel production.
---------------------------------------------------------------------------

\58\ A steam methane reformer (SMR) is used to produce the
hydrogen necessary for hydroprocessing. In the U.S. over 95% of
hydrogen is currently produced via steam reforming (DOE, 2002 ``A
National Vision of America's Transition to a Hydrogen Economy to
2030 and Beyond''). Other alternatives are available, such as
renewable or nuclear resources used to extract hydrogen from water
or the use of biomass to produces hydrogen. These alternative
methods, however, are currently not as efficient or cost effective
as the use of fossil fuels and therefore we conservatively estimate
emissions from hydrogen production using the more commonly used SMR
technology.

Table 9--Fuel Production Emissions for Catalytic Pyrolysis and Upgrading
to Renewable Gasoline or Renewable Gasoline Blendstock Using Corn Stover
------------------------------------------------------------------------
Catalytic pyrolysis to
renewable gasoline or
Lifecycle stage renewable gasoline
blendstock (g CO2-eq./
mmBtu)
------------------------------------------------------------------------
On-Site & Upstream Emissions (Natural Gas & 31,000
Biomass*).....................................
Electricity Co-Product Credit.................. -3,000
------------------------
Total Fuel Production Emissions:........... 28,000
------------------------------------------------------------------------
* Only non-CO2 combustion emissions from biomass

b. Catalytic Upgrading of Biochemically Derived Intermediates to
Renewable Gasoline and Renewable Gasoline Blendstock
The second production process we investigated is a biochemical
fermentation process to intermediate, such as carboxylic acids with
catalytic upgrading to renewable gasoline or renewable gasoline
blendstock. This process involves the fermentation of biomass using
microorganisms that produce a variety of carboxylic acids. If the
feedstock has high lignin content, then the biomass is pretreated to
enhance digestibility. The acids are then neutralized to carboxylate
salts and further converted to ketones and alcohols for refining into
gasoline, diesel, and jet fuel.
The process requires the use of natural gas and hydrogen
inputs.\59\ No purchased electricity is required as lignin is projected
to be used to meet all facility demands as well as provide excess
electricity to the grid. EPA used the estimated energy and material
inputs along with emission factors to estimate the GHG emissions from
this process. The energy inputs and electricity credits are shown in
Table 10, below. These inputs are based on Confidential Business
Information (CBI), rounded to the nearest 1000 units, provided by
industry as part of the petition process for new fuel pathways.
---------------------------------------------------------------------------

\59\ Hydrogen emissions are modeled as natural gas and
electricity demands.

Table 10--2022 Energy Use at Cellulosic Facility
[Btu/gal]
----------------------------------------------------------------------------------------------------------------
Natural gas Purchased Sold
Technology Biomass use use electricity electricity
----------------------------------------------------------------------------------------------------------------
Biochemical Fermentation to Renewable Gasoline 49,000 59,000 0 -2,000
or Renewable Gasoline Blendstock via Carboxylic
Acid...........................................
----------------------------------------------------------------------------------------------------------------

The process also uses a small amount of buffer material as
neutralizer which was not included in the GHG lifecycle results due to
its likely negligible emissions impact. The GHG emissions estimates
from the fuel production stage are seen in Table 11.

Table 11--Fuel Production Emissions for Biochemical Fermentation to
Renewable Gasoline or Renewable Gasoline Blendstock via Carboxylic Acid
Using Corn Stover
------------------------------------------------------------------------
GHG Emissions (g CO2-
Lifecycle stage eq./mmBtu)
------------------------------------------------------------------------
On-Site & Upstream Emissions (Natural Gas & 33,000
Biomass*).....................................
Electricity Co-Product Credit.................. -3,000
Total Fuel Production Emissions:............... 30,000
------------------------------------------------------------------------
* Only non-CO2 combustion emissions from biomass

[[Page 14210]]

c. Biological Conversion to Renewable Gasoline and Renewable Gasoline
Blendstock
The third production process we investigated involves the use of
microorganisms to biologically convert 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 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 generally separate spontaneously from
the aqueous phase, thereby avoiding poisoning of microbes by the
accumulated products and facilitating separation/collection of
hydrocarbons 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.
Therefore, we can conservatively extend our final March 2010 RFS
rule biochemical fermentation to ethanol process results to a similar
(but likely slightly improved) process that instead produces
hydrocarbons. Since the final rule cellulosic ethanol GHG results were
well above the 60% GHG reduction threshold for cellulosic biofuels, if
actual emissions from other necessary changes to the direct biochemical
fermentation to hydrocarbons process represent some small increment in
GHG emissions, the pathway would still likely meet the threshold. Table
12 is our qualitative assessment of the potential emissions reductions
from a process using biochemical fermentation to cellulosic
hydrocarbons assuming similarities to the biochemical fermentation to
cellulosic ethanol route from the final rule.

Table 12--Fuel Production Emissions for March 2010 RFS Cellulosic Biochemical Ethanol Compared to Direct
Biochemical Fermentation to Renewable Gasoline or Renewable Gasoline Blendstock Using Corn Stover
----------------------------------------------------------------------------------------------------------------
Direct biochemical
fermentation to
Cellulosic biochemical renewable gasoline and
Lifecycle stage ethanol emissions (g renewable gasoline
CO2-eq./mmBtu) blendstock emissions
(g CO2-eq./mmBtu)
----------------------------------------------------------------------------------------------------------------
On-Site Emissions & Upstream (biomass)........................ 3,000 < or = 3,000
Electricity Co-Product Credit................................. -35,000 = -35,000
Total Fuel Production Emissions \60\:......................... -33,000 < or = -33,000
----------------------------------------------------------------------------------------------------------------

Table 13 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.\61\ As noted above, these analyses assume natural gas as the
process energy when needed; using biogas as process energy would result
in an even better lifecycle GHG impact.
---------------------------------------------------------------------------

\60\ Numbers do not add up due to rounding.
\61\ Memorandum to the Air and Radiation Docket EPA-HQ-OAR-2011-
0542 ``Supplemental Information for Renewable Gasoline and Renewable
Gasoline Blendstock Pathways Under the Renewable Fuel Standard
(RFS2) Program''.

Table 13--Lifecycle GHG Emissions for Renewable Gasoline and Renewable Gasoline Blendstock Pathways Using Corn
Stover, 2022
[kg CO2-eq./mmBtu]
----------------------------------------------------------------------------------------------------------------
Biochemical
Catalytic fermentation Direct
pyrolysis and to renewable biochemical
upgrade to gasoline and fermentation
Fuel type renewable renewable to renewable 2005 gasoline
gasoline and gasoline gasoline and baseline
renewable blendstock via renewable
gasoline carboxylic gasoline
blendstock acid blendstock
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change).. 9 8 ~ 11 ..............
Net International Agriculture (w/o land use .............. .............. .............. ..............
change)........................................
Domestic Land Use Change........................ -9 -8 ~ -11 ..............
International Land Use Change................... .............. .............. .............. ..............
Fuel Production................................. 28 30 < or = -33 19
Fuel and Feedstock Transport.................... 2 2 ~ 2 *
Tailpipe Emissions.............................. 2 2 ~ 1 79
---------------------------------------------------------------
Total Emissions............................. 32 34 < or = -29 98

[[Page 14211]]

% Change from Baseline.......................... -67% -65% -129% ..............
----------------------------------------------------------------------------------------------------------------
* Emissions included in fuel production stage.

d. Extension of Modeling Results to Other Production Processes
Producing Renewable Gasoline or Renewable Gasoline Blendstock
In the March 2010 RFS rulemaking, we modeled the GHG emissions
results from the biochemical fermentation process to ethanol,
thermochemical gasification processes to mixed alcohols (primarily
ethanol) and mixed hydrocarbons (primarily diesel fuel). We extended
these modeled process results to apply when the biofuel was produced
from ``any'' process. We determined that since we modeled multiple
cellulosic biofuel processes and all were shown to exceed the 60%
lifecycle GHG threshold requirements for cellulosic biofuel using the
specified feedstocks its was reasonable to extend to other processes
(e.g. additional thermo-catalytic hydrodeoxygenation routes with
upgrading similar to pyrolysis and aqueous phase processing) that might
develop as these would likely represent improvements over existing
processes as the industry works to improve the economics of cellulosic
biofuel production by, for example, reducing energy consumption and
improving process yields. Similarly, this rule assesses multiple
processes for the production of renewable gasoline and renewable
gasoline blendstocks and all were shown to exceed the 60% lifecycle GHG
threshold requirements for cellulosic biofuel using specified
feedstocks.
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. 62
63 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:
---------------------------------------------------------------------------

\62\ Regalbuto, John. ``An NSF perspective on next generation
hydrocarbon biorefineries,'' Computers and Chemical Engineering 34
(2010) 1393-1396. February 2010.
\63\ Serrano-Ruiz, J., Dumesic, James. ``Catalytic routes for
the conversion of biomass into liquid hydrocarbon transportation
fuels,'' Energy Environmental Science (2011) 4, 83-99.
---------------------------------------------------------------------------

Pyrolysis and Upgrading--in which cellulosic biomass is
decomposed with temperature to bio-oils and requires further catalytic
processing to produce a finished fuel
Gasification--in which cellulosic biomass is decomposed to
syngas with further catalytic processing of methanol to gasoline or
through Fischer-Tropsch (F-T) synthesis to gasoline

The processes under the biochemical category include:
Biological conversion to hydrocarbons--requires the
release of sugars from biomass and microorganisms to biologically
convert sugars straight into hydrocarbons instead of alcohols
Catalytic upgrading of biochemically produced
intermediates--requires the release of sugars from biomass and aqueous-
or liquid-phase processing of sugars or biochemically produced
intermediate products into hydrocarbons using solid catalysts,
As part of the modeling effort here, as well as for the March 2010
RFS final rule, we have considered the lifecycle GHG impacts of the
four possible production technologies mentioned above. The pyrolysis
and upgrading, direct biological conversion, and catalytic upgrading of
biochemically produced intermediates are considered in this rule and
the gasification route was already included in the March 2010 final
rule. In all cases, the processes that we have considered meet the 60%
lifecycle GHG reduction required for cellulosic biofuels. Furthermore,
we believe that the results from our modeling would cover all the
likely variations within these potential routes for producing renewable
gasoline and renewable gasoline blendstock which also use natural gas,
biogas or biomass \64\ for process energy and that all such production
variations would also meet the 60% lifecycle threshold.\65\
---------------------------------------------------------------------------

\64\ Our lifecycle analysis assumes that producers would use the
same type of biomass as both the feedstock and the process energy.
\65\ One commenter wanted clarification of the term ``process
energy'' as it applies to the production of renewable gasoline. The
EPA did not intend for the term, ``process energy'', to include
other energy sources, such as electricity to provide power for
ancillary processes, such as lights, small pumps, computers, and
other small support equipment.
---------------------------------------------------------------------------

The main reason for this is that we believe that our energy input
assumptions are reasonable at this time but probably in some cases are
conservatively high for commercial scale cellulosic facilities. The
cellulosic industry is in its early stages of development and many of
the estimates of process technology GHG impacts is based on pre-
commercial scale assessments and demonstration programs. Commercial
scale cellulosic facilities will continue to make efficiency
improvements over time to maximize their fuel products/co-products and
minimize wastes. For cellulosic facilities, such improvements include
increasing conversion yields and fully utilizing the biomass input for
valuable products.
An example of increasing the amount of biomass utilized is the
combustion of undigested or unconverted biomass for heat and power. The
three routes that we analyzed for the production of renewable gasoline
and renewable gasoline blendstock in today's rule assume an electricity
production credit from the economically-driven use of lignin or waste
byproducts; we also ran

[[Page 14212]]

a sensitivity case where no electricity credit was given. We found that
all of the routes analyzed would still pass the GHG threshold without
an electricity credit, providing confidence that over the range of
technology options, these process technologies will surely allow the
cellulosic biofuel produced to exceed the threshold for cellulosic
biofuel GHG performance. Without excess electricity production the
catalytic pyrolysis pathway results in a 65% lifecycle GHG reduction,
the biochemical fermentation via carboxylic acid pathway results in a
62% lifecycle GHG reduction, and the direct biochemical fermentation
pathway results in a 93% reduction in lifecycle GHG emissions compared
to the petroleum fuel baseline.
Additionally, while the final results reported in this rule include
an electricity credit, this electricity credit is based on current
technology for generating electricity; it is possible that over the
next decade as cellulosic biofuel production matures, the efficiency
with which electricity is generated at these facilities will also
improve. Such efficiency improvements will tend to improve the GHG
performance for cellulosic biofuel technologies in general including
those used to produce renewable gasoline.
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 than
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.\66\ Thus, fossil natural gas consumption could be
further minimized under certain scenarios. We believe that as
commercial scale cellulosic facilities develop, more of these
improvements will be made to maximize the use of all the biomass and
waste byproducts available to bring the facility closer to energy self-
sufficiency. These improvements could help to increase the economic
profitability for cellulosic facilities where fossil energy inputs
become costly to purchase. Therefore we can extend the modeling results
for our pyrolysis route to all variations of this production technology
which use natural gas, biogas or biomass for production energy for
producing renewable gasoline or renewable gasoline blendstock.
---------------------------------------------------------------------------

\66\ Kinchin, Christopher. Catalytic Fast Pyrolysis with
Upgrading to Gasoline and Diesel Blendstocks. National Renewable
Energy Laboratory (NREL). 2011.
---------------------------------------------------------------------------

The F-T gasification technology route considered as part of the
March 2010 RFS final rule resulted in an approximately 91% reduction in
lifecycle GHG emissions compared to the petroleum baseline. This could
be considered a conservatively high 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 H2 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 originally 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.
There is an even wider gap between the results modeled for the
direct fermentation route and the cellulosic lifecycle GHG threshold.
The variation we considered for the direct fermentation process
resulted in an approximately 129% reduction in lifecycle GHG emissions
compared to the petroleum baseline. This process did consider
production of electricity as part of the process but as mentioned even
if this was not the case the pathway would still easily fall below the
60% lifecycle threshold for cellulosic biofuels. If actual emissions
from other necessary changes to the direct biochemical fermentation to
hydrocarbons process represent some small increment in GHG emissions,
the pathway would still likely meet the threshold. Therefore, we can
extend the results to all variations of the direct biochemical route
for renewable gasoline or renewable gasoline blendstock production
which use natural gas, biogas or biomass for production energy.
The biochemical with catalytic upgrading route that we evaluated
resulted in a 65% reduction in GHG emissions compared to the petroleum
baseline. However, this can be considered a conservatively high
estimate. For instance, the biochemical fermentation to gasoline via
carboxylic acid route considered did not include the potential for
generating steam from the combustion of undigested biomass and then
using this steam for process energy. If this had been included, natural
gas consumption could potentially be decreased which would lower the
potential GHG emissions estimated from the process. Therefore, the
scenario analyzed could be considered conservative in estimating actual
natural gas usage. As was the case with the pyrolysis route considered,
we believe that as commercial scale cellulosic facilities develop,
improvements will be made to maximize the use of all the biomass and
waste byproducts available to bring the facility closer to energy self-
sufficiency. These improvements help to increase the economic
profitability for cellulosic facilities where fossil energy inputs
become costly to purchase. The processes we analyzed for this
rulemaking utilized a mix of natural gas and biomass for process
energy, with biogas replacing natural gas providing improved GHG
performance. We have not analyzed other fuel types (e.g., coal) and are
therefore not approving processes that utilized other fuel sources at
this point. Therefore, we are

[[Page 14213]]

extending our results to include all variations of the biochemical with
catalytic upgrading process utilizing natural gas, biogas or biomass
for process energy.
While actual cellulosic facilities may show some modifications to
the process scenarios we have already analyzed, our results give a good
indication of the range of emissions we could expect from processes
producing renewable gasoline and renewable gasoline blendstock from
cellulosic feedstock, all of which meet the 60% cellulosic biofuel
threshold (assuming they are utilizing natural gas, biogas or biomass
for process energy). Technology changes in the future are likely to
increase efficiency to maximize profits, while also lowering lifecycle
GHG emissions. Therefore, we have concluded that since all of the
renewable gasoline or renewable gasoline blendstock fuel processing
methods we have analyzed exceed the 60% threshold using specific
cellulosic feedstock types, we can conclude that processes producing
renewable gasoline or renewable gasoline blendstock that fit within the
categories of process analyzed here and are produced from the same
feedstock types and using natural gas, biogas or biomass for process
energy use will also meet the 60% GHG reduction threshold. In addition,
while other technologies may develop, we expect that they will only
become commercially competitive if they have better yields (more
gallons per ton of feedstock) or lower production costs due to lower
energy consumption. Both of these factors would suggest better GHG
performance. This would certainly be the case if such processes also
relied upon using biogas and/or biomass as the primary energy source.
Therefore based on our review of the existing primary cellulosic
biofuel production processes, likely GHG emission improvements for
existing or new technologies, and consideration of the positive GHG
emissions benefits associated with using biogas and/or biomass for
process energy, we are approving for cellulosic RIN generation any
process for renewable gasoline and renewable gasoline blendstock
production using specified cellulosic biomass feedstocks as long as the
process utilizes biogas and/or biomass for all process energy.
5. Summary
Three renewable gasoline and renewable gasoline blendstock pathways
were compared to baseline petroleum gasoline, using the same value for
baseline gasoline as in the March 2010 RFS final rule analysis. The
results of the analysis indicate that the renewable gasoline and
renewable gasoline blendstock pathways result in a GHG emissions
reduction of 65-129% or better compared to the gasoline fuel it would
replace using corn stover as a feedstock. The renewable gasoline and
renewable gasoline blendstock pathways which use corn stover as a
feedstock all exceed the 60% lifecycle GHG threshold requirements for
cellulosic biofuel, these pathways capture the likely current
technologies, and future technology improvements are likely to increase
efficiency and lower GHG emissions. Therefore we have determined that
all processes producing renewable gasoline or renewable gasoline
blendstock from corn stover can qualify if they fall in the following
process characterizations:
Catalytic pyrolysis and upgrading utilizing natural gas,
biogas, and/or biomass as the only process energy sources
Gasification and upgrading utilizing natural gas, biogas,
and/or biomass as the only process energy sources
Thermo-catalytic hydrodeoxygenation processes such as
aqueous phase processing with upgrading sufficiently similar to
pyrolysis and gasification
Direct fermentation utilizing natural gas, biogas, and/or
biomass as the only process energy sources
Fermentation and upgrading 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.
As was the case for extending corn stover results to other
feedstocks in the March 2010 RFS final rule, these results are also
reasonably extended to feedstocks with similar or lower GHG emissions
profiles, including the following feedstocks:
Cellulosic biomass from crop residue, slash, pre-
commercial thinnings and tree residue, annual cover crops;
Cellulosic components of separated yard waste;
Cellulosic components of separated food waste; and
Cellulosic components of separated MSW
For more information on the reasoning for extension to these other
feedstocks refer to the feedstock production and distribution section
or the March 2010 RFS rulemaking (75 FR 14670).
Based on these results, today's rule includes pathways for the
generation of cellulosic biofuel RINs for renewable gasoline or
renewable gasoline blendstock produced by catalytic pyrolysis and
upgrading, gasification and upgrading, other similar thermo-catalytic
hydrodeoxygenation routes with upgrading, direct fermentation,
fermentation and upgrading, all utilizing natural gas, biogas, and/or
biomass as the only process energy sources or any process utilizing
biogas and/or biomass as the only energy sources, and using corn stover
as a feedstock or the feedstocks noted above. In order to qualify for
RIN generation, the fuel must meet the other definitional criteria for
renewable fuel (e.g., produced from renewable biomass, and used to
reduce or replace petroleum-based transportation fuel, heating oil or
jet fuel) specified in the Clean Air Act and the RFS regulations.
A manufacturer of a renewable motor vehicle gasoline (including
parties using a renewable blendstock obtained from another party), must
satisfy EPA motor vehicle registration requirements in 40 CFR part 79
for the fuel to be used as a transportation fuel. Per 40 CFR
79.56(e)(3)(i), a renewable motor vehicle gasoline would be in the Non-
Baseline Gasoline category or the Atypical Gasoline category (depending
on its properties) since it is not derived only from conventional
petroleum, heavy oil deposits, coal, tar sands and/or oil sands (40 CFR
79.56(e)(3)(i)(5)). In either case, the Tier 1 requirements at 40 CFR
79.52 (emissions characterization) and the Tier 2 requirements at 40
CFR 79.53 (animal exposure) are conditions for registration unless the
manufacturer qualifies for a small business provision at 40 CFR
79.58(d). For a non-baseline gasoline, a manufacturer under $50 million
in annual revenue is exempt from Tier 1 and Tier 2. For an atypical
gasoline there is no exemption from Tier 1, but a manufacturer under
$10 million in annual revenue is exempt from Tier 2.
Registration for a motor vehicle gasoline at 40 CFR 79 is via EPA
Form 3520-12, Fuel Manufacturer Notification for Motor Vehicle Fuel,
available at: https://www.epa.gov/otaq/regs/fuels/ffarsfrms.htm.

D. Esterification Production Process Inclusion for Specified Feedstocks
Producing Biodiesel

The Agency is not taking final action at this time on its proposed
inclusion of the process ``esterification'' as an approved biodiesel
production process in Table 1 to Sec. 40 CFR 80.1426. See 77 FR 465.
We continue to evaluate the issue and anticipate issuing a final
determination as part of a subsequent rulemaking.

[[Page 14214]]

III. Additional Changes to Listing of Available Pathways in Table 1 of
80.1426

We are also finalizing two changes to Table 1 to 80.1426 that were
proposed on July 1, 2011(76 FR 38844). The first change adds ID letters
to pathways to facilitate references to specific pathways. The second
change adds ``rapeseed'' to the existing pathway for renewable fuel
made from canola oil.
On September 28, 2010, EPA published a ``Supplemental Determination
for Renewable Fuels Produced Under the Final RFS2 Program from Canola
Oil'' (75 FR 59622). 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 Sec. 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 Sec. 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 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.
Second, we wish to clarify that although the GHG emissions of
producing fuels from canola feedstock grown in the U.S. and Canada was
specifically modeled as the most likely source of canola (or rapeseed)
oil used for biodiesel produced for sale and use in the U.S., we also
intended that the approved pathway cover canola/rapeseed oil from other
countries, and we interpret our regulations in that manner. We expect
the vast majority of biodiesel used in the U.S. and produced from
canola/rapeseed oil will come from U.S. and Canadian crops. Incidental
amounts from crops produced in other nations will not impact our
average GHG emissions for two reasons. First, our analyses considered
world-wide impacts and thus considered canola/rapeseed crop production
in other countries. Second, other countries most likely to be exporting
canola/rapeseed or biodiesel product from canola/rapeseed are likely to
be major producers which typically use similar cultivars and farming
techniques. Therefore, GHG emissions from producing biodiesel with
canola/rapeseed grown in other countries should be very similar to the
GHG emissions we modeled for Canadian and U.S. canola, though they
could be slightly (and insignificantly) higher or lower. At any rate,
even if there were unexpected larger differences, EPA believes the
small amounts of feedstock or fuel potentially coming from other
countries will not impact our threshold analysis. Therefore, EPA
interprets the approved canola pathway as covering canola/rapeseed
regardless of country of origin.
We are also correcting an inadvertent omission to the proposal
which incorrectly did not include a pathway for producing naphtha from
switchgrass and miscanthus; this pathway was included in the original
March 2010 RFS final rule. This pathway also incorporates the
additional energy grass feedstock sources being added today, namely
energy cane.

IV. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review

Under Executive Order 12866 (58 FR 51735, October 4, 1993), this
action is a ``significant regulatory action.'' Accordingly, EPA
submitted this action to the Office of Management and Budget (OMB) for
review under Executive Orders 12866 and 13563 (76 FR 3821, January 21,
2011) and any changes made in response to OMB recommendations have been
documented in the docket for this action.

B. Paperwork Reduction Act

This action does not impose any new information collection burden.
The corrections, clarifications, and modifications to the final March
2010 RFS regulations contained in this rule are within the scope of the
information collection requirements submitted to the Office of
Management and Budget (OMB) for the final March 2010 RFS regulations.
OMB has approved the information collection requirements contained
in the existing regulations at 40 CFR part 80, subpart M under the
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and
has assigned OMB control numbers 2060- 0637 and 2060-0640. The OMB
control numbers for EPA's regulations in 40 CFR are listed in 40 CFR
part 9.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
After considering the economic impacts of this action on small
entities, I certify that this rule will not have a significant economic
impact on a substantial number of small entities. This rule will not
impose any new requirements on small entities. The relatively minor
corrections and modifications this rule makes to the final March 2010
RFS regulations do not impact small entities.

D. Unfunded Mandates Reform Act

This rule does not contain a Federal mandate that may result in
expenditures of $100 million or more for State, local, and tribal
governments, in the aggregate, or the private sector in any one year.
We have determined that this action will not result in expenditures of
$100 million or more for the above parties and thus, this rule is not
subject to the requirements of sections 202 or 205 of UMRA.
This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. It only applies to
gasoline, diesel, and renewable fuel producers, importers, distributors
and marketers and makes

[[Page 14215]]

relatively minor corrections and modifications to the RFS regulations.

E. Executive Order 13132 (Federalism)

This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. This action only applies to
gasoline, diesel, and renewable fuel producers, importers, distributors
and marketers and makes relatively minor corrections and modifications
to the RFS regulations. Thus, Executive Order 13132 does not apply to
this action.

F. Executive Order 13175 (Consultation and Coordination With Indian
Tribal Governments)

This rule does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It applies to
gasoline, diesel, and renewable fuel producers, importers, distributors
and marketers. This action makes relatively minor corrections and
modifications to the RFS regulations, and does not impose any
enforceable duties on communities of Indian tribal governments. Thus,
Executive Order 13175 does not apply to this action.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying
only to those regulatory actions that concern health or safety risks,
such that the analysis required under section 5-501 of the EO has the
potential to influence the regulation. This action is not subject to EO
13045 because it does not establish an environmental standard intended
to mitigate health or safety risks.

H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

This action is not a ``significant energy action'' as defined in
Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. This rulemaking does not change any
programmatic structural component of the RFS regulatory requirements.
This rulemaking does not add any new requirements for obligated parties
under the program or mandate the use of any of the new pathways
contained in the rule. This rulemaking only makes a determination to
qualify new fuel pathways under the RFS regulations, creating further
opportunity and flexibility for compliance with the Energy Independence
and Security Act of 2007 (EISA) mandates.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
This action does not involve technical standards. Therefore, EPA
did not consider the use of any voluntary consensus standards.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
Federal executive policy on environmental justice. Its main provision
directs Federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
EPA has determined that this rule will not have disproportionately
high and adverse human health or environmental effects on minority or
low-income populations because it does not affect the level of
protection provided to human health or the environment. These
amendments would not relax the control measures on sources regulated by
the RFS regulations and therefore would not cause emissions increases
from these sources.

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. A major rule cannot take effect until 60 days after it
is published in the Federal Register. EPA will submit a report
containing this rule and other required information to the U.S. Senate,
the U.S. House of Representatives, and the Comptroller General of the
United States prior to publication of the rule the Federal Register.
This action is not a ``major rule'' as defined by 5 U.S.C. 804(2).

V. Statutory Provisions and Legal Authority

Statutory authority for the rule finalized today can be found in
section 211 of the Clean Air Act, 42 U.S.C. 7545. Additional support
for today's rule comes from Section 301(a) of the Clean Air Act, 42
U.S.C. 7414, 7542, and 7601(a).

List of Subjects in 40 CFR Part 80

Environmental protection, Administrative practice and procedure,
Agriculture, Air pollution control, Confidential business information,
Diesel Fuel, Energy, Forest and Forest Products, Fuel additives,
Gasoline, Imports, Labeling, Motor vehicle pollution, Penalties,
Petroleum, Reporting and recordkeeping requirements.

Dated: February 22, 2013.
Bob Perciasepe,
Acting Administrator.
For the reasons set forth in the preamble, 40 CFR part 80 is
amended as follows:

PART 80--REGULATION OF FUELS AND FUEL ADDITIVES

0
1. The authority citation for part 80 continues to read as follows:

Authority: 42 U.S.C. 7414, 7521(1), 7545 and 7601(a).

0
2. Section 80.1401 is amended by adding definitions of ``Energy cane,''
``Renewable gasoline'' and ``Renewable gasoline blendstock'' in
alphabetical order to read as follows:

Sec. 80.1401 Definitions.

* * * * *
Energy cane means a complex hybrid in the Saccharum genus that has
been bred to maximize cellulosic rather than sugar content. For the
purposes of this section, energy cane excludes the species Saccharum
spontaneum, but includes hybrids derived from S.

[[Page 14216]]

spontaneum that have been developed and publicly released by USDA.
* * * * *
Renewable gasoline means renewable fuel made from renewable biomass
that is composed of only hydrocarbons and which meets the definition of
gasoline in Sec. 80.2(c).
Renewable gasoline blendstock means a blendstock made from
renewable biomass that is composed of only hydrocarbons and which meets
the definition of gasoline blendstock in Sec. 80.2(s).
* * * * *

0
3. Section 80.1426 is amended by revising Table 1 in paragraph (f)(1)
to read as follows:

Sec. 80.1426 How are RINs generated and assigned to batches of
renewable fuel by renewable fuel producers or importers?

* * * * *
(f) * * *
(1) * * *

Table 1 to Sec. 80.1426--Applicable D Codes for Each Fuel Pathway for Use in Generating RINs
----------------------------------------------------------------------------------------------------------------
Production process
Fuel type Feedstock requirements D-Code
----------------------------------------------------------------------------------------------------------------
A............. Ethanol................ Corn starch................. All of the following: Dry 6
mill process, using natural
gas, biomass, or biogas for
process energy and at least
two advanced technologies
from Table 2 to this
section.
B............. Ethanol................ Corn starch................. All of the following: Dry 6
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.
C............. Ethanol................ Corn starch................. All of the following: Dry 6
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.
D............. Ethanol................ Corn starch................. Wet mill process using 6
biomass or biogas for
process energy.
E............. Ethanol................ Starches from crop residue Fermentation using natural 6
and annual covercrops. gas, biomass, or biogas for
process energy.
F............. Biodiesel, renewable Soy bean oil; Oil from One of the following: Trans- 4
diesel, jet fuel and annual covercrops; Algal Esterification
heating oil. oil; Biogenic waste oils/ Hydrotreating Excluding
fats/greases; Non-food processes that co-process
grade corn oil Camelina renewable biomass and
sativa oil. petroleum.
G............. Biodiesel, heating oil. Canola/Rapeseed oil......... Trans-Esterification using 4
natural gas or biomass for
process energy.
H............. Biodiesel, renewable Soy bean oil; Oil from One of the following: Trans- 5
diesel, jet fuel and annual covercrops; Algal Esterification
heating oil. oil; Biogenic waste oils/ Hydrotreating Includes only
fats/greases; Non-food processes that co-process
grade corn oil Camelina renewable biomass and
sativa oil. petroleum.
I............. Naphtha, LPG........... Camelina sativa oil......... Hydrotreating............... 5
J............. Ethanol................ Sugarcane................... Fermentation................ 5
K............. Ethanol................ Cellulosic Biomass from crop Any......................... 3
residue, slash, pre-
commercial thinnings and
tree residue, annual
covercrops, switchgrass,
miscanthus, and energy
cane; cellulosic components
of separated yard waste;
cellulosic components of
separated food waste; and
cellulosic components of
separated MSW.
L............. Cellulosic diesel, jet Cellulosic Biomass from crop Any......................... 7
fuel and heating oil. residue, slash, pre-
commercial thinnings and
tree residue, annual
covercrops, switchgrass,
miscanthus, and energy
cane; cellulosic components
of separated yard waste;
cellulosic components of
separated food waste; and
cellulosic components of
separated MSW.
M............. Renewable gasoline and Cellulosic Biomass from crop Catalytic Pyrolysis and 3
renewable gasoline residue, slash, pre- Upgrading, Gasification and
blendstock. commercial thinnings, tree Upgrading, Thermo-Catalytic
residue, annual cover Hydrodeoxygenation and
crops; cellulosic Upgrading, Direct
components of separated Biological Conversion,
yard waste; cellulosic Biological Conversion and
components of separated Upgrading, all utilizing
food waste; and cellulosic natural gas, biogas, and/or
components of separated MSW. biomass as the only process
energy sources Any process
utilizing biogas and/or
biomass as the only process
energy sources.
N............. Naphtha................ Cellulosic biomass from Gasification and upgrading.. 3
switchgrass, miscanthus,
and energy cane.
O............. Butanol................ Corn starch................. Fermentation; dry mill using 6
natural gas, biomass, or
biogas for process energy.

[[Page 14217]]

P............. Ethanol, renewable The non-cellulosic portions Any......................... 5
diesel, jet fuel, of separated food waste.
heating oil, and
naphtha.
Q............. Biogas................. Landfills, sewage waste Any......................... 5
treatment plants, manure
digesters.
R............. Ethanol................ Grain Sorghum............... Dry mill process using 6
biogas from landfills,
waste treatment plants, and/
or waste digesters, and/or
natural gas, for process
energy.
S............. Ethanol................ Grain Sorghum............... Dry mill process, using only 5
biogas from landfills,
waste treatment plants, and/
or waste digesters for
process energy and for on-
site production of all
electricity used at the
site other than up to 0.15
kWh of electricity from the
grid per gallon of ethanol
produced, calculated on a
per batch basis.
----------------------------------------------------------------------------------------------------------------

* * * * *
[FR Doc. 2013-04929 Filed 3-4-13; 8:45 am]
BILLING CODE 6560-50-P

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