Regulation of Fuels and Fuel Additives: RFS Pathways II and Technical Amendments to the RFS 2 Standards, 36041-36078 [2013-12714]

Download as PDF Vol. 78 Friday, No. 115 June 14, 2013 Part II Environmental Protection Agency mstockstill on DSK4VPTVN1PROD with PROPOSALS2 40 CFR Part 80 Regulation of Fuels and Fuel Additives: RFS Pathways II and Technical Amendments to the RFS 2 Standards; Proposed Rule VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 PO 00000 Frm 00001 Fmt 4717 Sfmt 4717 E:\FR\FM\14JNP2.SGM 14JNP2 36042 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 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 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 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 18:55 Jun 13, 2013 Jkt 229001 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: • https://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 DATES: Environmental Protection Agency (EPA). ACTION: Notice of Proposed Rulemaking. AGENCY: VerDate Mar<15>2010 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. PO 00000 Frm 00002 Fmt 4701 Sfmt 4702 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 https:// 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 E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 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 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 NAICS Codes a Industry Industry Industry Industry Industry Industry Industry a North ............................................................. ............................................................. ............................................................. ............................................................. ............................................................. ............................................................. ............................................................. SIC Codes b 324110 325193 325199 424690 424710 424720 454319 2911 2869 2869 5169 5171 5172 5989 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: I. Why is EPA taking this action? Category 36043 Examples of potentially regulated parties Petroleum refiners, importers. Ethyl alcohol manufacturers. Other basic organic chemical manufacturers. Chemical and allied products merchant wholesalers. Petroleum bulk stations and terminals. Petroleum and petroleum products merchant wholesalers. Other fuel dealers. American Industry Classification System (NAICS). Industrial Classification (SIC) system code. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 b Standard This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that EPA is now aware could be potentially regulated by this action. Other types of entities not listed in the table could also be regulated. To determine whether your entity is regulated by this action, you should carefully examine the VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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 PO 00000 Frm 00003 Fmt 4701 Sfmt 4702 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 E:\FR\FM\14JNP2.SGM 14JNP2 36044 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules mstockstill on DSK4VPTVN1PROD with PROPOSALS2 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 VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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. PO 00000 Frm 00004 Fmt 4701 Sfmt 4702 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 E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules mstockstill on DSK4VPTVN1PROD with PROPOSALS2 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 36045 TABLE V.A.–1—AVERAGE CELLULOSIC characterizing the different components COMPOSITION OF DIFFERENT TYPES of feedstocks, mainly focused on how the materials could be broken down and OF FEEDSTOCKS4—Continued converted into fuel. There has been work also in defining standardized procedures and test methods for Feedstock type analyzing the different components of biomass; 5 however, the studies Switchgrass .................... 85 considered all employ slightly different Miscanthus ...................... 85 methods. For the purposes of this rule, Other Grasses ................ 81 EPA considered the amount of the Wood and Branches ....... 92 feedstocks that is composed of cellulosic components i.e., how much EPA is proposing to allow 100% of comes from the cellulose, hemicellulose the volume of renewable fuel produced or lignin, as opposed to any other from specific cellulosic feedstock components of the feedstock. There is sources found in Table 1 of section significant variation in the data reported 80.1426 to generate D–3 or D–7 RINs (depending on the type of finished fuel). on feedstock component compositions. The variation is due to a number of However separated food waste, causes, such as measurement separated yard waste, and separated methods,6 7 variety within a generic MSW would continue to be treated as feedstock type, and storage time.8 before, as discussed below. There are three major justifications for this Although there are many factors that determination: (1) There can be contribute to the large variability in significant variation in the amount of assessments of cellulosic content, all cellulosic content in any feedstock, studies confirm that the feedstocks in which varies within a growing season, Table 1 of section 80.1426 have an across samples, and across sites. adjusted cellulosic content of at least Attempting to account for this 70%, with an average content of around variability would impose a significant 85% cellulosic.9 A memorandum to the administrative burden on producers and docket provides more information on EPA; (2) The amount of the final fuel cellulosic terminology, percent that is produced from the cellulosic composition of various feedstocks, and portion of the feedstock is likely to be the variability of different feedstock very high, particularly for fuels components.10 From this data, EPA produced using a biochemical reaction; concludes that each of the qualified (3) EPA has already made previous feedstocks listed in section 80.1426 are determinations in which a single RIN comprised predominantly of cellulose, value was assigned to the fuel produced hemicellulose and lignin. since it came primarily from one source even though it was also produced from 5 See, e.g., the Standard Biomass Analytical incidental amounts of other sources. Procedures developed by the National Renewable This determination is based on the Energy Laboratory, https://www.nrel.gov/biomass/ view that the statutory requirement does analytical_procedures.html. 6 Compositional Analysis of Lignocellulosic not mandate that in all cases the 2. Method Uncertainties, David TABLE V.A.–1—AVERAGE CELLULOSIC renewable fuel must be produced solely Feedstocks. Christopher J. Scarlata, Justin B.W. Templeton, Sluiter, from the cellulosic material in the COMPOSITION OF DIFFERENT TYPES And Edward J. Wolfrum, J. Agric. Food Chem. 2010, renewable biomass. EPA considers the 58, 9054–9062 OF FEEDSTOCKS4 7 Relative standard deviations (RSD) of 5–8% are statutory definition of cellulosic biofuel reported for cellulose, hemicelluloses and lignin to be flexible on this point. Given these Average with the other minor components showing 16–22% adjusted cellulosic factors cited above, the Agency believes Feedstock type RSD. composition this interpretation of ‘‘derived from’’ is 8 Composition of Herbaceous Biomass Feedstocks, (percent) consistent with the Congressional intent DoKyoung Lee, Vance N. Owens, Arvid Boe, Peter Jeranyama, Plant Science Department, South Dakota Crop Residue .................. 90 to require increased use of cellulosic State University, SGINC1–07, June 2007. biofuels while ensuring that the 9 EPA only considered the organic components of program can be implemented in a 1 See Memorandum to Docket, ‘‘Cellulosic the materials when determining cellulosic content. reasonable way. Details on the Content of Various Feedstocks,’’ Docket EPA–HQ– Inorganic materials are not likely to end up in the OAR–2012–0401. variability in feedstocks, characteristics final fuel product and would not contribute to the 2 Peplinski et al. (1992) Physical, chemical and fuel heating content in the event that they remained of the final fuel, previous precedents, dry-mill properties of corn of varying density and in the final fuel. This methodology is consistent and alternative proposals are included breakage susceptibility. Cereal Chemistry, 69(4), with how RINs are determined. In this section, EPA in the following sections. 397–400. refers to this as ‘‘adjusted cellulosic.’’ Adjusted 3 Illinois Soybean Association. Facts and Statistics for the Illinois Soybean Industry. https:// 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. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 Average adjusted cellulosic composition (percent) 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 PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 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. E:\FR\FM\14JNP2.SGM 14JNP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 36046 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 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 biooils 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. Thermochemical 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 VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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 noncellulosic 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 noncellulosic 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 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 11 75 PO 00000 FR 14670, 14706 (March 26, 2010). Frm 00006 Fmt 4701 Sfmt 4702 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 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 noncellulosic 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 12 75 E:\FR\FM\14JNP2.SGM FR at 14706. 14JNP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 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 noncellulosic components of the renewable biomass could be reasonably identified or estimated.13 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 timeconsuming 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. 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. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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 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; precommercial 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. 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 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). 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. PO 00000 Frm 00007 Fmt 4701 Sfmt 4702 36047 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 E:\FR\FM\14JNP2.SGM 14JNP2 36048 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules mstockstill on DSK4VPTVN1PROD with PROPOSALS2 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 VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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 facilityspecific 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 PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 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 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 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 https://www.epa.gov/ climatechange/Downloads/ghgemissions/US-GHGInventory-2013-Main-Text.pdf. E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules § 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: mstockstill on DSK4VPTVN1PROD with PROPOSALS2 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 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. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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. 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 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. https://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 https://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. https://epa.gov/lmop/publicationstools/handbook.html. PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 36049 generated is derived from landfills that flare their gas and another 38% is derived from landfills with gas-toelectricity projects. By mass balance, this suggests that 24% of the landfill methane generated is from landfills that vent their methane. 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-toenergy 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-toenergy projects in place at one point either replaced flaring with a gas-toenergy project or installed a gas-toenergy 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 E:\FR\FM\14JNP2.SGM 14JNP2 36050 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 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. 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 biogasderived electricity rather than grid electricity upon installation of a gas-toenergy 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 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 Electricity generation efficiency ........................................................................................................... Gross electricity production ................................................................................................................. Electricity produced after parasitic losses ........................................................................................... Energy used for blowers ..................................................................................................................... Distribution losses ............................................................................................................................... Net electricity delivered to consumer .................................................................................................. 11700 0.292 0.267 0.014 0.017 0.236 Units Btu/kWh. mmBtu/mmBtu mmBtu/mmBtu mmBtu/mmBtu mmBtu/mmBtu mmBtu/mmBtu biogas. biogas. biogas. biogas. biogas. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 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 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. 24 Argonne National Laboratory (2011) Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation Model (GREET), Version 1 2011, https://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. 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. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 PO 00000 Frm 00010 Fmt 4701 Sfmt 4702 E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 36051 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 GHG emissions Renewable electricity Lifecycle stage kg CO2-eq/ mmBtu electricity 2005 Gasoline baseline kg CO2-eq/ mmBtu fuel equivalent U.S. Average grid electricity kg CO2-eq/ mmBtu fuel kg CO2-eq/ mmBtu electricity 25 ¥13 8 ¥4 ........................ ........................ ........................ ........................ Total Emissions: ....................................................................................... % Change from Gasoline Baseline ................................................................. % Change from Grid Electricity ....................................................................... mstockstill on DSK4VPTVN1PROD with PROPOSALS2 On-site emissions ............................................................................................ Upstream (electricity production for blowers) .................................................. 12 ¥87% ¥94% 4 ¥96% N/A 98 ........................ ........................ 220 ........................ ........................ 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 CO2-eq/mmBtu electricity, or 4 kg CO2-eq/mmBtu fuel equivalent. Compared with the gasoline baseline GHG emissions of 98 kg CO2-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. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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 FischerTropsch (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 coproduct credit for the wax generated. PO 00000 Frm 00011 Fmt 4701 Sfmt 4702 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 coproduct 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. 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 29 Argonne National Laboratory, ‘‘Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation Model (GREET),’’ Version 1 2011, https://greet.es.anl.gov/. 30 Department of Energy: National Energy Technology Laboratory. (2009) NETL: PetroleumBased Fuels Life Cycle Greenhouse Gas Analysis— 2005 Baseline Model. www.netl.doe.gov/energyanalyses. E:\FR\FM\14JNP2.SGM 14JNP2 36052 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 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 coproduct credit disappears but total fuel production emissions decrease to 30 kg CO2-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. 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-CO2 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. TABLE V.B.–3—TOTAL GHG EMISSIONS FOR RENEWABLE DIESEL AND NAPHTHA PRODUCED FROM LANDFILL BIOGAS AND COMPARED TO THE APPROPRIATE PETROLEUM BASELINE GHG emissions (kg CO2-eq/mmBtu) Biofuels Lifecycle stage Renewable diesel Petroleum baselines 2005 diesel baseline Naphtha 2005 gasoline baseline Fuel Production ................................................................................................ Fuel Transport ................................................................................................. Tailpipe Emissions ........................................................................................... 44 1 1 44 2 2 18 * 79 19 * 79 Total Emissions ........................................................................................ % Change from Petroleum Baseline ............................................................... 47 ¥52% 48 ¥51% 97 ........................ 98 ........................ * Emissions included in fuel production stage. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 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 31 Kline Group (2011) Global Wax Industry 2010: Market Analysis and Opportunities. https:// www.klinegroup.com/reports/brochures/y635a/ brochure.pdf. 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 PetroleumBased Fuels. https://www.netl.doe.gov/energyanalyses/pubs/NETL%20LCA%20PetroleumBased%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, https://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. ITSDavis. 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. VerDate Mar<15>2010 20:07 Jun 13, 2013 Jkt 229001 PO 00000 Frm 00012 Fmt 4701 Sfmt 4702 E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules mstockstill on DSK4VPTVN1PROD with PROPOSALS2 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. The lifecycle analysis for these fuels considered that the renewable diesel product produced from the FischerTropsch 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 FischerTropsch 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 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, https://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 PetroleumBased Fuels. https://www.netl.doe.gov/energyanalyses/pubs/NETL%20LCA%20PetroleumBased%20Fuels%20Nov%202008.pdf. 39 Emissions estimates are conservatively high. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 requirements are discussed in greater length in Section C.4. ‘‘Changes Applicable to Process Electricity Production Requirement for the BiogasDerived 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 PO 00000 Frm 00013 Fmt 4701 Sfmt 4702 36053 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 BiogasRelated 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 E:\FR\FM\14JNP2.SGM 14JNP2 36054 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules mstockstill on DSK4VPTVN1PROD with PROPOSALS2 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. The current regulations provide a pathway for biogas produced from a biodigester 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 biodigester 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. 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. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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 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. PO 00000 Frm 00014 Fmt 4701 Sfmt 4702 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). 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 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. E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules mstockstill on DSK4VPTVN1PROD with PROPOSALS2 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 VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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 PO 00000 Frm 00015 Fmt 4701 Sfmt 4702 36055 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. 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 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.’’ E:\FR\FM\14JNP2.SGM 14JNP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 36056 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 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 VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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 PO 00000 Frm 00016 Fmt 4701 Sfmt 4702 ‘‘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. 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 Sugarcane Bagasse. Corn Kernel Fiber (excluding the corn starch component). 44 See E:\FR\FM\14JNP2.SGM D Code D–3 Cellulosic biofuel. D–3 Cellulosic biofuel. specifically § 80.1401 Definitions. 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules TABLE IV.D.–1—FEEDSTOCKS THAT has no ‘‘impact that would result in a MAY QUALIFY AS CROP RESIDUE— significant increase in direct or indirect GHG emissions’’ for this feedstock to Continued Feedstock D Code mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Corn Stover ........... Citrus Residue ...... Rice Straw ............. Wheat Straw ......... D–3 D–3 D–3 D–3 Cellulosic Cellulosic Cellulosic Cellulosic biofuel. biofuel. biofuel. 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 VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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. 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. 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 45 See 46 See PO 00000 specifically § 80.1426(f)(1). specifically § 80.1426(f)(3). Frm 00017 Fmt 4701 Sfmt 4702 36057 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. 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. 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 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. 48 See Shurson, G.C. 2006. The Value of HighProtein Distillers Coproducts in Swine Feeds. Distillers Grains Quarterly, First Quarter, p. 22, available on the docket for this rulemaking. E:\FR\FM\14JNP2.SGM 14JNP2 36058 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 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. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 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 VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 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 PO 00000 Frm 00018 Fmt 4701 Sfmt 4702 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. The emissions from the use of energy were calculated by multiplying the amount of energy by emission factors for fuel production and combustion, based on the same method and factors used in the RFS2 final rulemaking. The emission factors for the different fuel types are from GREET and were based on assumed carbon contents of the different process fuels. One area where EPA is soliciting comments is on the most appropriate energy content assumption to use for butanol (lower heating value). As part of this analysis, EPA used the GREET value for the energy content of butanol, E:\FR\FM\14JNP2.SGM 14JNP2 36059 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules product production which we similarly applied to the advanced butanol production process. Since DDGs impact the agricultural markets, production of DDGs was already included as part of the FASOM and FAPRI modeling already described in the feedstock production section, above. Thus no additional co-product credits for the DDGs are applied for the fuel production stage of the analysis. The advanced butanol production process analyzed here also results in excess electricity production. As per the which is 99,837 Btus per gallon.49 Differences in the measurement of the energy content of butanol can occur for a number of reasons including variations amongst isomers (t-butanol, n-butanol, isobutanol, and sec-butanol), and differences in testing methodologies. EPA is seeking comment on whether there are any reasons why EPA should change its assumptions and use a different energy content of butanol. The RFS2 corn butanol pathways included an estimate for DDGs co- pathway description the process produces excess electricity of at least 40% of the purchased natural gas energy of the facility. The onsite emissions of the electricity production are accounted for in the facility natural gas and biogas use. The co-product credit of the excess electricity is accounted for by assuming the electricity offsets average grid electricity production and results in associated emission reductions. The estimated production emissions from the advanced butanol process are shown below in Table V.F.–1. TABLE V.F.–1—FUEL PRODUCTION EMISSIONS FOR THE ADVANCED BUTANOL PROCESS GEVO isobutanol (g CO2-eq./mmBtu) Fuel production source On-Site Emissions ............................................................................................................................................................... Upstream (natural gas and electricity production) .............................................................................................................. Emissions Credit from Offset Electricity .............................................................................................................................. 15,273 2,424 ¥17,448 Total Fuel Production Emissions ..................................................................................................................................... 249 Fuel and feedstock distribution—We used the same feedstock distribution emissions assumption considered for corn butanol under the RFS2 final rule for the advanced butanol pathway corn feedstock. The fuel type, butanol, and hence the fuel distribution for butanol, was already considered as part of the RFS2 final rule. Therefore, the existing feedstock and fuel distribution lifecycle GHG impacts for corn butanol were applied to the advanced butanol pathway analysis. Use of the fuel—The advanced butanol pathway produces a fuel that was analyzed as part of the RFS2 final rule. Thus, the fuel combustion emissions calculated as part of the RFS2 final rule for butanol were applied to our analysis of the advanced butanol pathway. The advanced butanol fuel was then compared to baseline petroleum gasoline, using the same value for baseline gasoline as in the RFS2 final rule analysis. The results of the analysis indicate that the advance butanol pathway would result in a GHG emissions reduction of 51.3% compared to the gasoline fuel it would replace. Based on our LCA, we are proposing to add a new pathway to Table 1 to section 80.1426 that includes butanol from corn starch using the butanol process described here as an advanced biofuel (D–5 RINs). EPA invites comments on the assumptions used in this analysis. Table V.F.–2 below breaks down by stage the lifecycle GHG emissions for the RFS2 corn butanol pathway, the advanced butanol pathway and the 2005 gasoline baseline. This table demonstrates the contribution of each stage in the fuel pathway and its relative significance in terms of GHG emissions. TABLE V.F.–2—LIFECYCLE GHG EMISSIONS FOR THE ADVANCED BUTANOL PATHWAY, 2022 [Kg CO2-eq./mmBtu] RFS2 corn ethanol, natural gas fired dry mill 63% dry DDGS Fuel type GEVO butanol RFS2 2005 gasoline baseline 4 12 ¥4 32 (21/46) 28 4 1 4 12 ¥4 31 0 4 1 ............................ ............................ ............................ ............................ 19 * 79 Total Emissions, Mean ............................................................................................. % Reduction .................................................................................................................... mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Net Domestic Agriculture (w/o land use change) ............................................................ Net International Agriculture (w/o land use change) ....................................................... Domestic Land Use Change ........................................................................................... International Land Use Change, Mean (Low/High) ......................................................... Fuel Production ................................................................................................................ Fuel and Feedstock Transport ........................................................................................ Tailpipe Emissions ........................................................................................................... 77 (66/91) ¥21% 48 ¥51% 98 ............................ * Emissions included in fuel production stage. Table V.F.–3 lists the proposed DCodes by fuel type (butanol), considering the feedstock (corn starch) and different production process requirements. 49 The GREET value is based on: Guibet, J.-C., 1997, Carburants et Moteurs: Technologies, Energie, Environnement, Publication de l’Institut Francais ¸ ´ du Petrole, ISBN 2–7108–0704–1. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 PO 00000 Frm 00019 Fmt 4701 Sfmt 4702 E:\FR\FM\14JNP2.SGM 14JNP2 36060 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules TABLE V.F.–3—PROPOSED D CODES FOR BUTANOL Fuel type Feedstock Production process requirements Butanol ............. Butanol ............. Corn starch ....... Corn starch ....... Fermentation; dry mill using natural gas, biomass, or biogas for process energy ............... Fermentation; dry mill using natural gas and biogas from on-site thin stillage anaerobic digester for process energy w/CHP producing excess electricity of at least 40% of the purchased natural gas energy used by the facility. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 2. Butanol, Biobutanol, and Volatility Considerations Butanol is a flammable colorless liquid that is used as a fuel and as an industrial solvent. Butanol is composed of the chemical elements hydrogen, oxygen, and carbon. It can be made from petroleum or renewable biomass, such as corn, grasses, agricultural waste and other renewable sources. It can be used in internal combustion engines as an additive to gasoline and is currently registered under the Fuel and Fuel Additives Registration System (FFARS) for use at up to 12 volume percent. A higher blend level would require a new FFARS registration that would include meeting Tier 1 and Tier 2 health effects testing requirements. Biobutanol is the common name for butanol made from renewable sources. There has been an increased interest in the use of biobutanol as a direct result of the requirements for increased use of renewable fuel volumes, adopted in EISA 2007. These provisions require an increase in the use of renewable fuels, with 36 billion gallons of renewable fuel to be used in the U.S. by 2022. Parties required to meet these standards are interested in cost effective and practical ways to satisfy the standards and meet the performance needs of the vehicles and engines. Biobutanol is one attractive option because of its higher energy density, lower blending vapor pressure, and lower heat of vaporization in comparison to ethanol, as well as the fact that it can be distributed as a gasoline blend throughout the fungible gasoline distribution system. The Clean Air Act (section 211(h)(4)) requires EPA to adopt regulations limiting the volatility of gasoline during the summer months, when ozone is of most concern, including a one pound per square inch (psi) Reid Vapor Pressure (RVP) increase in the volatility limit for blends of gasoline containing 9–10% ethanol (E10). This allowance for a 1 psi increase in allowable volatility is commonly called the 1 psi waiver. EPA’s regulations at 40 CFR 80.27 adopt RVP standards that apply to the gasoline at all points in the distribution system, including the retail outlet. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 Under the provisions for the 1 psi waiver, blends of gasoline that contain from 9 volume percent to 10 volume percent ethanol are allowed to have volatility 1 psi higher than otherwise would be allowed (40 CFR 80.27(d)(2)). The chemical characteristics of ethanol are such that blends of gasoline with less than 9 volume percent to 10 volume percent ethanol would still have a significant increase in volatility. Thus the restriction on the 1 psi waiver to blends that have 9 volume percent to 10 volume percent ethanol has the effect of prohibiting the blending of E10 with other gasoline/renewable fuel blends at any point in the gasoline distribution system (wholesale or retail) in conventional gasoline areas during the summer control season. Blends of E10 gasoline and gasoline that is not E10 would have less than 9 volume percent or greater than 10 volume percent ethanol, would have a resulting increase in volatility compared to E0, but would not have the 1 psi waiver to allow for such an increase. This increase would lead to an RVP above the allowable limit, unless a sub-RVP gasoline blendstock was used. The practical effect is a prohibition on commingling of E10 and gasoline blends other than E10. Under the current regulations, EPA applies the RVP standard to the commingled mixture as a whole, not to the components of the commingled mixture. Once the ethanol and nonethanol blends are mixed, the commingled mixture is treated as the gasoline that is tested and compared to the RVP standard. A single RVP value is determined by testing the volatility of the commingled mixture, and this is compared to the standard. If the mixture has from 9 volume percent to 10 volume percent ethanol, then the 1 psi waiver applies to the mixture. If the mixture has a different percentage of ethanol, whether lower or higher, then the 1 psi waiver does not apply to the mixture. This avoids a situation where there is an overall increase in volatility because of the commingling of E10 and gasoline that is not E10. As discussed below, the chemical characteristics of ethanol and the nonlinear nature of the volatility increase associated with varying volumes of ethanol, mean that mixing PO 00000 Frm 00020 Fmt 4701 Sfmt 4702 D-Code 6 5 E10 gasoline with gasoline that is not E10 typically results in a net overall increase in emissions—the mixture has a higher volatility and emissions than the separate gasolines had on average before they were mixed. Several parties have identified this as an obstacle that currently inhibits the opportunity for biobutanol to enter the commercial market. The primary issue is application of the RVP regulations at the final point of fuel dispensing, when the biobutanol (Bu) and the ethanol blends would be mixed, that is in a storage tank at the retail station. When a butanol product that complies with the RVP standards prior to commingling (e.g., a complying Bu12 blend) is commingled with a compliant E10 in underground storage tanks at fuel dispensing facilities, the resulting mix generally would exceed the applicable RVP standard as EPA’s RVP regulations currently apply the standard. Certain fuels, including renewable biofuels such as butanol, however, do not have a net negative impact on RVP when blended with E10 at wholesale or retail. That is, the RVP and related emissions of the commingled blend of butanol and ethanol is no higher than the average RVP if the fuels had never been commingled. Thus, in these kinds of circumstances it may be appropriate to adopt a modified approach to applying the RVP standard to permit the commingling of complying E10 blends with complying butanol blends at wholesale and retail, as there is no overall degradation of RVP and the air quality impacts compared to what would occur if they were not blended. Today, the agency is providing some additional background on this issue and requesting information for use in deciding whether EPA can and should modify its RVP regulations as discussed below. Specifically, we are inviting comment on the ability of regulated parties to comply with the existing regulations by segregating biobutanol blends from ethanol blends and whether there is a need to change the regulations. We are also seeking comment on an alternative approach to applying the RVP standards to a commingled mixture of E10 with biobutanol or other approved gasoline additives, where the additives have E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules mstockstill on DSK4VPTVN1PROD with PROPOSALS2 characteristics such that there is no net adverse emissions effect from the commingling. We are inviting comments as to whether the RVP standards can and should be applied such that the commingled mixture of E10 and specified blends of gasoline additives such as biobutanol is treated as complying with the RVP standard as long as the components of that mixture complied with the RVP standard prior to the commingling. This approach would provide a limited modification to how the RVP standards are applied, and the modification would apply for only certain fuel mixtures—those where the overall or net volatility of the commingled mixture is no higher than the weighted average of the original blends themselves, such that there is no adverse impact on emissions from the mixing compared to what would have occurred without such mixing. In order to assist parties in preparing comments, EPA is providing some additional background regarding the RVP program in the following paragraphs. Background and History of Volatility Regulations Reid Vapor Pressure (RVP) is the most common measure of gasoline volatility under ambient conditions. In 1989, EPA began reducing gasoline volatility by limiting its RVP (54 FR 11868, March 22, 1989) (40 CFR 80.27). Due to the presence of gasoline in certain markets mixed with about 10 volume percent ethanol (known as gasohol at the time), and because blending an alcohol into gasoline increases the volatility of the final product, EPA provided an additional 1 psi allowance for such blends. In the absence of the 1 psi allowance, a special blend stock would have been required for such blends to comply with the RVP standards and such sub-RVP blendstocks did not exist at the time. EPA imposed the RVP standards at all points in the gasoline distribution system, i.e., anywhere gasoline is sold, supplied, offered for sale or supply or transported, including service stations, refinery shipping, tanks, importer shipping tanks, pipeline and bulk terminals and plants. (40 CFR 80.28) (1989). In 1990, the agency promulgated additional regulations that further lowered the RVP standards. (55 FR 23658, June 11, 1990). EPA continued to provide both the 1.0 psi allowance to fuel blends containing about 10 volume percent ethanol, (40 CFR 80.27) (1990), and the requirement that RVP standards applied at all points in the distribution system. Congress largely codified the approach taken in EPA’s RVP regulations by adding a new section VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 211(h) in the 1990 CAA amendments. Section 211(h)(1) requires EPA to set the maximum RVP standard during the high ozone season as 9.0 psi. EPA was to ‘‘promulgate regulations making it unlawful for any person during the high ozone season to sell, offer for sale, dispense, supply, offer for supply, transport, or introduce into commerce gasoline with a Reid Vapor Pressure in excess of 9.0 pounds per square inch (psi).’’ Lower RVP standards could be set for ozone nonattainment areas. See Clean Air Act section 211(h)(1). Section 211(h)(2) addresses the RVP standard that apply in attainment areas, and sets the standard at 9.0 psi for attainment areas with authority for EPA to set a more stringent RVP level under certain circumstances. In section 211(h)(2), Congress allowed a 1-psi waiver for E10 gasoline, stating: ‘‘For fuel blends containing gasoline and 10 percent denatured anhydrous ethanol, the Reid vapor pressure limitation under this subsection shall be one pound per square inch (psi) greater than the applicable Reid vapor pressure limitations established under paragraph (1).’’ Additionally, Congress enacted a conditional defense against liability for violations of the RVP level allowed under the 1 psi waiver by stating that ‘‘[p]rovided; however, that a distributor, blender, marketer, reseller, carrier, retailer, or wholesale purchaserconsumer shall be deemed to be in full compliance with the provisions of this subsection and the regulations promulgated there under if it can demonstrate that—(A) the gasoline portion of the blend complies with the Reid vapor pressure limitations promulgated pursuant to this subsection; (B) the ethanol portion of the blend does not exceed its waiver condition under subsection (f)(4) of this section; and (C) no additional alcohol or other additive has been added to increase the Reid Vapor Pressure of the ethanol portion of this blend.’’ Section 211(h)(4). In a 1991 rulemaking, EPA modified the RVP regulations to conform to the 1990 amendments (56 FR 64704, December 12, 1991). These regulations addressed the RVP standards in attainment areas, required the use of denatured anhydrous ethanol as a specific condition for the 1-psi waiver for fuel blends containing gasoline and from 9 volume percent to 10 volume percent ethanol, and included a new defense against liability for violations of the RVP standards for such fuel blends. We made no changes to the requirement that the RVP standards applied at all points in the distribution system. PO 00000 Frm 00021 Fmt 4701 Sfmt 4702 36061 What modification is EPA considering to the application of the RVP standards to certain fuel blends? Gasoline and ethanol are mixed or blended after the refining process. The practice of blending ethanol with gasoline increases the RVP of the resulting blend by approximately 1.0 psi. It is a non-linear relationship, most of the volatility increase occurs after just a few percent of ethanol have been added, with the volatility increasing more slowly as the gasoline ethanol blend increases to 10 volume percent. Above 10 volume percent the volatility generally does not increase any more, and at even higher levels of ethanol the volatility starts to decrease again. As explained above, section 211(h)(4) provides a 1-psi waiver for fuel blends containing gasoline from 9 volume percent to 10 volume percent ethanol. The absence of such a waiver would have required the creation of a production and distribution network for sub-9.0 psi RVP gasoline, to offset the increase in volatility associated with blending ethanol into the gasoline. At the time the costs of producing and distributing an additional grade of this type of fuel, especially in consideration of the low volumes of fuel being blended with ethanol at the time, would have likely been prohibitive and resulted in the termination of the availability of ethanol in the marketplace. Thus, the 1-psi waiver facilitated the participation of ethanol in the transportation fuel industry while also limiting gasoline volatility resulting from ethanol blending. But the RVP levels of gasoline actually used by consumers are dependent on the mixture of alcohol blends and gasoline that are commingling in either vehicle or storage tanks. Depending on the mixture, the resulting RVP level could be significantly higher than the average volatility of the fuels prior to the commingling. This is because the volatility increase when ethanol is added to gasoline is non-linear, with a large increase with the first few percent and then slowly tapering off as the concentration increases (see Illustration V.F.–4). In other words, mixing E10 and EO gasoline results in a net increase in the volatility of the gasoline mixture, compared to the average volatility that would occur absent such mixing. For example, 2000 gallons of 10 psi E10 added to a service station tank with 8000 gallons of 9.0 psi E0 would result in 10,000 gallons of fuel with a volatility of approximately 10 psi. However if the fuels had not been mixed, the average volatility of the 10000 gallons would E:\FR\FM\14JNP2.SGM 14JNP2 36062 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules mstockstill on DSK4VPTVN1PROD with PROPOSALS2 have been 9.2 psi. The emissions associated with the commingled mixture (10000 gallons at 10 psi) would be significantly higher than the emissions associated with the two separate blends of 2000 gallons at 10 psi and 8000 gallons at 9 psi. The commingling thus results in an adverse environmental impact compared to what would occur absent the commingling. EPA’s current RVP regulations address this adverse emissions impact by applying the RVP standard to the commingled mixture as a single fuel. In this case the commingled mixture has an RVP of 10 psi. The 1 psi waiver does not apply as the mixture is now 2% ethanol, not from 9 volume percent to 10 volume percent ethanol. The commingled mixture thus would not comply with the 9.0 psi RVP standard, effectively prohibiting such commingling. As discussed earlier, the EPAct 2005 and EISA2007 mandated increased volumes of renewable fuel for use in gasoline. This has resulted in the increased use of ethanol. E10 is now present in nearly all gasoline sold in the country. Recently, EPA granted a waiver from the substantially similar requirements under section 211(f)(4) for the use of E15 blends in MY2001 and newer light-duty vehicles (See 75 FR 68094, November 4, 2010 and 76 FR 4662, January 26, 2011). EPA interpreted section 211(h) as not extending the 1 psi waiver to such blends with ethanol levels above 10%. Several companies are also developing and planning on introducing biobutanol into commerce. The characteristics of butanol are such that it could be beneficial with respect to volatility and vehicle evaporative emission performance. For example, 2000 gallons of 10 psi E10 added to a service station tank with 8000 gallons of 9.0 psi Bu12 would result in 10000 gallons of fuel with an RVP of 9.2 psi. The RVP of the commingled blend would be the same as the average of the separate blends if they had never been commingled. There is no adverse emissions impact from the commingling of the E10 and Bu12 blends. However the 1-psi waiver would not be applicable because the resulting blend no longer contains from 9 volume VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 percent to 10 volume percent ethanol. The RVP level for the resulting blend would also be higher than the maximum RVP standard of 9.0 psi, making the commingled blend noncomplying with the RVP standard. However the available data indicates that commingling of biobutanol blends with ethanol blends would not result in any net increase in gasoline volatility. This is because biobutanol blends and gasoline containing from 9 volume percent to 10 volume percent ethanol blend linearly from a volatility perspective, resulting in no net increase in volatility compared to what would occur without the blending. This means that there would be no net degradation in environmental performance, as indicated in Illustration V.F.–4, below. We are inviting comment on an alternative approach to applying the RVP standard to the gasoline that results from commingling of E10 and certain other products like biobutanol. We are inviting comment as to whether the RVP standards could be applied to the commingled blend such that the commingled blend would be considered in compliance as long as the separate components of the commingled product were in compliance with the RVP standards prior to commingling. In effect the RVP standard would be applied to the commingled mixture by treating it as if it still contained two separate products, with each product required to comply with the RVP standard separately. This approach would be somewhat artificial but would allow for the commingling of specified blends of fuels, such as biobutanol, with E10 where the resulting commingled mixture does not result in a net increase in average RVP and associated emissions. This would provide more flexibility in achieving the RFS standards while avoiding adverse environmental impacts. This approach would provide a limited modification to the RVP provisions for only certain fuel blends. EPA invites comment on whether it would have the authority under § 211(h) to adopt such an approach, and if so whether it would be appropriate to do so and under what conditions. PO 00000 Frm 00022 Fmt 4701 Sfmt 4702 Specifically, we would consider imposing the following conditions on such fuel blends: (1) Each separate component must individually meet the applicable RVP standards (e.g., 10 psi for E10 and 9 psi for other blends). (2) The resulting commingled mixture would have to have an RVP that is no higher than the weighted average of the products or components considered separately. This could occur with blends that blend linearly with respect to RVP (e.g., butanol). (3) The burden would be on the retailer to show that these conditions had been satisfied. If a commingled product had volatility above the allowable standard, and did not have from 9 volume percent to 10 volume percent ethanol, then the fuel would be considered noncomplying unless the regulated party demonstrated that it met the limited conditions discussed here. The retailer would have to demonstrate that the conditions were met for application of this modified method of determining compliance. This would call for at least retaining records of the products received (with all required regulatory statements and indications required) and volumes of the products received in order to demonstrate a calculation to verify compliance with the RVP standard. (4) In situations where the RVP of retail tank samples exceed 9.0/7.8 psi, for defense purposes the retailer would need to test the sample for the concentration of ethanol, butanol, and any other applicable oxygenate in addition to the RVP level in order to allow for the calculation in (3). The resulting blend ratio would need to meet or demonstrate better performance reductions of such ratio on a linear scale as established through regulation. Under this approach, we believe there would be no adverse environmental effects because such mixtures would result in no net increase in volatility. We also believe this would enable us to give effect to the RFS provisions that call for increased use of renewable fuels, and also be consistent with our rational for the treatment of gasohol at the time we promulgated the RVP standards. E:\FR\FM\14JNP2.SGM 14JNP2 F. Amendments to Various RFS2 Compliance Related Provisions We are proposing a number of changes to the RFS2 regulations. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 1. Proposed Changes to Definitions ‘‘Responsible Corporate Officer’’ The existing RFS2 regulations at sections 80.1416, 80.1451 and 80.1454, and EPA guidance and instructions regarding registration and reporting, frequently refer to the responsibilities of the ‘‘owner or a responsible corporate officer.’’ However, the term ‘‘responsible corporate officer’’ is not currently defined in the RFS2 regulations. We propose that, for purposes of the RFS2 program, a ‘‘responsible corporate officer’’ (RCO) means a corporate officer who has the authority and is assigned responsibility to provide information to EPA on behalf of a company. A company may name only one RCO, and VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 the RCO may not delegate his/her responsibility to any other person. However, the RCO may delegate the ability to submit information to EPA to one or more employees of the company or to one or more agents. The RCO remains responsible for the information submitted to EPA by any employee or agent. Adding a definition of RCO will codify existing practices and will assist regulated parties in understanding roles under the RFS2 regulation. ‘‘Small Refinery’’ Section 211(o)(9)(A) of the Clean Air Act provides an exemption from RFS requirements through 2010 for ‘‘small refineries,’’ defined as refineries having an average aggregate daily crude oil throughput for a calendar year that does not exceed 75,000 barrels. It also provides for possible extensions of this exemption, through individual petitions PO 00000 Frm 00023 Fmt 4701 Sfmt 4702 36063 to EPA. CAA 211(o)(9)(B). In EPA’s March 26, 2010 regulations implementing the EISA amendments we specified in the regulatory definition of ‘‘small refinery’’ that the 75,000 bpd threshold determination should be calculated based on information from calendar year 2006. At the beginning of the program, having a single year in which to make this determination, simplified the calculations, and helped to ensure that all refineries were treated similarly. However, we no longer believe that it is appropriate that refineries satisfying the 75,000 bpd threshold in 2006 should be eligible for extensions to their small refinery RFS exemption if they no longer meet the 75,000 bpd threshold. Allowing such facilities to qualify for an exemption extension, while not allowing similarly sized facilities that have not grown since 2006 to qualify for an exemption, E:\FR\FM\14JNP2.SGM 14JNP2 EP14JN13.001</GPH> Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 36064 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules does not appear fair, nor does it further the objectives of the statute to target relief to only truly small facilities. Therefore, we propose modifying the definition of small refinery so that the crude throughput threshold of 75,000 bpd must apply in 2006 and in all subsequent years. We also propose specifying in section 80.1441(e)(2)(iii) that in order to qualify for an extension of its small refinery exemption, a refinery must meet the definition of ‘‘small refinery’’ in section 80.1401 for all full calendar years between 2006 and the date of submission of the petition for an extension of the exemption. We proposed that that these changes would not affect any existing exemption extensions under CAA 211(o)(9)(B); rather, they would apply at such time as any approved exemption extension expires and the refinery at issue seeks a further exemption extension. No further extension would be permitted unless the revised crude oil throughput specifications were satisfied. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 2. Provisions for Small Blenders of Renewable Fuels The RFS2 regulations at section 80.1440 allow renewable fuel blenders who handle and blend less than 125,000 gallons of renewable fuel per year, and who are not obligated parties or exporters, to delegate their RIN-related responsibilities to the party directly upstream from them who supplied the renewable fuel for blending. EPA has received feedback from several parties to the effect that the 125,000 threshold is too low, and is a lower threshold than what industry considers ‘‘small.’’ EPA seeks input on what a more appropriate gallon threshold should be. EPA seeks comment on the regulated community’s experience with the existing gallon threshold associated with the provisions. EPA may adjust the gallon threshold in the final rule based on further consideration of this issue and evaluation of comments received. 3. Proposed Changes to Section 80.1450—Registration Requirements We propose to add a new paragraph (h) to section 80.1450 that will describe the circumstances under which EPA may cancel a company registration. EPA proposes to initiate a process to cancel a company registration if the company has reported no activity in the EPA Moderated Transaction System (EMTS) under section 80.1452 for one year. EPA also proposes to initiate a process to cancel a company registration if a party fails to comply with any registration requirement of section 80.1450, if the party fails to submit any required compliance report under section VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 80.1451, if the party fails to meet the requirements related to the EPA Moderated Transaction System (EMTS) under section 80.1452, or if the party fails to meet the requirements related to attest engagements under section 80.1454. If any required report, including the attest engagement, is thirty (30) or more days overdue, EPA would provide written notice to the owner or responsible corporate officer (RCO) that it intends to cancel the company’s registration and would allow the company fourteen (14) days from the date of the letter’s issuance to respond. If there is no satisfactory response received, then EPA would cancel the registration. Re-registration would be possible following the standard registration procedures. 4. Proposed Changes to Section 80.1452—EPA Moderated Transaction System (EMTS) Requirements— Alternative Reporting Method for Sell and Buy Transactions for Assigned RINs Reporting and product transfer document (PTD) requirements, found in sections 80.1452 and 80.1453, respectively, currently state that the reportable event for a RIN purchase or sale occurs on the date of transfer. Sellers must report the sale of RINs within five (5) business days of the reportable event via the EPA Moderated Transaction System (EMTS). Buyers must report the purchase of RINs within ten (10) business days of the reportable event via EMTS. The date of transfer is the date on which title of RINs is transferred from the seller to the buyer. Some buyers and sellers of assigned RINs have expressed concerns with these requirements stating they have difficulty determining the date of transfer since title of the renewable fuel is not transferred until the fuel physically reaches the buyer. Some transactions, for example those by rail or barge, may take several weeks, and their current accounting systems do not include a means for capturing the buyer’s receipt date. EPA understands this concern, but also recognizes that some regulated parties have modified their accounting systems to address the current reporting and PTD requirements in RFS2. We also believe that for parties separating, retiring, and selling or buying separated RINs, the current reporting and PTD requirements are effective and should remain unchanged. Therefore, at this time EPA is not proposing to replace existing requirements, but is instead proposing an additional, alternative method for reporting sell and buy transactions involving assigned RINs only. PO 00000 Frm 00024 Fmt 4701 Sfmt 4702 The proposed alternative method for sell and buy transactions of assigned RINs would redefine the reportable event for both the seller and the buyer, introduce a unique identifier that the seller must provide to the buyer, and require the buyer to report the date of transfer. Buyers and sellers would need to agree on which method they would be using to report transfers of assigned RINs; either the current method or the alternative method. EPA believes that this alternative would provide the regulated community with the flexibility to address their reporting concerns and also provide EPA with the data necessary to effectively administer and enforce transactions of assigned RINs. EPA welcomes comment on this proposed alternative method for reporting assigned RIN buy and sell transactions. We propose that sellers of assigned RINs under the alternative method be required to do the following: • Within five (5) business days of shipping renewable fuel with assigned RINs, report a sell transaction, using the alternative method, via EMTS; • Include in the EMTS sell transaction report other required information per section 80.1452; and • Provide a PTD to the assigned RIN buyer with a unique identifier, also reported via EMTS, in addition to the information in section 80.1453. The date of transfer is not required for the alternative method. We propose that buyers of assigned RINs under the alternative method be required to do the following: • Within five (5) business days of receiving a shipment of renewable fuel with assigned RINs, report a buy transaction, indicating use of the alternative method, via EMTS; • Include in the EMTS buy transaction report other required information per section 80.1452; • Include in the EMTS buy transaction report the unique identifier provided by the seller; and • Include in the EMTS buy transaction report the date the renewable fuel was received, i.e. the date of transfer. If this proposed alternative method is finalized, the EMTS would be modified to accept such transactions. EPA would provide additional instruction and guidance at the time of the new EMTS version release. EPA invites comment on all aspects of this proposal. E:\FR\FM\14JNP2.SGM 14JNP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 5. Proposed Changes to Section 80.1463—Confirm That Each Day an Invalid RIN Remains in the Marketplace Is a Separate Day of Violation Preventing the generation and use of invalid RINs and encouraging rapid retirement and replacement of invalid RINs is crucial to the integrity of the RFS2 program. The RFS regulations include various provisions related to prohibited acts and liability for violations. Section 80.1460(a) sets forth the prohibited acts for the renewable fuels program. Section 80.1460(b)(2) prohibits parties from creating or transferring invalid RINs. Section 80.1461(a) states that the person who violates a prohibited act is liable for the violation of that prohibition. Section 80.1461(b) provides the liability provisions for failure to meet other provisions of the regulations. The penalty provisions of the regulations at section 80.1463(a) state that any person who is liable for a violation under section 80.1461 is subject to a civil penalty as specified in sections 205 and 211(d) of the Clean Air Act (CAA), for every day of each such violation and the amount of economic benefit or savings resulting from each violation. Section 80.1463(c) provides that ‘‘any person . . . is liable for a separate day of violation for each day such a requirement remains unfulfilled.’’ EPA interprets these statutory and regulatory penalty provisions to give the Agency the authority to seek penalties against parties generating, transferring or causing another person to generate or transfer invalid RINs for each day subsequent to the party’s action that an invalid RIN is available for sale or use by a party subject to an obligation under the RFS2 program to acquire and retire RINs. For example, for a RIN generator, this time period typically runs from the date of invalid RIN generation until either corrective action is taken by the RIN generator to remove the invalid RIN from the marketplace or a party uses the RIN to satisfy an RVO or other requirement to retire RINs (such as would apply under today’s proposal to exporters of renewable fuel or parties using fuel produced as renewable fuel for a use other than as transportation fuel, heating oil or jet fuel). This is consistent with the CAA approach of assessing penalties for every day of a violation, consistent with EPA’s historic approach under the fuels regulations (See Section 80.615), and will encourage renewable fuel producers that generate invalid RINs to promptly take corrective action. We are proposing to amend section 80.1463 to more explicitly incorporate VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 EPA’s interpretation of these penalty provisions into the regulations. The amendments would state that any person liable for a violation of section 80.1460(b) for creating or transferring an invalid RIN, or for causing another person to create or transfer and invalid RIN, is subject to a separate day of violation for each day that the invalid RIN remains available for use for compliance purposes, and EPA has the authority to seek the maximum statutory penalty for each day of violation. EPA will apply the statutory factors in sections 211(c) and 205(b) of the CAA to evaluate the appropriate penalties for each violation on a case by case basis. 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 The current regulations include requirements that foreign renewable fuel producers that generate RINs agree to be subject to a number of additional requirements at section § 80.1466, including, but not limited to, designation, foreign producer certification, product transfer document, load port independent testing and producer identification, submission to U.S. jurisdiction and posting of a bond. We are proposing to require the same requirements for foreign renewable fuel producers, and foreign ethanol producers that produce biofuel for which importers ultimately generate RINs, and for importers of renewable fuel. In order to evaluate whether a fuel qualifies as RIN generating renewable fuel (including determining the proper renewable fuel category and RIN type for the imported fuel), EPA must be able to evaluate the feedstocks and processes used to produce the renewable components of the fuel. This is a particular challenge for fuel produced at foreign facilities; unlike our other fuels programs, EPA cannot determine whether a particular shipment of renewable fuel is eligible to generate RINs under the RFS program by testing the fuel itself. Furthermore, significant opportunity for fraud and noncompliance with the regulations exists where EPA is not able to ensure that RINs entering the U.S. are valid, and where enforcement of the regulations may be hampered due to a facility’s foreign location. We believe that the same safeguards that apply to foreign RIN generating renewable fuel producers should apply to other foreign producers whose product is used by importers to generate RINs, and to those PO 00000 Frm 00025 Fmt 4701 Sfmt 4702 36065 importers themselves. Accordingly, we propose that foreign renewable fuel producers and foreign ethanol producers who do not themselves generate RINs for their product, and importers of renewable fuel, be required to comply with the safeguards of section 80.1466. Given the challenges associated with EPA’s ability to determine whether a fuel qualifies as RIN generating renewable fuel, and the potential for fraud, we believe these additional safeguards are necessary for all foreign produced renewable fuel, regardless of who generates the RINs. However, we seek comment on the reasonability of expanding these additional requirements onto foreign renewable fuel producers, and foreign ethanol producers that produce biofuel for which importers ultimately generate RINs, and for importers of renewable fuel. We further propose to amend section 80.1426(a)(4) to prohibit importers from generating RINs for renewable fuel imported from a foreign renewable fuel producer or foreign ethanol producer, unless and until the foreign renewable fuel producer or foreign ethanol producer has satisfied all requirements of section 80.1466. 7. Proposed Changes to Section 80.1466(h)—Calculation of Bond Amount for Foreign Renewable Fuel Producers, Foreign Ethanol Producers and Importers EPA proposes two changes to section 80.1466 regarding calculation of bonds. EPA proposes to amend the procedures for calculating the bond amount for foreign renewable fuel producers, foreign ethanol producers and importers to require that the bond amount be the larger of: (1) One cent times the largest volume of renewable fuel produced by the foreign producer and exported to the United States, in gallons, during a single calendar year among the five preceding calendar years, or the largest volume of renewable fuel that the foreign producers expects to export to the Unites States during any calendar year identified in the Production Outlook Report required by section 80.1449, or (2) the sum of the following calculation for each RIN type: 0.25 times the largest volume of renewable fuel produced by the foreign producer and exported to the United States, in gallons, during a single calendar year among the five preceding calendar years, or the largest volume of renewable fuel that the foreign producers expects to export to the Unites States during any calendar year identified in the Production Outlook Report required by section 80.1449, times a ‘‘RIN multiplier D code’’ established by EPA in the regulations. E:\FR\FM\14JNP2.SGM 14JNP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 36066 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules The proposed ‘‘RIN multiplier D codes’’ vary from $.02 for D code 6 to $1.30 for D code 4. When the original renewable fuels standard regulations (RFS1) were written, an RFS1 RIN was worth pennies. With the implementation of RFS2, the price of some RINs has increased significantly, in part because of the demand for certain categories of fuel such as biomass-based diesel. In order to keep up with these market conditions, the bond amount needs to be increased; a penny per gallon of fuel may no longer be a fair valuation of a foreign renewable fuel producer’s potential penalty for RFS violations. Bonds are used to satisfy any judicial judgment that results from an administrative or judicial enforcement action for conduct in violation of this subpart. Therefore, we propose to amend section 80.1466(h)(1) to include the calculation described above, that reflects current market valuation for different types of RINs. We seek comment on whether the proposed bond calculation procedures are appropriate, and in particular whether they are sufficiently large to cover potential liability. EPA also proposes to amend paragraph (h) of section 80.1466 to be consistent with paragraph (j)(4), which prohibits generating RINs in excess of the number for which the bond requirements have been satisfied. Paragraph (h) regulates the size of the bond a foreign renewable fuel producer must post in order to generate RINs. This formula takes into account the volume of renewable fuel a foreign renewable fuel producer has exported or intends to export to the United States. Section 80.1466(h) states, in part: ‘‘If the volume of renewable fuel exported to the United States increases above the largest volume identified in the Production Outlook Report during any calendar year, the foreign producer shall increase the bond to cover the shortfall within 90 days.’’ This conflicts with the stricter language in paragraph (j)(4) of the same section, which prohibits a foreign producer of renewable fuel from generating RINs in excess of the number for which the bond requirements of section 80.1466 have been satisfied. EPA interprets the stricter provision at section 80.1466(j)(4) to be controlling, and we propose to change the language in section 80.1466(h) accordingly. 8. Proposed Changes to Facility’s Baseline Volume To Allow ‘‘Nameplate Capacity’’ for Facilities Not Claiming Exemption From the 20% GHG Reduction Threshold As a requirement of registration under the RFS2 program, each renewable fuel producer and foreign ethanol producer must establish and provide documents to support its facility’s baseline volume as defined in section 80.1401. This is either the permitted capacity or, if permitted capacity cannot be determined, the actual peak capacity of a specific renewable fuel production facility on a calendar year basis. After the promulgation of the March 26, 2010 RFS2 rule, we have received many requests from companies to allow them to use their nameplate or ‘‘design’’ capacity to establish their facility’s baseline volume due to either the facility being exempt from obtaining a permit, and thus not able to determine their permitted capacity, or the facility not starting operations, or not being operational for a full calendar year to produce actual production records to establish actual peak capacities. Because the regulations currently only allow a facility’s baseline volume to be established by a limit stated in a permit or actual production records for at least one calendar year, facilities that had neither a permit or sufficient production records had difficulty registering under the RFS2 program. To allow facilities that fall under this predication to register under the RFS2 program, we are proposing in this rulemaking to allow a facility to use its ‘‘nameplate capacity’’ to establish its facility’s baseline volume for the purposes of registration, only if (1) the facility does not have a permit or there is no limit stated in the permit to establish their permitted capacity, and (2) has not started operations or does not have at least one calendar year of production records, and (3) does not claim exemption from the 20 percent GHG threshold under § 80.1403. Due to the complexity of the exemption provision provided under § 80.1403, and the added flexibility that facilities claiming this exemption are allotted under the program, we are not proposing to extend this option to facilities claiming an exemption under § 80.1403. Additionally, by this stage in the RFS2 program, the facilities that would qualify for registration under § 80.1403 would be very few, if any. This proposal would revise the definition of baseline volume to include ‘‘nameplate capacity,’’ add a new definition for ‘‘nameplate capacity’’ to § 80.1401, and include conforming amendments to the registration requirements of § 80.1450. G. Minor Corrections to RFS2 Provisions We are proposing a number of corrections to address minor definitional issues that have been identified as we have been implementing the RFS2 program. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 PO 00000 Frm 00026 Fmt 4701 Sfmt 4702 Renewable Biomass We propose to amend the definition of ‘‘renewable biomass’’ in section 80.1401 to make clear that biomass obtained in the vicinity of buildings means biomass obtained within 200 feet of the buildings. The preamble for the March 26, 2010 RFS2 final rule cites the distance of 200 feet (see 75 FR 14696), but EPA did not include a reference to this value in the regulations. We believe doing so would provide additional clarity to the regulations. English Language Translations We propose to add a new paragraph (i) to section 80.1450 to state that any registration materials submitted to EPA must be in English or accompanied by an English language translation. Similarly, we propose to add a new paragraph (h) to section 80.1451 that will state that any reports submitted to EPA must be in English or accompanied by an English language translation and add a new paragraph (q) to section 80.1454 that will state that any records submitted to EPA must be in English or accompanied by an English language translation. The translation and all other associated documents must be maintained by the submitting company for a period of five (5) years, which is already the established time period for keeping records under the existing RFS2 program. Correction of Typographical Errors We propose to correct various typographical errors in section 80.1466. Specifically, we propose to amend paragraph (o) to correct a typographical error in the last sentence of the affirmation statement, by changing the citation from § 80.1465 to § 80.1466. We also propose to amend paragraph (d)(3)(ii) to correct a typographical error. The current regulation cites section 80.65(e)(2)(iii), which does not exist. The correct citation is to section 80.65(f)(2)(iii). VI. Amendments to the E15 Misfueling Mitigation Rule We propose the following minor corrections and other changes to the E15 misfueling mitigation rule (E15 MMR) found at 40 CFR Part 80, subpart N. A. Proposed Changes to Section 80.1501—Label We propose to correct several minor errors in the description of the E15 label required by the E15 MMR at section 80.1501, including corrections in the dimensions of the label and ensuring that the word ‘‘ATTENTION’’ is capitalized. The Agency intended the label required by the regulations to look E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules identical to that pictured in the Federal Register notice for the final E15 MMR (see 76 FR 44406, 44418, July 25, 2011). B. Proposed Changes to Section 80.1502—E15 Survey We are proposing two changes to the survey requirements found at section 80.1502. First, we propose to clarify that E15 surveys need to sample for Reid vapor pressure (RVP) only during the high ozone season as defined in section 80.27(a)(2)(ii) or during any time RVP standards apply in any state implementation plan approved or promulgated under the Clean Air Act. EPA did not intend to require RVP sampling and testing during the rest of the year, when RVP standards do not apply. Second, we propose to change when the results of surveys that detect potential noncompliance must be reported to the Agency. As originally drafted, the regulations require the independent survey association conducting a survey to notify EPA of potentially noncompliant samples within 24 hours of the laboratory receiving this sample (see 76 FR at 44423, July 25, 2011). EPA has since learned that more time may be needed for reporting of noncompliant samples since it may take several days for analysis of the sample to be completed. We are therefore requiring that noncompliant samples be reported to EPA within 24 hours of being analyzed. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 C. Proposed Changes to Section 80.1503—Product Transfer Documents EPA is proposing certain minor changes to the product transfer document (PTD) requirements found at section 80.1503. Specifically, we are proposing to allow the use of product codes for conventional blendstock/ gasoline upstream of an ethanol blending facility, since historically, the codes have been allowed to be used for conventional blendstock/gasoline upstream of an ethanol blending facility in other fuels programs. This was an omission from the original regulation. We are also seeking comment on potential ways of streamlining the PTD language required at section 80.1503. D. Proposed Changes to Section 80.1504—Prohibited Acts EPA is slightly rewording section 80.1504(g) to state that blending E10 that has taken advantage of the statutory 1.0 psi RVP waiver during the summertime RVP control period with a gasoline-ethanol fuel that cannot take advantage of the 1.0 psi RVP waiver (i.e., a fuel that contains more than 10.0 volume percent ethanol (e.g., E15) or VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 less than 9 volume percent ethanol) would be a violation of the E15 MMR. As originally written, the language does not clearly describe the prohibited activity (see 76 FR 44435, 44436, Jult 25, 2011). E. Proposed Changes to Section 80.1500—Definitions On August 17, 2011, the National Petroleum Refiners Association, now called American Fuel and Petrochemical Manufacturers (AFPM), filed a petition for reconsideration with the Agency under CAA section 307(d)(7)(B) asking EPA to reconsider certain portions of the E15 MMR. A copy of the petition has been placed in the docket. The petition fundamentally focuses on one issue—AFPM expressed concern that the Agency had defined E10 and E15 in the E15 MMR in a way that would change how ethanol concentrations are determined for regulatory purposes. Today we grant AFPM’s request for reconsideration of this issue as explained in their August 17, 2011 petition. As explained below, while EPA did not intend the definitions of E10 and E15 in the E15 MMR to have this effect, we are proposing changes to the regulations to avoid this perceived impact. On April 6, 1979, fuel containing 90% unleaded gasoline and 10% ethyl alcohol received a waiver under section 211(f)(4) by operation of law (see 44 FR 20777, April 6, 1979). Later, EPA issued an interpretative ruling that stated the April 6, 1979 waiver covered gasolineethanol blends that contained up to 10 vol% ethanol content (see 47 FR 14596, April 5, 1982). Finally, in the context of regulations limiting the Reid vapor pressure (RVP) of gasoline, EPA has defined E10 as gasoline containing between 9 and 10 volume percent ethanol. Under the RVP regulations and the Clean Air Act, the RVP of E10 is allowed to be 1 pound per square inch (psi) higher than it is for gasoline or gasoline-ethanol blends containing less than 9 and more than 10 vol% ethanol (often referred to as the ‘‘1.0 psi waiver’’). In the E15 MMR, EPA defined E10 as gasoline containing at least 9.0 and no more than 10.0 vol% ethanol and defined E15 as a gasoline-ethanol blend containing greater than 10.0 and no more than 15.0 vol% ethanol. EPA included those definitions in the E15 MMR so that fuels blended to contain more than 10.0 vol% ethanol were subject to the misfueling mitigation requirements for E15. After publication of the E15 MMR, stakeholders including AFPM expressed concern that by defining E10 as E10.0, the Agency may PO 00000 Frm 00027 Fmt 4701 Sfmt 4702 36067 have effectively made the ethanol concentration limits specified in the E10 and the E15 waiver decisions and the RVP regulations more stringent, which in turn would impact whether a party must comply with the E15 MMR requirements and whether a fuel qualifies for the RVP 1.0 psi waiver. In its petition, AFPM noted that under existing EPA regulations at 40 CFR 80.9, the results of compliance testing for the ethanol concentration in gasoline are ‘‘rounded down’’ when the results indicate that gasoline-ethanol fuel may contain slightly more than 10 vol% ethanol. AFPM further stated that in view of this rounding procedure, fuel that compliance testing indicates has an ethanol concentration of between 10.0 and 10.4 should be considered E10. AFPM argued that the E15 MMR definition of E10 as containing no more than 10.0 vol% ethanol constituted a ‘‘substantive change’’ to the proposed E15 MMR that would also alter the implementation of other EPA fuels regulations without a required rulemaking. As part of the E15 MMR proposed rule, we identified prospective responsible parties for each misfueling mitigation measure, including requirements related to labeling E15 fuel dispensers, compliance surveys, and product transfer documents. We received a number of comments from many affected stakeholders, including AFPM, that asked us to clarify which party or parties would be responsible for each misfueling mitigation measure and when each party or parties would be subject to those requirements. In the final E15 MMR, we added the significant digit to the definitions of E10 and E15 in order to provide a delineation between E10 and E15 and consequently the parties subject to one or more of the E15 misfueling mitigation measures. AFPM argued in their petition that by defining E10 as containing no more than 10.0 vol% ethanol, EPA effectively made a substantive change to the way test results used for determining compliance with fuel requirements are rounded. For example, for a gasolineethanol blend to be considered E10, it could no longer contain up to 10.4 vol% ethanol; it could only contain up to 10.04 vol% ethanol. AFPM asserted that there is a tolerance for blending ethanol that allows blends containing up to 10.4 vol% ethanol to be considered E10. While we do not agree that there is a blending tolerance for ethanol, we agree that test results are rounded utilizing the procedures identified in section 80.9 when compared to applicable standards, in this case the ethanol concentrations E:\FR\FM\14JNP2.SGM 14JNP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 36068 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules specified in the E10 and the E15 waivers. The Agency specifically addressed the issue of blending tolerances versus testing tolerances for gasoline-ethanol blends in the RFS2 NPRM.50 At the time, some stakeholders had suggested that the implementation of a blending tolerance for the ethanol content of gasoline could be allowed to help obligated parties satisfy RFS requirements without the need for a CAA section 211(f)(4) waiver. In response, we argued that although the test methods used to measure ethanol concentration (ASTM D 5599 and ASTM D 4815) include some variability, ethanol is different than other fuel properties and components that are controlled in other fuel programs.51 Fuel properties such as RVP, and components such as sulfur and benzene, are natural characteristics of gasoline as a result of the chemical nature of crude oil and the refining process. Their levels or concentrations in gasoline are unknown until measured and are dependent upon the accuracy of the test method. In contrast, ethanol is intentionally added in known amounts using equipment designed to ensure a specific concentration within a very narrow range. Parties that blend ethanol into gasoline normally have precise control over the final concentration. Therefore, a blending tolerance for ethanol would not be appropriate. During the comment period for the RFS2 NPRM, EPA received a number of comments from stakeholders that argued that the volume percentage of ethanol in gasoline is readily determined using very accurate volumetric ratio blending facilities now in place at most blending terminals; therefore, the Agency should not allow a blending tolerance. In the final RFS rule, we did not include a blending tolerance for ethanol blends.52 We continue to believe that blending tolerances for ethanol are not appropriate, and the definitions of E10 and E15 in the E15 MMR are consistent with this view. The E10 waiver is for gasoline containing ‘‘up to’’ 10 vol% ethanol, not for gasoline containing ‘‘up to’’ 10.4 vol% ethanol, and the E15 partial waivers are for fuel designed to contain ‘‘greater than 10 vol% ethanol and not more than 15 vol% ethanol.’’ In the case of both waivers, the ‘‘10’’ and the ‘‘15’’ are exact numbers, not approximations, and they express how much ethanol can be lawfully added to fuel. Testing by the Department of Energy utilized in making the E15 50 See 74 FR 25018 (May 26, 2009). 51 See 74 FR 25018 (May 26, 2009). 52 See 75 FR 14762–14764 (March 26, 2010). VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 partial waiver decisions was blended as precisely as possible to contain the relevant percentage of ethanol, not that percentage plus ‘‘0.49.’’ Testing for registration of E10 and E15 fuel and fuel additives under 40 CFR part 79 was also done with fuels blended as precisely as possible to contain the relevant percentage of ethanol. Similarly, EPA regulations provide that only fuel with an ethanol concentration of between 9 and 10 vol%, not more or less, may lawfully use the statutory 1.0 psi RVP waiver. At the same time, we did not intend to change the definition of E10 in a way that impacts the rounding of test results for ethanol concentrations.53 If a manufacturer blends in a way designed to result in a gasoline-ethanol fuel containing no more than 10.0 vol% ethanol, but compliance testing indicates a concentration of 10.4 vol%, we will still round down the test result in accordance with procedures in section 80.9. The purpose of the E15 MMR definitions state that if a manufacturer blends ethanol into gasoline in a way designed to result in a gasoline-ethanol fuel containing greater than 10.0 vol% and no more than 15.0 vol% ethanol, it will be subject to applicable E15 MMR requirements. For example, bills of lading for an E10 fuel manufacturer that indicates the manufacturer has purchased and blended more ethanol than 10.0 vol% ethanol may indicate that a fuel does not meet the definition of E10 for E15 MMR purposes. AFPM also argued that the E15 MMR definitions of E10 would alter the implementation of other EPA fuels regulations without a required rulemaking, specifically the application of the 1.0 psi RVP waiver to E10. Since the Agency intended the E15 MMR definition of E10 to only apply for purposes of determining the applicability of E15 MMR requirements, the Agency does not believe these definitions affect the implementation and enforcement of others fuels programs, including the applicability of the 1.0 psi RVP waiver. The introductory language to the definitions at 40 CFR part 80, subpart N clearly states that definitions in section 80.1500 are ‘‘[f]or purposes of this subpart only.’’ In order to clarify that these definitions only apply in the context of the E15 MMR, EPA is proposing to add a new section 80.1509, which contains language that clearly states that when 53 For an explanation of the rounding procedures outlined in § 80.9 and the rationale the Agency used to adopt those procedures, see 71 FR 16496 (April 3, 2006). PO 00000 Frm 00028 Fmt 4701 Sfmt 4702 ethanol concentrations are measured for compliance testing purposes for 40 CFR, Part 80, Subpart N, the applicable ethanol concentration value will be rounded using the rounding procedures at section 80.9. EPA is also proposing new prohibited acts language in section 80.1504 that should make it clear that only those parties that (1) produce gasoline, blendstocks for oxygenate blending (BOBs), or ethanol designed to be used in the manufacture of E15 as currently defined (i.e., E15.0); (2) that manufacture E15 to be introduced into commerce; or (3) that dispense E15 from a retail outlet. The Agency specifically seeks comments on this proposed language. VII. Proposed Amendments to the ULSD Diesel Sulfur Survey EPA is requesting comment concerning whether to amend a provision of the ultra-low sulfur diesel (ULSD) rule. The ULSD rule includes a provision that deems branded refiners liable for violations of the ULSD sulfur standard that are found at retail outlets displaying the refiner’s brand (40 CFR 80.612). The regulations include defense provisions. One element of a branded refiner’s defense to such violations is that it must have a periodic sampling and testing program at the retail level (40 CFR 80.613(b) and (d)). The regulations also set forth an alternative sampling and testing defense element provision for branded refiners. This alternative defense element provision (40 CFR 80.613(e)) allows a branded refiner to meet the companyspecific downstream periodic sampling and testing element of its defense by participating in funding a survey consortium that samples diesel fuel at retail outlets nationwide. This sampling and testing of fuel to determine compliance with the ULSD sulfur standard is carried out by an independent survey association. EPA reviews and approves the annual survey plan submitted by the survey association. The number of samples that are taken each year is determined by a statistical formula that is based in part on the previous year’s compliance rate. In addition, the regulations set a floor and a ceiling for the number of samples that must be taken in an annual survey cycle regardless of the sample number that would be calculated using the regulatory formula. Therefore, the number of samples required to be taken can potentially be less than the formula would require, or it can be more. Compliance with the ULSD sulfur content standard has been extremely high; less than 1% of the samples have been in violation in recent years. The E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules minimum number of samples currently required to be taken annually is set by the regulation at 5,250 regardless of this high compliance rate. Due to the high compliance rate, use of the statistical formula would result in a sampling rate of several hundred samples for each of the past several years, instead of 5,250 samples. The cost difference between taking several hundred samples versus taking over 5,000 samples is significant. For these reasons we believe the continued high compliance rate, and the substantial discrepancy between the sampling rate calculated by the formula and the minimum sampling rate, argue for lowering the minimum sampling rate. However, we believe there is a point where the number of samples per year would be so few that the survey would be meaningless relative to robust sampling and testing programs conducted by each refiner individually. Balancing these concerns, we believe minimum sampling rate of about 1,800 samples is appropriate. We are requesting comment on reducing the minimum number of samples to some rate below 2,000 samples. VIII. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is a ‘‘significant regulatory action’’ because it raises novel legal or policy issues. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in response to OMB recommendations have been documented in the docket for this action. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 B. Paperwork Reduction Act The information collection requirements in this notice of proposed rulemaking have been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The Information Collection Request (ICR) document prepared by EPA related to this proposal has been assigned EPA ICR number 2469.01. A supporting statement for the proposed ICR has been placed in the docket. The proposed information collection is described in the following paragraphs. This action contains recordkeeping and reporting that may affect the following parties under the RFS2 regulation: RIN generators (producers, importers), obligated parties (refiners), exporters, and parties who own or VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 transact RINs. We estimate that 670 parties may be subject to the proposed information collection. We estimate an annual recordkeeping and reporting burden of 3.1 hours per respondent. This action contains recordkeeping and reporting that may affect the following parties under the E15 regulation: gasoline refiners, gasoline and ethanol importers, gasoline and ethanol blenders (including terminals and carriers). We estimate that 2,000 respondents may be subject to the proposed information collection. We estimate an annual recordkeeping and reporting burden of 1.3 hours per respondent. Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to review the instructions; develop, acquire, install, and utilize technology and systems for the purpose of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transit or otherwise disclose the information. Burden is as defined at 5 CFR 1320.3(b). An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR Part 9. To comment on the Agency’s need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, EPA has established a public docket for this proposed rule, which includes the ICR described above, under Docket ID number EPA– HQ–OAR–2012–0401. Submit any comments related to the ICR to EPA and OMB. See the ADDRESSES section at the beginning of this notice for where to submit comments to EPA. Send comments to OMB at the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after June 14, 2013, a comment to OMB is best assured of having its full effect if OMB receives it by July 15, 2013. PO 00000 Frm 00029 Fmt 4701 Sfmt 4702 36069 C. Regulatory Flexibility Act The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of today’s rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration’s (SBA) regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field. After considering the economic impacts of this action on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. The amendments to the RFS2 provisions in this direct final rule will not impose any requirements on small entities that were not already considered under the final RFS2 regulations, as it makes relatively minor corrections and modifications to those regulations. We continue to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such impacts. D. Unfunded Mandates Reform Act This rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year. We have determined that this action will not result in expenditures of $100 million or more for the above parties and thus, this rule is not subject to the requirements of sections 202 or 205 of UMRA. This rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. It only applies to gasoline, diesel, and renewable fuel producers, importers, distributors and marketers and makes relatively minor corrections and E:\FR\FM\14JNP2.SGM 14JNP2 36070 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules modifications to the RFS2 and diesel regulations. E. Executive Order 13132 (Federalism) This action does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. This action only applies to gasoline, diesel, and renewable fuel producers, importers, distributors and marketers and makes relatively minor corrections and modifications to the RFS2 and diesel regulations. Thus, Executive Order 13132 does not apply to this action. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicits comment on this proposed action from State and local officials. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 F. Executive Order 13175 (Consultation and Coordination With Indian Tribal Governments) This proposed rule does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). It applies to gasoline, diesel, and renewable fuel producers, importers, distributors and marketers. This action makes relatively minor corrections and modifications to the RFS and diesel regulations, and does not impose any enforceable duties on communities of Indian tribal governments. Thus, Executive Order 13175 does not apply to this action. EPA specifically solicits additional comment on this proposed action from tribal officials. G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5–501 of the EO has the potential to influence the regulation. This action is not subject to EO 13045 because it does not establish an environmental standard intended to mitigate health or safety risks. H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This action is not a ‘‘significant energy action’’ as defined in Executive Order 13211 (66 FR 28355, (May 22, 2001)), because it is not likely to have VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 a significant adverse effect on the supply, distribution, or use of energy. This action amends existing regulations related to renewable fuel, E15, and ultra-lower sulfur diesel. We have concluded that this rule is not likely to have any adverse energy effects. In fact, we expect this proposed rule may result in positive effects, because many of the changes we are proposing will facilitate the introduction of new renewable fuels under the RFS2 program and have come at the suggestion of industry stakeholders. I. National Technology Transfer and Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (‘‘NTTAA’’), Public Law 104–113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards. This action does not involve technical standards. Therefore, EPA did not consider the use of any voluntary consensus standards. EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially-applicable voluntary consensus standards and to explain why such standards should be used in this regulation. J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States. EPA has determined that this proposed rule will not have disproportionately high and adverse PO 00000 Frm 00030 Fmt 4701 Sfmt 4702 human health or environmental effects on minority or low-income populations because it does not affect the level of protection provided to human health or the environment. These technical amendments do not relax the control measures on sources regulated by the RFS regulations and therefore will not cause emissions increases from these sources. K. Clean Air Act Section 307(d) This rule is subject to Section 307(d) of the CAA. Section 307(d)(7)(B) provides that ‘‘[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.’’ This section also provides a mechanism for the EPA to convene a proceeding for reconsideration, ‘‘[i]f the person raising an objection can demonstrate to the EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.’’ Any person seeking to make such a demonstration to the EPA should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave. NW., Washington, DC 20460, with a copy to both the person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT section, and the Director of the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave. NW., Washington, DC 20460. List of Subjects in 40 CFR Part 80 Environmental protection, Administrative practice and procedure, Agriculture, Air pollution control, Confidential business information, Energy, Forest and Forest Products, Fuel additives, Gasoline, Imports, Motor vehicle pollution, Penalties, Petroleum, Reporting and recordkeeping requirements. Dated: May 20, 2013. Bob Perciasepe, Acting Administrator. For the reasons stated in the preamble, the Environmental Protection Agency proposes to amend 40 CFR chapter I as set forth below: E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules PART 80—REGULATION OF FUELS AND FUEL ADDITIVES 1. The authority citation for part 80 continues to read as follows: ■ Authority: 42 U.S.C. 7414, 7521, 7542, 7545 and 7601(a). 2. Section 80.613 is amended by revising paragraph (e)(4)(v)(A) definition ‘‘n’’ as follows: ■ § 80.613 What defenses apply to persons deemed liable for a violation of a prohibited act under this subpart? * * * (e) * * * (4) * * * (v) * * * (A) * * * * * Where: n= minimum number of samples in a yearlong survey series. However, in no case shall n be larger than 9,600 nor smaller than 1,800. * * * * * 3. Section 80.1401 is amended by adding the definitions of ‘‘Nameplate capacity’’, ‘‘Renewable compressed natural gas’’, ‘‘Renewable fuel producer’’, ‘‘Renewable liquefied natural gas’’, ‘‘Responsible corporate officer’’, in alphabetical order and revising the definitions of ‘‘Biogas’’, ‘‘Crop residue’’, ‘‘Naphtha’’, ‘‘Renewable biomass’’, and ‘‘Small refinery’’ in to read as follows: ■ § 80.1401 Definitions. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 * * * * * Biogas means 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. Biogas includes landfill gas, gas from waste digesters, and gas from waste treatment plants. Waste digesters include digesters processing animal wastes, biogenic waste oils/fats/greases, separated food and yard wastes, and crop residues, and waste treatment plants include wastewater treatment plants and publicly owned treatment works. * * * * * 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 VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 demand for the feedstock crop, products produced from that feedstock crop, and all substitutes for the crop and its products, nor any other impact that would result in a significant increase in direct or indirect GHG emissions. * * * * * Nameplate capacity means the peak design capacity of a facility for the purposes of registration of a facility under § 80.1450(b)(1)(V)(E). Naphtha means a blendstock or fuel blending component falling within the boiling range of gasoline which is composed of only hydrocarbons, is commonly or commercially known as naphtha and is used to produce gasoline through blending. * * * * * Renewable biomass means each of the following (including any incidental, de minimis contaminants that are impractical to remove and are related to customary feedstock production and transport): (1) Planted crops and crop residue harvested from existing agricultural land cleared or cultivated prior to December 19, 2007 and that was nonforested and either actively managed or fallow on December 19, 2007. (2) Planted trees and tree residue from a tree plantation located on non-federal land (including land belonging to an Indian tribe or an Indian individual that is held in trust by the U.S. or subject to a restriction against alienation imposed by the U.S.) that was cleared at any time prior to December 19, 2007 and actively managed on December 19, 2007. (3) Animal waste material and animal byproducts. (4) Slash and pre-commercial thinnings from non-federal forestland (including forestland belonging to an Indian tribe or an Indian individual, that are held in trust by the United States or subject to a restriction against alienation imposed by the United States) that is not ecologically sensitive forestland. (5) Biomass (organic matter that is available on a renewable or recurring basis) obtained from the immediate vicinity (i.e., obtained within 200 feet) of buildings and other areas regularly occupied by people, or of public infrastructure, in an area at risk of wildfire. (6) Algae. (7) Separated yard waste or food waste, including recycled cooking and trap grease, and materials described in § 80.1426(f)(5)(i). Renewable compressed natural gas means biogas as defined in this section, that is processed to the standards of pipeline natural gas as defined in 40 PO 00000 Frm 00031 Fmt 4701 Sfmt 4702 36071 CFR 72.2 and that is compressed to pressures up to 3600 psi. Only renewable CNG that qualifies as renewable fuel and is used for transportation purposes can generate RINs. * * * * * Renewable fuel producer means a person who operates or directly supervises the operation of a facility where renewable fuel is produced. * * * * * Renewable liquefied natural gas means biogas as defined in this section, 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. Only renewable LNG that qualifies as renewable fuel and is used for transportation fuel can generate RINs. Responsible Corporate Officer, or RCO, for this subpart only, means a corporate officer who has the authority and is assigned responsibility to provide information to EPA on behalf of a company. A company may name only one Responsible Corporate Officer. A Responsible Corporate Officer may not delegate his or her responsibility to any other person. The Responsible Corporate Officer may delegate the ability to submit information to EPA, but the Responsible Corporate Officer remains responsible for the actions of such employees or agents. * * * * * Small Refinery, for this subpart only, means a refinery for which the average aggregate daily crude oil throughput for calendar year 2006 and subsequent years (as determined by dividing the aggregate throughput for the calendar year by the number of days in the calendar year) does not exceed 75,000 barrels. ■ 4. Section 80.1415 is amended by revising paragraphs (b)(5) and (c)(1) to read as follows: § 80.1415 How are equivalence values assigned to renewable fuel? (b) * * * (5) 77,000 Btu (lower heating value) of compressed natural gas (CNG) or liquefied natural gas (LNG) shall represent one gallon of renewable fuel with an equivalence value of 1.0. (c) * * * (1) The equivalence value for renewable fuels described in paragraph (b)(7) of this section shall be calculated using the following formula: EV = (R/0.972) * (EC/77,000) Where: E:\FR\FM\14JNP2.SGM 14JNP2 36072 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules EV = Equivalence Value for the renewable fuel, rounded to the nearest tenth. R = Renewable content of the renewable fuel. Except as provided in § 80.1426(f)(4)(iii), this is a measure of the portion of a renewable fuel that came from renewable biomass, expressed as a fraction, on an energy basis. EC = Energy content of the renewable fuel, in Btu per gallon (lower heating value). 5. Section 80.1426 is amended by: a. Revising Table 1 of paragraph (f)(1) by: ■ 1. Revising the entry for ‘‘Q’’; and ■ 2. Adding new entries for T through AA to the end of the table; ■ b. Revising paragraphs (f)(10) and f(11); and ■ c. Adding paragraph (f)(14). ■ ■ The revisions and additions read as follows: § 80.1426 How are RINs generated and assigned to batches of renewable fuel by renewable fuel producers or importers? (f) * * * (1) * * * TABLE 1 TO § 80.1426—APPLICABLE D CODES FOR EACH FUEL PATHWAY FOR USE IN GENERATING RINS Fuel type Feedstock Production process requirements D-Code * Q ............... * * * Renewable Compressed Natural Biogas from waste treatGas, Renewable Liquefied Natural ment plants and Gas. waste digesters. * * Any ........................................................................ * * T ............... * * * Butanol .............................................. Corn starch .................... * U ............... Renewable Compressed Natural Gas, Renewable Liquefied Natural Gas. Renewable Electricity ........................ Cellulosic Naphtha ............................ Biogas from Landfills ..... * * Fermentation; dry mill using natural gas and biogas from on-site thin stillage anaerobic digester for process energy w/CHP producing excess electricity of at least 40% of the purchased natural gas energy used by the facility. Any ........................................................................ X ............... Cellulosic Diesel for use as conventional diesel fuel. Biogas from landfills ...... Y ............... Z ............... Naphtha ............................................. Renewable Diesel for use as conventional diesel fuel. Biogas from landfills ...... Biogas from landfills ...... AA ............. Renewable Diesel for use as conventional diesel fuel. Biogas from landfills ...... V ............... W .............. mstockstill on DSK4VPTVN1PROD with PROPOSALS2 * * * * * (10)(i) For purposes of this section, renewable electricity that is not introduced into a distribution system with electricity derived from nonrenewable feedstocks is considered renewable fuel and the producer may generate RINs if all of the following apply: (A) The electricity is produced from renewable biomass and qualifies for a D code in Table 1 to this section or has received approval for use of a D code by the Administrator; (B) The fuel producer has entered into a written contract for the sale of a specific quantity of renewable electricity as transportation fuel; and (C) The renewable electricity is used as a transportation fuel. (ii) For purposes of this section, fuels produced from biogas that is not introduced into a distribution system with gas derived from non-renewable feedstocks is considered renewable fuel and the producer may generate RINs if all of the following apply: VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 Biogas from landfills ...... Biogas from landfills ...... Any ........................................................................ Fischer-Tropsch process; Facilities must produce at least 20% of their electricity usage at the facility. Fischer-Tropsch process; Facilities must produce at least 20% of their electricity usage at the facility. Fischer-Tropsch process ....................................... Fischer-Tropsch process; Excluding processes that co-process renewable biomass and petroleum. Fischer-Tropsch process; Includes only processes that co-process renewable biomass and petroleum. (A) The fuel is produced from renewable biomass and qualifies for a D code in Table 1 to this section or has received approval for use of a D code by the Administrator; (B) The fuel producer has entered into a written contract for the sale of a specific quantity of biogas to be used as a feedstock for transportation fuel; and (C) The fuel produced from the biogas is used as a transportation fuel. (iii) A producer of renewable electricity that is generated by co-firing a combination of renewable biomass and fossil fuel may generate RINs only for the portion attributable to the renewable biomass, using the procedure described in paragraph (f)(4) of this section. (11)(i) For purposes of this section, renewable electricity that is introduced into a commercial distribution system (transmission grid) may be considered renewable fuel and the producer may generate RINs if: (A) The electricity is produced from renewable biomass and qualifies for a D PO 00000 Frm 00032 Fmt 4701 Sfmt 4702 5 5 3 3 3 7 5 4 5 code in Table 1 of this section or has received approval for use of a D code by the Administrator; (B) The fuel producer has entered into a written contract for the sale of a specific quantity of electricity derived from renewable biomass sources with a party that uses electricity taken from a commercial distribution system for use as a transportation fuel, and such electricity has been introduced into that commercial distribution system (transmission grid); (C) The quantity of renewable electricity for which RINs were generated was sold for use as transportation fuel and for no other purposes; and (D) The renewable electricity was loaded onto and withdrawn from a physically connected transmission grid as defined by the North American Electrical Reliability Corporation (NERC) regions. (ii) For purposes of this section, fuel produced from biogas that is introduced E:\FR\FM\14JNP2.SGM 14JNP2 mstockstill on DSK4VPTVN1PROD with PROPOSALS2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules into a commercial distribution system may be considered renewable fuel and the producer may generate RINs if: (A) The fuel is produced from renewable biomass and qualifies for a D code in Table 1 of this section or has received approval for use of a D code by the Administrator; (B) The fuel producer has entered into a written contract for the sale of a specific quantity of fuel derived from renewable biomass sources with a party that uses fuel taken from a commercial distribution system for transportation fuel, and such fuel has been introduced into that commercial distribution system (e.g., pipeline); (C) The quantity of fuel produced from the biogas for which RINs were generated was sold for use as transportation fuel and for no other purposes; (D) The biogas was injected into and withdrawn from a physically connected carrier pipeline; (E) The gas that is ultimately withdrawn from that pipeline for use in a transportation fuel is withdrawn in a manner and at a time consistent with the transport of gas between the injection and withdrawal points; and (F) The volume and heat content of biogas injected into the pipeline and the volume of gas withdrawn to make a transportation fuel are measured by continuous metering. (iii) The fuel sold for use in transportation fuel is considered produced from renewable biomass only to the extent that: (A) The amount of fuel sold for use as transportation fuel matches the amount of fuel derived from renewable biomass that the producer contracted to have placed into the commercial distribution system; and (B) No other party relied upon the contracted volume of biogas or renewable electricity for the creation of RINs. (iv) For renewable electricity that is generated by co-firing a combination of renewable biomass and fossil fuel, the producer may generate RINs only for the portion attributable to the renewable biomass, using the procedure described in paragraph (f)(4) of this section. * * * * * (14) For purposes of verification, in order for facilities to meet the renewable electricity production requirement for the biogas-derived cellulosic diesel and cellulosic naphtha pathways, all conditions below apply. (i) The quantity of process electricity produced on-site must be measured by continuous metering. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 (ii) The electricity must be used to provide power to process units or process equipment at the facility. (iii) The electrical energy must derive 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. ■ 6. Section 80.1427 is amended by: ■ a. Revising paragraphs (a)(1), (a)(1)(i) definition ‘‘RVOCB,i’’, (a)(1)(ii) definition ‘‘RVOBBD,i’’, (a)(1)(iii) definition ‘‘RVOAB,i’’, (a)(1)(iv) definition ‘‘RVORF,i, (a)(5) introductory text, and (a)(6); and ■ b. Adding paragraph (a)(1)(v), (a)(1)(vi), (a)(1)(vii), (a)(1)(viii), The additions and revisions read as follows: § 80.1427 How are RINs used to demonstrate compliance? (a) Renewable Volume Obligations and Exporter Renewable Volume Obligations. (1) Except as specified in paragraph (b) of this section or § 80.1456, each party that is an obligated party under § 80 1406 and is obligated to meet the Renewable Volume Obligations under § 80.1407, or is an exporter of renewable fuel that is obligated to meet the Exporter Renewable Volume Obligations under § 80.1430, must demonstrate pursuant to § 80.1451(a)(1) that it is retiring for compliance purposes a sufficient number of RINs to satisfy the following equations. (i) * * * RVOCB,i = The renewable Volume Obligation for cellulosic biofuel for the obligated party for calendar year i, in gallons, pursuant to § 80.1407. (ii) * * * RVOBBD,i = The renewable Volume Obligation for biomass-based diesel for the obligated party for calendar year i, in gallons, pursuant to § 80.1407. (iii) * * * RVOAB,i = The renewable Volume Obligation for advanced biofuel for the obligated party for calendar year i, in gallons, pursuant to 80.1407. (iv) * * * RVORF,i = The renewable Volume Obligation for renewable fuel for the obligated party for calendar year i, in gallons, pursuant to 80.1407. (v) Cellulosic biofuel—Exporter. (SRINNUM)CB,i+ (SRINNUM)CB,i¥1= ERVOCB,i Where: (SRINNUM)CB,i= Sum of all owned gallonRINs that are valid for use in complying PO 00000 Frm 00033 Fmt 4701 Sfmt 4702 36073 with the cellulosic biofuel ERVO, were generated in year i, and are being applied towards the ERVOCB,i, in gallons. (SRINNUM)CB,i-1= Sum of all owned gallonRINs that are valid under subparagraph (6) of this paragraph for use in complying with the cellulosic biofuel ERVO, were generated in year i-1, and are being applied towards the ERVOCB,i, in gallons. ERVOCB, k= The Exporter Renewable Volume Obligation for cellulosic biofuel for the renewable fuel exporter for an export of renewable fuel k, in gallons, pursuant to § 80.1430. (vi) Biomass-based diesel—Exporter. (SRINNUM)BBD,i+ (SRINNUM)BBD,i-1= ERVOBBD,i Where: (SRINNUM)BBD,i= Sum of all owned gallonRINs that are valid for use in complying with the biomass-based diesel ERVO, were generated in year i, and are being applied towards the ERVOBBD,i, in gallons. (SRINNUM)BBD,i-1= Sum of all owned gallon-RINs that are valid under subparagraph (6) of this paragraph for use in complying with the biomass-based diesel ERVO, were generated in year i-1, and are being applied towards the ERVOBBD,i, in gallons. ERVOBBD,i= The Exporter Renewable Volume Obligation for biomass-based diesel for the renewable fuel exporter for an export of renewable fuel I after 2010, in gallons, pursuant to § 80.1430. (vii) Advanced biofuel—Exporter. (SRINNUM)AB,i+ (SRINNUM)AB,i-1= ERVOAB,i Where: (SRINNUM)AB,i= Sum of all owned gallonRINs that are valid for use in complying with the advanced biofuel ERVO, were generated in year i, and are being applied towards the ERVOAB,i, in gallons. (SRINNUM)AB,i-1= Sum of all owned gallonRINs that are valid under subparagraph (6) of this paragraph for use in complying with the advanced biofuel ERVO, were generated in year i-1, and are being applied towards the ERVOAB,i, in gallons. ERVOAB,i= The Exporter Renewable Volume Obligation for advanced biofuel for the renewable fuel exporter for an export of renewable fuel i, in gallons, pursuant to § 80.1430. (viii) Renewable fuel—Exporter. (SRINNUM)RF,i+ (SRINNUM)RF,i-1= ERVORF,i Where: (SRINNUM)RF,i= Sum of all owned gallonRINs that are valid for use in complying with the renewable fuel (D code 6) E ERVORF,i, in gallons. (SRINNUM)RF,i-1= Sum of all owned gallonRINs that are valid under subparagraph (6) of this paragraph for use in complying with the renewable fuel (D code 6) ERVO, were generated in year i- E:\FR\FM\14JNP2.SGM 14JNP2 36074 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 1, and are being applied towards the ERVORF,i, in gallons. ERVORF,i= The exporter Renewable Volume Obligation for renewable fuel for the renewable fuel exporter for an export of renewable fuel i, in gallons, pursuant to § 80.1430. * * * * * (5) The value of (SRINNUM)i-1 may not exceed values determined by the following inequalities as provided in paragraph (a)(7)(iii) of this section and 80.1442(d), for obligated parties only. * * * * * (6) Except as provided in paragraph (a)(7) of this section: (i) For obligated parties, RINs may only be used to demonstrate compliance with the RVOs for the calendar year in which they were generated or the following calendar year. (ii) [Reserved.] (iii) For Renewable Fuel Exporters, RINs generated in calendar year i, must be used to demonstrate compliance with the ERVOs from renewable fuel export(s) in calendar year i, except as provided in paragraph (a)(6)(iv) of this section. (iv) For Renewable Fuel Exporters, RINs generated in calendar year i-1, may only be used to demonstrate compliance with the ERVOs from renewable fuel exports in January of calendar year i. * * * * * ■ 7. Section 80.1441 is amended by adding paragraph (e)(2)(iii) to read as follows: § 80.1441 Small refinery exemption. * * * * (e) * * * (2) * * * (iii) In order to qualify for an extension of its small refinery exemption, a refinery must meet the definition of ‘‘small refinery’’ in § 80.1401 for all full calendar years between 2006 and the date of submission of the petition for an extension. * * * * * ■ 8. Section 80.1450 is amended by: ■ a. Adding paragraph (b)(1)(iv)(C); ■ b. Revising paragraphs (b)(1)(v)(C), (b)(1)(v)(D); and adding (b)(1)(v)(E); and ■ c. Adding paragraphs (h) and (i). The additions and revisions read as follows: mstockstill on DSK4VPTVN1PROD with PROPOSALS2 * § 80.1450 What are the registration requirements under the RFS program? * * * * * (b) * * * (1) * * * (iv) * * * (C) To demonstrate compliance with the renewable electricity production requirement for the biogas-derived VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 cellulosic diesel and cellulosic naphtha pathways, provide all the following information: (1) The energy source, equipment and/or process used to generate the electricity. Permitted sources are raw landfill gas, waste heat from the production process, unconverted syngas from the Fischer-Tropsch process, fuel gas from the hydroprocessing, or combined heat-and-power (CHP) units that use non-fossil fuel based gas or other renewable sources. (2) Estimates of the total amount of electricity to be used, the total amount of grid electricity to be purchased, the total amount of renewable electricity to be produced, and a calculation of the percent of total process electricity use to be produced from allowed sources at the facility. (v) * * * (C)(1) For all facilities, copies of documents demonstrating each facility’s actual peak capacity as defined in § 80.1401 if the maximum rated annual volume output of renewable fuel is not specified in the air permits specified in paragraphs (b)(1)(v)(A) and (b)(1)(v)(B) of this section, as appropriate. (2) For facilities claiming the exemption described in § 80.1403 (c) or (d) which are exempt from air permit requirements and for which insufficient production records exist to establish actual peak capacity, copies of document demonstrating the facility’s nameplate capacity, as defined in § 80.1401. (D) For all facilities producing renewable electricity or fuel from biogas that qualifies as renewable fuel, submit all relevant information in § 80.1426(f)(10) or (11), and copies of all contracts that the track the biogas or renewable electricity from its original source, to the producer that processes it into renewable fuel, and finally to the end user that will actually use the renewable electricity or the renewable fuel derived from biogas for transportation purposes. (1) Specific quantity and the heat content, percent efficiency of transfer, if applicable, and any conversion factors of the biogas or renewable biomass. (2) Specific quantity and the heat content and percent efficiency of transfer, if applicable, and any conversion factors for the renewable fuel derived from biogas or renewable electricity. (E) Such other records as may be requested by the Administrator. * * * * * (h) Cancellation of Company Registration. (1) EPA may cancel a company’s registration, using the PO 00000 Frm 00034 Fmt 4701 Sfmt 4702 process in paragraph (h)(2) of this section, if any of the following circumstances exist: (i) The company has reported no activity in EMTS for one calendar year (January 1 through December 31) or has failed to meet any EMTS requirement under § 80.1452; (ii) The company has failed to comply with the registration requirements of this section; (iii) The company has failed to submit any required report within thirty (30) days of the required submission date under § 80.1451; or (iv) The attest engagement required under § 80.1454 has not been received within thirty (30) days of the required submission date. (2) EPA will use the following process whenever it decides to cancel the registration of a company: (i) EPA will notify the company’s owner or Responsible Corporate Officer (RCO), in writing, that it intends to cancel the company’s registration, and identifying the reasons for that proposed action. The company will have fourteen (14) calendar days from the date of the notification to correct the deficiencies identified or explain why there is no need for corrective action. (ii) If the basis for EPA’s notice of intent to cancel registration is the absence of EMTS activity for one calendar year, a stated intent to engage in activity reported through EMTS within the next calendar year will be sufficient to avoid cancellation of registration. (iii) If the company does not respond, does not correct identified deficiencies, or does not explain why such correction is not necessary within the time allotted for response, EPA may cancel the company’s registration within further notice to the party. (3) Impact of registration cancellation. (i) A company whose registration is cancelled shall still be liable for violation of any requirements of this subpart. (ii) A company whose registration is cancelled will not be listed on any public list of actively registered companies that is maintained by EPA. (iii) If the company whose registration is cancelled is a renewable fuel producer or foreign ethanol producer, it will not be listed on any public list of registered producers maintained by EPA. (iv) A company whose registration is cancelled will not have access to any of the electronic reporting systems associated with the renewable fuel standard program, including the EPA Moderated Transaction System (EMTS). E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules (v) A company whose registration is canceled must submit any corrections of deficiencies to EPA on forms, and following policies, established by EPA. (vi) If a company whose registration has been canceled wishes to re-register, they may initiate that process by submitting a new registration, consistent with paragraphs (a)–(c) of this section. (vii) English language registrations. Any document submitted to EPA under § 80.1450 must be submitted in English, or shall include an English translation. ■ 9. Section 80.1451 is amended by revising paragraphs (a)(1)(vi) and (b)(1)(ii)(Q), and by adding paragraph (h) to read as follows: mstockstill on DSK4VPTVN1PROD with PROPOSALS2 § 80.1451 What are the reporting requirements under the RFS program? (a) * * * (1) * * * (vi) The RVOs for obligated parties, as defined in § 80.1427(a) and for exporters of renewable fuel, as defined in § 80.1427(a) and 80.1430(b), for the reporting year. * * * * * (b) * * * (1) * * * (ii) * * * (Q) Producers or importers of renewable fuel produced at facilities that use biogas for process heat as described in § 80.1426(f)(12), shall report the total energy supplied to the renewable fuel facility, in MMBtu based on metering of gas volume. Producers or importers of renewable fuel produced at facilities that meet the renewable electricity production requirement for the biogas-derived cellulosic diesel and cellulosic naphtha pathways as described in § 80.1426(f)(13), shall report the total renewable electricity produced by the renewable facility, in kilowatt-hour (kWh) or megawatt-hour (MWh), the total amount of electricity used, the total amount of grid electricity purchased, and a calculation verifying the percent of total process electricity from allowed sources produced on-site. * * * * * (h) English language reports. Any document submitted to EPA under § 80.1451 must be submitted in English, or shall include an English translation. ■ 10. Amend Section 80.1452 to revise paragraph (c) introductory text and add paragraphs (e) and (f) to read as follows: § 80.1452 What are the requirements related to the EPA Moderated Transaction System (EMTS)? * * * * * (c) Starting July 1, 2010, each time any party sells, separates, or retires RINs generated on or after July 1, 2010, all of the following information must be VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 submitted to EPA via the submitting party’s EMTS account within five (5) business days of the reportable event, except as provided in § 80.1430(f). Starting July 1, 2010, each time any party purchases RINs generated on or after July 1, 2010, all the following information must be submitted to EPA via the submitting party’s EMTS account within ten (10) business days of the reportable event. The reportable event for a RIN separation occurs on the date of separation as described in § 80.1429. The reportable event for a RIN retirement occurs on the date of retirement as described in this subpart. * * * * * (e) [Reserved.] (f) [Reserved.] ■ 11. Amend Section 80.1454 by ■ a. Adding paragraph (a)(7); ■ b. Revising paragraph (b)(4)(i); ■ c. Adding paragraph (b)(7); ■ d. Revising paragraph (f)(3)(i) and adding paragraph (f)(5); and ■ e. Revising paragraph (k)(1); and ■ f. Adding paragraph (q). The additions and revisions read as follows: § 80.1454 What are the recordkeeping requirements under the RFS program? * * * * * (a) * * * (7) Records related to any volume of renewable fuel that was disqualified by the party pursuant to § 80.1433: (b) * * * (4) * * * (i) A list of the RINs owned, purchased, sold, separated, retired, or reinstated. * * * * * (7) Records related to any volume of renewable fuel where RINs were not generated by the renewable fuel producer or importer pursuant to § 80.1426(c): * * * * * (f) * * * (3) * * * (i) A list of the RINs owned, purchased, sold, separated, retired, or reinstated. * * * * * (5) Records related to any volume of renewable fuel that was disqualified by the party pursuant to § 80.1433. * * * * * (k)(1) Biogas and electricity in pathways involving feedstocks other than grain sorghum. A renewable fuel producer that generates RINs for renewable CNG/LNG or renewable electricity produced from renewable biomass for fuels that are used for transportation pursuant to § 80.1426(f)(10) and (11), or that uses PO 00000 Frm 00035 Fmt 4701 Sfmt 4702 36075 process heat from biogas to generate RINs for renewable fuel pursuant to § 80.1426(f)(12) or that meets the renewable electricity production requirement for the biogas-derived cellulosic diesel and cellulosic naphtha pathways pursuant to § 80.1426(f)(13) shall keep all of the following additional records: (i) Documents demonstrating the kilowatt-hours (kWh) of allowable electricity relied upon under § 80.1426(f)(13) that was generated at the facility, if applicable. (ii) The energy source, equipment and/or process used to generate the electricity relied upon under § 80.1426(f)(13), if applicable. Permitted sources are raw landfill gas, waste heat from the production process, unconverted syngas from the FischerTropsch process, fuel gas from the hydroprocessing, or combined heat-andpower (CHP) units that use non-fossil fuel based gas or other renewable sources. (iii) Contracts and documents memorializing the sale of renewable CNG/LNG or renewable electricity for use as transportation fuel relied upon in § 80.1426(f)(10), § 80.1426(f)(11), or for use of biogas for use as process heat to make renewable fuel as relied upon in § 80.1426(f)(12) and the transfer of title of the biogas or renewable electricity and all associated environmental attributes from the point of generation to the facility which sells or uses the fuel for transportation purposes. (iv) Documents demonstrating the volume and energy content of biogas, or kilowatts of renewable electricity, relied upon under § 80.1426(f)(10) that was delivered to the facility which sells or uses the fuel for transportation purposes. (v) Documents demonstrating the volume and energy content of biogas, or kilowatts of renewable electricity, relied upon under § 80.1426(f)(11), or biogas relied upon under § 80.1426(f)(12) that was placed into the common carrier pipeline (for biogas) or transmission line shared power grid (for renewable electricity). (vi) Documents demonstrating the volume and energy content of biogas relied upon under § 80.1426(f)(12) at the point of distribution. (vii) Affidavits from the biogas or renewable electricity producer and all parties that held title to the biogas or renewable electricity confirming that title and environmental attributes of the biogas or renewable electricity relied upon under § 80.1426(f)(10) and (11) were used for transportation purposes only, and that the environmental attributes of the biogas or process E:\FR\FM\14JNP2.SGM 14JNP2 36076 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules electricity relied upon under § 80.1426(f)(12) or § 80.1426(f)(13) were used for process heat or electricity at the renewable fuel producer’s facility, and for no other purpose. The renewable fuel producer shall create and/or obtain these affidavits at least once per calendar quarter. (viii) The biogas or renewable electricity producer’s Compliance Certification required under Title V of the Clean Air Act. (ix) Documents demonstrating the total amount of grid electricity purchased and calculations showing the percent of total electricity usage provided by allowable electricity production at the facility, if applicable. (x) Such other records as may be requested by the Administrator. * * * * * (q) English language records. Any document requested by the Administrator under this section must be submitted in English, or shall include an English translation. ■ 12. Section 80.1463 is amended by adding paragraph (d) to read as follows: § 80.1463 What penalties apply under the RFS program? * * * * * (d) Any person violating § 80.1460(b)(1)–(4) or (6) engages in a separate violation for each day that an invalid RIN remains available for use in RFS compliance, and each such daily violation is punishable by the maximum daily penalty allowed under the Clean Air Act. ■ 13. Section 80.1466 is amended by revising the section heading and paragraphs (a), (d)(1), (d)(1)(vi), (d)(3)(ii), (e)(1)(i), (f) introductory text, (h), (h)(1), and (o)(2) and adding paragraph (p) as follows: mstockstill on DSK4VPTVN1PROD with PROPOSALS2 § 80.1466 What are the additional requirements under this subpart for RINgenerating foreign producers, non RINgenerating foreign producers, foreign ethanol producers and importers of renewable fuels? (a) Foreign producer of renewable fuel. For purposes of this subpart, a foreign producer of renewable fuel is a person located outside the United States, the Commonwealth of Puerto Rico, the Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern Mariana Islands (collectively referred to in this section as ‘‘the United States’’) that has been registered with EPA as a renewable fuel producer or foreign ethanol producer, regardless of whether the foreign renewable fuel producer generates RINs or an importer of renewable fuel generates RINs for the VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 fuel. Hereinafter referred to as a ‘‘foreign producer’’ under this section. (d) * * * (1) On each occasion that RFS–FRRF is loaded onto a vessel for transport to the United States the foreign producer shall have an independent third party do all the following: * * * * * (vi) Review original documents that reflect movement and storage of the RFS–FRRF from the foreign producer to the load port, and from this review determine all the following: * * * * * (3) * * * (ii) Be independent under the criteria specified in § 80.65(f)(2)(iii); and * * * * * (e) * * * (1)(i) Any foreign producer and any United States importer of RFS– FRRF shall compare the results from the load port testing under paragraph (d) of this section, with the port of entry testing as reported under paragraph (k) of this section, for the volume of renewable fuel, standardized per § 80.1426(f)(8), except as specified in paragraph (e)(1)(ii) of this section. * * * * * (f) Foreign producer commitments. Any foreign producer shall commit to and comply with the provisions contained in this paragraph (f) as a condition to being approved as a foreign producer under this subpart. * * * * * (h) Bond posting. Any foreign producer shall meet the requirements of this paragraph (h) as a condition to approval as a foreign producer under this subpart and on a continuing basis if the foreign producer exceeds projections used in calculated the bond. (1) The foreign producer shall post a bond of the amount calculated using one of the two following equations whichever equation results in a higher bond value: Bond = G * $0.01 Or Bond = .25 * S(Mi * RINi) Where: Bond = amount of the bond in U.S. dollars. G = the greater of: the largest volume of renewable fuel produced by the foreign producer and exported to the United States, in gallons, during a single calendar year among the five preceding calendar years, or the largest volume of renewable fuel that the foreign producer expects to export to the Unites States during any calendar year identified in the Production Outlook Report required by § 80.1449. If the volume of renewable fuel anticipated to be exported to the United States during any calendar year increases above the value used in PO 00000 Frm 00036 Fmt 4701 Sfmt 4702 calculating the existing bond amount, the foreign producer shall increase the bond by using the higher anticipated export volume for the calendar year to calculate a higher bond amount and purchasing the higher bond prior to the generation of RINs to reflect the increase in export volume. Mi = RIN multiplier for specified D code, i, in U.S. dollars, as follows: The RIN multiplier for a D3 RIN is $0.78 The RIN multiplier for a D4 RIN is $1.30 The RIN multiplier for a D5 RIN is $0.80 The RIN multiplier for a D6 RIN is $0.02 The RIN multiplier for a D7 RIN is $0.78 RINi = the greater of: (i) the largest quantity of RINs for a specified D code, i, produced by the foreign producer and exported to the United States, in gallons, during a single calendar year among the five preceding calendar years, or (ii) the largest quantity of RINs that the foreign producer expects to export to the United States during any calendar year identified in the Production Outlook Report required by § 80.1449. If the volume of renewable fuel anticipated to be exported to the United States during any calendar year increases above the value used in calculating the existing bond amount, the foreign producer shall increase the bond by using the higher anticipated export volume for the calendar year to calculate a higher bond amount and purchasing the higher bond prior to the generation of RINs to reflect the increased export volume. * * * * * (o) (2) Signed by the president or owner of the foreign producer company, or by that person’s immediate designee, and shall contain the following declaration: ‘‘I hereby certify: (1) That I have actual authority to sign on behalf of and to bind [INSERT NAME OF FOREIGN PRODUCER] with regard to all statements contained herein; (2) that I am aware that the information contained herein is being Certified, or submitted to the United States Environmental Protection Agency, under the requirements of 40 CFR part 80, subpart M, and that the information is material for determining compliance under these regulations; and (3) that I have read and understand the information being Certified or submitted, and this information is true, complete and correct to the best of my knowledge and belief after I have taken reasonable and appropriate steps to verify the accuracy thereof. I affirm that I have read and understand the provisions of 40 CFR part 80, subpart M, including 40 CFR 80.1466 apply to [INSERT NAME OF FOREIGN PRODUCER]. Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 1001, the penalty for furnishing false, incomplete or misleading information in this certification or submission is a fine of E:\FR\FM\14JNP2.SGM 14JNP2 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules § 80.1500 Definitions. * * * * E10 means a gasoline-ethanol blend that contains at least 9 and no more than 10 volume percent ethanol. E15 means a gasoline-ethanol blend that contains greater than 10 volume percent ethanol and not more than 15 volume percent ethanol. EX means a gasoline–ethanol blend that contains less than 9 volume percent ethanol where X equals the maximum volume percent ethanol in the gasolineethanol blend. * * * * * ■ 15. Section 80.1501 is amended by revising the section 80.1501 heading paragraphs (a) introductory text, (b)(3)(i) and (iv), and (b)(4)(ii) to read as follows: mstockstill on DSK4VPTVN1PROD with PROPOSALS2 * Where: n = minimum number of samples in a yearlong survey series. However, in no case shall n be smaller than 7,500. Za = upper percentile point from the normal distribution to achieve a one-tailed 95% confidence level (5% a-level). Thus, Za equals 1.645. Zb = upper percentile point to achieve 95% power. Thus, Zb equals 1.645. VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 § 80.1501 What are the labeling requirements that apply to retailers and wholesale purchaser-consumers of gasoline-ethanol blends that contain greater than 10 volume percent ethanol and not more than 15 volume percent ethanol? * * * * (b) * * * (3) * * * (iii) * * * (A) Samples collected at retail outlets shall be shipped the same day the samples are collected via ground service to the laboratory and analyzed for oxygenate content. Samples collected at a dispenser labeled E15 in any manner, or at a tank serving such a dispenser, shall also be analyzed for RVP during the high ozone season defined in § 80.27(a)(2)(ii) or any SIP approved or promulgated under §§ 110 or 172 of the Clean Air Act. Such analysis shall be completed within 10 days after receipt of the sample in the laboratory. Nothing in this section shall be interpreted to require RVP testing of a sample from any dispenser or tank serving it unless the dispenser is labeled E15 in any manner. * * * * * (iv) In the case of any test that yields a result that does not match the label affixed to the product (e.g., a sample greater than 15 volume percent ethanol dispensed from a fuel dispenser labeled as ‘‘E15’’ or a sample containing greater than 10 volume percent ethanol and not more than 15 volume percent ethanol dispensed from a fuel dispenser not labeled as ‘‘E15’’), or the RVP standard of § 80.27(a)(2), the independent survey association shall, within 24 hours after the laboratory has completed analysis of the sample, send notification of the test result as follows: * * * * * (4) * * * (iv) * * * (B) In the case of any retail outlet from which a sample of gasoline was collected during a survey and determined to have an ethanol content that does not match the fuel dispenser label (e.g. a sample greater than 15 volume percent ethanol dispensed from a fuel dispenser labeled as ‘‘E15’’ or a sample with greater than 10 volume percent ethanol and not more than 15 volume percent ethanol dispensed from a fuel dispenser not labeled as ‘‘E15’’) or determined to have a dispenser containing fuel whose RVP does not comply with § 80.27(a)(2), that retail outlet shall be included in the subsequent survey. * * * * * (v) * * * (A) The minimum number of samples to be included in the survey plan for each calendar year shall be calculated as follows: f1 = the maximum proportion of noncompliant stations for a region to be deemed compliant. In this test, the parameter needs to be 5% or greater, i.e., 5% or more of the stations, within a stratum such that the region is considered non-compliant. For this survey, f1 will be 5%. fo= the underlying proportion of noncompliant stations in a sample. For the first survey plan, fo will be 2.3%. For subsequent survey plans, fo will be the average of the proportion of stations found to be non-compliant over the previous four surveys. Stn = number of sampling strata. For purposes of this survey program, Stn equals 3. Fa = adjustment factor for the number of extra samples required to compensate for collected samples that cannot be included in the survey, based on the (a) Any retailer or wholesale purchaser-consumer who sells, dispenses, or offers for sale or dispensing E15 shall affix the following conspicuous and legible label to the fuel dispenser: * * * * * (b) * * * (3) * * * (i) The word ‘‘ATTENTION’’ shall be capitalized in 20-point, orange, Helvetica Neue LT 77 Bold Condensed font, and shall be placed in the top 1.25 inches of the label as further described in (b)(4)(iii) below. * * * * * (iv) The words ‘‘Use only in’’ shall be in 20-point, left-justified, black, Helvetica Bold font in the bottom 1.875 inches of the label. (4) * * * * * * * * (ii) The background of the bottom 1.875 inches of the label shall be orange. * * * * * ■ 16. Section 80.1502 is amended by revising paragraphs (b)(3)(iii)(A), (b)(3)(iv), (b)(4)(iv)(B), (b)(4)(v)(A), (c)(4), and (c)(6) to read as follows: § 80.1502 What are the survey requirements related to gasoline-ethanol blends? * PO 00000 Frm 00037 Fmt 4701 Sfmt 4702 E:\FR\FM\14JNP2.SGM 14JNP2 EP14JN13.003</GPH> up to $10,000 U.S., and/or imprisonment for up to five years.’’ (p) Foreign Produced Renewable Fuel and Foreign Produced Ethanol for Which RINs Have Been or Will Be Generated by the Importer (1) For non-RIN generating foreign producers and foreign ethanol producers already registered pursuant to section § 80.1450, all of the requirements in paragraphs (a) through (o) of this section must be satisfied no later than January 1, 2013. (2) For RIN generating foreign producers and foreign ethanol producers already registered pursuant to section § 80.1450 and 80.1466, paragraph (h) of this section must be satisfied no later than January 1, 2013 if the required amount in paragraph (h) of this section exceeds the original amount of the bond posted when the producer was originally approved under 80.1466. ■ 14. Section 80.1500 is amended by revising the definitions of E10, E15, and EX to read as follows: 36077 36078 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules number of additional samples required during the previous four surveys. However, in no case shall the value of Fa be smaller than 1.1. Fb = adjustment factor for the number of samples required to resample each retail outlet with test results exceeding the labeled amount (e.g. a sample greater than 15 volume percent ethanol dispensed from a fuel dispenser labeled as ‘‘E15’’, a sample with greater than 10 volume percent ethanol and not more than 15 volume percent ethanol dispensed from a fuel dispenser not labeled as ‘‘E15’’), or a sample dispensed from a fuel dispenser labeled as ‘‘E15’’ with greater than the applicable seasonal and geographic RVP pursuant to § 80.27, based on the rate of resampling required during the previous four surveys. However, in no case shall the value of Fb be smaller than 1.1. Sun = number of surveys per year. For purposes of this survey program, Sun equals 4. * * * * * (c) * * * (4) The survey program plan must be sent to the following address: Director, Compliance Division, U.S. Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Mail Code 6506J, Washington, DC 20460. * * * * * (6) The approving official for a survey plan under this section is the Director of the Compliance Division, Office of Transportation and Air Quality. * * * * * ■ 17. Section 80.1503 is amended by revising paragraphs (a)(1)(vi)(B)(3), (a)(1)(vi)(C)(2), adding paragraph (a)(1)(vi)(C)(3), and revising paragraphs (b)(1)(vi)(B) through (D). The revisions and additions read as follows: mstockstill on DSK4VPTVN1PROD with PROPOSALS2 § 80.1503 What are the product transfer document requirements for gasolineethanol blends, gasolines, and conventional blendstocks for oxygenate blending subject to this subpart? (a) * * * (1) * * * (vi) * * * (B) * * * (3) ‘‘The use of this blendstock/ gasoline to manufacture a gasolineethanol blend containing anything other than between 9 and 10 volume percent ethanol may cause a summertime RVP violation.’’ (C) * * * (2) The requirements in paragraph (a)(1) do not apply to reformulated gasoline blendstock for oxygenate blending, as defined in § 80.2(kk), which is subject to the product transfer VerDate Mar<15>2010 18:55 Jun 13, 2013 Jkt 229001 document requirements of § 80.69 and § 80.77. (3) Except for transfers to truck carriers, retailers, or wholesale purchaser-consumers, product codes may be used to convey the information required under paragraph (a)(1) of this section if such codes are clearly understood by each transferee. (b) * * * (1) * * * (vi) * * * (B) For gasoline containing less than 9 volume percent ethanol, the following statement: ‘‘EX—Contains up to X% ethanol. The RVP does not exceed [fill in appropriate value] psi.’’ The term X refers to the maximum volume percent ethanol present in the gasoline. (C) For gasoline containing between 9 and 10 volume percent ethanol (E10), the following statement: ‘‘E10: Contains between 9 and 10 vol % ethanol. The RVP does not exceed [fill in appropriate value] psi. The 1 psi RVP waiver applies to this gasoline. Do not mix with gasoline containing anything other than between 9 and 10 vol % ethanol.’’ (D) For gasoline containing greater than 10 volume percent and not more than 15 volume percent ethanol (E15), the following statement: ‘‘E15: Contains up to 15 vol % ethanol. The RVP does not exceed [fill in appropriate value] psi;’’ or * * * * * ■ 18. Section 80.1504 is amended by revising paragraphs (a)(1), (a)(3), (e), and (g) to read as follows: conventional blendstock for oxygenate blending, gasoline or gasoline already containing ethanol, in a manner inconsistent with the information on the product transfer document under § 80.1503(a)(1)(vi) or § 80.1503(b)(1)(vi); (2) No person shall produce E10 by blending ethanol and gasoline in a manner designed to produce a fuel that contains less than 9.0 or more than 10.0 volume percent ethanol. (3) No person shall produce E15 by blending ethanol and gasoline in a manner designed to produce a fuel that contains less than 10.0 volume percent ethanol or more than 15.0 volume percent ethanol. (4) No person shall produce EX by blending ethanol and gasoline in a manner designed to produce a fuel that contains less than 9.0 volume percent ethanol. * * * * * (g) For gasoline during the regulatory control periods, combine any gasolineethanol blend that qualifies for the 1 psi allowance under the special regulatory treatment as provided by § 80.27(d) applicable to 9–10 volume percent gasoline-ethanol blends with any gasoline containing less than 9 volume percent ethanol or more than 10 volume percent ethanol up to a maximum of 15 volume percent ethanol. * * * * * ■ 19. Section 80.1508 is amended by revising paragraph (b) as follows: § 80.1504 What acts are prohibited under this subpart? § 80.1508 What evidence may be used to determine compliance with the requirements of this subpart and liability for violations of this subpart? * * * * * (a)(1) Sell, introduce, cause or permit the sale or introduction of gasoline containing greater than 10 volume percent ethanol (i.e., greater than E10) into any model year 2000 or older lightduty gasoline motor vehicle, any heavyduty gasoline motor vehicle or engine, any highway or off-highway motorcycle, or any gasoline-powered nonroad engines, vehicles or equipment. * * * * * (3) Notwithstanding paragraphs (a)(1) and (a)(2) of this section, no person shall be prohibited from manufacturing, selling, introducing, or causing or allowing the sale or introduction of gasoline containing greater than 10 volume percent ethanol into any flexfuel vehicle. * * * * * (e)(1) Improperly blend, or cause the improper blending of, ethanol into PO 00000 Frm 00038 Fmt 4701 Sfmt 9990 * * * * * (b) Determinations of compliance with the requirements of this subpart and determinations of liability for any violation of this subpart may be based on information obtained from any source or location. Such information may include, but is not limited to, business records and commercial documents. ■ 20. Section 80.1509 is added to read as follows: § 80.1509 Rounding a test result for purposes of this Subpart. The provisions of Section 80.9 apply for purposes of determining the ethanol content of a gasoline-ethanol blend under this subpart. [FR Doc. 2013–12714 Filed 6–13–13; 8:45 am] BILLING CODE 6560–50–P E:\FR\FM\14JNP2.SGM 14JNP2

Agencies

ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 78, Number 115 (Friday, June 14, 2013)]
[Proposed Rules]
[Pages 36041-36078]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-12714]

[[Page 36041]]

Vol. 78

Friday,

No. 115

June 14, 2013

Part II

Environmental Protection Agency

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

40 CFR Part 80

Regulation of Fuels and Fuel Additives: RFS Pathways II and Technical
Amendments to the RFS 2 Standards; Proposed Rule

Federal Register / Vol. 78 , No. 115 / Friday, June 14, 2013 /
Proposed Rules

[[Page 36042]]

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

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:
https://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 https://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

[[Page 36043]]

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:

----------------------------------------------------------------------------------------------------------------
NAICS Codes Examples of potentially regulated
Category \a\ SIC Codes \b\ 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

[[Page 36044]]

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

[[Page 36045]]

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. https://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\
------------------------------------------------------------------------
Average adjusted
cellulosic
Feedstock type 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, https://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.

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

[[Page 36046]]

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

[[Page 36047]]

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

[[Page 36048]]

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 Sec.
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 Sec. 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 Sec.
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 https://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

[[Page 36049]]

Sec. 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. https://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 https://www.epa.gov/lmop/projects-candidates/.
\22\ Environmental Protection Agency, Landfill Methane Outreach
Program. 2010. LFG Energy Project Development Handbook: Chapter 2.
Landfill Gas Modeling. https://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

[[Page 36050]]

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, https://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.

[[Page 36051]]

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
----------------------------------------------------------------------------------------------------------------
GHG emissions
---------------------------------------------------------------
Renewable electricity 2005 Gasoline U.S. Average
-------------------------------- baseline grid
Lifecycle stage ---------------- electricity
kg CO2-eq/ kg CO2-eq/ ---------------
mmBtu mmBtu fuel kg CO2-eq/ kg CO2-eq/
electricity equivalent mmBtu fuel 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 CO2-eq/mmBtu electricity, or 4
kg CO2-eq/mmBtu fuel equivalent. Compared with the gasoline
baseline GHG emissions of 98 kg CO2-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, https://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

[[Page 36052]]

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 CO2-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. https://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-
CO2 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. https://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, https://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
----------------------------------------------------------------------------------------------------------------
GHG emissions (kg CO2-eq/mmBtu)
---------------------------------------------------------------
Biofuels Petroleum baselines
Lifecycle stage ---------------------------------------------------------------
Renewable 2005 diesel 2005 gasoline
diesel Naphtha baseline 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

[[Page 36053]]

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,
https://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. https://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

[[Page 36054]]

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

[[Page 36055]]

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

[[Page 36056]]

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 Sec. 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 D-3 Cellulosic biofuel.
corn starch component).

[[Page 36057]]

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 Sec. 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 Sec. 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

[[Page 36058]]

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.
The emissions from the use of energy were calculated by multiplying
the amount of energy by emission factors for fuel production and
combustion, based on the same method and factors used in the RFS2 final
rulemaking. The emission factors for the different fuel types are from
GREET and were based on assumed carbon contents of the different
process fuels.
One area where EPA is soliciting comments is on the most
appropriate energy content assumption to use for butanol (lower heating
value). As part of this analysis, EPA used the GREET value for the
energy content of butanol,

[[Page 36059]]

which is 99,837 Btus per gallon.\49\ Differences in the measurement of
the energy content of butanol can occur for a number of reasons
including variations amongst isomers (t-butanol, n-butanol, isobutanol,
and sec-butanol), and differences in testing methodologies. EPA is
seeking comment on whether there are any reasons why EPA should change
its assumptions and use a different energy content of butanol.
---------------------------------------------------------------------------

\49\ The GREET value is based on: Guibet, J.-C., 1997,
Carburants et Moteurs: Technologies, Energie, Environnement,
Publication de l'Institut Fran[ccedil]ais du P[eacute]trole, ISBN 2-
7108-0704-1.
---------------------------------------------------------------------------

The RFS2 corn butanol pathways included an estimate for DDGs co-
product production which we similarly applied to the advanced butanol
production process. Since DDGs impact the agricultural markets,
production of DDGs was already included as part of the FASOM and FAPRI
modeling already described in the feedstock production section, above.
Thus no additional co-product credits for the DDGs are applied for the
fuel production stage of the analysis.
The advanced butanol production process analyzed here also results
in excess electricity production. As per the pathway description the
process produces excess electricity of at least 40% of the purchased
natural gas energy of the facility. The onsite emissions of the
electricity production are accounted for in the facility natural gas
and biogas use. The co-product credit of the excess electricity is
accounted for by assuming the electricity offsets average grid
electricity production and results in associated emission reductions.
The estimated production emissions from the advanced butanol
process are shown below in Table V.F.-1.

Table V.F.-1--Fuel Production Emissions for the Advanced Butanol Process
------------------------------------------------------------------------
GEVO isobutanol (g CO2-
Fuel production source eq./mmBtu)
------------------------------------------------------------------------
On-Site Emissions.............................. 15,273
Upstream (natural gas and electricity 2,424
production)...................................
Emissions Credit from Offset Electricity....... -17,448
------------------------
Total Fuel Production Emissions.............. 249
------------------------------------------------------------------------

Fuel and feedstock distribution--We used the same feedstock
distribution emissions assumption considered for corn butanol under the
RFS2 final rule for the advanced butanol pathway corn feedstock. The
fuel type, butanol, and hence the fuel distribution for butanol, was
already considered as part of the RFS2 final rule. Therefore, the
existing feedstock and fuel distribution lifecycle GHG impacts for corn
butanol were applied to the advanced butanol pathway analysis.
Use of the fuel--The advanced butanol pathway produces a fuel that
was analyzed as part of the RFS2 final rule. Thus, the fuel combustion
emissions calculated as part of the RFS2 final rule for butanol were
applied to our analysis of the advanced butanol pathway.
The advanced butanol fuel was then compared to baseline petroleum
gasoline, using the same value for baseline gasoline as in the RFS2
final rule analysis. The results of the analysis indicate that the
advance butanol pathway would result in a GHG emissions reduction of
51.3% compared to the gasoline fuel it would replace.
Based on our LCA, we are proposing to add a new pathway to Table 1
to section 80.1426 that includes butanol from corn starch using the
butanol process described here as an advanced biofuel (D-5 RINs). EPA
invites comments on the assumptions used in this analysis.
Table V.F.-2 below breaks down by stage the lifecycle GHG emissions
for the RFS2 corn butanol pathway, the advanced butanol pathway and the
2005 gasoline baseline. This table demonstrates the contribution of
each stage in the fuel pathway and its relative significance in terms
of GHG emissions.

Table V.F.-2--Lifecycle GHG Emissions for the Advanced Butanol Pathway, 2022
[Kg CO2-eq./mmBtu]
----------------------------------------------------------------------------------------------------------------
RFS2 corn
ethanol, natural RFS2 2005
Fuel type gas fired dry GEVO butanol gasoline
mill 63% dry baseline
DDGS
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change)............ 4 4 ................
Net International Agriculture (w/o land use change)....... 12 12 ................
Domestic Land Use Change.................................. -4 -4 ................
International Land Use Change, Mean (Low/High)............ 32 (21/46) 31 ................
Fuel Production........................................... 28 0 19
Fuel and Feedstock Transport.............................. 4 4 *
Tailpipe Emissions........................................ 1 1 79
-----------------------------------------------------
Total Emissions, Mean................................. 77 (66/91) 48 98
% Reduction............................................... -21% -51% ................
----------------------------------------------------------------------------------------------------------------
* Emissions included in fuel production stage.

Table V.F.-3 lists the proposed D-Codes by fuel type (butanol),
considering the feedstock (corn starch) and different production
process requirements.

[[Page 36060]]

Table V.F.-3--Proposed D Codes for Butanol
----------------------------------------------------------------------------------------------------------------
Production process
Fuel type Feedstock requirements D-Code
----------------------------------------------------------------------------------------------------------------
Butanol.......................... Corn starch..................... Fermentation; dry mill 6
using natural gas,
biomass, or biogas for
process energy.
Butanol.......................... Corn starch..................... Fermentation; dry mill 5
using natural gas and
biogas from on-site thin
stillage anaerobic
digester for process
energy w/CHP producing
excess electricity of at
least 40% of the purchased
natural gas energy used by
the facility.
----------------------------------------------------------------------------------------------------------------

2. Butanol, Biobutanol, and Volatility Considerations
Butanol is a flammable colorless liquid that is used as a fuel and
as an industrial solvent. Butanol is composed of the chemical elements
hydrogen, oxygen, and carbon. It can be made from petroleum or
renewable biomass, such as corn, grasses, agricultural waste and other
renewable sources. It can be used in internal combustion engines as an
additive to gasoline and is currently registered under the Fuel and
Fuel Additives Registration System (FFARS) for use at up to 12 volume
percent. A higher blend level would require a new FFARS registration
that would include meeting Tier 1 and Tier 2 health effects testing
requirements. Biobutanol is the common name for butanol made from
renewable sources.
There has been an increased interest in the use of biobutanol as a
direct result of the requirements for increased use of renewable fuel
volumes, adopted in EISA 2007. These provisions require an increase in
the use of renewable fuels, with 36 billion gallons of renewable fuel
to be used in the U.S. by 2022. Parties required to meet these
standards are interested in cost effective and practical ways to
satisfy the standards and meet the performance needs of the vehicles
and engines. Biobutanol is one attractive option because of its higher
energy density, lower blending vapor pressure, and lower heat of
vaporization in comparison to ethanol, as well as the fact that it can
be distributed as a gasoline blend throughout the fungible gasoline
distribution system.
The Clean Air Act (section 211(h)(4)) requires EPA to adopt
regulations limiting the volatility of gasoline during the summer
months, when ozone is of most concern, including a one pound per square
inch (psi) Reid Vapor Pressure (RVP) increase in the volatility limit
for blends of gasoline containing 9-10% ethanol (E10). This allowance
for a 1 psi increase in allowable volatility is commonly called the 1
psi waiver.
EPA's regulations at 40 CFR 80.27 adopt RVP standards that apply to
the gasoline at all points in the distribution system, including the
retail outlet. Under the provisions for the 1 psi waiver, blends of
gasoline that contain from 9 volume percent to 10 volume percent
ethanol are allowed to have volatility 1 psi higher than otherwise
would be allowed (40 CFR 80.27(d)(2)). The chemical characteristics of
ethanol are such that blends of gasoline with less than 9 volume
percent to 10 volume percent ethanol would still have a significant
increase in volatility. Thus the restriction on the 1 psi waiver to
blends that have 9 volume percent to 10 volume percent ethanol has the
effect of prohibiting the blending of E10 with other gasoline/renewable
fuel blends at any point in the gasoline distribution system (wholesale
or retail) in conventional gasoline areas during the summer control
season. Blends of E10 gasoline and gasoline that is not E10 would have
less than 9 volume percent or greater than 10 volume percent ethanol,
would have a resulting increase in volatility compared to E0, but would
not have the 1 psi waiver to allow for such an increase. This increase
would lead to an RVP above the allowable limit, unless a sub-RVP
gasoline blendstock was used. The practical effect is a prohibition on
commingling of E10 and gasoline blends other than E10.
Under the current regulations, EPA applies the RVP standard to the
commingled mixture as a whole, not to the components of the commingled
mixture. Once the ethanol and non-ethanol blends are mixed, the
commingled mixture is treated as the gasoline that is tested and
compared to the RVP standard. A single RVP value is determined by
testing the volatility of the commingled mixture, and this is compared
to the standard. If the mixture has from 9 volume percent to 10 volume
percent ethanol, then the 1 psi waiver applies to the mixture. If the
mixture has a different percentage of ethanol, whether lower or higher,
then the 1 psi waiver does not apply to the mixture.
This avoids a situation where there is an overall increase in
volatility because of the commingling of E10 and gasoline that is not
E10. As discussed below, the chemical characteristics of ethanol and
the nonlinear nature of the volatility increase associated with varying
volumes of ethanol, mean that mixing E10 gasoline with gasoline that is
not E10 typically results in a net overall increase in emissions--the
mixture has a higher volatility and emissions than the separate
gasolines had on average before they were mixed.
Several parties have identified this as an obstacle that currently
inhibits the opportunity for biobutanol to enter the commercial market.
The primary issue is application of the RVP regulations at the final
point of fuel dispensing, when the biobutanol (Bu) and the ethanol
blends would be mixed, that is in a storage tank at the retail station.
When a butanol product that complies with the RVP standards prior to
commingling (e.g., a complying Bu12 blend) is commingled with a
compliant E10 in underground storage tanks at fuel dispensing
facilities, the resulting mix generally would exceed the applicable RVP
standard as EPA's RVP regulations currently apply the standard. Certain
fuels, including renewable biofuels such as butanol, however, do not
have a net negative impact on RVP when blended with E10 at wholesale or
retail. That is, the RVP and related emissions of the commingled blend
of butanol and ethanol is no higher than the average RVP if the fuels
had never been commingled. Thus, in these kinds of circumstances it may
be appropriate to adopt a modified approach to applying the RVP
standard to permit the commingling of complying E10 blends with
complying butanol blends at wholesale and retail, as there is no
overall degradation of RVP and the air quality impacts compared to what
would occur if they were not blended.
Today, the agency is providing some additional background on this
issue and requesting information for use in deciding whether EPA can
and should modify its RVP regulations as discussed below. Specifically,
we are inviting comment on the ability of regulated parties to comply
with the existing regulations by segregating biobutanol blends from
ethanol blends and whether there is a need to change the regulations.
We are also seeking comment on an alternative approach to applying the
RVP standards to a commingled mixture of E10 with biobutanol or other
approved gasoline additives, where the additives have

[[Page 36061]]

characteristics such that there is no net adverse emissions effect from
the commingling. We are inviting comments as to whether the RVP
standards can and should be applied such that the commingled mixture of
E10 and specified blends of gasoline additives such as biobutanol is
treated as complying with the RVP standard as long as the components of
that mixture complied with the RVP standard prior to the commingling.
This approach would provide a limited modification to how the RVP
standards are applied, and the modification would apply for only
certain fuel mixtures--those where the overall or net volatility of the
commingled mixture is no higher than the weighted average of the
original blends themselves, such that there is no adverse impact on
emissions from the mixing compared to what would have occurred without
such mixing. In order to assist parties in preparing comments, EPA is
providing some additional background regarding the RVP program in the
following paragraphs.
Background and History of Volatility Regulations
Reid Vapor Pressure (RVP) is the most common measure of gasoline
volatility under ambient conditions. In 1989, EPA began reducing
gasoline volatility by limiting its RVP (54 FR 11868, March 22, 1989)
(40 CFR 80.27). Due to the presence of gasoline in certain markets
mixed with about 10 volume percent ethanol (known as gasohol at the
time), and because blending an alcohol into gasoline increases the
volatility of the final product, EPA provided an additional 1 psi
allowance for such blends. In the absence of the 1 psi allowance, a
special blend stock would have been required for such blends to comply
with the RVP standards and such sub-RVP blendstocks did not exist at
the time. EPA imposed the RVP standards at all points in the gasoline
distribution system, i.e., anywhere gasoline is sold, supplied, offered
for sale or supply or transported, including service stations, refinery
shipping, tanks, importer shipping tanks, pipeline and bulk terminals
and plants. (40 CFR 80.28) (1989). In 1990, the agency promulgated
additional regulations that further lowered the RVP standards. (55 FR
23658, June 11, 1990). EPA continued to provide both the 1.0 psi
allowance to fuel blends containing about 10 volume percent ethanol,
(40 CFR 80.27) (1990), and the requirement that RVP standards applied
at all points in the distribution system.
Congress largely codified the approach taken in EPA's RVP
regulations by adding a new section 211(h) in the 1990 CAA amendments.
Section 211(h)(1) requires EPA to set the maximum RVP standard during
the high ozone season as 9.0 psi. EPA was to ``promulgate regulations
making it unlawful for any person during the high ozone season to sell,
offer for sale, dispense, supply, offer for supply, transport, or
introduce into commerce gasoline with a Reid Vapor Pressure in excess
of 9.0 pounds per square inch (psi).'' Lower RVP standards could be set
for ozone nonattainment areas. See Clean Air Act section 211(h)(1).
Section 211(h)(2) addresses the RVP standard that apply in attainment
areas, and sets the standard at 9.0 psi for attainment areas with
authority for EPA to set a more stringent RVP level under certain
circumstances. In section 211(h)(2), Congress allowed a 1-psi waiver
for E10 gasoline, stating: ``For fuel blends containing gasoline and 10
percent denatured anhydrous ethanol, the Reid vapor pressure limitation
under this subsection shall be one pound per square inch (psi) greater
than the applicable Reid vapor pressure limitations established under
paragraph (1).'' Additionally, Congress enacted a conditional defense
against liability for violations of the RVP level allowed under the 1
psi waiver by stating that ``[p]rovided; however, that a distributor,
blender, marketer, reseller, carrier, retailer, or wholesale purchaser-
consumer shall be deemed to be in full compliance with the provisions
of this subsection and the regulations promulgated there under if it
can demonstrate that--(A) the gasoline portion of the blend complies
with the Reid vapor pressure limitations promulgated pursuant to this
subsection; (B) the ethanol portion of the blend does not exceed its
waiver condition under subsection (f)(4) of this section; and (C) no
additional alcohol or other additive has been added to increase the
Reid Vapor Pressure of the ethanol portion of this blend.'' Section
211(h)(4).
In a 1991 rulemaking, EPA modified the RVP regulations to conform
to the 1990 amendments (56 FR 64704, December 12, 1991). These
regulations addressed the RVP standards in attainment areas, required
the use of denatured anhydrous ethanol as a specific condition for the
1-psi waiver for fuel blends containing gasoline and from 9 volume
percent to 10 volume percent ethanol, and included a new defense
against liability for violations of the RVP standards for such fuel
blends. We made no changes to the requirement that the RVP standards
applied at all points in the distribution system.
What modification is EPA considering to the application of the RVP
standards to certain fuel blends?
Gasoline and ethanol are mixed or blended after the refining
process. The practice of blending ethanol with gasoline increases the
RVP of the resulting blend by approximately 1.0 psi. It is a non-linear
relationship, most of the volatility increase occurs after just a few
percent of ethanol have been added, with the volatility increasing more
slowly as the gasoline ethanol blend increases to 10 volume percent.
Above 10 volume percent the volatility generally does not increase any
more, and at even higher levels of ethanol the volatility starts to
decrease again. As explained above, section 211(h)(4) provides a 1-psi
waiver for fuel blends containing gasoline from 9 volume percent to 10
volume percent ethanol. The absence of such a waiver would have
required the creation of a production and distribution network for sub-
9.0 psi RVP gasoline, to offset the increase in volatility associated
with blending ethanol into the gasoline. At the time the costs of
producing and distributing an additional grade of this type of fuel,
especially in consideration of the low volumes of fuel being blended
with ethanol at the time, would have likely been prohibitive and
resulted in the termination of the availability of ethanol in the
marketplace. Thus, the 1-psi waiver facilitated the participation of
ethanol in the transportation fuel industry while also limiting
gasoline volatility resulting from ethanol blending.
But the RVP levels of gasoline actually used by consumers are
dependent on the mixture of alcohol blends and gasoline that are
commingling in either vehicle or storage tanks. Depending on the
mixture, the resulting RVP level could be significantly higher than the
average volatility of the fuels prior to the commingling. This is
because the volatility increase when ethanol is added to gasoline is
non-linear, with a large increase with the first few percent and then
slowly tapering off as the concentration increases (see Illustration
V.F.-4). In other words, mixing E10 and EO gasoline results in a net
increase in the volatility of the gasoline mixture, compared to the
average volatility that would occur absent such mixing. For example,
2000 gallons of 10 psi E10 added to a service station tank with 8000
gallons of 9.0 psi E0 would result in 10,000 gallons of fuel with a
volatility of approximately 10 psi. However if the fuels had not been
mixed, the average volatility of the 10000 gallons would

[[Page 36062]]

have been 9.2 psi. The emissions associated with the commingled mixture
(10000 gallons at 10 psi) would be significantly higher than the
emissions associated with the two separate blends of 2000 gallons at 10
psi and 8000 gallons at 9 psi. The commingling thus results in an
adverse environmental impact compared to what would occur absent the
commingling. EPA's current RVP regulations address this adverse
emissions impact by applying the RVP standard to the commingled mixture
as a single fuel. In this case the commingled mixture has an RVP of 10
psi. The 1 psi waiver does not apply as the mixture is now 2% ethanol,
not from 9 volume percent to 10 volume percent ethanol. The commingled
mixture thus would not comply with the 9.0 psi RVP standard,
effectively prohibiting such commingling.
As discussed earlier, the EPAct 2005 and EISA2007 mandated
increased volumes of renewable fuel for use in gasoline. This has
resulted in the increased use of ethanol. E10 is now present in nearly
all gasoline sold in the country. Recently, EPA granted a waiver from
the substantially similar requirements under section 211(f)(4) for the
use of E15 blends in MY2001 and newer light-duty vehicles (See 75 FR
68094, November 4, 2010 and 76 FR 4662, January 26, 2011). EPA
interpreted section 211(h) as not extending the 1 psi waiver to such
blends with ethanol levels above 10%. Several companies are also
developing and planning on introducing biobutanol into commerce. The
characteristics of butanol are such that it could be beneficial with
respect to volatility and vehicle evaporative emission performance. For
example, 2000 gallons of 10 psi E10 added to a service station tank
with 8000 gallons of 9.0 psi Bu12 would result in 10000 gallons of fuel
with an RVP of 9.2 psi. The RVP of the commingled blend would be the
same as the average of the separate blends if they had never been
commingled. There is no adverse emissions impact from the commingling
of the E10 and Bu12 blends. However the 1-psi waiver would not be
applicable because the resulting blend no longer contains from 9 volume
percent to 10 volume percent ethanol. The RVP level for the resulting
blend would also be higher than the maximum RVP standard of 9.0 psi,
making the commingled blend noncomplying with the RVP standard. However
the available data indicates that commingling of biobutanol blends with
ethanol blends would not result in any net increase in gasoline
volatility. This is because biobutanol blends and gasoline containing
from 9 volume percent to 10 volume percent ethanol blend linearly from
a volatility perspective, resulting in no net increase in volatility
compared to what would occur without the blending. This means that
there would be no net degradation in environmental performance, as
indicated in Illustration V.F.-4, below.
We are inviting comment on an alternative approach to applying the
RVP standard to the gasoline that results from commingling of E10 and
certain other products like biobutanol. We are inviting comment as to
whether the RVP standards could be applied to the commingled blend such
that the commingled blend would be considered in compliance as long as
the separate components of the commingled product were in compliance
with the RVP standards prior to commingling. In effect the RVP standard
would be applied to the commingled mixture by treating it as if it
still contained two separate products, with each product required to
comply with the RVP standard separately. This approach would be
somewhat artificial but would allow for the commingling of specified
blends of fuels, such as biobutanol, with E10 where the resulting
commingled mixture does not result in a net increase in average RVP and
associated emissions. This would provide more flexibility in achieving
the RFS standards while avoiding adverse environmental impacts. This
approach would provide a limited modification to the RVP provisions for
only certain fuel blends. EPA invites comment on whether it would have
the authority under Sec. 211(h) to adopt such an approach, and if so
whether it would be appropriate to do so and under what conditions.
Specifically, we would consider imposing the following conditions
on such fuel blends:
(1) Each separate component must individually meet the applicable
RVP standards (e.g., 10 psi for E10 and 9 psi for other blends).
(2) The resulting commingled mixture would have to have an RVP that
is no higher than the weighted average of the products or components
considered separately. This could occur with blends that blend linearly
with respect to RVP (e.g., butanol).
(3) The burden would be on the retailer to show that these
conditions had been satisfied. If a commingled product had volatility
above the allowable standard, and did not have from 9 volume percent to
10 volume percent ethanol, then the fuel would be considered
noncomplying unless the regulated party demonstrated that it met the
limited conditions discussed here. The retailer would have to
demonstrate that the conditions were met for application of this
modified method of determining compliance. This would call for at least
retaining records of the products received (with all required
regulatory statements and indications required) and volumes of the
products received in order to demonstrate a calculation to verify
compliance with the RVP standard.
(4) In situations where the RVP of retail tank samples exceed 9.0/
7.8 psi, for defense purposes the retailer would need to test the
sample for the concentration of ethanol, butanol, and any other
applicable oxygenate in addition to the RVP level in order to allow for
the calculation in (3). The resulting blend ratio would need to meet or
demonstrate better performance reductions of such ratio on a linear
scale as established through regulation.
Under this approach, we believe there would be no adverse
environmental effects because such mixtures would result in no net
increase in volatility. We also believe this would enable us to give
effect to the RFS provisions that call for increased use of renewable
fuels, and also be consistent with our rational for the treatment of
gasohol at the time we promulgated the RVP standards.

[[Page 36063]]

[GRAPHIC] [TIFF OMITTED] TP14JN13.001

F. Amendments to Various RFS2 Compliance Related Provisions

We are proposing a number of changes to the RFS2 regulations.
1. Proposed Changes to Definitions
``Responsible Corporate Officer''
The existing RFS2 regulations at sections 80.1416, 80.1451 and
80.1454, and EPA guidance and instructions regarding registration and
reporting, frequently refer to the responsibilities of the ``owner or a
responsible corporate officer.'' However, the term ``responsible
corporate officer'' is not currently defined in the RFS2 regulations.
We propose that, for purposes of the RFS2 program, a ``responsible
corporate officer'' (RCO) means a corporate officer who has the
authority and is assigned responsibility to provide information to EPA
on behalf of a company. A company may name only one RCO, and the RCO
may not delegate his/her responsibility to any other person. However,
the RCO may delegate the ability to submit information to EPA to one or
more employees of the company or to one or more agents. The RCO remains
responsible for the information submitted to EPA by any employee or
agent. Adding a definition of RCO will codify existing practices and
will assist regulated parties in understanding roles under the RFS2
regulation.
``Small Refinery''
Section 211(o)(9)(A) of the Clean Air Act provides an exemption
from RFS requirements through 2010 for ``small refineries,'' defined as
refineries having an average aggregate daily crude oil throughput for a
calendar year that does not exceed 75,000 barrels. It also provides for
possible extensions of this exemption, through individual petitions to
EPA. CAA 211(o)(9)(B). In EPA's March 26, 2010 regulations implementing
the EISA amendments we specified in the regulatory definition of
``small refinery'' that the 75,000 bpd threshold determination should
be calculated based on information from calendar year 2006. At the
beginning of the program, having a single year in which to make this
determination, simplified the calculations, and helped to ensure that
all refineries were treated similarly. However, we no longer believe
that it is appropriate that refineries satisfying the 75,000 bpd
threshold in 2006 should be eligible for extensions to their small
refinery RFS exemption if they no longer meet the 75,000 bpd threshold.
Allowing such facilities to qualify for an exemption extension, while
not allowing similarly sized facilities that have not grown since 2006
to qualify for an exemption,

[[Page 36064]]

does not appear fair, nor does it further the objectives of the statute
to target relief to only truly small facilities. Therefore, we propose
modifying the definition of small refinery so that the crude throughput
threshold of 75,000 bpd must apply in 2006 and in all subsequent years.
We also propose specifying in section 80.1441(e)(2)(iii) that in order
to qualify for an extension of its small refinery exemption, a refinery
must meet the definition of ``small refinery'' in section 80.1401 for
all full calendar years between 2006 and the date of submission of the
petition for an extension of the exemption.
We proposed that that these changes would not affect any existing
exemption extensions under CAA 211(o)(9)(B); rather, they would apply
at such time as any approved exemption extension expires and the
refinery at issue seeks a further exemption extension. No further
extension would be permitted unless the revised crude oil throughput
specifications were satisfied.
2. Provisions for Small Blenders of Renewable Fuels
The RFS2 regulations at section 80.1440 allow renewable fuel
blenders who handle and blend less than 125,000 gallons of renewable
fuel per year, and who are not obligated parties or exporters, to
delegate their RIN-related responsibilities to the party directly
upstream from them who supplied the renewable fuel for blending. EPA
has received feedback from several parties to the effect that the
125,000 threshold is too low, and is a lower threshold than what
industry considers ``small.'' EPA seeks input on what a more
appropriate gallon threshold should be. EPA seeks comment on the
regulated community's experience with the existing gallon threshold
associated with the provisions. EPA may adjust the gallon threshold in
the final rule based on further consideration of this issue and
evaluation of comments received.
3. Proposed Changes to Section 80.1450--Registration Requirements
We propose to add a new paragraph (h) to section 80.1450 that will
describe the circumstances under which EPA may cancel a company
registration. EPA proposes to initiate a process to cancel a company
registration if the company has reported no activity in the EPA
Moderated Transaction System (EMTS) under section 80.1452 for one year.
EPA also proposes to initiate a process to cancel a company
registration if a party fails to comply with any registration
requirement of section 80.1450, if the party fails to submit any
required compliance report under section 80.1451, if the party fails to
meet the requirements related to the EPA Moderated Transaction System
(EMTS) under section 80.1452, or if the party fails to meet the
requirements related to attest engagements under section 80.1454. If
any required report, including the attest engagement, is thirty (30) or
more days overdue, EPA would provide written notice to the owner or
responsible corporate officer (RCO) that it intends to cancel the
company's registration and would allow the company fourteen (14) days
from the date of the letter's issuance to respond. If there is no
satisfactory response received, then EPA would cancel the registration.
Re-registration would be possible following the standard registration
procedures.
4. Proposed Changes to Section 80.1452--EPA Moderated Transaction
System (EMTS) Requirements--Alternative Reporting Method for Sell and
Buy Transactions for Assigned RINs
Reporting and product transfer document (PTD) requirements, found
in sections 80.1452 and 80.1453, respectively, currently state that the
reportable event for a RIN purchase or sale occurs on the date of
transfer. Sellers must report the sale of RINs within five (5) business
days of the reportable event via the EPA Moderated Transaction System
(EMTS). Buyers must report the purchase of RINs within ten (10)
business days of the reportable event via EMTS. The date of transfer is
the date on which title of RINs is transferred from the seller to the
buyer. Some buyers and sellers of assigned RINs have expressed concerns
with these requirements stating they have difficulty determining the
date of transfer since title of the renewable fuel is not transferred
until the fuel physically reaches the buyer. Some transactions, for
example those by rail or barge, may take several weeks, and their
current accounting systems do not include a means for capturing the
buyer's receipt date.
EPA understands this concern, but also recognizes that some
regulated parties have modified their accounting systems to address the
current reporting and PTD requirements in RFS2. We also believe that
for parties separating, retiring, and selling or buying separated RINs,
the current reporting and PTD requirements are effective and should
remain unchanged. Therefore, at this time EPA is not proposing to
replace existing requirements, but is instead proposing an additional,
alternative method for reporting sell and buy transactions involving
assigned RINs only.
The proposed alternative method for sell and buy transactions of
assigned RINs would redefine the reportable event for both the seller
and the buyer, introduce a unique identifier that the seller must
provide to the buyer, and require the buyer to report the date of
transfer. Buyers and sellers would need to agree on which method they
would be using to report transfers of assigned RINs; either the current
method or the alternative method. EPA believes that this alternative
would provide the regulated community with the flexibility to address
their reporting concerns and also provide EPA with the data necessary
to effectively administer and enforce transactions of assigned RINs.
EPA welcomes comment on this proposed alternative method for reporting
assigned RIN buy and sell transactions.
We propose that sellers of assigned RINs under the alternative
method be required to do the following:
Within five (5) business days of shipping renewable fuel
with assigned RINs, report a sell transaction, using the alternative
method, via EMTS;
Include in the EMTS sell transaction report other required
information per section 80.1452; and
Provide a PTD to the assigned RIN buyer with a unique
identifier, also reported via EMTS, in addition to the information in
section 80.1453. The date of transfer is not required for the
alternative method.
We propose that buyers of assigned RINs under the alternative
method be required to do the following:
Within five (5) business days of receiving a shipment of
renewable fuel with assigned RINs, report a buy transaction, indicating
use of the alternative method, via EMTS;
Include in the EMTS buy transaction report other required
information per section 80.1452;
Include in the EMTS buy transaction report the unique
identifier provided by the seller; and
Include in the EMTS buy transaction report the date the
renewable fuel was received, i.e. the date of transfer.
If this proposed alternative method is finalized, the EMTS would be
modified to accept such transactions. EPA would provide additional
instruction and guidance at the time of the new EMTS version release.
EPA invites comment on all aspects of this proposal.

[[Page 36065]]

5. Proposed Changes to Section 80.1463--Confirm That Each Day an
Invalid RIN Remains in the Marketplace Is a Separate Day of Violation
Preventing the generation and use of invalid RINs and encouraging
rapid retirement and replacement of invalid RINs is crucial to the
integrity of the RFS2 program. The RFS regulations include various
provisions related to prohibited acts and liability for violations.
Section 80.1460(a) sets forth the prohibited acts for the renewable
fuels program. Section 80.1460(b)(2) prohibits parties from creating or
transferring invalid RINs. Section 80.1461(a) states that the person
who violates a prohibited act is liable for the violation of that
prohibition. Section 80.1461(b) provides the liability provisions for
failure to meet other provisions of the regulations. The penalty
provisions of the regulations at section 80.1463(a) state that any
person who is liable for a violation under section 80.1461 is subject
to a civil penalty as specified in sections 205 and 211(d) of the Clean
Air Act (CAA), for every day of each such violation and the amount of
economic benefit or savings resulting from each violation. Section
80.1463(c) provides that ``any person . . . is liable for a separate
day of violation for each day such a requirement remains unfulfilled.''
EPA interprets these statutory and regulatory penalty provisions to
give the Agency the authority to seek penalties against parties
generating, transferring or causing another person to generate or
transfer invalid RINs for each day subsequent to the party's action
that an invalid RIN is available for sale or use by a party subject to
an obligation under the RFS2 program to acquire and retire RINs. For
example, for a RIN generator, this time period typically runs from the
date of invalid RIN generation until either corrective action is taken
by the RIN generator to remove the invalid RIN from the marketplace or
a party uses the RIN to satisfy an RVO or other requirement to retire
RINs (such as would apply under today's proposal to exporters of
renewable fuel or parties using fuel produced as renewable fuel for a
use other than as transportation fuel, heating oil or jet fuel). This
is consistent with the CAA approach of assessing penalties for every
day of a violation, consistent with EPA's historic approach under the
fuels regulations (See Section 80.615), and will encourage renewable
fuel producers that generate invalid RINs to promptly take corrective
action.
We are proposing to amend section 80.1463 to more explicitly
incorporate EPA's interpretation of these penalty provisions into the
regulations. The amendments would state that any person liable for a
violation of section 80.1460(b) for creating or transferring an invalid
RIN, or for causing another person to create or transfer and invalid
RIN, is subject to a separate day of violation for each day that the
invalid RIN remains available for use for compliance purposes, and EPA
has the authority to seek the maximum statutory penalty for each day of
violation. EPA will apply the statutory factors in sections 211(c) and
205(b) of the CAA to evaluate the appropriate penalties for each
violation on a case by case basis.
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
The current regulations include requirements that foreign renewable
fuel producers that generate RINs agree to be subject to a number of
additional requirements at section Sec. 80.1466, including, but not
limited to, designation, foreign producer certification, product
transfer document, load port independent testing and producer
identification, submission to U.S. jurisdiction and posting of a bond.
We are proposing to require the same requirements for foreign renewable
fuel producers, and foreign ethanol producers that produce biofuel for
which importers ultimately generate RINs, and for importers of
renewable fuel.
In order to evaluate whether a fuel qualifies as RIN generating
renewable fuel (including determining the proper renewable fuel
category and RIN type for the imported fuel), EPA must be able to
evaluate the feedstocks and processes used to produce the renewable
components of the fuel. This is a particular challenge for fuel
produced at foreign facilities; unlike our other fuels programs, EPA
cannot determine whether a particular shipment of renewable fuel is
eligible to generate RINs under the RFS program by testing the fuel
itself. Furthermore, significant opportunity for fraud and non-
compliance with the regulations exists where EPA is not able to ensure
that RINs entering the U.S. are valid, and where enforcement of the
regulations may be hampered due to a facility's foreign location. We
believe that the same safeguards that apply to foreign RIN generating
renewable fuel producers should apply to other foreign producers whose
product is used by importers to generate RINs, and to those importers
themselves. Accordingly, we propose that foreign renewable fuel
producers and foreign ethanol producers who do not themselves generate
RINs for their product, and importers of renewable fuel, be required to
comply with the safeguards of section 80.1466. Given the challenges
associated with EPA's ability to determine whether a fuel qualifies as
RIN generating renewable fuel, and the potential for fraud, we believe
these additional safeguards are necessary for all foreign produced
renewable fuel, regardless of who generates the RINs. However, we seek
comment on the reasonability of expanding these additional requirements
onto foreign renewable fuel producers, and foreign ethanol producers
that produce biofuel for which importers ultimately generate RINs, and
for importers of renewable fuel. We further propose to amend section
80.1426(a)(4) to prohibit importers from generating RINs for renewable
fuel imported from a foreign renewable fuel producer or foreign ethanol
producer, unless and until the foreign renewable fuel producer or
foreign ethanol producer has satisfied all requirements of section
80.1466.
7. Proposed Changes to Section 80.1466(h)--Calculation of Bond Amount
for Foreign Renewable Fuel Producers, Foreign Ethanol Producers and
Importers
EPA proposes two changes to section 80.1466 regarding calculation
of bonds. EPA proposes to amend the procedures for calculating the bond
amount for foreign renewable fuel producers, foreign ethanol producers
and importers to require that the bond amount be the larger of: (1) One
cent times the largest volume of renewable fuel produced by the foreign
producer and exported to the United States, in gallons, during a single
calendar year among the five preceding calendar years, or the largest
volume of renewable fuel that the foreign producers expects to export
to the Unites States during any calendar year identified in the
Production Outlook Report required by section 80.1449, or (2) the sum
of the following calculation for each RIN type: 0.25 times the largest
volume of renewable fuel produced by the foreign producer and exported
to the United States, in gallons, during a single calendar year among
the five preceding calendar years, or the largest volume of renewable
fuel that the foreign producers expects to export to the Unites States
during any calendar year identified in the Production Outlook Report
required by section 80.1449, times a ``RIN multiplier D code''
established by EPA in the regulations.

[[Page 36066]]

The proposed ``RIN multiplier D codes'' vary from $.02 for D code 6 to
$1.30 for D code 4. When the original renewable fuels standard
regulations (RFS1) were written, an RFS1 RIN was worth pennies. With
the implementation of RFS2, the price of some RINs has increased
significantly, in part because of the demand for certain categories of
fuel such as biomass-based diesel. In order to keep up with these
market conditions, the bond amount needs to be increased; a penny per
gallon of fuel may no longer be a fair valuation of a foreign renewable
fuel producer's potential penalty for RFS violations. Bonds are used to
satisfy any judicial judgment that results from an administrative or
judicial enforcement action for conduct in violation of this subpart.
Therefore, we propose to amend section 80.1466(h)(1) to include the
calculation described above, that reflects current market valuation for
different types of RINs. We seek comment on whether the proposed bond
calculation procedures are appropriate, and in particular whether they
are sufficiently large to cover potential liability.
EPA also proposes to amend paragraph (h) of section 80.1466 to be
consistent with paragraph (j)(4), which prohibits generating RINs in
excess of the number for which the bond requirements have been
satisfied. Paragraph (h) regulates the size of the bond a foreign
renewable fuel producer must post in order to generate RINs. This
formula takes into account the volume of renewable fuel a foreign
renewable fuel producer has exported or intends to export to the United
States. Section 80.1466(h) states, in part: ``If the volume of
renewable fuel exported to the United States increases above the
largest volume identified in the Production Outlook Report during any
calendar year, the foreign producer shall increase the bond to cover
the shortfall within 90 days.'' This conflicts with the stricter
language in paragraph (j)(4) of the same section, which prohibits a
foreign producer of renewable fuel from generating RINs in excess of
the number for which the bond requirements of section 80.1466 have been
satisfied. EPA interprets the stricter provision at section
80.1466(j)(4) to be controlling, and we propose to change the language
in section 80.1466(h) accordingly.
8. Proposed Changes to Facility's Baseline Volume To Allow ``Nameplate
Capacity'' for Facilities Not Claiming Exemption From the 20% GHG
Reduction Threshold
As a requirement of registration under the RFS2 program, each
renewable fuel producer and foreign ethanol producer must establish and
provide documents to support its facility's baseline volume as defined
in section 80.1401. This is either the permitted capacity or, if
permitted capacity cannot be determined, the actual peak capacity of a
specific renewable fuel production facility on a calendar year basis.
After the promulgation of the March 26, 2010 RFS2 rule, we have
received many requests from companies to allow them to use their
nameplate or ``design'' capacity to establish their facility's baseline
volume due to either the facility being exempt from obtaining a permit,
and thus not able to determine their permitted capacity, or the
facility not starting operations, or not being operational for a full
calendar year to produce actual production records to establish actual
peak capacities. Because the regulations currently only allow a
facility's baseline volume to be established by a limit stated in a
permit or actual production records for at least one calendar year,
facilities that had neither a permit or sufficient production records
had difficulty registering under the RFS2 program. To allow facilities
that fall under this predication to register under the RFS2 program, we
are proposing in this rulemaking to allow a facility to use its
``nameplate capacity'' to establish its facility's baseline volume for
the purposes of registration, only if (1) the facility does not have a
permit or there is no limit stated in the permit to establish their
permitted capacity, and (2) has not started operations or does not have
at least one calendar year of production records, and (3) does not
claim exemption from the 20 percent GHG threshold under Sec. 80.1403.
Due to the complexity of the exemption provision provided under Sec.
80.1403, and the added flexibility that facilities claiming this
exemption are allotted under the program, we are not proposing to
extend this option to facilities claiming an exemption under Sec.
80.1403. Additionally, by this stage in the RFS2 program, the
facilities that would qualify for registration under Sec. 80.1403
would be very few, if any. This proposal would revise the definition of
baseline volume to include ``nameplate capacity,'' add a new definition
for ``nameplate capacity'' to Sec. 80.1401, and include conforming
amendments to the registration requirements of Sec. 80.1450.

G. Minor Corrections to RFS2 Provisions

We are proposing a number of corrections to address minor
definitional issues that have been identified as we have been
implementing the RFS2 program.
Renewable Biomass
We propose to amend the definition of ``renewable biomass'' in
section 80.1401 to make clear that biomass obtained in the vicinity of
buildings means biomass obtained within 200 feet of the buildings. The
preamble for the March 26, 2010 RFS2 final rule cites the distance of
200 feet (see 75 FR 14696), but EPA did not include a reference to this
value in the regulations. We believe doing so would provide additional
clarity to the regulations.
English Language Translations
We propose to add a new paragraph (i) to section 80.1450 to state
that any registration materials submitted to EPA must be in English or
accompanied by an English language translation. Similarly, we propose
to add a new paragraph (h) to section 80.1451 that will state that any
reports submitted to EPA must be in English or accompanied by an
English language translation and add a new paragraph (q) to section
80.1454 that will state that any records submitted to EPA must be in
English or accompanied by an English language translation. The
translation and all other associated documents must be maintained by
the submitting company for a period of five (5) years, which is already
the established time period for keeping records under the existing RFS2
program.
Correction of Typographical Errors
We propose to correct various typographical errors in section
80.1466. Specifically, we propose to amend paragraph (o) to correct a
typographical error in the last sentence of the affirmation statement,
by changing the citation from Sec. 80.1465 to Sec. 80.1466. We also
propose to amend paragraph (d)(3)(ii) to correct a typographical error.
The current regulation cites section 80.65(e)(2)(iii), which does not
exist. The correct citation is to section 80.65(f)(2)(iii).

VI. Amendments to the E15 Misfueling Mitigation Rule

We propose the following minor corrections and other changes to the
E15 misfueling mitigation rule (E15 MMR) found at 40 CFR Part 80,
subpart N.

A. Proposed Changes to Section 80.1501--Label

We propose to correct several minor errors in the description of
the E15 label required by the E15 MMR at section 80.1501, including
corrections in the dimensions of the label and ensuring that the word
``ATTENTION'' is capitalized. The Agency intended the label required by
the regulations to look

[[Page 36067]]

identical to that pictured in the Federal Register notice for the final
E15 MMR (see 76 FR 44406, 44418, July 25, 2011).

B. Proposed Changes to Section 80.1502--E15 Survey

We are proposing two changes to the survey requirements found at
section 80.1502. First, we propose to clarify that E15 surveys need to
sample for Reid vapor pressure (RVP) only during the high ozone season
as defined in section 80.27(a)(2)(ii) or during any time RVP standards
apply in any state implementation plan approved or promulgated under
the Clean Air Act. EPA did not intend to require RVP sampling and
testing during the rest of the year, when RVP standards do not apply.
Second, we propose to change when the results of surveys that
detect potential noncompliance must be reported to the Agency. As
originally drafted, the regulations require the independent survey
association conducting a survey to notify EPA of potentially
noncompliant samples within 24 hours of the laboratory receiving this
sample (see 76 FR at 44423, July 25, 2011). EPA has since learned that
more time may be needed for reporting of noncompliant samples since it
may take several days for analysis of the sample to be completed. We
are therefore requiring that noncompliant samples be reported to EPA
within 24 hours of being analyzed.

C. Proposed Changes to Section 80.1503--Product Transfer Documents

EPA is proposing certain minor changes to the product transfer
document (PTD) requirements found at section 80.1503. Specifically, we
are proposing to allow the use of product codes for conventional
blendstock/gasoline upstream of an ethanol blending facility, since
historically, the codes have been allowed to be used for conventional
blendstock/gasoline upstream of an ethanol blending facility in other
fuels programs. This was an omission from the original regulation.
We are also seeking comment on potential ways of streamlining the
PTD language required at section 80.1503.

D. Proposed Changes to Section 80.1504--Prohibited Acts

EPA is slightly rewording section 80.1504(g) to state that blending
E10 that has taken advantage of the statutory 1.0 psi RVP waiver during
the summertime RVP control period with a gasoline-ethanol fuel that
cannot take advantage of the 1.0 psi RVP waiver (i.e., a fuel that
contains more than 10.0 volume percent ethanol (e.g., E15) or less than
9 volume percent ethanol) would be a violation of the E15 MMR. As
originally written, the language does not clearly describe the
prohibited activity (see 76 FR 44435, 44436, Jult 25, 2011).

E. Proposed Changes to Section 80.1500--Definitions

On August 17, 2011, the National Petroleum Refiners Association,
now called American Fuel and Petrochemical Manufacturers (AFPM), filed
a petition for reconsideration with the Agency under CAA section
307(d)(7)(B) asking EPA to reconsider certain portions of the E15 MMR.
A copy of the petition has been placed in the docket. The petition
fundamentally focuses on one issue--AFPM expressed concern that the
Agency had defined E10 and E15 in the E15 MMR in a way that would
change how ethanol concentrations are determined for regulatory
purposes. Today we grant AFPM's request for reconsideration of this
issue as explained in their August 17, 2011 petition. As explained
below, while EPA did not intend the definitions of E10 and E15 in the
E15 MMR to have this effect, we are proposing changes to the
regulations to avoid this perceived impact.
On April 6, 1979, fuel containing 90% unleaded gasoline and 10%
ethyl alcohol received a waiver under section 211(f)(4) by operation of
law (see 44 FR 20777, April 6, 1979). Later, EPA issued an
interpretative ruling that stated the April 6, 1979 waiver covered
gasoline-ethanol blends that contained up to 10 vol% ethanol content
(see 47 FR 14596, April 5, 1982). Finally, in the context of
regulations limiting the Reid vapor pressure (RVP) of gasoline, EPA has
defined E10 as gasoline containing between 9 and 10 volume percent
ethanol. Under the RVP regulations and the Clean Air Act, the RVP of
E10 is allowed to be 1 pound per square inch (psi) higher than it is
for gasoline or gasoline-ethanol blends containing less than 9 and more
than 10 vol% ethanol (often referred to as the ``1.0 psi waiver'').
In the E15 MMR, EPA defined E10 as gasoline containing at least 9.0
and no more than 10.0 vol% ethanol and defined E15 as a gasoline-
ethanol blend containing greater than 10.0 and no more than 15.0 vol%
ethanol. EPA included those definitions in the E15 MMR so that fuels
blended to contain more than 10.0 vol% ethanol were subject to the
misfueling mitigation requirements for E15. After publication of the
E15 MMR, stakeholders including AFPM expressed concern that by defining
E10 as E10.0, the Agency may have effectively made the ethanol
concentration limits specified in the E10 and the E15 waiver decisions
and the RVP regulations more stringent, which in turn would impact
whether a party must comply with the E15 MMR requirements and whether a
fuel qualifies for the RVP 1.0 psi waiver.
In its petition, AFPM noted that under existing EPA regulations at
40 CFR 80.9, the results of compliance testing for the ethanol
concentration in gasoline are ``rounded down'' when the results
indicate that gasoline-ethanol fuel may contain slightly more than 10
vol% ethanol. AFPM further stated that in view of this rounding
procedure, fuel that compliance testing indicates has an ethanol
concentration of between 10.0 and 10.4 should be considered E10. AFPM
argued that the E15 MMR definition of E10 as containing no more than
10.0 vol% ethanol constituted a ``substantive change'' to the proposed
E15 MMR that would also alter the implementation of other EPA fuels
regulations without a required rulemaking.
As part of the E15 MMR proposed rule, we identified prospective
responsible parties for each misfueling mitigation measure, including
requirements related to labeling E15 fuel dispensers, compliance
surveys, and product transfer documents. We received a number of
comments from many affected stakeholders, including AFPM, that asked us
to clarify which party or parties would be responsible for each
misfueling mitigation measure and when each party or parties would be
subject to those requirements. In the final E15 MMR, we added the
significant digit to the definitions of E10 and E15 in order to provide
a delineation between E10 and E15 and consequently the parties subject
to one or more of the E15 misfueling mitigation measures.
AFPM argued in their petition that by defining E10 as containing no
more than 10.0 vol% ethanol, EPA effectively made a substantive change
to the way test results used for determining compliance with fuel
requirements are rounded. For example, for a gasoline-ethanol blend to
be considered E10, it could no longer contain up to 10.4 vol% ethanol;
it could only contain up to 10.04 vol% ethanol. AFPM asserted that
there is a tolerance for blending ethanol that allows blends containing
up to 10.4 vol% ethanol to be considered E10. While we do not agree
that there is a blending tolerance for ethanol, we agree that test
results are rounded utilizing the procedures identified in section 80.9
when compared to applicable standards, in this case the ethanol
concentrations

[[Page 36068]]

specified in the E10 and the E15 waivers.
The Agency specifically addressed the issue of blending tolerances
versus testing tolerances for gasoline-ethanol blends in the RFS2
NPRM.\50\ At the time, some stakeholders had suggested that the
implementation of a blending tolerance for the ethanol content of
gasoline could be allowed to help obligated parties satisfy RFS
requirements without the need for a CAA section 211(f)(4) waiver. In
response, we argued that although the test methods used to measure
ethanol concentration (ASTM D 5599 and ASTM D 4815) include some
variability, ethanol is different than other fuel properties and
components that are controlled in other fuel programs.\51\ Fuel
properties such as RVP, and components such as sulfur and benzene, are
natural characteristics of gasoline as a result of the chemical nature
of crude oil and the refining process. Their levels or concentrations
in gasoline are unknown until measured and are dependent upon the
accuracy of the test method. In contrast, ethanol is intentionally
added in known amounts using equipment designed to ensure a specific
concentration within a very narrow range. Parties that blend ethanol
into gasoline normally have precise control over the final
concentration. Therefore, a blending tolerance for ethanol would not be
appropriate. During the comment period for the RFS2 NPRM, EPA received
a number of comments from stakeholders that argued that the volume
percentage of ethanol in gasoline is readily determined using very
accurate volumetric ratio blending facilities now in place at most
blending terminals; therefore, the Agency should not allow a blending
tolerance. In the final RFS rule, we did not include a blending
tolerance for ethanol blends.\52\
---------------------------------------------------------------------------

\50\ See 74 FR 25018 (May 26, 2009).
\51\ See 74 FR 25018 (May 26, 2009).
\52\ See 75 FR 14762-14764 (March 26, 2010).
---------------------------------------------------------------------------

We continue to believe that blending tolerances for ethanol are not
appropriate, and the definitions of E10 and E15 in the E15 MMR are
consistent with this view. The E10 waiver is for gasoline containing
``up to'' 10 vol% ethanol, not for gasoline containing ``up to'' 10.4
vol% ethanol, and the E15 partial waivers are for fuel designed to
contain ``greater than 10 vol% ethanol and not more than 15 vol%
ethanol.'' In the case of both waivers, the ``10'' and the ``15'' are
exact numbers, not approximations, and they express how much ethanol
can be lawfully added to fuel. Testing by the Department of Energy
utilized in making the E15 partial waiver decisions was blended as
precisely as possible to contain the relevant percentage of ethanol,
not that percentage plus ``0.49.'' Testing for registration of E10 and
E15 fuel and fuel additives under 40 CFR part 79 was also done with
fuels blended as precisely as possible to contain the relevant
percentage of ethanol. Similarly, EPA regulations provide that only
fuel with an ethanol concentration of between 9 and 10 vol%, not more
or less, may lawfully use the statutory 1.0 psi RVP waiver.
At the same time, we did not intend to change the definition of E10
in a way that impacts the rounding of test results for ethanol
concentrations.\53\ If a manufacturer blends in a way designed to
result in a gasoline-ethanol fuel containing no more than 10.0 vol%
ethanol, but compliance testing indicates a concentration of 10.4 vol%,
we will still round down the test result in accordance with procedures
in section 80.9. The purpose of the E15 MMR definitions state that if a
manufacturer blends ethanol into gasoline in a way designed to result
in a gasoline-ethanol fuel containing greater than 10.0 vol% and no
more than 15.0 vol% ethanol, it will be subject to applicable E15 MMR
requirements. For example, bills of lading for an E10 fuel manufacturer
that indicates the manufacturer has purchased and blended more ethanol
than 10.0 vol% ethanol may indicate that a fuel does not meet the
definition of E10 for E15 MMR purposes.
---------------------------------------------------------------------------

\53\ For an explanation of the rounding procedures outlined in
Sec. 80.9 and the rationale the Agency used to adopt those
procedures, see 71 FR 16496 (April 3, 2006).
---------------------------------------------------------------------------

AFPM also argued that the E15 MMR definitions of E10 would alter
the implementation of other EPA fuels regulations without a required
rulemaking, specifically the application of the 1.0 psi RVP waiver to
E10. Since the Agency intended the E15 MMR definition of E10 to only
apply for purposes of determining the applicability of E15 MMR
requirements, the Agency does not believe these definitions affect the
implementation and enforcement of others fuels programs, including the
applicability of the 1.0 psi RVP waiver. The introductory language to
the definitions at 40 CFR part 80, subpart N clearly states that
definitions in section 80.1500 are ``[f]or purposes of this subpart
only.''
In order to clarify that these definitions only apply in the
context of the E15 MMR, EPA is proposing to add a new section 80.1509,
which contains language that clearly states that when ethanol
concentrations are measured for compliance testing purposes for 40 CFR,
Part 80, Subpart N, the applicable ethanol concentration value will be
rounded using the rounding procedures at section 80.9. EPA is also
proposing new prohibited acts language in section 80.1504 that should
make it clear that only those parties that (1) produce gasoline,
blendstocks for oxygenate blending (BOBs), or ethanol designed to be
used in the manufacture of E15 as currently defined (i.e., E15.0); (2)
that manufacture E15 to be introduced into commerce; or (3) that
dispense E15 from a retail outlet. The Agency specifically seeks
comments on this proposed language.

VII. Proposed Amendments to the ULSD Diesel Sulfur Survey

EPA is requesting comment concerning whether to amend a provision
of the ultra-low sulfur diesel (ULSD) rule. The ULSD rule includes a
provision that deems branded refiners liable for violations of the ULSD
sulfur standard that are found at retail outlets displaying the
refiner's brand (40 CFR 80.612). The regulations include defense
provisions. One element of a branded refiner's defense to such
violations is that it must have a periodic sampling and testing program
at the retail level (40 CFR 80.613(b) and (d)). The regulations also
set forth an alternative sampling and testing defense element provision
for branded refiners.
This alternative defense element provision (40 CFR 80.613(e))
allows a branded refiner to meet the company-specific downstream
periodic sampling and testing element of its defense by participating
in funding a survey consortium that samples diesel fuel at retail
outlets nationwide. This sampling and testing of fuel to determine
compliance with the ULSD sulfur standard is carried out by an
independent survey association. EPA reviews and approves the annual
survey plan submitted by the survey association. The number of samples
that are taken each year is determined by a statistical formula that is
based in part on the previous year's compliance rate. In addition, the
regulations set a floor and a ceiling for the number of samples that
must be taken in an annual survey cycle regardless of the sample number
that would be calculated using the regulatory formula. Therefore, the
number of samples required to be taken can potentially be less than the
formula would require, or it can be more.
Compliance with the ULSD sulfur content standard has been extremely
high; less than 1% of the samples have been in violation in recent
years. The

[[Page 36069]]

minimum number of samples currently required to be taken annually is
set by the regulation at 5,250 regardless of this high compliance rate.
Due to the high compliance rate, use of the statistical formula would
result in a sampling rate of several hundred samples for each of the
past several years, instead of 5,250 samples. The cost difference
between taking several hundred samples versus taking over 5,000 samples
is significant. For these reasons we believe the continued high
compliance rate, and the substantial discrepancy between the sampling
rate calculated by the formula and the minimum sampling rate, argue for
lowering the minimum sampling rate. However, we believe there is a
point where the number of samples per year would be so few that the
survey would be meaningless relative to robust sampling and testing
programs conducted by each refiner individually. Balancing these
concerns, we believe minimum sampling rate of about 1,800 samples is
appropriate. We are requesting comment on reducing the minimum number
of samples to some rate below 2,000 samples.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

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

B. Paperwork Reduction Act

The information collection requirements in this notice of proposed
rulemaking have been submitted for approval to the Office of Management
and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et
seq. The Information Collection Request (ICR) document prepared by EPA
related to this proposal has been assigned EPA ICR number 2469.01. A
supporting statement for the proposed ICR has been placed in the
docket. The proposed information collection is described in the
following paragraphs.
This action contains recordkeeping and reporting that may affect
the following parties under the RFS2 regulation: RIN generators
(producers, importers), obligated parties (refiners), exporters, and
parties who own or transact RINs. We estimate that 670 parties may be
subject to the proposed information collection. We estimate an annual
recordkeeping and reporting burden of 3.1 hours per respondent. This
action contains recordkeeping and reporting that may affect the
following parties under the E15 regulation: gasoline refiners, gasoline
and ethanol importers, gasoline and ethanol blenders (including
terminals and carriers). We estimate that 2,000 respondents may be
subject to the proposed information collection. We estimate an annual
recordkeeping and reporting burden of 1.3 hours per respondent. Burden
means the total time, effort, or financial resources expended by
persons to generate, maintain, retain, or disclose or provide
information to or for a Federal agency. This includes the time needed
to review the instructions; develop, acquire, install, and utilize
technology and systems for the purpose of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transit or otherwise disclose the information. Burden is as defined
at 5 CFR 1320.3(b).
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR Part 9.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, EPA has established a public docket for
this proposed rule, which includes the ICR described above, under
Docket ID number EPA-HQ-OAR-2012-0401. Submit any comments related to
the ICR to EPA and OMB. See the ADDRESSES section at the beginning of
this notice for where to submit comments to EPA. Send comments to OMB
at the Office of Information and Regulatory Affairs, Office of
Management and Budget, 725 17th Street NW., Washington, DC 20503,
Attention: Desk Office for EPA. Since OMB is required to make a
decision concerning the ICR between 30 and 60 days after June 14, 2013,
a comment to OMB is best assured of having its full effect if OMB
receives it by July 15, 2013.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
After considering the economic impacts of this action on small
entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. The
amendments to the RFS2 provisions in this direct final rule will not
impose any requirements on small entities that were not already
considered under the final RFS2 regulations, as it makes relatively
minor corrections and modifications to those regulations. We continue
to be interested in the potential impacts of the proposed rule on small
entities and welcome comments on issues related to such impacts.

D. Unfunded Mandates Reform Act

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

[[Page 36070]]

modifications to the RFS2 and diesel regulations.

E. Executive Order 13132 (Federalism)

This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. This action only applies to
gasoline, diesel, and renewable fuel producers, importers, distributors
and marketers and makes relatively minor corrections and modifications
to the RFS2 and diesel regulations. Thus, Executive Order 13132 does
not apply to this action. In the spirit of Executive Order 13132, and
consistent with EPA policy to promote communications between EPA and
State and local governments, EPA specifically solicits comment on this
proposed action from State and local officials.

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

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

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

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

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

This action is not a ``significant energy action'' as defined in
Executive Order 13211 (66 FR 28355, (May 22, 2001)), because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. This action amends existing regulations
related to renewable fuel, E15, and ultra-lower sulfur diesel. We have
concluded that this rule is not likely to have any adverse energy
effects. In fact, we expect this proposed rule may result in positive
effects, because many of the changes we are proposing will facilitate
the introduction of new renewable fuels under the RFS2 program and have
come at the suggestion of industry stakeholders.

I. National Technology Transfer and Advancement Act

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

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

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

K. Clean Air Act Section 307(d)

This rule is subject to Section 307(d) of the CAA. Section
307(d)(7)(B) provides that ``[o]nly an objection to a rule or procedure
which was raised with reasonable specificity during the period for
public comment (including any public hearing) may be raised during
judicial review.'' This section also provides a mechanism for the EPA
to convene a proceeding for reconsideration, ``[i]f the person raising
an objection can demonstrate to the EPA that it was impracticable to
raise such objection within [the period for public comment] or if the
grounds for such objection arose after the period for public comment
(but within the time specified for judicial review) and if such
objection is of central relevance to the outcome of the rule.'' Any
person seeking to make such a demonstration to the EPA should submit a
Petition for Reconsideration to the Office of the Administrator, U.S.
EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave. NW.,
Washington, DC 20460, with a copy to both the person(s) listed in the
preceding FOR FURTHER INFORMATION CONTACT section, and the Director of
the Air and Radiation Law Office, Office of General Counsel (Mail Code
2344A), U.S. EPA, 1200 Pennsylvania Ave. NW., Washington, DC 20460.

List of Subjects in 40 CFR Part 80

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

Dated: May 20, 2013.
Bob Perciasepe,
Acting Administrator.

For the reasons stated in the preamble, the Environmental
Protection Agency proposes to amend 40 CFR chapter I as set forth
below:

[[Page 36071]]

PART 80--REGULATION OF FUELS AND FUEL ADDITIVES

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

Authority: 42 U.S.C. 7414, 7521, 7542, 7545 and 7601(a).

0
2. Section 80.613 is amended by revising paragraph (e)(4)(v)(A)
definition ``n'' as follows:

Sec. 80.613 What defenses apply to persons deemed liable for a
violation of a prohibited act under this subpart?

* * * * *
(e) * * *
(4) * * *
(v) * * *
(A) * * *

Where:

n= minimum number of samples in a year-long survey series. However,
in no case shall n be larger than 9,600 nor smaller than 1,800.
* * * * *
0
3. Section 80.1401 is amended by adding the definitions of ``Nameplate
capacity'', ``Renewable compressed natural gas'', ``Renewable fuel
producer'', ``Renewable liquefied natural gas'', ``Responsible
corporate officer'', in alphabetical order and revising the definitions
of ``Biogas'', ``Crop residue'', ``Naphtha'', ``Renewable biomass'',
and ``Small refinery'' in to read as follows:

Sec. 80.1401 Definitions.

* * * * *
Biogas means 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. Biogas includes landfill gas, gas from
waste digesters, and gas from waste treatment plants. Waste digesters
include digesters processing animal wastes, biogenic waste oils/fats/
greases, separated food and yard wastes, and crop residues, and waste
treatment plants include wastewater treatment plants and publicly owned
treatment works.
* * * * *
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, nor any other impact that
would result in a significant increase in direct or indirect GHG
emissions.
* * * * *
Nameplate capacity means the peak design capacity of a facility for
the purposes of registration of a facility under Sec.
80.1450(b)(1)(V)(E).
Naphtha means a blendstock or fuel blending component falling
within the boiling range of gasoline which is composed of only
hydrocarbons, is commonly or commercially known as naphtha and is used
to produce gasoline through blending.
* * * * *
Renewable biomass means each of the following (including any
incidental, de minimis contaminants that are impractical to remove and
are related to customary feedstock production and transport):
(1) Planted crops and crop residue harvested from existing
agricultural land cleared or cultivated prior to December 19, 2007 and
that was nonforested and either actively managed or fallow on December
19, 2007.
(2) Planted trees and tree residue from a tree plantation located
on non-federal land (including land belonging to an Indian tribe or an
Indian individual that is held in trust by the U.S. or subject to a
restriction against alienation imposed by the U.S.) that was cleared at
any time prior to December 19, 2007 and actively managed on December
19, 2007.
(3) Animal waste material and animal byproducts.
(4) Slash and pre-commercial thinnings from non-federal forestland
(including forestland belonging to an Indian tribe or an Indian
individual, that are held in trust by the United States or subject to a
restriction against alienation imposed by the United States) that is
not ecologically sensitive forestland.
(5) Biomass (organic matter that is available on a renewable or
recurring basis) obtained from the immediate vicinity (i.e., obtained
within 200 feet) of buildings and other areas regularly occupied by
people, or of public infrastructure, in an area at risk of wildfire.
(6) Algae.
(7) Separated yard waste or food waste, including recycled cooking
and trap grease, and materials described in Sec. 80.1426(f)(5)(i).
Renewable compressed natural gas means biogas as defined in this
section, 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. Only renewable CNG that qualifies as renewable fuel and is used
for transportation purposes can generate RINs.
* * * * *
Renewable fuel producer means a person who operates or directly
supervises the operation of a facility where renewable fuel is
produced.
* * * * *
Renewable liquefied natural gas means biogas as defined in this
section, 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. Only renewable LNG that qualifies as renewable fuel and is
used for transportation fuel can generate RINs.
Responsible Corporate Officer, or RCO, for this subpart only, means
a corporate officer who has the authority and is assigned
responsibility to provide information to EPA on behalf of a company. A
company may name only one Responsible Corporate Officer. A Responsible
Corporate Officer may not delegate his or her responsibility to any
other person. The Responsible Corporate Officer may delegate the
ability to submit information to EPA, but the Responsible Corporate
Officer remains responsible for the actions of such employees or
agents.
* * * * *
Small Refinery, for this subpart only, means a refinery for which
the average aggregate daily crude oil throughput for calendar year 2006
and subsequent years (as determined by dividing the aggregate
throughput for the calendar year by the number of days in the calendar
year) does not exceed 75,000 barrels.
0
4. Section 80.1415 is amended by revising paragraphs (b)(5) and (c)(1)
to read as follows:

Sec. 80.1415 How are equivalence values assigned to renewable fuel?

(b) * * *
(5) 77,000 Btu (lower heating value) of compressed natural gas
(CNG) or liquefied natural gas (LNG) shall represent one gallon of
renewable fuel with an equivalence value of 1.0.
(c) * * *
(1) The equivalence value for renewable fuels described in
paragraph (b)(7) of this section shall be calculated using the
following formula:

EV = (R/0.972) * (EC/77,000)

Where:

[[Page 36072]]

EV = Equivalence Value for the renewable fuel, rounded to the
nearest tenth.
R = Renewable content of the renewable fuel. Except as provided in
Sec. 80.1426(f)(4)(iii), this is a measure of the portion of a
renewable fuel that came from renewable biomass, expressed as a
fraction, on an energy basis.
EC = Energy content of the renewable fuel, in Btu per gallon (lower
heating value).

0
5. Section 80.1426 is amended by:
0
a. Revising Table 1 of paragraph (f)(1) by:
0
1. Revising the entry for ``Q''; and
0
2. Adding new entries for T through AA to the end of the table;
0
b. Revising paragraphs (f)(10) and f(11); and
0
c. Adding paragraph (f)(14).
The revisions and additions read as follows:

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

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

Table 1 to Sec. 80.1426--Applicable D Codes for Each Fuel Pathway for Use in Generating RINs
----------------------------------------------------------------------------------------------------------------
Production process
Fuel type Feedstock requirements D-Code
----------------------------------------------------------------------------------------------------------------

* * * * * * *
Q..................... Renewable Compressed Biogas from waste Any........................ 5
Natural Gas, treatment plants and
Renewable Liquefied waste digesters.
Natural Gas.

* * * * * * *
T..................... Butanol............... Corn starch........... Fermentation; dry mill 5
using natural gas and
biogas from on-site thin
stillage anaerobic
digester for process
energy w/CHP producing
excess electricity of at
least 40% of the purchased
natural gas energy used by
the facility.
U..................... Renewable Compressed Biogas from Landfills. Any........................ 3
Natural Gas,
Renewable Liquefied
Natural Gas.
V..................... Renewable Electricity. Biogas from landfills. Any........................ 3
W..................... Cellulosic Naphtha.... Biogas from landfills. Fischer-Tropsch process; 3
Facilities must produce at
least 20% of their
electricity usage at the
facility.
X..................... Cellulosic Diesel for Biogas from landfills. Fischer-Tropsch process; 7
use as conventional Facilities must produce at
diesel fuel. least 20% of their
electricity usage at the
facility.
Y..................... Naphtha............... Biogas from landfills. Fischer-Tropsch process.... 5
Z..................... Renewable Diesel for Biogas from landfills. Fischer-Tropsch process; 4
use as conventional Excluding processes that
diesel fuel. co-process renewable
biomass and petroleum.
AA.................... Renewable Diesel for Biogas from landfills. Fischer-Tropsch process; 5
use as conventional Includes only processes
diesel fuel. that co-process renewable
biomass and petroleum.
----------------------------------------------------------------------------------------------------------------

* * * * *
(10)(i) For purposes of this section, renewable electricity that is
not introduced into a distribution system with electricity derived from
non-renewable feedstocks is considered renewable fuel and the producer
may generate RINs if all of the following apply:
(A) The electricity is produced from renewable biomass and
qualifies for a D code in Table 1 to this section or has received
approval for use of a D code by the Administrator;
(B) The fuel producer has entered into a written contract for the
sale of a specific quantity of renewable electricity as transportation
fuel; and
(C) The renewable electricity is used as a transportation fuel.
(ii) For purposes of this section, fuels produced from biogas that
is not introduced into a distribution system with gas derived from non-
renewable feedstocks is considered renewable fuel and the producer may
generate RINs if all of the following apply:
(A) The fuel is produced from renewable biomass and qualifies for a
D code in Table 1 to this section or has received approval for use of a
D code by the Administrator;
(B) The fuel producer has entered into a written contract for the
sale of a specific quantity of biogas to be used as a feedstock for
transportation fuel; and
(C) The fuel produced from the biogas is used as a transportation
fuel.
(iii) A producer of renewable electricity that is generated by co-
firing a combination of renewable biomass and fossil fuel may generate
RINs only for the portion attributable to the renewable biomass, using
the procedure described in paragraph (f)(4) of this section.
(11)(i) For purposes of this section, renewable electricity that is
introduced into a commercial distribution system (transmission grid)
may be considered renewable fuel and the producer may generate RINs if:
(A) The electricity is produced from renewable biomass and
qualifies for a D code in Table 1 of this section or has received
approval for use of a D code by the Administrator;
(B) The fuel producer has entered into a written contract for the
sale of a specific quantity of electricity derived from renewable
biomass sources with a party that uses electricity taken from a
commercial distribution system for use as a transportation fuel, and
such electricity has been introduced into that commercial distribution
system (transmission grid);
(C) The quantity of renewable electricity for which RINs were
generated was sold for use as transportation fuel and for no other
purposes; and
(D) The renewable electricity was loaded onto and withdrawn from a
physically connected transmission grid as defined by the North American
Electrical Reliability Corporation (NERC) regions.
(ii) For purposes of this section, fuel produced from biogas that
is introduced

[[Page 36073]]

into a commercial distribution system may be considered renewable fuel
and the producer may generate RINs if:
(A) The fuel is produced from renewable biomass and qualifies for a
D code in Table 1 of this section or has received approval for use of a
D code by the Administrator;
(B) The fuel producer has entered into a written contract for the
sale of a specific quantity of fuel derived from renewable biomass
sources with a party that uses fuel taken from a commercial
distribution system for transportation fuel, and such fuel has been
introduced into that commercial distribution system (e.g., pipeline);
(C) The quantity of fuel produced from the biogas for which RINs
were generated was sold for use as transportation fuel and for no other
purposes;
(D) The biogas was injected into and withdrawn from a physically
connected carrier pipeline;
(E) The gas that is ultimately withdrawn from that pipeline for use
in a transportation fuel is withdrawn in a manner and at a time
consistent with the transport of gas between the injection and
withdrawal points; and
(F) The volume and heat content of biogas injected into the
pipeline and the volume of gas withdrawn to make a transportation fuel
are measured by continuous metering.
(iii) The fuel sold for use in transportation fuel is considered
produced from renewable biomass only to the extent that:
(A) The amount of fuel sold for use as transportation fuel matches
the amount of fuel derived from renewable biomass that the producer
contracted to have placed into the commercial distribution system; and
(B) No other party relied upon the contracted volume of biogas or
renewable electricity for the creation of RINs.
(iv) For renewable electricity that is generated by co-firing a
combination of renewable biomass and fossil fuel, the producer may
generate RINs only for the portion attributable to the renewable
biomass, using the procedure described in paragraph (f)(4) of this
section.
* * * * *
(14) For purposes of verification, in order for facilities to meet
the renewable electricity production requirement for the biogas-derived
cellulosic diesel and cellulosic naphtha pathways, all conditions below
apply.
(i) The quantity of process electricity produced on-site must be
measured by continuous metering.
(ii) The electricity must be used to provide power to process units
or process equipment at the facility.
(iii) The electrical energy must derive 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.
0
6. Section 80.1427 is amended by:
0
a. Revising paragraphs (a)(1), (a)(1)(i) definition
``RVOCB,i'', (a)(1)(ii) definition ``RVOBBD,i'',
(a)(1)(iii) definition ``RVOAB,i'', (a)(1)(iv) definition
``RVORF,i, (a)(5) introductory text, and (a)(6); and
0
b. Adding paragraph (a)(1)(v), (a)(1)(vi), (a)(1)(vii), (a)(1)(viii),
The additions and revisions read as follows:

Sec. 80.1427 How are RINs used to demonstrate compliance?

(a) Renewable Volume Obligations and Exporter Renewable Volume
Obligations. (1) Except as specified in paragraph (b) of this section
or Sec. 80.1456, each party that is an obligated party under Sec. 80
1406 and is obligated to meet the Renewable Volume Obligations under
Sec. 80.1407, or is an exporter of renewable fuel that is obligated to
meet the Exporter Renewable Volume Obligations under Sec. 80.1430,
must demonstrate pursuant to Sec. 80.1451(a)(1) that it is retiring
for compliance purposes a sufficient number of RINs to satisfy the
following equations.
(i) * * *

RVOCB,i = The renewable Volume Obligation for cellulosic
biofuel for the obligated party for calendar year i, in gallons,
pursuant to Sec. 80.1407.

(ii) * * *

RVOBBD,i = The renewable Volume Obligation for biomass-
based diesel for the obligated party for calendar year i, in
gallons, pursuant to Sec. 80.1407.

(iii) * * *

RVOAB,i = The renewable Volume Obligation for advanced
biofuel for the obligated party for calendar year i, in gallons,
pursuant to 80.1407.

(iv) * * *

RVORF,i = The renewable Volume Obligation for renewable
fuel for the obligated party for calendar year i, in gallons,
pursuant to 80.1407.

(v) Cellulosic biofuel--Exporter.

([Sigma]RINNUM)CB,i+ ([Sigma]RINNUM)CB,i-1=
ERVOCB,i

Where:

([Sigma]RINNUM)CB,i= Sum of all owned gallon-RINs that
are valid for use in complying with the cellulosic biofuel ERVO,
were generated in year i, and are being applied towards the
ERVOCB,i, in gallons.
([Sigma]RINNUM)CB,i-1= Sum of all owned gallon-RINs that are valid
under subparagraph (6) of this paragraph for use in complying with
the cellulosic biofuel ERVO, were generated in year i-1, and are
being applied towards the ERVOCB,i, in gallons.
ERVOCB, k= The Exporter Renewable Volume Obligation for
cellulosic biofuel for the renewable fuel exporter for an export of
renewable fuel k, in gallons, pursuant to Sec. 80.1430.

(vi) Biomass-based diesel--Exporter.

([Sigma]RINNUM)BBD,i+ ([Sigma]RINNUM)BBD,i-1=
ERVOBBD,i

Where:

([Sigma]RINNUM)BBD,i= Sum of all owned gallon-RINs that
are valid for use in complying with the biomass-based diesel ERVO,
were generated in year i, and are being applied towards the
ERVOBBD,i, in gallons.
([Sigma]RINNUM)BBD,i-1= Sum of all owned gallon-RINs that are valid
under subparagraph (6) of this paragraph for use in complying with
the biomass-based diesel ERVO, were generated in year i-1, and are
being applied towards the ERVOBBD,i, in gallons.
ERVOBBD,i= The Exporter Renewable Volume Obligation for
biomass-based diesel for the renewable fuel exporter for an export
of renewable fuel I after 2010, in gallons, pursuant to Sec.
80.1430.

(vii) Advanced biofuel--Exporter.

([Sigma]RINNUM)AB,i+ ([Sigma]RINNUM)AB,i-1=
ERVOAB,i

Where:

([Sigma]RINNUM)AB,i= Sum of all owned gallon-RINs that
are valid for use in complying with the advanced biofuel ERVO, were
generated in year i, and are being applied towards the
ERVOAB,i, in gallons.
([Sigma]RINNUM)AB,i-1= Sum of all owned gallon-RINs that are valid
under subparagraph (6) of this paragraph for use in complying with
the advanced biofuel ERVO, were generated in year i-1, and are being
applied towards the ERVOAB,i, in gallons.
ERVOAB,i= The Exporter Renewable Volume Obligation for
advanced biofuel for the renewable fuel exporter for an export of
renewable fuel i, in gallons, pursuant to Sec. 80.1430.

(viii) Renewable fuel--Exporter.

([Sigma]RINNUM)RF,i+ ([Sigma]RINNUM)RF,i-1=
ERVORF,i

Where:

([Sigma]RINNUM)RF,i= Sum of all owned gallon-RINs that
are valid for use in complying with the renewable fuel (D code 6) E
ERVORF,i, in gallons.
([Sigma]RINNUM)RF,i-1= Sum of all owned gallon-RINs that are valid
under subparagraph (6) of this paragraph for use in complying with
the renewable fuel (D code 6) ERVO, were generated in year i-

[[Page 36074]]

1, and are being applied towards the ERVORF,i, in
gallons.
ERVORF,i= The exporter Renewable Volume Obligation for
renewable fuel for the renewable fuel exporter for an export of
renewable fuel i, in gallons, pursuant to Sec. 80.1430.
* * * * *
(5) The value of ([Sigma]RINNUM)i-1 may not exceed values
determined by the following inequalities as provided in paragraph
(a)(7)(iii) of this section and 80.1442(d), for obligated parties only.
* * * * *
(6) Except as provided in paragraph (a)(7) of this section:
(i) For obligated parties, RINs may only be used to demonstrate
compliance with the RVOs for the calendar year in which they were
generated or the following calendar year.
(ii) [Reserved.]
(iii) For Renewable Fuel Exporters, RINs generated in calendar year
i, must be used to demonstrate compliance with the ERVOs from renewable
fuel export(s) in calendar year i, except as provided in paragraph
(a)(6)(iv) of this section.
(iv) For Renewable Fuel Exporters, RINs generated in calendar year
i-1, may only be used to demonstrate compliance with the ERVOs from
renewable fuel exports in January of calendar year i.
* * * * *
0
7. Section 80.1441 is amended by adding paragraph (e)(2)(iii) to read
as follows:

Sec. 80.1441 Small refinery exemption.

* * * * *
(e) * * *
(2) * * *
(iii) In order to qualify for an extension of its small refinery
exemption, a refinery must meet the definition of ``small refinery'' in
Sec. 80.1401 for all full calendar years between 2006 and the date of
submission of the petition for an extension.
* * * * *
0
8. Section 80.1450 is amended by:
0
a. Adding paragraph (b)(1)(iv)(C);
0
b. Revising paragraphs (b)(1)(v)(C), (b)(1)(v)(D); and adding
(b)(1)(v)(E); and
0
c. Adding paragraphs (h) and (i).
The additions and revisions read as follows:

Sec. 80.1450 What are the registration requirements under the RFS
program?

* * * * *
(b) * * *
(1) * * *
(iv) * * *
(C) To demonstrate compliance with the renewable electricity
production requirement for the biogas-derived cellulosic diesel and
cellulosic naphtha pathways, provide all the following information:
(1) The energy source, equipment and/or process used to generate
the electricity. Permitted sources are raw landfill gas, waste heat
from the production process, unconverted syngas from the Fischer-
Tropsch process, fuel gas from the hydroprocessing, or combined heat-
and-power (CHP) units that use non-fossil fuel based gas or other
renewable sources.
(2) Estimates of the total amount of electricity to be used, the
total amount of grid electricity to be purchased, the total amount of
renewable electricity to be produced, and a calculation of the percent
of total process electricity use to be produced from allowed sources at
the facility.
(v) * * *
(C)(1) For all facilities, copies of documents demonstrating each
facility's actual peak capacity as defined in Sec. 80.1401 if the
maximum rated annual volume output of renewable fuel is not specified
in the air permits specified in paragraphs (b)(1)(v)(A) and
(b)(1)(v)(B) of this section, as appropriate.
(2) For facilities claiming the exemption described in Sec.
80.1403 (c) or (d) which are exempt from air permit requirements and
for which insufficient production records exist to establish actual
peak capacity, copies of document demonstrating the facility's
nameplate capacity, as defined in Sec. 80.1401.
(D) For all facilities producing renewable electricity or fuel from
biogas that qualifies as renewable fuel, submit all relevant
information in Sec. 80.1426(f)(10) or (11), and copies of all
contracts that the track the biogas or renewable electricity from its
original source, to the producer that processes it into renewable fuel,
and finally to the end user that will actually use the renewable
electricity or the renewable fuel derived from biogas for
transportation purposes.
(1) Specific quantity and the heat content, percent efficiency of
transfer, if applicable, and any conversion factors of the biogas or
renewable biomass.
(2) Specific quantity and the heat content and percent efficiency
of transfer, if applicable, and any conversion factors for the
renewable fuel derived from biogas or renewable electricity.
(E) Such other records as may be requested by the Administrator.
* * * * *
(h) Cancellation of Company Registration. (1) EPA may cancel a
company's registration, using the process in paragraph (h)(2) of this
section, if any of the following circumstances exist:
(i) The company has reported no activity in EMTS for one calendar
year (January 1 through December 31) or has failed to meet any EMTS
requirement under Sec. 80.1452;
(ii) The company has failed to comply with the registration
requirements of this section;
(iii) The company has failed to submit any required report within
thirty (30) days of the required submission date under Sec. 80.1451;
or
(iv) The attest engagement required under Sec. 80.1454 has not
been received within thirty (30) days of the required submission date.
(2) EPA will use the following process whenever it decides to
cancel the registration of a company:
(i) EPA will notify the company's owner or Responsible Corporate
Officer (RCO), in writing, that it intends to cancel the company's
registration, and identifying the reasons for that proposed action. The
company will have fourteen (14) calendar days from the date of the
notification to correct the deficiencies identified or explain why
there is no need for corrective action.
(ii) If the basis for EPA's notice of intent to cancel registration
is the absence of EMTS activity for one calendar year, a stated intent
to engage in activity reported through EMTS within the next calendar
year will be sufficient to avoid cancellation of registration.
(iii) If the company does not respond, does not correct identified
deficiencies, or does not explain why such correction is not necessary
within the time allotted for response, EPA may cancel the company's
registration within further notice to the party.
(3) Impact of registration cancellation.
(i) A company whose registration is cancelled shall still be liable
for violation of any requirements of this subpart.
(ii) A company whose registration is cancelled will not be listed
on any public list of actively registered companies that is maintained
by EPA.
(iii) If the company whose registration is cancelled is a renewable
fuel producer or foreign ethanol producer, it will not be listed on any
public list of registered producers maintained by EPA.
(iv) A company whose registration is cancelled will not have access
to any of the electronic reporting systems associated with the
renewable fuel standard program, including the EPA Moderated
Transaction System (EMTS).

[[Page 36075]]

(v) A company whose registration is canceled must submit any
corrections of deficiencies to EPA on forms, and following policies,
established by EPA.
(vi) If a company whose registration has been canceled wishes to
re-register, they may initiate that process by submitting a new
registration, consistent with paragraphs (a)-(c) of this section.
(vii) English language registrations. Any document submitted to EPA
under Sec. 80.1450 must be submitted in English, or shall include an
English translation.
0
9. Section 80.1451 is amended by revising paragraphs (a)(1)(vi) and
(b)(1)(ii)(Q), and by adding paragraph (h) to read as follows:

Sec. 80.1451 What are the reporting requirements under the RFS
program?

(a) * * *
(1) * * *
(vi) The RVOs for obligated parties, as defined in Sec. 80.1427(a)
and for exporters of renewable fuel, as defined in Sec. 80.1427(a) and
80.1430(b), for the reporting year.
* * * * *
(b) * * *
(1) * * *
(ii) * * *
(Q) Producers or importers of renewable fuel produced at facilities
that use biogas for process heat as described in Sec. 80.1426(f)(12),
shall report the total energy supplied to the renewable fuel facility,
in MMBtu based on metering of gas volume. Producers or importers of
renewable fuel produced at facilities that meet the renewable
electricity production requirement for the biogas-derived cellulosic
diesel and cellulosic naphtha pathways as described in Sec.
80.1426(f)(13), shall report the total renewable electricity produced
by the renewable facility, in kilowatt-hour (kWh) or megawatt-hour
(MWh), the total amount of electricity used, the total amount of grid
electricity purchased, and a calculation verifying the percent of total
process electricity from allowed sources produced on-site.
* * * * *
(h) English language reports. Any document submitted to EPA under
Sec. 80.1451 must be submitted in English, or shall include an English
translation.
0
10. Amend Section 80.1452 to revise paragraph (c) introductory text and
add paragraphs (e) and (f) to read as follows:

Sec. 80.1452 What are the requirements related to the EPA Moderated
Transaction System (EMTS)?

* * * * *
(c) Starting July 1, 2010, each time any party sells, separates, or
retires RINs generated on or after July 1, 2010, all of the following
information must be submitted to EPA via the submitting party's EMTS
account within five (5) business days of the reportable event, except
as provided in Sec. 80.1430(f). Starting July 1, 2010, each time any
party purchases RINs generated on or after July 1, 2010, all the
following information must be submitted to EPA via the submitting
party's EMTS account within ten (10) business days of the reportable
event. The reportable event for a RIN separation occurs on the date of
separation as described in Sec. 80.1429. The reportable event for a
RIN retirement occurs on the date of retirement as described in this
subpart.
* * * * *
(e) [Reserved.]
(f) [Reserved.]
0
11. Amend Section 80.1454 by
0
a. Adding paragraph (a)(7);
0
b. Revising paragraph (b)(4)(i);
0
c. Adding paragraph (b)(7);
0
d. Revising paragraph (f)(3)(i) and adding paragraph (f)(5); and
0
e. Revising paragraph (k)(1); and
0
f. Adding paragraph (q).
The additions and revisions read as follows:

Sec. 80.1454 What are the recordkeeping requirements under the RFS
program?

* * * * *
(a) * * *
(7) Records related to any volume of renewable fuel that was
disqualified by the party pursuant to Sec. 80.1433:
(b) * * *
(4) * * *
(i) A list of the RINs owned, purchased, sold, separated, retired,
or reinstated.
* * * * *
(7) Records related to any volume of renewable fuel where RINs were
not generated by the renewable fuel producer or importer pursuant to
Sec. 80.1426(c):
* * * * *
(f) * * *
(3) * * *
(i) A list of the RINs owned, purchased, sold, separated, retired,
or reinstated.
* * * * *
(5) Records related to any volume of renewable fuel that was
disqualified by the party pursuant to Sec. 80.1433.
* * * * *
(k)(1) Biogas and electricity in pathways involving feedstocks
other than grain sorghum. A renewable fuel producer that generates RINs
for renewable CNG/LNG or renewable electricity produced from renewable
biomass for fuels that are used for transportation pursuant to Sec.
80.1426(f)(10) and (11), or that uses process heat from biogas to
generate RINs for renewable fuel pursuant to Sec. 80.1426(f)(12) or
that meets the renewable electricity production requirement for the
biogas-derived cellulosic diesel and cellulosic naphtha pathways
pursuant to Sec. 80.1426(f)(13) shall keep all of the following
additional records:
(i) Documents demonstrating the kilowatt-hours (kWh) of allowable
electricity relied upon under Sec. 80.1426(f)(13) that was generated
at the facility, if applicable.
(ii) The energy source, equipment and/or process used to generate
the electricity relied upon under Sec. 80.1426(f)(13), if applicable.
Permitted sources are raw landfill gas, waste heat from the production
process, unconverted syngas from the Fischer-Tropsch process, fuel gas
from the hydroprocessing, or combined heat-and-power (CHP) units that
use non-fossil fuel based gas or other renewable sources.
(iii) Contracts and documents memorializing the sale of renewable
CNG/LNG or renewable electricity for use as transportation fuel relied
upon in Sec. 80.1426(f)(10), Sec. 80.1426(f)(11), or for use of
biogas for use as process heat to make renewable fuel as relied upon in
Sec. 80.1426(f)(12) and the transfer of title of the biogas or
renewable electricity and all associated environmental attributes from
the point of generation to the facility which sells or uses the fuel
for transportation purposes.
(iv) Documents demonstrating the volume and energy content of
biogas, or kilowatts of renewable electricity, relied upon under Sec.
80.1426(f)(10) that was delivered to the facility which sells or uses
the fuel for transportation purposes.
(v) Documents demonstrating the volume and energy content of
biogas, or kilowatts of renewable electricity, relied upon under Sec.
80.1426(f)(11), or biogas relied upon under Sec. 80.1426(f)(12) that
was placed into the common carrier pipeline (for biogas) or
transmission line shared power grid (for renewable electricity).
(vi) Documents demonstrating the volume and energy content of
biogas relied upon under Sec. 80.1426(f)(12) at the point of
distribution.
(vii) Affidavits from the biogas or renewable electricity producer
and all parties that held title to the biogas or renewable electricity
confirming that title and environmental attributes of the biogas or
renewable electricity relied upon under Sec. 80.1426(f)(10) and (11)
were used for transportation purposes only, and that the environmental
attributes of the biogas or process

[[Page 36076]]

electricity relied upon under Sec. 80.1426(f)(12) or Sec.
80.1426(f)(13) were used for process heat or electricity at the
renewable fuel producer's facility, and for no other purpose. The
renewable fuel producer shall create and/or obtain these affidavits at
least once per calendar quarter.
(viii) The biogas or renewable electricity producer's Compliance
Certification required under Title V of the Clean Air Act.
(ix) Documents demonstrating the total amount of grid electricity
purchased and calculations showing the percent of total electricity
usage provided by allowable electricity production at the facility, if
applicable.
(x) Such other records as may be requested by the Administrator.
* * * * *
(q) English language records. Any document requested by the
Administrator under this section must be submitted in English, or shall
include an English translation.
0
12. Section 80.1463 is amended by adding paragraph (d) to read as
follows:

Sec. 80.1463 What penalties apply under the RFS program?

* * * * *
(d) Any person violating Sec. 80.1460(b)(1)-(4) or (6) engages in
a separate violation for each day that an invalid RIN remains available
for use in RFS compliance, and each such daily violation is punishable
by the maximum daily penalty allowed under the Clean Air Act.
0
13. Section 80.1466 is amended by revising the section heading and
paragraphs (a), (d)(1), (d)(1)(vi), (d)(3)(ii), (e)(1)(i), (f)
introductory text, (h), (h)(1), and (o)(2) and adding paragraph (p) as
follows:

Sec. 80.1466 What are the additional requirements under this subpart
for RIN-generating foreign producers, non RIN-generating foreign
producers, foreign ethanol producers and importers of renewable fuels?

(a) Foreign producer of renewable fuel. For purposes of this
subpart, a foreign producer of renewable fuel is a person located
outside the United States, the Commonwealth of Puerto Rico, the Virgin
Islands, Guam, American Samoa, and the Commonwealth of the Northern
Mariana Islands (collectively referred to in this section as ``the
United States'') that has been registered with EPA as a renewable fuel
producer or foreign ethanol producer, regardless of whether the foreign
renewable fuel producer generates RINs or an importer of renewable fuel
generates RINs for the fuel. Hereinafter referred to as a ``foreign
producer'' under this section.
(d) * * * (1) On each occasion that RFS-FRRF is loaded onto a
vessel for transport to the United States the foreign producer shall
have an independent third party do all the following:
* * * * *
(vi) Review original documents that reflect movement and storage of
the RFS-FRRF from the foreign producer to the load port, and from this
review determine all the following:
* * * * *
(3) * * *
(ii) Be independent under the criteria specified in Sec.
80.65(f)(2)(iii); and
* * * * *
(e) * * * (1)(i) Any foreign producer and any United States
importer of RFS-FRRF shall compare the results from the load port
testing under paragraph (d) of this section, with the port of entry
testing as reported under paragraph (k) of this section, for the volume
of renewable fuel, standardized per Sec. 80.1426(f)(8), except as
specified in paragraph (e)(1)(ii) of this section.
* * * * *
(f) Foreign producer commitments. Any foreign producer shall commit
to and comply with the provisions contained in this paragraph (f) as a
condition to being approved as a foreign producer under this subpart.
* * * * *
(h) Bond posting. Any foreign producer shall meet the requirements
of this paragraph (h) as a condition to approval as a foreign producer
under this subpart and on a continuing basis if the foreign producer
exceeds projections used in calculated the bond.
(1) The foreign producer shall post a bond of the amount calculated
using one of the two following equations whichever equation results in
a higher bond value:

Bond = G * $0.01

Bond = .25 * [Sigma](Mi * RINi)

Where:

Bond = amount of the bond in U.S. dollars.
G = the greater of: the largest volume of renewable fuel produced by
the foreign producer and exported to the United States, in gallons,
during a single calendar year among the five preceding calendar
years, or the largest volume of renewable fuel that the foreign
producer expects to export to the Unites States during any calendar
year identified in the Production Outlook Report required by Sec.
80.1449. If the volume of renewable fuel anticipated to be exported
to the United States during any calendar year increases above the
value used in calculating the existing bond amount, the foreign
producer shall increase the bond by using the higher anticipated
export volume for the calendar year to calculate a higher bond
amount and purchasing the higher bond prior to the generation of
RINs to reflect the increase in export volume. Mi = RIN
multiplier for specified D code, i, in U.S. dollars, as follows:
The RIN multiplier for a D3 RIN is $0.78
The RIN multiplier for a D4 RIN is $1.30
The RIN multiplier for a D5 RIN is $0.80
The RIN multiplier for a D6 RIN is $0.02
The RIN multiplier for a D7 RIN is $0.78
RINi = the greater of: (i) the largest quantity of
RINs for a specified D code, i, produced by the foreign producer and
exported to the United States, in gallons, during a single calendar
year among the five preceding calendar years, or (ii) the largest
quantity of RINs that the foreign producer expects to export to the
United States during any calendar year identified in the Production
Outlook Report required by Sec. 80.1449. If the volume of renewable
fuel anticipated to be exported to the United States during any
calendar year increases above the value used in calculating the
existing bond amount, the foreign producer shall increase the bond
by using the higher anticipated export volume for the calendar year
to calculate a higher bond amount and purchasing the higher bond
prior to the generation of RINs to reflect the increased export
volume.
* * * * *
(o)
(2) Signed by the president or owner of the foreign producer
company, or by that person's immediate designee, and shall contain the
following declaration: ``I hereby certify: (1) That I have actual
authority to sign on behalf of and to bind [INSERT NAME OF FOREIGN
PRODUCER] with regard to all statements contained herein; (2) that I am
aware that the information contained herein is being Certified, or
submitted to the United States Environmental Protection Agency, under
the requirements of 40 CFR part 80, subpart M, and that the information
is material for determining compliance under these regulations; and (3)
that I have read and understand the information being Certified or
submitted, and this information is true, complete and correct to the
best of my knowledge and belief after I have taken reasonable and
appropriate steps to verify the accuracy thereof. I affirm that I have
read and understand the provisions of 40 CFR part 80, subpart M,
including 40 CFR 80.1466 apply to [INSERT NAME OF FOREIGN PRODUCER].
Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 1001, the
penalty for furnishing false, incomplete or misleading information in
this certification or submission is a fine of

[[Page 36077]]

up to $10,000 U.S., and/or imprisonment for up to five years.''
(p) Foreign Produced Renewable Fuel and Foreign Produced Ethanol
for Which RINs Have Been or Will Be Generated by the Importer
(1) For non-RIN generating foreign producers and foreign ethanol
producers already registered pursuant to section Sec. 80.1450, all of
the requirements in paragraphs (a) through (o) of this section must be
satisfied no later than January 1, 2013.
(2) For RIN generating foreign producers and foreign ethanol
producers already registered pursuant to section Sec. 80.1450 and
80.1466, paragraph (h) of this section must be satisfied no later than
January 1, 2013 if the required amount in paragraph (h) of this section
exceeds the original amount of the bond posted when the producer was
originally approved under 80.1466.
0
14. Section 80.1500 is amended by revising the definitions of E10, E15,
and EX to read as follows:

Sec. 80.1500 Definitions.

* * * * *
E10 means a gasoline-ethanol blend that contains at least 9 and no
more than 10 volume percent ethanol.
E15 means a gasoline-ethanol blend that contains greater than 10
volume percent ethanol and not more than 15 volume percent ethanol.
EX means a gasoline-ethanol blend that contains less than 9 volume
percent ethanol where X equals the maximum volume percent ethanol in
the gasoline-ethanol blend.
* * * * *
0
15. Section 80.1501 is amended by revising the section 80.1501 heading
paragraphs (a) introductory text, (b)(3)(i) and (iv), and (b)(4)(ii) to
read as follows:

Sec. 80.1501 What are the labeling requirements that apply to
retailers and wholesale purchaser-consumers of gasoline-ethanol blends
that contain greater than 10 volume percent ethanol and not more than
15 volume percent ethanol?

(a) Any retailer or wholesale purchaser-consumer who sells,
dispenses, or offers for sale or dispensing E15 shall affix the
following conspicuous and legible label to the fuel dispenser:
* * * * *
(b) * * *
(3) * * *
(i) The word ``ATTENTION'' shall be capitalized in 20-point,
orange, Helvetica Neue LT 77 Bold Condensed font, and shall be placed
in the top 1.25 inches of the label as further described in (b)(4)(iii)
below.
* * * * *
(iv) The words ``Use only in'' shall be in 20-point, left-
justified, black, Helvetica Bold font in the bottom 1.875 inches of the
label.
(4) * * *
* * * * *
(ii) The background of the bottom 1.875 inches of the label shall
be orange.
* * * * *
0
16. Section 80.1502 is amended by revising paragraphs (b)(3)(iii)(A),
(b)(3)(iv), (b)(4)(iv)(B), (b)(4)(v)(A), (c)(4), and (c)(6) to read as
follows:

Sec. 80.1502 What are the survey requirements related to gasoline-
ethanol blends?

* * * * *
(b) * * *
(3) * * *
(iii) * * *
(A) Samples collected at retail outlets shall be shipped the same
day the samples are collected via ground service to the laboratory and
analyzed for oxygenate content. Samples collected at a dispenser
labeled E15 in any manner, or at a tank serving such a dispenser, shall
also be analyzed for RVP during the high ozone season defined in Sec.
80.27(a)(2)(ii) or any SIP approved or promulgated under Sec. Sec. 110
or 172 of the Clean Air Act. Such analysis shall be completed within 10
days after receipt of the sample in the laboratory. Nothing in this
section shall be interpreted to require RVP testing of a sample from
any dispenser or tank serving it unless the dispenser is labeled E15 in
any manner.
* * * * *
(iv) In the case of any test that yields a result that does not
match the label affixed to the product (e.g., a sample greater than 15
volume percent ethanol dispensed from a fuel dispenser labeled as
``E15'' or a sample containing greater than 10 volume percent ethanol
and not more than 15 volume percent ethanol dispensed from a fuel
dispenser not labeled as ``E15''), or the RVP standard of Sec.
80.27(a)(2), the independent survey association shall, within 24 hours
after the laboratory has completed analysis of the sample, send
notification of the test result as follows:
* * * * *
(4) * * *
(iv) * * *
(B) In the case of any retail outlet from which a sample of
gasoline was collected during a survey and determined to have an
ethanol content that does not match the fuel dispenser label (e.g. a
sample greater than 15 volume percent ethanol dispensed from a fuel
dispenser labeled as ``E15'' or a sample with greater than 10 volume
percent ethanol and not more than 15 volume percent ethanol dispensed
from a fuel dispenser not labeled as ``E15'') or determined to have a
dispenser containing fuel whose RVP does not comply with Sec.
80.27(a)(2), that retail outlet shall be included in the subsequent
survey.
* * * * *
(v) * * *
(A) The minimum number of samples to be included in the survey plan
for each calendar year shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP14JN13.003

Where:

n = minimum number of samples in a year-long survey series. However,
in no case shall n be smaller than 7,500.
Z[alpha] = upper percentile point from the normal distribution to
achieve a one-tailed 95% confidence level (5% [alpha]-level). Thus,
Z[alpha] equals 1.645.
Z[beta] = upper percentile point to achieve 95% power. Thus,
Z[beta] equals 1.645.
[phiv]1 = the maximum proportion of non-compliant stations for a
region to be deemed compliant. In this test, the parameter needs to
be 5% or greater, i.e., 5% or more of the stations, within a stratum
such that the region is considered non-compliant. For this survey,
[phiv]1 will be 5%.
[phiv]o= the underlying proportion of non-compliant stations in a
sample. For the first survey plan, [phiv]o will be 2.3%. For
subsequent survey plans, [phiv]o will be the average of the
proportion of stations found to be non-compliant over the previous
four surveys.
Stn = number of sampling strata. For purposes of this
survey program, Stn equals 3.
Fa = adjustment factor for the number of extra samples
required to compensate for collected samples that cannot be included
in the survey, based on the

[[Page 36078]]

number of additional samples required during the previous four
surveys. However, in no case shall the value of Fa be
smaller than 1.1.
Fb = adjustment factor for the number of samples required
to resample each retail outlet with test results exceeding the
labeled amount (e.g. a sample greater than 15 volume percent ethanol
dispensed from a fuel dispenser labeled as ``E15'', a sample with
greater than 10 volume percent ethanol and not more than 15 volume
percent ethanol dispensed from a fuel dispenser not labeled as
``E15''), or a sample dispensed from a fuel dispenser labeled as
``E15'' with greater than the applicable seasonal and geographic RVP
pursuant to Sec. 80.27, based on the rate of resampling required
during the previous four surveys. However, in no case shall the
value of Fb be smaller than 1.1.
Sun = number of surveys per year. For purposes of this
survey program, Sun equals 4.
* * * * *
(c) * * *
(4) The survey program plan must be sent to the following address:
Director, Compliance Division, U.S. Environmental Protection Agency,
1200 Pennsylvania Ave. NW., Mail Code 6506J, Washington, DC 20460.
* * * * *
(6) The approving official for a survey plan under this section is
the Director of the Compliance Division, Office of Transportation and
Air Quality.
* * * * *
0
17. Section 80.1503 is amended by revising paragraphs (a)(1)(vi)(B)(3),
(a)(1)(vi)(C)(2), adding paragraph (a)(1)(vi)(C)(3), and revising
paragraphs (b)(1)(vi)(B) through (D).
The revisions and additions read as follows:

Sec. 80.1503 What are the product transfer document requirements for
gasoline-ethanol blends, gasolines, and conventional blendstocks for
oxygenate blending subject to this subpart?

(a) * * *
(1) * * *
(vi) * * *
(B) * * *
(3) ``The use of this blendstock/gasoline to manufacture a
gasoline-ethanol blend containing anything other than between 9 and 10
volume percent ethanol may cause a summertime RVP violation.''
(C) * * *
(2) The requirements in paragraph (a)(1) do not apply to
reformulated gasoline blendstock for oxygenate blending, as defined in
Sec. 80.2(kk), which is subject to the product transfer document
requirements of Sec. 80.69 and Sec. 80.77.
(3) Except for transfers to truck carriers, retailers, or wholesale
purchaser-consumers, product codes may be used to convey the
information required under paragraph (a)(1) of this section if such
codes are clearly understood by each transferee.
(b) * * *
(1) * * *
(vi) * * *
(B) For gasoline containing less than 9 volume percent ethanol, the
following statement: ``EX--Contains up to X% ethanol. The RVP does not
exceed [fill in appropriate value] psi.'' The term X refers to the
maximum volume percent ethanol present in the gasoline.
(C) For gasoline containing between 9 and 10 volume percent ethanol
(E10), the following statement: ``E10: Contains between 9 and 10 vol %
ethanol. The RVP does not exceed [fill in appropriate value] psi. The 1
psi RVP waiver applies to this gasoline. Do not mix with gasoline
containing anything other than between 9 and 10 vol % ethanol.''
(D) For gasoline containing greater than 10 volume percent and not
more than 15 volume percent ethanol (E15), the following statement:
``E15: Contains up to 15 vol % ethanol. The RVP does not exceed [fill
in appropriate value] psi;'' or
* * * * *
0
18. Section 80.1504 is amended by revising paragraphs (a)(1), (a)(3),
(e), and (g) to read as follows:

Sec. 80.1504 What acts are prohibited under this subpart?

* * * * *
(a)(1) Sell, introduce, cause or permit the sale or introduction of
gasoline containing greater than 10 volume percent ethanol (i.e.,
greater than E10) into any model year 2000 or older light-duty gasoline
motor vehicle, any heavy-duty gasoline motor vehicle or engine, any
highway or off-highway motorcycle, or any gasoline-powered nonroad
engines, vehicles or equipment.
* * * * *
(3) Notwithstanding paragraphs (a)(1) and (a)(2) of this section,
no person shall be prohibited from manufacturing, selling, introducing,
or causing or allowing the sale or introduction of gasoline containing
greater than 10 volume percent ethanol into any flex-fuel vehicle.
* * * * *
(e)(1) Improperly blend, or cause the improper blending of, ethanol
into conventional blendstock for oxygenate blending, gasoline or
gasoline already containing ethanol, in a manner inconsistent with the
information on the product transfer document under Sec.
80.1503(a)(1)(vi) or Sec. 80.1503(b)(1)(vi);
(2) No person shall produce E10 by blending ethanol and gasoline in
a manner designed to produce a fuel that contains less than 9.0 or more
than 10.0 volume percent ethanol.
(3) No person shall produce E15 by blending ethanol and gasoline in
a manner designed to produce a fuel that contains less than 10.0 volume
percent ethanol or more than 15.0 volume percent ethanol.
(4) No person shall produce EX by blending ethanol and gasoline in
a manner designed to produce a fuel that contains less than 9.0 volume
percent ethanol.
* * * * *
(g) For gasoline during the regulatory control periods, combine any
gasoline-ethanol blend that qualifies for the 1 psi allowance under the
special regulatory treatment as provided by Sec. 80.27(d) applicable
to 9-10 volume percent gasoline-ethanol blends with any gasoline
containing less than 9 volume percent ethanol or more than 10 volume
percent ethanol up to a maximum of 15 volume percent ethanol.
* * * * *
0
19. Section 80.1508 is amended by revising paragraph (b) as follows:

Sec. 80.1508 What evidence may be used to determine compliance with
the requirements of this subpart and liability for violations of this
subpart?

* * * * *
(b) Determinations of compliance with the requirements of this
subpart and determinations of liability for any violation of this
subpart may be based on information obtained from any source or
location. Such information may include, but is not limited to, business
records and commercial documents.
0
20. Section 80.1509 is added to read as follows:

Sec. 80.1509 Rounding a test result for purposes of this Subpart.

The provisions of Section 80.9 apply for purposes of determining
the ethanol content of a gasoline-ethanol blend under this subpart.

[FR Doc. 2013-12714 Filed 6-13-13; 8:45 am]
BILLING CODE 6560-50-P

This site is protected by reCAPTCHA and the Google Privacy Policy and Terms of Service apply.