# Regulation of Fuels and Fuel Additives: RFS Pathways II and Technical Amendments to the RFS 2 Standards > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2013-12714 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** June 14, 2013 - **Citation:** 78 FR 36042 ## Text ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 80 [EPA-HQ-OAR-2012-0401; FRL-9816-3] RIN 2060—AR21 Regulation of Fuels and Fuel Additives: RFS Pathways II and Technical Amendments to the RFS 2 Standards AGENCY: Environmental Protection Agency (EPA). ACTION: Notice of Proposed Rulemaking. SUMMARY: In this Notice of Proposed Rulemaking, EPA is proposing amendments to three separate sets of regulations relating to fuels. First, EPA is proposing to amend certain of the renewable fuels standard (RFS2) program regulations. We believe these proposals will facilitate the introduction of new renewable fuels as well as improve implementation of the program. This proposal includes various changes related to biogas, including changes related to the revised compressed natural gas (CNG)/liquefied natural gas (LNG) pathway and amendments to various associated registration, recordkeeping, and reporting provisions. This proposed regulation includes the addition of new pathways for renewable diesel, renewable naphtha, and renewable electricity (used in electric vehicles) produced from landfill biogas. Adding these new pathways will enhance the ability of the biofuels industry to supply advanced biofuels, including cellulosic biofuels, which greatly reduce the greenhouse gas emissions (GHG) compared to the petroleum-based fuels they replace. It also addresses “nameplate capacity” issues for certain production facilities that do not claim exemption from the 20% greenhouse gas (GHG) reduction threshold. In this notice, EPA addresses issues related to crop residue and corn kernel fiber and proposes an approach to determining the volume of cellulosic RINs produced from various cellulosic feedstocks. We also include a lifecycle analysis of advanced butanol and discuss the potential to allow for commingling of compliant products at the retail facility level as long as the environmental performance of the fuels would not be detrimental. Several other amendments to the RFS2 program are included. Second, EPA is also proposing various changes to the E15 misfueling mitigation regulations (E15 MMR). Among the E15 changes proposed are technical corrections and amendments to sections dealing with labeling, E15 surveys, product transfer documents, and prohibited acts. We also propose to amend the definitions in order to address a concern about the rounding of test results for ethanol content violations. Lastly, EPA is proposing changes to the survey requirements associated with the ultra-low sulfur diesel (ULSD) program. DATES: Comments must be received on or before July 15, 2013. We do not expect a request for a public hearing. However, if we receive a request for a public hearing by July 1, 2013 we will publish information related to the timing and location of the hearing and the timing of a new deadline for public comments. ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2012-0401, by one of the following methods: • http://www.regulations.gov. Follow the on-line instructions for submitting comments. • Email: a-and-r-docket@epa.gov, Attention Air and Radiation Docket ID No. EPA-HQ-OAR-2012-0401. • Mail: Air and Radiation Docket, Docket No. EPA-HQ-OAR-2012-0401, Environmental Protection Agency, Mail code: 6406J, 1200 Pennsylvania Ave. NW., Washington, DC 20460. Please include a total of two (2) copies. • Hand Delivery: EPA Docket Center, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave. NW., Washington, DC 20460, Attention Air and Radiation Docket, ID No. EPA-HQ-OAR-2012-0401. Such deliveries are only accepted during the Docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information. Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-2012-0401. EPA's policy is that all comments received will be included in the public docket without change and may be made available online at www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through www.regulations.gov or email. The www.regulations.gov Web site is an “anonymous access” system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to EPA without going through www.regulations.gov, your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. For additional information about EPA's public docket visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm. Docket: All documents in the docket are listed in the www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g., CBI or other information for which disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in www.regulations.gov or in hard copy at the Air and Radiation Docket, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave. NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the Air and Radiation Docket is (202) 566-1742. FOR FURTHER INFORMATION CONTACT: Joseph Sopata, Chemist, Office of Transportation and Air Quality, Mail Code: 6406J, U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue NW., 20460; telephone number: (202) 343-9034; fax number: (202) 343-2801; email address: sopata.joe@epa.gov. SUPPLEMENTARY INFORMATION: This preamble follows the following outline: I. Why is EPA taking this action? II. Does this action apply to me? III. What should I consider as I prepare my comments for EPA? IV. Executive Summary V. Renewable Fuel Standard (RFS2) Program Amendments A. Approving Cellulosic Volumes From Cellulosic Feedstocks 1. Variability in Cellulosic Content Estimates of Feedstocks 2. Characteristics of the Amount of the Final Fuel Derived From Cellulosic Materials 3. Previous Precedents 4. Alternative Approaches B. Lifecycle Greenhouse Gas Emissions Analysis for Renewable Electricity, Renewable Diesel and Naphtha Produced From Landfill Biogas 1. Feedstock Production 2. Determination of the Cellulosic Composition of Landfill Biogas 3. Fuel Production—General Considerations 4. Fuel Production for Renewable Electricity 5. Fuel Production, Transport and Tailpipe Emissions for Renewable Diesel and Naphtha C. Proposed Regulatory Amendments Related to Biogas 1. Changes Applicable to the Revised CNG/LNG Pathway From Biogas 2. New Registration (Contract Requirements) for Renewable Electricity and Fuels Produced From Biogas That Qualify as Renewable Fuel and That are Registered for RIN Generation 3. Changes Applicable to all Biogas Related Pathways for RIN Generation 4. Changes Applicable To Process Electricity Production Requirement for the Biogas-Derived Cellulosic Diesel and Naphtha Pathways D. Amendment to the Definition of “Crop Residue” and Definition of a Pathway for Corn Kernel Fiber E. Consideration of Advanced Butanol Pathway 1. Proposed New Pathway 2. Butanol, Biobutanol, and Volatility Considerations F. Amendments to Various RFS2 Compliance Related Provisions 1. Proposed Changes to Definitions 2. Provisions for Small Blenders of Renewable Fuels 3. Proposed Changes to Section 80.1450—Registration Requirements 4. Proposed Changes to Section 80.1452—EPA Moderated Transaction System (EMTS) Requirements—Alternative Reporting Method for Sell and Buy Transactions for Assigned RINs 5. Proposed Changes to Section 80.1463—Confirm That Each Day an Invalid RIN Remains in the Market is a Separate Day of Violation 6. Proposed Changes to Section 80.1466—Require Foreign Ethanol Producers, Importers and Foreign Renewable Fuel Producers That Sell to Importers to be Subject to U.S. Jurisdiction and Post a Bond 7. Proposed Changes to Section 80.1466(h)—Calculation of Bond Amount for Foreign Renewable Fuel Producers, Foreign Ethanol Producers and Importers 8. Proposed Changes to Facility's Baseline Volume To Allow “Nameplate Capacity” for Facilities not Claiming Exemption From the 20% GHG Reduction Threshold G. Minor Corrections to RFS2 Provisions VI. Amendments to the E15 Misfueling Mitigation Rule A. Proposed Changes to Section 80.1501—Label B. Proposed Changes to Section 80.1502—E15 Survey C. Proposed Changes to Section 80.1503—Product Transfer Documents D. Proposed Changes to Section 80.1504—Prohibited Acts E. Proposed Changes to Section 80.1500—Definitions VII. Proposed Amendments to the ULSD Diesel Survey VIII. Statutory and Executive Order Reviews I. Why is EPA taking this action? EPA is taking this action to amend various provisions in its regulations pertaining to fuels and fuel additives. First, EPA is proposing to amend 40 CFR part 80, subpart M related to the renewable fuels standard (RFS2). The RFS2 program was required by the Energy Independence and Security Act of 2007 (EISA 2007), which amended the Clean Air Act (CAA). The final regulations for RFS2 were published in the Federal Register on March 26, 2010 (75 FR 14670). In this notice, references to the “RFS2 final rule” refer to the March 26, 2010 Federal Register notice unless otherwise noted. Second, EPA is proposing to amend provisions of 40 CFR part 80, subpart N, related to misfueling mitigation for 15 volume percent (%) ethanol blends (E15). The final regulations for E15 were published in the Federal Register on July 25, 2011 (76 FR 44422). Several items in this proposed action will assist regulated parties in complying with RFS2 and E15 requirements. This action is not expected to result in significant changes in regulatory burdens or costs associated with the RFS2 and E15 programs. Third, EPA is proposing a change to the ultra low sulfur diesel (ULSD) program of 40 CFR part 80, subpart I. Specifically, EPA is proposing an amendment to the survey provisions that would likely result in decreasing the number of samples that must be taken, and as such would be expected to result in a decrease in regulatory burdens or costs. II. Does this action apply to me? Entities potentially affected by this action include 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: Category NAICS Codes a SIC Codes b Examples of potentially regulated parties Industry 324110 2911 Petroleum refiners, importers. Industry 325193 2869 Ethyl alcohol manufacturers. Industry 325199 2869 Other basic organic chemical manufacturers. 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. a North American Industry Classification System (NAICS). b 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 I, M and N 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. III. What should I consider as I prepare my comments for EPA? A. Submitting CBI. Do not submit this information to EPA through www.regulations.gov or email. Clearly mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD-ROM that you mail to EPA, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. B. Tips for Preparing Your Comments. When submitting comments, remember to: • Identify the rulemaking by docket number and other identifying information (subject heading, Federal Register date and page number). • Follow directions—The agency may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or section number. • Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes. • Describe any assumptions and provide any technical information and/or data that you used. • If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced. • Provide specific examples to illustrate your concerns, and suggest alternatives. • Explain your views as clearly as possible, avoiding the use of profanity or personal threats. • Make sure to submit your comments by the comment period deadline identified. C. Docket Copying Costs. You may be charged a reasonable fee for photocopying docket materials, as provided in 40 CFR part 2. IV. Executive Summary EPA is proposing amendments to three sets of regulations. First, EPA is proposing to amend certain of the renewable fuels standard (RFS2) program regulations at 40 CFR part 80, Subpart M. Section V of this preamble includes several proposed amendments to the RFS2 regulations of 40 CFR part 80. The final regulations for RFS2 were published in the Federal Register on March 25, 2010 (75 FR 14670). EPA has issued technical corrections in the past. We have identified several additional changes. Some of the proposed changes in this notice are of a substantive nature; others are more in the nature of technical corrections, including corrections of obvious omissions and errors in citation. Among the more substantive modifications are various proposed changes related to biogas, including changes related to the revised compressed natural gas (CNG)/liquefied natural gas (LNG) pathway and amendments to various associated registration, recordkeeping, and reporting provisions. These fuels have the potential to add notable volumes of advanced biofuel including cellulosic biofuel to the existing renewable fuel volumes already being produced. Many of these changes are being proposed in order to facilitate the introduction of new renewable fuels under the RFS2 program and have come at the suggestion of industry stakeholders. This preamble includes the addition of new pathways for renewable diesel, and renewable naphtha, and renewable electricity (used in electric vehicles) produced from landfill biogas. It includes a proposal to address “nameplate capacity” issues for certain production facilities that do not claim exemption from the 20% greenhouse gas (GHG) reduction threshold. EPA proposes to address issues related to crop residue and corn kernel fiber. We propose an approach for approving the cellulosic volumes from cellulosic feedstocks. We include a lifecycle analysis of advanced butanol and discuss the potential to allow for commingling of compliant products at the retail facility level as long as the environmental performance of the fuels would not be detrimental when compared to existing practices. We specifically discuss this consideration for commingling in regards to the volatility associated with butanol gasoline and ethanol gasoline blends. We state when and how EPA may cancel a company registration. Of a more minor scope, this preamble includes proposed amendments that would define terminology used for registration and reporting purposes and propose changes to registration and reporting requirements. This preamble also discusses some minor corrections, including adding language to registration, recordkeeping and reporting sections requiring English language translation of documents. We have also proposed to correct obvious omissions and errors in citation in the existing RFS2 regulation. Second, EPA is also proposing various changes to the E15 misfueling mitigation regulations (E15 MMR) at 40 CFR part 80, subpart N. The final E15 MMR was published in the Federal Register on July 25, 2011 (76 FR 44406). Among the E15 changes proposed are technical corrections and amendments to sections dealing with labeling, E15 surveys, product transfer documents, and prohibited acts. We also propose to amend the definitions in order to address a concern about the rounding of Reid Vapor Pressure (RVP) test results, in response to a question raised by some industry stakeholders. Third, in response to questions received from regulated parties, we propose to amend the ultra low sulfur diesel (ULSD) survey provisions in a manner that will likely reduce the number of samples required. This may mean a reduction in costs and burdens associated with compliance for regulated parties, with no expected degradation in the highly successful environmental performance of the program. V. Renewable Fuel Standard (RFS2) Program Amendments The RFS2 program was required by the Energy Independence and Security Act of 2007 (EISA 2007), which amended the Clean Air Act (CAA). The final regulations for RFS2 were published in the Federal Register on March 26, 2010 (75 FR 14670). The rule took effect on July 1, 2010. In this notice, we are proposing several new renewable fuel pathway options for advanced biofuels including new cellulosic biofuel pathways. This proposed regulation would also provide modifications and technical amendments to the existing RFS2 program. A. Approving Cellulosic Volumes From Cellulosic Feedstocks Since the inception of the RFS program, EPA has qualified several fuel pathways that are able to generate cellulosic biofuel RINs (D codes 3 and 7). See 40 CFR 80.1426. Each of the qualified cellulosic feedstocks listed in section 80.1426 contain other components such as starches, sugars, lipids, and proteins. To date, EPA has not provided detailed information on how other components should be treated. This has led to uncertainty amongst renewable fuel producers about whether their entire volume of fuel produced from a cellulosic feedstock would be eligible to generate cellulosic RINs. In this rulemaking, EPA proposes to allow 100% of the volume of renewable fuel produced from certain specified, currently approved cellulosic feedstocks to generate cellulosic (D-3 or D-7) RINs. We also take comment on two alternative approaches for how to treat non-cellulosic components of cellulosic feedstocks. For purposes of the RFS program, cellulosic biofuel is defined as “renewable fuel derived from any cellulose, hemicellulose, or lignin that is derived from renewable biomass and that has lifecycle greenhouse gas emissions, as determined by the Administrator, that are at least 60 percent less than the baseline lifecycle greenhouse gas emissions.” This definition was added in Section 211(o)(1)(E) by the Energy Independence and Security Act (EISA) of 2007, where Congress specified four different categories of renewable fuel and their associated volume requirements. The threshold for reduction in greenhouse gases is set at a higher percentage for cellulosic biofuel than the reduction for the other categories of renewable fuels. While the volume requirements for cellulosic biofuel start at a relatively low volume, Congress specified large volume increases over time such that the main growth in the use of renewable fuels comes from cellulosic biofuels. This reflects a strong Congressional intention to promote the use of cellulosic biofuel and achieve the associated greenhouse gas emissions reductions. However, no plant matter can ever consist entirely of cellulose, hemicellulose and lignin. Plants require proteins, DNA, carbohydrates and many other types of compounds in order to grow and function. Even feedstocks such as switchgrass, corn stover, and woody materials which are the most commonly cited “cellulosic” feedstocks, contain measurable proportions of other types of organic molecules. However, these “cellulosic” feedstocks contain much more cellulose, hemicellulose and lignin than do other types of biomass. As shown in Table V.A.-1, most “cellulosic” feedstocks consist of approximately 80-95% cellulose, hemicellulose, or lignin. 1 In contrast, corn kernels contain roughly 75% starch and less than 10% fiber (which includes the cellulosic components, as well as other materials), 2 and soybeans are roughly 60% oil and protein and only about 15% fiber. 3 1 See Memorandum to Docket, “Cellulosic Content of Various Feedstocks,” Docket EPA-HQ-OAR-2012-0401. 2 Peplinski et al. (1992) Physical, chemical and dry-mill properties of corn of varying density and breakage susceptibility. Cereal Chemistry, 69(4), 397-400. 3 Illinois Soybean Association. Facts and Statistics for the Illinois Soybean Industry. http://www.ilsoy.org/_data/mediaCenter/files/1290.pdf. 4 Values have been adjusted to account for the presence of inorganic ash, which will not produce fuel, as described in the Memorandum to the Docket, “Cellulosic Content of Various Feedstocks,” Docket EPA-HQ-OAR-2012-0401. Table V.A.-1—Average Cellulosic Composition of Different Types of Feedstocks 4 Feedstock type Average adjusted cellulosic composition (percent) Crop Residue 90 Switchgrass 85 Miscanthus 85 Other Grasses 81 Wood and Branches 92 EPA is proposing to allow 100% of the volume of renewable fuel produced from specific cellulosic feedstock sources found in Table 1 of section 80.1426 to generate D-3 or D-7 RINs (depending on the type of finished fuel). However separated food waste, separated yard waste, and separated MSW would continue to be treated as before, as discussed below. There are three major justifications for this determination: (1) There can be significant variation in the amount of cellulosic content in any feedstock, which varies within a growing season, across samples, and across sites. Attempting to account for this variability would impose a significant administrative burden on producers and EPA; (2) The amount of the final fuel that is produced from the cellulosic portion of the feedstock is likely to be very high, particularly for fuels produced using a biochemical reaction; (3) EPA has already made previous determinations in which a single RIN value was assigned to the fuel produced since it came primarily from one source even though it was also produced from incidental amounts of other sources. This determination is based on the view that the statutory requirement does not mandate that in all cases the renewable fuel must be produced solely from the cellulosic material in the renewable biomass. EPA considers the statutory definition of cellulosic biofuel to be flexible on this point. Given these factors cited above, the Agency believes this interpretation of “derived from” is consistent with the Congressional intent to require increased use of cellulosic biofuels while ensuring that the program can be implemented in a reasonable way. Details on the variability in feedstocks, characteristics of the final fuel, previous precedents, and alternative proposals are included in the following sections. 1. Variability in Cellulosic Content Estimates of Feedstocks The cellulosic components of feedstock consist of the major structural components; cellulose; hemicellulose; and lignin. EPA has reviewed research characterizing the different components of feedstocks, mainly focused on how the materials could be broken down and converted into fuel. There has been work also in defining standardized procedures and test methods for analyzing the different components of biomass; 5 however, the studies considered all employ slightly different methods. For the purposes of this rule, EPA considered the amount of the feedstocks that is composed of cellulosic components i.e., how much comes from the cellulose, hemicellulose or lignin, as opposed to any other components of the feedstock. There is significant variation in the data reported on feedstock component compositions. The variation is due to a number of causes, such as measurement methods, 6 7 variety within a generic feedstock type, and storage time. 8 5 See, e.g., the Standard Biomass Analytical Procedures developed by the National Renewable Energy Laboratory, http://www.nrel.gov/biomass/analytical_procedures.html. 6 Compositional Analysis of Lignocellulosic Feedstocks. 2. Method Uncertainties, David W. Templeton, Christopher J. Scarlata, Justin B. Sluiter, And Edward J. Wolfrum, J. Agric. Food Chem. 2010, 58, 9054-9062 7 Relative standard deviations (RSD) of 5-8% are reported for cellulose, hemicelluloses and lignin with the other minor components showing 16-22% RSD. 8 Composition of Herbaceous Biomass Feedstocks, DoKyoung Lee, Vance N. Owens, Arvid Boe, Peter Jeranyama, Plant Science Department, South Dakota State University, SGINC1-07, June 2007. Although there are many factors that contribute to the large variability in assessments of cellulosic content, all studies confirm that the feedstocks in Table 1 of section 80.1426 have an adjusted cellulosic content of at least 70%, with an average content of around 85% cellulosic. 9 A memorandum to the docket provides more information on cellulosic terminology, percent composition of various feedstocks, and the variability of different feedstock components. 10 From this data, EPA concludes that each of the qualified feedstocks listed in section 80.1426 are comprised predominantly of cellulose, hemicellulose and lignin. 9 EPA only considered the organic components of the materials when determining cellulosic content. Inorganic materials are not likely to end up in the final fuel product and would not contribute to the fuel heating content in the event that they remained in the final fuel. This methodology is consistent with how RINs are determined. In this section, EPA refers to this as “adjusted cellulosic.” Adjusted cellulosic content does not consider other material that is not converted into biofuel such as minerals or other components that would show up as part of the ash remaining after a thermo-chemical conversion process. 10 See Memorandum to Docket, “Cellulosic Content of Various Feedstocks,” Docket EPA-HQ-OAR-2012-0401. 2. Characteristics of the Amount of the Final Fuel Derived From Cellulosic Materials Process technology plays a key role in how much of the final fuel product is actually produced from cellulose, hemicellulose, or lignin. There are two basic processes for converting cellulosic feedstocks into fuel: thermo-chemical and biochemical. Thermo-chemical processes mainly consist of pyrolysis—in which cellulosic biomass is decomposed with temperature to bio-oils and could be further processed to produce a finished fuel—and gasification—in which cellulosic biomass is decomposed to synthesis gas (“syngas”) with further catalytic processing to produce a finished fuel product. The biochemical process requires the release of sugars from biomass and the use of microorganisms to convert sugars into fuels. Thermo-chemical processes can accept a more heterogeneous mix of feedstock and typically convert all of the organic components of the feedstock into finished fuel. The biochemical process generally accepts a more homogeneous mix of feedstocks and typically converts only the cellulosic and hemicellulosic components of the feedstock into the final fuel product. Therefore, regardless of the feedstock used, the final fuel produced from the biochemical process will typically only come from the cellulosic or hemicellulosic portions of feedstock, while the final fuel produced from the thermo-chemical process could come from cellulosic and non-cellulosic components. For thermo-chemical production in which the non-cellulosic components of the feedstock can contribute to the volume of fuel produced in addition to the cellulosic components, the percent of fuel produced from the non-cellulosic portion can vary due to such factors as feedstock type and the time and location of feedstock harvest. Regardless, we believe that the majority of the fuel produced will be from the cellulosic components. As a practical matter, there is no simple test that can be used to measure the amount of fuel end product that originated from cellulosic materials. For fuel produced via the biochemical process, 100% of the fuel produced is directly the result of conversion of the cellulosic content. In selecting a cellulosic process, whether based on biochemical or thermo-chemical design, the fuel producer is clearly demonstrating that its primary intent is to convert the cellulosic portions of the feedstock. Cellulosic fuel producers invest in expensive process technologies with the intent of converting the cellulosic components of a feedstock into fuel; conversion of the non-cellulosic components can be achieved much more easily with less of a capital investment. Furthermore, since the fuel produced will be primarily the result of the direct conversion of cellulosic content of the feedstock and considering the relatively small range of non-cellulosic portion of feedstock that could contribute to the volume of fuel produced, EPA believes it is reasonable to consider all the fuel produced when relying on cellulosic conversion processes to be cellulosic biofuel. 3. Previous Precedents EPA has already considered instances where one RIN value was assigned to the fuel produced since it came primarily from one source even though it was also produced from some amount of other chemical compounds. In the March 2010 RFS rulemaking, EPA discussed two different situations for fuel produced from separated yard waste and food waste as the renewable biomass feedstock. The first involved food waste or yard waste that was kept separate, from generation, from municipal solid waste (MSW). EPA determined that both of these feedstocks could be considered renewable biomass. With respect to separated yard waste, EPA determined that the yard waste was expected to be composed almost entirely of woody material or leaves, and this would be deemed to be cellulosic material and would generate cellulosic biofuel RINs. Separated food waste, however, was likely to be composed of both cellulosic and non-cellulosic materials, and in certain cases would likely be composed primarily of non-cellulosic materials, such as sugars and starches from the food. EPA determined that separated food waste would be deemed to be non-cellulosic material, and would generate advanced biofuel RINs and not cellulosic RINs, unless the renewable fuel producer demonstrated the part of the food waste that was cellulosic. This portion would then generate cellulosic RINs. 11 11 75 FR 14670, 14706 (March 26, 2010). The second situation EPA previously addressed involved separated MSW. EPA determined that separated MSW that met certain regulatory requirements would qualify as a renewable biomass for purposes of producing renewable fuel. EPA recognized that the biogenic portion of this feedstock would be composed of a “variety of materials, including yard waste (largely cellulosic) and food waste (largely starches and sugar), as well as incidental materials remaining after reasonably practicable separation efforts such as plastic and rubber of fossil origin.” Testing could identify the portion of the fuel produced from biogenic materials, and these biogenic materials “will likely be largely derived from cellulosic materials (yard waste, textiles, paper, and construction materials), and to a much smaller extent starch-based materials (food wastes).” However, EPA was not aware of a test method to distinguish between renewable fuel produced from the cellulose and fuel produced from the starch and under those circumstances determined that it was appropriate to base the assignment of RINs on the “predominant” component of the biogenic material. EPA thus determined that all of the fuel generated from the biogenic portion of separated MSW would be considered cellulosic biofuel. 12 12 75 FR at 14706. Thus, EPA has interpreted the definition of cellulosic biofuel as including in some cases a renewable fuel that is produced from both the cellulosic and incremental amounts of non-cellulosic components of the feedstock. EPA has treated the resulting fuel as all derived from cellulosic material where the feedstock is composed almost entirely of woody materials and leaves, or where the predominant component of the feedstock is likely cellulosic. The fuel will be largely derived from this cellulosic material and to a much smaller extent from non-cellulosic materials. There currently is no ready test to identify the portion of fuel produced from non-cellulosic materials. EPA has not considered the fuel as cellulosic in cases where the feedstock was likely to be largely non-cellulosic materials. In all of these cases, EPA has recognized that the fuel would be produced from both the cellulosic and non-cellulosic materials in the feedstock, and has determined in some cases to consider the fuel entirely cellulosic biofuel based on the relative amounts of the cellulosic and non-cellulosic materials and, for fuel made from the biogenic portion of separated MSW, on the lack of availability of a test procedure to differentiate how much of the fuel came from the cellulosic materials. These determinations have been based on the view that the statutory requirement that cellulosic biofuel be “derived from cellulose, hemicellulose, or lignin” does not mandate that in all cases the renewable fuel must be produced solely from the cellulosic material in the renewable biomass. EPA considers the statutory definition of cellulosic biofuel to be ambiguous on this point, providing EPA the discretion to reasonably determine under what circumstances a fuel appropriately could be considered cellulosic biofuel when the fuel is produced from a feedstock that is a mixture of cellulosic and non-cellulosic materials. To date, EPA has specified certain circumstances where the entire fuel will be considered cellulosic biofuel. EPA has taken this action in cases where the cellulosic material is almost entirely woody materials or leaves, or the fuel is produced from materials that are predominantly composed of cellulosic materials and to a much smaller extent non-cellulosic materials, with no current test to identify the differing portions. There have been two elements present in these decisions. One involves a determination that the feedstock is composed almost entirely or largely of cellulosic materials. EPA has also considered whether or not there is a test method to identify the actual portion of the fuel produced from cellulosic materials. In this rulemaking EPA is proposing an approach that is consistent with and an outgrowth of the approach taken in the RFS2 rulemaking. EPA is proposing to approve certain fuels as cellulosic biofuel where the cellulosic components account for a predominant percentage of the biogenic material in the renewable biomass feedstock used to produce the fuel, even where the non-cellulosic components of the renewable biomass could be reasonably identified or estimated. 13 13 By predominant, EPA means the very high percentages for adjusted cellulosic content discussed in section V.A.1. above for the feedstocks at issue in this proposal. EPA is proposing to classify all of the biofuel as cellulosic in the fuel pathways proposed today, where the cellulosic material makes up a predominant percentage of the organic material from which the fuel is produced. This approach will avoid the administrative and technical burden on producers and EPA of trying to determine the specific amounts of cellulosic and non-cellulosic materials in the specified high-cellulosic feedstock sources, removing potential difficult and potentially time-consuming and expensive impediment to expansion of the cellulosic biofuel industry. The growth in cellulosic biofuel volumes promoted by today's proposal is expected to result in greater reductions in GHGs, as all of the biofuel qualified as cellulosic would have to achieve the minimum 60% reduction in GHG emissions specified in the Act. EPA's application of this approach to the specific fuel pathways and feedstocks discussed in this proposal is intended to ensure that cellulosic materials are the predominant portion of the biogenic materials used to produce cellulosic biofuel. This approach avoids administrative, technical and cost burdens on EPA and industry and promotes the volume and greenhouse gas objectives of Congress. EPA proposes that this is a reasonable interpretation of the definition of cellulosic biofuels, and invites comment on this approach. 14 14 See Bot v. IRS, 353 F.3d 595 (8th Cir. 2003), Wuebker v. IRS, 205 F.2d 897 (6th Cir. 2000), Milligan v. IRS, 38 F.3d 1094 (9th Cir. 1994). See also Hecla Mining Company v. US, 909 F.2d 1371 (10th Cir. 1990) (DOE's interpretation of the term “derived from” in the Uranium Mill Tailings Radiation Control Act of 1978 accepted as a reasonable interpretation under Chevron ). EPA is proposing that biofuel made from the following cellulosic feedstocks will be able to generate applicable cellulosic RINs for 100% of the volume produced: crop residue; slash; pre-commercial thinnings and tree residue; annual cover crops; switchgrass; miscanthus; and energy cane. EPA's prior treatment of separated yard waste, separated food waste, and separated MSW is discussed above and is not being changed. On January 5, 2012, EPA proposed to qualify napier grass and Arundo donax as new feedstocks that would be eligible to generate cellulosic RINs. If those pathways are approved before this rule is final, EPA is proposing to apply the approach discussed above to these feedstocks as well. 15 To the extent that additional cellulosic pathways are approved in the future, we would expect to apply this same methodology to those feedstocks as well, but will evaluate them on a case-by-case basis. 15 In addition, in section B of this proposal, EPA is also proposing to include corn fiber, CNG, LNG, electricity, and renewable diesel and naphtha from landfill biogas as cellulosic pathways for the reasons discussed therein. EPA requests comments on this proposed approach to allow 100% of the volume of renewable fuel produced from the specified cellulosic feedstock sources found in Table 1 of section 80.1426 to generate cellulosic RINs. We also take comment on the cellulosic content values presented for different feedstocks. In addition, we request comments about any analytical methods that may exist to determine what percent of a finished biofuel product may have derived from cellulosic versus non-cellulosic components, and what the costs may be associated with these test methods. We also request comment on the alternative approaches outlined below. 4. Alternative Approaches EPA seeks comment on two alternative approaches to assigning cellulosic RINs to fuels produced from the cellulosic feedstocks discussed above. Separate from the specific pathways addressed in this proposal, EPA also seeks comment on potential approaches for assigning cellulosic RINs for anticipated future pathways for renewable fuels produced from feedstocks that contain lower cellulosic content than those discussed in this rulemaking. Cellulosic Content Threshold Approach An alternative approach for handling the variability in cellulosic content would be for EPA to set a minimum threshold of cellulosic content in the feedstock. Fuels produced from feedstocks with a cellulosic content above this minimum threshold would be eligible to generate cellulosic RINs for 100% of their volume. Thresholds under consideration would range from 70% to 99.9%. A higher percentage would place more emphasis on the feedstock content having a higher actual cellulosic component, whereas the lower percentages would place more emphasis on promoting the volume of fuels that could be categorized as cellulosic biofuel. EPA invites comment on this approach, and also invites comment on the most appropriate value to use as the threshold. Furthermore, EPA invites comment on whether individual producers should be responsible for submitting data that their feedstock meets this threshold, or whether EPA should determine whether feedstocks meet this threshold based on existing published data. Since biochemical processes generally only convert the cellulosic, hemicellulosic, or lignin components of the feedstock to fuel, EPA believes under this alternative approach, it may still be appropriate to allow fuel producers using biochemical processes to generate RINs for 100% of the fuel produced from cellulosic feedstocks. EPA requests comments on our assumption that biochemical processes will be specific for the cellulosic components, and we also request comment on whether to allow 100% of the fuel produced via biochemical processes to generate cellulosic RINs. Specified Percentage Approach As noted above, examining the range of feedstock data compiled by EPA, it appears that 85% would be a reasonable approximation for the average adjusted cellulosic content across a range of assessments of the specific feedstocks that are qualified to produce cellulosic fuel. Under this approach, fuels produced from the cellulosic feedstocks discussed above would be eligible to generate cellulosic RINs for 85% of their volume, and the remaining 15% would be eligible to generate advanced RINs. The specified percentage approach would reduce administrative burden but also incentivize renewable fuel production. For this approach, EPA would effectively be treating 85% of the fuel produced from all of these feedstock sources as being derived from cellulosic material. However, EPA would consider allowing a larger percentage of the fuel to qualify for cellulosic RINs if the producer could submit data that demonstrates a consistently higher cellulosic content in their feedstock. Under this approach, producers could submit a written plan for approval under the registration procedures in 40 CFR 80.1416(b)(vii). The plan would need to detail the cellulosic content of the feedstock, the method used for quantifying the cellulosic and non-cellulosic contents, and the production process used. Since biochemical processes generally only convert the cellulose, hemicellulose, or lignin components of the feedstock to fuel, EPA believes under this alternative approach it would be appropriate to allow fuel producers using biochemical processes to generate RINs for 100% of the fuel produced from cellulosic feedstocks. EPA requests comments on our assumption that biochemical processes will be specific for the cellulosic components, and we also request comment on whether to allow 100% of the fuel produced via biochemical processes to generate cellulosic RINs. Request for Comment on Potential Approaches for Fuels Produced From Feedstocks With Lower Cellulosic Content Finally, EPA anticipates that in the future, we may address biofuels that are produced from feedstocks that contain lower cellulosic content than those discussed in this rulemaking. Accordingly, we request comment on how EPA should assign RINs to the fuels produced from feedstocks with lower cellulosic content than those presented in this rulemaking but for which some of the fuel is produced from the cellulosic components. One possible example would be a feedstock that contained in the range of 40-60% cellulose, hemicellulose and lignin, where the fuel was produced using thermochemical methods such that the same percentage of the fuel may come from cellulosic materials. EPA invites comments about what approaches could be taken for assigning cellulosic RINs to the biofuel. For example, would one or more of the approaches outlined above be appropriate for assigning RINs to this fuel? Are there variations on these approaches that EPA should consider? EPA also invites comments on how to assign cellulosic RINs where processes other than thermochemical methods are used. B. Lifecycle Greenhouse Gas Emissions Analysis for Renewable Electricity, Renewable Diesel and Naphtha Produced from Landfill Biogas EPA has received several facility-specific petitions under § 80.1416 to allow renewable electricity, renewable diesel and naphtha produced from landfill biogas to qualify as renewable fuels under the RFS program. Since these new pathways could be more broadly applicable, EPA is proposing to add these pathways to Table 1 to § 80.1426 through this rulemaking process. Based on questions from companies, EPA is also modifying the existing biogas pathway to specify that compressed natural gas (CNG) or liquefied natural gas (LNG) is the fuel and biogas is the feedstock. For this proposal, EPA considered both the cellulosic origin of landfill biogas and the lifecycle GHG impacts of three types of fuel produced from landfill-derived biogas. In the final RFS2 rule, EPA established biogas as a fuel type when derived from landfills, sewage waste treatment plants, and manure digesters. This biogas was classified as an advanced biofuel eligible to generate D-Code 5 RINs. EPA also established cellulosic diesel and cellulosic naphtha as cellulosic biofuels eligible to generate D-Code 7 and 3 RINs, respectively. The eligible feedstocks for these biofuels include cellulosic components of separated municipal solid waste but did not include biogas from landfills. Based in part on additional information received through the petition process for EPA approval of renewable electricity and renewable diesel and naphtha produced from landfill biogas, EPA has evaluated these pathways and is proposing to include renewable electricity produced from landfill biogas feedstock in Table 1 to § 80.1426 as a cellulosic fuel type. It is important to note that RINs may only be generated for electricity from biogas that can be tracked to use in the transportation sector, such as by an electric vehicle. We are also proposing to add renewable diesel produced from landfill biogas via the Fischer-Tropsch process as an approved advanced and/or biomass-based diesel biofuel and naphtha produced from landfill biogas via the Fischer-Tropsch process as an approved advanced biofuel. If the Fischer-Tropsch facilities produce at least 20% of their electricity demand at the facility from certain allowed sources, we are proposing that the renewable diesel and naphtha produced would further qualify as cellulosic biofuels. We are also proposing to amend the existing biogas pathway to list renewable CNG/LNG as the fuel types instead of biogas since the biogas is converted into CNG or LNG before being used as a transportation fuel, as discussed below. Renewable CNG/LNG produced from biogas from waste treatment plants and waste digesters is still classified as an advanced biofuel. However, renewable CNG/LNG produced from biogas from landfills now qualifies as a cellulosic pathway. The changes to the renewable CNG/LNG pathway are described in section C.1. “Changes Applicable to the Revised CNG/LNG pathway from Biogas” below. 1. Feedstock Production When waste materials are buried in a landfill, decomposition of the organic materials consumes all of the oxygen present within roughly one year, leaving the bulk of the material to undergo slower, anaerobic decomposition. This process produces large amounts of methane for several decades, as well as other products, with the gases released as “biogas.” Biogas from landfills typically contains approximately 50% methane and 50% carbon dioxide, with small or trace amounts of other gases. Methane is a potent greenhouse gas (GHG), with a global warming potential of 21 times that of carbon dioxide, and landfills are the third-largest anthropogenic source of methane to the atmosphere in the United States. 16 16 U.S. Environmental Protection Agency. 2013. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011, Chapter 8: Waste. EPA 430-R-13- 001, available at http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-Main-Text.pdf. The methane present in biogas is also a potential energy source that may be purified and compressed to be used directly in CNG or LNG vehicles, combusted to produce electricity or converted to renewable diesel and naphtha via the Fischer-Tropsch process. The March 2010 RFS final rule concluded that municipal solid waste has no agricultural or land use change GHG emissions associated with its production. Furthermore, the feedstock for these fuels is landfill biogas, which already appears in Table 1 of § 80.1426(f) of the RFS2 regulations and has already been evaluated as part of the RFS2 final rule lifecycle GHG determinations. Therefore no new renewable feedstock production modeling was required, no GHG emissions were attributed to feedstock production for any of these renewable fuel pathways, and EPA focused our analysis on the new fuel production processes. 2. Determination of the Cellulosic Composition of Landfill Biogas In order for fuels produced from landfill biogas as a feedstock to qualify to generate D-Code 3 or 7 (cellulosic) RINs, the renewable fuel must be derived from cellulosic materials and must meet a 60% GHG emissions reduction threshold, as described in the following sections. In this section, we discuss our determination that biogas derived from landfills is derived from cellulose, hemicellulose or lignin. CAA 211(o) specifies “separated yard waste or food waste” as a type of renewable biomass, and in the March 2010 RFS final rule, EPA stated: As a result of the intermixing of wastes, the fact that biogas is formed only from the biogenic portion of landfill material, and the fact that landfill material is as a practical matter inaccessible for further separation, EPA believes that no further practical separation is possible for landfill material and biogas should be considered as produced from separated yard and food waste for purposes of EISA. The March 2010 RFS final rule stated that all landfill-derived biogas was therefore eligible to generate RINs. An in-depth study of methane production from different chemical components of municipal solid waste found that roughly 90% of the methane generated in landfills derived was from cellulose and hemicellulose. 17 Accordingly, EPA is proposing to classify renewable fuels produced from landfill biogas as derived from cellulose, hemicellulose or lignin. This determination is discussed in more detail in a memo to the docket. 18 Consistent with the discussion in the section above, “Approving Cellulosic Volumes from Cellulosic Feedstock,” we are classifying all of the biofuel volume produced from landfill biogas as cellulosic in origin. Therefore the entire volume of renewable fuels using landfill biogas as a feedstock will be eligible to generate cellulosic RINs (D-Codes 3 and 7) if the fuel also meets the required 60% GHG emissions reductions. EPA invites comment and data on the cellulosic component of biogas. 17 Barlaz, M.A., R.K. Ham, and D.M. Schaefer. 1989. Mass-balance analysis of anaerobically decomposed refuse. Journal of Environmental Engineering, 15(6) 1088-1102. 18 “Support for Cellulosic Determination for Landfill Biogas and Summary of Lifecycle Analysis Assumptions and Calculations for Biofuels Produced from Landfill Biogas,” which has been placed in docket EPA-HQ-2012-0401. 3. Fuel Production—General Considerations Landfills currently treat their methane in one of several ways. Municipal solid waste (MSW) landfills designed to collect at least 2.5 million megagrams (Mg) and 2.5 million cubic meters of waste and emitting at least 50 Mg of non-methane organic compounds per year are required by EPA regulations to capture and control their biogas. 19 These large, regulated landfills represent a small percentage of all landfills by number but are responsible for the majority of biogas emissions from landfills. To comply with the regulations, these landfills must at a minimum combust their biogas in a flare, converting the methane to carbon dioxide, a less potent GHG. They may also use it to generate electricity from combustion of the methane, in which case, the electricity produced may displace electricity from other sources (such as gas-fired power plants) once it enters the grid. If displacing other sources of electricity that on average have greater GHG emissions, landfills that generate electricity may reduce GHG emissions and are using the “best practices” in the industry. 20 Many smaller, unregulated landfills do not collect their biogas, and this methane is “vented” to the atmosphere. In 2010, 29% of the methane generated at landfills was flared and 29% of the methane was used to generate electricity. 21 Accounting for the 25% average collection efficiency of biogas collection systems, 22 we estimate that approximately 38% of the methane generated is derived from landfills that flare their gas and another 38% is derived from landfills with gas-to-electricity projects. By mass balance, this suggests that 24% of the landfill methane generated is from landfills that vent their methane. 19 Standards of Performance for New Stationary Sources and Guidelines for Control of Existing Sources: Municipal Solid Waste Landfills, 61 FR 9905, 9944 (March 12, 1996). 20 Some facilities also use the biogas directly in boilers and other applications or purify the biogas to create CNG or LNG or inject it directly into natural gas pipelines. 21 Environmental Protection Agency. 2012. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010, Annex 3: Methodological Descriptions for Additional Source or Sink Categories. http://epa.gov/climatechange/emissions/usinventoryreport.html. As of December 2012, landfills produced 1913 MW of electricity based on figures from LMOP. This electricity would be almost entirely sold for use on the grid. From http://www.epa.gov/lmop/projects-candidates/index.html. 22 Environmental Protection Agency, Landfill Methane Outreach Program. 2010. LFG Energy Project Development Handbook: Chapter 2. Landfill Gas Modeling. http://epa.gov/lmop/publications-tools/handbook.html. In our lifecycle GHG analysis of these biofuels we need to consider what would have happened to the landfill gas if it was not used to produce transportation fuels. This is the baseline for comparison to calculate the GHG impacts of the fuels in question. Once we have chosen a baseline for comparison, we propose to treat biogas from all landfills the same regardless of how the biogas is processed at that landfill. This approach is consistent with how we have treated the implementation of advanced technologies for all biofuels producers. For the landfill gas-to-electricity pathway we use landfills that flare their biogas as the baseline GHG emissions with which we compare scenarios involving production of electricity from the landfill biogas. We chose this baseline because these landfills are the ones most likely to convert to gas-to-energy projects, since they already have gas collections systems in place. They are also the ones most likely to be the alternative to gas to energy projects since these projects will likely go into larger landfills that are required by regulation to collect and treat the biogas. We expect that small, unregulated landfills would be unlikely to generate enough biogas to justify collecting it for conversion to renewable fuels. Furthermore, we expect that the capital costs for such small landfills would preclude them from making such changes. However, if such small landfills were to capture and use their biogas in transportation fuels, this would result in significantly greater reductions in GHG emissions at each landfill than assumed for landfills already capturing biogas because of the decrease in methane release, so that biofuels produced from such facilities would easily meet the required emissions reduction thresholds. Since landfills that currently have gas-to-energy projects in place at one point either replaced flaring with a gas-to-energy project or installed a gas-to-energy project as an alternative to the minimal compliance route of flaring, we are proposing to treat the emissions from these landfills compared to the same flaring baseline. We show lifecycle results calculated using alternative baselines and discuss our choice of baseline in more depth in a memo to the docket. 23 We invite comment on our baseline assumptions for the electricity pathway. If commenters believe a different baseline is appropriate, EPA specifically invites the submission of data supporting this alternative baseline. 23 “Support for Cellulosic Determination for Landfill Biogas and Summary of Lifecycle Analysis Assumptions and Calculations for Biofuels Produced from Landfill Biogas,” which has been placed in docket EPA-HQ-2012-0401. For gas to liquids projects we also use landfills that flare their biogas as the baseline GHG emissions with which we compare scenarios involving production of gas to liquids, for the same reasons outlined above. We further consider that landfills that have already invested the capital to generate electricity are unlikely to stop doing so in order to generate liquid fuels from the biogas, which would require considerable additional capital investments. These facilities are therefore an unlikely baseline for the pathways generating renewable diesel and naphtha. We invite comment on our baseline assumptions for the liquids pathway and whether a different baseline would be more appropriate. If commenters believe a different baseline is appropriate, EPA specifically invites the submission of data supporting this alternative baseline. 4. Fuel Production for Renewable Electricity Landfills can generate electricity by combustion of the methane in their biogas. Generating electricity at landfills requires collection of the biogas (using wells, piping and blowers), purification and compression of the biogas and electricity generation. Most landfills use internal combustion engines to generate the electricity, but a significant proportion also use gas or steam turbines or combined cycle systems. Once generated, the electricity enters the electrical grid. In determining the lifecycle GHG analysis of renewable electricity, we examined two main factors. The first involved determining by how much emissions at the landfill (from flaring) would change upon installation of a gas-to-energy project. For this calculation, we used emission factors from the GREET model. 24 The second involved calculation of the decrease in GHG emissions caused by powering the gas blowers already in use with biogas-derived electricity rather than grid electricity upon installation of a gas-to-energy project. This calculation used data from the EPA Landfill Methane Outreach Project (LMOP). 25 For each factor, we needed to first calculate how much electricity could be generated and delivered to the consumer. We used values from LMOP as estimates of the relative shares of different types of engines or turbines, the electricity generation efficiency, parasitic losses, energy use in collecting and preparing the biogas, and a value from the U.S. Energy Information Agency to estimate distribution losses. Values used are shown in Table V.B.-1, and the assumptions and calculations are discussed in more detail in a memo to the docket. 26 24 Argonne National Laboratory (2011) Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation Model (GREET), Version 1 2011, http://greet.es.anl.gov/. 25 EPA LMOP Data. 26 “Support for Cellulosic Determination for Landfill Biogas and Summary of Lifecycle Analysis Assumptions and Calculations for Biofuels Produced from Landfill Biogas,” which has been placed in docket EPA-HQ-2012-0401. 27 All values are derived from information provided by the EPA Landfill Methane Outreach Program except the distribution loss number, which is from the U.S. Energy Information Agency. Parasitic losses were calculated by apportioning the gross electricity generation to different types of generators and using parasitic loss values for that particular type of generator. Table V.B.-1—Calculation of the Net Amount of Electricity Delivered to the Consumer Produced From a Given Amount of Landfill Biogas 27 Value Units Electricity generation efficiency 11700 Btu/kWh. Gross electricity production 0.292 mmBtu/mmBtu biogas. Electricity produced after parasitic losses 0.267 mmBtu/mmBtu biogas. Energy used for blowers 0.014 mmBtu/mmBtu biogas. Distribution losses 0.017 mmBtu/mmBtu biogas. Net electricity delivered to consumer 0.236 mmBtu/mmBtu biogas. We used the value for the net city yield from biogas to calculate how GHG emissions from the landfill itself would change upon conversion from flaring to a gas-to-energy project. We first calculated emissions per mmBtu electricity (Table V.B.-2). However, the drivetrains of electric vehicles are roughly three times as efficient as those of conventional gasoline-powered vehicles, meaning that any given EV would be able to travel about three times as far per Btu of input. To account for this difference, we also calculated emissions per mmBtu fuel equivalent. It would take roughly three times the amount of energy from liquid fuel to drive a conventional vehicle a given distance compared to an EV powered by electricity, so the emissions per mmBtu fuel equivalent are approximately one third as large as the emissions per mmBtu electricity. EPA invites comments on the assumptions regarding electricity equivalence. 28 28 Note that in order to determine the number of RINs generated from a given amount of renewable electricity, section 80.1415(b)(6) of the regulations states that 22.6 kW-hr of electricity shall represent one gallon of renewable fuel with an equivalence value of 1.0. Table V.B.-2—Fuel GHG Emissions for the Renewable Electricity Pathway, Calculated per mmBtu Electricity and per mmBtu Fuel Equivalent Compared to the 2005 Gasoline Baseline Lifecycle stage GHG emissions Renewable electricity kg CO 2 -eq/mmBtu electricity kg CO 2 -eq/mmBtu fuel equivalent 2005 Gasoline baseline kg CO 2 -eq/mmBtu fuel U.S. Average grid electricity kg CO 2 -eq/mmBtu electricity On-site emissions 25 8 Upstream (electricity production for blowers) −13 −4 Total Emissions: 12 4 98 220 % Change from Gasoline Baseline −87% −96% % Change from Grid Electricity −94% N/A On-site emissions of facilities that generate electricity would be slightly higher than emissions from facilities that flare because reciprocating engines, which are the dominant technology used to generate electricity from biogas, are less efficient at destroying methane than flares. Facilities that originally flared their biogas are assumed to have been purchasing electricity from the grid to power the blowers needed to collect the biogas. Upon conversion to gas-to-energy projects, the facilities would now generate that electricity themselves and thus no longer need to purchase this electricity from the grid. The calculations above include a credit in GHG emissions for the avoided purchase of grid electricity (Table V.B.-2). Unlike traditional transportation fuels, there are no GHG emissions involved in transportation or distribution of renewable electricity (distribution losses are accounted for above), nor are there any tailpipe emissions from the direct use of the fuel. Therefore, the only emissions considered are those from production of the fuel, as outlined in Table V.B.-2. The total GHG emissions for conversion from flaring to a gas-to-energy project are 12 kg CO 2 -eq/mmBtu electricity, or 4 kg CO 2 -eq/mmBtu fuel equivalent. Compared with the gasoline baseline GHG emissions of 98 kg CO 2 -eq/mmBtu, these projects would be accompanied by an 87% reduction in GHG emissions when normalized per mmBtu electricity. Accounting for the improved efficiency of EV drivetrains increases the GHG emissions reductions to 96%. Renewable electricity therefore meets the statutory baseline of 60% reductions in GHG emissions relative to the gasoline baseline and qualifies as a cellulosic biofuel. EPA invites comments on the assumptions and calculations of GHG emissions related to renewable electricity from landfill gas. 5. Fuel Production, Transport and Tailpipe Emissions for Renewable Diesel and Naphtha Renewable diesel and naphtha can be made from landfill biogas by a combination of methane reforming and the Fischer-Tropsch gas-to-liquids (GTL) process. For methane reforming, the biogas must first be purified and then be reformed to create synthesis gas, known as “syngas,” which is composed of a mixture of carbon monoxide and hydrogen gas. This process may occur via either steam methane reforming or autothermal reforming. The syngas is next purified and then sent to a Fischer-Tropsch (F-T) system in which the carbon monoxide and hydrogen are combined in the presence of a catalyst to form a range of hydrocarbons. This reaction produces relatively short-chain (naphtha), medium-length (diesel) and long-chain (wax) hydrocarbons. The wax can subsequently be upgraded by hydroprocessing to form naphtha and diesel fuels. The different products are then separated by simple distillation. Heat generated by the reaction can be used to preheat gases in the system and to generate electricity for use in the system or for export. Unconverted syngas from the F-T process and fuel gas from hydroprocessing can also be combusted to generate electricity. GTL plants may have substantially different lifecycle GHG impacts depending on whether they upgrade their waxes and whether they generate electricity as a side product of the reaction. Electricity generation can add to the capital costs of a facility but also greatly reduces the lifecycle GHG emissions of a plant. In determining the lifecycle GHG impacts of GTL fuels, we considered two main factors: on-site emissions at the landfill and upstream emissions from electricity production to power the plant. Additionally, a facility that produced wax was assigned a co-product credit for the wax generated. We did the calculations assuming the facility did not generate any electricity and then calculated what fraction of their electricity demands they would need to generate internally to meet the 60% emissions reduction threshold to qualify for cellulosic RINs. To determine the lifecycle GHG emissions, we used confidential business information (CBI) data provided in a petition submitted to EPA. This process did not involve upgrading of wax to liquid fuels. For this scenario, we used the supplied information about inputs of biogas, outputs of fuel and co-product and electrical demand for the lifecycle analysis. We first determined how many GHG emissions would be avoided on-site at the landfill by changing from the baseline scenario of flaring to collecting the biogas for conversion to liquid fuels. This calculation was similar to that described above for renewable electricity and relied on values from GREET 29 for the emissions factor for flaring. To calculate the emissions from electricity required by the process, we used the emissions factors for average U.S. electrical production used in the RFS2 final rule. 29 Argonne National Laboratory, “Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation Model (GREET),” Version 1 2011, http://greet.es.anl.gov/. To assign a co-product credit to the fuels, we assumed that the wax produced during the Fischer-Tropsch process would enter a market in which it would displace wax derived from petroleum. To determine the effects of such a displacement on GHG emissions, we used data from a model by the Department of Energy's National Energy Technology Laboratory (NETL) 30 for the yields and GHG emissions attributable to wax production from petroleum feedstock. These values only include production emissions and do not include any emissions from combustion of the wax in, for example, candles because we do not have information about what fraction of wax is combusted. If combustion emissions were included, the co-product credit would be even larger. The global wax market is growing, with demand expected to outpace supply in the next few years. 31 As such, it is unlikely that F-T waxes would in reality displace petroleum-derived waxes. Instead, waxes from both sources are likely to be used in parallel to fulfill demand, and such waxes would replace any substitutes that might be used to fill the gap between supply and demand. The nature of these alternatives is presently unknown to EPA, as are their lifecycle GHG emissions. As an alternative to assigning a displacement credit, we could allocate emissions to the waxes along with the renewable diesel and naphtha products. In this case, the co-product credit disappears but total fuel production emissions decrease to 30 kg CO 2 -eq/mm Btu, leading to overall GHG emissions reductions of 68%. Our use of the displacement approach is conservative compared to the allocation approach, which would have resulted in a larger credit for the wax co-product. We welcome comment regarding what kinds of materials these new waxes might replace, as well as how to best account for them in our lifecycle GHG analysis. 30 Department of Energy: National Energy Technology Laboratory. (2009) NETL: Petroleum-Based Fuels Life Cycle Greenhouse Gas Analysis—2005 Baseline Model. www.netl.doe.gov/energy-analyses. 31 Kline Group (2011) Global Wax Industry 2010: Market Analysis and Opportunities. http://www.klinegroup.com/reports/brochures/y635a/brochure.pdf. The results of this analysis are shown on the “Fuel Production” line of Table V.B.-3, and the assumptions and calculations are discussed in more detail in a memo to the docket. 32 Emissions from electricity production used to power the F-T plant is the greatest contributor to the overall fuel production emissions. In addition to emissions from fuel production, there were minor GHG emissions attributable to fuel transport and tailpipe emissions of non-CO 2 GHGs (Table V.B.-3). Overall, renewable diesel and naphtha produced from landfill biogas via this process showed 52% and 51% reductions in GHG emissions, respectively, relative to the diesel or gasoline baseline (Table V.B.-3). These fuels would therefore qualify as advanced biofuels but not qualify as cellulosic biofuels. However, if the facility produced roughly 15% of its process electricity internally, using either waste heat from the reaction or combustion of unreacted chemicals, emissions from purchased electricity would drop enough to reach the 60% GHG reduction threshold, qualifying these fuels as cellulosic. Because emissions from production of these biofuels (without internal production of electricity) fall so close to the 50% threshold to qualify as advanced biofuels, the assumptions used to make the calculations are especially important and could potentially change the classification of these fuels. Accordingly, we request comments about the assumptions and values used in the calculations, which are detailed in a memo to the docket. 33 In particular, we request comment about the estimate for the on-site GHG emissions at the Fischer-Tropsch facility. Data regarding fugitive emissions from Fischer-Tropsch facilities using methane as a feedstock appear to be limited, however, the GREET model assumed a loss factor of 1.0000 for the production of F-T diesel, indicating their estimate that no methane is lost during this process. Several studies mentioned emissions from the steam methane reforming of natural gas to produce hydrogen, and we assumed emissions would be similar from a Fischer-Tropsch facility using steam methane reforming. Two of these studies 34 35 found or estimated that losses of methane from such facilities were negligible, agreeing with the GREET estimate. Accordingly, we assumed no emissions of methane from F-T facilities. However, another study 36 estimated losses of 0.125% of the natural gas processed. Using this last value, the GHG emissions reductions for renewable diesel and naphtha would decrease to 49% for both fuels, meaning that the biofuels would no longer qualify as advanced fuels. We request comments and information about our estimates of fugitive emissions from Fischer-Tropsch facilities. 32 “Support for Cellulosic Determination for Landfill Biogas and Summary of Lifecycle Analysis Assumptions and Calculations for Biofuels Produced from Landfill Biogas,” which has been placed in docket EPA-HQ-2012-0401. 33 “Support for Cellulosic Determination for Landfill Biogas and Summary of Lifecycle Analysis Assumptions and Calculations for Biofuels Produced from Landfill Biogas,” which has been placed in docket EPA-HQ-2012-0401. 34 Skone, T.J. and Gerdes, K. (2008) NETL: Development of Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels. http://www.netl.doe.gov/energy-analyses/pubs/NETL%20LCA%20Petroleum-Based%20Fuels%20Nov%202008.pdf. 35 Spath, P.M. and Mann, M.K. (2001) Lifecycle Assessment of Hydrogen Production via Natural Gas Steam Reforming. NREL Technical Report NREL/TP-570-27637, http://www.nrel.gov/docs/fy01osti/27637.pdf. 36 Contadini, J.F., Diniz, C.V., Sperling, D., and Moore, R.M. (2000) Hydrogen production plants: emissions and thermal efficiency analysis. ITS-Davis. Presented at the Second International Symposium on Technological and Environmental Topics in Transports, October 26-27, 2000. Milan, Italy. Publication No. UCD-ITS-RR-00-16. Table V.B.-3—Total GHG Emissions for Renewable Diesel and Naphtha Produced From Landfill Biogas and Compared to the Appropriate Petroleum Baseline Lifecycle stage GHG emissions (kg CO 2 -eq/mmBtu) Biofuels Renewable diesel Naphtha Petroleum baselines 2005 diesel baseline 2005 gasoline baseline Fuel Production 44 44 18 19 Fuel Transport 1 2 * * Tailpipe Emissions 1 2 79 79 Total Emissions 47 48 97 98 % Change from Petroleum Baseline −52% −51% * Emissions included in fuel production stage. For this lifecycle analysis, we have only examined a facility that does not upgrade its wax and therefore produces wax as a co-product. It is likely that other facilities may produce F-T renewable diesel and naphtha by a process that does involve upgrading waxes to increase the yield of the liquid fuels. Accordingly, we used assessments from other analyses of theoretical F-T 37 or steam methane reforming 38 plants using wax upgrading to estimate the lifecycle GHG emissions from such products. Based on this analysis (not shown), these facilities should theoretically have GHG emissions that are as low as or lower than those calculated above. For this reason, we believe that the lifecycle analysis shown above is a reasonable, if slightly conservative, 39 representation of expected landfill biogas-to-liquids projects. We accordingly classify all renewable diesel and naphtha produced via the F-T process from landfill biogas as advanced biofuel. 37 Swanson, R.M., Satrio, J.A., Brown, R.C., Platon, A., and Hsu, D.D. (2010) Techno-Economic Analysis of Biofuels Production Based on Gasification. NREL Technical Report NREL/TP-6A20-46587, http://www.nrel.gov/docs/fy11osti/46587.pdf. 38 Skone, T.J. and Gerdes, K. (2008) NETL: Development of Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels. http://www.netl.doe.gov/energy-analyses/pubs/NETL%20LCA%20Petroleum-Based%20Fuels%20Nov%202008.pdf. 39 Emissions estimates are conservatively high. The lifecycle analysis for these fuels considered that the renewable diesel product produced from the Fischer-Tropsch process would be used as conventional diesel fuel. EPA does not have sufficient information to evaluate the lifecycle greenhouse gas emissions for jet fuel or heating oil produced from landfill biogas using the Fischer-Tropsch process. Because the lifecycle analysis results for this process fell so close to the threshold for advanced biofuels, in this pathway, we are proposing to only allow renewable diesel for use as conventional diesel fuel to qualify under the RFS program. We invite comments and supporting data about whether we should also allow jet fuel and heating oil produced from landfill biogas to qualify. Our lifecycle analysis showed that if the evaluated facility meets approximately 15% of its electricity demand with internally produced electricity from eligible sources, it will meet the 60% threshold to qualify as cellulosic. Because other facilities are likely to be somewhat different, and because this analysis relies on a number of assumptions, we are using a slightly more conservative threshold of 20% of electrical generation. Accordingly, we are proposing that if a biogas-to-liquids facility produces at least 20 percent of its process electricity internally as discussed above, these biofuels will qualify as cellulosic. These requirements are discussed in greater length in Section C.4. “ Changes Applicable to Process Electricity Production Requirement for the Biogas- Derived Cellulosic Diesel and Naphtha Pathways” below. Facilities that can supply data that demonstrate they meet the 60% GHG emissions reduction threshold without production of 20% electricity are welcome to petition the EPA individually under section 80.1416. EPA invites comment and data on the GHG emissions associated with landfill biogas renewable fuel pathways. We also welcome comment on the methodology and assumptions underlying this analysis. We do not at this point have sufficient information to evaluate the lifecycle greenhouse gas emissions for production of renewable electricity or renewable diesel and naphtha from biogas from waste treatment plants or waste digesters. Accordingly, we invite comments providing information about these potential pathways. C. Proposed Regulatory Amendments Related to Biogas 1. Changes Applicable to the Revised CNG/LNG Pathway From Biogas In the existing RFS2 regulations, an approved fuel pathway in Table 1 to section 80.1426(f)(1) allows biogas from landfill gas, manure digesters or sewage treatment plants to qualify as an advanced biofuel and generate a D code of 5 for the biofuel produced under the RFS2 program. Since the promulgation of the final rule, we have received many requests about what fuel qualifies under this pathway, including: (1) The renewable fuel type that is qualified under the term “biogas,” (2) what are the eligible sources of biogas, (3) what company along the production chain of biogas from generation to end user is considered the producer that qualifies to register under this pathway and generate RINs, and (4) what are the contract requirements to track the biogas from generation to end use. In response, EPA is proposing in this rulemaking to amend the existing biogas pathway in Table 1 to section 80.1426(f) by changing the renewable fuel type in the pathway from “biogas” to “renewable compressed natural gas (renewable CNG) and renewable liquefied natural gas (renewable LNG)” and to replace the feedstock type of “landfills, manure digesters or sewage waste treatment plants” with “biogas from landfills, waste treatment plants or waste digesters.” We are also proposing to revise the definition of biogas and add definitions for CNG and LNG to section 1401 to provide additional clarity. In addition, we are proposing to revise and add new contracting, registration, reporting and recordkeeping requirements along the production chain. Furthermore, we are specifying which company along the production chain is considered the “producer” and eligible to generate RINs under the RFS2 program. These proposed compliance requirements are applicable to this revised CNG/LNG pathway, and all the newly proposed pathways for renewable fuels produced from landfill gas in this rulemaking. The details of the proposed new requirements for contract, registration, reporting and recordkeeping are discussed below in the section titled “Changes Applicable to All Biogas-Related Pathways for RIN Generation.” The existing biogas pathway in Table 1 to section 80.1426(f) refers to “biogas” as the renewable fuel type and “landfills, manure digesters and sewage waste treatment plants” as the feedstock. Companies have raised questions whether the term “biogas” in this pathway could refer to the unprocessed or raw gas from the landfills, manure digesters or sewage treatment plants, or processed “biogas” that has been upgraded and could be used directly for transportation fuel or as an ingredient in the production of transportation fuel or as an energy source used in the production of transportation fuel, or other fuel types that can be produced from the raw biogas either through a physical or chemical process (such as CNG, LNG, renewable electricity, renewable diesel or naphtha). The companies further inquire if the various forms of biogas discussed above could qualify under this pathway, and therefore be eligible for RIN generation under the RFS2 program. We agree that the term “biogas” in this pathway is used broadly in the industry to refer to various raw and processed forms of the biogas from various sources. However, under the existing requirements in sections 80.1426(f)(10) and (11), only biogas that is used for transportation fuel can qualify as renewable fuel for RIN generation under the RFS2 program. We believe the stipulations in sections 80.1426(f)(10) and (11) are clear that biogas used for non-transportation fuel purposes, such as an energy source for providing process heat would not qualify under this biogas pathway for RIN generation. Similarly, raw biogas would also not qualify under this pathway since unprocessed biogas cannot be used as transportation fuel. With regard to the fuel types that can be produced from the raw biogas such as CNG, LNG, renewable electricity, renewable diesel, or naphtha, the pathway determinations for the final rule did not account for all factors relevant for the additional fuel types such as renewable electricity, renewable diesel or naphtha produced from the raw biogas through a chemical process. Therefore, renewable electricity, renewable diesel and naphtha produced from biogas do not qualify under the existing pathway. 40 For CNG and LNG, we concluded that these types of fuels were close enough to the physical molecules of biogas since these fuels only go through a physical process in which the biogas is compressed or liquefied, and that because CNG and LNG can be used directly for transportation purposes, thus meeting the provisions in sections 80.1426(f)(10) and (11), we concluded that CNG and LNG could qualify under the existing pathway. For the reasons discussed above, we are proposing to amend the existing biogas pathway to clearly state that only CNG and LNG produced from biogas from landfills, waste treatment plants and waste digesters, and used as transportation fuel, qualify as a cellulosic or advanced biofuel for RIN generation under the RFS2 program. 40 For this rulemaking, we conducted lifecycle analysis for renewable electricity, renewable diesel, naphtha produced from landfill gas, and are proposing new fuel pathways to Table 1 to Section 80.1426 for these fuel types. Please see section titled, “Lifecycle Greenhouse Gas Emissions Analysis for Renewable Electricity, Renewable Diesel and Naphtha Produced from Landfill Biogas” for the lifecycle analysis discussion in this rulemaking. The current regulations provide a pathway for biogas produced from a bio-digester which uses manure. We are also proposing to expand the type of materials that may be used to produce CNG/LNG in a digester to include animal wastes, biogenic waste oils/fats/greases, separated food and yard wastes, and crop residues. These feedstock sources are already eligible in the existing rules pathways and therefore should reasonably be added to the bio-digester pathway. We are doing so in response to a petition request to generate RINs from biogas which is produced from bio-feedstock sources in addition to the already allowed manure, either individually or in combination with manure in a bio-digester. As with other LCA pathways using these materials, EPA is proposing to assume these waste materials do not have emissions associated with feedstock production, and therefore qualify as cellulosic or advanced renewable fuels when used to produce CNG/LNG. To provide improvement for this revised pathway, we are proposing to revise the definition of biogas and add new definitions for renewable CNG and renewable LNG to section 80.1401 to read as follows: We are proposing Biogas would mean a mixture of hydrocarbons that is a gas at 60 degrees Fahrenheit and 1 atmosphere of pressure that is produced through the conversion of organic matter. We are also proposing that Biogas would include landfill gas, gas from waste digesters, and gas from waste treatment plants. Waste digesters would include digesters processing animal wastes, biogenic waste oils/fats/greases, separated food and yard wastes, and crop residues. Waste treatment plants would include wastewater treatment plants and publicly owned treatment works. We are proposing that Renewable compressed natural gas (“renewable CNG”) would mean biogas that is processed to the standards of pipeline natural gas as defined in 40 CFR 72.2 and that is compressed to pressures up to 3600 psi. We are also proposing that only renewable CNG that qualifies as renewable fuel and is used for transportation fuel can generate RINs. We are proposing that Renewable liquefied natural gas (“renewable LNG”) would mean biogas that is processed to the standards of pipeline natural gas as defined in 40 CFR 72.2 and that goes through the process of liquefaction in which the biogas is cooled below its boiling point and weighs less than half the weight of water so it will float if spilled on water. We are also proposing that only renewable LNG that qualifies as renewable fuel and is used for transportation fuel can generate RINs. 2. New Registration (Contract Requirements) for Renewable Electricity and Fuels Produced From Biogas That Qualify as Renewable Fuel and That Are Registered for RIN Generation The regulations as currently written allow a producer of biogas or renewable electricity 41 that qualifies as renewable fuel and has an approved fuel pathway in Table 1 of section 1426(f)(1) to register and generate RINs for the volume it produces under the RFS2 program. We modified the existing regulations to state that biogas is the feedstock used to produce renewable fuel, as described above. The revised regulations in sections 1426(f)(10) and (11) detail the requirements for distribution and tracking for renewable electricity and biogas used to produce fuel that qualifies as renewable fuel that can either be distributed in a dedicated pipeline or transmission line or distributed in a shared pipeline or power grid system. The purpose of these requirements is to provide EPA assurance and verification that once the biogas or renewable electricity is put into a dedicated or shared distribution system that in fact an equivalent volume of biogas or renewable electricity will be used for transportation fuel, and for no other purposes. The requirements are also meant to address concerns of double counting of the biogas or renewable electricity, especially in situations that the biogas or renewable electricity is placed in or loaded onto shared distribution systems that contain gas or electricity from non-renewable biomass sources. EPA intended to require producers to submit the information and contract requirements in sections 1426(f)(10) and (11) as part of the registration requirements for renewable electricity and renewable fuels produced from biogas that are used for transportation 42 fuel, but had not done so in the prior rulemakings. Therefore, as a natural outgrowth of the regulations for implementation and compliance purposes, we are proposing in this rulemaking to incorporate the requirements in sections 1426(f)(10) and (11) as part of registration requirements for producers of renewable electricity and renewable fuels produced from biogas that qualify as renewable fuel under the regulations under section 1450(b)(1)(iv)(C). 41 EPA notes that currently, producers of renewable electricity that may qualify as a renewable fuel cannot register and generate RINs because there is no approved pathway in Table 1 for renewable electricity from any approved feedstock. But in the event that an approved pathway for renewable electricity is added to Table 1, EPA notes there are existing requirements such as tracking and distribution requirements recordkeeping and reporting that are applicable for the registration of renewable electricity for RIN generation. 42 Distribution and registration requirements for biogas used as process heat, and not for RIN generation as renewable fuel is detailed in Section 1426(f)(12) and 1450(b)(1)(iv), respectively. Section 1426(f)(11)(ii) of the regulations requires that, in order for renewable fuel made from biogas withdrawn from a commercial distribution system for use as a transportation fuel to generate RINs, the biogas introduced into the system must have been added to a common carrier pipeline. We propose to add a similar provision to section 1426(f)(11)(i) for renewable electricity, requiring a company to load the renewable electricity to a power grid shared by the second company that withdraws the electricity, such that the two companies must be physically connected to the same grid or located within the same area. EPA is requesting comments about whether the other existing requirements in sections 1426(f)(10) and (11) for renewable electricity and renewable fuels from biogas used for transportation fuel are sufficient to provide assurance and verification for the following situations. First, do the proposed requirements provide assurance and verification that the same amount of biogas or renewable electricity is in fact delivered to the renewable fuel producer or end user who will actually use the biogas or renewable electricity for transportation purposes? If the proposed requirements are not sufficient, what alternative requirements should be considered? Second, are the proposed requirements sufficient to ensure that double counting does not occur, e.g., to ensure that the biogas or renewable electricity once it is loaded into a shared pipeline or power grid is not sold to multiple clients or for purposes other than for transportation purposes? Similarly, if the proposed requirements are not sufficient, what alternative requirements could be considered to ensure double counting does not occur? 3. Changes Applicable to All Biogas Related Pathways for RIN Generation As discussed above, we have had many inquiries related to the “biogas” pathway, specifically regarding contract requirements for tracking the biogas through the distribution system and regarding what company along the production chain is considered the “producer” and eligible to generate RINs under the RFS2 program. In this rulemaking, we are proposing to revise and add new requirements for contracts to track the biogas as it moves into and out of the distribution system, as well as provisions on registration, reporting and recordkeeping. These proposed amended requirements are applicable to all pathways related to biogas that are eligible for RIN generation that are existing or proposed in this rulemaking. In response to the question of what company is considered the producer of renewable fuel and eligible to generate RINs under the RFS program, we propose to clarify who is the “producer” for renewable CNG/LNG and renewable electricity. We propose that the “producer” of renewable CNG/LNG is the company that compresses or liquefies the gas and distributes the CNG/LNG for transportation fuel, and for renewable electricity, the “producer” is the company that distributes the electricity for use as transportation fuel. There are two registration situations that this clarification will address: (1) The owner/operator of a landfill collects biogas and processes it to a qualifying renewable CNG/LNG/electricity for transportation use and distributes on site and (2) the owner/operator of a landfill collects biogas and it is processed into a qualifying renewable CNG/LNG/electricity for transportation use by a contracted third party and distributed by this third party. The party that converts the biogas to renewable CNG/LNG/electricity and distributes for use as a transportation fuel is responsible for RIN generation. Under the first scenario, the registration package, including the engineering review, would cover the biogas source (landfill, waste digester, etc.) as well as the distribution that is occurring on site. Under the the second scenario, the registration package, including engineering review, would cover the biogas source (landfill, waste digester, etc.) the pipeline (common carrier or dedicated) and each distribution facility. By requiring the party that is responsible for conversion and distribution to register as the RIN generator, we can prevent RINs from being generated for a batch or renewable CNG/LNG/electricity prior to use as a qualifying transportation fuel. For any of the fuels, the company designated as the “producer” will be required to register under the RFS2 program. We seek comment on our proposed definition of producer regarding renewable CNG/LNG and renewable electricity. We acknowledge that the process train from raw biogas to the final transportation fuel is complex, and may include many companies and processing steps from the point when the raw biogas is withdrawn from its source (such as landfills, waste digesters, waste treatment plants), processed and converted into biofuel and distributed to consumers. Alternatively, the fuel may be cleaned at a biogas facility to pipeline quality specifications for distribution, and then withdrawn from the commercial pipeline to be processed further at another production facility into renewable CNG/LNG or renewable electricity. Due to the complexity of the many entities potentially involved in this process train, we are proposing that the company deemed as the “producer” under the qualifications described above also be responsible for providing all the required information and supporting documentation in their registration, reporting and recordkeeping to track and verify the information from point of extraction of the raw biogas from its original source, and all the processing steps and distribution in between, to the last step where the actual fuel is used for transportation purposes. In the engineering review report required for registration, the producer must include documentation that the professional engineer performed site visits at each production facility, including the biogas facility and the facility that produces the final fuel (if these are not the same facility). The producer must also review and verify all related supporting documents such as design documents, calculations, regulatory permits, and contracts between facilities that track the raw biogas from the point of withdrawal from its source, the various injection/withdraw points into the distribution pipeline, the various production facilities, and the final step for use as transportation fuel. We believe these requirements will ensure that producers will perform due diligence that the fuel for which they generate RINs under the RFS2 program are in compliance with all the regulatory requirements for renewable fuel. The proposed registration, reporting and recordkeeping requirements are in sections 80.1426(f), 80.1450, 80.1451 and 80.1454 in this rulemaking. Additional changes regarding the contract requirements for distribution of the biogas in shared commercial pipelines are discussed below, and can be located in sections 80.1426(f)(10), (11), and (13). 4. Changes Applicable To Process Electricity Production Requirement for the Biogas-Derived Cellulosic Diesel and Naphtha Pathways In this proposed rulemaking, EPA conducted greenhouse gas (GHG) lifecycle analysis for various renewable fuels produced from landfill gas as new or revised advanced and cellulosic biofuel pathways that will be added to Table 1 to section 80.1426(f). 43 For some of these pathways, we are proposing to add various registration, recordkeeping and reporting requirements to the regulations to ensure that the facilities using these pathways meet the parameters stipulated in the lifecycle analysis. The additional registration, recordkeeping and reporting requirements are discussed in detail below. 43 Refer to preamble discussion for these various biogas pathways in section titled, “Lifecycle Greenhouse Gas Emissions Analysis for Renewable Electricity, Renewable Diesel and Naphtha Produced from Landfill Biogas.” For the proposed fuel pathways for cellulosic diesel and cellulosic naphtha produced from landfill gas, we are proposing to require the renewable fuel production facility to produce a minimum of 20 percent of the process electricity used at the facility on a calendar year basis, from raw landfill gas, waste heat from the production process, unconverted syngas from the F-T process, fuel gas from the hydroprocessing or combined heat and power (CHP) units that use non-fossil fuel based gas or other renewable sources. We propose that if less than 20 percent (on an annual average basis) of process energy comes from one of these alternative sources, then no cellulosic RINs can be generated for that year. For the renewable fuel production facility applying to use the proposed fuel pathway with the requirement to internally produce at least 20 percent of the total amount of process electricity used at its facility, we are proposing the facility submit to EPA the information described below to demonstrate compliance with this requirement. For registration purposes, we are proposing that producers submit the following additional information in the process fuel supply plan that is currently required as part of the registration process (estimated summaries are to be reported on an annual/calendar year basis): —Estimated amount of total electricity used at the facility —Estimated amount of total electricity purchased for the facility —Estimated amount of total renewable electricity produced on-site, including the source of the energy and the equipment and/or process used to generate the renewable electricity —Calculation that verifies the facility meets the specified 20 percent minimum electricity production requirement based on the reported total amount of electricity used at the facility, total amount of electricity purchased, and total amount of renewable electricity produced For reporting purposes, we are proposing for producers to submit the following additional information as part of their existing quarterly and annual reporting obligations (reported amounts should be provided as monthly summaries on an annual/calendar year basis, and must be obtained from a utility meter that is continuously measured): —Actual total amount of electricity used at the facility —Actual total amount of electricity purchased for the facility —Actual amount of total renewable electricity produced on-site, including source of energy and the equipment or process used to generate the renewable electricity —Calculation that verifies the facility meets the specified 20 percent minimum electricity production requirement based on the reported total amount of electricity used at the facility, total amount of fossil-fuel based electricity purchased, and total amount of renewable electricity produced For recordkeeping purposes, we are proposing that producers retain the additional information, calculations and supporting documents required for registration and reporting as discussed above. The regulatory requirements for registration, reporting and recordkeeping as discussed in this proposed rulemaking can be located in the following applicable regulatory sections 80.1450, 80.1451 and 80.1454, respectively. D. Amendment to the Definition of “Crop Residue” and Definition of a Pathway for Corn Kernel Fiber We propose to amend the definition of “crop residue” so that this category includes only feedstock sources that are determined by EPA would not result in a significant increase in direct or indirect GHG emissions. “Crop residue” is the biomass left over from the harvesting or processing of planted crops from existing agricultural land and any biomass removed from existing agricultural land that facilitates crop management (including biomass removed from such lands in relation to invasive species control or fire management), whether or not the biomass includes any portion of a crop or crop plant. Biomass is considered crop residue only if the use of that biomass for the production of renewable fuel has no significant impact on demand for the feedstock crop, products produced from that feedstock crop, and all substitutes for the crop and its products including the residue, nor any other impact that would result in a significant increase in direct or indirect GHG emissions. EPA is amending the definition of “crop residue” to confirm the meaning of the term “left over” in the text of this definition. The phrase “left over” in our original definition of “crop residue” is meant to indicate that the use of a residue as a biofuel feedstock should not increase demand for the crop it is derived from, should not induce further crop production, and should not result in additional direct or indirect GHG emissions. The residue must come from crop production or processing for some other primary purpose (e.g., refined sugar, corn starch ethanol), such that the crop residue is not the reason the crop was planted. The residue must also come from existing agricultural land, the exact definition of which is laid out in our current regulations that define “renewable biomass”. 44 Further, the residue should generally not have a significant market in its own right, to the extent that removing it from that market to produce biofuels instead will result in increased GHG emissions. EPA is seeking comments on this revision to the crop residue definition. EPA invites all comments regarding this revision, but specifically invites comments regarding the potential for the revision to create a significant shift in direct or indirect GHG emissions and what ought to constitute a “significant” increase or decrease in GHG emissions in the context of this definition. 44 See specifically § 80.1401 Definitions. EPA has previously identified several potential feedstocks that we believe meet the criteria of crop residue. Table IV.D.-1 lists feedstocks which may fit the definition of crop residue. Most of these feedstocks were discussed in the final RFS2 rulemaking. For example, EPA analyzed the agricultural sector GHG emissions of using corn stover for biofuels in the final RFS2, and found that fuel produced from this feedstock met the 60% GHG reduction threshold for cellulosic biofuels. Since the direct and indirect impacts of citrus residue, rice straw, and wheat straw removal were expected to be similar to corn stover, EPA also applied the land use change impacts associated with corn stover to citrus residue, rice straw, and wheat straw. Based on that analysis, EPA found that fuels produced from citrus residues, rice straw, and wheat straw also met the 60% reduction threshold. EPA further determined that fuels produced from materials left over after the processing of a crop into a useable resource had land use impacts sufficiently similar to agricultural residues to also meet the 60% threshold. EPA specifically cited bagasse left over from sugarcane processing as an example of this type of residue. EPA is seeking comment on whether the feedstocks on this list should be considered crop residues, if these feedstocks would have similar direct and indirect impacts as corn stover, and whether additional feedstocks should also be included in this list. Table IV.D.-1—Feedstocks That May Qualify as Crop Residue Feedstock D Code Sugarcane Bagasse D-3 Cellulosic biofuel. Corn Kernel Fiber (excluding the corn starch component) D-3 Cellulosic biofuel. Corn Stover D-3 Cellulosic biofuel. Citrus Residue D-3 Cellulosic biofuel. Rice Straw D-3 Cellulosic biofuel. Wheat Straw D-3 Cellulosic biofuel. While EPA believes that, under current conditions, generation of RINs for batches of renewable fuel produced from the feedstocks listed in Table IV.D.-1 above would not result in a significant increase in direct or indirect GHG emissions, we also acknowledge the potential for this assessment to change in the future based on unforeseeable factors. For example, some new use for one of these products could be developed which would change our assessment that the feedstock has no significant market in its own right. Further, it is possible that, at some point in the future, large enough quantities of renewable fuel could be produced from one of these fuels to create demand pull for the feedstock, potentially altering the behavior of producers of the residue and leading to significant increases in direct or indirect GHG emissions. To our knowledge, this is not currently the case for any of the feedstocks listed above. However, EPA will continue to monitor RIN generation from fuel produced using each of these feedstocks and the general use of these feedstocks in the marketplace. We further reserve the right to revisit the status of any feedstock that we have determined qualifies under the crop residue pathway. Should any feedstock qualifying as a crop residue be used to generate significant quantities of ethanol in the future, or should a significant market emerge for the product such that there is demand pull for it in excess of the demand pull for the planted crop from which it is a derived byproduct, we will revisit whether that feedstock should remain under the crop residue pathway or be subjected to further scrutiny. EPA is seeking comment on this approach and on the potential for significant demand pull to emerge for the feedstocks we are proposing to consider as crop residues. We also propose that this definition of “crop residue” includes corn kernel fiber. Corn kernel fiber is not specifically mentioned as a type of crop residue under the Renewable Fuel Standard (RFS2) regulations. Per the RFS2 definition of “crop residue”, EPA must evaluate whether corn kernel fiber is “left over from the harvesting or processing of planted crops” and that it has no “impact that would result in a significant increase in direct or indirect GHG emissions” for this feedstock to qualify as a residue. One additional consideration in the classification of corn kernel as a crop residue is the fact that some amount of corn starch might still adhere to the corn kernel after separation. The percentage of contamination will vary, but as much as 20% of the final fuel could be derived from corn starch. By definition, corn starch ethanol can only qualify as a renewable fuel, not as an advanced fuel. However, our current regulations state that “producers and importers may disregard any incidental, de minimis feedstock contaminants that are impractical to remove and are related to customary feedstock production and transport”. 45 Therefore, EPA is seeking comment on whether the definition of crop residue should be amended to explicitly exclude the corn starch component. 45 See specifically § 80.1426(f)(1). EPA also invites comment on how RINs should be allocated for ethanol derived from corn fiber. EPA has existing regulations that define procedures for generating RINs from batches of fuel that contain multiple feedstocks, including feedstocks that generate RINs of different D codes. 46 We believe that these regulations provide sufficient guidance to producers and importers regarding how to assign RINs to batches of renewable fuel that can be described by two or more pathways (e.g., corn starch ethanol and corn kernel fiber ethanol). However, we invite comment on the sufficiency of these regulations with regards to the assignment of RINs to coprocessed batches of corn starch ethanol and corn kernel fiber ethanol, including whether producers have the technological capability to adequately demonstrate volume produced under each pathway. 46 See specifically § 80.1426(f)(3). To determine whether the use of corn kernel fiber to produce ethanol would lead to increased direct or indirect GHG emissions, EPA conducted a detailed assessment of the two major potential sources of emissions from this feedstock, namely effects on feed markets and effects on demand for corn. The proposed method of acquiring corn kernel fiber is to extract it from matter that is otherwise converted to dried distillers grains (DDG) during the dry mill corn ethanol process. Consequently, this analysis relied significantly on the assessment of corn starch ethanol-derived DDG that was conducted for the RFS2 final rule, adjusting the analysis to account for the extraction of fiber from this product. The analysis also drew substantially on the available scientific literature on low fiber DDG (LF-DDG), as well as the expertise of the U.S. Department of Agriculture. Potential producers also submitted important data to EPA that helped determine whether producing cellulosic ethanol from corn kernel fiber would result in a significant increase in GHG emissions. This included a full nutritional analysis of LF-DDG for swine, poultry, and cattle. EPA found that extracting the fiber from corn matter used to produce standard DDG would not have a significant effect on feed markets. Processors who extract the fiber from corn produce a feed product known as LF-DDG, as opposed to standard DDG which retains the fiber. The scientific literature on LF-DDG animal nutrition has found that this product has at least equal, and perhaps even slightly superior, nutritional value for swine and poultry compared to standard DDG. 47 This means that, even though the physical volume of the DDG produced by ethanol plants using corn kernel fiber extraction technology will be somewhat smaller, its nutritional content for swine and poultry will be equivalent to or greater than their output without fiber extraction. 47 See, e.g., Kim, E.J., C.M. Parsons, R. Srinivasan, and V. Singh. 2010. Nutritional composition, nitrogen-corrected true metabolizable energy, and amino acid digestibilities of new corn distillers dried grains with solubles produced by new fractionation processes. Poultry Science 89, p. 44, available on the docket for this rulemaking. See also additional studies cited within Kim et al 2010. Conversely, LF-DDF is an inferior feed for cattle compared to standard DDG, since ruminants benefit from ingesting corn fiber in DDG. 48 Therefore, EPA expects swine and poultry producers to absorb the supply of LF-DDG, while the cattle and dairy industry will continue to consume standard DDG. With this dynamic in place, fiber extraction from DDG should not significantly affect feed markets, since there will be no reduction in the overall supply of DDG in terms of nutritional content nor will there be any impact on aggregate demand for other animal feed sources. 48 See Shurson, G.C. 2006. The Value of High-Protein Distillers Coproducts in Swine Feeds. Distillers Grains Quarterly, First Quarter, p. 22, available on the docket for this rulemaking. If enough corn ethanol producers adopt fiber extraction technology, LF-DDG could saturate swine and poultry demand and spill over into dairy and cattle feed markets. If a situation arises where LF-DDG begin to replace standard DDG in cattle markets, this could lead to an increase in feed demand, most likely in the form of increased demand for fiber supplements in dairy and cattle feed. This could cause an increase in GHG emissions. If swine and poultry demand for LF-DDG becomes saturated, demand for standard DDG in the cattle and dairy industries should create sufficient market incentives for the remaining corn starch ethanol producers to decide against adopting corn fiber ethanol production. EPA believes this will prevent a situation where there is insufficient supply of standard DDG in the cattle and dairy industries. However, as noted above, EPA reserves the right to reexamine corn kernel fiber as a feedstock in the future. EPA's analysis indicates that producing cellulosic ethanol from corn kernel fiber is unlikely to increase overall demand for corn. In order to meet the definition of a crop residue, the source of corn kernel fiber must be a crop processing facility (e.g., a corn starch ethanol plant). A corn kernel fiber ethanol producer cannot purchase whole corn specifically for the generation of corn fiber ethanol and still qualify their feedstock as crop residue. EPA is seeking comment on this analysis. Based on our assessment, EPA proposes that corn kernel fiber would meet the definition of a crop residue, and qualify for Cellulosic Ethanol and Advanced Biofuel (D-codes 3 & 5, respectively) RINs under the RFS2. EPA is seeking comment on whether corn kernel fiber should be considered a crop residue. E. Consideration of Advanced Butanol Pathway 1. Proposed New Pathway EPA is proposing to add a new pathway to Table 1 to section 80.1426 that allows butanol made from corn starch using a combination of advanced technologies to meet the 50% GHG emissions reduction needed to qualify as an advanced renewable fuel. This pathway applies to dry mill fermentation facilities that use natural gas and biogas from an on-site thin stillage anaerobic digester for process energy with combined heat and power (CHP) producing excess electricity of at least 40% of the purchased natural gas energy of the facility (the proposed “advanced butanol pathway”). GEVO Incorporated submitted a petition requesting authorization to generate D-code 5 RINs for fuel produced through the GEVO butanol pathway. A petition is required because the proposed process utilizes a high yield butanol fermentation process that is different from those analyzed as part of the RFS2 corn ethanol pathways, and does not use the approved advanced technologies shown in Table 2 to section 80.1426 of the RFS2 regulations. EPA's evaluation of the lifecycle GHG emissions of the advanced butanol pathway under this petition request is consistent with EISA's applicable requirements, including the definition of lifecycle GHG emissions and threshold evaluation requirements. It was based on information regarding GEVO's production process that was submitted under a claim of Confidential Business Information (CBI) by GEVO on April 11, 2011. The information provided included the mass and energy balances necessary for EPA to evaluate the lifecycle GHG emissions of the advanced butanol pathway. The lifecycle GHG emissions of fuel produced pursuant to the advanced butanol pathway were determined as follows: Feedstock production —The advanced butanol pathway uses corn starch as a feedstock. Corn starch is one of the feedstocks already listed in Table 1 to section 80.1426 of the RFS2 regulations. Since corn starch has already been evaluated as part of the RFS2 final rule, no new feedstock production modeling was required. The FASOM and FAPRI models were used to analyze the GHG impacts of the feedstock production portion of the fuel's lifecycle. The same FASOM and FAPRI results representing the emissions from an increase in corn production that were generated as part of the RFS2 final rule analysis of the existing corn butanol pathways were used in this analysis of the advanced butanol pathway. These results represent agriculture/feedstock production emissions for a certain quantity of corn produced. For the RFS2 analysis, this was roughly 960 million bushels of corn used to produce 2.6 billion gallons of fuel. We have calculated GHG emissions from feedstock production for that amount of corn. EPA does not believe the advanced butanol process for converting corn into butanol will materially affect the total amount of corn used for biofuels and modeled as part of the RFS2 final rule. Based on information provided by industry, the technologies to produce corn butanol are primarily being targeted at retrofitting existing corn ethanol facilities, where the infrastructure to produce renewable fuels already exists and the capital expenditures would be relatively small. Therefore, the existing agricultural sector modeling analyses for corn as a feedstock remain valid for use in estimating the lifecycle impact of renewable fuel produced using the advanced butanol pathway. The Agency is seeking comment on whether there is any research to suggest that converting corn into an advanced butanol pathway would materially affect the total amount of corn used. GEVO provided, as part of the information claimed CBI, their process yield in terms of gallons of fuel produced per bushel of corn. Based on the data, GEVO's process yield is slightly more efficient than the pathways modeled as part of the RFS2 rulemaking. Therefore, compared to the corn butanol pathways already analyzed, the GEVO process results in 0.93% more Btus of fuel produced for the same amount of corn feedstock. Fuel production —The fuel production method included in this advanced butanol pathway involves the production of butanol from corn starch in a dry mill. The amount and type of energy used in this analysis is different than production methods that were analyzed under the final rule. While there were slight differences in the total amount of natural gas and electricity used in this analysis, the main difference was the use of biogas and production of excess electricity. To analyze the GHG impacts of the advanced butanol pathway, EPA utilized the same approach that was used to determine the impacts of processes in the RFS2 corn butanol pathways. The amount and type of energy used was taken from GEVO's mass balance & energy balance submitted to EPA. GEVO submitted energy data on natural gas and biogas (in Btus) and electricity (in kWhs) inputs, as well as gallons of fuel produced. Biogas and natural gas are used in combination, while the RFS2 corn butanol analyses only considered natural gas or biogas used independently, not in combination. [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2013-12714. Public record. Not legal advice.