Interagency working comments on draft language under EO 12866 review. Subject to further 

policy review. EO12866_RFS Amendments 2060-AR21 NPRM FRN_ 20130130.docx

*** E.O. 12866 Review – Revised Version – Do Not Cite, Quote, or Release During Review***

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2012-0401; FRL – 9716-3]

RIN 2060--AR21

Regulation of Fuels and Fuel Additives: Modifications to Renewable Fuel Standard

Program, E15 Misfueling Mitigation Regulations, and Ultra Low Sulfur Diesel 

Requirements

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice of Proposed Rulemaking

SUMMARY: In this Notice of Proposed Rulemaking, EPA is proposing amendments to 

three separate sets of regulations relating to fuels. First, EPA is proposing to amend certain 

of the renewable fuels standard (RFS2) program regulations at 40 CFR Part 80, Subpart M. We 

believe these proposals will facilitate the introduction of new renewable fuels as well as improve 

implementation of the program. This proposal includes various changes related to biogas, 

including changes related to the revised compressed natural gas (CNG)/liquefied natural gas 

(LNG) pathway and amendments to various associated registration, recordkeeping, and reporting 

provisions. This proposed regulation includes a lifecycle greenhouse gas emissions analysis for 

renewable electricity, renewable diesel and naphtha produced from landfill biogas. Adding these 

new pathways will enhance the ability of the biofuels industry to supply advanced biofuels, 

including cellulosic biofuels, which greatly reduce the greenhouse gas emissions (GHG) 

compared to the petroleum-based fuels they replace. It also addresses “nameplate capacity” 

issues for certain production facilities that do not claim exemption from the 20% greenhouse gas 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review*** 

2

(GHG) reduction threshold. In this notice, EPA addresses issues related to crop residue and corn 

kernel fiber and proposes an approach to determining the volume of cellulosic RINs produced 

from various cellulosic feedstocks. We also include a lifecycle analysis of advanced butanol and 

discuss the potential to allow for commingling of compliant products at the retail facility level as 

long as the environmental performance of the fuels would not be detrimental. Several other 

amendments to the RFS2 program are included.

Second, EPA is also proposing various changes to the E15 misfueling mitigation 

regulations (E15 MMR) at 40 CFR Part 80, Subpart N. Among the E15 changes proposed are 

technical corrections and amendments to sections dealing with labeling, E15 surveys, product 

transfer documents, and prohibited acts. We also propose to amend the definitions in order to 

address a concern about the rounding of test results for ethanol content violations. 

 

Lastly, EPA is proposing changes to the survey requirements associated with the ultralow sulfur diesel (ULSD) program.

DATES: Comments must be received on or before [insert a date 60 days after publication in 

the Federal Register]. We do not expect to hold a public hearing. However, if we receive a 

request for a public hearing by [insert a date 45 days after publication in the Federal Register] 

we will publish information related to the timing and location of the hearing and the timing of a 

new deadline for public comments.
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3

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2012-

0401, by one of the following methods:

 http://www.regulations.gov. Follow the on-line instructions for submitting comments.

 Email: a-and-r-docket@epa.gov, Attention Air and Radiation Docket ID No. EPA-HQOAR-2012-0401. 

 Mail: Air and Radiation Docket, Docket No. EPA-HQ-OAR-2012-0401, 

Environmental Protection Agency, Mail code: 6406J, 1200 Pennsylvania Ave., N.W., 

Washington, DC 20460. Please include a total of two (2) copies.

 Hand Delivery: EPA Docket Center, EPA/DC, EPA West, Room 3334, 1301 

Constitution Ave., NW, Washington, DC, 20460, Attention Air and Radiation Docket, ID 

No. EPA-HQ-OAR-2012-0401. Such deliveries are only accepted during the Docket’s 

normal hours of operation, and special arrangements should be made for deliveries of 

boxed information.

Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-2012-0401. EPA's policy

is that all comments received will be included in the public docket without change and may be 

made available online at www.regulations.gov, including any personal information provided, 

unless the comment includes information claimed to be Confidential Business Information (CBI) 

or other information whose disclosure is restricted by statute. Do not submit information that you 

consider to be CBI or otherwise protected through www.regulations.gov or e-mail. The 

www.regulations.gov website is an “anonymous access” system, which means EPA will not 

know your identity or contact information unless you provide it in the body of your comment. If 

you send an e-mail comment directly to EPA without going through www.regulations.gov, your 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review*** 

4

e-mail address will be automatically captured and included as part of the comment that is placed 

in the public docket and made available on the Internet. If you submit an electronic comment, 

EPA recommends that you include your name and other contact information in the body of your 

comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to 

technical difficulties and cannot contact you for clarification, EPA may not be able to consider 

your comment. Electronic files should avoid the use of special characters, any form of 

encryption, and be free of any defects or viruses. For additional information about EPA’s public 

docket visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm. 

Docket: All documents in the docket are listed in the www.regulations.gov index. Although 

listed in the index, some information is not publicly available, e.g., CBI or other information for 

which disclosure is restricted by statute. Certain other material, such as copyrighted material, 

will be publicly available only in hard copy. Publicly available docket materials are available 

either electronically in www.regulations.gov or in hard copy at the Air and Radiation Docket, 

EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW, Washington, DC. The Public 

Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal 

holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the 

telephone number for the Air and Radiation Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Joseph Sopata, Chemist, Office of 

Transportation and Air Quality, Mail Code: 6406J, U.S. Environmental Protection Agency, 1200 

Pennsylvania Avenue, NW, 20460; telephone number: (202) 343-9034; fax number: (202) 343-

2801; email address: sopata.joe@epa.gov. 
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5

SUPPLEMENTARY INFORMATION:

This preamble follows the following outline: 

I. Why is EPA Taking This Action?

II. Does this Action Apply to Me?

III. What Should I Consider as I Prepare My Comments for EPA?

IV. Executive Summary

V. Renewable Fuel Standard (RFS2) Program Amendments

A. Approving Cellulosic Volumes from Cellulosic Feedstocks

1. Variability in Cellulosic Content Estimates of Feedstocks 

2. Characteristics of the Amount of the Final Fuel Derived from 

Cellulosic Materials

3. Previous Precedents

4. Alternative Approaches

B. Lifecycle Greenhouse Gas Emissions Analysis for Renewable Electricity, Renewable 

Diesel and Naphtha Produced from Landfill Biogas

1. Feedstock Production

2. Determination of the Cellulosic Composition of Landfill Biogas

3. Fuel Production – General Considerations

4. Fuel Production for Renewable Electricity

5. Fuel Production, Transport and Tailpipe Emissions for Renewable 

Diesel and Naphtha

C. Proposed Regulatory Amendments related to Biogas

1. Changes Applicable to the Revised CNG/LNG pathway from 

Biogas

2. New Registration (Contract Requirements) for Renewable 

Electricity and Fuels Produced from Biogas that Qualify as 

Renewable Fuel and that is Registered for RIN Generation

3. Changes Applicable to all Biogas Related Pathways for RIN 

Generation

4. Changes Applicable to Process Electricity Production Requirement 

for the Biogas-Derived Cellulosic Diesel and Naphtha Pathways 

D. Amendment to the Definition of “Crop Residue” and Definition of a Pathway for Corn 

Kernel Fiber 

E. Lifecycle Analysis of Advanced Butanol Pathway

1. Proposed New Pathway

2. Butanol, Biobutanol, and Volatility Considerations

3. Background and History of Volatility Regulations

4. What Modification is EPA consideration to the Application of the RVP 

Standards to Certain Fuel Blends?

F. Amendments to Various Compliance Related Provisions
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6

1. Proposed Changes to Definitions

2. Provisions for Small Blenders of Renewable Fuels

3. Proposed Changes to Section 80.1450 – Registration Requirements

4. Proposed Changes to Section 80.1452 – EPA Moderated Transaction System 

(EMTS) Requirements – Alternative Reporting Method for Sell and Buy 

Transactions for Assigned RINs

5. Proposed Changes to Section 80.1463 –Confirm that Each Day an Invalid RIN 

Remains in the Market is a Separate Day of Violation

6. Proposed Changes to Section 80.1466 – Require Importers and Foreign 

Renewable Fuel Producers that Sell to Importers to be Subject to U.S. 

Jurisdiction and Post a Bond

7. Proposed Changes to Section 80.1466(h) – Calculation of Bond Amount for 

Foreign Renewable Fuel Producers

8. Potential Changes Related to “Renewable Process Electricity” under 

Various Sections

9. Proposed Changes to Facility’s Baseline Volume to allow “Nameplate 

Capacity” for Facilities not Claiming Exemption from the 20% GHG 

Reduction Threshold

G. Minor Corrections 

VI. Amendments to the E15 Misfueling Mitigation Rule 

A. Proposed Changes to Section 80.1501 – Label

B. Proposed Changes to Section 80.1502 – E15 Survey

C. Proposed Changes to Section 80.1503 – Product Transfer Documents 

D. Proposed Changes to Section 80.1504 - Prohibited Acts

E. Proposed Changes to Section 80.1500 -- Definitions

VII. Proposed Amendments to the ULSD Diesel Survey

VIII. Statutory and Executive Order Reviews
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7

I. Why is EPA Taking This Action?

EPA is taking this action to amend various provisions in its regulations pertaining to fuels 

and fuel additives. First, EPA is proposing to amend 40 CFR Part 80, Subpart M related to the 

renewable fuels standard (RFS). The RFS2 program was required by the Energy Independence 

and Security Act of 2007 (EISA 2007), which amended the Clean Air Act (CAA). The final 

regulations for RFS2 were published in the Federal Register on March 26, 2010 (75 FR 14670). 

In this notice, references to the “RFS2 final rule” refer to the March 26, 2010 Federal Register

notice unless otherwise noted. Second, EPA is proposing to amend provisions of 40 CFR Part 

80, Subpart N, related to misfueling mitigation for 15 volume percent (%) ethanol blends (E15). 

The final regulations for E15 were published in the Federal Register on July 25, 2011 (76 FR 

44422). Several items in this proposed action will assist regulated parties in complying with 

RFS2 and E15 requirements. This action is not expected to result in significant changes in 

regulatory burdens or costs associated with the RFS2 and E15 programs. Third, EPA is 

proposing a change to the ultra low sulfur diesel (ULSD) program of 40 CFR Part 80, Subpart I. 

Specifically, EPA is proposing an amendment to the survey provisions that would likely result in 

decreasing the number of samples that must be taken, and as such would be expected to result in 

a decrease in regulatory burdens or costs. 

 

II. Does This Action Apply to Me?

Entities potentially affected by this action include those involved with the production, 

distribution and sale of transportation fuels, including gasoline and diesel fuel, or renewable 
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8

fuels such as ethanol and biodiesel. Regulated categories and entities affected by this action 

include:

Category NAICS CodesaSIC Codesb Examples of Potentially 

Regulated Parties

Industry

Industry

Industry

Industry

Industry

Industry

Industry

324110

325193

325199

424690

424710

424720

454319

2911

2869

2869

5169

5171

5172

5989

Petroleum refiners, importers.

Ethyl alcohol manufacturers.

Other basic organic chemical 

manufacturers.

Chemical and allied products 

merchant wholesalers.

Petroleum bulk stations and 

terminals.

Petroleum and petroleum 

products merchant wholesalers.

Other fuel dealers.

aNorth American Industry Classification System (NAICS).

b

Standard Industrial Classification (SIC) system code.

This table is not intended to be exhaustive, but rather provides a guide for readers 

regarding entities likely to be regulated by this action. This table lists the types of entities that 

EPA is now aware could be potentially regulated by this action. Other types of entities not listed 

in the table could also be regulated. To determine whether your entity is regulated by this action, 

you should carefully examine the applicability criteria of Part 80, subparts I, M and N of Title 40 

of the Code of Federal Regulations. If you have any question regarding applicability of this 

action to a particular entity, consult the person in the preceding “FOR FURTHER 

INFORMATION CONTACT” section above.

III. What Should I Consider as I Prepare My Comments for EPA?

A. Submitting CBI. Do not submit this information to EPA through 

www.regulations.gov or e-mail. Clearly mark the part or all of the information that you claim to 

be CBI. For CBI information in a disk or CD ROM that you mail to EPA, mark the outside of 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review*** 

9

the disk or CD ROM as CBI and then identify electronically within the disk or CD ROM the 

specific information that is claimed as CBI. In addition to one complete version of the comment 

that includes information claimed as CBI, a copy of the comment that does not contain the 

information claimed as CBI must be submitted for inclusion in the public docket. Information so 

marked will not be disclosed except in accordance with procedures set forth in 40 CFR Part 2. 

B. Tips for Preparing Your Comments. When submitting comments, remember to:

• Identify the rulemaking by docket number and other identifying information 

(subject heading, Federal Register date and page number).

• Follow directions - The agency may ask you to respond to specific questions or 

organize comments by referencing a Code of Federal Regulations (CFR) part or 

section number.

• Explain why you agree or disagree; suggest alternatives and substitute language 

for your requested changes.

• Describe any assumptions and provide any technical information and/or data that 

you used.

• If you estimate potential costs or burdens, explain how you arrived at your 

estimate in sufficient detail to allow for it to be reproduced.

• Provide specific examples to illustrate your concerns, and suggest alternatives.

• Explain your views as clearly as possible, avoiding the use of profanity or 

personal threats.

• Make sure to submit your comments by the comment period deadline identified.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review*** 

10

C. Docket Copying Costs. You may be charged a reasonable fee for photocopying 

docket materials, as provided in 40 CFR Part 2. 

IV. Executive Summary

 EPA is proposing amendments to three sets of regulations. First, EPA is proposing to 

amend certain of the renewable fuels standard (RFS2) program regulations at 40 CFR Part 80, 

Subpart M. Section V of this preamble includes several proposed amendments to the renewable 

fuel standard (RFS2) regulations of 40 CFR Part 80. The final regulations for RFS2 were 

published in the Federal Register on March 25, 2010 (75 FR 14670). EPA has issued technical 

corrections in the past. We have identified several additional changes. Some of the proposed 

changes in this notice are of a substantive nature; others are more in the nature of technical 

corrections, including corrections of obvious omissions and errors in citation. Among the more 

substantive modifications are various proposed changes related to biogas, including changes 

related to the revised compressed natural gas (CNG)/liquefied natural gas (LNG) pathway and 

amendments to various associated registration, recordkeeping, and reporting provisions. These 

fuels have the potential to add notable volumes of advanced biofuel including cellulosic biofuel 

to the existing renewable fuel volumes already being produced. Many of these changes are being 

proposed in order to facilitate the introduction of new renewable fuels under the RFS2 program

and have come at the suggestion of industry stakeholders. 

This preamble includes a lifecycle greenhouse gas emissions analysis (LCA) for 

renewable electricity, renewable diesel and naphtha produced from landfill biogas. It includes a 
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11

proposal to address “nameplate capacity” issues for certain production facilities that do not claim 

exemption from the 20% greenhouse gas (GHG) reduction threshold. EPA proposes to address 

issues related to crop residue and corn kernel fiber. We propose an approach for approving the 

cellulosic volumes from cellulosic feedstocks. We include a lifecycle analysis of advanced 

butanol and discuss the potential to allow for commingling of compliant products at the retail 

facility level as long as the environmental performance of the fuels would not be detrimental 

when compared to existing practices. We specifically discuss this consideration for 

commingling in regards to the volatility associated with butanol gasoline and ethanol gasoline 

blends.

We state when and how EPA may cancel a company registration. Of a more minor scope, 

this preamble includes proposed amendments that would define terminology used for registration 

and reporting purposes and propose changes to registration and reporting requirements. This 

preamble also discusses some minor corrections, including adding language to registration, 

recordkeeping and reporting sections requiring English language translation of documents. We 

have also proposed to correct obvious omissions and errors in citation in the existing RFS2 

regulation. 

Second, EPA is also proposing various changes to the E15 misfueling mitigation 

regulations (E15 MMR) at 40 CFR Part 80, Subpart N. The final E15 MRR was published in 

the Federal Register on July 25, 2011 (76 FR 44406). Among the E15 changes proposed are 

technical corrections and amendments to sections dealing with labeling, E15 surveys, product 

transfer documents, and prohibited acts. We also propose to amend the definitions in order to
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12

address a concern about the rounding of Reid Vapor Pressure (RVP) test results, in response to a 

question raised by some industry stakeholders. 

Third, in response to questions received from regulated parties, we propose to amend the 

ultra low sulfur diesel (ULSD) survey provisions in a manner that will likely reduce the number 

of samples required. This may mean a reduction in costs and burdens associated with 

compliance for regulated parties, with no expected degradation in the highly successful 

environmental performance of the program.

V. Renewable Fuel Standard (RFS2) Program Amendments

The RFS2 program was required by the Energy Independence and Security Act of 2007 

(EISA 2007), which amended the Clean Air Act (CAA). The final regulations for RFS2 were 

published in the Federal Register on March 26, 2010 (75 FR 14670). The rule took effect on 

July 1, 2010. In this notice, we are proposing several new renewable fuel pathway options for 

advanced biofuels including new cellulosic biofuel pathways. This proposed regulation would 

also provide modifications and technical amendments to the existing RFS2 program. 

A. Approving Cellulosic Volumes from Cellulosic Feedstock

For purposes of the RFS program, cellulosic biofuel is defined as “renewable fuel derived 

from any cellulose, hemicellulose, or lignin that is derived from renewable biomass and that has 

lifecycle greenhouse gas emissions, as determined by the Administrator, that are at least 60 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review*** 

13

percent less than the baseline lifecycle greenhouse gas emissions.” This definition was added in 

Section 211(o)(1)(E) of the Energy Independence and Security Act (EISA) of 2007, where 

Congress specified four different categories of renewable fuel and their associated volume 

requirements. The threshold for reduction in greenhouse gases is set at a higher percentage for 

cellulosic biofuel than the reduction for the other categories of renewable fuels. While the 

volume requirements for cellulosic biofuel start at a relatively low volume, Congress specified 

large volume increases over time such that the main growth in the use of renewable fuels comes 

from cellulosic biofuels. This reflects a strong Congressional intention to promote the use of 

cellulosic biofuel and achieve the associated greenhouse gas emissions reductions. 

Since the inception of the RFS program, EPA has qualified several fuel pathways that are 

able to generate cellulosic biofuel RINs (D codes 3 and 7). See 40 CFR 80.1426. Each of the 

qualified cellulosic feedstocks listed in section 80.1426 contain other components such as 

starches, sugars, lipids, and proteins. To date, EPA has not provided detailed information on 

how other components should be treated. This has led to uncertainty amongst renewable fuel 

producers about what constitutes cellulosic biofuel and whether their entire volume of fuel 

produced would be eligible to generate cellulosic RINs. 

EPA is proposing to allow 100% of the volume of renewable fuel produced from the 

cellulosic feedstock sources found in Table 1 of section 80.1426 to generate D-3 or D-7 RINs 

(depending on the type of finished fuel). However separated food waste, separated yard waste, 

and separated MSW would continue to be treated as before, as discussed below. There are three 

major justifications for this determination: 1) there can be significant variation in the amount of 
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14

cellulosic content in any feedstock, which varies within a growing season, across samples, and 

across sites. Attempting to account for this variability would impose a significant administrative 

burden on producers and EPA; 2) The amount of the final fuel that is derived from the cellulosic 

portion of the feedstock is likely to be very high, particularly for fuels produced using a 

biochemical reaction; and, 3) EPA has already made previous determinations in which a single 

RIN value was assigned to the fuel produced since it came primarily from one source even 

though it was also produced from incidental amounts of other sources. 

This determination is based on the view that the statutory requirement does not mandate 

that in all cases the renewable fuel must be produced solely from the cellulosic material in the 

renewable biomass. EPA considers the statutory definition of cellulosic biofuel to be flexible on 

this point. Given these factors cited above, the Agency believes this interpretation of “derived 

from” is consistent with the Congressional intent to encourage the development of cellulosic 

biofuels in EISA while ensuring that the program can be implemented in a reasonable way. 

Details on the variability in feedstocks, characteristics of the final fuel, previous precedents, and 

alternative proposals are included in the following sections. 

1. Variability in Cellulosic Content Estimates of Feedstocks 

The cellulosic components of feedstock consist of the major structural components; 

cellulose; hemicellulose; and lignin. EPA has reviewed research characterizing the different 

components of feedstocks, mainly focused on how the materials could be broken down and 

converted into fuel. There has been work also in defining standardized procedures and test 
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15

methods for analyzing the different components of biomass1; however, the studies considered all 

employ slightly different methods. For the purposes of this rule, EPA considered the amount of 

the feedstocks that is composed of cellulosic components i.e., how much comes from the 

cellulose, hemicellulose or lignin, as opposed to any other components of the feedstock. There is 

significant variation in the data reported on feedstock component compositions. The variation is 

due to a number of causes, such as measurement methods2,3, variety within a generic feedstock 

type, and storage time4. 

Although there are many factors that contribute to the large variability in assessments of 

cellulosic content, all studies confirm that the feedstocks in Table 1 of section 80.1426 have an 

adjusted cellulosic content of at least 70%, with an average content of around 85% cellulosic.

5

 A 

memorandum to the docket provides more information on cellulosic terminology, percent 

composition of various feedstocks, and the variability of different feedstock components.6 From 

 

1 See for example the Standard Biomass Analytical Procedures developed by the National 

Renewable Energy Laboratory, http://www.nrel.gov/biomass/analytical_procedures.html. 

2 Compositional Analysis of Lignocellulosic Feedstocks. 2. Method Uncertainties, David W. 

Templeton, Christopher J. Scarlata, Justin B. Sluiter, And Edward J. Wolfrum, J. Agric. Food 

Chem. 2010, 58, 9054–9062

3 Relative standard deviations (RSD) of 5-8%% are reported for cellulose, hemicelluloses and 

lignin with the other minor components showing 16-22% RSD. 

4 Composition of Herbaceous Biomass Feedstocks, DoKyoung Lee, Vance N. Owens, Arvid 

Boe, Peter Jeranyama, Plant Science Department, South Dakota State University, SGINC1-07, 

June 2007

5

EPA only considered the organic components of the materials when determining cellulosic 

content. Inorganic materials are not likely to end up in the final fuel product and would not 

contribute to the fuel heating content in the event that they remained in the final fuel. This 

methodology is consistent with how RINs are determined. In this section, EPA refers to this as 

“adjusted cellulosic”. Adjusted cellulosic content does not consider other material that is not 

converted into biofuel such as minerals or other components that would show up as part of the 

ash remaining after a thermo-chemical conversion process.

6

See Memorandum to Docket, ‘‘Cellulosic Content of Various Feedstocks,’’ Docket EPA–HQ–

OAR–2012-0401.
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16

this data, EPA concludes that each of the qualified feedstocks listed in section 80.1426 are 

comprised predominantly of cellulose, hemicellulose and lignin. 

2. Characteristics of the Amount of the Final Fuel Produced from Cellulosic Materials

Process technology plays a key role in how much of the final fuel product is actually

produced from cellulose, hemicellulose, or lignin. There are two basic processes for converting 

cellulosic feedstocks into fuel: thermo-chemical and biochemical. Thermo-chemical processes 

mainly consist of pyrolysis – in which cellulosic biomass is decomposed with temperature to biooils and could be further processed to produce a finished fuel – and gasification – in which 

cellulosic biomass is decomposed to synthesis gas (“syngas”) with further catalytic processing to 

produce a finished fuel product. The biochemical process requires the release of sugars from 

biomass and the use of microorganisms to convert sugars into fuels. Thermo-chemical processes 

can accept a more heterogeneous mix of feedstock and typically convert all of the organic 

components of the feedstock into finished fuel. The biochemical process generally accepts a 

more homogeneous mix of feedstocks and typically converts only the cellulosic and 

hemicellulosic components of the feedstock into the final fuel product. Therefore, regardless of 

the feedstock used, the final fuel produced from the biochemical process will typically only 

come from the cellulosic or hemicellulosic portions of feedstock, while the final fuel produced 

from the thermo-chemical process could come from cellulosic and non-cellulosic components. 

For thermo-chemical production in which the non-cellulosic components of the feedstock 

can contribute to the volume of fuel produced in addition to the cellulosic components, the 
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17

percent of fuel produced from the non-cellulosic portion can vary due to such factors as 

feedstock type and the time and location of feedstock harvest. Regardless, we believe that the 

majority of the fuel produced will be from the cellulosic components. As a practical matter, 

there is no simple test that can be used to measure the amount of fuel end product that originated 

from cellulosic materials. For fuel produced via the biochemical process, 100% of the fuel 

produced is directly the result of conversion of the cellulosic content. 

In selecting a cellulosic process, whether based on biochemical or thermo-chemical 

design, the fuel producer is clearly demonstrating that its primary intent is to convert the 

cellulosic portions of the feedstock. Cellulosic fuel producers invest in expensive process 

technologies with the intent of converting the cellulosic components of a feedstock into fuel; 

conversion of the non-cellulosic components can be achieved much more easily with less of a 

capital investment. Furthermore, since the fuel produced will be primarily the result of the direct 

conversion of cellulosic content of the feedstock and considering the relatively small range of 

non-cellulosic portion of feedstock that could contribute to the volume of fuel produced, EPA 

believes it is reasonable to consider all the fuel produced when relying on cellulosic conversion 

processes to be cellulosic biofuel. 

3. Previous Precedents

EPA has already considered instances where one RIN value was assigned to the fuel 

produced since it came primarily from one source even though it was also produced from some 

amount of other chemical compounds. In the RFS2 rulemaking, EPA specified several fuel 
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18

pathways that would qualify for generation of cellulosic RINs. EPA also made several decisions 

concerning how the fuel produced from certain pathways should be categorized as cellulosic. 

EPA discussed two different situations for fuel produced from separated yard waste and food 

waste as the renewable biomass feedstock. The first involved food waste or yard waste that was 

kept separate, from generation, from municipal solid waste (MSW). EPA determined that both of 

these feedstocks could be considered renewable biomass. With respect to separated yard waste, 

EPA determined that the yard waste was expected to be composed almost entirely of woody

material or leaves, and this would be deemed to be cellulosic material and would generate 

cellulosic biofuel RINs. Separated food waste, however, was likely to be composed of both 

cellulosic and non-cellulosic materials, and in certain cases would likely be composed primarily 

of non-cellulosic materials, such as sugars and starches from the food. EPA determined that 

separated food waste would be deemed to be non-cellulosic material, and would generate 

advanced biofuel RINs and not cellulosic RINs, unless the renewable fuel producer demonstrated 

the part of the food waste that was cellulosic. This portion would then generate cellulosic RINs. 

75 FR 14670, 14706 (March 26, 2010).

The second situation EPA previously addressed involved separated MSW. EPA 

determined that separated MSW that met certain regulatory requirements would qualify as a 

renewable biomass for purposes of producing renewable fuel. EPA recognized that the biogenic 

portion of this feedstock would be composed of a “variety of materials, including yard waste 

(largely cellulosic) and food waste (largely starches and sugar), as well as incidental materials 

remaining after reasonably practicable separation efforts such as plastic and rubber of fossil 

origin.” Testing could identify the portion of the fuel produced from biogenic materials, and 
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19

these biogenic materials “will likely be largely derived from cellulosic materials (yard waste, 

textiles, paper, and construction materials), and to a much smaller extent starch-based materials 

(food wastes).” However, EPA was not aware of a test method to distinguish between renewable 

fuel produced from the cellulose and fuel produced from the starch and under those 

circumstances determined that it was appropriate to base the assignment of RINs on the 

“predominant” component of the biogenic material. EPA thus determined that all of the fuel 

generated from the biogenic portion of separated MSW would be considered cellulosic biofuel. 

75 FR at 14706.

Thus, EPA has interpreted the definition of cellulosic biofuel as including in some cases a 

renewable fuel that is produced from both the cellulosic and incremental amounts of noncellulosic components of the feedstock. EPA has treated the resulting fuel as all derived from 

cellulosic material where the feedstock is composed almost entirely of woody materials and 

leaves, or where the predominant component of the feedstock is likely cellulosic. The fuel will 

be largely derived from this cellulosic material and to a much smaller extent from non-cellulosic 

materials. There currently is no ready test to identify the portion of fuel produced from noncellulosic materials. EPA has not considered the fuel as cellulosic in cases where the feedstock 

was likely to be largely non-cellulosic materials. In all of these cases, EPA has recognized that 

the fuel would be produced from both the cellulosic and non-cellulosic materials in the 

feedstock, and has determined in some cases to consider the fuel entirely cellulosic biofuel based 

on the relative amounts of the cellulosic and non-cellulosic materials and, for fuel made from the 

biogenic portion of separated MSW, on the lack of availability of a test procedure to differentiate 

how much of the fuel came from the cellulosic materials. 
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20

These determinations have been based on the view that the statutory requirement that 

cellulosic biofuel be “derived from cellulose, hemicellulose, or lignin” does not mandate that in 

all cases the renewable fuel must be produced solely from the cellulosic material in the 

renewable biomass. EPA considers the statutory definition of cellulosic biofuel to be ambiguous 

on this point, providing EPA the discretion to reasonably determine under what circumstances a 

fuel appropriately could be considered cellulosic biofuel when the fuel is produced from a 

feedstock that is a mixture of cellulosic and non-cellulosic materials. To date, EPA has specified 

certain circumstances where the entire fuel will be considered cellulosic biofuel. EPA has taken 

this action in cases where the cellulosic material is almost entirely woody materials or leaves, or 

the fuel is produced from materials that are predominantly composed of cellulosic materials and 

to a much smaller extent non-cellulosic materials, with no current test to identify the differing 

portions. There have been two elements present in these decisions. One involves a 

determination that the feedstock is composed almost entirely or largely of cellulosic materials. 

EPA has also considered whether or not there is a test method to identify the actual portion of the 

fuel produced from cellulosic materials. In this rulemaking EPA is proposing an approach that is 

consistent with and an outgrowth of the approach taken in the RFS2 rulemaking. EPA is 

proposing to approve certain fuels as cellulosic biofuel where the cellulosic components account 

for a predominant percentage of the biogenic material in the renewable biomass feedstock used 

to produce the fuel, even where the non-cellulosic components of the renewable biomass could 

be reasonably identified or estimated.

7

 

7

 By predominant, EPA means the very high percentages for adjusted cellulosic content 

discussed in section V. A.1. above for the feedstocks at issue in this proposal.
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21

In order to promote the growth of cellulosic biofuel that Congress intended and to 

simplify compliance with and implementation of the RFS requirements, EPA is proposing to 

classify all of the biofuel as cellulosic in the fuel pathways proposed today, where the cellulosic 

material makes up a predominant percentage of the organic material from which the fuel is 

produced. This will promote the growth in volume of cellulosic biofuels intended by Congress. 

It will avoid the administrative burden on producers and EPA of trying to determine the specific 

amounts of cellulosic and non-cellulosic materials in the specified high-cellulosic feedstock 

sources, removing a potential impediment to expansion of cellulosic biofuel production. The 

growth in cellulosic biofuel volumes promoted by today’s proposal is expected to result in 

greater reductions in GHGs, as the cellulosic biofuel will have to achieve the minimum 60% 

reduction in GHG emissions specified in the Act. EPA’s application of this approach to the fuel 

pathways and feedstocks discussed in this proposal ensures that the cellulosic materials are the 

predominant portion of the biogenic materials used to produce cellulosic biofuel. This approach 

avoids administrative burdens and promotes the volume and greenhouse gas objectives of 

Congress. EPA proposes that this is a reasonable interpretation of the definition of cellulosic 

biofuels, and invites comment on this approach.8

EPA is proposing that biofuel made from the following cellulosic feedstocks will be able 

to generate applicable cellulosic RINs for 100% of the volume produced: crop residue; slash; 

pre-commercial thinnings and tree residue; annual cover crops; switchgrass; and miscanthus. 

EPA’s prior treatment of separated yard waste, separated food waste, and separated MSW is 

 

8

 See Bot v. IRS, 353 F.3d 595 (8th Cir. 2003), Wuebker v. IRS, 205 F.2d 897 (6th Cir. 2000), 

Milligan v. IRS, 38 F.3d 1094 (9th Cir. 1994). Also see Hecla Mining Company v. US, 909 F.2d 

1371 (10th Cir. 1990) (DOE’s interpretation of the term “derived from” in the Uranium Mill 

Tailings Radiation Control Act of 1978 accepted as a reasonable interpretation under Chevron)

.
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22

discussed above and is not being changed. On January 5, 2012, EPA proposed to qualify

napiergrass, giant reed, and energy cane as new feedstocks that would be eligible to generate 

cellulosic RINs. If those pathways are approved before this rule is final, EPA is proposing to 

apply the approach discussed above to these feedstocks as well.9 To the extent that additional 

cellulosic pathways are approved in the future, we would expect to apply this same methodology

to those feedstocks as well, but will evaluate them on a case-by-case basis. 

4. Alternative Approaches

EPA also seeks comment on two alternative approaches:

Cellulosic Content Threshold Approach

An alternative approach for handling the variability in cellulosic content would be for 

EPA to set a minimum threshold of cellulosic content in the feedstock. Fuels produced from 

feedstocks with a cellulosic content above this minimum threshold would be eligible to generate 

cellulosic RINs for 100% of their volume. Thresholds under consideration would range from 

70% to 99.9%. A higher percentage would place more emphasis on the feedstock content having 

a higher actual cellulosic component, whereas the lower percentages would place more emphasis 

on promoting the volume of fuels that could be categorized as cellulosic biofuel. EPA invites 

comment on this approach, and also invites comment on the most appropriate value to use as the 

 

9

 In addition, in section B of this proposal, EPA is also proposing to include corn fiber, 

CNG, LNG, electricity, and renewable diesel and naphtha from landfill biogas as cellulosic 

pathways for the reasons discussed therein. 
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23

threshold. Furthermore, EPA invites comment on whether individual producers should be 

responsible for submitting data that their feedstock meets this threshold, or whether EPA should 

determine whether feedstocks meet this threshold based on existing published data. 

Since biochemical processes generally only convert the cellulosic, hemicellulosic, or 

lignin components of the feedstock to fuel, EPA believes under this alternative approach, it may

still be appropriate to allow fuel producers using biochemical processes to generate RINs for 

100% of the fuel produced from cellulosic feedstocks.

Specified Percentage Approach 

As noted above, examining the range of feedstock data compiled by EPA, it appears that 

85% would be a reasonable approximation for the average adjusted cellulosic content across a 

range of assessments of feedstock types that are qualified to produce cellulosic fuel. Under this 

approach, fuels produced from the cellulosic feedstocks discussed above would be eligible to 

generate cellulosic RINs for 85% of their volume, and the remaining 15% would be eligible to 

generate advanced RINs. The specified percentage approach would reduce administrative 

burden but also incentivize renewable fuel production. For this approach, EPA would effectively

be treating 85% of the fuel produced from all of these feedstock sources as being derived from 

cellulosic material. However, EPA would consider allowing a larger percentage of the fuel to 

qualify for cellulosic RINs if the producer could submit data that demonstrates a consistently

higher cellulosic content in their feedstock. Under this approach, producers could submit a 

written plan for approval under the registration procedures in 40 CFR 80.1416(b)(vii). The plan 
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24

would need to detail the cellulosic content of the feedstock, the method used for quantifying the 

cellulosic and non-cellulosic contents, and the production process used. 

Since biochemical processes generally only convert the cellulose, hemicellulose, or lignin 

components of the feedstock to fuel, EPA believes under this alternative approach it would be 

appropriate to allow fuel producers using biochemical processes to generate RINs for 100% of 

the fuel produced from cellulosic feedstocks.

B. Lifecycle Greenhouse Gas Emissions Analysis for Renewable Electricity, Renewable 

Diesel and Naphtha Produced from Landfill Biogas

EPA has received several facility-specific petitions under § 80.1416 to allow renewable 

electricity, renewable diesel and naphtha produced from landfill biogas to qualify as renewable 

fuels under the RFS program. Since these new pathways could be more broadly applicable, EPA 

is proposing to add these pathways to Table 1 to § 80.1426 through this rulemaking process. 

Based on questions from companies, EPA is also modifying the existing biogas pathway to 

specify that compressed natural gas (CNG) or liquefied natural gas (LNG) is the fuel and biogas 

is the feedstock. For this proposal, EPA considered both the cellulosic origin of landfill biogas 

and the lifecycle GHG impacts of three types of fuel produced from landfill-derived biogas. In 

the final RFS2 rule, EPA established biogas as a fuel type when derived from landfills, sewage 

waste treatment plants, and manure digesters. This biogas was classified as an advanced biofuel 
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25

eligible to generate D-Code 5 RINs. EPA also established cellulosic diesel and cellulosic 

naphtha as cellulosic biofuels eligible to generate D-Code 7 and 3 RINs, respectively. The 

eligible feedstocks for these biofuels include cellulosic components of separated municipal solid 

waste but did not include biogas from landfills.

Based in part on additional information received through the petition process for EPA 

approval of renewable electricity and renewable diesel and naphtha produced from landfill 

biogas, EPA has evaluated these pathways and is proposing to include renewable electricity 

produced from landfill biogas feedstock in Table 1 to § 80.1426 as a cellulosic fuel type. We are 

also proposing to add renewable diesel and naphtha produced from landfill biogas via the 

Fischer-Tropsch process as approved advanced and/or biomass-based diesel biofuels. If the 

Fischer-Tropsch facilities produce at least 20% of their electricity demand internally, we are 

proposing that the renewable diesel and naphtha produced would further qualify as cellulosic 

biofuels. We are also proposing to amend the existing biogas pathway to list CNG/LNG as the 

fuel types instead of biogas since the biogas is converted into CNG or LNG before being used as 

a transportation fuel, as discussed below. CNG/LNG produced from biogas from waste 

treatment plants and waste digesters is still classified as an advanced biofuel. However, 

CNG/LNG produced from biogas from landfills now qualifies as a cellulosic pathway.

1. Feedstock Production

When waste materials are buried in a landfill, decomposition of the organic materials 

consumes all of the oxygen present within roughly one year, leaving the bulk of the material to 
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26

undergo slower, anaerobic decomposition. This process produces large amounts of methane for 

several decades, as well as other products, with the gases released as “biogas.” Biogas from 

landfills typically contains roughly 50% methane and 50% carbon dioxide, with small or trace 

amounts of other gases. Methane is a potent greenhouse gas (GHG), with a global warming 

potential of 21 times that of carbon dioxide, and landfills are the third-largest anthropogenic 

source of methane to the atmosphere in the United States.10

The methane present in biogas is also a potential energy source that may be purified and 

compressed to be used directly in CNG or LNG vehicles, combusted to produce electricity or 

converted to renewable diesel and naphtha via the Fischer-Tropsch process. The RFS2 final 

analysis concluded that waste materials have no agricultural or land use change GHG emissions 

associated with their production. Furthermore, the feedstock for these fuels is landfill biogas, a 

waste material which already appears in Table 1 of § 80.1426(f) of the RFS2 regulations and has 

already been evaluated as part of the RFS2 final rule lifecycle GHG determinations. Therefore 

no new renewable feedstock production modeling was required, no GHG emissions were 

attributed to feedstock production for any of these renewable fuel pathways, and EPA focused 

our analysis on the new fuel production processes.

2. Determination of the Cellulosic Composition of Landfill Biogas

In order for fuels produced from landfill biogas as a feedstock to qualify to generate DCode 3 or 7 (cellulosic) RINs, the renewable fuel must be derived from cellulosic materials and 

 

10 Environmental Protection Agency. 2012. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010, 

Chapter 8: Waste. http://epa.gov/climatechange/emissions/usinventoryreport.html
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27

must meet a 60% GHG emissions reduction threshold, as described in the following sections. In 

this section, we discuss our determination that biogas derived from landfills is derived from 

cellulose, hemicellulose or lignin.

CAA 211(o) specifies “separated yard waste or food waste” as a type of renewable 

biomass, and in the final RFS2 rule, EPA stated:

As a result of the intermixing of wastes, the fact that biogas is formed only from 

the biogenic portion of landfill material, and the fact that landfill material is as a 

practical matter inaccessible for further separation, EPA believes that no further 

practical separation is possible for landfill material and biogas should be 

considered as produced from separated yard and food waste for purposes of EISA.

The RFS2 rule stated that all landfill-derived biogas was therefore eligible to generate 

RINs. 

An in-depth study of methane production from different chemical components of 

municipal solid waste found that roughly 90% of the methane generated in landfills derived was 

from cellulose and hemicellulose.11 Accordingly, EPA is proposing to classify renewable fuels 

produced from landfill biogas as derived from cellulose, hemicellulose or lignin. This 

 

11 Barlaz, M.A., R.K. Ham, and D.M. Schaefer. 1989. Mass-balance analysis of anaerobically 

decomposed refuse. Journal of Environmental Engineering, 15(6) 1088-1102.
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28

determination is discussed in more detail in a memo to the docket.12 Consistent with the 

discussion in the section above, “Approving Cellulosic Volumes from Cellulosic Feedstock”, we 

are classifying all of the biofuel volume produced from landfill biogas as cellulosic in origin. 

Therefore the entire volume of renewable fuels using landfill biogas as a feedstock will be 

eligible to generate cellulosic RINs (D-Codes 3 and 7) if the fuel also meets the required 60% 

GHG emissions reductions. EPA invites comment and data on the cellulosic component of 

biogas. 

3. Fuel Production – General Considerations

Landfills currently treat their methane in one of several ways. Municipal solid waste 

(MSW) landfills designed to collect at least 2.5 million megagrams (Mg) and 2.5 million cubic 

meters of waste and emitting at least 50 Mg of non-methane organic compounds per year are 

required by EPA regulations to capture and control their biogas.13 These large, regulated 

landfills represent a small percentage of all landfills by number but are responsible for the 

majority of biogas emissions from landfills. To comply with the regulations, these landfills must 

at a minimum combust their biogas in a flare, converting the methane to carbon dioxide, a less 

potent GHG. They may also use it to generate electricity from combustion of the methane, in 

which case, the electricity produced may displace electricity from other sources (such as gasfired power plants) once it enters the grid. If displacing other sources of electricity that on 

 

12

“Support for Cellulosic Determination for Landfill Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels Produced from Landfill Biogas”, which has been 

placed in docket EPA-HQ-2012-0401.

13 Standards of Performance for New Stationary Sources and Guidelines for Control of 

Existing Sources: Municipal Solid Waste Landfills, 61 FR 9905, 9944 (March 12, 1996).
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29

average have greater GHG emissions, landfills that generate electricity may reduce GHG

emissions and are using the “best practices” in the industry.

14

 Many smaller, unregulated 

landfills do not collect their biogas, and this methane is “vented” to the atmosphere. In 2010, 

29% of the methane generated at landfills was flared and 29% of the methane was used to 

generate electricity.

15 Accounting for the 25% average collection efficiency of biogas collection 

systems,16 we estimate that approximately 38% of the methane generated is derived from 

landfills that flare their gas and another 38% is derived from landfills with gas-to-electricity

projects. By mass balance, this suggests that 24% of the landfill methane generated is from 

landfills that vent their methane.

In our lifecycle GHG analysis of these biofuels we need to consider what would have 

happened to the landfill gas if it was not used to produce transportation fuels. This is the 

baseline for comparison to calculate the GHG impacts of the fuels in question. There are 

actually two baselines, one for each of the new pathways, landfill gas-to-electricity and landfill 

gas-to-liquids. 

For the landfill gas-to-electricity pathway we use landfills that flare their biogas as the 

baseline GHG emissions with which we compare scenarios involving production of electricity 

from the landfill biogas. We chose this baseline because these landfills are the ones most likely 

 

14 Some facilities also use the biogas directly in boilers and other applications or purify the biogas 

to create CNG or LNG or inject it directly into natural gas pipelines.

15 Environmental Protection Agency. 2012. Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990-2010, Annex 3: Methodological Descriptions for Additional Source or Sink 

Categories. http://epa.gov/climatechange/emissions/usinventoryreport.html

16 Environmental Protection Agency, Landfill Methane Outreach Program. 2010. LFG Energy

Project Development Handbook: Chapter 2. Landfill Gas Modeling.. 

http://epa.gov/lmop/publications-tools/handbook.html
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30

to convert to gas-to-energy projects, since they already have gas collections systems in place. 

They are also the ones most likely to be the alternative to gas to energy projects since these 

projects will likely go into larger landfills that are required by regulation to collect and treat the 

biogas. We expect that small, unregulated landfills would be unlikely to generate enough biogas 

to justify collecting it for conversion to renewable fuels. Furthermore, we expect that the capital 

costs for such small landfills would preclude them from making such changes. However, if such 

small landfills were to capture and use their biogas in transportation fuels, this would result in 

significantly greater reductions in GHG emissions at each landfill than assumed for landfills 

already capturing biogas because of the decrease in methane release, so that biofuels produced 

from such facilities would easily meet the required emissions reduction thresholds. Since 

landfills that currently have gas-to-energy projects in place at one point either replaced flaring 

with a gas-to-energy project or installed a gas-to-energy project as an alternative to the minimal 

compliance route of flaring, we are proposing to treat the emissions from these landfills 

compared to the same flaring baseline. We show lifecycle results calculated using alternative 

baselines and discuss our choice of baseline in more depth in a memo to the docket.17 We invite 

comment on our baseline assumptions for the electricity pathway. If commenters believe a 

different baseline is appropriate, EPA specifically invites the submission of data supporting this 

alternative baseline. 

For gas to liquids projects we assume the same baseline of flaring as the alternative to the 

transportation fuel project, for the same reasons outlined above. We further consider that 

 

17

“Support for Cellulosic Determination for Landfill Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels Produced from Landfill Biogas”, which has been 

placed in docket EPA-HQ-2012-0401.
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31

landfills that have already invested the capital to generate electricity are unlikely to stop doing so 

in order to generate liquid fuels from the biogas, which would require considerable additional 

capital investments. These facilities are therefore an unlikely baseline for the pathways 

generating renewable diesel and naphtha. However, our results do not change if we include 

these landfills in a baseline that includes the “industry average practices” for regulated landfills. 

We invite comment on our baseline assumptions for the liquids pathway and whether a different 

baseline would be more appropriate. If commenters believe a different baseline is appropriate, 

EPA specifically invites the submission of data supporting this alternative baseline. 

4. Fuel Production for Renewable Electricity

Landfills can generate electricity by combustion of the methane in their biogas. 

Generating electricity at landfills requires collection of the biogas (using wells, piping and 

blowers), purification and compression of the biogas and electricity generation. Most landfills 

use internal combustion engines to generate the electricity, but a significant proportion also use 

gas or steam turbines or combined cycle systems. Once generated, the electricity enters the 

electrical grid.

In determining the lifecycle GHG analysis of renewable electricity, we examined two 

main factors. The first involved determining by how much emissions at the landfill (from 

flaring) would change upon installation of a gas-to-energy project. For this calculation, we used 
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32

emission factors from the GREET model.

18

 The second involved calculation of the decrease in 

GHG emissions caused by powering the gas blowers already in use with biogas-derived 

electricity rather than grid electricity upon installation of a gas-to-energy project. This 

calculation used data from the EPA Landfill Methane Outreach Project (LMOP).19 For each 

factor, we needed to first calculate how much electricity could be generated and delivered to the 

consumer. We used values from LMOP8as estimates of the relative shares of different types of 

engines or turbines, the electricity generation efficiency, parasitic losses, energy use in collecting 

and preparing the biogas, and a value from the U.S. Energy Information Agency to estimate 

distribution losses. Values used are shown in Table V.B.-1, and the assumptions and 

calculations are discussed in more detail in a memo to the docket.20

Table V.B.-1. Calculation of the net amount of electricity delivered to the consumer 

produced from a given amount of landfill biogas.21 .

Value Units

Electricity generation efficiency 11700 Btu/kWh

Gross electricity production 0.292 mmBtu/mmBtu biogas

Electricity produced after parasitic losses 0.267 mmBtu/mmBtu biogas

Energy used for blowers 0.014 mmBtu/mmBtu biogas

Distribution losses 0.017 mmBtu/mmBtu biogas

Net electricity delivered to consumer 0.236 mmBtu/mmBtu biogas

 

18 Argonne National Laboratory (2011) Greenhouse Gases, Regulated Emissions, and Energy

Use in Transportation Model (GREET), Version 1 2011, http://greet.es.anl.gov/

19 EPA LMOP. LFGcost–Web–Landfill Gas Energy Cost Model User’s Manual. 

http://www.epa.gov/lmop/publications-tools/

20

“Support for Cellulosic Determination for Landfill Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels Produced from Landfill Biogas”, which has been 

placed in docket EPA-HQ-2012-0401.

21 All values are derived from information provided by the EPA Landfill Methane Outreach Program 

except the distribution loss number, which is from the U.S. Energy Information Agency. Parasitic losses 

were calculated by apportioning the gross electricity generation to different types of generators and using 

parasitic loss values for that particular type of generator.
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33

We used the value for the net electricity yield from biogas to calculate how GHG 

emissions from the landfill itself would change upon conversion from flaring to a gas-to-energy

project. We first calculated emissions per mmBtu electricity (Table V.B.-2). However, the 

drivetrains of electric vehicles are roughly three times as efficient as those of conventional 

gasoline-powered vehicles, meaning that any given EV would be able to travel about three times 

as far per Btu of input. To account for this difference, we also calculated emissions per mmBtu 

fuel equivalent. It would take roughly three times the amount of energy from liquid fuel to drive 

a conventional vehicle a given distance compared to an EV powered by electricity, so the 

emissions per mmBtu fuel equivalent are approximately one third as large as the emissions per 

mmBtu electricity. EPA invites comments on the assumptions regarding electricity equivalence. 

Table V.B.-2. Fuel GHG Emissions for the Renewable Electricity Pathway, Calculated per 

mmBtu Electricity and per mmBtu Fuel Equivalent Compared to the 2005 Gasoline 

Baseline.

GHG Emissions

Renewable Electricity

2005 

Gasoline 

Baseline

U.S. Average 

Grid 

Electricity

Lifecycle Stage

kg CO2-eq/ 

mmBtu 

electricity

kg CO2-eq/ 

mmBtu fuel 

equivalent

kg CO2-eq/ 

mmBtu fuel

kg CO2-eq/ 

mmBtu 

electricity

On-site emissions 25 8

Upstream (electricity production 

for blowers) -13 -4

Total Emissions: 12 4

98 220

% Change from Gasoline 

Baseline -87% -96%
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34

% Change from Grid Electricity -94% N/A

On-site emissions of facilities that generate electricity would be slightly higher than 

emissions from facilities that flare because reciprocating engines, which are the dominant 

technology used to generate electricity from biogas, are less efficient at destroying methane than 

flares. Facilities that originally flared their biogas are assumed to have been purchasing 

electricity from the grid to power the blowers needed to collect the biogas. Upon conversion to 

gas-to-energy projects, the facilities would now generate that electricity themselves and thus no 

longer need to purchase this electricity from the grid. The calculations above include a credit in 

GHG emissions for the avoided purchase of grid electricity (Table V.B.-2). Unlike traditional 

transportation fuels, there are no GHG emissions involved in transportation or distribution of 

renewable electricity (distribution losses are accounted for above), nor are there any tailpipe 

emissions from the direct use of the fuel. Therefore, the only emissions considered are those 

from production of the fuel, as outlined in Table V.B.-2. The total GHG emissions for 

conversion from flaring to a gas-to-energy project are 12 kg CO2-eq/mmBtu electricity, or 4 kg 

CO2-eq/mmBtu fuel equivalent. Compared with the gasoline baseline GHG emissions of 98 kg 

CO2-eq/mmBtu, these projects would be accompanied by an 87% reduction in GHG emissions 

when normalized per mmBtu electricity. Accounting for the improved efficiency of EV 

drivetrains increases the GHG emissions reductions to 96%. Renewable electricity therefore 

meets the statutory baseline of 60% reductions in GHG emissions relative to the gasoline 

baseline and qualifies as a cellulosic biofuel. EPA invites comments on the assumptions and 

calculations of GHG emissions related to renewable electricity from landfill gas. 

5. Fuel Production, Transport and Tailpipe Emissions for Renewable Diesel and Naphtha
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35

Renewable diesel and naphtha can be made from landfill biogas by a combination of 

methane reforming and the Fischer-Tropsch gas-to-liquids (GTL) process. For methane 

reforming, the biogas must first be purified and then be reformed to create synthesis gas, known 

as “syngas”, which is composed of a mixture of carbon monoxide and hydrogen gas. This 

process may occur via either steam methane reforming or autothermal reforming. The syngas is 

next purified and then sent to a Fischer-Tropsch (F-T) system in which the carbon monoxide and 

hydrogen are combined in the presence of a catalyst to form a range of hydrocarbons. This 

reaction produces relatively short-chain (naphtha), medium-length (diesel) and long-chain (wax) 

hydrocarbons. The wax can subsequently be upgraded by hydroprocessing to form naphtha and 

diesel fuels. The different products are then separated by simple distillation. Heat generated by 

the reaction can be used to preheat gases in the system and to generate electricity for use in the 

system or for export. Unconverted syngas from the F-T process and fuel gas from 

hydroprocessing can also be combusted to generate electricity. GTL plants may have 

substantially different lifecycle GHG impacts depending on whether they upgrade their waxes 

and whether they generate electricity as a side product of the reaction. Electricity generation can 

add to the capital costs of a facility but also greatly reduces the lifecycle GHG emissions of a 

plant.

In determining the lifecycle GHG impacts of GTL fuels, we considered two main factors: 

on-site emissions at the landfill and upstream emissions from electricity production to power the 

plant. Additionally, a facility that produced wax was assigned a co-product credit for the wax 

generated. We did the calculations assuming the facility did not generate any electricity and then 
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36

calculated what fraction of their electricity demands they would need to generate internally to 

meet the 60% emissions reduction threshold to qualify for cellulosic RINs.

To determine the lifecycle GHG emissions, we used confidential business information 

(CBI) data provided in a petition submitted to EPA. This process did not involve upgrading of 

wax to liquid fuels. For this scenario, we used the supplied information about inputs of biogas, 

outputs of fuel and co-product and electrical demand for the lifecycle analysis. We first 

determined how many GHG emissions would be avoided on-site at the landfill by changing from 

the baseline scenario of flaring to collecting the biogas for conversion to liquid fuels. This 

calculation was similar to that described above for renewable electricity and relied on values 

from GREET22 for the emissions factor for flaring. To calculate the emissions from electricity

production, we used the emissions factors for average U.S. electrical production used in the 

RFS2 final rule. 

To assign a co-product credit to the fuels, we assumed that the wax produced during the 

Fischer-Tropsch process would enter a market in which it would displace wax derived from 

petroleum. To determine the effects of such a displacement on GHG emissions, we used data 

from a model by the Department of Energy’s National Energy Technology Laboratory (NETL)23

for the yields and GHG emissions attributable to wax production from petroleum feedstock. 

These values only include production emissions and do not include any emissions from 

combustion of the wax in, for example, candles because we do not have information about what 

 

22 Argonne National Laboratory (2011) Greenhouse Gases, Regulated Emissions, and Energy

Use in Transportation Model (GREET), Version 1 2011, http://greet.es.anl.gov/

23 Department of Energy: National Energy Technology Laboratory. (2009) NETL: PetroleumBased Fuels Life Cycle Greenhouse Gas Analysis - 2005 Baseline Model. 

www.netl.doe.gov/energy-analyses.
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37

fraction of wax is combusted. If combustion emissions were included, the co-product credit 

would be even larger. The global wax market is growing, with demand expected to outpace 

supply in the next few years.24 As such, it is unlikely that F-T waxes would in reality displace 

petroleum-derived waxes. Instead, waxes from both sources are likely to be used in parallel to 

fulfill demand, and such waxes would replace any substitutes that might be used to fill the gap 

between supply and demand. The nature of these alternatives is presently unknown to EPA, as 

are their lifecycle GHG emissions. As an alternative to assigning a displacement credit, we 

could allocate emissions to the waxes along with the renewable diesel and naphtha products. In 

this case, the co-product credit disappears but total fuel production emissions decrease to 30 kg 

CO2-eq/mm Btu, leading to overall GHG emissions reductions of 68%, considerably lower than 

if we assign a displacement credit. However, we chose to use the displacement approach as a 

conservative way to account for the wax co-product. We welcome comment regarding what 

kinds of materials these new waxes might replace, as well as how to best account for them in our 

lifecycle GHG analysis.

The results of this analysis are shown on the “Fuel Production” line of Table V.B.-3, and 

the assumptions and calculations are discussed in more detail in a memo to the docket.

25

 

Emissions from electricity production used to power the F-T plant is the greatest contributor to 

the overall fuel production emissions. In addition to emissions from fuel production, there were 

minor GHG emissions attributable to fuel transport and tailpipe emissions of non-CO2 GHGs 

 

24 Kline Group (2011) Global Wax Industry 2010: Market Analysis and Opportunities. 

http://www.klinegroup.com/reports/brochures/y635a/brochure.pdf

25

“Support for Cellulosic Determination for Landfill Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels Produced from Landfill Biogas”, which has been 

placed in docket EPA-HQ-2012-0401.
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38

(Table V.B.-3). Overall, renewable diesel and naphtha produced from landfill biogas via this 

process showed 52% and 51% reductions in GHG emissions, respectively, relative to the diesel 

or gasoline baseline (Table V.B.-3). These fuels would therefore qualify as advanced biofuels 

but not qualify as cellulosic biofuels. However, if the facility produced roughly 15% of its 

process electricity internally, using either waste heat from the reaction or combustion of 

unreacted chemicals, emissions from purchased electricity would drop enough to reach the 60% 

GHG reduction threshold, qualifying these fuels as cellulosic. Because emissions from 

production of these biofuels (without internal production of electricity) fall so close to the 50% 

threshold to qualify as advanced biofuels, the assumptions used to make the calculations are 

especially important and could potentially change the classification of these fuels. Accordingly, 

we request comments about the assumptions and values used in the calculations, which are 

detailed in a memo to the docket26. In particular, we request comment about the estimate for the 

on-site GHG emissions at the Fischer-Tropsch facility. Data regarding fugitive emissions from 

Fischer-Tropsch facilities using methane as a feedstock appear to be limited, however, the 

GREET model assumed a loss factor of 1.0000 for the production of F-T diesel, indicating their 

estimate that no methane is lost during this process. Several studies mentioned emissions from 

the steam methane reforming of natural gas to produce hydrogen, and we assumed emissions 

would be similar from a Fischer-Tropsch facility using steam methane reforming. Two of these 

studies27,28 found or estimated that losses of methane from such facilities were negligible, 

 

26

“Support for Cellulosic Determination for Landfill Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels Produced from Landfill Biogas”, which has been 

placed in docket EPA-HQ-2012-0401.

27 Skone, T.J. and Gerdes, K. (2008) NETL: Development of Baseline Data and Analysis of Life 

Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels. http://www.netl.doe.gov/energyanalyses/pubs/NETL%20LCA%20Petroleum-Based%20Fuels%20Nov%202008.pdf
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39

agreeing with the GREET estimate. Accordingly, we assumed no emissions of methane from FT facilities. However, another study29 estimated losses of 0.125% of the natural gas processed. 

Using this last value, the GHG emissions reductions for renewable diesel and naphtha would 

decrease to 49% for both fuels, meaning that the biofuels would no longer qualify as advanced 

fuels. We request comments and information about our estimates of fugitive emissions from 

Fischer-Tropsch facilities. 

Table V.B.-3. Total GHG Emissions for Renewable Diesel and Naphtha Produced from 

Landfill Biogas and Compared to the Appropriate Petroleum Baseline

GHG Emissions (kg CO2-eq/mmBtu)

Biofuels

Petroleum Baselines

Lifecycle Stage

Renewable 

Diesel Naphtha

2005 Diesel 

Baseline

2005 

Gasoline 

Baseline

Fuel Production 44 44 18 19

Fuel Transport 1 2

* *

Tailpipe Emissions 1 2

79 79

Total Emissions 47 48 97 98

% Change from 

Petroleum Baseline -52% -51%

*Emissions included in fuel production stage

 

28 Spath, P.M. and Mann, M.K. (2001) Lifecycle Assessment of Hydrogen Production via 

Natural Gas Steam Reforming. NREL Technical Report NREL/TP-570-27637, 

http://www.nrel.gov/docs/fy01osti/27637.pdf

29 Contadini, J.F., Diniz, C.V., Sperling, D., and Moore, R.M. (2000) Hydrogen production 

plants: emissions and thermal efficiency analysis. ITS-Davis. Presented at the Second 

International Symposium on Technological and Environmental Topics in Transports, October 

26-27, 2000. Milan, Italy. Publication No. UCD-ITS-RR-00-16.
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40

For this lifecycle analysis, we have only examined a facility that does not upgrade its wax 

and therefore produces wax as a co-product. It is likely that other facilities may produce F-T 

renewable diesel and naphtha by a process that does involve upgrading waxes to increase the 

yield of the liquid fuels. Accordingly, we used assessments from other analyses of theoretical FT

30 or steam methane reforming31 plants using wax upgrading to estimate the lifecycle GHG 

emissions from such products. Based on this analysis (not shown), these facilities should 

theoretically have GHG emissions that are as low as or lower than those calculated above. For 

this reason, we believe that the lifecycle analysis shown above is a reasonable, if slightly

conservative, representation of expected landfill biogas-to-liquids projects. We accordingly 

classify all renewable diesel and naphtha produced via the F-T process from landfill biogas as 

advanced biofuel.

Our lifecycle analysis showed that if the evaluated facility meets approximately 15% of 

its electricity demand with internally produced electricity, it will meet the 60% threshold to 

qualify as cellulosic. Because other facilities are likely to be somewhat different, and because 

this analysis relies on a number of assumptions, we are using a slightly more conservative 

threshold of 20% of electrical generation. Accordingly, we are proposing that if a biogas-toliquids facility produces at least 20 percent of its process electricity internally as discussed 

 

30 Swanson, R.M., Satrio, J.A., Brown, R.C., Platon, A., and Hsu, D.D. (2010) TechnoEconomic Analysis of Biofuels Production Based on Gasification. NREL Technical Report 

NREL/TP-6A20-46587, http://www.nrel.gov/docs/fy11osti/46587.pdf

31 Skone, T.J. and Gerdes, K. (2008) NETL: Development of Baseline Data and Analysis of Life 

Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels. http://www.netl.doe.gov/energyanalyses/pubs/NETL%20LCA%20Petroleum-Based%20Fuels%20Nov%202008.pdf
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41

above,32 these biofuels will qualify as cellulosic. Facilities that can supply data that demonstrate 

they meet the 60% GHG emissions reduction threshold without production of 20% electricity are 

welcome to petition the EPA individually under section 80.1416. 

EPA invites comment and data on the GHG emissions associated with landfill biogas 

renewable fuel pathways. We also welcome comment on the methodology and assumptions 

underlying this analysis. We do not at this point have sufficient information to evaluate the 

lifecycle greenhouse gas emissions for production of renewable electricity or renewable diesel 

and naphtha from biogas from waste treatment plants or waste digesters. Accordingly, we invite 

comments providing information about these potential pathways.

C. Proposed Regulatory Amendments related to Biogas

1. Changes Applicable to the Revised CNG/LNG pathway from Biogas

In the existing RFS2 regulations, an approved fuel pathway in Table 1 to section

80.1426(f)(1) allows biogas from landfill gas, manure digesters or sewage treatment plants to 

qualify as an advanced biofuel and generate a D code of 5 for the biofuel produced under the 

RFS2 program. Since the promulgation of the final rule, we have received many requests about 

what fuel qualifies under this pathway, including: 1) the renewable fuel type that is qualified 

under the term “biogas,” 2) what are the eligible sources of biogas, 3) what company along the 

 

32 Ways to meet this requirement are discussed in detail in the section titled “Changes 

Applicable to 20% Process Energy Displacement Requirement for Various Proposed Biogas 

Pathways.”
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42

production chain of biogas from generation to end user is considered the producer that qualifies 

to register under this pathway and generate RINs, and 4) what are the contract requirements to 

track the biogas from generation to end use. 

In response, EPA is proposing in this rulemaking to amend the existing biogas pathway

in Table 1 to section 80.1426(f) by changing the renewable fuel type in the pathway from 

“biogas” to “renewable compressed natural gas (renewable CNG) and renewable liquefied 

natural gas (renewable LNG)” and to replace the feedstock type of “landfills, manure digesters or 

sewage waste treatment plants” with “biogas from landfills, waste treatment plants or waste 

digesters.” We are also proposing to add definitions for CNG and LNG to section 1401 to 

provide additional clarity. In addition, we are proposing to revise and add new contracting, 

registration, reporting and recordkeeping requirements along the production chain. Furthermore, 

we are specifying which company along the production chain is considered the “producer” and 

eligible to generate RINs under the RFS2 program. These proposed compliance requirements are 

applicable to this revised CNG/LNG pathway, and all the newly proposed pathways for 

renewable fuels produced from landfill gas in this rulemaking. The details of the proposed new 

requirements for contract, registration, reporting and recordkeeping are discussed below in the 

section titled “Changes Applicable to All Biogas-Related Pathways for RIN Generation.”

The existing biogas pathway in Table 1 to section 80.1426(f) refers to “biogas” as the 

renewable fuel type and “landfills, manure digesters and sewage waste treatment plants” as the 

feedstock. Companies have raised questions whether the term “biogas” in this pathway could 

refer to the unprocessed or raw gas from the landfills, manure digesters or sewage treatment 
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43

plants, or processed “biogas” that has been upgraded and could be used directly for 

transportation fuel or as an ingredient in the production of transportation fuel or as an energy

source used in the production of transportation fuel, or other fuel types that can be produced 

from the raw biogas either through a physical or chemical process (such as CNG, LNG, 

renewable electricity, renewable diesel or naphtha). The companies further inquire if the various 

forms of biogas discussed above could qualify under this pathway, and therefore be eligible for 

RIN generation under the RFS2 program. 

We agree that the term “biogas” in this pathway is used broadly in the industry to refer to 

various raw and processed forms of the biogas from various sources. However, under the 

existing requirements in sections 80.1426(f)(10) and (11), only biogas that is used for 

transportation fuel can qualify as renewable fuel for RIN generation under the RFS2 program. 

We believe the stipulations in sections 80.1426(f)(10) and (11) are clear that biogas used for nontransportation fuel purposes, such as an energy source for providing process heat would not 

qualify under this biogas pathway for RIN generation. Similarly, raw biogas would also not 

qualify under this pathway since unprocessed biogas cannot be used as transportation fuel. With 

regard to the fuel types that can be produced from the raw biogas such as CNG, LNG, renewable 

electricity, renewable diesel, or naphtha, the pathway determinations for the final rule did not 

account for all factors relevant for the additional fuel types such as renewable electricity, 

renewable diesel or naphtha produced from the raw biogas through a chemical process. 

Therefore, renewable electricity, renewable diesel and naphtha produced from biogas do not 
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44

qualify under this pathway.

33

 For CNG and LNG, we concluded that these types of fuels were 

close enough to the physical molecules of biogas since these fuels only go through a physical 

process in which the biogas is compressed or liquefied, and that because CNG and LNG can be 

used directly for transportation purposes, thus meeting the provisions in sections 80.1426(f)(10) 

and (11), we concluded that CNG and LNG could qualify under the existing pathway. For the 

reasons discussed above, we are proposing to amend the existing biogas pathway to clearly state 

that only CNG and LNG produced from biogas from landfills, waste treatment plants and waste 

digesters, and used as transportation fuel, qualify as a cellulosic or advanced biofuel for RIN 

generation under the RFS2 program. 

The current regulations provide a pathway for biogas produced from a bio-digester which 

uses manure. We are also proposing to expand the type of materials that may be used to produce 

CNG/LNG in a digester to include animal wastes, biogenic waste oils/fats/greases, separated 

food and yard wastes, and crop residues. These feedstock sources are already eligible in the 

existing rules pathways and therefore should reasonably be added to the bio-digester pathway. 

We are doing so in response to a petition request to generate RINs from biogas which is 

produced from bio-feedstock sources in addition to the already allowed manure, either 

individually or in combination with manure in a bio-digester. As with other LCA pathways 

using these materials, EPA is proposing to assume these waste materials do not have emissions 

 

33 For this rulemaking, we conducted lifecycle analysis for renewable electricity, renewable 

diesel, naphtha produced from landfill gas, and are proposing new fuel pathways to Table 1 to 

Section 80.1426 for these fuel types. Please see section titled, “Lifecycle Greenhouse Gas 

Emissions Analysis for Renewable Electricity, Renewable Diesel and Naphtha Produced from 

Landfill Biogas” for the lifecycle analysis discussion in this rulemaking.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review*** 

45

associated with feedstock production, and therefore qualify as cellulosic or advanced renewable 

fuels when used to produce CNG/LNG.

To provide improvement for this revised pathway, we are proposing to add new

definitions for renewable CNG and renewable LNG to section 80.1401 to read as follows:

Renewable compressed natural gas (“renewable CNG”) means biogas as defined in this 

section, that is processed to the standards of pipeline natural gas as defined in 40 CFR 

72.2 and that is compressed to pressures up to 3600 psi. Only renewable CNG that 

qualifies as renewable fuel and is used for transportation fuel can generate RINs. 

Renewable liquefied natural gas (“renewable LNG”) means biogas as defined in this 

section, that is processed to the standards of pipeline natural gas as defined in 40 CFR 

72.2 and that goes through the process of liquefaction in which the biogas is cooled 

below its boiling point and weighs less than half the weight of water so it will float if 

spilled on water. Only renewable LNG that qualifies as renewable fuel and is used for 

transportation fuel can generate RINs. 

2. New Registration (Contract Requirements) for Renewable Electricity and Fuels Produced 

from Biogas that Qualify as Renewable Fuel and that is Registered for RIN Generation
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46

The regulations as currently written allow a producer of biogas or renewable electricity34

that qualify as renewable fuel and has an approved fuel pathway in Table 1 of section 1426(f)(1) 

to register and generate RINs for the volume it produces under the RFS2 program. We modified 

the existing regulations to state that biogas is the feedstock used to produce renewable fuel, as 

described above. The regulations in sections 1426(f)(10) and (11) detail the requirements for 

distribution and tracking for renewable electricity and biogas used to produce fuel that qualifies 

as renewable fuel that can either be distributed in a dedicated pipeline or transmission line or 

distributed in a shared pipeline or power grid system. The purpose of these requirements is to 

provide EPA assurance and verification that once the biogas or renewable electricity is put into a 

dedicated or shared distribution system that in fact an equivalent volume of biogas or renewable 

electricity will be used for transportation fuel, and for no other purposes. The requirements are 

also meant to address concerns of double counting of the biogas or renewable electricity, 

especially in situations that the biogas or renewable electricity is placed in or loaded onto shared 

distribution systems that contain gas or electricity from non-renewable biomass sources. EPA 

intended to require producers to submit the information and contract requirements in sections

1426(f)(10) and (11) as part of the registration requirements for renewable electricity and 

renewable fuels produced from biogas that are used for transportation35 fuel, but had not done so 

in the prior rulemakings. Therefore, as a natural outgrowth of the regulations for implementation 

and compliance purposes, we are proposing in this rulemaking to incorporate the requirements in 

 

34 EPA notes that currently, producers of renewable electricity that may qualify as a renewable 

fuel cannot register and generate RINs because there is no approved pathway in Table 1 for 

renewable electricity from any approved feedstock. But in the event that an approved pathway 

for renewable electricity is added to Table 1, EPA notes there are existing requirements such as 

tracking and distribution requirements recordkeeping and reporting that are applicable for the 

registration of renewable electricity for RIN generation.

35 Distribution and registration requirements for biogas used as process heat, and not for RIN 

generation as renewable fuel is detailed in Section 1426(f)(12) and 1450(b)(1)(iv), respectively.
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47

sections 1426(f)(10) and (11) as part of registration requirements for producers of renewable 

electricity and renewable fuels produced from biogas that qualify as renewable fuel under the 

regulations under section 1450(b)(1)(iv)(C).

Section 1426(f)(11)(ii) of the regulations requires that, in order for renewable fuel made 

from biogas withdrawn from a commercial distribution system for use as a transportation fuel to 

generate RINs, the biogas introduced into the system must have been added to a common, shared 

pipeline. We propose to add a similar provision to section 1426(f)(11)(i) for renewable 

electricity, requiring a company to load the renewable electricity to a power grid shared by the 

second company that withdraws the electricity, such that the two companies must be physically 

connected to the same grid or located within the same area. 

EPA is requesting comments about whether the other existing requirements in sections

1426(f)(10) and (11) for renewable electricity and renewable fuels from biogas used for 

transportation fuel are sufficient to provide assurance and verification for the following 

situations. First, do the proposed requirements provide assurance and verification that the same 

amount of biogas or renewable electricity is in fact delivered to the renewable fuel producer or 

end user who will actually use the biogas or renewable electricity for transportation purposes? If 

the proposed requirements are not sufficient, what alternative requirements should be 

considered? Second, are the proposed requirements sufficient to ensure that double counting 

does not occur, e.g., to ensure that the biogas or renewable electricity once it is loaded into a 

shared pipeline or power grid is not sold to multiple clients or for purposes other than for 

transportation purposes? Similarly, if the proposed requirements are not sufficient, what 
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48

alternative requirements could be considered to ensure double counting does not occur? Finally, 

we invite comments about whether EPA should restrict renewable electricity that generates RINs 

under the RFS2 program from also generating renewable energy credits (RECs) for compliance 

with state programs or other equivalent programs. If such restrictions should be used, we also 

request suggestions of the types of information and documentation that could be used to verify

that RECs are not also generated for the electricity.

3. Changes Applicable to all Biogas Related Pathways for RIN Generation

As discussed above, we have had many inquiries related to the “biogas” pathway, 

specifically regarding contract requirements for tracking the biogas through the distribution 

system and regarding what company along the production chain is considered the “producer” and 

eligible to generate RINs under the RFS2 program. In this rulemaking, we are proposing to 

revise and add new requirements for contracts to track the biogas as it moves into and out of the 

distribution system, as well as provisions on registration, reporting and recordkeeping. These 

proposed amended requirements are applicable to all pathways related to biogas that are eligible 

for RIN generation that are existing or proposed in this rulemaking.

In response to the question of what company is considered the producer of renewable fuel 

and eligible to generate RINs under the RFS2 program, we propose to define the “producer” 

differently for renewable CNG/LNG than we do for the other fuels because of the very different 

nature of fuel production for these different biogas-derived fuels. For renewable electricity, 

renewable diesel and naphtha, we propose to define the “producer” as the company that produces 
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49

the actual fuel that is to be used for transportation purposes. For example, the producer would be 

considered the company that produces the renewable electricity, renewable diesel or naphtha and 

can track and verify that the fuel it produces is being used for transportation fuel. In contrast, for 

renewable CNG/LNG, we propose that the company that upgrades the raw biogas to pipeline 

quality gas (that is ultimately compressed or liquefied to CNG or LNG) will be the producer. 

This company would be similar to a foreign undenatured ethanol producer, where the party who 

upgrades the raw biogas to pipeline quality gas would not have the ability to generate RINs in 

EMTS, but still be required to register under the same requirements as a RIN generating 

producer. The party that compresses or liquefies the contracted amount of pipeline quality gas 

would generate RINs referencing the biogas producer’s facility ID, in the same manner that a 

domestic importer denatures ethanol and generates RINs. We define “producer” in this way

because, even though pipeline-quality gas must be further processed before it can be used for 

transportation purposes, this processing is minimal, requiring simple physical compression or 

liquification. Additionally, we would want to prevent RINs from being generated for a batch or 

renewable CNG/LNG prior to use as a qualifying transportation fuel. This is in contrast to 

production of renewable electricity, renewable diesel and naphtha from pipeline quality biogas, 

which requires significant chemical processing and alteration of the raw biogas. For these other 

fuels, it would not make sense to define the “producer” as the company that creates the pipeline 

quality gas because this gas undergoes dramatic changes in the production of the final fuel, with 

significant losses of energy in the process. For any of the fuels, the company designated as the 

“producer” will be required to register under the RFS2 program. We seek comment on our 

proposed definition of producer regarding renewable CNG/LNG. In addition, any finalized 

changes will need to be reflected in EMTS before this approach will be allowed.
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50

We acknowledge that the process train from raw biogas to the final transportation fuel is 

complex, and may include many companies and processing steps from the point when the raw 

biogas is withdrawn from its source (such as landfills, waste digesters, waste treatment plants), 

processed and converted into biofuel and distributed to consumers. Alternatively, the fuel may

be cleaned at a biomethane facility to pipeline quality specifications for distribution, and then 

withdrawn from the commercial pipeline to be processed further at another production facility

into renewable CNG/LNG, renewable electricity, renewable diesel or naphtha. Due to the 

complexity of the many entities potentially involved in this process train, we are proposing that 

the company deemed as the “producer” under the qualifications described above also be 

responsible for providing all the required information and supporting documentation in their 

registration, reporting and recordkeeping to track and verify the information from point of 

extraction of the raw biogas from its original source, and all the processing steps and distribution 

in between, to the last step where the actual fuel is used for transportation purposes. In the 

engineering review report required for registration, the producer must include documentation that 

the professional engineer performed site visits at each production facility, including the biogas 

facility and the facility that produces the final fuel (if these are not the same facility). The 

producer must also review and verify all related supporting documents such as design 

documents, calculations, regulatory permits, and contracts between facilities that track the raw 

biogas from the point of withdrawal from its source, the various injection/withdraw points into 

the distribution pipeline, the various production facilities, and the final step for use as 

transportation fuel. We believe these requirements will ensure that producers will perform due 

diligence that the fuel for which they generate RINs under the RFS2 program are in compliance 
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51

with all the regulatory requirements for renewable fuel. The proposed registration, reporting and 

recordkeeping requirements are in sections 80.1426(f), 80.1450, 80.1451 and 80.1454 in this 

rulemaking. Additional changes regarding the contract requirements for distribution of the 

biogas in shared commercial pipelines are discussed below, and can be located in sections

80.1426(f)(10), (11), and (13). 

4. Changes Applicable to Process Electricity Production Requirement for the 

Biogas- Derived Cellulosic Diesel and Naphtha Pathways 

In this proposed rulemaking, EPA conducted greenhouse gas (GHG) lifecycle analysis 

for various renewable fuels produced from landfill gas as new or revised advanced and cellulosic 

biofuel pathways that will be added to Table 1 to section 80.1426(f). 36 For some of these 

pathways, we are proposing to add various registration, recordkeeping and reporting 

requirements to the regulations to ensure that the facilities using these pathways meet the 

parameters stipulated in the lifecycle analysis. The additional registration, recordkeeping and 

reporting requirements are discussed in detail below. 

For the proposed fuel pathways for cellulosic diesel and cellulosic naphtha produced 

from landfill gas, we are proposing to require the renewable fuel production facility to produce a 

minimum of 20 percent of the process electricity used at the facility on a calendar year basis,

from raw landfill gas, waste heat from the production process, unconverted syngas from the F-T 

 

36 Refer to preamble discussion for these various biogas pathways in section titled, “Lifecycle 

Greenhouse Gas Emissions Analysis for Renewable Electricity, Renewable Diesel and Naphtha 

Produced from Landfill Biogas.”
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52

process, fuel gas from the hydroprocessing or combined heat and power (CHP) units that use 

non-fossil fuel based gas or other renewable sources. We propose that if less than 20 percent (on 

an annual average basis) of process energy comes from one of these alternative sources, then no 

cellulosic RINs can be generated for that year.

For the renewable fuel production facility applying to use the proposed fuel pathway with 

the requirement to internally produce at least 20 percent of the total amount of process electricity 

used at its facility, we are proposing the facility submit to EPA the information described below 

to demonstrate compliance with this requirement. For registration purposes, we are proposing 

that producers submit the following additional information in the process fuel supply plan that is 

currently required as part of the registration process (estimated summaries are to be reported on 

an annual/calendar year basis):

- Estimated amount of total electricity used at the facility

- Estimated amount of total electricity purchased for the facility

- Estimated amount of total renewable electricity produced on-site, including the 

source of the energy and the equipment and/or process used to generate the renewable 

electricity

- Calculation that verifies the facility meets the specified 20 percent minimum 

electricity production requirement based on the reported total amount of electricity 

used at the facility, total amount of electricity purchased, and total amount of 

renewable electricity produced

For reporting purposes, we are proposing for producers to submit the following additional 

information as part of their existing quarterly and annual reporting obligations (reported amounts 
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53

should be provided as monthly summaries on an annual/calendar year basis, and must be 

obtained from a utility meter that is continuously measured):

- Actual total amount of electricity used at the facility

- Actual total amount of electricity purchased for the facility

- Actual amount of total renewable electricity produced on-site, including source of 

energy and the equipment or process used to generate the renewable electricity

- Calculation that verifies the facility meets the specified 20 percent minimum 

electricity production requirement based on the reported total amount of electricity 

used at the facility, total amount of fossil-fuel based electricity purchased, and total 

amount of renewable electricity produced 

For recordkeeping purposes, we are proposing that producers retain the additional 

information, calculations and supporting documents required for registration and reporting as 

discussed above. The regulatory requirements for registration, reporting and recordkeeping as 

discussed in this proposed rulemaking can be located in the following applicable regulatory

sections 80.1450, 80.1451 and 80.1454, respectively.

D. Amendment to the Definition of “Crop Residue” and Identification Corn Kernel Fiber as a 

Crop Residue

We propose to amend the definition of “crop residue” so that this category includes only

feedstock sources that are determined by EPA would not result in a significant increase in direct 
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54

or indirect GHG emissions. “Crop residue” is the biomass left over from the harvesting or 

processing of planted crops from existing agricultural land and any biomass removed from 

existing agricultural land that facilitates crop management (including biomass removed from 

such lands in relation to invasive species control or fire management), whether or not the 

biomass includes any portion of a crop or crop plant. Biomass is considered crop residue only if 

the use of that biomass for the production of renewable fuel has no significant impact on demand 

for the feedstock crop, products produced from that feedstock crop, and all substitutes for the 

crop and its products including the residue, nor any other impact that would result in a significant 

increase in direct or indirect GHG emissions.

EPA is amending the definition of “crop residue” to confirm the meaning of the term 

“left over” in the text of this definition. The phrase “left over” in our original definition of “crop 

residue” is meant to indicate that the use of a residue as a biofuel feedstock should not increase 

demand for the crop it is derived from, should not induce further crop production, and should not 

result in additional direct or indirect GHG emissions. The residue must come from crop 

production or processing for some other primary purpose (e.g., refined sugar, corn starch 

ethanol), such that the crop residue is not the reason the crop was planted. The residue must also 

come from existing agricultural land, the exact definition of which is laid out in our current 

regulations that define “renewable biomass”.37 Further, the residue should generally not have a 

significant market in its own right, to the extent that removing it from that market to produce 

biofuels instead will result in increased GHG emissions. EPA is seeking comments on this 

revision to the crop residue definition. EPA invites all comments regarding this revision, but 

specifically invites comments regarding the potential for the revision to create a significant shift 

 

37 See specifically § 80.1401 Definitions.
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55

in direct or indirect GHG emissions and what ought to constitute a “significant” increase or 

decrease in GHG emissions in the context of this definition.

EPA has previously identified several potential feedstocks that we believe meet the 

criteria of crop residue. Table IV.D.-1 lists feedstocks which may fit the definition of crop 

residue. Most of these feedstocks were discussed in the final RFS2 rulemaking. For example, 

EPA analyzed the agricultural sector GHG emissions of using corn stover for biofuels in the final 

RFS2, and found that fuel produced from this feedstock met the 60% GHG reduction threshold 

for cellulosic biofuels. Since the direct and indirect impacts of citrus residue, rice straw, and 

wheat straw removal were expected to be similar to corn stover, EPA also applied the land use 

change impacts associated with corn stover to citrus residue, rice straw, and wheat straw. Based 

on that analysis, EPA found that fuels produced from citrus residues, rice straw, and wheat straw 

also met the 60% reduction threshold. EPA further determined that fuels produced from 

materials left over after the processing of a crop into a useable resource had land use impacts 

sufficiently similar to agricultural residues to also meet the 60% threshold. EPA specifically 

cited bagasse left over from sugarcane processing as an example of this type of residue. EPA is 

seeking comment on whether the feedstocks on this list should be considered crop residues and 

whether additional feedstocks should also be included in this list.

Table IV.D.-1 – Feedstocks That May Qualify as Crop Residue

Feedstock D Code

Sugarcane Bagasse D-3 Cellulosic biofuel

Corn Kernel Fiber (excluding the corn starch D-3 Cellulosic biofuel
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56

component)

Corn Stover D-3 Cellulosic biofuel

Citrus Residue D-3 Cellulosic biofuel

Rice Straw D-3 Cellulosic biofuel

Wheat Straw D-3 Cellulosic biofuel

While EPA believes that, under current conditions, generation of RINs for batches of 

renewable fuel produced from the feedstocks listed in Table IV.D.-1 above would not result in a 

significant increase in direct or indirect GHG emissions, we also acknowledge the potential for 

this assessment to change in the future based on unforeseeable factors. For example, some new 

use for one of these products could be developed which would change our assessment that the 

feedstock has no significant market in its own right. Further, it is possible that, at some point in 

the future, large enough quantities of renewable fuel could be produced from one of these fuels 

to create demand pull for the feedstock, potentially altering the behavior of producers of the 

residue and leading to significant increases in direct or indirect GHG emissions. To our 

knowledge, this is not currently the case for any of the feedstocks listed above. However, EPA 

will continue to monitor RIN generation from fuel produced using each of these feedstocks and 

the general use of these feedstocks in the marketplace. We further reserve the right to revisit the 

status of any feedstock that we have determined qualifies under the crop residue pathway. 

Should any feedstock qualifying as a crop residue be used to generate significant quantities of 

ethanol in the future, or should a significant market emerge for the product such that there is 

demand pull for it in excess of the demand pull for the planted crop from which it is a derived 

byproduct, we will revisit whether that feedstock should remain under the crop residue pathway
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57

or be subjected to further scrutiny. EPA is seeking comment on this approach and on the 

potential for significant demand pull to emerge for the feedstocks we are proposing to consider 

as crop residues.

We also propose that this definition of “crop residue” includes corn kernel fiber. Corn 

kernel fiber is not specifically mentioned as a type of crop residue under the Renewable Fuel 

Standard (RFS2) regulations. Per the RFS2 definition of “crop residue”, EPA must evaluate 

whether corn kernel fiber is “left over from the harvesting or processing of planted crops” and 

that it has no “impact that would result in a significant increase in direct or indirect GHG 

emissions” for this feedstock to qualify as a residue. 

One additional consideration in the classification of corn kernel as a crop residue is the 

fact that some amount of corn starch might still adhere to the corn kernel after separation. The 

percentage of contamination will vary, but as much as 20% of the final fuel could be derived 

from corn starch. By definition, corn starch ethanol can only qualify as a renewable fuel, not as 

an advanced fuel. However, our current regulations state that “producers and importers may

disregard any incidental, de minimis feedstock contaminants that are impractical to remove and 

are related to customary feedstock production and transport”.38 Therefore, EPA is seeking 

comment on whether the definition of crop residue should be amended to explicitly exclude the 

corn starch component. 

EPA also invites comment on how RINs should be allocated for ethanol derived from 

corn fiber. EPA has existing regulations that define procedures for generating RINs from 

 

38 See specifically § 80.1426 (f) (1).
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58

batches of fuel that contain multiple feedstocks, including feedstocks that generate RINs of 

different D codes.39 We believe that these regulations provide sufficient guidance to producers 

and importers regarding how to assign RINs to batches of renewable fuel that can be described 

by two or more pathways (e.g., corn starch ethanol and corn kernel fiber ethanol). However, we 

invite comment on the sufficiency of these regulations with regards to the assignment of RINs to 

coprocessed batches of corn starch ethanol and corn kernel fiber ethanol, including whether 

producers have the technological capability to adequately demonstrate volume produced under 

each pathway.

To determine whether the use of corn kernel fiber to produce ethanol would lead to 

increased direct or indirect GHG emissions, EPA conducted a detailed assessment of the two 

major potential sources of emissions from this feedstock, namely effects on feed markets and 

effects on demand for corn. The proposed method of acquiring corn kernel fiber is to extract it 

from matter that is otherwise converted to dried distillers grains (DDG) during the dry mill corn 

ethanol process. Consequently, this analysis relied significantly on the assessment of corn starch 

ethanol-derived DDG that was conducted for the RFS2 final rule, adjusting the analysis to 

account for the extraction of fiber from this product. The analysis also drew substantially on the 

available scientific literature on low fiber DDG (LF-DDG), as well as the expertise of the U.S. 

Department of Agriculture. Potential producers also submitted important data to EPA that 

helped determine whether producing cellulosic ethanol from corn kernel fiber would result in a 

significant increase in GHG emissions. This included a full nutritional analysis of LF-DDG for 

swine, poultry, and cattle.

 

39 See specifically § 80.1426 (f) (3).
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EPA found that extracting the fiber from corn matter used to produce standard DDG 

would not have a significant effect on feed markets. Processors who extract the fiber from corn 

produce a feed product known as LF-DDG, as opposed to standard DDG which retains the fiber. 

The scientific literature on LF-DDG animal nutrition has found that this product has at least 

equal, and perhaps even slightly superior, nutritional value for swine and poultry compared to 

standard DDG.40 This means that, even though the physical volume of the DDG produced by 

ethanol plants using corn kernel fiber extraction technology will be somewhat smaller, its 

nutritional content for swine and poultry will be equivalent to or greater than their output without 

fiber extraction.

Conversely, LF-DDF is an inferior feed for cattle compared to standard DDG, since 

ruminants benefit from ingesting corn fiber in DDG.

41

 Therefore, EPA expects swine and 

poultry producers to absorb the supply of LF-DDG, while the cattle and dairy industry will 

continue to consume standard DDG. With this dynamic in place, fiber extraction from DDG 

should not significantly affect feed markets, since there will be no reduction in the overall supply

of DDG in terms of nutritional content nor will there be any impact on aggregate demand for 

other animal feed sources.

If enough corn ethanol producers adopt fiber extraction technology, LF-DDG could 

saturate swine and poultry demand and spill over into dairy and cattle feed markets. If a 

 

40 See, for example: Kim, E.J., C.M. Parsons, R. Srinivasan, and V. Singh. 2010 Nutritional composition, nitrogencorrected true metabolizable energy, and amino acid digestibilities of new corn distillers dried grains with solubles 

produced by new fractionation processes. Poultry Science 89, p. 44. Available on the docket for this rulemaking. 

See also additional studies cited within Kim et al 2010.

41 See Shurson, G.C. 2006. The Value of High-Protein Distillers Coproducts in Swine Feeds. Distillers Grains 

Quarterly, First Quarter, p. 22. Available on the docket for this rulemaking.
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situation arises where LF-DDG begin to replace standard DDG in cattle markets, this could lead 

to an increase in feed demand, most likely in the form of increased demand for fiber supplements 

in dairy and cattle feed. This could cause an increase in GHG emissions. If swine and poultry

demand for LF-DDG becomes saturated, demand for standard DDG in the cattle and dairy

industries should create sufficient market incentives for the remaining corn starch ethanol 

producers to decide against adopting corn fiber ethanol production. EPA believes this will 

prevent a situation where there is insufficient supply of standard DDG in the cattle and dairy

industries. However, as noted above, EPA reserves the right to reexamine corn kernel fiber as a 

feedstock in the future.

EPA’s analysis indicates that producing cellulosic ethanol from corn kernel fiber is 

unlikely to increase overall demand for corn. In order to meet the definition of a crop residue, 

the source of corn kernel fiber must be a crop processing facility (e.g., a corn starch ethanol 

plant). A corn kernel fiber ethanol producer cannot purchase whole corn specifically for the 

generation of corn fiber ethanol and still qualify their feedstock as crop residue. EPA is seeking 

comment on this analysis.

Based on our assessment, EPA proposes that corn kernel fiber would meet the definition 

of a crop residue, and qualify for Cellulosic Ethanol and Advanced Biofuel (D-codes 3 & 5, 

respectively) RINs under the RFS2. EPA is seeking comment on whether corn kernel fiber 

should be considered a crop residue. 
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E. Lifecycle Analysis of Advanced Butanol Pathway

1. Proposed New Pathway

EPA is proposing to add a new pathway to Table 1 to section 80.1426 that allows butanol 

made from corn starch using a combination of advanced technologies to meet the 50% GHG 

emissions reduction needed to qualify as an advanced renewable fuel. This pathway applies to 

dry mill fermentation facilities that use natural gas and biogas from an on-site thin stillage 

anaerobic digester for process energy with combined heat and power (CHP) producing excess 

electricity of at least 40% of the purchased natural gas energy of the facility (the proposed 

“advanced butanol pathway”). 

GEVO Incorporated submitted a petition requesting authorization to generate D-code 5 

RINs for fuel produced through the GEVO butanol pathway. A petition is required because the 

proposed process utilizes a high yield butanol fermentation process that is different from those 

analyzed as part of the RFS2 corn ethanol pathways, and does not use the approved advanced 

technologies shown in Table 2 to section 80.1426 of the RFS2 regulations. 

EPA’s evaluation of the lifecycle GHG emissions of the advanced butanol pathway under 

this petition request is consistent with EISA’s applicable requirements, including the definition 

of lifecycle GHG emissions and threshold evaluation requirements. It was based on information 

regarding GEVO’s production process that was submitted under a claim of Confidential Business 

Information (CBI) by GEVO on April 11, 2011. The information provided included the mass 
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62

and energy balances necessary for EPA to evaluate the lifecycle GHG emissions of the advanced 

butanol pathway. 

The lifecycle GHG emissions of fuel produced pursuant to the advanced butanol pathway

were determined as follows:

Feedstock production – The advanced butanol pathway uses corn starch as a feedstock. 

Corn starch is one of the feedstocks already listed in Table 1 to section 80.1426 of the RFS2 

regulations. Since corn starch has already been evaluated as part of the RFS2 final rule, no new 

feedstock production modeling was required.

The FASOM and FAPRI models were used to analyze the GHG impacts of the feedstock 

production portion of the fuel’s lifecycle. The same FASOM and FAPRI results representing the 

emissions from an increase in corn production that were generated as part of the RFS2 final rule 

analysis of the existing corn butanol pathways were used in this analysis of the advanced butanol 

pathway. These results represent agriculture/feedstock production emissions for a certain 

quantity of corn produced. For the RFS2 analysis, this was roughly 960 million bushels of corn 

used to produce 2.6 billion gallons of fuel. We have calculated GHG emissions from feedstock 

production for that amount of corn. EPA does not believe the advanced butanol process for 

converting corn into butanol will materially affect the total amount of corn used for biofuels and 

modeled as part of the RFS2 final rule. Based on information provided by industry, the 

technologies to produce corn butanol are primarily being targeted at retrofitting existing corn 

ethanol facilities, where the infrastructure to produce renewable fuels already exists and the 
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63

capital expenditures would be relatively small. Therefore, the existing agricultural sector 

modeling analyses for corn as a feedstock remain valid for use in estimating the lifecycle impact 

of renewable fuel produced using the advanced butanol pathway. The Agency is seeking 

comment on whether there is any research to suggest that converting corn into an advanced 

butanol pathway would materially affect the total amount of corn used. 

GEVO provided, as part of the information claimed CBI, their process yield in terms of 

gallons of fuel produced per bushel of corn. Based on the data, GEVO’s process yield is slightly

more efficient than the pathways modeled as part of the RFS2 rulemaking. Therefore, compared 

to the corn butanol pathways already analyzed, the GEVO process results in 0.93% more Btus of 

fuel produced for the same amount of corn feedstock. 

Fuel production – The fuel production method included in this advanced butanol pathway

involves the production of butanol from corn starch in a dry mill. The amount and type of 

energy used in this analysis is different than production methods that were analyzed under the 

final rule. While there were slight differences in the total amount of natural gas and electricity 

used in this analysis, the main difference was the use of biogas and production of excess 

electricity. To analyze the GHG impacts of the advanced butanol pathway, EPA utilized the 

same approach that was used to determine the impacts of processes in the RFS2 corn butanol 

pathways. 

The amount and type of energy used was taken from GEVO’s mass balance & energy

balance submitted to EPA. GEVO submitted energy data on natural gas and biogas (in Btus) and 
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64

electricity (in kWhs) inputs, as well as gallons of fuel produced. Biogas and natural gas is used 

in combination, while the RFS2 corn butanol analyses only considered natural gas or biogas used 

independently, not in combination. 

The emissions from the use of energy was calculated by multiplying the amount of 

energy by emission factors for fuel production and combustion, based on the same method and 

factors used in the RFS2 final rulemaking. The emission factors for the different fuel types are 

from GREET and were based on assumed carbon contents of the different process fuels. 

One area where EPA is soliciting comments is on the most appropriate energy content 

assumption to use for butanol (lower heating value). As part of this analysis, EPA used the 

GREET value for the energy content of butanol, which is 99,837 Btus per gallon42. Differences 

in the measurement of the energy content of butanol can occur for a number of reasons including 

variations amongst isomers (t-butanol, n-butanol, isobutanol, and sec-butanol), and differences in 

testing methodologies. EPA is seeking comment on whether there are any reasons why EPA 

should change its assumptions and use a different energy content of butanol. 

The RFS2 corn butanol pathways included an estimate for DDGS co-product production 

which we similarly applied to the advanced butanol production process. Since DDGS impact the 

agricultural markets, such inclusion was included as part of the FASOM and FAPRI modeling 

 

42 The GREET value is based on: Guibet, J.-C., 1997, Carburants et Moteurs: 

Technologies, Energie, Environnement, Publication de l’Institut Français du Pétrole, ISBN 2-

7108-0704-1. 
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65

already described in the feedstock production section, above. Thus no additional co-product 

credits for the DDGS are applied for the fuel production stage of the analysis. 

The advanced butanol production process analyzed here also results in excess electricity 

production. As per the pathway description the process produces excess electricity of at least 

40% of the purchased natural gas energy of the facility. The onsite emissions of the electricity

production are accounted for in the facility natural gas and biogas use. The co-product credit of 

the excess electricity is accounted for by assuming the electricity offsets average grid electricity 

production and results in associated emission reductions. 

The estimated production emissions from the advanced butanol process are shown below 

in Table V.F.-1.

Table V.F.-1: Fuel Production Emissions for the Advanced Butanol Process

Fuel Production Source GEVO Isobutanol (g 

CO2-eq./mmBtu)

On-Site Emissions 15,273

Upstream

(natural gas and electricity production)

2,424

Emissions Credit from Offset Electricity - 17,448

Total Fuel Production Emissions: 249

 

Fuel and feedstock distribution – We used the same feedstock distribution emissions 

assumption considered for corn butanol under the RFS2 final rule for the advanced butanol 
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66

pathway corn feedstock. The fuel type, butanol, and hence the fuel distribution for butanol, was 

already considered as part of the RFS2 final rule. Therefore, the existing feedstock and fuel 

distribution lifecycle GHG impacts for corn butanol were applied to the advanced butanol 

pathway analysis. 

Use of the fuel – the advanced butanol pathway produces a fuel that was analyzed as part 

of the RFS2 final rule. Thus, the fuel combustion emissions calculated as part of the RFS2 final 

rule for butanol were applied to our analysis of the advanced butanol pathway. 

The advanced butanol fuel was then compared to baseline petroleum gasoline, using the 

same value for baseline gasoline as in the RFS2 final rule analysis. The results of the analysis 

indicate that the advance butanol pathway would result in a GHG emissions reduction of 51.3% 

compared to the gasoline fuel it would replace. 

Based on our LCA analysis, we are proposing to add a new pathway to Table 1 to section

80.1426 that includes butanol from corn starch using the butanol process described here as an 

advanced biofuel (D-5 RINs). EPA invites comments on the assumptions used in this analysis. 

Table V.F.-2 below breaks down by stage the lifecycle GHG emissions for the RFS2 corn 

butanol pathway, the advanced butanol pathway and the 2005 gasoline baseline. This table 

demonstrates the contribution of each stage in the fuel pathway and its relative significance in 

terms of GHG emissions. 
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Table V.F.-2: Lifecycle GHG Emissions for the Advanced Butanol Pathway, 2022 (kg CO2-

eq./mmBtu)

Fuel Type

RFS2 

Corn 

Ethanol, 

Natural 

Gas Fired 

Dry Mill 

63% Dry

DDGS

RFS2

GEVO 

Butanol

2005 

Gasoline 

Baseline

Net Domestic Agriculture (w/o land use change) 4 4

Net International Agriculture (w/o land use 

change) 12 12

Domestic Land Use Change -4 -4

International Land Use Change,

Mean (Low/High) 32 (21/46) 31

Fuel Production 28 0 19

Fuel and Feedstock Transport 4 4 *

Tailpipe Emissions 1 1 79

Total Emissions, Mean 77 (66/91) 48 98

% Reduction -21% -51%

*Emissions included in fuel production stage.

Table V.F.-3 lists the proposed D-Codes by fuel type (butanol), considering the feedstock 

(corn starch) and different production process requirements.
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Table V.F.– 3: Proposed D Codes for Butanol

Fuel Type Feedstock Production process 

requirements

D-Code

Butanol Corn starch Fermentation; dry mill 

using natural gas, 

biomass, or biogas for 

process energy

6

Butanol Corn starch Fermentation; dry mill 

using natural gas and 

biogas from on-site thin 

stillage anaerobic 

digester for process 

energy w/ CHP 

producing excess 

electricity of at least 

40% of the purchased 

natural gas energy used 

by the facility

5

2. Butanol, Biobutanol, and Volatility Considerations

Butanol is a flammable colorless liquid that is used as a fuel and as an industrial solvent. 

Butanol is composed of the chemical elements hydrogen, oxygen, and carbon. It can be made 

from petroleum or renewable biomass, such as corn, grasses, agricultural waste and other 

renewable sources. It can be used in internal combustion engines as an additive to gasoline and 

is currently registered under the Fuel and Fuel Additives Registration system (FFARs) for use at

up to 12 volume percent. A higher blend level would require a new FFARS registration that 

would include meeting Tier 1 and Tier 2 health effects testing requirements. Biobutanol is the 

common name for butanol made from renewable sources. 

There has been an increased interest in the use of biobutanol as a direct result of the 

requirements for increased use of renewable fuel volumes, adopted in EISA 2007. These 
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69

provisions require an increase in the use of renewable fuels, with 36 billion gallons of renewable 

fuel to be used in the U.S. by 2022. Parties required to meet these standards are interested in cost 

effective and practical ways to satisfy the standards and meet the performance needs of the 

vehicles and engines. Biobutanol is one attractive option because of its higher energy density, 

lower blending vapor pressure, and lower heat of vaporization in comparison to ethanol, as well 

as the fact that it can be distributed as a gasoline blend throughout the fungible gasoline 

distribution system.

The Clean Air Act (section 211(h)(4)) requires EPA to adopt regulations limiting the 

volatility of gasoline during the summer months, when ozone is of most concern, including a one 

pound per square inch (psi) Reid Vapor Pressure (RVP) increase in the volatility limit for 

blends of gasoline containing 9-10% ethanol (E10). This allowance for a 1 psi increase in 

allowable volatility is commonly called the 1 psi waiver.

EPA’s regulations at 40 CFR 80.27 adopt RVP standards that apply to the gasoline at all 

points in the distribution system, including the retail outlet. Under the provisions for the 1 psi 

waiver, blends of gasoline that contain from 9 volume percent to 10 volume percent ethanol are 

allowed to have volatility 1 psi higher than otherwise would be allowed (40 CFR 80.27(d)(2)). 

The chemical characteristics of ethanol are such that blends of gasoline with less than 9 volume 

percent to 10 volume percent ethanol would still have a significant increase in volatility. Thus 

the restriction on the 1 psi waiver to blends that have 9 volume percent to 10 volume percent

ethanol has the effect of prohibiting the blending of E10 with other gasoline/renewable fuel 

blends at any point in the gasoline distribution system (wholesale or retail) in conventional 
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gasoline areas during the summer control season. Blends of E10 gasoline and gasoline that is not 

E10 would have less than 9 volume percent or greater than 10 volume percent ethanol, would 

have a resulting increase in volatility compared to E0, but would not have the 1 psi waiver to 

allow for such an increase. This increase would lead to an RVP above the allowable limit, unless 

a sub-RVP gasoline blendstock was used. The practical effect is a prohibition on commingling 

of E10 and gasoline blends other than E10.

Under the current regulations, EPA applies the RVP standard to the commingled mixture 

as a whole, not to the components of the commingled mixture. Once the ethanol and non-ethanol 

blends are mixed, the commingled mixture is treated as the gasoline that is tested and compared 

to the RVP standard. A single RVP value is determined by testing the volatility of the 

commingled mixture, and this is compared to the standard. If the mixture has from 9 volume 

percent to 10 volume percent ethanol, then the 1 psi waiver applies to the mixture. If the mixture 

has a different percentage of ethanol, whether lower or higher, then the 1 psi waiver does not 

apply to the mixture.

This avoids a situation where there is an overall increase in volatility because of the 

commingling of E10 and gasoline that is not E10. As discussed below, the chemical 

characteristics of ethanol and the nonlinear nature of the volatility increase associated with 

varying volumes of ethanol, mean that mixing E10 gasoline with gasoline that is not E10 

typically results in a net overall increase in emissions – the mixture has a higher volatility and 

emissions than the separate gasolines had on average before they were mixed. 
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71

Several parties have identified this as an obstacle that currently inhibits the opportunity

for biobutanol to enter the commercial market. The primary issue is application of the RVP 

regulations at the final point of fuel dispensing, when the biobutanol (Bu) and the ethanol blends 

would be mixed, that is in a storage tank at the retail station. When a butanol product that 

complies with the RVP standards prior to commingling (e.g. a complying Bu12 blend) is 

commingled with a compliant E10 in underground storage tanks at fuel dispensing facilities, the 

resulting mix generally would exceed the applicable RVP standard as EPA’s RVP regulations 

currently apply the standard. Certain fuels, including renewable biofuels such as butanol, 

however, do not have a net negative impact on RVP when blended with E10 at wholesale or 

retail. That is, the RVP and related emissions of the commingled blend of butanol and ethanol is 

no higher than the average RVP if the fuels had never been commingled. Thus, in these kinds of 

circumstances it may be appropriate to adopt a modified approach to applying the RVP standard 

to permit the commingling of complying E10 blends with complying butanol blends at wholesale 

and retail, as there is no overall degradation of RVP and the air quality impacts compared to 

what would occur if they were not blended. 

Today, the agency is providing some additional background on this issue and requesting 

information for use in deciding whether EPA can and should modify its RVP regulations as 

discussed below. Specifically, we are inviting comment on the ability of regulated parties to 

comply with the existing regulations by segregating biobutanol blends from ethanol blends and 

whether there is a need to change the regulations. We are also seeking comment on an 

alternative approach to applying the RVP standards to a commingled mixture of E10 with 

biobutanol or other approved gasoline additives, where the additives have characteristics such 
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72

that there is no net adverse emissions effect from the commingling. We are inviting comments 

as to whether the RVP standards can and should be applied such that the commingled mixture of 

E10 and specified blends of gasoline additives such as biobutanol is treated as complying with 

the RVP standard as long as the components of that mixture complied with the RVP standard 

prior to the commingling. This approach would provide a limited modification to how the RVP 

standards are applied, and the modification would apply for only certain fuel mixtures – those 

where the overall or net volatility of the commingled mixture is no higher than the weighted 

average of the original blends themselves, such that there is no adverse impact on emissions from 

the mixing compared to what would have occurred without such mixing. In order to assist 

parties in preparing comments, EPA is providing some additional background regarding the RVP 

program in the following paragraphs. 

A. Background and History of Volatility Regulations

Reid Vapor Pressure (RVP) is the most common measure of gasoline volatility under 

ambient conditions. In 1989, EPA began reducing gasoline volatility by limiting its RVP (54 FR 

11868, March 22, 1989)(40 C.F.R. section 80.27). Due to the presence of gasoline in certain 

markets mixed with about 10 volume percent ethanol (known as gasohol at the time), and 

because blending an alcohol into gasoline increases the volatility of the final product, EPA 

provided an additional 1 psi allowance for such blends. In the absence of the 1 psi allowance, a 

special blend stock would have been required for such blends to comply with the RVP standards

and such sub-RVP blendstocks did not exist at the time. EPA imposed the RVP standards at all 

points in the gasoline distribution system, i.e., anywhere gasoline is sold, supplied, offered for 
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73

sale or supply or transported, including service stations, refinery shipping, tanks, importer 

shipping tanks, pipeline and bulk terminals and plants. (40 C.F.R. section 80.28)(1989). In 

1990, the Agency promulgated additional regulations that further lowered the RVP standards. 

(55 FR 23658, June 11, 1990). EPA continued to provide both the 1.0 psi allowance to fuel 

blends containing about 10 volume percent ethanol, (40 C.F.R. section 80.27)(1990), and the 

requirement that RVP standards applied at all points in the distribution system.

Congress largely codified the approach taken in EPA’s RVP regulations by adding a new 

section 211(h) in the 1990 CAA amendments. Section 211(h)(1) requires EPA to set the 

maximum RVP standard during the high ozone season as 9.0 psi. EPA was to “promulgate 

regulations making it unlawful for any person during the high ozone season to sell, offer for sale, 

dispense, supply, offer for supply, transport, or introduce into commerce gasoline with a Reid 

Vapor Pressure in excess of 9.0 pounds per square inch (psi).” Lower RVP standards could be 

set for ozone nonattainment areas. See Clean Air Act section 211(h)(1). Section 211(h)(2) 

addresses the RVP standard that apply in attainment areas, and sets the standard at 9.0 psi for 

attainment areas with authority for EPA to set a more stringent RVP level under certain 

circumstances. In section 211(h)(2), Congress allowed a 1-psi waiver for E10 gasoline, stating: 

“For fuel blends containing gasoline and 10 percent denatured anhydrous ethanol, the Reid vapor 

pressure limitation under this subsection shall be one pound per square inch (psi) greater than the 

applicable Reid vapor pressure limitations established under paragraph (1).” Additionally, 

Congress enacted a conditional defense against liability for violations of the RVP level allowed 

under the 1 psi waiver by stating that “[p]rovided; however, that a distributor, blender, marketer, 

reseller, carrier, retailer, or wholesale purchaser-consumer shall be deemed to be in full 
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compliance with the provisions of this subsection and the regulations promulgated there under if 

it can demonstrate that – (A) the gasoline portion of the blend complies with the Reid vapor 

pressure limitations promulgated pursuant to this subsection; (B) the ethanol portion of the blend 

does not exceed its waiver condition under subsection (f)(4) of this section; and (C) no additional 

alcohol or other additive has been added to increase the Reid Vapor Pressure of the ethanol 

portion of this blend.” Section 211(h)(4). 

In a 1991 rulemaking, EPA modified the RVP regulations to conform to the 1990 

amendments (56 FR 64704, December 12, 1991). These regulations addressed the RVP 

standards in attainment areas, required the use of denatured anhydrous ethanol as a specific 

condition for the 1-psi waiver for fuel blends containing gasoline and from 9 volume percent to 

10 volume percent ethanol, and included a new defense against liability for violations of the RVP 

standards for such fuel blends. We made no changes to the requirement that the RVP standards 

applied at all points in the distribution system.

B. What Modification is EPA Considering to the Application of the RVP Standards to 

Certain Fuel Blends?

Gasoline and ethanol are mixed or blended after the refining process. The practice of 

blending ethanol with gasoline increases the RVP of the resulting blend by approximately 1.0 

psi. It is a non-linear relationship, most of the volatility increase occurs after just a few percent 

of ethanol have been added, with the volatility increasing more slowly as the gasoline ethanol 

blend increases to 10 volume percent. Above 10 volume percent the volatility generally does not 
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increase any more, and at even higher levels of ethanol the volatility starts to decrease again. As 

explained above, section 211(h)(4) provides a 1-psi waiver for fuel blends containing gasoline 

from 9 volume percent to 10 volume percent ethanol. The absence of such a waiver would have 

required the creation of a production and distribution network for sub-9.0 psi RVP gasoline, to 

offset the increase in volatility associated with blending ethanol into the gasoline. At the time 

the costs of producing and distributing an additional grade of this type of fuel, especially in 

consideration of the low volumes of fuel being blended with ethanol at the time, would have 

likely been prohibitive and resulted in the termination of the availability of ethanol in the 

marketplace. Thus, the 1-psi waiver facilitated the participation of ethanol in the transportation 

fuel industry while also limiting gasoline volatility resulting from ethanol blending.

But the RVP levels of gasoline actually used by consumers are dependent on the mixture 

of alcohol blends and gasoline that are commingling in either vehicle or storage tanks. 

Depending on the mixture, the resulting RVP level could be significantly higher than the average 

volatility of the fuels prior to the commingling. This is because the volatility increase when 

ethanol is added to gasoline is non-linear, with a large increase with the first few percent and 

then slowly tapering off as the concentration increases (see Illustration V.F.-4). In other words, 

mixing E10 and EO gasoline results in a net increase in the volatility of the gasoline mixture, 

compared to the average volatility that would occur absent such mixing. For example, 2000 

gallons of 10 psi E10 added to a service station tank with 8000 gallons of 9.0 psi E0 would result 

in 10,000 gallons of fuel with a volatility of approximately 10 psi. However if the fuels had not 

been mixed, the average volatility of the 10000 gallons would have been 9.2 psi. The emissions 

associated with the commingled mixture (10000 gallons at 10 psi) would be significantly higher 
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than the emissions associated with the two separate blends of 2000 gallons at 10 psi and 8000 

gallons at 9 psi. The commingling thus results in an adverse environmental impact compared to 

what would occur absent the commingling. EPA’s current RVP regulations address this adverse 

emissions impact by applying the RVP standard to the commingled mixture as a single fuel. In 

this case the commingled mixture has an RVP of 10 psi. The 1 psi waiver does not apply as the 

mixture is now 2% ethanol, not from 9 volume percent to 10 volume percent ethanol. The 

commingled mixture thus would not comply with the 9.0 psi RVP standard, effectively 

prohibiting such commingling. 

As discussed earlier, the EPAct 2005 and EISA2007 mandated increased volumes of 

renewable fuel for use in gasoline. This has resulted in the increased use of ethanol. E10 is now 

present in nearly all gasoline sold in the country. Recently, EPA granted a waiver from the 

substantially similar requirements under section 211(f)(4) for the use of E15 blends in MY2001 

and newer light-duty vehicles (See 75 FR 68094, November 4, 2010 and 76 FR 4662, January

26, 2011). EPA interpreted section 211(h) as not extending the 1 psi waiver to such blends with 

ethanol levels above 10%. Several companies are also developing and planning on introducing 

biobutanol into commerce. The characteristics of butanol are such that it could be beneficial with 

respect to volatility and vehicle evaporative emission performance. For example, 2000 gallons 

of 10 psi E10 added to a service station tank with 8000 gallons of 9.0 psi Bu12 would result in 

10000 gallons of fuel with an RVP of 9.2 psi. The RVP of the commingled blend would be the 

same as the average of the separate blends if they had never been commingled. There is no 

adverse emissions impact from the commingling of the E10 and Bu12 blends. However the 1-psi 

waiver would not be applicable because the resulting blend no longer contains from 9 volume 
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77

percent to 10 volume percent ethanol. The RVP level for the resulting blend would also be 

higher than the maximum RVP standard of 9.0 psi, making the commingled blend noncomplying 

with the RVP standard. However the available data indicates that commingling of biobutanol 

blends with ethanol blends would not result in any net increase in gasoline volatility. This is 

because biobutanol blends and gasoline containing from 9 volume percent to 10 volume percent

ethanol blend linearly from a volatility perspective, resulting in no net increase in volatility

compared to what would occur without the blending. This means that there would be no net 

degradation in environmental performance, as indicated in Illustration V.F.-4, below. 

We are inviting comment on an alternative approach to applying the RVP standard to the 

gasoline that results from commingling of E10 and certain other products like biobutanol. We 

are inviting comment as to whether the RVP standards could be applied to the commingled blend 

such that the commingled blend would be considered in compliance as long as the separate 

components of the commingled product were in compliance with the RVP standards prior to 

commingling. In effect the RVP standard would be applied to the commingled mixture by 

treating it as if it still contained two separate products, with each product required to comply 

with the RVP standard separately. This approach would be somewhat artificial but would allow 

for the commingling of specified blends of fuels, such as biobutanol, with E10 where the 

resulting commingled mixture does not result in a net increase in average RVP and associated 

emissions. This would provide more flexibility in achieving the RFS standards while avoiding 

adverse environmental impacts. This approach would provide a limited modification to the RVP 

provisions for only certain fuel blends. EPA invites comment on whether it would have the 
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78

authority under § 211(h) to adopt such an approach, and if so whether it would be appropriate to 

do so and under what conditions. 

Specifically, we would consider imposing the following conditions on such fuel blends:

(1) Each separate component must individually meet the applicable RVP standards (e.g., 10 psi 

for E10 and 9 psi for other blends).

(2) The resulting commingled mixture would have to have an RVP that is no higher than the 

weighted average of the products or components considered separately. This could occur with 

blends that blend linearly with respect to RVP (e.g., butanol).

(3) The burden would be on the retailer to show that these conditions had been satisfied. If a 

commingled product had volatility above the allowable standard, and did not have from 9

volume percent to 10 volume percent ethanol, then the fuel would be considered noncomplying 

unless the regulated party demonstrated that it met the limited conditions discussed here. The 

retailer would have to demonstrate that the conditions were met for application of this modified 

method of determining compliance. This would call for at least retaining records of the products 

received (with all required regulatory statements and indications required) and volumes of the 

products received in order to demonstrate a calculation to verify compliance with the RVP 

standard.
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(4) In situations where the RVP of retail tank samples exceed 9.0/7.8 psi, for defense purposes 

the retailer would need to test the sample for the concentration of ethanol, butanol, and any other 

applicable oxygenate in addition to the RVP level in order to allow for the calculation in (3). 

The resulting blend ratio would need to meet or demonstrate better performance reductions of 

such ratio on a linear scale as established through regulation.

Under this approach, we believe there would be no adverse environmental effects 

because such mixtures would result in no net increase in volatility. We also believe this would 

enable us to give effect to the RFS provisions that call for increased use of renewable fuels, and 

also be consistent with our rational for the treatment of gasohol at the time we promulgated the 

RVP standards. 
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Illustration V.F.-4 – Linear Plot for Commingled E10 and Bu12 Retail Fuel Blending

Source: EPA

8

8.25

8.5

8.75

9

9.25

9.5

9.75

10

0 20 40 60 80 100

RV

P (p

si)

% Bu12 Blend

Cert Gas RVP = 8.79 psi
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F. Amendments to Various RFS2 Compliance Related Provisions

We are proposing a number of changes to the RFS2 regulations. 

1. Proposed Changes to Definitions

“Responsible Corporate Officer”

The existing RFS2 regulations at sections 80.1416, 80.1451 and 80.1454, and EPA 

guidance and instructions regarding registration and reporting, frequently refer to the 

responsibilities of the “owner or a responsible corporate officer.” However, the term 

“responsible corporate officer” is not currently defined in the RFS2 regulations. We propose 

that, for purposes of the RFS2 program, a “responsible corporate officer” (RCO) means a 

corporate officer who has the authority and is assigned responsibility to provide information to 

EPA on behalf of a company. A company may name only one RCO, and the RCO may not 

delegate his/her responsibility to any other person. However, the RCO may delegate the ability

to submit information to EPA to one or more employees of the company or to one or more 

agents. The RCO remains responsible for the information submitted to EPA by any employee or 

agent. Adding a definition of RCO will codify existing practices and will assist regulated parties 

in understanding roles under the RFS2 regulation. 

“Small Refinery”
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Section 211(o)(9)(A) of the Clean Air Act provides an exemption from RFS requirements 

through 2010 for “small refineries,” defined as refineries having an average aggregate daily 

crude oil throughput for a calendar year that does not exceed 75,000 barrels. It also provides for 

possible extensions of this exemption, through individual petitions to EPA. CAA 211(o)(9)(B). 

In EPA’s March 26, 2010 regulations implementing the EISA amendments we specified in the 

regulatory definition of “small refinery” that the 75,000 bpd threshold determination should be 

calculated based on information from calendar year 2006. At the beginning of the program, 

having a single year in which to make this determination, simplified the calculations, and helped 

to ensure that all refineries were treated similarly. However, we no longer believe that it is 

appropriate that refineries satisfying the 75,000 bpd threshold in 2006 should be eligible for 

extensions to their small refinery RFS exemption if they no longer meet the 75,000 bpd 

threshold. Allowing such facilities to qualify for an exemption extension, while not allowing 

similarly sized facilities that have not grown since 2006 to qualify for an exemption, does not 

appear fair, nor does it further the objectives of the statute to target relief to only truly small 

facilities. Therefore, we propose modifying the definition of small refinery so that the crude 

throughput threshold of 75,000 bpd must apply in 2006 and in all subsequent years. We also 

propose specifying in section 80.1441(e)(2)(iii) that in order to qualify for an extension of its 

small refinery exemption, a refinery must meet the definition of “small refinery” in section 

80.1401 for all full calendar years between 2006 and the date of submission of the petition for an 

extension of the exemption. 
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We proposed that that these changes would not affect any existing exemption extensions 

under CAA 211(o)(9)(B); rather, they would apply at such time as any approved exemption 

extension expires and the refinery at issue seeks a further exemption extension. No further 

extension would be permitted unless the revised crude oil throughput specifications were 

satisfied. 

2. Provisions for Small Blenders of Renewable Fuels

The RFS2 regulations at section 80.1440 allow renewable fuel blenders who handle and 

blend less than 125,000 gallons of renewable fuel per year, and who are not obligated parties or 

exporters, to delegate their RIN-related responsibilities to the party directly upstream from them 

who supplied the renewable fuel for blending. EPA has received feedback from several parties 

to the effect that the 125,000 threshold is too low, and is a lower threshold than what industry

considers “small.” EPA seeks input on what a more appropriate gallon threshold should be. 

EPA seeks comment on the regulated community’s experience with the existing gallon threshold 

associated with the provisions. EPA may adjust the gallon threshold in the final rule based on 

further consideration of this issue and evaluation of comments received. 

3. Proposed Changes to Section 80.1450 – Registration Requirements
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We propose to add a new paragraph (h) to section 80.1450 that will describe the 

circumstances under which EPA may cancel a company registration. EPA proposes to initiate a 

process to cancel a company registration if the company has reported no activity in the EPA 

Moderated Transaction System (EMTS) under section 80.1452 for one year. EPA also proposes 

to initiate a process to cancel a company registration if a party fails to comply with any 

registration requirement of section 80.1450, if the party fails to submit any required compliance 

report under section 80.1451, if the party fails to meet the requirements related to the EPA 

Moderated Transaction System (EMTS) under section 80.1452, or if the party fails to meet the 

requirements related to attest engagements under section 80.1454. If any required report, 

including the attest engagement, is thirty (30) or more days overdue, EPA would provide written 

notice to the owner or responsible corporate officer (RCO) that it intends to cancel the 

company’s registration and would allow the company fourteen (14) days from the date of the 

letter’s issuance to respond. If there is no satisfactory response received, then EPA would cancel 

the registration. Re-registration would be possible following the standard registration 

procedures. 

We are proposing to provide a simplified electronic template format for the engineering 

review report. Once implemented, this template would be available online through EPA’s 

Central Data Exchange (CDX) and our registration flow (OTAQREG). The professional 

engineer (PE) conducting the engineering review for the facility would input data via the online 

form. This form would serve as the standard template for all engineering review reports. The 

purpose of this electronic template is to simplify the engineering review and provide a consistent 

format for which registration information is verified by a professional engineer and submitted to 
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85

EPA. The additional advantage of the PE entering the data online is that it will help EPA 

develop a database and allow quicker access to information in case a question is raised regarding 

the engineering report. Each PE submitting the engineering review would be required to obtain a 

CDX account. A draft copy of this template is provided in the docket for this rulemaking, and 

we are requesting comments for any revisions, additions, or deletions to the format and 

information requested. 

4. Proposed Changes to Section 80.1452 – EPA Moderated Transaction System 

(EMTS) Requirements – Alternative Reporting Method for Sell and Buy 

Transactions for Assigned RINs

Reporting and product transfer document (PTD) requirements, found in sections 80.1452 

and 80.1453, respectively, currently state that the reportable event for a RIN purchase or sale 

occurs on the date of transfer. Sellers must report the sale of RINs within five (5) business days 

of the reportable event via the EPA Moderated Transaction System (EMTS). Buyers must report 

the purchase of RINs within ten (10) business days of the reportable event via EMTS. The date 

of transfer is the date on which title of RINs is transferred from the seller to the buyer. Some 

buyers and sellers of assigned RINs have expressed concerns with these requirements stating 

they have difficulty determining the date of transfer since title of the renewable fuel is not 

transferred until the fuel physically reaches the buyer. Some transactions, for example those by 

rail or barge, may take several weeks, and their current accounting systems do not include a 

means for capturing the buyer’s receipt date. 
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EPA understands this concern, but also recognizes that some regulated parties have 

modified their accounting systems to address the current reporting and PTD requirements in 

RFS2. We also believe that for parties separating, retiring, and selling or buying separated RINs, 

the current reporting and PTD requirements are effective and should remain unchanged. 

Therefore, at this time EPA is not proposing to replace existing requirements, but is instead 

proposing an additional, alternative method for reporting sell and buy transactions involving 

assigned RINs only. 

The proposed alternative method for sell and buy transactions of assigned RINs would 

redefine the reportable event for both the seller and the buyer, introduce a unique identifier that 

the seller must provide to the buyer, and require the buyer to report the date of transfer. Buyers 

and sellers would need to agree on which method they would be using to report transfers of 

assigned RINs; either the current method or the alternative method. EPA believes that this 

alternative would provide the regulated community with the flexibility to address their reporting 

concerns and also provide EPA with the data necessary to effectively administer and enforce 

transactions of assigned RINs. EPA welcomes comment on this proposed alternative method for 

reporting assigned RIN buy and sell transactions.

We propose that sellers of assigned RINs under the alternative method be required to do 

the following:
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 Within five (5) business days of shipping renewable fuel with assigned RINs, report a sell 

transaction, using the alternative method, via EMTS;

 Include in the EMTS sell transaction report other required information per section

80.1452; and

 Provide a PTD to the assigned RIN buyer with a unique identifier, also reported via 

EMTS, in addition to the information in section 80.1453. The date of transfer is not 

required for the alternative method.

We propose that buyers of assigned RINs under the alternative method be required to do 

the following:

 Within five (5) business days of receiving a shipment of renewable fuel with assigned 

RINs, report a buy transaction, indicating use of the alternative method, via EMTS;

 Include in the EMTS buy transaction report other required information per section

80.1452;

 Include in the EMTS buy transaction report the unique identifier provided by the seller;

and

 Include in the EMTS buy transaction report the date the renewable fuel was received, 

i.e. the date of transfer.

If this proposed alternative method is finalized, the EMTS would be modified to accept 

such transactions. EPA would provide additional instruction and guidance at the time of the new 

EMTS version release. EPA invites comment on all aspects of this proposal. 
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5. Proposed Changes to Section 80.1463 –Confirm that Each Day an 

Invalid RIN remains in the Marketplace is a Separate Day of Violation.

Preventing the generation and use of invalid RINs and encouraging rapid retirement and 

replacement of invalid RINs is crucial to the integrity of the RFS2 program. The RFS 

regulations include various provisions related to prohibited acts and liability for violations. 

Section 80.1460(a) sets forth the prohibited acts for the renewable fuels program. Section 

80.1460(b)(2) prohibits parties from creating or transferring invalid RINs. Section 80.1461(a) 

states that the person who violates a prohibited act is liable for the violation of that prohibition. 

Section 80.1461(b) provides the liability provisions for failure to meet other provisions of the 

regulations. The penalty provisions of the regulations at section 80.1463(a) state that any person 

who is liable for a violation under section 80.1461 is subject to a civil penalty as specified in 

sections 205 and 211(d) of the Clean Air Act (CAA), for every day of each such violation and 

the amount of economic benefit or savings resulting from each violation. Section 80.1463(c) 

provides that “any person...is liable for a separate day of violation for each day such a 

requirement remains unfulfilled.” 

EPA interprets the statutory and regulatory penalty provisions to give the Agency the 

authority to seek the penalties against parties generating, transferring or causing another person 

to generate or transfer invalid RINs for each day subsequent to the party’s action that an invalid 

RIN is available for sale or use by a party subject to an obligation under the RFS2 program to 

acquire and retire RINs. For example, for a RIN generator, this time period typically runs from 

the date of invalid RIN generation until either corrective action is taken by the RIN generator to 
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89

remove the invalid RIN from the marketplace or a party uses the RIN to satisfy an RVO or other 

requirement to retire RINs (such as would apply under today’s proposal to exporters of 

renewable fuel or parties using fuel produced as renewable fuel for a use other than as 

transportation fuel, heating oil or jet fuel). This is consistent with the CAA approach of 

assessing penalties for every day of a violation, consistent with EPA’s historic approach under 

the fuels regulations (See Section 80.615), and will encourage renewable fuel producers that 

generate invalid RINs to promptly take corrective action. 

We are proposing to amend section 80.1463 to more explicitly incorporate EPA’s 

interpretation of these penalty provisions into the regulations. The amendments would state that 

any person liable for a violation of section 80.1460(b) for creating or transferring an invalid RIN, 

or for causing another person to create or transfer and invalid RIN, is subject to a separate day of 

violation for each day that the invalid RIN remains available for use for compliance purposes, 

and EPA has the authority to seek the maximum statutory penalty for each day of violation. EPA 

will apply the statutory factors in sections 211(c) and 205(b) of the CAA to evaluate the 

appropriate penalties for each violation on a case by case basis. 

6. Proposed Changes to Section 80.1466 – Require Foreign Ethanol Producers, Importers 

and Foreign Renewable Fuel Producers that Sell to Importers to be Subject to U.S. 

Jurisdiction and Post a Bond.

The current regulations include requirements that foreign renewable fuel producers that 

generate RINs agree to be subject to a number of additional requirements at section § 80.1466, 

including, but not limited to, designation, foreign producer certification, product transfer 

document, load port independent testing and producer identification, submission to U.S. 
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jurisdiction and posting of a bond. We are proposing to require the same requirements for 

foreign renewable fuel producers, and foreign ethanol producers that produce biofuel for which 

importers ultimately generate RINs, and for importers of renewable fuel.

 In order to evaluate whether a fuel qualifies as RIN generating renewable fuel (including 

determining the proper renewable fuel category and RIN type for the imported fuel), EPA must 

be able to evaluate the feedstocks and processes used to produce the renewable components of 

the fuel. This is a particular challenge for fuel produced at foreign facilities; unlike our other 

fuels programs, EPA cannot determine whether a particular shipment of renewable fuel is 

eligible to generate RINs under the RFS program by testing the fuel itself. Furthermore, 

significant opportunity for fraud and non-compliance with the regulations exists where EPA is 

not able to ensure that RINs entering the U.S. are valid, and where enforcement of the 

regulations may be hampered due to a facility’s foreign location. We believe that the same 

safeguards that apply to foreign RIN generating renewable fuel producers should apply to other 

foreign producers whose product is used by importers to generate RINs, and to those importers 

themselves. Accordingly, we propose that foreign renewable fuel producers and foreign ethanol 

producers who do not themselves generate RINs for their product, and importers of renewable 

fuel, be required to comply with the safeguards of section 80.1466. Given the challenges 

associated with EPA’s ability to determine whether a fuel qualifies as RIN generating renewable 

fuel, and the potential for fraud, we believe these additional safeguards are necessary for all 

foreign produced renewable fuel, regardless of who generates the RINs. However, we seek 

comment on the reasonability of expanding these additional requirements onto foreign renewable 

fuel producers, and foreign ethanol producers that produce biofuel for which importers 

ultimately generate RINs, and for importers of renewable fuel. We further propose to amend 
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section 80.1426(a)(4) to prohibit importers from generating RINs for renewable fuel imported 

from a foreign renewable fuel producer or foreign ethanol producer, unless and until the foreign 

renewable fuel producer or foreign ethanol producer has satisfied all requirements of section

80.1466. 

7. Proposed Changes to Section 80.1466(h) – Calculation of Bond Amount for 

Foreign Renewable Fuel Producers, Foreign Ethanol Producers and

Importers

EPA proposes two changes to section 80.1466 regarding calculation of bonds. EPA 

proposes to amend the procedures for calculating the bond amount for foreign renewable fuel 

producers, foreign ethanol producers and importers to require that the bond amount be the larger 

of: (1) one cent times the largest volume of renewable fuel produced by the foreign producer and 

exported to the United States, in gallons, during a single calendar year among the five preceding 

calendar years, or the largest volume of renewable fuel that the foreign producers expects to 

export to the Unites States during any calendar year identified in the Production Outlook Report 

required by section 80.1449, or (2) the sum of the following calculation for each RIN type: 0. 25

times the largest volume of renewable fuel produced by the foreign producer and exported to the 

United States, in gallons, during a single calendar year among the five preceding calendar years, 

or the largest volume of renewable fuel that the foreign producers expects to export to the Unites 

States during any calendar year identified in the Production Outlook Report required by section 

80.1449, times a “ RIN multiplier D code” established by EPA in the regulations. The 
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proposed “RIN multiplier D codes” vary from $.02 for D code 6 to $1.30 for D code 4. When 

the original renewable fuels standard regulations (RFS1) were written, an RFS1 RIN was worth 

pennies. With the implementation of RFS2, the price of some RINs has increased significantly, 

in part because of the demand for certain categories of fuel such as biomass-based diesel. In 

order to keep up with these market conditions, the bond amount needs to be increased; a penny 

per gallon of fuel may no longer be a fair valuation of a foreign renewable fuel producer’s 

potential penalty for RFS violations. Bonds are used to satisfy any judicial judgment that results 

from an administrative or judicial enforcement action for conduct in violation of this subpart. 

Therefore, we propose to amend section 80.1466(h)(1) to include the calculation described 

above, that reflects current market valuation for different types of RINs. We seek comment on 

whether the proposed bond calculation procedures are appropriate, and in particular whether they

are sufficiently large to cover potential liability. . 

 

EPA also proposes to amend paragraph (h) of section 80.1466 to be consistent with 

paragraph (j)(4), which prohibits generating RINs in excess of the number for which the bond 

requirements have been satisfied. Paragraph (h) regulates the size of the bond a foreign 

renewable fuel producer must post in order to generate RINs. This formula takes into account 

the volume of renewable fuel a foreign renewable fuel producer has exported or intends to export 

to the United States. Section 80.1466(h) states, in part: “If the volume of renewable fuel 

exported to the United States increases above the largest volume identified in the Production 

Outlook Report during any calendar year, the foreign producer shall increase the bond to cover 

the shortfall within 90 days.” This conflicts with the stricter language in paragraph (j)(4) of the 

same section, which prohibits a foreign producer of renewable fuel from generating RINs in 
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93

excess of the number for which the bond requirements of section 80.1466 have been satisfied. 

EPA interprets the stricter provision at section 80.1466(j)(4) to be controlling, and we propose to 

change the language in section 80.1466(h) accordingly.

8. Potential Changes Related to “Renewable Process Electricity” under 

Various Sections

Since the promulgation of the March 26, 2010 RFS2 rule, we have received petitions 

from a number of renewable fuel producers that are using or intend to use electricity that is 

derived from wind, solar, geothermal, biogas or hydrokinetic energy, as power for process units 

and equipment. These petitioners requested that EPA take into account the resultant reduction in 

the use of fossil fuels at these facilities and associated lower lifecycle greenhouse gas emissions 

when we conduct our analysis of these fuels. We are today soliciting comment on whether and 

how renewable electricity should be allowed in the calculations of lifecycle GHG emission under 

the RFS program. The renewable attributes of renewable electricity are currently traded as 

“renewable energy certificates” (RECs), so we are taking comment on whether RECs could be 

used within the RFS program to demonstrate and track the purchase and use of renewable 

electricity for process uses by a biofuels producer. We believe there are three possible ways that 

renewable electricity could help to reduce the overall lifecycle GHG emissions associated with 

renewable fuel production: (1) a renewable fuel producer could generate renewable electricity on 

the site of their facility to meet their process electricity needs; (2) a renewable fuel producer 

could purchase renewable electricity from a utility or retail electricity provider, in which case 
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purchase of a REC is bundled with purchase of the electricity, or; 3) a renewable fuel producer 

could purchase unbundled RECs independent of their purchase of electricity.

RECs are generally used for compliance with various voluntary and mandatory 

renewable portfolio standard (RPS) programs at the state level, as well as to meet consumer 

demand for renewable electricity. A REC represents the renewable attributes of 1 megawatthour (MWh) of electricity and may be sold separately from the electricity itself. Over the last ten 

years, REC tracking systems have been developed to issue RECs to producers of renewable 

electricity. REC tracking systems issue uniquely numbered certificates for each MWh of 

renewable electricity generated, track the ownership of certificates as they are traded, and retire 

certificates once they are used.

In this rulemaking, we are presenting a conceptual framework and regulatory language 

for comment that would, if included in finalized regulations, allow producers a mechanism to 

qualify and to account for the use of renewable process electricity at their facility. Accordingly, 

we are inviting comment on possible regulatory terms and conditions that could be useful in the 

future if EPA approves renewable fuel production pathways that envision the use of renewable 

electricity to power process units and equipment in renewable fuel production. EPA is aware 

that there is no current allowance in the regulations for producers to receive credit in approved 

renewable fuel production pathways for the use of process electricity derived from renewable 

sources. However, if the verification system articulated below were finalized, it could potentially

be used by producers who petition for (pursuant to section 80.1416) and receive EPA approval of 

their specific fuel pathways that use renewable process electricity. Alternatively, EPA could 
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approve purchase of renewable process electricity as another type of advanced technology to be 

used for compliance with broadly applicable pathways (e.g., sorghum ethanol produced at a 

facility that uses biogas for process energy and RECs to cover all of the electricity purchased 

from the grid.) EPA has a number of enforcement and compliance concerns, discussed at the end 

of this section, and may not include this concept or draft language in the final regulatory package 

if these concerns, or others that may be raised through public comment, cannot be adequately

addressed.

EPA invites comment on the possibility of allowing renewable fuel producers to 

demonstrate reductions in lifecycle GHG emissions through the acquisition and retirement of 

RECs that are enrolled in a REC tracking system. EPA could then take into account the use of 

renewable process electricity in assessing the GHG performance of renewable fuel production 

pathways. For example, EPA might determine that a particular renewable fuel pathway

achieves a 50% GHG reduction as compared to baseline fuels if 90% of their electricity for 

processes and equipment is derived from renewable electricity sources. Producers acquiring and 

retiring a sufficient number of RECs to meet the 90% requirement could generate advanced 

biofuel RINs (assuming other definitional requirements were satisfied). Under the scenario 

outlined here, if the facility generated the electricity on-site, they would need to generate RECs 

and not sell the RECs to any other party. If the facility purchased RECs, either bundled with or 

unbundled from purchase of electricity, the RECs may not be sold to or claimed by any other 

party.
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EPA also solicits comments on an alternative approach in which only renewable 

electricity that is generated on-site at the biofuel production facility could be used to reduce LCA 

GHG emissions associated with a renewable fuel under the RFS program. For this approach, we 

invite comments about whether the facility should be required to generate and retire RECs or 

instead should not generate RECs for that electricity.

To facilitate understanding of this concept and help the public provide meaningful 

comments, EPA solicits comment on some possible regulation amendments that could be used to 

implement a REC-based system for acknowledging the use of renewable process electricity in 

the RFS program. 

Potential Definition Changes:

Renewable process electricity means electricity derived exclusively from wind, solar, 

geothermal, biogas as defined in § 80.1401, or hydrokinetic energy resources that are used at a 

renewable fuel production facility to provide power to process units or process equipment. 

Renewable energy certificate (REC) means a tradable commodity that represents the 

technology and environmental attributes of 1 megawatt-hour (MWh) of electricity generated 

from renewable energy resources. RECs are also known as renewable energy credits, green tags, 

green energy certificates, or tradable renewable certificates.
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REC tracking system means a state or regionally managed electronic database that (a) 

issues a uniquely numbered renewable energy certificate for each MWh of electricity generated 

by a generating unit registered in the system, (b) tracks the ownership of certificates as they are 

traded, (c) retires the certificates once they are used or claims are made based on their attributes 

or characteristics, (d) is available to any user who registers and maintains an account, and (e) 

makes public its operating rules.

Potential Additions to Section 80.1426:

For purposes of verification, renewable process electricity defined in section 80.1401 that is 

used for process power at a renewable fuel production facility and not as a renewable fuel for 

RIN generation, all conditions below apply. 

(i) For renewable process electricity produced at the facility, all of the following conditions 

must be met:

(A) The quantity of renewable process electricity produced must be metered;

(B) The renewable process electricity must generate renewable energy certificates (RECs), as 

defined in §80.1401;

(C) The RECs generated must be issued by a tracking system, as defined by §80.1401; and

(D) The facility must not sell any RECs used for compliance under RFS2 to any other 

parties.

(ii) For renewable process electricity that has been loaded onto a shared power grid, all of 

the following conditions must be met:
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(A) The producer has entered into a written contract for the procurement of RECs either in 

association with their purchase of renewable electricity (“bundled”) or independent of their 

purchase of electricity (“unbundled”);

(B) The RECs were issued by a tracking system; and

(C) The RECs were ultimately sold to the renewable fuel production facility, and may not be 

claimed by any other party.

(iii) The renewable process electricity cannot be counted as process power at a facility if any 

other party relied upon the same RECs for the creation of RINs.

Potential Additional Registration Requirements in Section 80.1450:

For renewable process electricity used to power process units or process equipment, provide 

all of the following information:

(1) The name and location of the generating unit at which the renewable energy certificates 

(RECs), as defined in §80.1401, are to be produced, and the type of renewable electricity to be 

generated;

(2) The name of the tracking system(s), as defined in §80.1401, in which the RECs are to be 

issued;

(3) Copies of all contracts as stipulated in §80.1426(f); and

(4) Estimates of the total amount of electricity to be used, the total amount of grid electricity

to be purchased, the total number of RECs to be generated or purchased, and a calculation of the 

percent of total process electricity use to be provided from each type of renewable process 

electricity.
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Potential Additional Reporting Requirements in Section 80.1451:

Producers or importers of renewable fuel produced at facilities that use renewable process 

electricity as described above, shall report the total number of renewable energy certificates, as 

defined in §80.1401, acquired by the renewable fuel production facility, the total amount of 

electricity used, the total amount of grid electricity purchased, and a calculation verifying the 

percent of total process electricity derived from renewable process electricity.

Potential Additional Recordkeeping Requirements in Section 80.1454:

A renewable fuel producer that uses a pathway for the production of renewable fuel that 

requires the use of renewable process electricity shall keep all of the following additional 

records:

(1) Documents demonstrating the megawatt-hours (MWh) of renewable process electricity

relied upon that were generated at the facility, if applicable.

(2) Contracts and documents memorializing the generation or purchase of renewable 

electricity credits (RECs), as defined in §80.1401, by the renewable fuel production facility, 

including the certificate numbers of the RECs.
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(3) Affidavits from the renewable electricity producer and all parties that held title to the 

RECs confirming that the environmental attributes of the renewable process electricity relied 

upon under §80.1426(f) were used for process electricity at the renewable fuel producer's 

facility, and for no other purpose. The renewable fuel producer shall create and/or obtain these 

affidavits at least once per calendar quarter. 

(4) Documents demonstrating the total amount of grid electricity purchased and calculations 

showing the percent of total electricity usage provided by renewable process electricity.

(5) Such other records as may be requested by the Administrator.

EPA is seeking comment on a number of issues related to the use of RECs for RFS purposes 

and on the possible regulatory provisions that are described above that could help to implement 

such a system. First, EPA solicits comments about whether we should allow purchase of RECs 

from off-site renewable electricity producers to be used for compliance under RFS or, instead, 

should allow only use of renewable electricity produced on-site at the fuel production facility. If 

EPA should only allow on-site production, we request comments about whether the renewable 

electricity production should be tracked through the generation and retirement of RECs. If not, 

we request comments about alternative types of regulations that would verify the production and 

use of this electricity. Second, we request comments about whether the approach described 

above would be sufficient to ensure that double counting does not occur, e.g., would it ensure 

that RECs used in the RFS program would not be sold to multiple parties? If the approach 

described above would not be sufficient, what alternative requirements could be considered to 
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ensure double counting does not occur. Third, EPA requests comments about whether we should 

restrict RECs used in the RFS program from also being used for compliance with state or 

voluntary programs. If such restrictions should be used, we also request suggestions of the types 

of information and documentation that could be used to verify that RECs used in the RFS 

program are not also used for compliance with state or voluntary programs. Fourth, we invite 

comments about whether EPA should set a maximum threshold for the number of RECs a 

facility may use for compliance under RFS. For example, should we only allow a facility to 

purchase RECs equivalent to the amount of process electricity used at the facility? If the EPA 

should use such restrictions, we also request comments suggesting what threshold would be most 

appropriate. Similarly, if a company generates renewable electricity on-site, should EPA 

consider any GHG benefits from electricity production in excess of the process electricity usage 

of the facility; in other words, should the facility be assigned a credit for any excess renewable 

electricity it sells into the power grid? Finally, if we allow use of RECs, EPA also solicits 

comment on the extent to which we should treat RECs from the different types of electricity 

fungibly for purposes of the RFS program. In conducting lifecycle GHG analyses for facilities 

using renewable process electricity, should EPA (a) treat all types of renewable process 

electricity as having zero GHG emissions, (b) use separate emissions factors for each type of 

renewable process electricity (e.g., solar, wind), or (c) use the same weighted average value for 

lifecycle GHG emissions for all sources of renewable process electricity. Adoption of option (b) 

would require different numbers of RECs for compliance depending on the types of renewable 

electricity used to generate the RECs. If a non-zero value should be used for GHG emissions, 

EPA solicits data demonstrating the lifecycle GHG emissions for different types of renewable 

electricity.
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 As mentioned above, EPA has a number of concerns about how well we could implement 

and enforce a REC-based system for accounting for the use of renewable process electricity in 

the RFS program. Our concerns center on the possibility that RECs could be used for 

compliance in situations in which the stated amount of renewable electricity may never have 

been generated or the RECs may have been sold to more than one party. We may not finalize 

this section of the regulations if we cannot adequately verify that such problems will not occur 

under this system. We are soliciting suggestions about how to best verify that only valid RECs 

are used. We particularly invite information about the verification methods used in existing 

tracking systems and whether these controls are adequate to avoid fraud or, alternatively, 

whether and how these systems could be modified to make them adequate to ensure compliance. 

Similarly, we request comments addressing whether the use of third-party certification of the 

renewable electricity would sufficiently ensure that the RECs used are valid. We request 

comment on whether EPA should review and approve individual REC tracking systems before 

relying on RECs issued and tracked by them for RFS2 purposes and, if so, what criteria EPA 

should consider in considering them for approval. Furthermore, EPA requests comments about 

whether we should restrict the types of RECs that are eligible for use under the RFS program in 

order to ensure that use of RECs results in lifecycle GHG benefits. Additionally, EPA requests 

comments about the possible impacts of linking biofuel RIN and renewable energy REC 

markets. We also request comments describing any other system that could be used to ensure 

that the renewable process electricity used for RFS purposes was indeed generated from 

renewable sources and was sold only to the renewable fuel-producing facility. For any of these 

scenarios, we also request suggestions of the types of documentation that would be required to 
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verify compliance. Finally, we solicit comment on the extent to which REC tracking systems 

exist in foreign countries and, if so, whether there would be any particular problems associated 

with relying on RECs or similar instruments issued by such systems for purposes of verifying the 

use of renewable process electricity in the RFS program.

9. Proposed Changes to Facility’s Baseline Volume to allow “Nameplate

Capacity” for Facilities not Claiming Exemption from the 20% GHG

Reduction Threshold

As a requirement of registration under the RFS2 program, each renewable fuel producer 

and foreign ethanol producer must establish and provide documents to support its facility’s

baseline volume as defined in section 80.1401. This is either the permitted capacity or, if 

permitted capacity cannot be determined, the actual peak capacity of a specific renewable fuel 

production facility on a calendar year basis. After the promulgation of the March 26, 2010 RFS2

rule, we have received many requests from companies to allow them to use their nameplate or 

“design” capacity to establish their facility’s baseline volume due to either the facility being 

exempt from obtaining a permit, and thus not able to determine their permitted capacity, or the 

facility not starting operations, or not being operational for a full calendar year to produce actual 

production records to establish actual peak capacities. Because the regulations currently only 

allow a facility’s baseline volume to be established by a limit stated in a permit or actual 

production records for at least one calendar year, facilities that had neither a permit or sufficient

production records had difficultly registering under the RFS2 program. To allow facilities that 
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fall under this predication to register under the RFS2 program, we are proposing in this 

rulemaking to allow a facility to use its “nameplate capacity” to establish its facility’s baseline 

volume for the purposes of registration, only if 1) the facility does not have a permit or there is 

no limit stated in the permit to establish their permitted capacity, and 2) has not started 

operations or does not have at least one calendar year of production records, and 3) does not 

claim exemption from the 20 percent GHG threshold under § 80.1403. Due to the complexity of 

the exemption provision provided under § 80.1403, and the added flexibility that facilities 

claiming this exemption are allotted under the program, we are not proposing to extend this 

option to facilities claiming an exemption under § 80.1403. Additionally, by this stage in the 

RFS2 program, the facilities that would qualify for registration under § 80.1403 would be very

few, if any. This proposal would revise the definition of baseline volume to include “nameplate 

capacity,” add a new definition for “nameplate capacity” to § 80.1401, and include conforming 

amendments to the registration requirements of §80.1450. 

G. Minor Corrections to RFS2 Provisions

We are proposing a number of corrections to address minor definitional issues that have 

been identified as we have been implementing the RFS2 program.

Renewable Biomass
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We propose to amend the definition of “renewable biomass” in section 80.1401 to make 

clear that biomass obtained in the vicinity of buildings means biomass obtained within 200 feet 

of the buildings. The preamble for the March 26, 2010 RFS2 final rule cites the distance of 200 

feet (See 75 FR 14696), but EPA did not include a reference to this value in the regulations. We 

believe doing so would provide additional clarity to the regulations. 

English Language Translations

We propose to add a new paragraph (i) to section 80.1450 to state that any registration 

materials submitted to EPA must be in English or accompanied by an English language 

translation. Similarly, we propose to add a new paragraph (h) to section 80.1451 that will state 

that any reports submitted to EPA must be in English or accompanied by an English language 

translation and add a new paragraph (q) to section 80.1454 that will state that any records 

submitted to EPA must be in English or accompanied by an English language translation. The 

translation and all other associated documents must be maintained by the submitting company 

for a period of five (5) years, which is already the established time period for keeping records 

under the existing RFS2 program.

Correction of Typographical Errors 

We propose to correct various typographical errors in section 80.1466. Specifically, we 

propose to amend paragraph (o) to correct a typographical error in the last sentence of the 

affirmation statement, by changing the citation from §80.1465 to §80.1466. We also propose to 
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amend paragraph (d)(3)(ii) to correct a typographical error. The current regulation cites section 

80.65(e)(2)(iii), which does not exist. The correct citation is to section 80.65(f)(2)(iii). 

VI. Amendments to the E15 Misfueling Mitigation Rule 

We propose the following minor corrections and other changes to the E15 misfueling 

mitigation rule (E15 MMR) found at 40 CFR Part 80, subpart N. 

A. Proposed Changes to Section 80.1501 – Label

We propose to correct several minor errors in the description of the E15 label required by 

the E15 MMR at section 80.1501, including corrections in the dimensions of the label and 

ensuring that the word “ATTENTION” is capitalized. The Agency intended the label required 

by the regulations to look identical to that pictured in the Federal Register notice for the final 

E15 MMR (see 76 FR 44406, 44418, July 25, 2011).

B. Proposed Changes to Section 80.1502 – E15 Survey

We are proposing two changes to the survey requirements found at section 80.1502. 

First, we propose to clarify that E15 surveys need to sample for Reid vapor pressure (RVP) only
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during the high ozone season as defined in section 80.27(a)(2)(ii) or during any time RVP 

standards apply in any state implementation plan approved or promulgated under the Clean Air 

Act. EPA did not intend to require RVP sampling and testing during the rest of the year, when 

RVP standards do not apply. 

Second, we propose to change when the results of surveys that detect potential 

noncompliance must be reported to the Agency. As originally drafted, the regulations require the 

independent survey association conducting a survey to notify EPA of potentially noncompliant 

samples within 24 hours of the laboratory receiving this sample(See 76 FR at 44423, July 25, 

2011). EPA has since learned that more time may be needed for reporting of noncompliant 

samples since it may take several days for analysis of the sample to be completed. We are 

therefore requiring that noncompliant samples be reported to EPA within 24 hours of being 

analyzed. 

C. Proposed Changes to Section 80.1503 – Product Transfer Documents 

EPA is proposing certain minor changes to the product transfer document (PTD) 

requirements found at section 80.1503. Specifically, we are proposing to allow the use of 

product codes for conventional blendstock/gasoline upstream of an ethanol blending facility,

since historically, the codes have been allowed to be used for conventional blendstock/gasoline 

upstream of an ethanol blending facility in other fuels programs. This was an omission from the 

original regulation. 
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We are also seeking comment on potential ways of streamlining the PTD language 

required at section 80.1503.

D. Proposed Changes to Section 80.1504 - Prohibited Acts

EPA is slightly rewording section 80.1504(g) to state that blending E10 that has taken 

advantage of the statutory 1.0 psi RVP waiver during the summertime RVP control period with a 

gasoline-ethanol fuel that cannot take advantage of the 1.0 psi RVP waiver (i.e. a fuel that 

contains more than 10.0 volume percent ethanol (e.g., E15) or less than 9 volume percent 

ethanol) would be a violation of the E15 MMR. As originally written, the language does not 

clearly describe the prohibited activity (see 76 FR 44435, 44436, Jult 25, 2011). 

E. Proposed Changes to Section 80.1500 -- Definitions 

On August 17, 2011, the National Petroleum Refiners Association, now called American 

Fuel and Petrochemical Manufacturers (AFPM), filed a petition for reconsideration with the 

Agency under CAA section 307(d)(7)(B) asking EPA to reconsider certain portions of the E15 

MMR. A copy of the petition has been placed in the docket. The petition fundamentally focuses 

on one issue - AFPM expressed concern that the Agency had defined E10 and E15 in the E15 

MMR in a way that would change how ethanol concentrations are determined for regulatory
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purposes. Today we grant AFPM’s request for reconsideration of this issue as explained in their 

August 17, 2011 petition. As explained below, while EPA did not intend the definitions of E10 

and E15 in the E15 MMR to have this effect, we are proposing changes to the regulations to 

avoid this perceived impact. 

On April 6, 1979, fuel containing 90% unleaded gasoline and 10% ethyl alcohol received 

a waiver under section 211(f)(4) by operation of law (see 44 FR 20777, April 6, 1979). Later, 

EPA issued an interpretative ruling that stated the April 6, 1979 waiver covered gasoline-ethanol 

blends that contained up to 10 vol% ethanol content (see 47 FR 14596, April 5, 1982). Finally, 

in the context of regulations limiting the Reid vapor pressure (RVP) of gasoline, EPA has 

defined E10 as gasoline containing between 9 and 10 volume percent ethanol. Under the RVP 

regulations and the Clean Air Act, the RVP of E10 is allowed to be 1 pound per square inch (psi) 

higher than it is for gasoline or gasoline-ethanol blends containing less than 9 and more than 10 

vol% ethanol (often referred to as the “1.0 psi waiver”).

In the E15 MMR, EPA defined E10 as gasoline containing at least 9.0 and no more than 

10.0 vol% ethanol and defined E15 as a gasoline-ethanol blend containing greater than 10.0 and 

no more than 15.0 vol% ethanol. EPA included those definitions in the E15 MMR so that fuels 

blended to contain more than 10.0 vol% ethanol were subject to the misfueling mitigation 

requirements for E15. After publication of the E15 MMR, stakeholders including AFPM 

expressed concern that by defining E10 as E10.0, the Agency may have effectively made the 

ethanol concentration limits specified in the E10 and the E15 waiver decisions and the RVP 
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regulations more stringent, which in turn would impact whether a party must comply with the 

E15 MMR requirements and whether a fuel qualifies for the RVP 1.0 psi waiver. 

In its petition, AFPM noted that under existing EPA regulations at 40 CFR 80.9, the 

results of compliance testing for the ethanol concentration in gasoline are “rounded down” when 

the results indicate that gasoline-ethanol fuel may contain slightly more than 10 vol% ethanol. 

AFPM further stated that in view of this rounding procedure, fuel that compliance testing 

indicates has an ethanol concentration of between 10.0 and 10.4 should be considered E10. 

AFPM argued that the E15 MMR definition of E10 as containing no more than 10.0 vol% 

ethanol constituted a “substantive change” to the proposed E15 MMR that would also alter the 

implementation of other EPA fuels regulations without a required rulemaking. 

As part of the E15 MMR proposed rule, we identified prospective responsible parties for 

each misfueling mitigation measure, including requirements related to labeling E15 fuel 

dispensers, compliance surveys, and product transfer documents. We received a number of 

comments from many affected stakeholders, including AFPM, that asked us to clarify which 

party or parties would be responsible for each misfueling mitigation measure and when each 

party or parties would be subject to those requirements. In the final E15 MMR, we added the 

significant digit to the definitions of E10 and E15 in order to provide a delineation between E10 

and E15 and consequently the parties subject to one or more of the E15 misfueling mitigation 

measures. 
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AFPM argued in their petition that by defining E10 as containing no more than 10.0 vol%

ethanol, EPA effectively made a substantive change to the way test results used for determining 

compliance with fuel requirements are rounded. For example, for a gasoline-ethanol blend to be 

considered E10, it could no longer contain up to 10.4 vol% ethanol; it could only contain up to 

10.04 vol% ethanol. AFPM asserted that there is a tolerance for blending ethanol that allows 

blends containing up to 10.4 vol% ethanol to be considered E10. While we do not agree that 

there is a blending tolerance for ethanol, we agree that test results are rounded utilizing the 

procedures identified in section 80.9 when compared to applicable standards, in this case the 

ethanol concentrations specified in the E10 and the E15 waivers. 

The Agency specifically addressed the issue of blending tolerances versus testing 

tolerances for gasoline-ethanol blends in the RFS2 NPRM.43 At the time, some stakeholders had 

suggested that the implementation of a blending tolerance for the ethanol content of gasoline 

could be allowed to help obligated parties satisfy RFS requirements without the need for a CAA 

section 211(f)(4) waiver. In response, we argued that although the test methods used to measure 

ethanol concentration (ASTM D 5599 and ASTM D 4815) include some variability, ethanol is 

different than other fuel properties and components that are controlled in other fuel programs.44 

Fuel properties such as RVP, and components such as sulfur and benzene, are natural 

characteristics of gasoline as a result of the chemical nature of crude oil and the refining process. 

Their levels or concentrations in gasoline are unknown until measured and are dependent upon 

the accuracy of the test method. In contrast, ethanol is intentionally added in known amounts 

using equipment designed to ensure a specific concentration within a very narrow range. Parties 

 

43 See 74 FR 25018 (May 26, 2009).

44 See 74 FR 25018 (May 26, 2009).
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that blend ethanol into gasoline normally have precise control over the final concentration. 

Therefore, a blending tolerance for ethanol would not be appropriate. During the comment 

period for the RFS2 NPRM, EPA received a number of comments from stakeholders that argued 

that the volume percentage of ethanol in gasoline is readily determined using very accurate 

volumetric ratio blending facilities now in place at most blending terminals; therefore, the 

Agency should not allow a blending tolerance. In the final RFS rule, we did not include a 

blending tolerance for ethanol blends.45

We continue to believe that blending tolerances for ethanol are not appropriate, and the 

definitions of E10 and E15 in the E15 MMR are consistent with this view. The E10 waiver is for 

gasoline containing “up to” 10 vol% ethanol, not for gasoline containing “up to” 10.4 vol%

ethanol, and the E15 partial waivers are for fuel designed to contain “greater than 10 vol% 

ethanol and not more than 15 vol% ethanol.” In the case of both waivers, the “10” and the “15” 

are exact numbers, not approximations, and they express how much ethanol can be lawfully

added to fuel. Testing by the Department of Energy utilized in making the E15 partial waiver 

decisions was blended as precisely as possible to contain the relevant percentage of ethanol, not 

that percentage plus “0.49”. Testing for registration of E10 and E15 fuel and fuel additives 

under 40 CFR part 79 was also done with fuels blended as precisely as possible to contain the 

relevant percentage of ethanol. Similarly, EPA regulations provide that only fuel with an ethanol 

concentration of between 9 and 10 vol%, not more or less, may lawfully use the statutory 1.0 psi 

RVP waiver.

 

45 See 75 FR 14762-14764 (March 26, 2010).
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At the same time, we did not intend to change the definition of E10 in a way that impacts 

the rounding of test results for ethanol concentrations.46 If a manufacturer blends in a way

designed to result in a gasoline-ethanol fuel containing no more than 10.0 vol% ethanol, but 

compliance testing indicates a concentration of 10.4 vol%, we will still round down the test 

result in accordance with procedures in section 80.9. The purpose of the E15 MMR definitions 

state that if a manufacturer blends ethanol into gasoline in a way designed to result in a gasolineethanol fuel containing greater than 10.0 vol% and no more than 15.0 vol% ethanol, it will be 

subject to applicable E15 MMR requirements. For example, bills of lading for an E10 fuel 

manufacturer that indicates the manufacturer has purchased and blended more ethanol than 10.0 

vol% ethanol may indicate that a fuel does not meet the definition of E10 for E15 MRR 

purposes. 

AFPM also argued that the E15 MMR definitions of E10 would alter the implementation 

of other EPA fuels regulations without a required rulemaking, specifically the application of the 

1.0 psi RVP waiver to E10. Since the Agency intended the E15 MMR definition of E10 to only

apply for purposes of determining the applicability of E15 MMR requirements, the Agency does 

not believe these definitions affect the implementation and enforcement of others fuels programs, 

including the applicability of the 1.0 psi RVP waiver. The introductory language to the 

definitions at 40 CFR part 80, subpart N clearly states that definitions in section 80.1500 are 

“[f]or purposes of this subpart only.” 

 

46 For an explanation of the rounding procedures outlined in §80.9 and the rationale the Agency

used to adopt those procedures, see 71 FR 16496 (April 3, 2006).
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In order to clarify that these definitions only apply in the context of the E15 MMR, EPA 

is proposing to add a new section 80.1509, which contains language that clearly states that when 

ethanol concentrations are measured for compliance testing purposes for 40 CFR, Part 80, 

Subpart N, the applicable ethanol concentration value will be rounded using the rounding 

procedures at section 80.9. EPA is also proposing new prohibited acts language in section 

80.1504 that should make it clear that only those parties that (1) produce gasoline, blendstocks 

for oxygenate blending (BOBs), or ethanol designed to be used in the manufacture of E15 as 

currently defined (i.e., E15.0); (2) that manufacture E15 to be introduced into commerce; or (3) 

that dispense E15 from a retail outlet. The Agency specifically seeks comments on this proposed 

language.

VII. Proposed Amendments to the ULSD Diesel Sulfur Survey

EPA is requesting comment concerning whether to amend a provision of the ultra-low 

sulfur diesel (ULSD) rule. The ULSD rule includes a provision that deems branded refiners 

liable for violations of the ULSD sulfur standard that are found at retail outlets displaying the 

refiner’s brand (40 CFR §80.612). The regulations include defense provisions. One element of a 

branded refiner’s defense to such violations is that it must have a periodic sampling and testing 

program at the retail level (40 CFR 80.613(b) and (d)). The regulations also set forth an 

alternative sampling and testing defense element provision for branded refiners. 
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This alternative defense element provision (40 CFR §80.613(e)) allows a branded refiner 

to meet the company-specific downstream periodic sampling and testing element of its defense 

by participating in funding a survey consortium that samples diesel fuel at retail outlets 

nationwide. This sampling and testing of fuel to determine compliance with the ULSD sulfur

standard is carried out by an independent survey association. EPA reviews and approves the 

annual survey plan submitted by the survey association. The number of samples that are taken 

each year is determined by a statistical formula that is based in part on the previous year’s 

compliance rate. In addition, the regulations set a floor and a ceiling for the number of samples 

that must be taken in an annual survey cycle regardless of the sample number that would be 

calculated using the regulatory formula. Therefore, the number of samples required to be taken 

can potentially be less than the formula would require, or it can be more. 

Compliance with the ULSD sulfur content standard has been extremely high; less than 

1% of the samples have been in violation in recent years. The minimum number of samples 

currently required to be taken annually is set by the regulation at 5,250 regardless of this high 

compliance rate. Due to the high compliance rate, use of the statistical formula would result in a 

sampling rate of several hundred samples for each of the past several years, instead of 5,250 

samples. The cost difference between taking several hundred samples versus taking over 5,000 

samples is significant. For these reasons we believe the continued high compliance rate, and the 

substantial discrepancy between the sampling rate calculated by the formula and the minimum 

sampling rate, argue for lowering the minimum sampling rate. However, we believe there is a 

point where the number of samples per year would be so few that the survey would be 

meaningless relative to robust sampling and testing programs conducted by each refiner 
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individually. Balancing these concerns, we believe minimum sampling rate of about 1,800 

samples is appropriate. We are requesting comment on reducing the minimum number of 

samples to some rate below 2,000 samples. 
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VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is a 

"significant regulatory action” because it raises novel legal or policy issues. Accordingly, EPA 

submitted this action to the Office of Management and Budget (OMB) for review under 

Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in 

response to OMB recommendations have been documented in the docket for this action.

B. Paperwork Reduction Act 

The information collection requirements in this notice of proposed rulemaking have been 

submitted for approval to the Office of Management and Budget (OMB) under the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. The Information Collection Request (ICR) document 

prepared by EPA related to this proposal has been assigned EPA ICR number 2469.01. A 

supporting statement for the proposed ICR has been placed in the docket. The proposed 

information collection is described in the following paragraphs. 

This action contains recordkeeping and reporting that may affect the following parties 

under the RFS2 regulation: RIN generators (producers, importers), obligated parties (refiners), 

exporters, and parties who own or transact RINs. We estimate that 670 parties may be subject to 

the proposed information collection. We estimate an annual recordkeeping and reporting burden 
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of 3.1 hours per respondent. This action contains recordkeeping and reporting that may affect 

the following parties under the E15 regulation: gasoline refiners, gasoline and ethanol importers, 

gasoline and ethanol blenders (including terminals and carriers). We estimate that 2,000 

respondents may be subject to the proposed information collection. We estimate an annual 

recordkeeping and reporting burden of 1.3 hours per respondent. Burden means the total time, 

effort, or financial resources expended by persons to generate, maintain, retain, or disclose or 

provide information to or for a Federal agency. This includes the time needed to review the 

instructions; develop, acquire, install, and utilize technology and systems for the purpose of 

collecting, validating, and verifying information, processing and maintaining information, and 

disclosing and providing information; adjust the existing ways to comply with any previously

applicable instructions and requirements; train personnel to be able to respond to a collection of 

information; search data sources; complete and review the collection of information; and transit 

or otherwise disclose the information. Burden is as defined at 5 CFR § 1320.3(b). 

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for EPA's regulations in 40 CFR are listed in 40 CFR Part 9.

To comment on the Agency’s need for this information, the accuracy of the provided 

burden estimates, and any suggested methods for minimizing respondent burden, EPA has 

established a public docket for this proposed rule, which includes the ICR described above, 

under Docket ID number EPA-HQ-OAR-2012-0401. Submit any comments related to the ICR 

to EPA and OMB. See the ADDRESSES section at the beginning of this notice for where to 
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submit comments to EPA. Send comments to OMB at the Office of Information and Regulatory

Affairs, Office of Management and Budget, 725 17th Street, NW, Washington, DC 20503, 

Attention: Desk Office for EPA. Since OMB is required to make a decision concerning the ICR 

between 30 and 60 days after [insert date of publication of this notice in the Federal Register.], a 

comment to OMB is best assured of having its full effect if OMB receives it by [insert date 30 

days after publication of this notice in the Federal Register.]. 

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.
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After considering the economic impacts of this action on small entities, I certify that this 

action will not have a significant economic impact on a substantial number of small entities. The 

amendments to the RFS2 provisions in this direct final rule will not impose any requirements on 

small entities that were not already considered under the final RFS2 regulations, as it makes 

relatively minor corrections and modifications to those regulations. We continue to be interested 

in the potential impacts of the proposed rule on small entities and welcome comments on issues 

related to such impacts.

D. Unfunded Mandates Reform Act

 

This rule does not contain a Federal mandate that may result in expenditures of $100 

million or more for State, local, and tribal governments, in the aggregate, or the private sector in 

any one year. We have determined that this action will not result in expenditures of $100 million 

or more for the above parties and thus, this rule is not subject to the requirements of sections 202 

or 205 of UMRA.

This rule is also not subject to the requirements of section 203 of UMRA because it 

contains no regulatory requirements that might significantly or uniquely affect small 

governments. It only applies to gasoline, diesel, and renewable fuel producers, importers, 

distributors and marketers and makes relatively minor corrections and modifications to the RFS2 

and diesel regulations.

E. Executive Order 13132 (Federalism)
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This action does not have federalism implications. It will not have substantial direct 

effects on the States, on the relationship between the national government and the States, or on 

the distribution of power and responsibilities among the various levels of government, as 

specified in Executive Order 13132. This action only applies to gasoline, diesel, and renewable 

fuel producers, importers, distributors and marketers and makes relatively minor corrections and 

modifications to the RFS2 and diesel regulations. Thus, Executive Order 13132 does not apply

to this action. In the spirit of Executive Order 13132, and consistent with EPA policy to promote 

communications between EPA and State and local governments, EPA specifically solicits 

comment on this proposed action from State and local officials. 

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

This proposed rule does not have tribal implications, as specified in Executive Order 

13175 (65 FR 67249, November 9, 2000). It applies to gasoline, diesel, and renewable fuel 

producers, importers, distributors and marketers. This action makes relatively minor corrections 

and modifications to the RFS and diesel regulations, and does not impose any enforceable duties 

on communities of Indian tribal governments. Thus, Executive Order 13175 does not apply to 

this action. EPA specifically solicits additional comment on this proposed action from tribal 

officials.

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

Safety Risks
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EPA interprets EO 13045 (62 F.R. 19885, April 23, 1997) as applying only to those 

regulatory actions that concern health or safety risks, such that the analysis required under 

section 5-501 of the EO has the potential to influence the regulation. This action is not subject to 

EO 13045 because it does not establish an environmental standard intended to mitigate health or 

safety risks.

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use

This action is not a “significant energy action” as defined in Executive Order 13211 (66 

FR 28355 (May 22, 2001)), because it is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. This action amends existing regulations related to 

renewable fuel, E15, and ultra-lower sulfur diesel. We have concluded that this rule is not likely

to have any adverse energy effects. In fact, we expect this proposed rule may result in positive 

effects, because many of the changes we are proposing will facilitate the introduction of new 

renewable fuels under the RFS2 program and have come at the suggestion of industry

stakeholders. 

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(“NTTAA”), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary
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123

consensus standards in its regulatory activities unless to do so would be inconsistent with 

applicable law or otherwise impractical. Voluntary consensus standards are technical standards 

(e.g., materials specifications, test methods, sampling procedures, and business practices) that are 

developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations when the Agency decides not to use available and 

applicable voluntary consensus standards. 

This action does not involve technical standards. Therefore, EPA did not consider the 

use of any voluntary consensus standards. EPA welcomes comments on this aspect of the 

proposed rulemaking and, specifically, invites the public to identify potentially-applicable 

voluntary consensus standards and to explain why such standards should be used in this 

regulation.

J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority

Populations and Low-Income Populations.

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive 

policy on environmental justice. Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental justice part of their mission by

identifying and addressing, as appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and activities on minority populations and lowincome populations in the United States. 
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EPA has determined that this proposed rule will not have disproportionately high and 

adverse human health or environmental effects on minority or low-income populations because it 

does not affect the level of protection provided to human health or the environment. These 

technical amendments do not relax the control measures on sources regulated by the RFS 

regulations and therefore will not cause emissions increases from these sources.

K. Clean Air Act Section 307(d)

This rule is subject to Section 307(d) of the CAA. Section 307(d)(7)(B) provides that 

"[o]nly an objection to a rule or procedure which was raised with reasonable specificity during 

the period for public comment (including any public hearing) may be raised during judicial 

review." This section also provides a mechanism for the EPA to convene a proceeding for 

reconsideration, "[i]f the person raising an objection can demonstrate to the EPA that it was 

impracticable to raise such objection within [the period for public comment] or if the grounds for 

such objection arose after the period for public comment (but within the time specified for 

judicial review) and if such objection is of central relevance to the outcome of the rule." Any 

person seeking to make such a demonstration to the EPA should submit a Petition for 

Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 

1200 Pennsylvania Ave., NW, Washington, D.C. 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, D.C. 20460.
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List of Subjects in 40 CFR Part 80

Environmental protection, Administrative practice and procedure, Agriculture, Air 

pollution control, Confidential business information, Energy, Forest and Forest Products, Fuel 

additives, Gasoline, Imports, Motor vehicle pollution, Penalties, Petroleum, Reporting and 

recordkeeping requirements.

Dated:

Lisa P. Jackson 

Administrator.
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40 CFR PART 80 – REGULATION OF FUELS AND FUEL ADDITIVES

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

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

2. Section 80.613 is amended by revising paragraph (e)(4)(C)(v)(A) definition “n” as 

follows:

§ 80.613 What defenses apply to persons deemed liable for violation of a prohibited 

act under this subpart? 

* * * * *

(e) * * *

(4) * * *

(C) * * *

(v) * * *

(A) * * *

Where:

n= minimum number of samples in a year-long survey series. 

However, in no case shall n be larger than 9,600 nor smaller than 1,800.

3. Section 80.1401 is amended by adding the definitions of “renewable compressed natural 

gas,” “renewable liquefied natural gas,” “responsible corporate officer,” and revising the 

definitions of “biogas,” “crop residue,” “naphtha,” and “renewable biomass,” in alphabetical 

order to read as follows: 
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§ 80.1401 Definitions.

* * * * *

Biogas means a mixture of hydrocarbons that is a gas at 60 degrees Fahrenheit and 1 

atmosphere of pressure that is produced through the conversion of organic matter. Biogas 

includes landfill gas, gas from waste digesters, and gas from waste treatment plants. Waste 

digesters include digesters processing animal wastes, biogenic waste oils/fats/greases, separated 

food and yard wastes, and crop residues, and waste treatment plants include wastewater 

treatment plants and privately owned treatment works.

* * * * *

Crop residue is the biomass left over from the harvesting or processing of planted crops 

from existing agricultural land and any biomass removed from existing agricultural land that 

facilitates crop management (including biomass removed from such lands in relation to invasive 

species control or fire management), whether or not the biomass includes any portion of a crop 

or crop plant. Biomass is considered crop residue only if the use of that biomass for the 

production of renewable fuel has no significant impact on demand for the feedstock crop, 

products produced from that feedstock crop, and all substitutes for the crop and its products, nor 

any other impact that would result in a significant increase in direct or indirect GHG emissions.
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* * * * *

Nameplate capacity means the peak design capacity of a facility for the purposes of 

registration of a facility under § 80.1450(b)(1)(V)(E). 

Naphtha means a blendstock or fuel blending component falling within the boiling range 

of gasoline which is composed of only hydrocarbons, is commonly or commercially known as 

naphtha and is used to produce gasoline through blending.

* * * * *

Renewable biomass means each of the following (including any incidental, de minimis

contaminants that are impractical to remove and are related to customary feedstock production 

and transport):

(1) Planted crops and crop residue harvested from existing agricultural land cleared or 

cultivated prior to December 19, 2007 and that was nonforested and either actively managed or 

fallow on December 19, 2007.

(2) Planted trees and tree residue from a tree plantation located on non-federal land 

(including land belonging to an Indian tribe or an Indian individual that is held in trust by the 
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U.S. or subject to a restriction against alienation imposed by the U.S.) that was cleared at any

time prior to December 19, 2007 and actively managed on December 19, 2007.

(3) Animal waste material and animal byproducts.

(4) Slash and pre-commercial thinnings from non-federal forestland (including forestland 

belonging to an Indian tribe or an Indian individual, that are held in trust by the United States or 

subject to a restriction against alienation imposed by the United States) that is not ecologically

sensitive forestland.

(5) Biomass (organic matter that is available on a renewable or recurring basis) obtained 

from the immediate vicinity (i.e., obtained within 200 feet) of buildings and other areas regularly 

occupied by people, or of public infrastructure, in an area at risk of wildfire.

(6) Algae.

(7) Separated yard waste or food waste, including recycled cooking and trap grease, and 

materials described in §80.1426(f)(5)(i).

Renewable compressed natural gas means biogas as defined in this section, that is 

processed to the standards of pipeline natural gas as defined in 40 CFR 72.2 and that is 
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compressed to pressures up to 3600 psi. Only renewable CNG that qualifies as renewable fuel 

and is used for transportation purposes can generate RINs. 

* * * * *

Renewable fuel producer means a person who operates or directly supervises the 

operation of a facility where renewable fuel is produced.

Renewable liquefied natural gas means biogas as defined in this section, that is processed 

to the standards of pipeline natural gas as defined in 40 CFR 72.2 and that goes through the 

process of liquefaction in which the biogas is cooled below its boiling point and weighs less than 

half the weight of water so it will float if spilled on water. Only renewable LNG that qualifies as 

renewable fuel and is used for transportation fuel can generate RINs. 

Responsible Corporate Officer, or RCO, for this subpart only, means a corporate officer 

who has the authority and is assigned responsibility to provide information to EPA on behalf of 

a company. A company may name only one Responsible Corporate Officer. A Responsible 

Corporate Officer may not delegate his or her responsibility to any other person. The 

Responsible Corporate Officer may delegate the ability to submit information to EPA, but the 

Responsible Corporate Officer remains responsible for the actions of such employees or agents.
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Small Refinery, for this subpart only, means a refinery for which the average aggregate 

daily crude oil throughput for calendar year 2006 and subsequent years (as determined by 

dividing the aggregate throughput for the calendar year by the number of days in the calendar 

year) does not exceed 75,000 barrels. 

4. Section 80.1415 is amended by revising paragraph (c)(1) to read as follows:

§ 80.1415 How are equivalence values assigned to renewable fuel?

(b) * * *

(5) 77,000 Btu (lower heating value) of compressed natural gas (CNG) or liquefied 

natural gas (LNG) shall represent one gallon of renewable fuel with an equivalence value of 1.0.

(c) * * *

(1) The equivalence value for renewable fuels described in paragraph (b)(7) of this section 

shall be calculated using the following formula:

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

Where:

EV = Equivalence Value for the renewable fuel, rounded to the nearest tenth.

R = Renewable content of the renewable fuel. Except as provided in 

§80.1426(f)(4)(iii), this is a measure of the portion of a renewable fuel that 

came from renewable biomass, expressed as a fraction, on an energy basis.

EC = Energy content of the renewable fuel, in Btu per gallon (lower heating 

value).

5. Section 80.1426 is amended by:
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a. Revising Table 1 of (f)(1), (f)(10), (f)(11) and (f)(13)

The additions and revisions read as follows:

§ 80.1426 How are RINs generated and assigned to batches of renewable fuel by 

renewable fuel producers or importers?

(f) * * *

(1) * * *

Table 1 to §80.1426—Applicable D Codes for Each Fuel Pathway for Use in Generating 

RINs

Fuel type Feedstock

Production process 

requirements

DCode

A Ethanol Corn starch All of the following:

Dry mill process, using 

natural gas, biomass, or 

biogas for process energy 

and at least two advanced 

technologies from Table 2 

to this section

6

B Ethanol Corn starch All of the following:

Dry mill process, using 

natural gas, biomass, or 

biogas for process energy 

and at least one of the 

advanced technologies 

from Table 2 to this 

section plus drying no 

more than 65% of the 

distillers grains with 

solubles it markets 

annually

6

C Ethanol Corn starch All of the following:

Dry mill process, using 

6
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natural gas, biomass, or 

biogas for process energy 

and drying no more than 

50% of the distillers grains 

with solubles it markets 

annually

D Ethanol Corn starch Wet mill process using 

biomass or biogas for 

process energy

6

E Ethanol Starches from crop residue and 

annual covercrops

Fermentation using 

natural gas, biomass, or 

biogas for process energy

6

F Biodiesel, and renewable diesel Soy bean oil;

Oil from annual covercrops;

Algal oil;

Biogenic waste oils/fats/greases;

Non-food grade corn oil

One of the following:

Trans-Esterification

Hydrotreating

Excluding processes that 

co-process renewable 

biomass and petroleum

4

G Biodiesel Canola oil Trans-Esterification using 

natural gas or biomass for 

process energy

4

H Biodiesel, and renewable diesel Soy bean oil;

Oil from annual covercrops;

Algal oil;

Biogenic waste oils/fats/greases;

Non-food grade corn oil

One of the following:

Trans-Esterification

Hydrotreating

Includes only processes 

that co-process renewable 

biomass and petroleum

5

I Ethanol Sugarcane Fermentation 5

J Ethanol Cellulosic Biomass from crop 

residue, slash, pre-commercial 

thinnings and tree residue, 

annual covercrops, switchgrass, 

and miscanthus; cellulosic 

components of separated yard 

waste; cellulosic components of 

separated food waste; and 

cellulosic components of 

Any 3
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separated MSW

K Cellulosic Diesel, Jet Fuel and 

Heating Oil

Cellulosic Biomass from crop 

residue, slash, pre-commercial 

thinnings and tree residue, 

annual covercrops, switchgrass, 

and miscanthus; cellulosic 

components of separated yard 

waste; cellulosic components of 

separated food waste; and 

cellulosic components of 

separated MSW

Any 7

L Butanol Corn starch Fermentation; dry mill 

using natural gas, biomass, 

or biogas for process 

energy

6

M Butanol Corn starch Fermentation; dry mill 

using natural gas and 

biogas from on-site thin 

stillage anaerobic digester 

for process energy w/ CHP 

producing excess 

electricity of at least 40% 

of the purchased natural 

gas energy used by the 

facility

5

N Cellulosic Naphtha Cellulosic Biomass from crop 

residue, slash, pre-commercial 

thinnings and tree residue, 

annual covercrops, switchgrass, 

and miscanthus; cellulosic 

components of separated yard

waste; cellulosic components of 

separated food waste; cellulosic 

components of separated MSW; 

and biogas from landfills

Fischer-Tropsch process; 

Facilities using biogas from 

landfills as feedstock must 

produce at least 20% of 

their electricity usage at 

the facility

3

O Ethanol, renewable diesel, jet fuel, 

heating oil, and naphtha

The non-cellulosic portions of 

separated food waste

Any 5

P Renewable Compressed Natural 

Gas, Renewable Liquefied Natural 

Biogas from Landfills Any 3
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Gas

Q Renewable Compressed Natural 

Gas, Renewable Liquefied Natural 

Gas

Biogas from waste treatment 

plants and waste digesters

Any 5

R Renewable Electricity Biogas from landfills Any 3

S Cellulosic Diesel Biogas from landfills Fischer-Tropsch process; 

Facilities must produce at 

least 20% of their 

electricity usage at the 

facility

7

T Naphtha Biogas from landfills Fischer-Tropsch process 5

U Renewable Diesel Biogas from landfills Fischer-Tropsch process; 

Excluding processes that 

co-process renewable 

biomass and petroleum

4

V Renewable Diesel Biogas from landfills Fischer-Tropsch process; 

Includes only processes 

that co-process renewable 

biomass and petroleum

5

* * * * *

* * * * *

(10)(i) For purposes of this section, renewable electricity that is not introduced into a 

distribution system with electricity derived from non-renewable feedstocks is considered 

renewable fuel and the producer may generate RINs if all of the following apply:

(A) The electricity is produced from renewable biomass and qualifies for a D code in 

Table 1 to this section or has received approval for use of a D code by the Administrator;
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(B) The fuel producer has entered into a written contract for the sale of a specific quantity 

of renewable electricity as transportation fuel; and

(C) The renewable electricity is used as a transportation fuel.

(ii) For purposes of this section, fuels produced from biogas that is not introduced into a 

distribution system with gas derived from non-renewable feedstocks is considered renewable 

fuel and the producer may generate RINs if all of the following apply:

(A) The fuel is produced from renewable biomass and qualifies for a D code in Table 1 to 

this section or has received approval for use of a D code by the Administrator;

(B) The fuel producer has entered into a written contract for the sale of a specific quantity 

of biogas to be used as a feedstock for transportation fuel; and

(C) The fuel produced from the biogas is used as a transportation fuel.

(iii) A producer of renewable electricity that is generated by co-firing a combination of 

renewable biomass and fossil fuel may generate RINs only for the portion attributable to the 

renewable biomass, using the procedure described in paragraph (f)(4) of this section.

(11)(i) For purposes of this section, renewable electricity that is introduced into a commercial 

distribution system (transmission grid) may be considered renewable fuel and the producer may

generate RINs if:

(A) The electricity is produced from renewable biomass and qualifies for a D code in 

Table 1 of this section or has received approval for use of a D code by the Administrator;

(B) The fuel producer has entered into a written contract for the sale of a specific quantity 

of electricity derived from renewable biomass sources with a party that uses electricity taken 
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from a commercial distribution system for use as a transportation fuel, and such electricity has 

been introduced into that commercial distribution system (transmission grid); 

(C) The quantity of renewable electricity for which RINs were generated was sold for use 

as transportation fuel and for no other purposes; and 

(D) The renewable electricity was loaded onto and withdrawn from a physically

connected transmission grid as defined by the North American Electrical Reliability Corporation 

(NERC) regions.

(ii) For purposes of this section, fuel produced from biogas that is introduced into a 

commercial distribution system may be considered renewable fuel and the producer may

generate RINs if:

(A) The fuel is produced from renewable biomass and qualifies for a D code in Table 1 of 

this section or has received approval for use of a D code by the Administrator;

(B) The fuel producer has entered into a written contract for the sale of a specific quantity 

of fuel derived from renewable biomass sources with a party that uses fuel taken from a 

commercial distribution system for transportation fuel, and such fuel has been introduced into 

that commercial distribution system (e.g., pipeline); 

(C) The quantity of fuel produced from the biogas for which RINs were generated was 

sold for use as transportation fuel and for no other purposes;

(D) The biogas was injected into and withdrawn from a physically connected carrier 

pipeline;
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(E) The gas that is ultimately withdrawn from that pipeline for use in a transportation fuel

is withdrawn in a manner and at a time consistent with the transport of gas between the injection 

and withdrawal points; and

(F) The volume and heat content of biogas injected into the pipeline and the volume of 

gas withdrawn to make a transportation fuel are measured by continuous metering.

(iii) The fuel sold for use in transportation fuel is considered produced from renewable 

biomass only to the extent that:

(A) The amount of fuel sold for use as transportation fuel matches the amount of fuel 

derived from renewable biomass that the producer contracted to have placed into the commercial 

distribution system; and

(B) No other party relied upon the contracted volume of biogas or renewable electricity 

for the creation of RINs.

(iv) For renewable electricity that is generated by co-firing a combination of renewable

biomass and fossil fuel, the producer may generate RINs only for the portion attributable to the 

renewable biomass, using the procedure described in paragraph (f)(4) of this section.

* * * * *

(13) For purposes of verification, in order for facilities to meet the renewable electricity 

production requirement for the biogas-derived cellulosic diesel and cellulosic naphtha pathways, 

all conditions below apply. 

(i) The quantity of renewable process electricity produced must be measured by continuous 

metering.

(ii) The electricity must be used to provide power to process units or process equipment at the 

facility.
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(iii) The electrical energy must derive from raw landfill gas, waste heat from the production 

process, unconverted syngas from the F-T process, fuel gas from the hydroprocessing or 

combined heat and power (CHP) units that use non-fossil fuel based gas or other 

renewable sources.

6. Section 80.1427 is amended by:

a. Revising paragraphs (a)(1)(i) definition “RVOCB,I”, (a)(1)(ii) definition “RVOBBD,i”,

(a)(1)(iii) definition “RVOBBD,i”, (a)(5) introductory text, and (a)(6) ; and

b. Adding paragraph (a)(1)(v)

The additions and revisions read as follows:

§80.1427 How are RINs used to demonstrate compliance?

(a) Renewable Volume Obligations and Exporter Renewable Volume Obligations. (1) 

Except as specified in paragraph (b) of this section or §80.1456, each party that is an obligated 

party under § 80 1406 and is obligated to meet the Renewable Volume Obligations under §

80.1407, or is an exporter of renewable fuel that is obligated to meet the Exporter Renewable 

Volume Obligations under § 80.1430, must demonstrate pursuant to § 80.1451(a)(1) that it is 

retiring for compliance purposes a sufficient number of RINs to satisfy the following equations.

* * * * *

(i) * * * * *
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RVOCB,i = The renewable Volume Obligation for cellulosic biofuel for the obligated party 

for calendar year i, in gallons, pursuant to 80.1407.

(ii) * * * * *

RVOBBD,i = The renewable Volume Obligation for biomass-based diesel for the obligated 

party for calendar year i, in gallons, pursuant to 80.1407.

(iii) * * *

RVOAF,i = The renewable Volume Obligation for advanced biofuel for the obligated party 

for calendar year i, in gallons, pursuant to 80.1407.

(iv) * * *

RVORF,i = The renewable Volume Obligation for renewable fuel for the obligated party 

for calendar year i, in gallons, pursuant to 80.1407.

(v) Cellulosic biofuel- Exporter. 

(ΣRINNUM)CB,i+ (ΣRINNUM)CB,i−1= ERVOCB,i

Where:

(ΣRINNUM)CB,i= Sum of all owned gallon-RINs that are valid for use in complying with 

the cellulosic biofuel ERVO, were generated in year i, and are being applied towards the 

ERVOCB,i, in gallons.

(ΣRINNUM)CB,i-1= Sum of all owned gallon-RINs that are valid under subparagraph 

(6) of this paragraph for use in complying with the cellulosic biofuel ERVO, were generated in 

year i-1, and are being applied towards the ERVOCB,i, in gallons.

ERVOCB, k= The Exporter Renewable Volume Obligation for cellulosic biofuel for the 

renewable fuel exporter for an export of renewable fuelk, in gallons, pursuant to §80.1430.

(vi) Biomass-based diesel - Exporter. 

(ΣRINNUM)BBD,i+ (ΣRINNUM)BBD,i-1= ERVOBBD,i

Where:

(ΣRINNUM)BBD,i= Sum of all owned gallon-RINs that are valid for use in complying 

with the biomass-based diesel ERVO, were generated in year i, and are being applied towards 

the ERVOBBD,i, in gallons.

(ΣRINNUM)BBD,i-1= Sum of all owned gallon-RINs that are valid under subparagraph 

(6) of this paragraph for use in complying with the biomass-based diesel ERVO, were generated 

in year i-1, and are being applied towards the ERVOBBD,i, in gallons.
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ERVOBBD,i= The Exporter Renewable Volume Obligation for biomass-based diesel for 

the renewable fuel exporter for an export of renewable fuel I after 2010, in gallons, pursuant to 

§80.1430.

(vii) Advanced biofuel - Exporter. 

(ΣRINNUM)AB,i+ (ΣRINNUM)AB,i-1= ERVOAB,i

Where:

(ΣRINNUM)AB,i= Sum of all owned gallon-RINs that are valid for use in complying with 

the advanced biofuel ERVO, were generated in year i, and are being applied towards the 

ERVOAB,i, in gallons.

(ΣRINNUM)AB,i-1= Sum of all owned gallon-RINs that are valid under subparagraph 

(6) of this paragraph for use in complying with the advanced biofuel ERVO, were generated in 

year i-1, and are being applied towards the ERVOAB,i, in gallons.

ERVOAB,i= The Exporter Renewable Volume Obligation for advanced biofuel for the 

renewable fuel exporter for an export of renewable fuel i, in gallons, pursuant to §80.1430.

(viii) Renewable fuel - Exporter. 

(ΣRINNUM)RF,i+ (ΣRINNUM)RF,i-1= ERVORF,i

Where:

(ΣRINNUM)RF,i= Sum of all owned gallon-RINs that are valid for use in complying with 

the renewable fuel (D code 6) E ERVORF,i, in gallons.

(ΣRINNUM)RF,i-1= Sum of all owned gallon-RINs that are valid under subparagraph 

(6) of this paragraph for use in complying with the renewable fuel (D code 6) ERVO, were 

generated in year i-1, and are being applied towards the ERVORF,i, in gallons.

ERVORF,i= The exporter Renewable Volume Obligation for renewable fuel for the 

renewable fuel exporter for an export of renewable fuel i, in gallons, pursuant to §80.1430.

* * * * *

(5) The value of (∑RINNUM)i-1 may not exceed values determined by the following 

inequalities as provided in paragraph (a)(7)(iii) of this section and 80.1442(d), for obligated 

parties only.

* * * * *

(6) Except as provided in paragraph (a)(7) of this section:
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(i) For obligated parties, RINs may only be used to demonstrate compliance with the 

RVOs for the calendar year in which they were generated or the following calendar year. 

(ii) [Reserved.]

(iii) For Renewable Fuel Exporters, RINs generated in calendar year i, must be used to 

demonstrate compliance with the ERVOs from renewable fuel export(s) in calendar year i, 

except as provided in paragraph (a)(6)(iv) of this section.

(iv) For Renewable Fuel Exporters, RINs generated in calendar year i-1, may only be 

used to demonstrate compliance with the ERVOs from renewable fuel exports in January of 

calendar year i.

7. Section 80.1441 is amended by adding paragraph (e)(2)(iii) to read as follows:

§ 80.1441 Small refinery exemption.

* * * * *

(e) * * *

(2) * * *

(iii) In order to qualify for an extension of its small refinery exemption, a refinery

must meet the definition of “small refinery” in §80.1401 for all full calendar years between 2006 

and the date of submission of the petition for an extension.
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* * * * *

8. Section 80.1450 is amended by adding paragraph (b)(1)(iv), revising (C), (b)(1)(v)(C)

and adding paragraphs (h) and (i) to read as follows:

§ 80.1450 What are the registration requirements under the RFS program?

* * * * *

(b) * * *

(1) * * *

(iv) * * *

(C) To demonstrate compliance with the renewable electricity production requirement for 

the biogas-derived cellulosic diesel and cellulosic naphtha pathways, provide all the following 

information:

(1) The energy source, equipment and/or process used to generate the electricity. 

Permitted sources are raw landfill gas, waste heat from the production process, unconverted 

syngas from the Fischer-Tropsch process, fuel gas from the hydroprocessing, or combined heatand-power (CHP) units that use non-fossil fuel based gas or other renewable sources.

(2) Estimates of the total amount of electricity to be used, the total amount of grid 

electricity to be purchased, the total amount of renewable electricity to be produced, and a 

calculation of the percent of total process electricity use to be produced from allowed sources at 

the facility.
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(v) * * *

(C) (1) For all facilities, copies of documents demonstrating each facility's actual peak 

capacity as defined in §80.1401 if the maximum rated annual volume output of renewable fuel is 

not specified in the air permits specified in paragraphs (b)(1)(v)(A) and (b)(1)(v)(B) of this 

section, as appropriate. 

(2) For facilities claiming the exemption described in § 80.1403 (c) or (d) which are 

exempt from air permit requirements and for which insufficient production records exist to 

establish actual peak capacity, copies of document demonstrating the facility’s nameplate 

capacity, as defined in § 80.1401. 

(D) For all facilities producing renewable electricity or fuel from biogas that qualifies as 

renewable fuel, submit all relevant information in §80.1426(f)(10) or (11), and copies of all 

contracts that the tracks the biogas or renewable electricity from its original source, to the 

producer that processes it into renewable fuel, and finally to the end user that will actually use 

the renewable electricity or the renewable fuel derived from biogas for transportation purposes. 

(1) Specific quantity and the heat content, percent efficiency of transfer, if applicable, and 

any conversion factors of the biogas or renewable biomass.

(2) Specific quantity and the heat content and percent efficiency of transfer, if applicable, 

and any conversion factors for the renewable fuel derived from biogas or renewable electricity.

(E) Such other records as may be requested by the Administrator. 

* * * * *
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(h) Cancellation of Company Registration. EPA may cancel a company’s registration, 

using the process in paragraph (h)(2) of this section, if any of the following circumstances exist:

(1) 

(i) The company has reported no activity in EMTS for one calendar year (January 1 

through December 31) or has failed to meet any EMTS requirement under § 80.1452;

(ii) The company has failed to comply with the registration requirements of this 

section;

(iii) The company has failed to submit any required report within thirty (30) days of 

the required submission date under § 80.1451; or

(iv) The attest engagement required under § 80.1454 has not been received within 

thirty (30) days of the required submission date.

(2) EPA will use the following process whenever it decides to cancel the registration of a 

company:

(i) EPA will notify the company’s owner or Responsible Corporate Officer (RCO), in 

writing, that it intends to cancel the company’s registration, and identifying the reasons for that 

proposed action. The company will have fourteen (14) calendar days from the date of the 

notification to correct the deficiencies identified or explain why there is no need for corrective 

action. 

(ii) If the basis for EPA’s notice of intent to cancel registration is the absence of EMTS 

activity for one calendar year, a stated intent to engage in activity reported through EMTS within 

the next calendar year will be sufficient to avoid cancellation of registration. 
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(iii) If the company does not respond, does not correct identified deficiencies, or does

not explain why such correction is not necessary within the time allotted for response, , EPA may

cancel the company’s registration within further notice to the party.

(3) Impact of registration cancellation. 

(i) A company whose registration is cancelled shall still be liable for violation of any 

requirements of this subpart. 

(ii) A company whose registration is cancelled will not be listed on any public list of 

actively registered companies that is maintained by EPA. . 

(iii) If the company whose registration is cancelled is a renewable fuel producer or 

foreign ethanol producer, it will not be listed on any public list of registered producers 

maintained by EPA. 

(iv) A company whose registration is cancelled will not have access to any of the 

electronic reporting systems associated with the renewable fuel standard program, including the 

EPA Moderated Transaction System (EMTS). 

(v) A company whose registration is canceled must submit any corrections of 

deficiencies to EPA on forms, and following policies, established by EPA. 

(v) If a company whose registration has been canceled wishes to re-register, they may

initiate that process by submitting a new registration, consistent with paragraphs (a)-(c) of this 

section.

(i) English language registrations. Any document submitted to EPA under §80.1450 

must be submitted in English, or shall include an English translation. 
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9. Section 80.1451 is amended by revising paragraph (b)(1)(ii)(Q), and by adding 

paragraphs (b)(1)(ii)(T) and (h) to read as follows:

§ 80.1451 What are the reporting requirements under the RFS program?

(a) * * *

(1) * * *

(vi) The RVOs for obligated parties, as defined in § 80.1427(a) and for exporters of 

renewable fuel, as defined in § 80.1427(a) and 80.1430(b), for the reporting year.

* * * * *

(b) * * *

(1) * * *

(ii) * * *

(Q) Producers or importers of renewable fuel produced at facilities that use biogas for 

process heat as described in §80.1426(f)(12), shall report the total energy supplied to the 

renewable fuel facility, in MMBtu based on metering of gas volume. Producers or importers of 

renewable fuel produced at facilities that meet the renewable electricity production requirement 

for the biogas-derived cellulosic diesel and cellulosic naphtha pathways as described in 

§80.1426(f)(13), shall report the total renewable electricity produced by the renewable facility, in 

kilowatt-hour (kWh) or megawatt-hour (MWh), the total amount of electricity used, the total 

amount of grid electricity purchased, and a calculation verifying the percent of total process 

electricity from allowed sources produced on-site.

* * *
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(T) Producers of fuel oil that is demonstrated to be used to heat interior spaces of homes 

or buildings to control ambient climate for human comfort and capable of flowing at 60 degrees 

Fahrenheit and 1 atmosphere of pressure as defined under the term heating oil in Section 1401, 

shall report all the following for each volume of fuel oil:

(1) Total volume of fuel oil produced for RIN generation, in units of U.S. gallon, and the 

respective heating content of the fuel oil, in units of BTU per U.S. gallon

(2) Total volume of fuel oil sold for RIN generation, in units of U.S. gallon, and the 

respective name and location of the building in which the fuel oil was sold to and used to heat

(3) Total volume of fuel oil that was produced or sold that did not qualify for RIN 

generation, and an explanation why these volumes of fuel oil did not qualify, what purpose or 

end use were applied for these volumes, and to what entity were the volumes eventually sold.

* * *

(h) English language reports. Any document submitted to EPA under §80.1451 must be 

submitted in English, or shall include an English translation.

10. Amend Section 80.1452 to revise paragraph (c) introductory text and add paragraphs (e)

and (f) to read as follows:

§80.1452 What are the requirements related to the EPA Moderated Transaction 

System (EMTS)?

* * * * *

(c) Starting July 1, 2010, each time any party sells, separates, or retires RINs generated 

on or after July 1, 2010, all of the following information must be submitted to EPA via the 
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submitting party’s EMTS account within five (5) business days of the reportable event., except 

as provided in §80.1430(f). Starting July 1, 2010, each time any party purchases RINs generated 

on or after July 1, 2010, all the following information must be submitted to EPA via the 

submitting party’s EMTS account within ten (10) business days of the reportable event. The 

reportable event for a RIN separation occurs on the date of separation as described in §80.1429. 

The reportable event for a RIN retirement occurs on the date of retirement as described in this 

subpart.

* * * * *

(e) [Reserved.]

(f) [Reserved.]

11. Amend Section 80.1454 by amending paragraph 

a. Adding paragraph (a)(7);

b. Revising paragraph (b)(4)(i);

c. Adding paragraph (b)(7);

d. Revising paragraph (f)(3)(i) and adding paragraph (f)(5); and

e. Adding paragraphs (k) and (q).

The additions and revisions read as follows:
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§ 80.1454 What are the recordkeeping requirements under the RFS program?

* * * * *

(a) * * *

(7) Records related to any volume of renewable fuel that was disqualified by the party 

pursuant to §80.1433.:

* * * * *

(b) * * *

(4) * * *

(i) A list of the RINs owned, purchased, sold, separated, retired, or reinstated.

* * * * *

(7) Records related to any volume of renewable fuel where RINs were not generated by

the renewable fuel producer or importer pursuant to §80.1426(c).:

* * * * *

(f) * * *

(3) * * *

(i) A list of the RINs owned, purchased, sold, separated, retired, or reinstated.

* * * * *

(5) Records related to any volume of renewable fuel that was disqualified by the party 

pursuant to §80.1433.

* * * * *

(k) A renewable fuel producer that generates RINs for biogas or electricity produced 

from renewable biomass (renewable electricity) for fuels that are used for transportation pursuant 
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to §80.1426(f)(10) and (11), or that uses process heat from biogas to generate RINs for 

renewable fuel pursuant to §80.1426(f)(12) or that meets the renewable electricity production 

requirement for the biogas-derived cellulosic diesel and cellulosic naphtha pathways pursuant to 

§80.1426(f)(13) shall keep all of the following additional records:

(1) Documents demonstrating the kilowatt-hours (kWh) of allowable electricity relied 

upon under §80.1426(f)(13) that was generated at the facility, if applicable.

(2) The energy source, equipment and/or process used to generate the electricity relied 

upon under §80.1426(f)(13), if applicable.. Permitted sources are raw landfill gas, waste heat 

from the production process, unconverted syngas from the Fischer-Tropsch process, fuel gas 

from the hydroprocessing, or combined heat-and-power (CHP) units that use non-fossil fuel 

based gas or other renewable sources.

(3) Contracts and documents memorializing the sale of biogas or renewable electricity for 

use as transportation fuel relied upon in §80.1426(f)(10), §80.1426(f)(11), or for use of biogas 

for use as process heat to make renewable fuel as relied upon in §80.1426(f)(12) and the transfer 

of title of the biogas or renewable electricity and all associated environmental attributes from the 

point of generation to the facility which sells or uses the fuel for transportation purposes.

(4) Documents demonstrating the volume and energy content of biogas, or kilowatts of 

renewable electricity, relied upon under §80.1426(f)(10) that was delivered to the facility which 

sells or uses the fuel for transportation purposes.

(5) Documents demonstrating the volume and energy content of biogas, or kilowatts of 

renewable electricity, relied upon under §80.1426(f)(11), or biogas relied upon under 

§80.1426(f)(12) that was placed into the common carrier pipeline (for biogas) or transmission 

line shared power grid (for renewable electricity or renewable process electricity).
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(6) Documents demonstrating the volume and energy content of biogas relied upon under 

§80.1426(f)(12) at the point of distribution.

(7) Affidavits from the biogas or renewable electricity producer and all parties that held 

title to the biogas or renewable electricity confirming that title and environmental attributes of 

the biogas or renewable electricity relied upon under §80.1426(f)(10) and (11) were used for 

transportation purposes only, and that the environmental attributes of the biogas or process 

electricity relied upon under §80.1426(f)(12) or §80.1426(f)(13) were used for process heat or 

electricity at the renewable fuel producer's facility, and for no other purpose. The renewable fuel 

producer shall create and/or obtain these affidavits at least once per calendar quarter. 

(8) The biogas or renewable electricity producer's Compliance Certification required 

under Title V of the Clean Air Act.

(9) Documents demonstrating the total amount of grid electricity purchased and 

calculations showing the percent of total electricity usage provided by allowable electricity 

production at the facility, if applicable.

(10) Such other records as may be requested by the Administrator.

* * * * *

(q) English language records. Any document requested by the Administrator under this 

section must be submitted in English, or shall include an English translation.

12. Section 80.1463 is amended by adding paragraph (d) to read as follows:
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§80.1463 What penalties apply under the RFS program? 

* * * * *

(d) Any person violating § 80.1460(b)(1)-(4) or (6) engages in a separate violation for 

each day that an invalid RIN remains available for use in RFS compliance , and each such daily 

violation is punishable by the maximum daily penalty allowed under the Clean Air Act. 

13. Section 80.1466 is amended by revising the section heading and paragraphs (a), (d)(1),

(d)(3)(ii), (e)(1)(i), (f) and (h)(1), (o)(2) and (p) as follows:

§ 80.1466 What are the additional requirements under this subpart for RIN- generating 

foreign producers, non RIN-generating foreign producers, foreign ethanol producers and 

importers of renewable fuels?

(a) Foreign producer of renewable fuel. For purposes of this subpart, a foreign producer 

of renewable fuel is a person located outside the United States, the Commonwealth of Puerto 

Rico, the Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern 

Mariana Islands (collectively referred to in this section as “the United States”) that has been 

registered with EPA as a renewable fuel producer or foreign ethanol producer, regardless of 

whether the foreign renewable fuel producer generates RINs or an importer of renewable fuel 

generates RINs for the fuel. Hereinafter referred to as a “foreign producer” under this section.
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(d) Load port independent testing and producer identification. (1) On each occasion that 

RFS–FRRF is loaded onto a vessel for transport to the United States the foreign producer shall 

have an independent third party do all the following:

(i) * * *

(ii) * * *

(iii) * * *

(iv) * * *

(v) * * *

(vi) Review original documents that reflect movement and storage of the RFS–FRRF 

from the foreign producer to the load port, and from this review determine all the following:

* * * * *

(3)

(ii) Be independent under the criteria specified in § 80.65(f)(2)(iii); and

* * * * *

(e) Comparison of load port and port of entry testing. (1)(i) Any foreign producer and 

any United States importer of RFS–FRRF shall compare the results from the load port testing 

under paragraph (d) of this section, with the port of entry testing as reported under paragraph (k) 

of this section, for the volume of renewable fuel, standardized per §80.1426(f)(8), except as 

specified in paragraph (e)(1)(ii) of this section.* * * * *
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(f) Foreign producer commitments. Any foreign producer shall commit to and comply 

with the provisions contained in this paragraph (f) as a condition to being approved as a foreign 

producer under this subpart.

* * * * *

(h) Bond posting. Any foreign producer shall meet the requirements of this paragraph (h) 

as a condition to approval as a foreign producer under this subpart and on a continuing basis if 

the foreign producer exceeds projections used in calculated the bond.

(1) The foreign producer shall post a bond of the amount calculated using one of the two 

following equations whichever equation results in a higher bond value:

Bond = G * $0.01 

Or

Bond = .25 * ∑(Mi * RINi)

Where:

Bond = amount of the bond in U.S. dollars.

G = the greater of: the largest volume of renewable fuel produced by the foreign producer 

and exported to the United States, in gallons, during a single calendar year among the five 

preceding calendar years, or the largest volume of renewable fuel that the foreign producer 

expects to export to the Unites States during any calendar year identified in the Production 

Outlook Report required by §80.1449. If the volume of renewable fuel anticipated to be 

exported to the United States during any calendar year increases above the value used in 

calculating the existing bond amount, the foreign producer shall increase the bond by using the 

higher anticipated export volume for the calendar year to calculate a higher bond amount and 

purchasing the higher bond prior to the generation of RINs to reflect the increase in export 

volume.Mi = RIN multiplier for specified D code, i, in U.S. dollars, as follows:

The RIN multiplier for a D3 RIN is $0.78

The RIN multiplier for a D4 RIN is $1.30

The RIN multiplier for a D5 RIN is $0.80

The RIN multiplier for a D6 RIN is $0.02

The RIN multiplier for a D7 RIN is $0.78

RINi = the greater of: (i) the largest quantity of RINs for a specified D code, i, produced 

by the foreign producer and exported to the United States, in gallons, during a single calendar 
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year among the five preceding calendar years, or (ii) the largest quantity of RINs that the foreign 

producer expects to export to the United States during any calendar year identified in the 

Production Outlook Report required by §80.1449. If the volume of renewable fuel anticipated to 

be exported to the United States during any calendar year increases above the value used in 

calculating the existing bond amount, the foreign producer shall increase the bond by using the 

higher anticipated export volume for the calendar year to calculate a higher bond amount and 

purchasing the higher bond prior to the generation of RINs to reflect the increased export 

volume. * * * * *

(o)

(1) * * *

(2) Signed by the president or owner of the foreign producer company, or by that 

person's immediate designee, and shall contain the following declaration: “I hereby certify: (1) 

That I have actual authority to sign on behalf of and to bind [INSERT NAME OF FOREIGN 

PRODUCER] with regard to all statements contained herein; (2) that I am aware that the 

information contained herein is being Certified, or submitted to the United States Environmental 

Protection Agency, under the requirements of 40 CFR part 80, subpart M, and that the 

information is material for determining compliance under these regulations; and (3) that I have 

read and understand the information being Certified or submitted, and this information is true, 

complete and correct to the best of my knowledge and belief after I have taken reasonable and 

appropriate steps to verify the accuracy thereof. I affirm that I have read and understand the 

provisions of 40 CFR part 80, subpart M, including 40 CFR 80.1466 apply to [INSERT NAME 

OF FOREIGN PRODUCER]. Pursuant to Clean Air Act section 113(c) and 18 U.S.C. 1001, the 

penalty for furnishing false, incomplete or misleading information in this certification or 

submission is a fine of up to $10,000 U.S., and/or imprisonment for up to five years.”

(p) Foreign Produced Renewable Fuel and Foreign Produced Ethanol for Which RINs 

have been or will be Generated by the Importer
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(1) For non-RIN generating foreign producers and foreign ethanol producers already 

registered pursuant to section §80.1450, all of the requirements in paragraphs (a) through (o) of 

this section must be satisfied no later than January 1, 2013. 

(2) For RIN generating foreign producers and foreign ethanol producers already 

registered pursuant to section §80.1450 and 80.1466, paragraph (h) of this section must be 

satisfied no later than January 1, 2013 if the required amount in paragraph (h) of this section 

exceeds the original amount of the bond posted when the producer was originally approved 

under 80.1466.

14. Section 80.1500 is amended by revising the definitions of E10, E15, and EX to read as 

follows: 

§ 80.1500 Definitions.

* * * * *

E10 means a gasoline-ethanol blend that contains at least 9 and no more than 10 volume 

percent ethanol.

E15 means a gasoline-ethanol blend that contains greater than 10 volume 

percent ethanol and not more than 15 volume percent ethanol.

EX means a gasoline–ethanol blend that contains less than 9 volume percent ethanol 

where X equals the maximum volume percent ethanol in the gasoline-ethanol blend. 
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* * * * *

15. Section 80.1501 is amended by revising paragraphs (a) introductory text, (b)(3)(i) and 

(iv), and (b)(4)(ii) to read as follows:

§ 80.1501 What are the labeling requirements that apply to retailers and wholesale 

purchaser-consumers of gasoline-ethanol blends that contain greater than 10 

volume percent ethanol and not more than 15 volume percent ethanol?

(a) Any retailer or wholesale purchaser-consumer who sells, dispenses, or offers for 

sale or dispensing E15 shall affix the following conspicuous and legible label to 

the fuel dispenser:

* * * * *

(b) * * *

(3) * * * 

(i) The word “ATTENTION” shall be capitalized in 20-point, orange, Helvetica 

Neue LT 77 Bold Condensed font, and shall be placed in the top 1.25 inches of 

the label as further described in (b)(4(iii) below.

* * * * *

(iv) The words “Use only in” shall be in 20-point, left-justified, black, Helvetica Bold 

font in the bottom 1.875 inches of the label.
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(4) * * *

* * * * *

(ii) The background of the bottom 1.875 inches of the label shall be orange.

* * * * *

16. Section 80.1502 is amended by revising paragraphs (b)(3)(iii)(A), (b)(4)(iv)(B), 

(b)(4)(v)(A), (c)(4), and (c)(6) to read as follows:

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

* * * * *

(b) * * * 

(3) * * *

(iii) * * * 

(A) Samples collected at retail outlets shall be shipped the same day the 

samples are collected via ground service to the laboratory and analyzed for oxygenate 

content. Samples collected at a dispenser labeled E15 in any manner, or at a tank serving 

such a dispenser, shall also be analyzed for RVP during the high ozone season defined in 

§ 80.27(a)(2)(ii) or any SIP approved or promulgated under §§ 110 or 172 of the Clean 

Air Act. Such analysis shall be completed within 10 days after receipt of the sample in 

the laboratory. Nothing in this section shall be interpreted to require RVP testing of a 

sample from any dispenser or tank serving it unless the dispenser is labeled E15 in any 

manner.

(iv) In the case of any test that yields a result that does not match the label 
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affixed to the product (e.g., a sample greater than 15 volume percent ethanol dispensed 

from a fuel dispenser labeled as “E15” or a sample containing greater than 10 volume 

percent ethanol and not more than 15 volume percent ethanol dispensed from a fuel 

dispenser not labeled as “E15”), or the RVP standard of §80.27(a)(2), the independent 

survey association shall, within 24 hours after the laboratory has completed analysis of 

the sample, send notification of the test result as follows: 

* * * * *

(4) * * *

(iv) * * *

(B) In the case of any retail outlet from which a sample of gasoline was collected 

during a survey and determined to have an ethanol content that does not match the fuel 

dispenser label (e.g. a sample greater than 15 volume percent ethanol dispensed from a 

fuel dispenser labeled as “E15” or a sample with greater than 10 volume percent ethanol 

and not more than 15 volume percent ethanol dispensed from a fuel dispenser not labeled 

as “E15”) or determined to have a dispenser containing fuel whose RVP does not comply

with §80.27(a)(2), that retail outlet shall be included in the subsequent survey. 

* * * * *

(v) * * *

(A) The minimum number of samples to be included in the survey plan for 

each calendar year shall be calculated as follows:

Where:

   n a b n

n  Z  Z (4*[arc sin( )  arc sin( )] )  St  F  F  Su 2

1 0

2

   
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161

n = minimum number of samples in a year-long survey series. 

However, in no case shall n be smaller than 7,500.

Z = upper percentile point from the normal distribution to achieve a 

one-tailed 95% confidence level (5% -level). Thus, Z equals 

1.645.

Z = upper percentile point to achieve 95% power. Thus, Z equals 

1.645.

= the maximum proportion of non-compliant stations for a region to

be deemed compliant. 

In this test, the parameter needs to be 5% or greater, i.e., 5% or 

more of the stations, within a stratum such that the region is 

considered non-compliant. For this survey, will be 5%.

= the underlying proportion of non-compliant stations in a sample. 

For the first survey plan, will be 2.3%. For subsequent survey

plans, will be the average of the proportion of stations found to 

be non-compliant over the previous four surveys.

Stn = number of sampling strata. For purposes of this survey program, 

Stn equals 3.

Fa = adjustment factor for the number of extra samples required to 

compensate for collected samples that cannot be included in the 

survey, based on the number of additional samples required during 

the previous four surveys. However, in no case shall the value of 

Fa be smaller than 1.1. 

Fb = adjustment factor for the number of samples required to resample 

each retail outlet with test results exceeding the labeled amount 

(e.g. a sample greater than 15 volume percent ethanol dispensed 

from a fuel dispenser labeled as “E15”, a sample with greater than 

10 volume percent ethanol and not more than 15 volume percent 

ethanol dispensed from a fuel dispenser not labeled as “E15”), or a 

sample dispensed from a fuel dispenser labeled as “E15” with 

greater than the applicable seasonal and geographic RVP pursuant 

to § 80.27, based on the rate of resampling required during the 

previous four surveys. However, in no case shall the value of Fb

be smaller than 1.1.

Sun = number of surveys per year. For purposes of this survey program, 

Sun equals 4.

* * * * *

(c) * * *

(4) The survey program plan must be sent to the following address: Director, 

1

1

o

o

o
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Compliance Division, U.S. Environmental Protection Agency, 1200 Pennsylvania 

Ave., N.W. Mail Code 6506J, Washington, D.C. 20460.

(5) * * *

(6) The approving official for a survey plan under this section is the Director of the 

Compliance Division, Office of Transportation and Air Quality. 

* * * * *

17. Section 80.1503 is amended by revising paragraphs (a)(1)(vi)(B)(3), (C)(2), 

(C)(3), and (b)(1)(vi)(B) through (D) as follows:

§ 80.1503 What are the product transfer document requirements for gasoline-ethanol 

blends, gasolines, and conventional blendstocks for oxygenate blending 

subject to this subpart?

(a) * * * 

(1) * * *

(vi) * * *

(B) * * *

(3) “The use of this blendstock/gasoline to manufacture a gasoline-ethanol blend 

containing anything other than between 9 and 10 volume percent ethanol may

cause a summertime RVP violation.”

(C) * * * 
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(2) The requirements in paragraph (a)(1) do not apply to reformulated gasoline 

blendstock for oxygenate blending, as defined in § 80.2(kk), which is subject to 

the product transfer document requirements of § 80.69 and § 80.77.

(3) Except for transfers to truck carriers, retailers, or wholesale purchaser-consumers, 

product codes may be used to convey the information required under paragraph 

(a)(1) of this section if such codes are clearly understood by each transferee.

(b) * * *

(1) * * *

(vi) * * *

(B) For gasoline containing less than 9 volume percent ethanol, the following 

statement: “EX – Contains up to X% ethanol. The RVP does not exceed [fill in appropriate 

value] psi.” The term X refers to the maximum volume percent ethanol present in the gasoline.

(C) For gasoline containing between 9 and 10 volume percent ethanol (E10), the 

following statement: “E10: Contains between 9 and 10 vol % ethanol. The RVP does not 

exceed [fill in appropriate value] psi. The 1 psi RVP waiver applies to this gasoline. Do not mix 

with gasoline containing anything other than between 9 and 10 vol % ethanol.”

(D) For gasoline containing greater than 10 volume percent and not more than 15 

volume percent ethanol (E15), the following statement: “E15: Contains up to 15 vol % ethanol. 

The RVP does not exceed [fill in appropriate value] psi;” or
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* * * * *

18. Section 80.1504 is amended by revising paragraphs (a)(1), (a)(3) and (e), (g) to read as 

follows:

§ 80.1504 What acts are prohibited under this subpart? 

* * * * *

(a)(1) Sell, introduce, cause or permit the sale or introduction of gasoline containing 

greater than 10 volume percent ethanol (i.e., greater than E10) into any model year 2000 or older 

light-duty gasoline motor vehicle, any heavy-duty gasoline motor vehicle or engine, any highway 

or off-highway motorcycle, or any gasoline-powered nonroad engines, vehicles or equipment.

* * * * *

(3) Notwithstanding paragraphs (a)(1) and (a)(2) of this section, no person shall be 

prohibited from manufacturing, selling, introducing, or causing or allowing the sale or 

introduction of gasoline containing greater than 10 volume percent ethanol into any flex-fuel 

vehicle. 

* * * * *

(e)(1) Improperly blend, or cause the improper blending of, ethanol into conventional 

blendstock for oxygenate blending, gasoline or gasoline already containing ethanol, in a manner 
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165

inconsistent with the information on the product transfer document under § 80.1503(a)(1)(vi) or 

§ 80.1503(b)(1)(vi);

(2) No person shall produce E10 by blending ethanol and gasoline in a manner 

designed to produce a fuel that contains less than 9.0 or more than 10.0 volume percent ethanol.

(3) No person shall produce E15 by blending ethanol and gasoline in a manner 

designed to produce a fuel that contains less than 10.0 volume percent ethanol or more than 15.0 

volume percent ethanol.

(4) No person shall produce EX by blending ethanol and gasoline in a manner 

designed to produce a fuel that contains less than 9.0 volume percent ethanol.

* * * * *

(g) For gasoline during the regulatory control periods, combine any gasoline-ethanol 

blend that qualifies for the 1 psi allowance under the special regulatory treatment as provided by

§ 80.27(d) applicable to 9-10 volume percent gasoline-ethanol blends with any gasoline 

containing less than 9 volume percent ethanol or more than 10 volume percent ethanol up to a 

maximum of 15 volume percent ethanol.

* * * * *

19. Section 80.1508 is amended by revising paragraph (b) as follows:

§ 80.1508 What evidence may be used to determine compliance with the requirements 

of this subpart and liability for violations of this subpart?
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* * * * *

(b) Determinations of compliance with the requirements of this subpart and 

determinations of liability for any violation of this subpart may be based on 

information obtained from any source or location. Such information may include, 

but is not limited to, business records and commercial documents.

20. Section 80.1509 is added to read as follows:

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

The provisions of Section 80.9 apply for purposes of determining the ethanol 

content of a gasoline-ethanol blend under this subpart.