2010-31910. Regulation of Fuels and Fuel Additives: Modifications to Renewable Fuel Standard Program

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Final r ule.

SUMMARY:

EPA is finalizing amendments to certain of the Renewable Fuel Standard program regulations that were published on March 26, 2010, and that took effect on July 1, 2010 (“the RFS2 regulations”). Following publication of the RFS2 regulations, promulgated in response to the requirements of the Energy Independence and Security Act of 2007, EPA discovered some technical errors and areas within the final RFS2 regulations that could benefit from clarification or modification. In a direct final rule and parallel notice of proposed rulemaking published on May 10, 2010, EPA included language to amend the regulations to make the appropriate corrections, clarifications, and modifications. However, EPA received adverse comment on a few provisions in the direct final rule and, on June 30, 2010, withdrew those provisions prior to their effective date of July 1, 2010. In today's action, EPA is addressing the comments received on the portions of the direct final rule that were withdrawn and is taking final action regarding the withdrawn provisions based on consideration of the comments received.

DATES:

This final rule is effective on January 1, 2011.

ADDRESSES:

EPA has established a docket for this action under Docket ID No. EPA-HQ-OAR-2005-0161. All documents in the docket are listed on the http:://www.regulations.gov Web site. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are generally available either electronically through http://www.regulations.gov or in hard copy at the Air and Radiation Docket, ID No. EPA-HQ-OAR-2005-0161, EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is [phone], and the telephone number for the Air and Radiation Docket is [phone].

FOR FURTHER INFORMATION CONTACT:

Megan Brachtl, Compliance and Innovative Strategies Division, Office of Transportation and Air Quality (6405J), Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., 20460; telephone number: [phone]; fax number: [phone]; e-mail address: [e-mail].

SUPPLEMENTARY INFORMATION:

I. General Information

A. Does this action apply to me?

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

Category	NAICS codesa	SIC codesb	Examples of potentially regulated parties
Industry	324110	2911	Petroleum refiners, importers.
Industry	325193	2869	Ethyl alcohol manufacturers.
Industry	325199	2869	Other basic organic chemical manufacturers.
Industry	424690	5169	Chemical and allied products merchant wholesalers.
Industry	424710	5171	Petroleum bulk stations and terminals.
Industry	424720	5172	Petroleum and petroleum products merchant wholesalers.
Industry	454319	5989	Other fuel dealers.
a North American Industry Classification System (NAICS).
b Standard Industrial Classification (SIC) system code.

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

II. Renewable Fuel Standard (RFS2) Program Amendments

EPA issued final regulations implementing changes to the Renewable Fuel Standard program required by EISA on March 26, 2010, at 75 FR 14670 (“the RFS2 regulations”). Following publication of the RFS2 regulations, EPA discovered some technical errors and areas that could benefit from clarification or modification and, in parallel proposed and direct final rules published on May 10, 2010 (75 FR 26049, 75 FR 26026), included amendments to the regulations to correct these deficiencies. EPA received adverse comment on a few of the amendments and therefore, on June 30, 2010, withdrew the portions of the direct final rule that were the subject of adverse comment (75 FR 37733). The withdrawn provisions consist of the following:

—Certain of the amendments to § 80.1401, specifically those which moved the definitions of “actual peak capacity,” “baseline volume,” and “permitted capacity” from § 80.1403(a), revised the definition of “actual peak capacity” to clarify how it is calculated, and revised the definition of “permitted capacity” to clarify the dates by which permits used to establish a facility's permitted capacity must have been issued or revised;

—§ 80.1425, which clarified that RINs generated after July 1, 2010, may only be generated and transferred using the EPA Moderated Transaction System (EMTS) and will not be identified by a 38-digit code, and that the value of EEEEEEEE in a batch-RIN will be determined by the number of gallon-RINs generated for the batch;

—§ 80.1426(d)(1), § 80.1426(f)(3)(iv), and § 80.1426(f)(3)(v), which clarified that a unique batch code in the RIN, or its equivalent in EMTS, is used to identify a batch of renewable fuel from a given renewable fuel producer or importer;

—Table 2 to § 80.1426, which clarified the extent to which renewable fuel producers must use advanced technologies in order for their fuel to qualify for certain pathways identified in Table 1 to § 80.1426;

—§ 80.1426(f)(12), which clarified the requirements for gas used for process heat at a renewable fuel facility to be considered biogas for purposes of Table 1 to § 80.1426;

—§ 80.1452(b), which clarified that RINs must be generated in EMTS within five business days of being assigned to a batch of renewable fuel and clarified the information required to be submitted via EMTS for each batch of renewable fuel produced or imported; and,

—§ 80.1452(c), which clarified that transactions involving RINs generated on or after July 1, 2010, must be conducted via EMTS within five business days of a reportable event, and clarified the meaning of the term “reportable event” and the information required to be submitted via EMTS for each transaction involving RINs generated on or after July 1, 2010.

EPA published a parallel proposed rule (75 FR 26049) on the same day as the direct final rule (75 FR 26026). The proposed rule invited comment on the provisions of the direct final rule and indicated that a second comment period would not be offered on the proposal in the event that portions of the direct final rule were withdrawn in response to adverse comment. In this action, we are responding to the comments received on the portions of the direct final rule that were subsequently withdrawn, and we are taking final action regarding the withdrawn provisions based on consideration of these comments. We are also finalizing a minor amendment to § 80.1451(b)(1)(ii)(M) which was described in the preamble to the direct final rule and was included in the accompanying regulations, but the amendatory language prefacing the regulation inadvertently omitted reference to it. As a result, the Office of the Federal Register did not codify the amended regulation even though it was included in the direct final rule. The modification simply removes the words “of renewable fuel” to make the regulatory language consistent with other entries in the subparagraph. We received no adverse comment on this proposed amendment, and we consider it a non-substantive technical correction.

A. Permitted Capacity for Renewable Fuel Production Facilities

In the final RFS2 regulations, we specified in § 80.1403(a)(1) that the “baseline volume” of fuel that is exempt from the 20 percent greenhouse gas (GHG) reduction requirement at grandfathered facilities described in §§ 80.1403(c) and (d) would be determined by their “permitted capacity” or, if that could not be determined, by their “actual peak capacity.” In the registration provisions at § 80.1450(b)(1)(v)(B), we identified the permits that are relevant in establishing “permitted capacity.” Specifically, for facilities that commenced construction on or before December 19, 2007, the final RFS2 regulations stated that “permitted capacity” is based on permits issued or revised no later than December 19, 2007. For ethanol facilities that commenced construction after December 19, 2007, and on or before December 31, 2009, and that are fired with natural gas, biomass, or a combination thereof, the RFS2 regulations stated that “permitted capacity” is based on permits issued or revised no later than December 31, 2009.

In the final RFS2 regulations, we did not include in the definition of “permitted capacity” references identical to those placed in the registration section to the latest issuance dates of permits that could be used to establish “permitted capacity.” Therefore, in the direct final rule published at 75 FR 26026 (May 10, 2010), EPA modified the definition of “permitted capacity” to specify the same dates for relevant permits as were provided in the registration provisions in the final RFS2 regulations. We believed that such a revision would improve the clarity of the regulations, while not changing the substance of the requirements.

However, we received adverse comments during and after the comment period expressing concern over the modified definition of “permitted capacity,” which commenters stated posed “new constraints” on the qualification of eligible fuel volumes that could be exempt at grandfathered facilities. One commenter described an ethanol facility fired by natural gas, and therefore potentially eligible for an exemption from the 20 percent GHG reduction requirement pursuant to § 80.1403(d), for which permits were issued and construction completed prior to December 31, 2009, and for which an application for a permit revision seeking an increase in permitted capacity was submitted to the permitting authority in 2008. The commenter claimed that the revised permit reflected the facility's original plant design, however the permitting authority did not issue a revised permit for the facility until March 2010. According to the revised definition of “permitted capacity” in the regulations as amended by the direct final rule and according to the original registration requirements of the final RFS2 regulations, permits issued or revised after December 31, 2009, could not be used to establish “permitted capacity,” and therefore the additional capacity in the revised permit could not be included in the facility's baseline volume. The commenter explained that many ethanol producers originally applied for permits for their facilities based on conservative initial production volumes supported by their plant designers' emission guarantees, and that after an initial period of operation, performance testing, and fine tuning of operations, they have found that they could produce greater volumes. They explained that many developers of ethanol facilities, including their own, sought to obtain construction permits without going through EPA's New Source Review (NSR) program, and were able to do so by obtaining construction permits that specified less than 100 tons per year of emissions even though their facilities were capable of emitting more and producing a correspondingly greater volume of renewable fuel. In May 2007, when EPA changed to 250 tons per year the emissions threshold that would trigger NSR for ethanol production facilities, these plants then found it in their interest to seek increases in their permitted capacity beyond that specified in their earlier-issued permits, since they could do so without triggering NSR. The commenter argued that ethanol facilities should be allowed to use the capacity in such later-issued permits, including their own March 2010 revised permit, to establish their “permitted capacity” under RFS2.

We also received additional comments after the close of the comment period from a collective group of ethanol facilities in Illinois referencing the initial commenter's comments that the cut-off dates in the revised definition of “permitted capacity” created restrictions for their facilities that would prohibit them from having the “inherent capacity” of their facilities qualify for the grandfathering exemption under RFS2. In addition, the commenters referenced what they felt was an inequitable allowance for facilities located in states that did not place production limits in their air permits, who therefore were allowed to use “actual peak capacity” (which is based on actual production records ^[1] ) to establish their baseline volume exempt from the 20 percent GHG reduction requirement under RFS2. The commenters further cited potential cost effects if their full “inherent capacity” was not allowed to be included in the exempt baseline volume, such as the additional costs associated with either plant modifications (presumably needed to qualify their non-exempt fuel as meeting the 20 percent GHG reduction requirement) or exporting the non-exempt volume of fuel for consumption outside of the United States.

The commenters proposed revised language for the definition of “permitted capacity” that would allow an extended time frame for facilities to seek permit modifications to reflect their “inherent capacity.” They proposed that EPA modify the final RFS2 regulations to allow facilities to use as their baseline volume the capacity limits in permits issued by regulatory authorities which were applied for within three years after start-up of a new or expanded facility (but not less than one year after the effective date of the final rule) and issued within not more than two years thereafter. The commenters also stated that many facilities had no notice of EPA's time limitation on those permits in either the proposed or final RFS2 rule (74 FR 24904, published May 26, 2009, and 75 FR 14670, published March 26, 2010) and therefore had inadequate notice to make appropriate plans to apply for and obtain new permits within the RFS2 deadlines. They further expressed concern that the permit cut-off date that restricts grandfathered production capacity precedes the date of the proposed rule. They also cited a statement made in the proposed RFS2 rule that EPA's guiding principal is to “allow production increases within a plant's inherent capacity” (74 FR 24904, 24926, May 26, 2009). One commenter also referred to EPA's RFS2 Summary and Analysis of Comments, p. 3-139 (Pub. No. EPA-420-R-10-003, February 2010), in which, they state, EPA assumed that permitted capacity would likely reflect maximum inherent capacity. The commenter said that such an assumption would be valid for some situations, but not valid for others, especially with the limitations EPA intended to place on the date of permits that could be used to establish “permitted capacity.”

The Energy Independence and Security Act of 2007 (EISA or “the Act”) provides that the 20 percent GHG reduction requirement applies to “new facilities” that commence construction after the date of enactment. It also provides that “for calendar years 2008 and 2009, any ethanol plant that is fired with natural gas, biomass, or any combination thereof is deemed to be in compliance with [the] 20 percent reduction requirement * * *” In the proposed RFS2 rule we noted that the term “new facility” is not defined in EISA and, therefore, that EPA would need to interpret the term in the context of the RFS2 regulations. We also noted ambiguity in the statutory section related to ethanol facilities that commenced construction in 2008 and 2009 and that are fired with natural gas or biomass, in that the Act was not clear as to whether these facilities should be “deemed compliant” with the 20 percent GHG reduction requirement for only the two years specified, or indefinitely. For both types of facilities, we believe the approach we are finalizing in this rule provides an appropriate method of implementing statutory requirements that is consistent with the text and objectives of the statute, while also leading to a workable program.

First, with respect to “deemed compliant” ethanol facilities fired with natural gas or biomass for which construction commenced after enactment of EISA but on or before December 31, 2009, we believe, as discussed in the proposed RFS2 rule, that Congress could have intended that these facilities are only “deemed compliant” for those two years or for a longer or indefinite time period (assuming they continued to be fired with natural gas or biomass). The ambiguity can be seen through a comparison of the first sentence of EISA Section 210(a) and the second sentence. The first sentence provides that “for calendar year 2008, transportation fuel sold or introduced into commerce in the United States” that is produced by facilities that commenced construction after the date of enactment of EISA must meet the 20 percent GHG reduction requirement. This sentence is very specific, applying directly to “transportation fuel” that is “sold or introduced into commerce” in 2008. The second sentence in this section does not specifically refer to fuel, but instead refers to “any ethanol plant that is fired with natural gas, biomass, or any combination thereof” and provides that such facilities are “deemed compliant” with the 20 percent GHG reduction requirements of the Act. The sentence is introduced by the words “[f]or 2008 and 2009.” Since fuel from facilities that commenced construction prior to the date of enactment is already exempt from the 20 percent GHG reduction requirement by virtue of CAA Section 211(o)(2)(A)(i), the “deemed compliant” provision in the second sentence of EISA 210(a) clearly applies to ethanol facilities that commenced construction after that date.

We believe the scope of the exemption is ambiguous, however, because Congress did not specifically refer to fuel sold in specified years in the second sentence, as they did in the first sentence, but instead referred to “ethanol plants.” Because of this construct, it is unclear exactly what fuel should be covered by the exemption. EPA identified two general approaches to interpreting this provision in its proposed rule: Either interpreting it to provide a limited two year exemption, or interpreting it to provide an exemption for fuel produced by qualifying facilities that would be of equal duration to the exemption provided in CAA Section 211(o)(2)(i) for fuel from facilities that commenced construction prior to EISA enactment. We reasoned that it would be a harsh result for investors in these new facilities, and generally inconsistent with the energy independence goals of EISA, to interpret the Act such that these facilities would only be guaranteed two years of participation in the RFS2 program. Therefore in our final RFS2 regulations we provided an indefinite exemption from the 20 percent GHG reduction requirement for their baseline volumes (determined through either “permitted capacity” or, if “permitted capacity” cannot be determined, “actual peak capacity”) provided that they continue to be fired by natural gas, biomass, or a combination thereof.

Contrary to the commenters' assertions, nothing in EISA suggests that these “deemed compliant” facilities should be allowed to continually expand their production beyond levels achieved in 2008 and 2009 simply because they could do so without additional physical construction. Rather, the approach EPA has adopted of seeking to limit the exempt volume at these grandfathered facilities to that which was lawfully allowed in applicable permits issued no later than December 31, 2009, is fully consistent with the statutory references to 2008 and 2009.

We believe it is consistent with the statutory text to limit the grandfathered production from “deemed compliant” facilities to the maximum volume allowed under applicable permits in the 2008 to 2009 timeframe. We also believe that this approach is supported by the same policy considerations, discussed below, that have led us to a similar approach for facilities that commenced construction prior to EISA enactment. We have only deviated from this concept with respect to those “deemed compliant” facilities for which capacity cannot be determined by reference to applicable permits. Those facilities, some of which may not have been operational in the 2008 to 2009 timeframe, by necessity are allowed to establish their baseline volume by reference to actual production levels (“actual peak capacity”) within a specified time period after they commence operations. For both “deemed compliant” facilities and facilities that commenced construction prior to EISA enactment, we believe that allowing facilities to establish their baseline volume by actual production for any calendar year within the first three years of operation is appropriate because it allows a reasonable amount of time to correct possible production launch problems. This is an exception to the general rule, and is allowed only if permit limits are not available to establish baseline volume.

While there may be instances, as suggested by commenters, in which facilities that use “actual peak capacity” to establish their baseline volume could come closer to obtaining an exemption for what the owner may consider their “inherent capacity” than those establishing their baseline volume through permit limits, EPA notes that this need not always be the case. For example, some plants, whose baseline volume is established through “actual peak capacity” because they do not have a capacity stated on a permit, may not, due to certain start-up problems or market conditions, actually produce up to their projected or potential capacity during the first three years of operation. Nonetheless, they are required under the final RFS2 regulations to use the maximum annual production during these first three years of operation to establish their baseline volume.^[2] On the other hand, some plants that applied for permits reflecting a certain “permitted capacity” that may have been based on their facility's projected maximum capacity, but who in practice may not be able to achieve this capacity or do not do so for some period of time due to market conditions, are allowed under the final RFS2 regulations to use this higher “permitted capacity” to establish their baseline volume. In these scenarios, baseline volume established through “permitted capacity” may be greater than the baseline volume that could be achieved by a comparable facility by reference to actual production during the first three years of operation. Thus, while it is true that “permitted capacity” does not always reflect potential capacity, “actual peak capacity” also does not necessarily reflect a facility's potential capacity, as demonstrated in our examples above. Therefore, we disagree with the commenters' statement that facilities using “actual peak capacity” to establish their baseline volume have an unfair advantage over facilities that must use their “permitted capacity” to establish their baseline volume.

With respect to facilities that commenced construction before the date of enactment of EISA, commenters also state that EPA should interpret the EISA grandfathering provisions to allow volumes from such facilities to be exempt up to the maximum of their “inherent capacity.” The statute does not use the term “inherent capacity,” and instead applies the 20 percent GHG reduction requirement to “new facilities that commence construction” after the date of enactment. In the RFS2 rulemaking, EPA addressed the issue of how to implement this grandfathering provision by defining both the facilities and their production volumes that would be grandfathered, and considering all other production volumes to be subject to the 20 percent GHG reduction threshold. EPA identified the grandfathered volumes in two steps. First, EPA identified the facilities that could be considered available for grandfathering by using definitions of “facility” and “commence construction” that were similar but not identical to those used in EPA's stationary source Prevention of Significant Deterioration (PSD) permitting program. After identifying these facilities, EPA followed a second step to identify what volumes at those facilities would be grandfathered. In this final rulemaking, EPA is addressing the same issue of what volume should be grandfathered as we did for the final RFS2 rulemaking.

EPA rejected the approach of determining that any and all volumes produced at qualifying facilities should be considered grandfathered. EPA also rejected the approach specified in the NPRM of requiring facilities to report on expenses for replacements, additions, and repairs so that EPA could determine on a case-by-case basis if such activities warranted considering the facility as effectively “new” for purposes of the grandfathering provisions. Instead, EPA chose an approach that extends an indefinite exemption to baseline volumes at qualifying facilities, and defines the grandfathered volume by reference to “permitted capacity” contained in air permits that govern the operation of a facility at the time of the statutory deadline. If such capacity is not stipulated in the permit, then the baseline is established by “actual peak capacity” achieved within either the last five calendar years prior to 2008 or, if the plant is not yet in operation, the first three years after start-up. The “permitted capacity” or the actual operations history of the plant would define a baseline volume, and increases above 105 percent of this volume would be considered production by a new facility. These criteria are objective and their use avoids the case-by-case decision-making that would be required if less objective criteria were applied.

In this rulemaking, EPA proposed to clarify but not change this approach, and commenters have suggested that EPA now change the approach substantially. EPA rejects this request for a change in approach for many of the same reasons given in the preamble to the final RFS2 regulations.

First, EPA notes that the statute does not define the terms “new facility” or “commence construction,” providing EPA discretion to interpret these terms in a reasonable fashion that promotes the goals of the statute. EPA notes that there were no objections to how EPA defined the universe of facilities that can produce grandfathered renewable fuel in the proposed RFS2 regulations. Rather, commenters raised issues regarding what volumes and years of production from these facilities (and from any modifications or expansions to the facilities) should be considered grandfathered. The only issue raised in the current set of comments, however, is the extent to which volumes above those allowed at the time of the statutory deadlines should be grandfathered.

As in the RFS2 rulemaking, EPA is faced with two basic approaches. The first approach is raised by commenters who suggest applying the concept of “maximum capacity” or “inherent capacity” on a case-by-case basis. Some commenters have suggested this could be limited in time to a set number of years in the future. Under this approach, EPA would evaluate each permit revision that occurs and would need to determine if the changes undertaken were within the “inherent capacity” of a qualifying facility. If they were not, the volumes would be considered produced by a new facility for which construction commenced after the statutory deadline.

EPA does not agree that this is either a required or an appropriate approach. EISA does not define the phrase “new facilities that commence construction,” nor does it refer to or require that EPA follow the approach suggested by the commenters. As was the case in the proposed and final RFS2 rules, EPA is concerned about the lack of objectivity and concreteness in applying a concept such as “inherent capacity.” There is no clear or concrete meaning to this term. In practice, renewable fuel facilities can and do evolve over time. A facility and its operations are typically in a constant state of flux to address changing circumstances and to optimize production under those circumstances. These changing circumstances can involve a full range of activities that may include changes in equipment or operations, with any of these changes ranging from minor to major. Once one aspect of facility design or operation that constrains capacity is optimized, another aspect becomes the constraining factor. This process, which can include what is often referred to as debottlenecking, is iterative and can continue indefinitely. Thus the terms “inherent capacity,” “nameplate capacity,” and “design capacity” have meaning only in a general or broad sense. EPA does not believe it could develop criteria that would fairly and objectively define these terms. Without such criteria, the case-by-case analysis to implement such an approach would be difficult to accomplish in a fair and consistent manner, thus making such an approach undesirable. Instead, EPA's approach is definitive, allowing in all cases 105 percent of “permitted capacity” or, if permit limits are not available, 105 percent of “actual peak capacity” to establish baseline volumes. The 105 percent factor allows a consistent and definitive allowance beyond “permitted capacity” or “actual peak capacity” measures. As stated in the preamble to the final RFS2 rule, it provides an allowance for debottlenecking and minor changes that may be brought about by normal maintenance that is consistent with the proper operation of a facility, while being sufficiently small so as to not encourage plant expansions that are unrelated to debottlenecking and normal maintenance procedures (75 FR 14670, 14689, March 26, 2010). EPA believes that such an allowance is consistent with the concept of applying the 20 percent GHG reduction requirement to “new facilities that commence construction” after EISA, while not also introducing a difficult case-by-case implementation approach to the rules as suggested by the commenters.

Under the approach taken in the final RFS2 rule and clarified in the direct final rule, future changes in production above 105 percent of the baseline volume would be treated as production by a new facility that commenced construction after the statutory deadline. Typically the increase in production, whether caused by a permit change or otherwise, would be the result of changes made in order to increase production, whether physical changes in equipment or changes in operation. These changes would make the plant different in a way that would allow it to produce more renewable fuel. Implementation of these changes would be considered construction, whether it is from a process of physical construction, physical replacement, change in operation, redesign, or reconfiguration. EPA broadly interprets the terms “new” and “construction” in the final RFS2 rule to encompass the kinds of changes typically taken to increase production.

EPA recognizes that the approach we have taken in the final RFS2 rule encompasses a broad variety of physical, operational, and other efficiency changes. EPA favors its approach because it gives reasonable meaning to the terms in EISA in a way that provides clear and objective criteria, and it avoids the problems and complexities noted above with the case-by-case approach that tries to implement an “inherent capacity” criterion. It is also a reasonable way to further the goals of the grandfathering provision and for evaluating future increases in production.

By arguing that the “inherent capacity” of a plant built before enactment must be grandfathered regardless of permit limitations on the date of enactment, commenters seem to be equating the term “construction” in the statute with “physical construction.” Their rationale is that if the increased volumes are not derived from new physical construction of a facility after the date of enactment, then any and all fuel from that grandfathered facility must be covered by the exemption. However, the term “construction” is not defined in EISA and need not be viewed in this manner. For example, Congress defined the term “construction” in CAA section 169(2) for the PSD program to include “modifications” as defined in CAA section 111(a)(4). That term is defined in the statute to include “any change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted.” The definition of “commence construction” adopted in the final RFS2 regulations specifically incorporates by reference the definition of “begin actual construction” from the PSD regulations, where the term “construction” is defined as “any physical change or change in the method of operation * * * that would result in a change in emissions.” (See 40 CFR 80. 1403(a)(4), 52.21(b)(1) and 53.21(b)(8).) EPA's treatment of post-enactment “construction” under the final RFS2 regulations to include operational modifications leading to the production of additional renewable fuel is therefore comparable to the approach adopted by Congress in the PSD program with respect to modifications that may lead to increased emissions.

The approach EPA adopted in the final RFS2 rule, and which we reaffirm today, reasonably promotes the goals of this statutory provision. EPA's analysis as part of the RFS2 rulemaking showed that the aggregate volumes of grandfathered ethanol for the entire industry would be approximately 15 billion gallons (74 FR 24904, 24925, May 26, 2009). Given the volume mandates and GHG reduction thresholds for the other three categories of renewable fuel (advanced biofuel, biomass-based diesel, and cellulosic biofuel), 15 billion gallons is (by coincidence) approximately the maximum amount of grandfathered ethanol that could be used in the RFS2 program for compliance purposes.^[3] In addition, EISA provides a considerable benefit to facilities claiming exemption from the 20 percent GHG reduction threshold. Such an exemption is not provided to similar facilities for which construction commences after the statutory deadlines. The exemption reasonably preserves the investment decisions of owners made prior to the time of enactment of EISA. Those investment decisions were clearly based on the practices of the facilities constructed on or before the statutory deadlines, including any permit-related constraints in existence at the time. Any future increases in production based on future permit changes could generally be an enhancement to the value of the facility and would be based on future decisions, not investment decisions made prior to enactment of EISA.

We acknowledge the statement we made in the proposal for the RFS2 regulations, referenced by one of the commenters, that “our guiding philosophy of protecting historical business investments that were made to comply with the provisions of RFS1 are realized by allowing production increases within a facility's inherent capacity,” (74 FR 24904, 24926, May 26, 2009). We need to point out, however, that the statement was made in the context of soliciting comment on allowing a 10 percent tolerance level above “permitted capacity” and, as noted above, we proposed that “permitted capacity” would be ascertained at the time of facility registration. The 10 percent allowance was, therefore, proposed for comment as a straightforward and readily-implementable mechanism to reflect in grandfathered volumes as much of a plant's “inherent capacity” as practical while avoiding case-by-case assessments into the future indefinitely. In the same paragraph in the proposal, we further state that “at the same time, the alternative of requiring compliance with the 20% GHG reduction requirement for increases in volume above 10% over the baseline volume, [sic] would place new volumes from grandfathered facilities on a level playing field with product from new grass roots facilities. We believe that a level playing field for new investments is fair and consistent with the provisions of EISA,” (74 FR 24904, 24926, May 26, 2009).

Based on comments received on the RFS2 proposed rule, we decided to reject the 10 percent tolerance and “to interpret the exemption of the baseline volume of renewable fuel from the 20 percent GHG reduction requirement as extending indefinitely.” We noted that any tolerance provided could, therefore, “be present in the marketplace for a considerable time period.” Furthermore, we also stated that “increases in volume of 10 percent or greater could be the result of modifications other than debottlenecking,” and instead adopted a 5 percent tolerance level (75 FR 14670, 14689, March 26, 2010). We believe that these statements from the preamble to the RFS2 final rule are consistent with the arguments we have set forth above.

We disagree with the commenters' statement that facilities had inadequate notice of the time limitations for permits that could be used to establish baseline volume that is exempt from the 20 percent GHG reduction requirement. The preamble to the proposed rule stated that “the facility registration process * * * would be used to define the baseline volume for individual facilities. Owners and operators would submit information substantiating the nameplate capacity of the plant, as well as historical annual peak capacity if such is greater than nameplate capacity,” (74 FR 24904, 24926, May 26, 2009). In the proposal, nameplate capacity was defined in terms of permitted capacity. Furthermore, in discussing the facility registration process, the preamble stated that “in order to determine what production volumes would be grandfathered and thus deemed to be in compliance with the 20% GHG threshold, we would require * * * information necessary to establish [a facility's] renewable fuel baseline volume * * * ” (74 FR 24904, 24942, May 26, 2009). These discussions made it clear that the baseline volume would be determined in the registration process, and they did not indicate that making such determinations would be an ongoing process into the future. Under the RFS2 proposal, registration was to occur by January 1, 2010, or 60 days prior to commencement of production, whichever was later. The January 1, 2010, proposal date for the submission of permits to establish baseline volume with registration materials is fully consistent with the provision in the final rule that permits used to establish “permitted capacity” for “deemed compliant” facilities must have been issued no later than December 31, 2009, and for other grandfathered facilities by December 19, 2007. While the proposal would have allowed grandfathered facilities that commenced production after January 1, 2010, additional time to submit their registration materials, the preamble discussion did not suggest that this would afford them the opportunity to use permits issued after the relevant time periods referenced in EISA for purposes of establishing baseline volume. In addition, in describing EPA's basic proposal, EPA explained that, for facilities that commenced construction prior to EISA enactment, volumes greater than baseline volume “which may typically be due to expansions of the facility which occur after December 19, 2007, would be subject to the 20% GHG reduction requirement in order for the facility to generate RINs for the incremental expanded volume. The increased volume would be considered as if produced from a `new facility' which commenced construction after December 19, 2007.” EPA believes that these preamble statements provided adequate notice to the regulated community that EPA was considering limitations on the dates of permits that could be used to establish baseline volume, and also believes that commenters were reasonably apprised based on the discussion of dates in the preamble and the dates referenced in the statute that the permit cut-off dates ultimately selected for this purpose were under consideration.

As stated previously, the definition of “permitted capacity” in the direct final rule was revised to include the same permit cut-off dates referenced in the existing unamended registration section in the final RFS2 regulations. The direct final rule would not have established these cut-off dates as new requirements, but would merely have provided clarity to the existing regulations by placing references to permit dates in the definition of “permitted capacity” that are comparable to those that already existed in § 80.1450(b)(1)(v)(B). Commenters clearly had notice of these permit cut-off dates in commenting on the direct final rule, and brought their concerns to EPA's attention in the context of this rulemaking. EPA has considered these comments and has decided not to revise the regulations in the manner they have proposed, but instead, for all of the reasons discussed above, to finalize in this rule the same definition of “permitted capacity” that was included in the direct final rule and parallel proposal.

EPA is also finalizing the amendments included in the direct final rule and parallel proposal that we did not receive adverse comment on, but that were tied to the revised definition of “permitted capacity” and therefore were also withdrawn in the June 30, 2010, notice (75 FR 37733). These related amendments move the definitions of “actual peak capacity,” “baseline volume,” and “permitted capacity” from their original locations at § 80.1403(a) to § 80.1401 in order to consolidate them with other definitions used in 40 CFR part 80, subpart M. They revise the definition of “actual peak capacity” to clarify that actual peak capacity for facilities that commenced construction prior to December 19, 2007, but that did not have at least one calendar year of actual production prior to 2008, should be based on any calendar year after startup during the first three years of operation. They also clarify that for facilities that commenced construction after December 19, 2007, but before January 1, 2010, that are fired with natural gas, biomass, or a combination thereof, “actual peak capacity” is based on any calendar year after startup during the first three years of operation. These amendments, which are closely tied to changes to the definition of “permitted capacity” that we are finalizing today, are also being finalized as they were proposed at 75 FR 26049 (May 10, 2010).

B. Treatment of Renewable Identification Numbers

In order to facilitate the transition from RFS1 to RFS2, many of the final RFS2 regulations clarified the differences between how Renewable Identification Numbers (RINs) are treated under each program. However, in the final RFS2 rule, the section on product transfer documents (PTD) requirements was not clear about the information that must be on PTDs for RINs under the RFS2 program, and we issued several amendments to § 80.1453 in the direct final rule to clarify the PTD requirements under RFS2. We did not receive any adverse comment on these amendments.

In conjunction with the amendments to § 80.1453, we proposed amendments to § 80.1425, which provides a description of the 38-digit RIN. The amendments were meant to clarify that RINs generated under RFS2 are not identified by a 38-digit code, but rather that most of the information contained within the RFS1 38-digit code is entered and made available in the EPA Moderated Transaction System (EMTS) as separate data elements. We also proposed amendments to § 80.1426(d)(1), (f)(3)(iv), and (f)(3)(v) to clarify that either the batch (BBBBB) component of the RIN or its EMTS-equivalent can be used to identify a particular batch of renewable fuel.

We received adverse comment from several parties on the proposed amendments to § 80.1425, who took issue with the elimination in EMTS of the SSSSSSSS and EEEEEEE components (start and end numbers) of the RFS1 38-digit RIN. The commenters expressed concern that the 38-digit code was being abandoned and claimed this proposed change would impact a regulated party's right and ability to maintain an independent accounting of their RINs at a unit (gallon-RIN) level. They also claimed that without this information, attempts to manage RIN transactions would be problematic for the regulated community. Furthermore, the commenters stated that they saw no steps taken in the rulemaking process that would have notified industry of EPA's intent to move away from the 38-digit RIN.

In the preamble to the RFS2 NPRM, we outlined the concept for EMTS and described the circumstances experienced under the RFS1 program that led us to conclude that such a system would be necessary and preferable to the RFS1 approach to RIN generation and transaction. We stated that “in implementing RFS1, we found that the 38-digit standardized RINs have proven confusing to many parties in the distribution chain. Parties have made various errors in generating and using RINs. * * * We have also seen incorrect numbering of volume start and end codes,” (74 FR 24974). In the preamble to the NPRM, we also acknowledged that “once an error is made within a RIN, the error propagates throughout the distribution system. Correcting an error can require significant time and resources and involve many steps,” (74 FR 24974). Finally, we noted that “incorrect RINs are invalid RINs. If parties in the distribution system cannot track down and correct the error made by one of them in a timely manner, then all downstream parties that trade the invalid RIN will be in violation. Because RINs are the basic unit of compliance for the RFS1 program, it is important that parties have confidence when generating and using them,” (74 FR 24974).

We proposed and finalized EMTS in the RFS2 rulemaking process as the solution to address most, if not all, of these issues, and to handle the increasingly complex RIN generation and transaction requirements under RFS2 due to the increased volume mandates and four categories of renewable fuel. While the commenters are correct that EMTS does not employ the 38-digit RIN as it was originally conceived for the RFS1 program, the system is designed to allow users to transact RINs in a generic way while still maintaining the ability to know any individual RIN's source at a company and facility level. We described this change in the preambles to both the proposed and final RFS2 regulations. (See 74 FR 24975 and 75 FR 14733.) Specifically, in the preamble to the final RFS2 regulations, we stated, “one major advantage of EMTS * * * is that the system will simplify trading by allowing RINs to be traded generically. Only some specifying information will be needed to trade RINs, such as RIN quantity, fuel type, RIN assignment, RIN year, RIN price or price per gallon. * * * The actual items of transactional information covered under RFS2 are very similar to those reported under RFS1,” (75 FR 14733).

Indeed, all major components of the RIN as conceived under the RFS1 program are used in EMTS with the exception of the “S” and “E” starting and ending RIN values. The S and E components of the 38-digit RIN served two purposes under RFS1. One was to determine the number of gallon-RINs contained in a batch-RIN segment, calculated by subtracting the ending RIN value from the starting RIN value. The second use was to ensure that the number of gallon-RINs represented by a batch-RIN did not grow or decrease as it was passed from buyer to seller, in many cases multiple times. As noted above, under RFS1, an overlap or duplication of S and E codes between transactions was an indication that something had gone wrong during the exchange of RIN information.

Under RFS2, EMTS performs transactions of individual RINs (the RFS1 equivalent of gallon-RINs) with a simple reference to RIN quantity, and the system does not use S and E components. Being a closed system, there is no opportunity for a RIN owner to purposefully or accidentally increase or decrease the number of RINs originally associated with a batch of renewable fuel. The original RIN quantity may be subdivided into smaller parts as the RINs and renewable fuel are transferred from one party to another, but EMTS accounts for the original total number of RINs at all times. This feature allows EMTS to manage RIN quantities without the need for S and E components.

We believe that the comment we received suggesting that a regulated party's right and ability to maintain an independent accounting of their RINs at a unit level would be negatively affected by eliminating the use of the 38-digit RIN is unfounded. In the preambles to both the proposed and final RFS2 rules, we discussed the fact that, like under the RFS1 program, there is no “good faith” provision with respect to RIN ownership. To help companies manage their RINs in such a “buyer beware” environment, we proposed and finalized that a RIN purchaser can accept or reject RINs from specific RIN generators or from classes of RIN generators (74 FR 24975, 75 FR 14733). In practice, this allowance has translated into a function within EMTS that allows a RIN account holder to block RINs generated by specific companies and/or facilities. EMTS now also allows a RIN transferee to review details of RINs offered by a transferor, such as the RIN generators' company and facility ID numbers, prior to accepting or rejecting the transaction. In this way, a RIN account holder can protect himself or herself from being transferred RINs generated by a company with whom the RIN account holder chooses not to do business, even if indirectly. There is also a function within EMTS that allows a RIN account holder to transact unique, as opposed to generic, RINs. Unique RINs carry specific information related to the RIN generator, date of production, and batch number. As discussed above, EMTS is a closed system, and the total number of RINs associated with a particular batch of renewable fuel cannot increase or decrease even as the RINs are subdivided and transferred to multiple RIN owners. This fundamental characteristic of EMTS, together with the added features of being able to block certain RINs and trade unique ones, enhances the ability of any RIN account holder to protect their interests.

As for the commenters' concerns that they were not notified of EPA's intent to move away from the 38-digit RIN during the RFS2 rulemaking process, EPA disagrees. As discussed above, EPA introduced the concept and basic functionality of EMTS in the preamble to the RFS2 NPRM (74 FR 24904) and development of the new system commenced shortly thereafter. The process of development and testing was conducted openly and with significant stakeholder input and participation, including direct involvement by at least one of the commenters. A number of workshops, webinars and discussions were held throughout the period between publication of the NPRM and issuance of the final RFS2 regulations. In addition, presentation materials, users' guides, data schema, data templates, and tutorials were offered for interested parties to understand and provide input on system design and development. Based on this input, EPA was able to successfully deploy EMTS on July 1, 2010, concurrent with the RFS2 regulations taking effect.

We believe that the transition from the 38-digit RIN under RFS1 to the generic RIN under RFS2 allows for greater system flexibility and integrity, while maintaining the detailed RIN information necessary for regulated parties to perform independent checks on RINs they generate, receive, and transfer. In addition, we believe that the information presented throughout the rulemaking process for RFS2 adequately and transparently prepared regulated parties for the transition to EMTS. For these reasons, we are finalizing the amendment to the introductory text to § 80.1425 as it was set forth in the May 10, 2010, direct final rule and parallel proposal (75 FR 26026, 75 FR 26049). Specifically, we are amending the text to clarify that RINs generated after July 1, 2010, may only be generated and transferred using EMTS and will not be identified by a 38-digit code. We are also amending § 80.1425(i) to simply clarify that the value of EEEEEEEE is a number representing the last gallon-RIN associated with a volume of renewable fuel.

In addition to the proposed amendments to § 80.1425, we also proposed amendments to § 80.1426(d)(1), (f)(3)(iv), and (f)(3)(v) to clarify that either the batch (BBBBB) component in the RIN or its EMTS-equivalent would be used to identify a particular batch of renewable fuel. A commenter stated that the phrase “or its equivalent in EMTS” when referring to batch-identifying information in EMTS is not clearly defined, and they expressed concern that this language would limit regulated companies from properly certifying their data and would inhibit the ability of accountants to attest to their clients' data. The commenter also requested that the language be clarified so that regulated parties can certify their data and accountants can reasonably rely on it.

Under RFS1, the BBBBB code was a unique user-specified value that could only contain numbers and had to contain five digits. The requirement to assign a “unique” batch number allowed the regulated community and EPA to determine which RINs were associated with each volume of renewable fuel, and it prevented double-counting by requiring renewable fuel producers or importers to generate one, and only one, RIN for each volume of renewable fuel. Because it could represent up to one calendar month's worth of renewable fuel production (or importation) and up to 99,999,999 gallons, RIN generators frequently generated 12 batches in a calendar year, one for each month. In EMTS, the batch number is a unique user-specified value that can contain up to 20 alphanumeric or other characters. It is a field required for RIN generation and a RIN owner may view the batch number associated with any RIN in their possession. We believe that the larger field format and ability to use letters as well as other characters to identify a batch in EMTS enhances a regulated party's ability to certify their RIN data—either as RIN generators or as RIN owners—and, in turn, allows a party's CPA to attest to the validity of such data. At the same time, we agree with the comment that the proposed language was vague and does not adequately describe what the EMTS-equivalent of the BBBBB code is. We are therefore not finalizing the amendments to these sections and will revert to the language in the final RFS2 regulations that simply refer to a “unique batch identifier,” which may be either the five-digit BBBBB component or the EMTS batch number of up to 20 characters.

C. Advanced Technologies for Renewable Fuel Pathways

The final RFS2 rule includes two corn ethanol pathways in Table 1 to § 80.1426 that require the use of one or two advanced technologies at the production facility as a prerequisite to the generation of RINs. The five advanced technologies available for this purpose are listed in Table 2 to § 80.1426. In developing this list of advanced technologies, EPA relied upon modeling that included the use of one or more advanced technologies at a base corn-ethanol plant.^[4] . In all cases, the modeling assumed use of a given advanced technology across 100 percent of the ethanol production. The pathways in Table 1 and the list of advanced technologies in Table 2 represent the application of advanced technologies to 100 percent of production, consistent with the modeling they were based on.

However, neither the list in Table 2 nor the pathway descriptions in Table 1 were explicit on this percent of usage. As a result, some producers of corn ethanol assumed that any degree of implementation of advanced technologies, even to the point of de minimis GHG benefit, would be acceptable and consistent with the letter of the regulations. In the direct final rule and parallel proposal published on May 10, 2010 (75 FR 26026, 75 FR 26049), we announced a revision to Table 2 to § 80.1426 to clarify the degree to which advanced technologies must be implemented in order to represent a valid advanced technology for the generation of RINs. The announced revision specified that the advanced technologies must be applied to all production at the corn ethanol facility. In response to the direct final rule, we received adverse comments from several stakeholders objecting to the changes to Table 2 to § 80.1426. As a result, we withdrew the changes to Table 2 to § 80.1426 in a Federal Register notice published on June 30, 2010 (75 FR 37733).

There were several alternative approaches to advanced technologies that were suggested by commenters, including the creation of additional pathways to add to Table 1 to § 80.1426. EPA notes at the outset that the scope of this rulemaking effort as it relates to Tables 1 and 2 to § 80.1426 is to clarify the regulatory language that identifies the pathways and specifications for advanced technologies that were modeled as part of the RFS2 rulemaking effort and that were determined to lead to an appropriate level of GHG reduction. EPA continues to evaluate additional pathways on its own initiative, and may approve the use of additional pathways, as it recently did for canola oil biodiesel.^[5] EPA has also established a petition process in § 80.1416 to allow parties seeking the addition of new pathways to Table 1 to § 80.1426 to bring those pathways to EPA's attention for evaluation. EPA urges parties seeking EPA consideration of new pathways to utilize that process. While EPA will fully evaluate any petitions for new pathways when and if they are submitted to EPA pursuant to § 80.1416, EPA also provides in this preamble some preliminary thoughts regarding some of the commenters' suggestions for new pathways, even though they are beyond the scope of this rulemaking effort.

One commenter suggested that EPA incorporate into Table 2 an energy-based metric for identifying the extent to which each advanced technology must be used at corn ethanol facilities in order to be deemed to achieve a 20 percent GHG reduction. The commenter suggested that this approach could be accomplished by basing the metric on the pathway in Table 1 to § 80.1426 that specifies no greater that 50 percent drying of distillers grains and solubles (DGS) and no advanced technologies. The premise of the comment is that any combination of advanced technologies that reduces energy usage by a specified amount will achieve the 20 percent GHG threshold. EPA rejects this approach as an oversimplification that is not currently consistent with the modeling used by EPA in developing the list of pathways and advanced technologies in Tables 1 and 2 to § 80.1426. First, EPA's modeling assumed an industry average for the various advanced technologies, and not any specific brand or type of technology. As such, the results cannot be translated into the specific equipment used and operated at a single plant. The precision of the modeling does not support an extrapolation down to specific technology at a specific plant, which would be required under the commenter's approach.

Second, EPA modeled various scenarios, including a base plant with 100 percent drying of DGS, a base plant with 100 percent wet DGS, and various combinations of advanced technologies. In some cases use of just one specific technology such as CHP or corn oil fractionation was modeled. In other cases a base plant was modeled while progressively adding different advanced technologies. EPA's modeling by necessity did not cover the universe of all possible combinations of advanced technologies, and as such does not allow for a precise quantification of each advanced technology either by itself or in combination with a second advanced technology. The modeling does provide clear indication that (1) There can be interactive effects between pairs of advanced technologies, (2) advanced technologies can have complex impacts, and the reductions in GHG emissions are not all based on just a simple linear reduction in energy use, and (3) different combinations of advanced technologies are likely to lead to a range of results across the various combinations. EPA's conclusion in the final RFS2 rulemaking was that the GHG benefits of the use of advanced technologies as specified in Tables 1 and 2 to § 80.1426 would in all cases allow at least a limited degree of GHG reduction beyond the 20 percent threshold, with the exact degree of reduction dependent on the specific combination of advanced technologies and drying of DGS. As a result, the modeling performed by EPA to date does not support specifying a simple formula that could allow usage of advanced technologies as a function of measured reductions in energy usage. Thus EPA believes there is not a technical basis at this time for the approach suggested by the commenter.

We also received a suggestion that the table of advanced technologies be modified to include the option of “energy efficient plant design” that could be achieved through documented low energy use. In this approach, EPA would establish a level of energy input per gallon of product that would reflect achievement of the 20 percent GHG reduction threshold, and industry would be free to use any method to achieve that required energy utilization standard. Records of fuel and electricity use in the facility would be submitted to demonstrate attainment of the standard. This suggestion is clearly beyond the scope of this rulemaking effort, which is limited to clarifying the regulatory language related to the modeling and analyses that EPA conducted as part of the RFS2 rulemaking. Although the commenter suggested that the energy utilization standard could be set using existing modeling tied to an existing pathway in Table 1 to § 80.1426, EPA believes that this would not be technically justified for the same reasons, described above, that it would not be appropriate to use this metric to establish specifications regarding use of advanced technologies. Thus, the suggested approach would likely require new analyses to identify an appropriate energy utilization standard that would take into account all possible direct and indirect effects associated with multiple possible permutations of facility technology and practice. It could also require additional recordkeeping and reporting requirements as well as new formulas or tabulated values in the regulations for converting energy use into GHG reductions. All such changes would entail dramatically different approaches to the identification of pathways that achieve the necessary amount of GHG reduction to qualify under the Act than were finalized in the RFS2 rulemaking. Therefore, we did not propose and are not adopting the commenter's suggested approach in today's rulemaking. Parties advocating this approach are encouraged to utilize the petition process in § 80.1416 to request that EPA further evaluate this concept and, in the context of their petition, to address the concerns that EPA noted above.

A number of commenters suggested that application of advanced technologies to 100 percent of the production at a corn ethanol plant was not feasible. One commenter pointed out that common and legitimate downtime for an advanced technology, even if it is of a very short duration, could preclude a corn ethanol producer from generating any RINs if Table 2 to § 80.1426 requires application of an advanced technology to all production at a facility. Another commenter suggested that advanced technologies be required to be applied to 90 percent of the production at a corn ethanol facility, instead of 100 percent. In response, we do recognize that there may be occasions in which an advanced technology must be halted or bypassed for a short time for maintenance, repair, or other reasons. To determine whether the regulations could be modified to address this concern, we reviewed the original lifecycle GHG modeling for corn ethanol plants that was done for the RFS2 final rule. The modeling indicates that use of the advanced technologies as specified should in all cases provide a minimum margin of compliance beyond the 20 percent GHG reduction threshold, and in some cases a larger margin. Thus a small reduction in the application of advanced technologies should still ensure that the 20 percent GHG threshold is met. EPA recognizes that this is a question of degree and is basing this on expert judgment and not specific new modeling. As such, no more than a small reduction in percent usage is warranted absent further modeling. As a result, we have modified the regulatory requirements so that advanced technologies must be applied to at least 90 percent of the production at a corn ethanol facility. Moreover, we are requiring that compliance with this 90 percent criterion be made over the course of a calendar year, consistent with the approach to the maximum allowable fraction of DGS that can be dried under certain corn ethanol pathways in Table 1 to § 80.1426. This approach relies on judgment based on the lifecycle modeling that was previously performed, as described above, to provide some flexibility for downtime of an advanced technology while still requiring the requisite level of GHG reduction.

Since compliance with the advanced technologies in Table 2 to § 80.1426 is determined on an annual basis, any RINs that are generated based upon the use of one or more of these technologies could be considered invalid if the technologies are not employed in accordance with the specifications in Table 2, including any requirement based upon use of these technologies for 90 percent of production on a calendar year basis. We note, however, that in determining an appropriate remedy for a violation arising from a renewable fuel producer's failure to properly employ advanced technologies in accordance with the specifications in Table 2 to § 80.1426, EPA may consider a number of factors, including the volume of fuel for which RINs were generated that was produced without the advanced technologies, the reasons that the advanced technologies were not employed, and efforts taken by the renewable fuel producer to remedy the harm caused by the violation.

Another suggested change would have allowed GHG reductions for ethanol volume that is grandfathered under § 80.1403 to be used as a credit for ethanol volume that has not been grandfathered. Such an approach could mean that all the GHG reductions associated with applying a given advanced technology to an entire corn ethanol plant could be deemed to apply to only the volume that is in excess of the plant's grandfathered baseline volume. We do not believe that this would be appropriate. Not only did we not propose such an approach to compliance with the 20 percent GHG reduction threshold, but it would amount to transferring GHG reductions from grandfathered volume to non-grandfathered volume. In so doing, a corn ethanol producer could claim that its non-grandfathered ethanol met the 20 percent GHG reduction threshold even if the plant as a whole did not and there was no discernable difference in plant operations between the grandfathered and non-grandfathered volume. The regulations do not allow GHG reduction credits to be assumed for grandfathered volume and then used to offset the GHG emissions from the non-grandfathered portion of the facility's production. Non-grandfathered production must be assessed separately.

Some commenters raised a concern that the proposed language requiring application of advanced technologies to “all” production at a facility necessarily required that the advanced technologies be applied to volumes that are grandfathered and are not subject to the 20 percent GHG reduction threshold for renewable fuel. This was not our intention. Advanced technologies are not required for volumes that are grandfathered according to § 80.1403. Thus, we have modified the regulations to clarify that Tables 1 and 2 to § 80.1426 do not apply to volumes of fuel for which RINs are generated pursuant to § 80.1426(f)(6).

With regard to corn oil extraction, we believe that the description in Table 2 to § 80.1426 requires additional modification to more accurately reflect the lifecycle modeling that was conducted. For instance, some commenters pointed out that the terms “thin stillage” and “distillers grains and solubles” do not accurately describe the byproduct categories to which corn oil extraction can be applied. More appropriate might be thin stillage and wet cake, or alternatively just the whole stillage which precedes the derivatives thin stillage and wet cake. Our lifecycle modeling assumed that corn oil extraction was applied to all the byproducts that are included in whole stillage. However, after further consideration, we believe that a more straightforward approach to specifying the required application of corn oil extraction in the regulations would be to identify the amount of oil that must be extracted rather than the amount of whole stillage to which the technology must be applied. This approach is consistent with a suggestion from one commenter and will result in the same GHG reductions as our proposed approach. This approach will also allow corn-ethanol producers utilizing the corn oil extraction advanced technology to apply it to particular byproducts as they see fit, providing only that the requisite quantity of oil is extracted.

The lifecycle modeling that led us to include corn oil fractionation in Table 2 to § 80.1426 assumed an oil extraction rate of 1.48 pounds of oil per bushel of corn. As described above, we have determined that a 10 percent reduction in the application of this advanced technology can be accommodated while still ensuring that the 20 percent GHG threshold has been met. An oil extraction rate of 1.33 pounds per bushel represents 90 percent of the value we assumed in developing Table 2 to § 80.1426. Thus, in today's rule we are modifying the description of corn oil extraction to require a minimum of 1.33 pounds of oil to be extracted from whole stillage or its derivatives per bushel of corn that is processed into ethanol. This oil extraction rate is substantially less than the total amount of oils contained in byproducts from corn ethanol processing. As a result, we believe this approach will address concerns from some commenters that the proposed language would have required all oil to be removed from distillers grains, potentially creating an unmarketable product. Although one commenter suggested a corn oil extraction rate of 1.0 pound per bushel, we do not believe that this level of implementation of this advanced technology would ensure that the 20 percent GHG reduction threshold has been met.

With regard to combined heat and power (CHP), one commenter expressed concern that the application of CHP to all of the production at a corn ethanol facility could require the installation of new boilers sized to produce electricity. The commenter argued that such actions were unnecessary and would make CHP commercially unviable. However, the identification of advanced technologies in Table 2 to § 80.1426 and the calculation of their required usage rate is designed to ensure that the 20 percent GHG reduction threshold can be met. The costs of implementation of CHP were not considered in determining the technical issue of the GHG reduction threshold determination. However, we have reviewed the modeling conducted as part of the RFS2 rulemaking and have determined that application of CHP to 90 percent of production at a corn ethanol facility will achieve a 20 percent GHG reduction, and we have modified Table 2 to § 80.1426 accordingly.

In conjunction with the modifications to Table 2 to § 80.1426 as described above, we are finalizing additional recordkeeping and attest engagement requirements to help ensure that RINs are properly generated for corn ethanol produced at facilities that employ advanced technologies listed in Table 2 to § 80.1426. Specifically, we are finalizing a requirement at § 80.1454(b)(3)(xi) that, for RINs generated for ethanol produced from corn starch at a facility using advanced technologies in accordance with the requirements in Tables 1 and 2 to § 80.1426, producers must maintain documentation to demonstrate that advanced technologies used to qualify such ethanol for RIN generation were employed at least 90 percent of the time on a calendar year basis. In addition, we are finalizing an amendment to the attest engagement procedures for renewable fuel producers at § 80.1464(b)(1)(iii) that, for RINs generated for ethanol produced from corn starch at a facility that used advanced technologies in accordance with the requirements in Tables 1 and 2 to § 80.1426, will require verification that the advanced technologies used to qualify such ethanol for RIN generation were employed at least 90 percent of the time on a calendar year basis. We believe that these requirements are natural outgrowths of the final changes being made to Table 2 to § 80.1426 in response to comments received on our proposed amendments to this section, and that these additional recordkeeping and attestation requirements are necessary to ensure compliance with and enforceability of this aspect of the RFS program.

D. Use of Biogas from a Dedicated Pipeline at Renewable Fuel Production Facilities

EPA proposed to amend 40 CFR 80.1426(f)(12) to clarify the requirements that must be met in order for gas used for process heat at a renewable fuel production facility to be considered biogas for purposes of the “production process requirements” column of Table 1 to § 80.1426. In order to differentiate the requirements associated with biogas transported via a dedicated pipeline versus those associated with biogas transported via a common carrier pipeline, we proposed to subdivide the requirements under § 80.1426(f)(12). Thus revisions to § 80.1426(f)(12)(i) were proposed to describe the requirements for biogas transported via a dedicated pipeline, and revisions to § 80.1426(f)(12)(ii) were proposed to describe the requirements for biogas transported via a common carrier pipeline. In drafting the proposed revised regulations applicable to biogas in a dedicated pipeline in § 80.1426(f)(12)(i), we mistakenly included language in paragraph § 80.1426(f)(12)(i)(D) that referred to biogas placed in a common carrier pipeline, and proposed requiring that such pipeline ultimately serve the renewable fuel producer's facility. A commenter rightfully expressed confusion over the proposed amendment at § 80.1426(f)(12)(i), since § 80.1426(f)(12)(ii) is the appropriate section for references to biogas in a common carrier pipeline. We received no other comments on our proposed changes to § 80.1426(f)(12).

EPA agrees that the amendment at § 80.1426(f)(12)(i)(D) was proposed in error and therefore is finalizing all proposed amendments to § 80.1426(f)(12), with the exception of § 80.1426(f)(12)(i)(D). We considered retaining the provision by deleting the words “common carrier” that modify the reference to “pipeline.” However, § 80.1426(f)(12)(i) already specifies that the biogas discussed in this section is “directly transported to the facility.” Therefore, a modified § 80.1426(f)(12)(i)(D) is not necessary, and we have simply deleted the provision. We also noted a typographical error and some potentially confusing text in § 80.1426(f)(12)(ii)(C) and have taken this opportunity to make the appropriate corrections.

E. Time Limits for Reporting Transactions in EMTS

The final RFS2 regulations require any RIN generator to submit, via their account in the EPA Moderated Transaction System (EMTS), information about any batch of renewable fuel and the RINs generated for it within five days of the production or importation of the batch (see § 80.1452(b) at 75 FR 14887). Likewise, the final RFS2 regulations also require any party that engages in RIN transactions to submit, via their EMTS account, information about the transaction within five business days (see § 80.1452(c) at 75 FR 14887). These transactional time limits were finalized in order to strike a balance between the need for EMTS to be a “real time” system and the need for some amount of flexibility to accommodate existing business practices related to conducting renewable fuel and RIN transactions.

After the RFS2 regulations were finalized, EPA received numerous inquiries from regulated parties about whether the five day limit applied to both the transactional buyer and seller together, or whether each seller and each buyer had five days to perform their respective actions in EMTS. We therefore proposed to amend § 80.1452(b) and (c) to clarify our original intent with respect to when RIN information needed to be submitted to EMTS. Specifically, we proposed to revise § 80.1452(b) to clarify that RIN information must be entered into EMTS within five business days of RINs being assigned to a batch of renewable fuel and to clarify the information required to be submitted via EMTS for each such batch. We also proposed to revise § 80.1452(c) to clarify that transactions involving RINs generated on or after July 1, 2010, must be conducted via EMTS within five business days of a reportable event, to clarify the meaning of the term “reportable event,” and to clarify the information required to be submitted via EMTS for each transaction involving RINs generated on or after July 1, 2010.

We received one adverse comment on the proposed amendatory language to § 80.1452(b) and (c) that expressed concern over a buyer's inability to check the accuracy and validity of RINs that may be received via a renewable fuel product transfer document (PTD) and an inability to prevent RINs with errors from being traded further. As discussed above, in addition to the adverse comment, we received feedback from regulated parties prior to the publication of the direct final and parallel proposed rules on May 10, 2010 (75 FR 26026, 75 FR 26049), that the five business day requirement for both parties may be acceptable on the seller's side of the transaction, but that it can prove difficult for a buyer to confirm or send transactional information within five days of the PTD date. This difficulty may be due to the fact that the PTD may be generated and sent when the fuel is shipped, and the shipping may take longer than a week, or because all RINs may be aggregated on one PTD that is sent weekly or monthly along with renewable fuel.

Based on the comment received as part of this rulemaking and the additional feedback received prior to this rulemaking, we are finalizing an amendment to § 80.1452(c) that will increase the number of days a buyer has to submit transactional information to EMTS. Specifically, a buyer will have ten business days from the date on the PTD to submit information about a transaction, including accepting a transaction initiated by a seller, in EMTS. The seller will still be required to submit information within five business days of the date on the PTD. Thus the buyer will have a minimum of five days, and a maximum of up to ten days if the seller acts on the same date as the date on the PTD, to enter the required information into EMTS.

Although the comment makes reference both to 80.1452(b) and (c), we believe that the amendatory language to § 80.1452(c) alleviates the problem cited by the commenter and therefore we are finalizing the amendment to 80.1452(b), to allow up to five business days after RIN assignment for a RIN generator to submit RIN information for a batch of renewable fuel to EMTS, as proposed at 75 FR 26049 (May 10, 2010). We also noted inconsistency and some potentially confusing text at § 80.1452(b)(1), (b)(2), (b)(4), and (b)(5) and have taken this opportunity to make the appropriate corrections.

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

Under Executive Order 12866, (58 FR 51735, October 4, 1993) the Agency must determine whether the regulatory action is “significant” and therefore subject to OMB review and the requirements of the Executive Order. The Order defines “significant regulatory action” as one that is likely to result in a rule that may:

(1) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities;

(2) Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency;

(3) Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or

(4) Raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order.

It has been determined that this action is not a “significant regulatory action” under the terms of Executive Order 12866 and is therefore not subject to OMB review.

B. Paperwork Reduction Act

This action does not impose any new information collection burden. The corrections, clarifications, and modifications to the final RFS2 regulations contained in this rule are within the scope of the information collection requirements submitted to the Office of Management and Budget (OMB) for the final RFS2 regulations. OMB has previously approved the information collection requirements contained in the existing regulations at 40 CFR part 80, subpart M under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control number 2060-0640. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.

For purposes of assessing the impacts of today's rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration's (SBA) regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.

After considering the economic impacts of this final rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. This final rule will note impose any requirements on small entities that were not already considered under the final RFS2 regulations, as it makes relatively minor corrections and modifications to those regulations.

D. Unfunded Mandates Reform Act

This rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year. We have determined that this action will not result in expenditures of $100 million or more for the above parties and thus, this rule is not subject to the requirements of sections 202 or 205 of UMRA.

This rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. It only applies to gasoline, diesel, and renewable fuel producers, importers, distributors and marketers and makes relatively minor corrections and modifications to the RFS2 regulations.

E. Executive Order 13132 (Federalism)

This action does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. This action only applies to gasoline, diesel, and renewable fuel producers, importers, distributors and marketers and makes relatively minor corrections and modifications to the RFS2 regulations. Thus, Executive Order 13132 does not apply to this action.

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

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

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

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

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

This rule is not subject to Executive Order 13211 (66 FR 18355, May 22, 2001), because it is not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

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

This action does not involve technical standards. Therefore, EPA did not consider the use of any voluntary consensus standards.

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

Executive Order (EO) 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States.

EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it does not affect the level of protection provided to human health or the environment. These technical amendments do not relax the control measures on sources regulated by the RFS regulations and therefore will not cause emissions increases from these sources.

K. Congressional Review Act

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

L. Clean Air Act Section 307(d)

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

List of Subjects in 40 CFR Part 80

• Environmental protection
• Fuel additives
• Gasoline
• Imports
• Motor vehicle pollution
• Reporting and recordkeeping requirements

Dated: December 14, 2010.

Lisa P. Jackson,

Administrator.

For the reasons set forth in the preamble, 40 CFR part 80 is amended as follows:

PART 80—REGULATION OF FUELS AND FUEL ADDITIVES

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

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

2. Section 80.1401 is amended by adding definitions of “Actual peak capacity”, “Baseline volume”, and “Permitted capacity”, in alphabetical order to read as follows:

§ 80.1401

Definitions.

* * * * *

Actual peak capacity means 105% of the maximum annual volume of renewable fuels produced from a specific renewable fuel production facility on a calendar year basis.

(1) 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.

(2) For facilities that commenced construction after December 19, 2007 and before January 1, 2010 that are fired with natural gas, biomass, or a combination thereof, the actual peak capacity is based on any calendar year after startup during the first three years of operation.

(3) For all other facilities not included above, the actual peak capacity is based on the last five calendar years prior to the year in which the owner or operator registers the facility under the provisions of § 80.1450, 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.

* * * * *

Baseline volume means the permitted capacity or, if permitted capacity cannot be determined, the actual peak capacity of a specific renewable fuel production facility on a calendar year basis.

* * * * *

Permitted capacity means 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 (including local, regional, state or a foreign equivalent of a state, and federal permits, or permits issued by foreign governmental agencies) that govern the construction and/or operation of the renewable fuel facility, based on an annual volume output on a calendar year basis. If the permit specifies maximum rated volume output on an hourly basis, then annual volume output is determined by multiplying the hourly output by 8,322 hours per year.

(1) For facilities that commenced construction prior to December 19, 2007, the permitted capacity is based on permits issued or revised no later than December 19, 2007.

(2) For facilities that commenced construction after December 19, 2007 and before January 1, 2010 that are fired with natural gas, biomass, or a combination thereof, the permitted capacity is based on permits issued or revised no later than December 31, 2009.

(3) For facilities other than those described in paragraphs (1) and (2) of this definition, permitted capacity is based on the most recent applicable permits.

* * * * *

3. Section 80.1403 is amended by revising paragraph (a) to read as follows:

§ 80.1403

Which fuels are not subject to the 20% GHG thresholds?

(a) For purposes of this section, the following definitions apply:

(1) Commence construction, as applied to facilities that produce renewable fuel, means that:

(i) The owner or operator has all necessary preconstruction approvals or permits (as defined at 40 CFR 52.21(b)(10)), and has satisfied either of the following:

(A) Begun, or caused to begin, a continuous program of actual construction on-site (as defined in 40 CFR 52.21(b)(11)).

(B) Entered into binding agreements or contractual obligations, which cannot be cancelled or modified without substantial loss to the owner or operator, to undertake a program of actual construction of the facility.

(ii) For multi-phased projects, the commencement of construction of one phase does not constitute commencement of construction of any later phase, unless each phase is mutually dependent for physical and chemical reasons only.

(2) [Reserved]

* * * * *

4. Section 80.1425 is amended by revising the introductory text and paragraph (i) to read as follows:

§ 80.1425

Renewable Identification Numbers (RINs).

RINs generated on or after July 1, 2010 shall not be generated as a 38-digit code, but shall be identified by the information specified in paragraphs (a) through (i) of this section and introduced into EMTS as data elements during the generation of RINs pursuant to § 80.1452(b). For RINs generated prior to July 1, 2010, each RIN is a 38-digit code of the following form:

KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE

* * * * *

(i) EEEEEEEE is a number representing the last gallon-RIN associated with a volume of renewable fuel.

5. Section 80.1426 is amended as follows:

a. By revising introductory text to paragraph (f)(1).

b. By revising Table 2 to § 80.1426.

c. By revising paragraph (f)(12).

§ 80.1426

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

* * * * *

(f) * * *

(1) Applicable pathways. D codes shall be used in RINs generated by producers or importers of renewable fuel according to the pathways listed in Table 1 to this section, subparagraph 6 of this section, or as approved by the Administrator. In choosing an appropriate D code, producers and importers may disregard any incidental, de minimis feedstock contaminants that are impractical to remove and are related to customary feedstock production and transport. Tables 1 and 2 to this section do not apply to, and impose no requirements with respect to, volumes of fuel for which RINs are generated pursuant to subparagraph 6 of this section.

* * * * *

Corn oil fractionation that is applied to at least 90% of the corn used to produce ethanol on a calendar year basis.

Corn oil extraction that is applied to the whole stillage and/or derivatives of whole stillage and results in recovery of corn oil at an annual average rate equal to or greater than 1.33 pounds oil per bushel of corn processed into ethanol.

Membrane separation in which at least 90% of ethanol dehydration is carried out using a hydrophilic membrane on a calendar year basis.

Raw starch hydrolysis that is used for at least 90% of starch hydrolysis used to produce ethanol instead of hydrolysis using a traditional high heat cooking process, calculated on a calendar year basis.

Combined heat and power such that, on a calendar year basis, at least 90% of the thermal energy associated with ethanol production (including thermal energy produced at the facility and that which is derived from an off-site waste heat supplier), exclusive of any thermal energy used for the drying of distillers grains and solubles, is used to produce electricity prior to being used to meet the process heat requirements of the facility.

* * * * *

(12) For purposes of Table 1 to this section, process heat produced from combustion of gas at a renewable fuel facility is considered derived from biomass if the gas is biogas.

(i) For biogas directly transported to the facility without being placed in a commercial distribution system, all of the following conditions must be met:

(A) The producer has entered into a written contract for the procurement of a specific volume of biogas with a specific heat content.

(B) The volume of biogas was sold to the renewable fuel production facility, and to no other facility.

(C) The volume and heat content of biogas injected into the pipeline and the volume of gas used as process heat are measured by continuous metering.

(ii) For biogas that has been gathered, processed and injected into a common carrier pipeline, all of the following conditions must be met:

(A) The producer has entered into a written contract for the procurement of a specific volume of biogas with a specific heat content.

(B) The volume of biogas was sold to the renewable fuel production facility, and to no other facility.

(C) The volume of biogas that is withdrawn from the pipeline is withdrawn in a manner and at a time consistent with the transport of fuel between the injection and withdrawal points.

(D) The volume and heat content of biogas injected into the pipeline and the volume of gas used as process heat are measured by continuous metering.

(E) The common carrier pipeline into which the biogas is placed ultimately serves the producer's renewable fuel facility.

(iii) The process heat produced from combustion of gas at a renewable fuel facility described in paragraph (f)(12)(i) of this section shall not be considered derived from biomass if any other party relied upon the contracted volume of biogas for the creation of RINs.

* * * * *

6. Section 80.1451 is amended by revising paragraph (b)(1)(ii)(M) to read as follows:

§ 80.1451

What are the reporting requirements under the RFS program?

* * * * *

(b) * * *

(1) * * *

(ii) * * *

(M) The type of co-products produced with each batch.

* * * * *

7. Section 80.1452 is amended as follows:

a. By revising paragraphs (b) introductory text, (b)(1), (b)(2), (b)(4), (b)(5), (b)(6), (b)(9), (b)(13), and (b)(15).

b. By revising paragraphs (c) introductory text, (c)(4), (c)(5), and (c)(7).

§ 80.1452

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

* * * * *

(b) Starting July 1, 2010, each time a domestic or foreign producer or importer of renewable fuel assigns RINs to a batch of renewable fuel pursuant to § 80.1426(e), all the following information must be submitted to EPA via the submitting party's EMTS account within five (5) business days of the date of RIN assignment.

(1) The name of the renewable fuel producer or importer.

(2) The EPA company registration number of the renewable fuel or foreign ethanol producer, as applicable.

* * * * *

(4) The EPA facility registration number of the renewable fuel or foreign ethanol producer, as applicable.

(5) The importer's EPA facility registration number if applicable.

(6) The D code of RINs generated for the batch.

* * * * *

(9) The fuel type of the batch.

* * * * *

(13) The type and quantity of feedstock(s) used for the batch.

* * * * *

(15) The type and quantity of co-products produced with the batch of renewable fuel.

* * * * *

(c) Starting July 1, 2010, each time any party sells, separates, or retires RINs generated on or after July 1, 2010, all the following information must be submitted to EPA via the submitting party's EMTS account within five (5) business days of the reportable event. Starting July 1, 2010, each time any party purchases RINs generated on or after July 1, 2010, all the following information must be submitted to EPA via the submitting party's EMTS account within ten (10) business days of the reportable event. The reportable event for a RIN purchase or sale occurs on the date of transfer per § 80.1453(a)(4). The reportable event for a RIN separation or retirement occurs on the date of separation or retirement as described in § 80.1429.

* * * * *

(4) The RIN status (Assigned or Separated).

(5) The D code of the RINs.

* * * * *

(7) The date of transfer per § 80.1453(a)(4), if applicable.

* * * * *

8. Section 80.1454 is amended by revising paragraph (b)(3)(xi) and adding a new paragraph (b)(3)(xii).

§ 80.1454

What are the recordkeeping requirements under the RFS program?

* * * * *

(b) * * *

(3) * * *

(xi) For RINs generated for ethanol produced from corn starch at a facility using a pathway in Table 1 to § 80.1426 that requires the use of one or more of the advanced technologies listed in Table 2 to § 80.1426, documentation to demonstrate that employment of the required advanced technology or technologies was conducted in accordance with the specifications in Tables 1 and 2 to § 80.1426, including any requirement for application to 90% of the production on a calendar year basis.

(xii) All commercial documents and additional information related to details of RIN generation.

* * * * *

9. Section 80.1464 is amended by revising paragraph (b)(1)(iii) to read as follows:

§ 80.1464

What are the attest engagement requirements under the RFS program?

* * * * *

(b) * * *

(1) * * *

(iii) Verify that the proper number of RINs were generated and assigned pursuant to the requirements of § 80.1426 for each batch of renewable fuel produced or imported. For RINs generated for ethanol produced from corn starch at a facility using a pathway in Table 1 to § 80.1426 that requires the use of one or more of the advanced technologies listed in Table 2 to § 80.1426, verify that the required advanced technology or technologies were employed in accordance with the specifications in Tables 1 and 2 to § 80.1426, including any requirement for application to 90% of the production on a calendar year basis.

* * * * *

Footnotes

1.  Pursuant to § 80.1403(a)(3)(i) in the RFS2 regulations issued March 26, 2010, “actual peak capacity” is based on the last five calendar years prior to 2008 for facilities qualifying under § 80.1403(c) unless no such capacity exists, in which case it is based on any calendar year after startup during the first three years of operation. For facilities qualifying pursuant to § 80.1403(d), “actual peak capacity” is based on any calendar year after start-up during the first three years of operation, as specified in § 80.1403(a)(3)(ii).

2.  We note that while some air permits may not contain restrictions on plant capacity, most contain restrictions on emission rates, fuel consumption, throughputs, and sizes of vessels. Thus, there are some limitations on capacity that are related to restrictions on these parameters in the air permit.

3.  Table 1.1.1 from “Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis” (EPA-420-R-10-006); February 2010.

4.  A base plant is one representing average energy usage and no advanced technologies. See the Regulatory Impact Analysis for the RFS2 final rule, EPA-420-R-10-006, February 2010, Section 1.5.1.3.

5.  75 FR 59622, September 28, 2010.