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Fuels and Fuel Additives

Questions and Answers on Changes to the Renewable Fuel Standard Program (RFS2)


Compliance and Innovative Strategies Division Office of Transportation and Air Quality U.S. Environmental Protection Agency

Introduction

The final rulemaking for the Renewable Fuel Standard (RFS2) was published in the Federal Register on March 26, 2010.

To assist regulated parties, we have collected questions pertaining to a variety of implementation issues and generated responses to those questions.

This frequent questions list was prepared by EPA's Office of Transportation and Air Quality (OTAQ). We will continue to update this frequent questions list periodically as new questions arise.

Regulated parties may use this frequent questions list to aid in achieving compliance with the RFS2 program regulations. However, this frequent questions list does not in any way alter the requirements of those regulations. While the answers provided in this frequent questions list represent the Agency's general plans for implementation of the regulations at this time, some of the responses may change as additional information becomes available, or as the Agency further considers certain issues.

This question and answer list does not establish or change legal rights or obligations. It does not establish binding rules or requirements and is not fully determinative of the issues addressed. Agency decisions in any particular case will be made applying the law and regulations on the basis of specific facts and actual action.

While we have attempted to include answers to all of the questions submitted to us, the necessity for policy decisions and/or resource constraints may have prevented the inclusion of certain questions. Questions not answered in this frequent questions list will be answered in subsequent updates. Questions that merely require a justification of the regulations, or that have been previously answered in the preamble to the regulations and require no further elaboration have generally been omitted.

Questions recently added or revised as of July 2010 are as follows: Section 6 introductory text, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7, 6.8

  1. Renewable fuel definitions
  2. Renewable biomass
  3. Assignment of pathways to renewable fuel
  4. Grandfathering
  5. Application of standards
  6. Treatment of biomass-based diesel in 2009 and 2010
  7. Renewable volume obligations
  8. Registration
  9. Generation of RINs
  10. RIN transactions
  11. Reinstating RINs
  12. Reporting
  13. Recordkeeping
  14. Attest engagements
  15. Foreign producers and importers
  16. Other questions
  1. Renewable fuel definitions

    1. While there is no renewable fuel obligation under the RFS2 program for the production or importation of conventional jet fuel, RINs can be generated for renewable jet fuel. Is that right?

      A: As described in 80.1407, only gasoline and diesel fuels produced or imported into the U.S. are subject to the renewable fuel standards. Thus, only gasoline and diesel fuel volumes produced or imported by an obligated party factor into their RVOs (renewable fuel volume obligations) calculated in 80.1407. Therefore, jet fuel production or importation is not subject to the renewable fuel standards. However, producers or importers of renewable jet fuel can generate RINs to represent that jet fuel if their fuel meets the definition of renewable fuel in 80.1401 and EPA has approved a D code pursuant to Table 1 to 80.1426 or 80.1416.

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  2. Renewable biomass

    1. What are the recordkeeping requirements for a renewable fuel producer that uses animal fats as feedstocks for renewable fuel?

      A: Renewable fuel producers using animal wastes as feedstocks are required under 40 CFR 80.1454(d)(3) to obtain from their feedstock supplier, and maintain in their records, documents which certify that the feedstock meets the definition of renewable biomass, describe the feedstock, and identify the process that was used to generate the feedstock. For example, a renewable fuel producer could maintain as a record a contract with a feedstock supplier that states that the supplier will provide the producer with a certain volume of chicken fat that meets the definition of renewable biomass because it is an animal waste or byproduct, and that it was produced as a by-product of the chicken rendering process.

    2. Can woody residues from a sawmill or paper mill be used as a feedstock for renewable fuels under the RFS2 program?

      A: For fuel to qualify under the RFS2 program, it must be derived from feedstocks that meet the definition of renewable biomass. Woody residues from saw mills and paper mills may meet the definition of renewable biomass in certain circumstances. If the woody residues are from planted trees from actively managed tree plantations on non-federal land cleared at any time prior to December 19, 2007, the residues are considered "tree residue" under RFS2 and therefore fall within the definition of "renewable biomass." However, only the biogenically derived portion of the renewable fuel that can be traced back to feedstocks meeting the definition of renewable biomass will qualify for RIN generation. That is, the producer may only generate RINs for the biogenic fraction of fuel produced that corresponds to the fraction of the feedstock that is tree residue, using the procedures described in ASTM test method D-6866. Thus, if the tree residues are mixed with chemicals or other materials during processing at the lumber or paper mills, producers may only generate RINs for the portion of the mixture that is actually derived from planted trees. In addition, for woody residue from saw mills or paper mills to be considered "tree residue" within the definition of renewable biomass it must not be mixed with similar residue from trees that do not originate in tree plantations. See the definition of "tree residue" in 80.1401 and preamble section II.B.4.a.ii for further discussion

    3. Are palm oil plantations considered agricultural land or tree plantations under RFS2?

      A: Palm oil trees are planted and managed for the purpose of harvesting palm fruit and not for harvesting the trees themselves, in the same way that a fruit orchard is planted and managed to yield fruit and not woody biomass per se. The RFS2 definition of forestland in 80.1401 includes tree plantations but excludes orchards, as we believe orchards are more appropriately considered a type of agricultural land (cropland, specifically), and orchard fruits planted crops. Thus, palm fruit qualifies as planted crops under the EISA definition of renewable biomass, and oil palm plantations would have to meet the criteria for existing agricultural land in order for their fruit and crop residue to qualify as renewable biomass under RFS2.

    4. How does the "active management" requirement in the definition of renewable biomass apply to land that changes status in the future?

      A: In RFS2, EPA has interpreted the EISA requirement that existing agricultural land be "cleared or cultivated at any time prior to [December 19, 2007] and actively managed or fallow and nonforested" to apply to land that existed as such on December 19, 2007. As a result, land meeting the existing agricultural land definition on December 19, 2007 will continue to meet the definition indefinitely, regardless of whether it is reforested and subsequently deforested in the future. Please see preamble section II.B.4.a. for further discussion of this issue.

    5. What are the RFS2 requirements for renewable fuel producers to track soy feedstocks?

      A: Since soy is considered a planted crop for purposes of RFS2, producers of renewable fuel made from soy grown on U.S. agricultural lands are covered by the aggregate compliance approach in §80.1454(g). Those producers using domestic soy need not maintain feedstock records until and unless EPA makes a finding that the aggregate compliance approach for planted crops and crop residue from U.S. agricultural lands is no longer applicable.

      Producers (domestic or foreign) or RIN-generating importers of fuel made from imported soy (beans or oil) as a biodiesel feedstock must maintain records that serve as evidence that their soy came from land that was cleared or cultivated prior to December 19, 2007 and that was actively managed or fallow, and nonforested on that date. This could consist of one of the following documents, which must be traceable to the land in question: sales records for planted crops, crop residue, or livestock; purchasing records for fertilizer, weed control, seeds, seedlings, or other nursery stock; a written management plan for agricultural purposes; documentation of participation in an agricultural program sponsored by a Federal, state, or local government agency; or documentation of land management in accordance with an agricultural product certification program. See section 80.1454(g)(2).

      Additionally, RIN-generating producers and RIN-generating importers of biodiesel made with foreign-grown soy as a feedstock must report to EPA on a quarterly basis a summary of the types and quantities of feedstocks used in that quarter and electronic data identifying the land where the feedstocks were harvested. See section 80.1451(d).

    6. Does a renewable fuel producer have to report and maintain records on the feedstocks for every batch of renewable fuel they produce?

      A: All renewable fuel producers must report and maintain records concerning the type and amount of feedstocks used for each batch of renewable fuel produced (see 80.1451(b)(1)(ii)(K) and 80.1454(b)(3)(vi)). With regard to the renewable biomass recordkeeping and reporting requirements, if a producer, whether foreign or domestic, is making renewable fuel using feedstocks that are planted crops or crop residue from existing U.S. agricultural land, then that feedstock is subject to the aggregate compliance approach in section 80.1454(g) and the producer need not maintain records for those feedstocks unless EPA makes a finding that the 2007 baseline amount of U.S. agricultural land has been exceeded and the aggregate compliance approach for such lands is terminated. However, if a producer is using any other type of feedstock, including crops or crop residues from existing foreign agricultural land, and either the producer or an importer is generating RINs for that fuel, then the producer must maintain records concerning the type and source of the feedstock for all fuel produced, pursuant to section 80.1454(c) and (d). Additionally, the producer must report to EPA on a quarterly basis concerning the source of the feedstocks, as required in section 80.1451(d). Whether the records and reporting should be done on a per-batch basis depends on the extent to which there is variability in the feedstocks used for different batches.

    7. How does a renewable fuel producer document that the MSW feedstock that they are using to produce cellulosic ethanol meets the definition of separated MSW as defined in Section 80.1426(f)(5)(i)(C )? How does the producer quantify the portion of the final fuel volume that qualifies as cellulosic biofuel to generate cellulosic biofuel RINs?

      A: The renewable fuel producer using separated MSW feedstock to produce renewable fuels such as cellulosic ethanol, cellulosic diesel, cellulosic naphtha, etc. must document that their feedstock meets the definition of separated municipal solid waste (MSW), which is "material remaining after separation actions have been taken to remove recyclable paper, cardboard, plastics, rubber, textiles, metals, and glass from municipal solid waste, and which is composed of both cellulosic and non-cellulosic materials" pursuant to §80.1426(f)(5)(i)(C ). For such waste streams to qualify as separated MSW, it must be collected according to a plan submitted to and approved by U.S. EPA under the registration procedures specified in §80.1450(b)(1)(viii). This plan must have specific information, including the following:

      1. The location of the municipal waste facility from which the separated food and yard waste is collected.
      2. Extent and nature of recycling that occurred prior to receipt of the waste material by the renewable fuel producer;
      3. Identification of available recycling technology and practices that are appropriate for removing recycling materials from the waste stream by the fuel producer; and
      4. Identification of the technology or practices selected for implementation by the fuel producer including an explanation for such selection, and reasons why other technologies or practices were not.

      EPA is in the process of developing additional guidance for the MSW Separation Plan.

      In order to quantify the portion of the final renewable fuel volume that qualifies as cellulosic biofuel for purposes of generating RINs, the producer is required (pursuant to §80.1426(f)(5)(v)) to use the carbon-14 dating test method described in §80.1426(f)(9). The carbon-14 test method quantifies the fossil fuel portion of the final fuel and the remaining volume that is not the fossil fuel portion qualifies as cellulosic biofuel.

    8. What materials from non-federal forestlands meet the definition of renewable biomass in RFS2?

      A: Slash and pre-commercial thinnings from non-federal forestland that is not ecologically sensitive forestland qualify as renewable biomass for purposes of RFS2.

      Slash is defined in 40 CFR 80.1401 as the residue, including treetops, branches and bark, left on the ground after logging or accumulating as a result of a storm, fire, delimbing or other similar disturbance. EPA interprets slash as being the residue that would typically be left on the ground after logging or a disturbance were it not for RFS2. We acknowledge that the demand for such material may increase due to increased demand for feedstocks that meet the definition of renewable biomass for use in renewable fuel production. We also acknowledge that to meet this demand, logging techniques on non-federal forestland may be altered in order to collect residue in the most efficient and economical way, such as leaving waste treetops intact on merchantable trees until they have been removed from the forest. We believe that the intent of the regulatory definition may be met by considering slash to include what was traditionally considered waste, and was typically left on the ground at the site of timber harvesting prior to the RFS program, whether or not efficient harvesting practices continue to lead to that result. Slash does not include pulpwood from the actual sawtimber trees, and only includes pulpwood from sawtimber tree residues (treetops, branches and bark).

      The term pre-commercial thinnings is defined in 40 CFR 80.1401 as trees, including unhealthy or diseased trees, removed to reduce stocking to concentrate growth on more desirable, healthy trees, or other vegetative materials that is removed to promote tree growth. EPA interprets pre-commercial thinnings to include all thinnings removed to improve growth and quality in the remaining healthy trees in the stand, provided substantial stock remains in the stand. Thus, unmerchantable trees removed during a clear-cut would not be considered pre-commercial thinnings because the term thinning requires that substantial stock remains in the stand. Furthermore, those trees remaining in the stand after a pre-commercial thinning cannot generally be considered pre-commercial thinnings at a later date. Pre-commercial thinnings that meet these criteria are considered renewable biomass regardless of the timing of the thinning process (whether the thinning is conducted before a commercial harvest or during a selective commercial harvest of a portion of the trees in a stand for purposes other than renewable fuel feedstock production) or the diameter of the thinned trees. 40 CFR 80.1401 also requires slash and pre-commercial thinnings must be harvested 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. Forestland is defined in 40 CFR 80.1401, in relevant part here, as generally undeveloped land covering a minimum area of 1 acre upon which the primary vegetative species are trees, including land that formerly had such tree cover and that will be regenerated and tree plantations. Ecologically sensitive forestland includes ecological communities in the U.S. with Natural Heritage Programs global ranking of G1 or G2, or with a State ranking of S1, S2, or S3 and old growth and late successional forestland which is characterized by trees at least 200 years old.

      If woody biomass is harvested in a manner consistent with the above interpretations, then it would qualify as slash and pre-commercial thinnings, and would meet the RFS2 definition of renewable biomass. The woody biomass would not lose its status as renewable biomass as a result of being subject to an additional processing step to extract the components that will be used for manufacturing other wood products, such as paper or building materials. However, EPA would only consider the biogenic portion of the waste from the processing to be slash and pre-commercial thinnings. To the extent that the slash and pre-commercial thinnings are mixed with chemicals or other materials during processing, the renewable fuel producer may only generate RINs for the fraction of renewable fuel made from the portion of the waste mixture that is actually biogenic (determined using the procedures described in ASTM test method D-6866, See 40 CFR 80.1426(f)(9)) and must be traced back to feedstocks meeting the definition of renewable biomass. Furthermore, cellulosic biofuel RINs may only be generated for the portion of the fuel that is made from feedstocks that both meets the renewable biomass requirements and consists of cellulose, hemi-cellulose or lignin.

      Any producer using these types of feedstocks must also meet the relevant renewable biomass recordkeeping and reporting requirements in 40 CFR 80.1451 and 80.1454 to demonstrate that their feedstock meets the renewable biomass definitions, as well as all other applicable requirements in 40 CFR Part 80, Subpart M.

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  3. Assignment of pathways to renewable fuel

    1. Will current canola based biodiesel production fall under the grandfathering provisions of the RFS2 regulations?

      A: Biodiesel facilities may qualify for the exemption under 80.1403(c) from the requirement that renewable fuels achieve a minimum 20% GHG reduction as compared to baseline fuels if they "commenced construction" prior to the date of enactment of EISA. Thus, RINs may be generated for qualifying renewable fuel produced by such facilities even if their feedstock and/or pathway is not listed in Table 1 to 80.1426. However, the fuel must meet all other requirements of the definition of the definitions in 80.1401, including the renewable biomass requirement, and RINs generated under these provisions must be assigned a D code of 6. The exemption in 80.1403(c) is limited in application to the 20% GHG reduction requirement for general renewable fuel. There are no exemptions in EISA or the RFS2 regulations from the requirements regarding GHG reduction requirements for renewable fuels identified as biomass-based diesel or advanced biofuel.

      Section 80.1403(d) provides a similar exemption from the 20% GHG reduction requirements for certain ethanol production facilities that commenced construction after enactment of EISA, but before December 31, 2009. Biodiesel facilities are not eligible for this exemption, For additional discussion of the exemptions in 80.1403 , see also section 4, below.

    2. Was Jatropha analyzed for this final rule and, if so, what D-code applies?

      A: The GHG emissions performance of a Jatropha-based pathway was not analyzed for the final rule because sufficient information was not available. Since EPA has not yet assigned a D code for this pathway, a producer cannot generate RINs for biofuels made from Jatropha unless the facility has been grandfathered according to 80.1403 and 80.1426(f)(6), and the fuel meets all other components of the definition of "renewable fuel" including the renewable biomass requirement.

    3. If none of the existing pathways specified in Table 1 to 80.1426 are applicable to a proposed biofuel pathway, does that mean that producers need to go through the petition process and have EPA analyze the GHG performance of the new pathway before any RINs can be generated for that fuel?

      A: Prior to July 1, 2010 when the RFS2 regulations take effect, fuel producers can generate RINs under the RFS1 rules, as long as the fuel meets the definition of renewable fuel under 80.1101. Beginning July 1, 2010, RFS2 regulations will apply and fuels produced through pathways not included in the regulations (see Table 1 to 80.1426) or approved by EPA in response to a petition under 80.1416 will not be eligible for generation of RINs (unless the facility's volume qualifies for grandfathering under 80.1403 - see additional questions in Section 4 below).

      Note that EPA has identified four additional pathways not included in the February 2010 final rule which will be added to this final rule later this year. These additional pathways are ethanol from grain sorghum, biodiesel from canola, biodiesel from palm oil and biofuel from wood pulp. EPA had not completed its assessment of these biofuel pathways in time for the February final rule but will do so as a supplement to this final rule. Since EPA is on track to finalize results for these pathways, producers of fuel for these four pathways should not apply through the petition process.

    4. If a biodiesel producer was able to show a full identity preserved chain of custody demonstrating that the palm oil feedstock they use is from lands cleared prior to December 19, 2007 and that meets all other components of the renewable biomass definition, could that producer generate RINs for their biodiesel prior to an EPA evaluation of the GHG performance of a palm oil-based pathway? Would this producer have to submit a formal petition to pursue this approach? Are there any standardized forms for doing so? Would EPA create a new D code so that they could generate RINs regardless of broader approval of palm oil?

      A: Prior to July 1, 2010, when the RFS2 regulations take effect, fuel producers can generate RINs under the RFS1 rules as long as the fuel meets the definition of renewable fuel under 80.1101. Beginning July 1, 2010, RFS2 regulations will apply. After that date, new fuel pathways not included in the existing regulations (Table 1 to 80.1426) will need to receive EPA’s lifecycle analysis and D-code designation prior to qualifying for RIN generation (unless the facility qualifies for grandfathering under 80.1403). As stated in the preamble to the final rule, EPA is actively analyzing the GHG performance of palm-oil based pathways, and intends to amend the RFS2 rules as appropriate to reflect its final conclusions. EPA anticipates that this analysis will be completed in 2010. Palm oil interests do not need to petition the Agency for this action. If EPA adds a new qualified pathway to Table 1 to 80.1426 reflecting its analysis of palm oil, fuel producers using palm oil will be able to start generating RINs with the next quarterly update of pathways in the EMTS. Prior to completion of this process, RINs with a D code of 6 can be generated for palm-oil based biofuels that meet the definition of renewable fuel (including the renewable biomass requirement) if the production facility qualifies for grandfathering under 80.1403.

    5. Do you have any updates on the status of EPA’s modeling of palm oil biodiesel?

      A: EPA is actively continuing its FRM evaluation of biodiesel produced from palm oil. We expect to complete that analysis within approximately 6 months, as stated in the preamble to the final rule. All currently available documents including meeting records and formal comments to the proposal regarding palm oil based biodiesel are in the current docket. However, as EPA continues its analysis, additional material may be provided by experts or analyses conducted by EPA which will then be added to the docket to form the complete record of the final action. Until the analyses are complete it would be inappropriate to speculate on the likely results of the analyses.

    6. The company I work for uses corn stover for its primary energy source and corn for the feedstock. I do not see a pathway in Table 1 to 80.1426 describing this pathway.

      A: Several pathways do exist in Table 1 to 80.1426 for corn-ethanol produced in a facility that used biomass (such as corn stover) for process heat. However, some of these pathways also have restrictions on the drying of distillers grains and solubles and may require the use of advanced technologies listed in Table 2 to 80.1426.

    7. If Table 1 to 80.1426 is complete, it appears that almost no ethanol plants in the US will qualify?

      A: Most existing corn-ethanol plants are grandfathered under 80.1403 and thus can generate RINs per 80.1426(f)(6), provided they comply with other EISA requirements. Newer plants may need to implement some advanced technologies as listed in Table 2 to 80.1426.

    8. In Table 1 to 80.1426, the only feedstock allowed to produce renewable heating oil is "non-cellulosic portions of separated food waste." If a company plans to produce renewable heating oil from used vegetable oil, can they qualify under that pathway? Also, would it be necessary to apply for a new equivalence value (EV), or would the renewable diesel EV of 1.7 automatically apply?

      A: There are two approved pathways for the generation of RINs for renewable heating oil: one that requires the use of cellulosic biomass, and another that requires the use of the non-cellulosic portions of separated food wastes. Used vegetable oil can count as non-cellulosic separated food waste if it meets the requirements of 80.1426(f)(5)(i)(B), as well as (f)(5)(ii)(A). There is currently no approved Equivalence Value explicitly for heating oil, but if a producer's product meets the definition of heating oil in 80.2(ccc) as well as the definition of either non-ester renewable diesel or biodiesel in 80.1401, it can be assigned an Equivalence Value of either 1.7 or 1.5, respectively. Otherwise, a producer of renewable heating oil would need to apply for an Equivalence Value under 80.1415(c).

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  4. Grandfathered fuel

    1. What is meant by "grandfathered" fuel?

      A: Under the RFS2 regulations, renewable fuel produced from facilities that commenced construction before December 19, 2007 and which completed construction within 36 months without an 18 month hiatus in construction and thereby exempt from the minimum 20% GHG reduction requirement that applies to general renewable fuel. Ethanol from facilities that commenced construction after December 19, 2007, but prior to December 31, 2009, qualify for the same exemption if they complete construction within 36 months without an 18 months hiatus in construction and are fired with natural gas, biomass, or any combination thereof. For convenience, we refer to the facilities that qualify for these exemptions, as well as the fuel produced by them as "grandfathered." It is important to note, however, that these facilities and fuels are only exempt from a single RFS2 requirement (the minimum 20% GHG reduction for general renewable fuel), and are otherwise fully subject to RFS2 requirements. For example, fuel produced by grandfathered facilities does not qualify as renewable fuel under RFS2 unless it is produced from renewable biomass. Also, fuel from grandfathered facilities cannot qualify as advanced biofuel, cellulosic biofuel, or biomass-based diesel unless it is produced through a pathway that EPA has determined will result in an appropriate level of GHG reduction (50% or 60%).

    2. Table 1 in 80.1426 does not include a coal fired ethanol plant. If a coal fired plant can be demonstrated as "grandfathered-in," can we assume the ethanol produced will have a D code of 6?

      A: Per 80.1403(c), all facilities (including coal-fired facilities) for which construction commenced prior to December 19, 2007 and which completed construction within 36 months without an 18 month hiatus in construction may qualify for grandfathered status regardless of the fuel used to provide process heat in the plant. If the fuel from such facilities satisfies the definition of "renewable fuel," including the requirement that the feedstock used to make the fuel is " renewable biomass" it is eligible for RIN generation, with a D code of 6, as described in 80.1426(f)(6)(ii). Ethanol facilities that commenced construction after December 19, 2007 but no later than December 31, 2009, are grandfathered only if they are also fired with natural gas, biogas, or combination thereof. (See 80.1403(d)). Thus coal fired facilities for which construction commences after December 19, 2007, cannot qualify as "grandfathered" facilities.

    3. How does EPA intend to measure the 36 months for a plant completion in 80.1403(c)(4) – from date of EISA enactment (as the RIA, and proposed rule indicate) or date of construction commencement (as preambles to the proposed and final rules and the final rule itself indicate).

      A: In attempting to clarify and simplify the regulations, we mistakenly removed language that would have identified an important distinction between the provisions for facilities that commenced construction prior to EISA enactment versus after enactment. We intend to issue a direct final rule to amend the regulations to provide that construction must be completed within 36 months of December 19, 2007 for facilities that commenced construction prior to that date or within three years of commencement of construction for those facilities that commenced construction after that date. Essentially the amended rule would provide that construction must be completed by December 19, 2010 or 3 years after commencement of construction, whichever is later.

    4. The preamble states that "fuel from the existing capacity of current facilities and the capacity of all new facilities that commenced construction prior to December 19, 2007 (and in some cases prior to December 31, 2009) are exempt, or grandfathered, from the 20% lifecycle requirement for the Renewable Fuel category." Does this mean that a biodiesel plant built prior to Dec 19, 2007 could use palm oil, or any other feedstock to generate RINs applicable to the Renewable Fuel Category, but not applicable to the Biomass Based Diesel Category?

      A: Biodiesel made at grandfathered facilities (as defined in 80.1403(c)) is only exempt from the 20% GHG reduction requirement. It is not exempt from the 50% GHG reduction requirement for biodiesel. Biodiesel producers who wish to generate biomass-based diesel RINS for biodiesel starting on July 1, 2010 must meet a 50% GHG reduction requirement regardless of when commencement of construction occurred. Thus, unless a grandfathered facility's fuel pathway is qualified for a different D code in Table 1 to 80.1426, or in response to a petition in 80.1416, the fuel from such facilities only qualifies for a D code of 6 per 80.1426(f)(6)(ii). Fuel from grandfathered facilities may generate fuels with a D code other than 6, however, if the facility's fuel pathway is listed in Table 1. For example, a plant that qualifies as grandfathered under 80.1403(c) and makes biodiesel from soy bean oil may generate RINs with a D code of 4 according to Table 1 to 80.1426. But if the plant switches feedstocks to palm oil, which is not listed in Table 1, the plant may still generate RINs with a D code of 6 as a grandfathered facility. The RINs for a particular batch are calculated using the general formula for a batch of fuel described by a single pathway in 80.1426(f)(2)(i).

    5. If a facility is grandfathered, is it also exempt from the requirement that feedstocks must be renewable biomass?

      A: Even if a facility is exempt from the 20% GHG reduction requirement, in order to generate RINs, the facility is still required to use feedstocks that meet the definition of renewable biomass. The definition of renewable fuel in 80.1401 specifies that renewable fuel be made from renewable biomass, which is also defined in that section.

    6. Are Canadian facilities included in the grandfathering provision? Does the grandfathering provision extend to facilities that commenced production up to December 31, 2009?

      A: The grandfathering provisions apply equally to facilities inside and outside the RFS program area. Facilities that commenced construction (as defined in §80.1403(a)(4)) prior to December 19, 2007, and which satisfy the timely construction requirements of §80.1403(c)(1) and (2) are included in the exemption specified in §80.1403(c). For facilities which commenced construction between December 19, 2007 and December 31, 2009, the provisions of §80.1403(d) apply, which, in addition to specifying timely construction requirements also restrict the exemption to 1) only ethanol produced, and 2) only that produced from facilities which are fired exclusively with natural gas, biomass, or a combination of these fuels.

    7. Do grandfathered facilities have an additional 6 months to submit their engineering reviews to EPA?

      A: Yes. In the preamble to the final RFS2 regulations at 75 Fed. Regs. 14709 (March 26, 2010), EPA stated that, in an effort to reduce demand on engineering resources in the interim between promulgation of the rule and July 1, 2010, the agency would allow grandfathered facilities an additional six months from the July 1, 2010 deadline to submit their engineering review (to be submitted no later than December 31, 2010). The regulations did not include this flexibility. EPA intends to propose changes in a direct final rule in the near future to amend the regulations to allow grandfathered facilities an additional six months from the July 1, 2010 deadline to submit their engineering review.

    8. How do you determine the "permitted capacity" as defined in the RFS2 regulations when there is no specific restriction on output volume in the preconstruction and operating permits, but the permit contains conditions that limit parameters such as fuel consumption, tank sizes, and feedstock throughput? Can these types of permit conditions be used to determine the facility's "maximum permissible volume"?

      A: Permitted capacity is defined in 80.1403(a)(2) as "105% of the maximum permissible volume output of renewable fuel that is allowed under operating conditions specified in the most restrictive of all applicable preconstruction, construction and operating permits issued by regulatory authorities. that govern the construction and/or operation of a renewable fuel facility, reported as: (i) Annual volume output on a calendar year basis." If the permit sets operating limits on fuel consumption and other parameters that the owner can show are directly related to and limit the annual volume of renewable fuel produced, then those conditions may be used in appropriate circumstances to determine maximum permissible volume output. In such instance, these limits would represent the "annual volume output on a calendar year basis." The renewable fuel producer should provide documentation to verify their permitted capacity or actual capacity as part of the registration requirements (80.1450(b)(1)) and recordkeeping requirements (80.1454(b)(6)). EPA suggests that parties proposing to use such measures contact EPA personnel to discuss the situation.

    9. EPA states in the preamble to the RFS2 rules that "volume limitations contained in air permits may be defined in terms of peak hourly production rates or maximum annual capacity," and the definition of "permitted capacity" describes how to convert maximum hourly output limitations in permits to maximum annual volume output. However, many permits contain volume limitations on different frequencies and averaging periods. If a facility's permit limits the volume output on a daily maximum, averaged over the period of a month, can the maximum annual volume be computed by multiplying the daily maximum by 365?

      A: A daily maximum limit averaged over a month may or may not recognize the daily variability of plant production. If it can be shown that the daily maximum limit specified in the permit is averaged over a month and takes into account downtime, then the maximum annual volume may be computed by multiplying the daily maximum by 365.

    10. How long will the grandfathering provision be effective? Once a grandfathered producer registers and completes their engineering review, will their baseline volume ever need to meet the 20% GHG reduction requirement?

      A: If a facility meets the requirements for exemption from the 20% GHG reduction requirement pursuant to 40 CFR 80.1403(c ) or (d), then the baseline volume of renewable fuel produced by that facility is exempt from the 20% GHG reduction requirement for the life of the plant.

    11. How does a foreign grandfathered renewable fuel production facility processing a mixture of feedstocks with different D codes or no D codes classify its production into D code categories so RINs can be generated when the product is imported into the U.S.?

      A: If the importer is generating the RINs, the importer must obtain all the required information for registration from the foreign producer of the renewable fuel pursuant to 80.1426(a)(2) and 80.1450. In the case of a foreign producer using multiple feedstocks with different D codes, the importer must obtain information about the feedstocks sufficient to calculate the feedestock energy values FE as described in 80.1426(f)(3)(vi).

    12. Can I include a permit update in the information I send to EPA for purposes of setting baseline volumes? What about if that permit is pending and will be completed by July 1, 2010?

      A: Baseline volumes are based on limits contained in air permits that are issued or revised no later than (1) December 19, 2007 for facilities described in 80.1403(c); or (2) December 31, 2009, for facilities described in 80.1403(d). Permits issued after these dates and which increase the limit of what the plant can produce may not be used to increase the baseline volume of a grandfathered facility. If permitted capacity cannot be determined baseline volume is determined through submission of documents that demonstrate the actual peak capacity of a specific renewable fuel production facility on a calendar year basis. For registration purposes, all information and copies of permits to establish baseline volume should be submitted by July 1, 2010 or 60 days prior to the generation of RINs, which ever date comes later. In addition, registration of facilities claiming an exemption pursuant to 80.1403(c) or (d) must occur no later than July 1, 2013.

    13. How will the volume of corn ethanol produced above the grandfathering threshold be treated?

      A: For grandfathered facilities, only the baseline volumes are exempt from the 20 percent GHG reduction requirement Thus, RINs may be generated for baseline volumes of fuel regardless of lifecycle greenhouse gas emissions performance. Volumes of fuel produced above the baseline volume must meet the 20 percent GHG reduction requirement to qualify for RIN generation under RFS2 .Table 1 to 80.1426 contains several approved pathways through which corn ethanol produced above the baseline volume can generate RINs.

    14. The definition of "actual peak capacity" in section 80.1403(a)(3) of the regulations published on March 26, 2010 states that for a facility which commenced construction prior to Dec 19, 2007 " the actual peak capacity is based on the last five calendar years prior to 2008, unless no such production exists, in which case actual peak capacity is determined pursuant to paragraph (a)(3)(ii) of this section." Paragraph (a)(3)(ii) states that actual peak capacity is based on "any calendar year after startup during the first three years of operation" but it applies only to plants constructed after December 19, 2007 and which are fired with natural gas, biomass or a combination thereof. How is actual peak capacity determined for facilities constructed prior to December 19, 2007 that are fired with coal?

      A: The definition contains a drafting error which EPA is proposing to correct in a technical amendment to this regulation. 80.1403(a)(3)(i) should read as follows: "(i) For facilities that commenced construction prior to December 19, 2007 the actual peak capacity is based on the last five calendar years prior to 2008, unless no such production exists, in which case actual peak capacity is based on any calendar year after startup during the first three years of operation." This would apply to facilities fired with coal or oil, as well as natural gas.

    15. An ethanol plant commenced construction in August 2006 and was 95% complete as of mid-2010. The facility has never operated, and the owner declared bankruptcy in January 2009. Another company is considering buying the facility and is proposing to fire the facility with natural gas. Under what circumstances can the facility qualify as a grandfathered facility?

      A: Under 80.1403(c) in the original RFS2 regulations published on March 26, 2010, , a renewable fuel facility which satisfies the requirements for having "commenced construction" prior to Dec 19, 2007 qualifies for grandfathered status if 1) it did not discontinue construction for a period of 18 months after commencement of construction; and (2) it completed construction within three years of commencement. However, EPA is proposing a technical amendment to 80.1403(c)(2) to provide that construction must be complete by December 19, 2010. Under these proposed amendments, a facility for which construction was suspended in January of 2009, could qualify for grandfathered status if construction is resumed within 18 months (by June of 2010) and construction is complete by December 19, 2010.

    16. If a facility which has met the requirements of 80.1403(c) or (d), is shut down for a period of time and then started up again will its baseline volume of fuel continue to be exempted from the 20% GHG reduction requirement? If so, would the exemption still apply if the shut down plant were acquired by a different company?

      A: Grandfathered status applies for the life of a plant. The mere shut-down and start-up of a plant does not alter this result. Facilities that have been shut down retain the grandfathered facility exemption upon start-up, regardless of the change in ownership of the facility or the length of time of the shut-down. The exemption is restricted, however, to the baseline volume of the plant, as defined in 80.1403(a)(1). (The "baseline volume" definition has been moved to 80.1401.in a technical amendment to the RFS2 regulations which has just been released as a direct final rule.)

    17. In the final rule preamble, it states that facilities that would qualify as grandfathered, but are not currently in operation, have until May 1, 2013 to submit and receive registration approval from the EPA. If such a facility has completed construction prior to May 1, 2013, but has not maintained a valid operational air permit, will it still be considered a grandfathered facility even though it will have to obtain a new air permit? If yes, how will baseline capacity be determined?

      A: If a facility satisfies the regulatory definition of "commenced construction" prior to December 19, 2007, then by definition it has acquired all "necessary preconstruction approvals or permits" as well as satisfying additional requirements regarding the initiation of a continuous program of actual on-site construction or entering into binding agreements regarding such construction. This term "all necessary preconstruction approvals or permits" is defined at 40 CFR 53.21(b)(10) to mean "those permits or approvals required under Federal air quality control laws and regulations and those air quality control laws and regulations which are part of the applicable State Implementation Plan." If the facility has satisfied all components of the definition of "commenced construction" prior to December 19, 2007, then the facility will qualify for the exemption in 80.1403(c) if it completed construction in a timely manner without an 18-month hiatus in construction. (See response to question 4.15). Expiration of an air permit (for whatever reasons) will not terminate the exemption status of a qualified facility. The baseline volume of the facility is determined by either the "permitted capacity" or, if permitted capacity cannot be determined, the "actual peak capacity" of the plant. In the event that baseline volume cannot be determined through applicable permits and the plant never operated, actual peak capacity can be determined based on any calendar year after startup during the first three years of operation.

    18. If a grandfathered facility produces both grandfathered fuel and non-grandfathered fuel, does six-month extension from the July 1, 2010 deadline to submit the engineering review applicable only for the grandfathered fuel? Do the requirements change if the grandfathered facility is domestic or foreign?

      A: The six-month extension from the July 1, 2010 deadline to submit the engineering review is applicable to the grandfathered facility and does not depend on the type of fuel the facility produces. Therefore, a grandfathered facility that produces both grandfathered fuel and non-grandfathered fuel may submit their engineering review by December 31, 2010 for all the fuel types produced at the facility. The requirements are the same whether a grandfathered facility is domestic or foreign.

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  5. Application of standards

    1. What are the "consequences" if the 6.5MM gallons of cellulosic are not met this year? Do you have a list of the projects you anticipate comprising the 6.5MM?

      A: Should the required volume of cellulosic biofuel not be produced in 2010, obligated parties can still comply through 1) the use of RFS1 RINs generated in 2009 or 2010 for cellulosic biomass ethanol, 2) the purchase of cellulosic waiver credits from EPA, and/or 3) carrying a deficit over into 2011. Preamble Section IV.B.3. contains the discussion of the various cellulosic biofuel companies and facilities that went into our 2010 cellulosic biofuel standard assessment.

    2. Is the Renewable Fuels Mandate in ethanol equivalent gallons? Can regular ethanol be blended at an increased volume to make up for higher ethanol equivalent fuels (i.e., biodiesel or advanced biofuels)?

      Since biodiesel has an ethanol equivalent value of 1.5, can producers satisfy the combined 2009/2010 biodiesel mandate by blending only 766.7 million gallons of biodiesel (which is equivalent to 1.15 billion ethanol-equivalent gallons)?

      A: The percentage standards applicable under RFS2 are intended to be met with ethanol-equivalent volumes of renewable fuel. As a result, a gallon of ethanol counts as one gallon of renewable fuel for purposes of compliance with the four percentage standards, while a gallon of other types of biofuels may count as more than a gallon for compliance purposes, depending on its energy content as compared to ethanol. Thus, for instance, 10 gallons of butanol would generate 13 RINs, and each of these 13 RINs count as one gallon of renewable fuel for purposes of compliance with the percentage standards. See discussion in preamble Section II.D.1. The use of renewable fuels with higher molecular weight (and thus higher energy content) than ethanol will reduce the physical volume needed to meet the standards since they will generate more than one RIN for each physical gallon produced.

      The standard for biomass-based diesel can only be met with renewable fuels that can be blended into diesel fuel. We believe that Congress intended the biomass-based diesel volume mandate to be treated as diesel volume. To implement this, we modified the formula for calculating the standard for biomass-based diesel to account for the higher Equivalence Value of the biofuels typically used to meet this standard. As a result, one physical gallon of biodiesel will generate 1.5 RINs which can be applied to the percentage standard for biomass-based diesel, but due to the change in the formula for calculating the standard, these 1.5 RINs will meet 1.0 physical gallon of the biomass-based diesel volume requirements. The same 1.5 RINs from biodiesel can also be used to meet the advanced biofuel and total renewable fuel standards. See preamble Section II.E.1.a. Effectively, the 1.15 billion gallons of biomass-based diesel used to derived the biomass-based diesel standard for 2010 must be met with 1.725 billion RINs with a D code of 4 or 7 (1.15 BG x Equivalence Value of 1.5).

      Standard ethanol cannot be blended at higher rates to substitute for biofuels qualifying as advanced or cellulosic biofuel.

    3. What is the purpose of a cellulosic biofuel waiver credit, priced at $1.56 in 2010 (40 CFR §80.1405(d))?

      A: Under EISA, EPA is required to make cellulosic biofuel waiver credits available for years where we waive some portion of the statutory volume for cellulosic biofuel. These credits can then be used by obligated parties to comply with the cellulosic biofuel volume obligation in lieu of RINs generated with the production of the cellulosic biofuel. Cellulosic biofuel waiver credits are for obligated parties who do not acquire sufficient RINs for their cellulosic biofuel RVO in a given compliance year. These credits cannot be traded. For 2010, obligated parties may purchase cellulosic biofuel waiver credits to use for compliance at $1.56 per credit (40 CFR 80.1405(d)). EPA will determine on an annual basis whether to waive all or a portion of the statutory requirements for the use of cellulosic biofuel, and will make cellulosic biofuel waiver credits available when it does so.

    4. Could you please expand upon the definition of the cellulosic biofuel waiver credit that may be for sale? I am not certain when, or if, a paper or pulp company could obtain a waiver credit or benefit from selling a waiver credit?

      A: Cellulosic biofuel waiver credits may only be purchased by obligated parties (e.g., gasoline and diesel fuel refiners and importers) from EPA. See section 80.1456(c).

    5. Is fuel sold in U.S. territories, such as Puerto Rico, required to comply with RFS2?

      A: United States territories, such as Puerto Rico, are not included in the RFS2 program unless they opt-in according to §80.1443. See also §§80.1407(f) and 80.1426(b).

    6. How many RFS1 cellulosic RINs are likely to be used for compliance with the 2010 cellulosic biofuel standard of 6.5 million gallons?

      A: The 2010 cellulosic biofuel standard can be met with cellulosic biofuel RINs generated under RFS2 regulations after July 1, 2010, cellulosic biomass ethanol RINs generated under RFS1 regulations between January 1, 2010 and July 1, 2010, and cellulosic biomass ethanol RINs generated under RFS1 regulations in 2009. As of the date of this response, we do not have information about the actual generation of cellulosic biomass ethanol RINs under RFS1 regulations for the first half of 2010. However, under the regulations at 80.1427(a)(5), the maximum number of 2009 cellulosic biomass ethanol RINs that can be used for compliance with the 2010 cellulosic biofuel standard of 6.5 mill gallons is 1.3 million (20% of 6.5). If the production volumes of cellulosic biomass ethanol in 2009 continue into the first half of 2010, the full cellulosic biofuel standard of 6.5 mill gallons may be met with RFS1 RINs.

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  6. Treatment of biomass-based diesel in 2009 and 2010

    Note regarding use of RINs generated in 2008 for compliance purposes in 2010

    In previous versions of this document, certain Q&As in this section were originally written to describe and clarify the use of 2008 biodiesel and renewable diesel RINs for compliance with the combined 2009/2010 volume obligation for biomass-based diesel. The manner in which 2008 biodiesel and renewable diesel RINs may be used to demonstrate compliance with this volume obligation is specified in detail in 80.1427(a)(7). Following consideration of a petition from the National Biodiesel Board (NBB)1 for reconsideration of 80.1427(a)(7) and/or modification of the Q&As describing it, EPA has reassessed its interpretation of 80.1427(a)(7)2. Our reassessment has led us to conclude that the rollover cap on 2008 biodiesel and renewable diesel RINs, specified in 80.1427(a)(7)(iii), uses terms that are defined in the previous paragraph of 80.1427(a)(7)(ii). The straight reading of the text of the regulation is that the definitions in paragraph 80.1427(a)(7)(ii) apply to the same terms used in paragraph 80.1427(a)(7)(iii). While the resulting rollover cap as it applies to the use of 2008 RINs in 2010 differs somewhat from certain descriptions in the final RFS2 rulemaking preamble, this approach is the appropriate way to interpret the regulations as written. The result of this interpretation is that the value of the term RVOBBD,2010 in 80.1427(a)(7)(iii) is based on the definition of that same term in 80.1427(a)(7)(ii), which is the adjusted value from 80.1427(a)(7)(i) rather than the unadjusted value, as indicated in the initial March 2010 version of the Q&A. We have modified Q&As 6.1, 6.2, and 6.3 below to reflect this result. We have also added Q&As 6.7 and 6.8 to describe the potential outcome of these changes on compliance with the standards in 2010 and 2011.

    Notes:
    1 Letter from Manning Feraci to Lisa Jackson, April 27, 2010.
    2 As EPA notes in the introduction to this Q&A document, while the answers provided represent the Agency's general plans for implementation of the regulations at the time they are written, "some of the responses may change as additional information becomes available, or as the Agency further considers certain issues." This is one instance where the Agency has decided that a change is warranted.

    1. How does the 20% rollover cap apply to 2008 and 2009 RINs when an obligated party complies with the 2010 standard for biomass-based diesel?

      A: Compliance with combined 2009/2010 volume obligation for biomass-based diesel (total 1.15 billion gallons)

        RFS1 RINs generated in 2008 or 2009 RFS1 RINs generated in 2010 RFS2 RINs generated in 2010
        D code of 2 and RR code of 15 or 17 D code of 2 and RR code of 15 or 17 D code of 4
      RINs were used for compliance for the 2008 compliance year 2008 RINs used for compliance in 2008 have no impact on 2010 compliance, and cannot be used to reduce the 2010 RVO for biomass-based diesel per §80.1427(a)(7)(i). n/a n/a
      RINs were used for compliance for the 2009 compliance year 100% of these RINs can be used to reduce the 2010 RVO for biomass-based diesel per 80.1427(a)(7)(i) prior to determining the number of RINs that an obligated party must acquire for compliance purposes under 80.1427(a)(7)(ii). n/a n/a
      RINs have not yet been used for compliance in either the 2008 or 2009 compliance year A maximum of 20% of the 2010 biomass-based RVO (after adjustment of the RVO per 80.1427(a)(7)(i)) can be met with excess pre-2010 RINs (i.e. those generated in 2008 or 2009), per 80.1427(a)(7)(iii).

      A maximum of 8.7% of the 2010 biomass-based RVO (after adjustment of the RVO per 80.1427(a)(7)(i)) can be met with 2008 RINs not previously used for compliance ("excess 2008 RINs"), per 80.1427(a)(7)(iii).

      If an obligated party uses no excess 2008 RINs to meet his 2010 RVO for biomass-based diesel, then a maximum of 20% of the biomass-based RVO (after adjustment of the RVO per 80.1427(a)(7)(i)) can be met with 2009 RINs.
      Remainder of the 2010 RVO for biomass- based diesel (after adjustment of the RVO per 80.1427(a)(7)(i)) must come from RINs generated in 2010.
    2. The regulations at 80.1427(a)(7)(iii) say that the sum of 2008 and 2009 biodiesel and renewable diesel RINs cannot exceed 20% of the 2010 RVO for biomass-based diesel (after adjustment of the RVO per 80.1427(a)(7)(i)). Does this mean that 80% of the adjusted 2010 biomass-based diesel RVO has to come from 2010 RINs?

      A: The rollover caps under 80.1427(a)(7)(iii) apply to the adjusted RVO for 2010. This means the rollover cap only places a limit on previous year RINs (2008 and 2009) that were NOT used for compliance in an earlier year ("excess" RINs). Any 2008 or 2009 biodiesel or renewable diesel RINs that were used to comply with the 2009 total renewable fuel standard are not subject to the 20% rollover cap. The RFS2 regulations include a special transition provision allowing such RINs to be subtracted off of the biomass-based diesel RVO prior to the determination of the number of RINs an obligated party needs for compliance. See 80.1427(a)(7)(i). After accounting for any 2008 or 2009 biodiesel or renewable diesel RINs that were used to comply with the 2009 total renewable fuel standard, as well as any 2008 or 2009 excess RINs that are applied to the 2010 biomass-based diesel standard under the rollover cap, the obligated party must meet the remaining portion of its adjusted 2010 RVO for biomass-based diesel with 2010 RINs or it becomes subject to the deficit carryover provisions and must meet that deficit (along with its entire 2011 RVO) in 2011. This remaining portion should be 80% or greater of the adjusted 2010 biomass-based diesel RVO, but it could be less than 80% of the unadjusted 2010 biomass-based diesel RVO, since the rollover caps only apply to the use of excess 2008 and 2009 RINs for 2010 compliance, not 2008 and 2009 RINs that were used for compliance in 2009.

    3. There are no definitions for the terms used in the equations in §80.1427(a)(7)(iii). Is the term RVOBBD,2010 supposed to represent the RVO before or after the adjustment allowed in §80.1427(a)(7)(i)?

      A: Based on the structure of 80.1427(a)(7), the terms in 80.1427(a)(7)(iii) have the meanings assigned to those same terms in the previous paragraph 80.1427(a)(7)(ii). Thus, the term RVOBBD,2010 in 80.1427(a)(7)(iii) is defined to represent the RVO after the adjustment per 80.1427(a)(7)(i).

    4. Is there any volume cap when using previously-retired 2008 or 2009 biodiesel or renewable diesel RINs to satisfy an obligated party's 2010 biomass-based diesel RVO? Can 2008 or 2009 biodiesel or renewable diesel RINs that were previously-retired in 2009 also be used to satisfy advanced biofuel or total renewable fuel RVOs in 2010?

      A: 2008 and 2009 biodiesel and renewable diesel RINs (that is, RFS1 RINs with a D code of 2 and RR code of 15, 16, or 17) used for compliance purposes in 2009 can also be used to reduce the 2010 RVO for biomass-based diesel per 80.1427(a)(7)(i), but not the advanced biofuel or total renewable fuel RVOs. The rollover caps in 80.1427(a)(7)(iii) apply when satisfying the RVO after it has been reduced by the number of biodiesel and renewable diesel RINs used for compliance in 2009, per 80.1427(a)(7)(i). This means that the rollover caps do not apply to biodiesel or renewable diesel RINs used for compliance in 2009 but rather only those excess biodiesel or renewable diesel RINs not used for compliance in 2008 or 2009.

    5. Under section 80.1405, the standard for biomass based diesel (BBD) is calculated via a fraction, the numerator of which is equal to the required volume of biomass-based diesel in compliance year i times 1.5. For 2010 only, would you agree that, using the example of the calculation for years 2011 and beyond, the numerator of the fraction would be (RFV BBD in yr i + RFV BBD in yr i-1) x 1.5?

      A: The percentage standard for biomass-based diesel in years 2011 and beyond will be based upon the applicable volumes specified in CAA 211(o)(2)(B)(i)(IV) for years 2011 and 2012, and on applicable volumes established by EPA pursuant to CAA 211(o)(2)(B)(ii) in 2013 and later years which must be at least 1 billion gallons per year. For 2010, the percentage standard for biomass-based diesel is specified in 80.1405(a)(2) as 1.10 percent. The formula in 80.1405(c) does not apply in 2010, and only applies for 2011 and later years.

    6. What impact will the increased volume requirements for biomass-based diesel have for 2010 considering that the biodiesel industry didn't produce the volumes specified in the statute in 2009 and, with idled production, likely won't meet the volume requirements in 2010? The regulations allow a certain amount of deficit carryover into 2011, but at what point does the EPA see a shift in the production/demand change and how does that relate to the 20% prior year application and/or deficit?

      A: Obligated parties are required to obtain the requisite amount of biomass-based diesel RINs to meet their RVOs, and these RINs can only be generated through the production of biodiesel and renewable diesel. However, according to information from the biodiesel industry, idled production capacity can be brought online relatively quickly to meet the combined 2009/2010 standard for biomass-based diesel. In addition, we believe that other provisions will facilitate compliance. For instance, obligated parties who use biodiesel and/or renewable diesel RINs for compliance in 2009 can also reduce their 2010 biomass based diesel RVO by this amount. Also, up to 20% of the 2010 RVO for biomass-based diesel (after adjustment of the RVO per 80.1427(a)(7)(i)) can be met with 2008 or 2009 excess (not previously used for compliance) biodiesel or renewable diesel RINs. Where compliance is still difficult, 80.1427(b) allows up to 57% of a party's RVO (as calculated prior to adjustment with biodiesel and renewable diesel RINs used for compliance in 2009) to be carried as a deficit into 2011, so long as the 2011 RVO including any deficit from 2010 is met in 2011.

    7. How will the application of the term definitions in paragraph 80.1427(a)(7)(ii) to the same terms used in paragraph 80.1427(a)(7)(iii) affect demand for biomass-based diesel and advanced biofuel in 2010?

      A: Obligated parties are required to obtain the requisite amount of biomass-based diesel RINs to meet their RVOs, and these RINs can only be generated through the production of biodiesel and renewable diesel. However, according to information from the biodiesel industry, idled production capacity can be brought online relatively quickly to meet the combined 2009/2010 standard for biomass-based diesel. In addition, we believe that other provisions will facilitate compliance. For instance, obligated parties who use biodiesel and/or renewable diesel RINs for compliance in 2009 can also reduce their 2010 biomass based diesel RVO by this amount. Also, up to 20% of the 2010 RVO for biomass-based diesel (after adjustment of the RVO per 80.1427(a)(7)(i)) can be met with 2008 or 2009 excess (not previously used for compliance) biodiesel or renewable diesel RINs. Where compliance is still difficult, 80.1427(b) allows up to 57% of a party's RVO (as calculated prior to adjustment with biodiesel and renewable diesel RINs used for compliance in 2009) to be carried as a deficit into 2011, so long as the 2011 RVO including any deficit from 2010 is met in 2011.

      Based on our current review of the 2009 RFS compliance report data submitted by obligated parties, we anticipate that this straight reading of the regulations would require obligated parties to obtain 2010 biomass-based diesel RINs representing approximately 345 million gallons (518 million RINs) after accounting for 2008 and 2009 RINs that EPA believes may be properly applied to the combined 2009/2010 biomass-based diesel requirement of 1.15 billion gallons. This demand can be met with any biodiesel or renewable diesel RINs generated under the RFS1 regulations prior to July 1, 2010, or with biodiesel or renewable diesel RINs representing fuel produced on or after July 1, 2010 that meets the requirements for biomass-based diesel in the RFS2 regulations (including being produced from renewable biomass and through an approved pathway in Table 1 to 80.1426). Based on discussions with representatives of the biodiesel industry, we understand that there is more than sufficient capacity to meet this estimated volume. Historically, the U.S. biodiesel industry produced 490 million gallons in 2009, about 1.1 billion gallons in 2008 and about 500 million gallons in 2007 and has the current capacity in both production facilities and feedstocks to produce more than 1.7 billion gallons a year. Nevertheless, if obligated parties become subject to the deficit carryover provisions (and the limitations therein) regarding the biomass-based diesel requirements, the deficit from 2010 and the new volume requirements from 2011 must be met in 2011, increasing the demand in 2011. Alternatively, if biomass-based diesel in excess of 345 million gal is produced in 2010 but not used for compliance purposes in 2010 for any of the applicable RVOs, up to a maximum of 160 million gallons can be carried over to 2011 for compliance with the 2011 biomass-based diesel requirements (20% of the 2011 biomass-based diesel requirement of 0.8 billion gal). Based on information from the U.S. Census Bureau on domestic production and availability of fats and oils, including soybean oil, the National Biodiesel Board estimated that biodiesel production for the first four months of 2010 has averaged about 34 million gallons per month. If this production rate were to continue through the remainder of 2010, total 2010 production volumes would exceed 400 million gallons.

      If 345 million gallons of 2010 biodiesel (or the equivalent of 518 million RINs) are used in satisfying the combined 2009/2010 biomass-based diesel mandate, these RINs would also be valid for meeting the 2010 advanced biofuel standard of 950 million gallons. However, an additional 432 million advanced biofuel RINs would still be required to meet the 2010 advanced biofuel standard. These additional RINs could come from any renewable fuel produced after July 1, 2010 that is made from a feedstock that meets the renewable biomass requirements and that has been assigned a D code other than 6 under Table 1 to 80.1426, or a renewable fuel RIN generated before July 1, 2010 that has been deemed equivalent to a RIN generated under RFS2 regulations per 80.1427(a)(4)(i) or (ii). Such biofuels could potentially include U.S. biodiesel production in excess of 345 million gallons, cellulosic biofuel RINs with a D code of 1, 3, or 7 in excess of the 6.5 million ethanol-equivalent gallons needed for 2010 compliance, or imported sugarcane ethanol RINs with a D code of 5. In addition, while up to 190 million RINs from 2009 could be used toward meeting the 2010 advanced biofuel requirement consistent with the applicable 20% rollover cap, only excess 2009 biodiesel or renewable diesel or cellulosic ethanol RINs (that is, RINs not used for compliance in 2009), could be used for this purpose.

    8. How do the requirements for biomass-based diesel in 2010 affect compliance in 2011? Is compliance in 2011 different than compliance in 2012 and beyond?

      A: The biomass-based diesel standard and associated compliance requirements for 2010 were unique, and generally do not affect compliance for calendar years 2011 and beyond. However, there is one provision worthy of note. While in general an obligated party can carry a deficit of any amount from one year into the next (contingent on the requirement that a deficit cannot be carried over two years in a row), any deficit for biomass-based diesel carried over from 2010 to 2011 can be no larger than 57% of an obligated party's 2010 RVO for biomass-based diesel. See 80.1427(b)(1)(iii). On a nationwide basis, since the 2010 obligation for biomass-based diesel was 1.15 billion gal, the maximum carryover from 2010 to 2011 is therefore 0.66 billion gal (57% of 1.15 billion gal). Any deficit carryover from 2010 must be met in 2011 in addition to the 0.80 billion gallons required for 2011. Parties that carry a deficit into 2011 must satisfy both that deficit and their 2011 RVO for compliance year 2011.

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  7. Renewable volume obligations

    1. Section 80.1407(f) of the final rule clearly seems to allow a party that exports product that it also produced or imported to exclude the exported volume from their RVO calculation. However, it is unclear whether this section addresses situations where an obligated party buys diesel or gasoline domestically and then exports it.

      A: Under § 80.1407(a), a party’s RVO is determined by the amount of gasoline or diesel fuel it produces or imports. The amount of gasoline or diesel fuel that is purchased from another domestic producer or importer is never included in the purchaser’s RVO, regardless of whether the purchaser sells the fuel domestically or exports it. On the other hand, a party that produces gasoline or diesel that is sold to another domestic entity must include that gasoline or diesel fuel in its RVO, whether or not the fuel is ultimately exported by another party. Section 80.1407(f) indicates that certain products must be excluded from a party's RVO calculation, including exported gasoline and diesel. This regulation is directed solely at those parties who both: (a) produced or imported the fuel, and (b) exported the fuel.

    2. Obligated parties can carry over 57% of their 2010 biomass-based diesel obligation – or 650 million gallons - into 2011. Do you know if it would be allowed for 2011 into 2012?

      A: The deficit carryover provisions can be found at §80.1427(b). Deficits cannot be carried over two years in a row. Thus, if an obligated party or exporter carried a deficit into 2011, it would not be allowed to carry a deficit into 2012. If an obligated party or exporter carried no deficit from 2010 to 2011, then it could carry a deficit from 2011 to 2012 that is as large as their 2011 RVO.

    3. I understand under CAA Section 211(o), compliance can be deferred for a year as long as the obligated party complies the next year. How does one petition for a one-year deferral? What criteria are considered?

      A: According to §80.1427(b), an obligated party may carry a deficit from one compliance year to the next under certain conditions. No petition for a deficit carryover is required. An obligated party will be presumed to be carrying over a deficit into the following year if they do not comply for the current year, and no enforcement action will be taken. However, deficit carryovers cannot occur two years in a row. Thus, if compliance is not achieved the following year for both the current and previous years, then the party would be subject to enforcement action.

    4. Is the volume of renewable fuels a fixed number of gallons? How does this affect an obligated party's requirements?

      A: The volume of renewable fuel used as the basis for calculating the percentage renewable fuel standards is fixed by CCA 211(o)(2)(B) for certain years (through 2012 for biomass-based diesel and 2022 for other renewable fuels), with volumes after those dates to be determined by EPA in accordance with considerations specified in the statute. However, for cellulosic biofuel EPA must annually project the anticipated volume of production for the coming year and, if the projection is less than the statutorily-prescribed volumes, provide for a corresponding downward adjustment of required volumes. EPA also has broad authority to waive any of the requirements under conditions specified in the Act. (See CAA 211(o)(7).

      In general we treat the mandated volumes as ethanol-equivalent. Thus, if only ethanol were used, the actual physical gallons of renewable fuel used would exactly match the mandated volumes. Renewable fuels with energy content than ethanol will have Equivalence Values higher than 1.0, and thus one gallon of nonethanol renewable fuel will count as more than one gallon in the context of compliance with the standards. As a result, the physical volume of renewable fuel used to meet the RFS2 standards may be lower than the volume on which the standards were based.

      The total actual volume of renewable fuel required may also vary from that used to set the standards if the projected volumes of gasoline and diesel used in the calculation of the standards differs from the actual volumes of gasoline and diesel produced in the U.S.

    5. Can 2009 Cellulosic Biomass ethanol RINs (with a D code of 1) be used to satisfy an obligated party’s Cellulosic Biofuel and/or Advanced Biofuel RVO in 2010? Is there a 20% rollover cap on this type of RIN being used to satisfy the Cellulosic and/or Advanced Biofuel RVO?

      A: 2009 cellulosic biomass ethanol RINs with a D code of 1 that are not used for compliance purposes in 2009 can be used to meet the cellulosic biofuel, advanced biofuel, and total renewable fuel RVOs in 2010. The 20% rollover cap will apply to 2009 RINs in this case per §80.1427(a)(5). 2010 cellulosic biomass ethanol RINs with a D code of 1 generated under RFS1 regulations between January 1, 2010 and June 30, 2010 can also be used to meet the cellulosic biofuel, advanced biofuel, and total renewable fuel RVOs in 2010.

    6. Do exports of renewable fuel between January 1, 2010 and July 1, 2010 apply towards an exporter's Renewable Volume Obligations under RFS2? If so, what if an exporter has a deficit from 2009?

      A: Pursuant to 80.1430, exporters of renewable fuel must calculate their Renewable Volume Obligations for an entire calendar year. This includes the calculation for the 2010 compliance year. Therefore, exporters do not have RFS1 and RFS2 RVOs in 2010, but instead RFS2 RVOs in 2010 only. Pursuant to 80.1430, any deficit carried from 2009 is included in the Renewable Fuel RVO calculation.

    7. Per 80.1427(a), RINs nest. Can the same RIN be used more than once (i.e., a RIN with a D code of 3 (cellulosic) being used to meet the cellulosic RVO, the advanced biofuel RVO and the total renewable fuel RVO)?

      A: Except for the specific and limited case where RFS1 biodiesel RINs may be used to meet both the 2009 standard for total renewable fuel and the combined 2009/2010 standard for biomass-based diesel, there is no other time when it is acceptable to use the same RIN in more than one compliance period. However, the standards for RFS2 are nested such that when cellulosic biofuel RINs and biomass based diesel RINs are used for compliance, those same RINs can be used to meet the standards for advanced biofuel and total renewable fuel in the same year. See 80.1427(a)(3)(i).

    8. Our refinery is producing No. 2 high-sulfur diesel for use (primarily) as a feedstock. Beginning later this year, the refinery will no longer be permitted to sell it for use in non road engines (its secondary use) due to heightened sulfur requirements for NR diesel. Can our refinery exclude this volume of No. 2 high sulfur diesel from its RVO calculations?

      A: If No. 2 high-sulfur diesel meets the definition of MVNRLM diesel fuel in 80.2(qqq), it is an obligated fuel subject to the standards under RFS2 unless it is specifically exempted pursuant to 80.1407(f). If a batch of diesel fuel does not meet the specifications for MVNRLM diesel fuel, it is not an obligated fuel. A fuel which is designated as a blendstock but nevertheless meets all the specifications for MVNRLM diesel fuel must be treated as MVNRLM diesel fuel for the purposes of determining an RVO. Likewise, a fuel which is designated for export but nevertheless meets all the specifications for MVNRLM diesel fuel must be treated as MVNRLM diesel fuel for the purposes of determining an RVO unless the fuel is actually exported out of the 48 contiguous states or Hawaii. See RFS2 regulations at 80.1407(e) and (f).

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  8. Registration

    1. What is the due date for the initial engineering review and the subsequent updated engineering reviews? Is there a deadline for EPA to approve the engineering review after it has been accepted?

      A: The initial engineering review must be submitted and accepted by EPA as part of a renewable fuel producer’s initial registration by July 1, 2010, or 60 days prior to the generation of RINs, whichever date comes later. Every 3 calendar years from the initial date of registration, an updated engineering review must be submitted to and accepted by EPA. In addition, if a renewable fuel producer makes changes to their facility that will qualify their renewable fuel for a renewable fuel category or D code that is not reflected in their registration information submitted to EPA, then pursuant to 80.1450(d)(1), an updated engineering review must be submitted to EPA at least 60 days prior to producing a new type of renewable fuel. Please see question 4.7 above for a discussion of the engineering review deadlines for grandfathered facilities.

      There is no deadline for EPA to approve an engineering review after it has been accepted. EPA will provide approval when staff deems the engineering review to be complete and to have met all the requirements stipulated in Section 80.1450.

    2. 80.1450 refers to a Fuel Supply Plan. Is this referring to the fuel used for process energy? If not, what is it referring to? If yes, by "source" do you mean the name of the supplier? The regulations ask for the locations from which the process energy fuel types were produced or extracted. Is it sufficient to give the fuel supplier's name and address? If not, what other data is needed?

      A: The Fuel Supply Plan refers to fuel used at a renewable fuel production facility to generate process energy. "Source" means the name of the supplier of that fuel. Since the regulations ask for the locations from which the process energy fuel types were produced or extracted the name and address of the supplier would not satisfy this requirement; we are asking for the location where the biogas is produced. We intend to clarify this through our upcoming technical amendment to the regulations.

    3. What types of engineers are qualified to conduct the third party engineering review of a domestic renewable fuel production facility, as required in 80.1450(b)(2)?

      A: The final regulations in 80.1450(b)(2)(i)(A) state that domestic renewable fuel production facilities must have an engineering review conducted by a "Professional Chemical Engineer." For foreign facilities, 80.1450(b)(2)(i)(B) provides that the review should be conducted by "a licensed professional engineer or foreign equivalent who works in the chemical engineering field ."

      EPA interprets these provisions similarly. For both domestic and foreign facilities the third party engineering review should be conducted by a professional engineer (or foreign equivalent) who works in the chemical engineering field. EPA views renewable fuel production to fall generally within the chemical engineering field, so that professional engineers with experience engineering such facilities would qualify to conduct the third party engineering reviews. As required in 80.1450(b)(2)(ii)(E), the engineer must provide to EPA documentation of his or her qualifications to conduct the engineering review, including but not limited to proof of a license as a professional engineer and relevant work experience.

    4. Is it required that the professional engineer conducting the engineering review must be licensed in the state in which the renewable fuel facility is located?

      A: The licensed professional engineer should comply with the state laws where the renewable fuel facility is located to determine whether or not their license allows them to conduct business in that state.

    5. Pursuant to 80.1450(b) the licensed professional conducting the engineering review is required to be free of any interest in the renewable fuel producer’s business. What are the guidelines to determine what qualifies and does not qualify as a conflict of interest?

      A: Engineers conducting the engineering review required in 80.1450(b) must be free of "any interest" in the fuel producer's business. Examples of the types of interest that would disqualify an engineer from conducting reviews would be ownership of stock in the company, being an employee or director of the company, having an arrangement or negotiating for future employment with the company, or having a substantial professional interest in the outcome of the review. The regulations also require that the fuel producer be free of any interest in the engineer's business.

    6. Is the licensed professional engineer conducting the engineering review required to perform the site visit in person, or can they delegate the site visit to another person who maybe assisting them in the engineering review?

      A: Pursuant to §80.1450(b)(2), all verifications must be performed by the licensed professional engineer conducting the engineering review. This requirement includes conducting the site visits. The licensed professional engineer conducting the engineering review must perform the site visits to the renewable fuel production facility in person and cannot delegate this task to another person.

    7. Does EPA consider it a conflict of interest for a third-party company to assist a group of renewable fuel producers and importers of renewable fuel to help meet the requirements of the re-registration and engineering review pursuant to section 80.1450?

      A: EPA does not restrict a renewable fuel producer or an importer of renewable fuel from seeking a third-party company to assist them in meeting the re-registration and engineering review requirements pursuant to section 80.1450. The renewable fuel producer and importer of renewable fuel are solely responsible and liable for complying with all requirements in RFS2, whether or not a third-party company assists them in the compliance process.

    8. If my fuel is already registered with the Fuels and Fuel Additives program under 40 CFR Part 79, do I still need to register with the RFS2 program under 40 CFR Part 80?

      A: Yes. Even if your fuel or fuel additive is already registered under 40 CFR Part 79, there are additional registration requirements for parties regulated under the RFS2 program, as specified in 40 CFR 80.1450.

    9. Once I register my fuel for the RFS2 program under §80.1450, do I still need to register my fuel under 40 CFR Part 79?

      A: Yes. Renewable fuels intended for use or used in motor vehicles are required to be registered under 40 CFR part 79 prior to any introduction into commerce. Manufacturers of renewable fuels and fuel additives not registered under part 79 will be liable for penalties under 40 CFR parts 79 in the event their unregistered product is introduced into commerce for use in a motor vehicle.

    10. Under "Business Activities" on the Company Details CDX web page, what does "Small Blender" mean?

      A: The small blender business activity is in relation to §80.1440: "What are the provisions for blenders who handle and blend less than 125,000 gallons of renewable fuel per year?" The small blender business activity entry is for those parties (such as ethanol splash blenders, construction companies or farms) that blend small volumes of renewable fuel and do not want to handle RINs and the associated responsibilities, and therefore may want to use the flexibility provided by §80.1440 to allow their suppliers to separate RINs on their behalf.

    11. Does the engineering review have to address GHG emissions from the process or for the fuel?

      A: The RFS2 regulations do not require that any lifecycle GHG emission performance assessment be conducted as part of the engineering review. Rather, the purpose of the engineering review is to confirm that the information the renewable fuel producer reported to EPA during the registration process is accurate and true to the type of renewable fuel produced and processes utilized at the renewable fuel facility. The independent third party evaluates and verifies the producer’s registration information through a site visit and a review of all relevant documents.

    12. Section 80.1451(g) states that "Registration shall be on forms, and following policies, established by the Administrator". Are these registration forms and registration policies now available?

      A: The registration forms are available through our CDX system (cdx.epa.gov). For instructions please visit, http://www.epa.gov/otaq/regs/fuels/fuelsregistration.htm. Please note, EPA will only accept complete registration and re-registration packages. Be sure all elements required for registration are submitted with your registration, including any engineering reviews, fuel supply plans and other required elements.

    13. Can an engineering review on a facility with multiple fuel pathways be combined into one report?

      A: Yes. The engineering review for a renewable fuel facility that contains multiple fuel pathways may be combined into one report. However, all information that is required to be reviewed and verified by the third party engineer conducting the engineering review should be included and identified separately for each fuel pathway in the engineering report.

    14. Are engineering drawings and process and instrumentation diagrams (P&IDs) required to be submitted as part of the engineering report?

      A: Engineering drawings or P&IDs are not required to be submitted in the engineering report, but EPA suggests the third party engineer provide a simple diagram to help supplement the description of the process train for each renewable fuel pathway at the production facility. The diagram can be presented in simple block and arrows format, which may include for each step along the process train, feedstock input, process unit, process fuel heat input, co-products produced, etc.

    15. How will engineering reports be treated in terms of public access and CBI? Will there be web access for submitted reports?

      A: EPA will process any public requests for engineering reports on a case-by-case basis and there will be no general web access to the engineering reports. Engineering reports, or portions thereof, for which the submitter asserts a confidential business information (CBI) claim will be protected from public disclosure as specified in 40 CFR Part 2, subpart B. Engineering reports, or portions thereof, for which no CBI claim is made may be released to the public in response to a Freedom of Information Act request pursuant to EPA regulations at 40 CFR Part 2, subpart A

    16. Given that all of the forms for MSW, and EPA responses to petitions for new Equivalence Values and D codes for new pathways, etc. are not available, is it realistic to think that all producers will be registered by July 1, 2010?

      A: The regulatory requirements for registration are clear and complete in their current form. Thus, producers can register under RFS2 now. There is no need for a producer to delay registration until other implementation actions are completed such as distribution of forms for MSW, or EPA responses to petitions for new Equivalence Values or D codes, or review of petitions for new pathways.

    17. Should producers submit copies of applicable permits or other documentation for baseline volume and supplemental plans such as the fuel supply plan or separated yard waste, food waste and municipal solid waste (MSW) plans with their registration or with their engineering review? Are requirements the same for grandfathered facilities?

      A: All copies of applicable permits or other documentation for baseline volume and supplemental plans such as the fuel supply plan or separated yard waste, separated food waste and separated municipal solid waste (MSW) plans should b submitted with the renewable fuel producer's registration, due by July 1, 2010. This requirement is also applicable to grandfathered facilities. Grandfathered facilities are provided a six month extension only for the engineering review, therefore these requirements are the same for grandfathered facilities.

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  9. Generation of RINs

    1. Does ethanol derived from cellulosic feedstock or sugar have the same Equivalence Value as ethanol derived form corn starch, i.e. 1.0?

      A: Yes. Equivalence Values are based on energy content in the fuel, adjusted for renewable content in comparison to denatured ethanol. See 80.1415(c). Ethanol from starch, sugar, and cellulose is all chemically identical, and is all 100% renewable (none of the carbon in the fuel comes from a fossil fuel source). Thus, all such ethanol has the same Equivalence Value.

    2. If I produce biodiesel using waste vegetable oil, can I generate more RINs per gallon than if I use virgin soy oil? Would the use of solar panels as a heat source for our process help with our RIN number per gallon?

      A: The number of RINs that can be generated for each gallon of renewable fuel is determined by the Equivalence Values. See regulations at 80.1415(b) and 8.1426(f)(2)(i), for example. Equivalence Values are based on energy content in the renewable fuel, adjusted for renewable content in comparison to denatured ethanol. Equivalence Values are not a function of the type of feedstock used to produce the renewable fuel, nor any elements of the fuel production process.

    3. If a producer is able to change its D code, can it make retroactive changes in the D code of the RINs it has issued previously during the year or earlier if the production during the previous period would meet the newly classified D code criteria?

      A: Once a RIN is generated and transferred to another party, it cannot be changed. Thus, retroactive changes to D codes in RINs are not allowed.

    4. What is the operational tolerance for denaturant in ethanol to meet the definition of Renewable Fuel? The RFS2 definition calls for a maximum of 2% denaturant. What if the lab results come back higher or lower than 2%? For example, what if the lab results come back with 2.44% or 2.66% denaturant?

      A: The definition of renewable fuel in 80.1401 specifies that the maximum amount of denaturant in ethanol that can be treated as renewable fuel is 2 volume percent. If lab results indicate that the concentration of denaturant is higher than 2%, then any denaturant in excess of 2% cannot be treated as renewable fuel, and RINs cannot be generated to represent it. However, conventional rules of rounding apply since the regulations specify the limit as 2%, not 2.0% or 2.00%. Thus, for example, if the denaturant concentration was tested and found to be 2.44%, this would be deemed equivalent to 2% and RINs could be generated for the entire volume. However, if the denaturant concentration was tested and found to be 2.66%, this would be deemed equivalent to 3% and RINs could only be generated to represent 99% of the volume of denatured ethanol.

    5. For plants that produce cellulosic ethanol by means of 80.1101 (a) (2), how should their RIN production be classified from January 1, 2010-June 30, 2010? From July 1, 2010 – December 31, 2010?

      A: RFS1 regulations (40 CFR Part 80 Subpart K) apply through June 30, 2010. Ethanol meeting the definition of "cellulosic biomass ethanol" under RFS1 would be assigned a D code of 1 and an RR code of 25. RFS1 regulations cease to apply on July 1, 2010, and the RFS2 regulations (40 CFR Part 80 Subpart M) then apply. There is no such thing as "cellulosic biomass ethanol" under RFS2 regulations. Instead, ethanol meeting the definition of "cellulosic biofuel" under RFS2 would be assigned a D code of 3 and an RR code of 10.

    6. Can a gallon of ethanol generate more than 1.0 RIN in RFS2? (In RFS1 this was possible.)

      A: The number of RINs that can be generated for each gallon of renewable fuel are determined by the Equivalence Values. See 80.1415 and 80.1426(f)(2)-(6). Equivalence Values are based on energy content in the renewable fuel in comparison to ethanol, adjusted for renewable content. Since the volumetric energy content of ethanol is unique, its Equivalence Value will never be higher than 1.0.

    7. If a producer generates RINs for cellulosic methanol, and then combusts that methanol in the producer's boiler, can the producer separate and retain the RINs?

      A: Renewable fuel for which RINs can be generated is that which is transportation fuel, heating oil, or jet fuel. Methanol does not qualify as transportation fuel unless it is designated for use in a vehicle or engine specifically designed to use it, and it does not qualify as heating oil or jet fuel because it does not meet the definition for either of these fuel types. Moreover, there is currently no approved pathway in Table 1 to 80.1426 for methanol. Therefore, RINs cannot currently be generated for renewable methanol.

    8. Can ethanol produced from sugarcane molasses through a fermentation process in a mixed sugar/ethanol mill generate D-Code 5 RINs under the existing pathway in Table 1 to §80.1426 for ethanol produced from sugarcane through the fermentation process?

      A: Yes, ethanol produced from sugarcane molasses through the fermentation process can generate D-Code 5 RINs under the RFS program. There are generally three types of sugarcane ethanol production mills: (1) Dedicated mills using all the sugarcane juice to produce ethanol; (2) Mixed sugar/molasses mills using the first juices for commercial sugar production and the remaining molasses for ethanol production; and (3) Purchased molasses mills, using purchased molasses from sugar production mills for ethanol production. There is a pathway in Table 1 to §80.1426 for the generation of D-Code 5 RINs for ethanol produced from sugarcane through the fermentation process. EPA interprets the term “sugarcane” in this pathway description in Table 1 to include non-finished intermediary products of sugarcane processing, such as molasses derived from sugarcane. Therefore, ethanol produced by fermentation from sugarcane in any of the three types of ethanol production mills, including mixed sugar/ethanol mills and purchased molasses mills, qualifies for the generation of D-code 5 RINs under this existing approved pathway. Although the lifecycle greenhouse gas modeling EPA conducted in support of the existing ethanol/sugarcane/fermentation pathway in Table 1 was specifically based on the lifecycle GHG performance of a dedicated mill, we have also determined that the ethanol produced from sugarcane molasses in both mixed sugar/molasses mills and purchased molasses mills has lifecycle GHG emission reductions of greater than 50% compared to the petroleum baseline. Therefore, EPA’s interpretation of the existing ethanol/sugarcane/fermentation pathway in Table 1 as including ethanol produced by fermentation from sugarcane molasses in a mixed sugar/molasses mill and in a purchased molasses mill is consistent with the GHG reduction requirements for advanced biofuel specified in the Clean Air Act.

      Ethanol produced in any of the three types of sugarcane ethanol production mills must be made from renewable biomass, and the producer must satisfy all renewable biomass recordkeeping requirements in order for RINs to be generated for a batch of ethanol. Foreign renewable fuel producers or foreign ethanol producers selling their product to an importer for distribution in the United States must supply any RIN generating importer with the documentation required by 40 CFR § 80.1454(c). For purchased molasses mills, renewable biomass requirements and documentation applies to the specific batches of sugar cane that were processed to make the molasses used in producing the specific batches of fuel for which RINs are generated. If this documentation cannot be provided, the feedstock cannot meet the definition of renewable biomass and therefore RINs cannot be generated for ethanol made from it.

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  10. RIN transactions

    1. Are parties required to submit information to EMTS within five (5) business days of the separation or retirement of RINs?

      A: Yes. EPA issued a direct final rule on May 10, 2010 (75 Fed. Reg. 26026) that includes amendments to 80.1452 clarifying that a party must submit information to EMTS within five days of separating or retiring RINs as described in 80.1429.

    2. In EMTS, do parties have to specify on a "buy" transaction whether or not the seller is sending assigned or separated RINs?

      A: Yes. Both parties, the buyer and seller, must identify the assignment of the RINs involved in the transfer pursuant to 80.1452(c)(4).

    3. When a small blender delegates RIN-related responsibilities upstream pursuant to 80.1440, are the RIN transactions reported under the delegatee's facility and company numbers?

      A: The delegatee will provide the small blender's company ID in EMTS while separating RINs on the small blender's behalf based on the renewable fuel volume that was blended.

    4. Are the PTD requirements in 80.1453(a)(11)(i) for listing assigned RINs interpreted in the same manner for both generic and unique RIN trades conducted through EMTS ?

      A: Parties conducting RIN trades through EMTS must still comply with the physical PTD requirements in 80.1453. In EMTS, RINs may be traded generically or uniquely. RINs traded generically will be identified by EMTS on the default first in-first out (FIFO) basis. EPA issued a direct final rule on May 10, 2010 (75 Fed. Reg. 26026) that includes amendments to 80.1453 that specify different PTD requirements for generic and unique RIN trades conducted through EMTS. If a party trades on the default FIFO basis, then the requirement in 80.1453(a)(11)(i)(A) to list assigned RINs on the PTD is satisfied if the PTD includes the information found in 80.1453(a)(1)-(a)(10).

      Example:
      Transferor Name: Company Name Example 1
      Transferor Address: 0000 Example St. Washington, DC 20005
      Transferor Company ID: CCCC
      Transfer Date: 7/1/2010,
      Transferee Name: Company Name Example 2
      Transferee Address: 0000 Example St. Washington, DC 20005
      Transferee Company ID: CCCC
      RIN Assignment: Assigned
      RIN Quantity: 10,000 RINs:
      RIN Type: D=6
      RIN Year: 2010
      Volume of Renewable Fuel: 10,000 gallons of ethanol
      PricePerGallon: $X.XX,
      Reason: Standard Trade

      Alternatively, RINs may be traded in EMTS uniquely. If a RIN is sold uniquely, additional specific identifying information must also be included on the PTD as part of the RIN listing requirement in 80.1453(a)(11)(i)(B). The additional unique identifying data that must be included are the RIN generator company ID, facility ID, and batch number. This unique identifying information must be passed to the buying party via the PTD to ensure that a trade match occurs.

      Example:
      Transferor Name: Company Name Example 1
      Transferor Address: 0000 Example St. Washington, DC 20005
      Transferor Company ID: CCCC
      Transfer Date: 7/1/2010,
      Transferee Name: Company Name Example 2
      Transferee Address: 0000 Example St. Washington, DC 20005
      Transferee Company ID: CCCC
      RIN Assignment: Assigned
      RIN Quantity: 10,000 RINs:
      RIN Type: D=6
      RIN Year: 2010
      Volume of Renewable Fuel: 10,000 gallons of ethanol
      PricePerGallon: $X.XX,
      Reason: Standard Trade
      RIN Generator Company ID: CCCC
      RIN Generator Facility ID: FFFFF
      RIN Batch Number: BBBBB

    5. How do we trade and report RFS1 38-digit RINs and RFS2 EMTS RINs starting July 1, 2010?

      A:RFS1 RINs will continue to be traded as they have been under RFS1, but RFS2 RIN transactions will occur only in EMTS. Quarterly reports, recordkeeping requirements, and PTD requirements are still required regardless of whether the RIN was generated in RFS1 or RFS2. There will be no import mechanism for RFS1 RINs into EMTS. EPA will develop and release new reporting forms prior to July 1, 2010 that must be used to report transactions involving RFS1 RINs that can be used to comply with RFS2. The revised forms must be used starting on July 1, 2010.

      Starting July 1, 2010, RFS1 RINs must be reported on revised RFS0100, RFS0200, and RFS0300 reports. The revised forms will be renumbered as RFS 101, RFS 201 and RFS 301. The RFS0400 may no longer be used for the generation of RINs.

      RFS2 RIN transactions (e.g. generated, bought, sold) will take place in EMTS. EMTS will provide additional information for the RFS0101 and RFS0301 reports. Additional RFS2 reporting forms pursuant to requirements in 80.1451 will be posted on EPA's website prior to July 1, 2010.

      The table below explains which existing RFS1 reporting forms and instructions will be revised, no longer used, and/or replaced by EMTS.
      RFS1 Reporting Form Is this reporting form applicable for RFS1 RINs under RFS2? Is this reporting form applicable for RFS2 RINs? Will this reporting form be revised for RFS2? Will a report be generated by EMTS to satisfy this requirement for RFS2 RINs?
      RFS0100: RFS Activity Reporting Form (40 CFR 80.1152(c)(2)) Yes Yes Yes. This form will be revised to include RFS2 RINs, reinstated RINs, etc. No. However, EMTS will provide additional RFS2 RIN information to aid in completion of this report.
      RFS0200: RFS RIN Transaction Reporting Form (40 CFR 80.1152(c)(1)) Yes No Yes. This form will be revised to include applicable RFS1 RIN reinstatements. Yes. EMTS will generate a RFS2 RIN transaction report. This must be submitted in conjunction with a revised RFS0200 for any RFS1 RIN transactions.
      RFS0300: RFS Annual Compliance Reporting Form (40 CFR 80.1152(a)) Yes Yes Yes. This form will be revised to reference the four separate RVOs and other RFS2 requirements. No. However, EMTS will provide additional RFS2 RIN information to aid in completion of this report.
      RFS0400: RFS RIN Generation Reporting Form (40 CFR 80.1152(b)(1)) No No No. This form may only be used for RFS1 RINs generated prior to July 1, 2010. Yes. Under RFS2, all RINs generated July 1, 2010 and beyond must submit information to EMTS. EMTS will provide the quarterly report for download all RIN generators.

    6. What should we do when a vendor sends a PTD but we do not receive it? Should we complete the transaction in EMTS if we already have transactional data in our system, but have not yet received a PTD from the counterparty?

      A: All parties are required to submit transactional information to EMTS within 5 business days of the transfer date as identified on the Product Transfer Document pursuant to 80.1452(c). The transfer date is the date that the seller transfers title of the renewable fuel to the buyer. The PTD identifying the RINs must be transferred to the buyer on the same day as the transfer of title of the fuel. Regardless of when the buyer receives the PTD, the buying party would be in violation if they do not submit the transactional information to EMTS within 5 business days of the ownership transfer date. A seller that fails to deliver a PTD to the buyer in a timely manner would be in violation of 80.1453(a). Furthermore, the selling party may be in violations of 80.1460(e) if their failure to deliver the PTD in a timely manner caused the buyer's violation. EPA suggests that sellers send buyers a facsimile or electronic version of the PTD, in addition to a paper copy, so as to avoid these problems.

    7. If a renewable fuel producer or importer discovers that they have generated invalid RINs, what actions should they take to minimize the harm caused by the violation?

      A: 80.1431(a)(1) identifies a number of actions that result in the generation of invalid RINs. For instance, a RIN is invalid if it was based upon incorrect volumes of renewable fuel, does not represent fuel that meets the definition of renewable fuel under 80.1401, or was assigned an incorrect "D" code under 80.1426. Any party that generates or sells invalid RINs will be in violation of 80.1460(b)(2). In order to mitigate the harm caused by these violations, the party that improperly generated the RINs should immediately identify the generation of invalid RINs to EPA. EPA will then attempt to notify all parties that hold these RINs that they have been identified as invalid. The current owner(s) of the invalid RINs cannot use the RINs for compliance purposes, but must instead retire those RINs pursuant to 80.1431(b)(1). The party retiring the RIN should use the appropriate Reason Code (i.e. RVC: Volume Error Correction per 80.1431, RIR: Invalid RIN per 80.1431). The party that generated the invalid RINs may then replace them with valid separated RINs or make other arrangements that are acceptable to the party that retired the invalid RINs. All parties must maintain documentation relating to the invalid RINs, including but not limited to: information regarding the generation of invalid RINs, all correspondence with EPA, all EMTS transactions (Buy, Sell and Retire), and all Product Transfer Documents.

    8. Do the prohibitions in 40 C.F.R. 80.1160(b)(2) and 80.1460(b)(2) against transferring invalid RINs prevent a party that has purchased a potentially invalid RIN from rescinding the RIN transfer, and sending RINs that a purchaser believes to be invalid back to the seller?

      A: The EPA will not adjudicate or participate in private disputes between parties to RIN transactions. If, however, a RIN transfer is rescinded as a result of concerns relating to the validity of a RIN either by agreement of the parties or as a result of a court order, the EPA will not consider the act of returning the RIN to the seller to be a violation, or the cause of a violation, of the prohibitions against transferring invalid RINs under the following conditions 1) the RIN purchaser has reason to believe that the RINs are invalid, 2) the parties note in the comment fields in EMTS that the action is a rescission, 3) the parties select remedial action/incorrect trade as the “sale reason” in EMTS.

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  11. Reinstating RINs

    1. In addition to 2009 RINs, may a party reinstate 2008 and 2010 RINs that were retired for non-motor vehicle use under RFS1?

      A: Pursuant to §80.1429(g), any 2009 RINs that were retired for non-motor vehicle, heating oil or jet fuel use under RFS1 may be reinstated under RFS2. The regulations do not allow 2008 RINs to be reinstated. Since RFS1 RINs generated in 2010 could also have been retired, we intend to propose an amendment to §80.1429(g) to explicitly allow 2010 RFS1 RINs to also be reinstated. In any case, no party may reinstate RINs prior to the effective date of the RFS2 regulations on July 1, 2010.

    2. How does a retiring party reinstate RFS1 RINs that were retired because renewable fuel was ultimately used for non-motor vehicle, heating oil or jet fuel purposes? What steps are required to be taken and do any codes require changing?

      A: Pursuant to §80.1429(g), parties may reinstate 2009 RINs that were retired under RFS1 because the renewable fuel was ultimately used in a non-motor vehicle application, heating oil or jet fuel. As stated in question 11.1, since RFS1 RINs generated in 2010 could also have been retired, we intend to propose an amendment to §80.1429(g) to explicitly allow 2010 RFS1 RINs to also be reinstated. Parties may only reinstate RINs that were retired in 2009 or 2010 and which were reported on a previously-submitted RFS-0200 form with codes: RNR (renewable fuel designated for non-road use) and RBH (renewable fuel used in boiler or heater). EPA will allow parties to reinstate those RINs on a modified RFS0200 report that will be released prior to the start of RFS2. No portion of the 38-digits in a reinstated RIN will change. Parties will be able to reinstate the RINs using an EPA issued modified RFS0200 no sooner than July 1, 2010, but may transfer them starting July 1, 2010. If a RIN was retired and the fuel was not used in a non-motor vehicle application, heating oil, or jet fuel then that RIN may not be reinstated. Please note, a change like this will result in new names for the RFS0100 and RFS0200. EPA will provide this information on the RFS reporting web site www.epa.gov/otaq/regs/fuels/rfsforms.htm.

    3. May I generate RINs that I produced and sold for non-road use in the past so that I can reinstate those RINs under RFS2?

      A: Section 80.1426(c)(2) provides that RINs are assigned to a volume of renewable fuel when ownership of the RIN is transferred along with ownership of the volume of renewable fuel. A comparable provision appear in the RFS1 regulations, at §80.1126(e)(2). Thus, a party may not generate RINS for renewable fuel produced and transferred to another party in the past in order to retire RINs and then reinstate them under RFS2. You may only reinstate RINs that were generated in 2009 and 2010 that were retired for non-motor vehicle, heating oil or jet fuel use.

    4. May I generate RINs for renewable fuel that I produced and sold for non-motor vehicle use in the past so that I can reinstate those RINs under RFS2?

      A: No. RINs that were previously generated in 2009 and 2010 may be reinstated if they were retired for non-motor vehicle use. However, RINs may not be generated for renewable fuel produced in the past in order to retire RINs and then reinstate them under RFS2.

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  12. Reporting

    1. Where can I find more information and documentation on the EPA Moderated Transaction System (EMTS)?

      A: For more information on the EPA Moderated Transaction System (EMTS), please visit the EMTS web page at http://www.epa.gov/otaq/fuels/renewablefuels/epamts.htm.

    2. What if pricing changes after the information has been reported to EMTS?

      A: Parties will not be required to resubmit price information if it changes. The price information must be accurate rounded to the nearest cent (US Dollar) at the time the transactional information is sent to EMTS.

    3. Will we enter in RFS1 RINs into EMTS, or will they continue to be traded outside of EMTS?

      A: RFS1 RINs trades will continue to be conducted in the same manner as they have been under RFS1 until they are used for compliance or they expire. They will not be entered into, or traded in, EMTS.

    4. How do I conduct the 2010 annual report with RFS1 RINs and RFS2 RINs?

      A: EPA will update the RFS0300 Annual Compliance Report form to facilitate reporting the use of RINs from both RFS1 and RFS2 for compliance.

    5. Does the ratio of feedstock quantity used to volume of renewable fuel produced have any significance in the RFS program? Would it impact the qualification of a renewable fuel's pathway or the equivalence value of the fuel?

      A: The amount of feedstock used to produce a biofuel is one of many factors that EPA takes into consideration in its assessment of the lifecycle GHG performance of a particular fuel pathway. However, once EPA establishes the lifecycle performance of the fuel pathway the amount of feedstock needed at a particular facility is not used for lifecycle performance verification. It is however, one piece of information that EPA can look at for assessing the reasonableness of reported fuel volumes produced and RINs generated. Equivalence values in the program are used to determine the number of RINs that are generated for each gallon of fuel produced. Equivalence values are based on the energy content of the fuel produced and are not impacted by the amount of feedstock needed to produce the fuel.

    6. Under RFS2, when engaging in transactions on EMTS and reporting under 80.1451(c), the RIN price and/or per gallon fuel price with RINs included has to be reported. For un-assigned (separated) RINs this is easy - it is the RIN price. However, what should companies be reporting if the RINs are assigned, and companies do not differentiate between the RIN price and fuel price? Should they estimate a RIN price to report, or should they report the per gallon renewable fuel price with RINs included? Section 80.1453(a)(5) says it should be the "per gallon RIN price or the per gallon renewable fuel price if the RIN price is included."

      A: For assigned RINs, we have provided the option, for the trading parties, to either report the actual RIN price, or the renewable volume price, of which the RIN price is included. However, if the RIN is included in the renewable volume price, parties may not report the RIN price as being $0.00.

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  14. Recordkeeping

    1. What is required in order to establish a contractual path for renewable biomass electricity for transportation use? It will be impossible, of course, to deliver the identical electrons created from the facility to the transportation end user, so is it sufficient if the producer creates a contract that ensures that power is delivered into the transmission system where the end-user is located?

      A: We recognize that it is impossible to deliver the identical electrons that were created from renewable biomass to the end user through a commercial grid. The RFS2 regulations therefore require that renewable electricity producers maintain records documenting the sale, delivery into the transmissions system, and the ultimate use of the electricity from the transmission system as transportation fuel. The records that producers of renewable electricity which is distributed through common/commercial transmission lines are required to keep are described in 80.1454(k). This section is on page 14891 of the March 26, 2010 Federal Register notice.

    2. For a natural gas used for process heat, or for renewable biogas used for transportation fuel, is it necessary to track individual gas molecules?

      A: Ethanol producers using natural gas for process heat are not required to submit information that tracks the natural gas molecules, and are only required to identify the supplier that provides the natural gas to the renewable fuel producer. This information will help EPA determine whether an ethanol production facility qualifies as a "deemed compliant" grandfathered facility pursuant to the requirements stipulated in 40 CFR Section 80.1403(d) and may also document use by a facility of a specific pathway in Table 1 to 80.1426.

      In the case of renewable biomass that is sold as transportation fuel, the RFS2 regulations specify recordkeeping requirements for RIN-generating biogas producers to document the sale, delivery into a common carrier pipeline, and ultimate use of gas withdrawn from the pipeline for transportation purposes. Tracking of individual molecules is not requires. The recordkeeping requirements are at 80.1454(k).

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  16. Attest engagements

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  17. Foreign producers and importers

    1. What are the requirements for a foreign producer who wishes to generate RINs for the renewable fuel they produce?

      A: Foreign producers who plan to generate RINs must register and conduct a third-party engineering review pursuant to section 80.1450. Additionally, such foreign producers must meet the requirements in section 80.1466 prior to generating any RINs for their fuel. The requirements in section 80.1466 include requirements such as posting a bond, committing to allow EPA inspections of the foreign production facility, and segregating the renewable fuel for which RINs are generated from non-renewable fuel and other renewable fuel that is not being imported into the U.S.

    2. Does an ethanol producer who sells undenatured ethanol to a U.S. importer who denatures it at the port need to register with EPA under RFS2?

      A: The May 10, 2010 direct final amendments to the RFS2 regulations specify that foreign producers of ethanol for use in transportation fuel, heating oil or jet fuel for import to the US who do not add denaturant to their product, must register under RFS2. See 80.1450(b) and 80.1401(definition of "foreign ethanol producer." The regulations also specify that importers may not generate RINs for renewable fuel made with ethanol produced by such a foreign producer, unless the foreign producer is registered with EPA. See 80.1426(c)(4).

    3. What are the reporting requirements for importers who import undenatured ethanol, denature it, and then generate RINs for it?

      A: Pursuant to 80.1451(b), importers who intend to generate RINs for imported renewable fuel must report to EPA concerning the source of that fuel. The reports must contain sufficient information for the importer to affirm that the feedstocks originally used in producing the renewable fuel or undenatured ethanol meet the definition of renewable biomass. Furthermore, the importer must also report to EPA information concerning the process used by the foreign producer to produce the batch of renewable fuel or ethanol. The feedstock and process information is necessary to ensure that the proper D code is generated by the importer for each batch of imported fuel. Much of the information that is required to be reported to EPA in 80.1451(b) by the RIN-generating importer is information from the original foreign producer of the renewable fuel or undenatured ethanol.

      For example, in a situation in which a foreign producer is making undenatured ethanol from sugarcane and exporting it to a U.S. importer who will denature it and generate RINs for that fuel, the importer would need to report to EPA information from the foreign producer, including information on feedstocks (sugarcane), processes (fermentation), and co-products (ethyl alcohol, bagasse, etc.).

    4. If an importer does not know the origins of the fuel they import, can they still generate RINs?

      A: No. An importer may only generate RINs for imported renewable fuel if the foreign producer of the fuel is registered with EPA pursuant to section 80.1450. Additionally, the importer must have documentation from the foreign producer concerning the origins of the fuel in order to generate RINs and comply with the recordkeeping and reporting requirements in sections 80.1451 and 80.1454. The required information includes, but is not limited to, documentation of the feedstocks and processes used to create the fuel, as well as any co-products generated with the fuel.

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  19. Other questions

    1. How do I find a listing of all obligated parties pertaining to the new RFS2 Program?

      A: Review the Fuels Programs Registrants list located at https://cdxnodengn.epa.gov/otaq-reg/list.do (Excel). (4.7MB, Updated Daily) Any party registered as an importer or refiner for either the gasoline or diesel programs may be an obligated party in any given compliance year.

    2. Can RFS1 RINs generated from the import of ethanol (sugarcane ethanol from Brazil) be used to meet an Advanced Biofuel obligation?

      A: No. RINs that can be used to meet an advanced biofuel obligation are those that have a D code of 3, 4, 5, or 7 [(see regulations at 80.1427(a)(2)]. All of these D codes are available to RIN generators only under the RFS2 regulations which go into effect on July 1, 2010. The D code is determined by the pathway provided in Table 1 to regulations section 80.1426. We did not create a regulatory provision for use of the F and C codes in the RIN for this purpose since this would require facility-specific lifecycle analyses.

      The use of prior-year RINs for current year compliance is limited by the rollover cap as described in regulation section 80.1427(a)(5). Moreover, as described in 80.1427(a)(4), there is no mechanism for representing RFS1 RINs as advanced biofuel under RFS2.

    3. Several locations in the preamble refer incorrectly to the time period in 2010 when the RFS1 regulations will be in effect. The correct phrase "first six months of 2010" should replace the incorrect phrase "first two months of 2010" and "first three months of 2010."

      A: There were several places in the preamble with the wrong time period references. The RFS2 regulations become effective on July 1, 2010, so the RFS1 regulations will be in effect for the first six months of 2010. Since the text at issue is preamble text and the regulations are correct in this regard, no changes to the regulations are required.

    4. How would sugarcane ethanol RINs generated in 2010 under RFS1 be handled under RFS2?

      A: §80.1427(a)(4) identifies the manner in which RFS1 RINs can be used for compliance with RFS2 cellulosic biofuel, biomass-based diesel, or general renewable fuel standards. Sugarcane ethanol RINs generated in 2010 under RFS1 would generally qualify as general renewable fuel with a D code of 6 under RFS2. See §80.1427(a)(4)(iii). Note that there is no provision for allowing RFS1 RINs to be treated as advanced biofuel under RFS2 regulations.

    5. Where can I find more information on biofuel subsidies?

      A: EPA does not issue biofuel subsidies. Please contact the IRS for more information on biofuel subsidies.

    6. Is commingling of different types of ethanol permitted? If so, what systems must be employed?

      A: With one exception, the RFS program places no restrictions on the mixing of ethanol produced in different facilities, with different feedstocks, or through different processes. Also, RINs assigned to ethanol are fungible, in that a specific assigned RIN is not required to be transfered with the same gallon of ethanol until separation of the RIN. RINs with a K code of 1 (assigned RINs) and volumes can be matched at the owner's discretion, so long as the requirements in 80.1428(a) are met. The one exception is for ethanol made at a foreign facility for which the foreign producer generated RINs and intends to export it to the U.S. In this case, the ethanol must be segregated from other volumes of ethanol. See 80.1466(d)(1)(vi).

    7. The answer to question 16.2 implies that the advanced biofuel standard under RFS2 cannot be met with any RFS1 RINs. What about using cellulosic biomass ethanol RINs generated under RFS1 to meet the advanced biofuel standard under RFS2?

      A: Section 80.1427(a)(4) states that, for purposes of demonstrating compliance for calendar years 2010 or 2011.a RIN generated pursuant to 80.1126 with a D code of 1 is deemed equivalent to a RIN generated pursuant to 80.1426 having a D code of 3. Thus, cellulosic biomass ethanol RINs (D = 1) generated before July 1, 2010 can be treated as cellulosic biofuel RINs (D = 3) for 2010 compliance. Moreover, as provided under 80.1427(a)(2), cellulosic biofuel RINs with a D code of 3 can be used to meet the cellulosic biofuel RVO, the advanced biofuel RVO, and/or the total renewable fuel RVO. Thus, cellulosic biomass ethanol RINs generated under RFS1 with a D code of 1 can indeed be used to meet the advanced biofuel standard under RFS2.

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