EO12866_RFS Pathways II 2060-AR21 FRM FRN_20140422.docx

*** Interagency Working Comments on Draft Language under E.O. 12866 Interagency Review – Draft Version –

Do Not Cite, Quote, or Release During Review – Subject to Further Policy Review***

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2012-0401; FRL –-]

RIN 2060-AR21

Regulation of Fuels and Fuel Additives: RFS Pathways II, and Technical Amendments to 

the RFS Standards and E15 Misfueling Mitigation Requirements

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

SUMMARY: In this final rulemaking, EPA is amending three separate sets of regulations 

relating to fuels. In amendments to the renewable fuels standard (RFS) program regulations,

EPA is clarifying the number of cellulosic biofuel renewable identification numbers that may be 

generated for fuel made with feedstocks of varying cellulosic content, is specifying new and 

amended pathways for the production of renewable fuels made from biogas, and is clarifying or 

amending a number of RFS program regulations that define terms or address registration,

recordkeeping, and reporting requirements. EPA is also making various changes to the 

misfueling mitigation regulations for gasoline that contains greater than 10 volume percent 

ethanol and no more than 15 volume percent ethanol (E15) and to the survey requirements 

associated with the ultra-low sulfur diesel program.

DATES: This rule is effective [INSERT DATE 30 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER]. 
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FOR FURTHER INFORMATION CONTACT: Jon Monger, Office of Transportation and 

Air Quality, Mail Code: 1101A, U.S. Environmental Protection Agency, 1200 Pennsylvania 

Avenue, NW, 20460; telephone number: (202) 564-0628; fax number: (202) 564-1686; email 

address: monger.jon@epa.gov. 

SUPPLEMENTARY INFORMATION:

This preamble follows the following outline: 

I. Why is EPA Taking This Action?

II. Does this Action Apply to Me?

III. Executive Summary

IV. Renewable Fuel Standard (RFS) Program Amendments

A. Renewable Identification Numbers (RIN) Generation for Fuels Made from 

Feedstocks Containing Cellulosic Biomass

1. Background

2. The Cellulosic Content Threshold Approach and its Application to 

Cellulosic Feedstocks Currently Listed in Table 1 to 40 CFR 80.1426

3. Compliance Requirements for Producers of Cellulosic Biofuel made from 

Feedstocks that are not Predominantly Cellulosic 

4. Testing, Registration, Reporting and Recordkeeping Requirements for 

Cellulosic Biofuel

a. Additional Registration Requirements for Producers Seeking to 

 Generate Cellulosic Biofuel RINs

b. Additional Registration Requirements for Renewable Fuel Produced 

 from Energy Cane

c. Additional Registration, Recordkeeping, and Reporting Requirements 

for Producers of Cellulosic Fuels Derived from the Simultaneous 

Conversion of Feedstocks that are Predominantly Cellulosic and 

Feedstocks that are Not Predominantly Cellulosic

5. Determining the Average Adjusted Cellulosic Content of Feedstocks 

Evaluated in the Future

6. Other Comments Received

a. Treatment of Cellulosic Feedstocks Currently Listed in Table 1 to 40 

 CFR 80.1426

b. Feedstocks with Lower Average Cellulosic Content than Feedstocks 

 Currently Listed in Table 1 to § 80.1426

B. Lifecycle Greenhouse Gas Emissions Analysis and Cellulosic Determinations for 

Pathways Using Biogas as a Feedstock

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

2. Determination of the Cellulosic Composition of Biogenic Waste-Derived 

Biogas

a. Landfill Biogas and MSW Digester Gas as Cellulosic in Origin
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b. Municipal Wastewater Treatment Facility Digester Biogas as 

Cellulosic

c. Agricultural Digester Gas as Cellulosic

d. Biogas from Waste Digesters

3. Consideration of Lifecycle GHG Emissions Associated with Biogas 

Pathways

a. Upstream GHG Analysis of Biogas as a Renewable Fuel Feedstock

b. Flaring Baseline Justification

c. Lifecycle GHG Analysis for Renewable Electricity

4. Alternative Biogas Options and Comments

a. Alternative Baseline Approaches

b. Additional Comments on Lifecycle Analysis for Renewable Electricity

C. Regulatory Amendments Related to Biogas

1. Changes Applicable to Renewable Electricity from Biogas Sources

a. Registration and RIN Generation Requirements

b. Distribution and Tracking Requirements

2. Regulatory Changes Applicable to All Biogas Related Pathways

D. Clarification of the Definition of “Crop Residue” and Clarification of Feedstocks 

that EPA Considers Crop Residues

1. Clarification of the Definition of “Crop Residue”

2. Consideration of Corn Kernel Fiber as a Crop Residue

a. Analysis of Corn Kernel Fiber as n a Crop Residue

b. Treatment of Corn Starch that Adheres to Corn Kernel Fiber After 

 Separation from DDG

c. Processing Corn Kernel Fiber

3. Identification of Feedstocks EPA Considers Crop Residues

4. Registration, Recordkeeping, and Reporting Requirements Associated 

with Using Crop Residue as a Feedstock

a. Registration Requirements for Producers Utilizing Crop Residue as a 

 Feedstock

b. Recordkeeping and Reporting Requirements for Producers Utilizing 

 Crop Residue as a Feedstock

E. Amendments to Various RFS Compliance Related Provisions

1. Changes to Definitions

2. Provisions for Small Blenders of Renewable Fuels

3. Changes to Section 80.1450 – Registration Requirements

4. Changes to Facility’s Baseline Volume to Allow “Nameplate Capacity” 

for Facilities not Claiming Exemption from the 20% GHG Reduction 

Threshold

5. Changes to Section 80.1463 – What penalties apply under the RFS 

program?

F. Minor Corrections to RFS Provisions

V. Amendments to the E15 Misfueling Mitigation Rule 

A. Changes to Section 80.1501 – Label

B. Changes to Section 80.1502 – E15 Survey

C. Changes to Section 80.1503 – Product Transfer Documents 
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D. Changes to Section 80.1504 – Prohibited Acts

E. Changes to Section 80.1500 – Definitions

VI. Amendments to the ULSD Diesel Survey

VII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act

D. Unfunded Mandates Reform Act

E. Executive Order 13132 (Federalism)

F. Executive Order 13175 (Consultation and Coordination with Indian Tribal 

Governments)

G. Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks

H. Executive Order 13211: Actions Concerning Regulations That Significantly

Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act

J. Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations.

K. Congressional Review Act 

L. Clean Air Act Section 307(d)

IX. Statutory Provisions and Legal Authority
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I. Why is EPA Taking This Action?

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

Renewable Fuels Standard (RFS) program (40 CFR part 80, subpart M) and misfueling 

mitigation for 15 volume percent (%) ethanol blends (E15) (40 CFR part 80, subpart N) to assist 

regulated parties in complying with RFS and E15 requirements. EPA is also amending the ultra 

low sulfur diesel (ULSD) survey provisions (40 CFR part 80, subpart I) to decrease regulatory

burdens and costs. 

 

II. Does This Action Apply to Me?

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

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

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

include:

Category NAICS 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.
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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. Executive Summary

In this rule, EPA is amending three sets of regulations. First, as described in section IV 

of this preamble, EPA is amending certain parts of the RFS program regulations at 40 CFR part 

80, subpart M. Some of the changes in this rule are of a substantive nature; others are more in 

the nature of technical corrections, including corrections of obvious omissions and errors in 

citation. In this final rule, EPA establishes requirements for determining the number of 

cellulosic biofuel Renewable Identification Numbers (RINs) that will be generated for fuel made 

from a range of cellulosic feedstocks. We also modify regulatory provisions related to 

renewable fuel made from biogas, including a new compressed natural gas (CNG)/liquefied 

natural gas (LNG) cellulosic biofuel pathway, and add a new cellulosic biofuel pathway for 

renewable electricity (used in electric vehicles) produced from biogas. These pathways have the 

potential to provide notable volumes of cellulosic biofuel for use in complying with the RFS 

program, since significant volumes of advanced biofuels are already being generated for fuel 

made from biogas, and in many cases this same fuel will qualify for cellulosic RINs when this 
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rule becomes effective. The approval of these new cellulosic pathways could have an impact on 

EPA’s projection of 2014 cellulosic biofuel volumes in the final 2014 RFS standards rulemaking. 

EPA noted the possibility of such an impact in its proposed rule.

1

 Many of the changes in 

today’s rule will facilitate the introduction of new renewable fuels under the RFS program. By

qualifying these new fuel pathways, this rule provides opportunities to increase the volume of 

advanced, low-GHG renewable fuels—such as cellulosic biofuels—under the RFS program. 

EPA’s analyses show significant lifecycle GHG emission reductions from these fuel types, as 

compared to the baseline gasoline or diesel fuel that they replace. In this rulemaking, EPA also 

clarifies or amends a number of RFS program regulations that define terms or address 

registration, recordkeeping, or reporting requirements. These include amendments related to: 1)

use of crop residue and corn kernel fiber as renewable fuel feedstock; 2) definition of “small 

refinery”; 3) provisions for small blenders of renewable fuels; 4) when EPA may deactivate a 

company registration; 5) the use for registration purposes of “nameplate capacity” for certain 

production facilities that do not claim exemption from the 20% greenhouse gas (GHG) reduction 

threshold; and 6) clarifying what penalties apply under the RFS program. 

EPA is also making various changes to the E15 misfueling mitigation regulations (E15 

MMR) at 40 CFR part 80, subpart N. Among the E15 changes are technical corrections and 

amendments to sections dealing with labeling, E15 surveys, product transfer documents, and 

prohibited acts. We also amend the definitions of E10 and E15 in subpart N to address a concern 

about the rounding of ethanol content test results, in response to a question raised by some 

industry stakeholders. 

 

1

78 FR 71732, November 29, 2013
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In response to questions received from regulated parties, we amend the ultra-low sulfur 

diesel (ULSD) survey provisions in a manner that reduces the number of samples required. This 

will reduce costs and burdens associated with compliance for regulated parties, with no expected 

degradation in the highly successful environmental performance of the program. We received 

helpful comments from the public on these three issues, and provide response to them in this 

preamble. 

We are not finalizing at this time all of the proposed changes in the Notice of Proposed 

Rulemaking.2 Due to comments received and time constraints, we are not taking final action at 

this time on the proposed advanced butanol pathway, the proposed pathways for the production 

of renewable diesel, naphtha and renewable gasoline from biogas, or the proposed additional 

compliance requirements for non-RIN-generating foreign renewable fuel producers. We are 

also not taking final action at this time on the definition of “producer” for renewable CNG/LNG 

and renewable electricity from biogas sources, the definition of responsible corporate officer, or 

the proposed amendments to compliance related provisions in Section 80.1452. The Agency is 

deferring the final decision on these matters until a later time.

IV. Renewable Fuel Standard (RFS) Program Amendments

In this rule, we are clarifying requirements related to existing cellulosic biofuel pathways

under the RFS program, and adopting new cellulosic biofuel pathways. This rule also modifies a 

number of RFS program regulations. 

 

2

78 FR 36042, June 14, 2013.
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A. RIN Generation for Fuels Made from Feedstocks Containing Cellulosic Biomass

1. Background

The Clean Air Act (CAA) defines “cellulosic biofuel” as “renewable fuel derived from 

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

greenhouse gas emissions, as determined by the Administrator, that are at least 60 percent less 

than the baseline lifecycle greenhouse gas emissions.” However, plants do not contain only

cellulose, hemicellulose, and lignin; depending on the plant species and other variables (such as 

variety within a generic feedstock type and storage time) they can also contain varying amounts 

of other compounds. Using cellulosic biofuel production technologies, some of these other 

compounds may be converted, along with the cellulosic compounds of plant feedstocks, into 

renewable fuel. When this occurs, biofuel producers must ascertain what type of RIN or RINs to 

assign to the resulting renewable fuel. Prior to the proposal, EPA had not provided detailed 

information on how other compounds should be treated, which led to uncertainty amongst 

renewable fuel producers about whether their entire volume of fuel produced from a cellulosic 

feedstock would be eligible to generate cellulosic RINs. 

In the proposed rule, EPA noted that existing RFS regulations specify that the fuel made 

from certain types of feedstocks that are predominantly of cellulosic content3(e.g., fuel made 

from the biogenic portion of separated municipal solid waste) are considered entirely made from 

cellulosic material.4 EPA noted that these regulations have been based on the view that the 

statutory requirement that cellulosic biofuel be “derived from cellulose, hemicellulose or lignin” 

 

3

For purposes of this preamble, “cellulosic content” means cellulose, hemicellulose, and lignin.

4

75 FR 14670, 14706. In the March 2010 RFS rulemaking, EPA determined, in certain circumstances, it is 

appropriate for producers to base RIN assignment on the predominant component.
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does not mandate that in all cases the renewable fuel must be produced only from the cellulosic 

material in the renewable biomass. Rather, 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 should be considered cellulosic biofuel when the 

fuel is produced from a feedstock that contains a mixture of cellulosic and non-cellulosic 

materials.5 Consistent with this view and the previously established statutory interpretation 

permitting assignment of a single RIN value to fuel produced predominantly from one source, 

EPA proposed that fuels made from feedstocks that are “predominantly” cellulosic should be 

considered cellulosic biofuel and that all of the volume of fuels from such feedstocks could 

generate cellulosic biofuel RINs. Accordingly, EPA proposed that the entire volume of fuel 

made pursuant to the cellulosic biofuel pathways in Table 1 to § 80.1426 be for cellulosic biofuel 

RINs (D code of 3 or 7), based on EPA’s proposed determination that the feedstocks associated 

with those pathways are composed predominantly of cellulosic materials.6

EPA solicited comment in the Notice of Proposed Rulemaking (NPRM) on several 

alternative approaches, including a “cellulosic content threshold approach.” Under the cellulosic 

content threshold approach, EPA would set a minimum threshold of cellulosic content, and only 

fuels made from feedstocks meeting this minimum threshold would be eligible to generate 

cellulosic RINs for their entire fuel volume. EPA suggested possible thresholds in the range of 

70% to 99.9%. 

 

5

78 FR 36042, 36047.

6 EPA included in the docket for the Notice of Proposed Rulemaking a Memorandum to the Docket, entitled 

“Cellulosic Content of Various Feedstocks,” Docket EPA-HQ-OAR-2012-0401. This memorandum discusses the 

cellulosic content of various feedstocks, including most of the cellulosic feedstocks listed in cellulosic biofuel 

pathways in Table 1 to 40 CFR 80.1426. The memorandum notes that the average cellulosic content of these 

feedstocks is above 75%. Because of the high degree of natural variability in biomass, average compositions are 

likely more meaningful than any single value reported, because no single value can reflect the compositional range 

and variability present. 
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After evaluating the comments received, EPA has decided to finalize a cellulosic content 

approach, with a minimum cellulosic content threshold of 75%. In section IV.A.2, below, we 

discuss the merits of the approach generally, and how we intend to implement it for feedstocks 

used in cellulosic biofuel pathways listed in Table 1 to § 80.1426. This includes special 

provisions for energy cane and annual cover crops. In section IV.A.3 we discuss how RINs 

should be allocated for fuel made from feedstocks containing less than 75% cellulosic content,

and the registration, recordkeeping and reporting requirements associated with the rule. In 

section IV.A.4 we discuss application of the cellulosic content threshold approach to feedstocks 

evaluated in the future, and in IV.A.5 we discuss in more detail the comments received and our 

responses to them. 

2. The Cellulosic Content Threshold Approach and its Application to Cellulosic 

Feedstocks Currently Listed in Table 1 to 40 CFR 80.1426

EPA has decided to finalize the cellulosic content threshold approach and to set the 

minimum threshold as an average adjusted cellulosic content of 75%, measured on a dry mass 

basis.7 Consistent with previous precedents permitting assignment of a single RIN value to fuel 

produced predominantly from one source, fuel made from feedstocks that EPA determines meet

this minimum threshold will, therefore, be eligible for cellulosic biofuel RINs for the entire fuel 

volume produced. As a result of this rule, all of the cellulosic biofuel made from the following 

feedstocks is eligible to generate cellulosic RINs for the entire volume of fuel produced: crop 

 

7

“Adjusted cellulosic content” is the percent of organic (non-ash) material that is cellulose, hemicellulose, or lignin, 

as described in the Memorandum to the Docket, “Cellulosic Content of Various Feedstocks,” Docket EPA-HQOAR-2012-0401. 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. 
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residue, slash, pre-commercial thinnings and tree residue, switchgrass, miscanthus, Arundo 

donax, Pennisetum purpureum, and biogas from landfills, municipal wastewater treatment 

facility digesters, agricultural digesters, and separated MSW digesters (collectively

“predominantly cellulosic feedstocks”). Fuels made from feedstocks which do not meet this 

minimum threshold will be able to generate both cellulosic and non-cellulosic RINs using the 

apportionment methods described below. 

However, EPA is not making the same categorical determination for biofuel made from 

energy cane or cover crops. Because considerable variability in cellulosic content may exist in 

plants that may be considered sugarcane or energy cane, we have amended the definition of 

energy cane to specify that it refers only to cultivars that have been demonstrated to contain an 

average adjusted cellulosic content of at least 75%. Fuel made through cellulosic biofuel 

pathways from feedstocks meeting the definition of energy cane are eligible for cellulosic biofuel 

RINs. 

Annual cover crops will also be treated differently than other cellulosic feedstocks in 

Table 1. We do not have enough data about annual cover crops to be confident that they will 

always meet the 75% threshold. Therefore, in Table 1 annual cover crops will still be listed as 

"cellulosic components of annual cover crops." However, we are also adding a new pathway for 

"non-cellulosic components of annual cover crops," which will be eligible for advanced RINs. 

In the future, as more information becomes available, we may revisit this determination. 
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EPA believes that a 75% content threshold is consistent with the statutory definition of 

cellulosic biofuel, as EPA indicated in the NPRM, and satisfies the objective identified in the 

proposed rule of allowing fuels made from feedstocks that are “predominantly” cellulosic to 

generate cellulosic biofuel RINs for their entire fuel volume. A threshold of 75% also allows 

fuel made from all predominantly cellulosic feedstocks to generate RINs for their entire fuel 

volume, consistent with EPA’s principal proposal. As compared to alternative approaches 

discussed in the NPRM, the approach will also greatly simplify compliance by cellulosic biofuel 

producers and reduce regulatory burden, since for qualifying cellulosic feedstocks the approach 

to RIN generation is straightforward and will not require testing or apportionment of RINs. 

These benefits, in turn, should help to promote cellulosic biofuel production, consistent with 

Congressional objectives. This final rule will help to ensure that cellulosic RINs are in fact only 

generated for fuels derived predominantly from cellulosic materials. 

Because all of the fuel produced from predominantly cellulosic feedstocks will qualify

for cellulosic biofuel RINs, EPA is making related modifications to the text in Table 1 to § 

80.1426. Specifically we are deleting the references to “cellulosic biomass from” in rows K, L, 

M, and N to reflect that fuel made pursuant to the listed pathways from the feedstocks listed 

without this modifier are eligible to generate cellulosic biofuel RINs even though the feedstocks 

contain some non-cellulosic compounds. However, because certain production processes that 

can be used to produce cellulosic biofuel may be employed so as to only derive fuel from the 

non-cellulosic components of feedstock, EPA is also modifying the production process 

description in these lines in the table to specify that the production process must convert the 

cellulosic components of feedstock into biofuel. The effect is that cellulosic RINs may only be 
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generated when a production process is employed that in fact produces biofuel that is derived 

from the cellulosic content of feedstocks. 

 Many commenters agreed that the cellulosic feedstocks currently listed in Table 1 are 

predominantly composed of cellulosic components and that allowing all of the fuel derived from 

these feedstocks to qualify for cellulosic biofuel RINs is consistent with the statutory definition 

of cellulosic biofuels. Some commenters asserted that allowing all the fuel produced from the 

cellulosic feedstocks in Table 1 was an overly expansive interpretation of the statutory definition 

of cellulosic biofuels.8EPA considers the statutory definition to be ambiguous on the point of 

whether cellulosic biofuel RINs may be generated for fuel produced from predominantly

cellulosic material, allowing EPA discretion to reasonably interpret this definition. As 

established in previous rulemakings,9EPA believes the statutory definition does not mandate that 

in all cases cellulosic biofuel must be produced exclusively from cellulosic material in the 

renewable biomass, and today’s rule adopts a common-sense approach to the matter that allows 

fuel made from predominantly cellulosic feedstocks to qualify as cellulosic biofuel. 

In the NPRM, EPA invited comment on an appropriate threshold value for use with a 

cellulosic threshold approach. EPA received comments on a wide range of suggested threshold 

values, with many commenters supporting 70% and 80%, some suggested multiple thresholds,

and some commenters requesting much higher (95%) thresholds. Some commenters opposed 

 

8 Comments provided by AFPM/API (EPA-HQ-OAR-2012-0401-0128) and Chevron (EPA-HQ-OAR-2012-0401-

0171).

9 EPA has previously considered instances where fuel would generate cellulosic biofuel RINs even if produced from 

feedstocks containing both cellulosic and non-cellulosic materials. In the March 2010 RFS rulemaking, EPA 

determined that biofuel from separated yard waste qualified as cellulosic and would generate cellulosic RINs 

because separated yard waste was “largely cellulosic.” 75 FR 14794, March 26, 2010.
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setting a cellulosic content threshold because there is not a consensus on a value for a threshold, 

and one commenter asserted that setting a minimum threshold content may stifle development of 

new feedstocks. In response, EPA has decided that a cellulosic content threshold of 75% is a 

reasonable value that appropriately implements the statutory requirements.10 Feedstocks which 

do not meet or exceed a 75% minimum cellulosic content threshold have a more significant noncellulosic portion of the feedstock which could contribute to the volume of fuel produced. These 

feedstocks start to resemble traditional crops that have been developed for purposes other than 

energy generation, such as crops that are grown for their sugar content (e.g., sugarcane, sweet 

sorghum). EPA believes that a threshold significantly below 75% might inadvertently encourage 

use of multipurpose feedstocks for the production of fuels that are qualified for cellulosic RINs, 

in lieu of the feedstocks with a higher cellulosic content that Congress envisioned would be used 

to produce this category of biofuel. On the other hand, a threshold higher than 75% would result 

in regulatory and administrative burdens on the use of predominantly cellulosic feedstocks.11 

EPA believes that the 75% threshold strikes a reasonable balance among these considerations, 

while remaining consistent with the statutory definition of cellulosic biofuels and past regulatory

approaches that EPA has taken for specified feedstocks. While arguments could be made for 

other numeric values, EPA believes that a rational basis exists for settling on 75%, as explained 

in this rule, and is within EPA’s exercise of discretion to reasonably interpret the CAA. EPA 

believes that 75% is consistent with the concept that cellulosic content should be predominant in 

feedstocks for which all resulting fuel is qualified for cellulosic biofuel RINs. The 75% 

 

10 All fuel that qualifies for cellulosic biofuel RINs must achieve a minimum 60% lifecycle greenhouse gas 

emissions reduction as compared to baseline fuels, even if some portion of the fuel is derived from non-cellulosic 

materials. 

11 Requirements for determining the number of cellulosic biofuel RINs that may be generated for fuel derived from 

feedstocks that do not satisfy the minimum cellulosic content threshold adopted in today’s rule are described in 

Section IV.A.3 of this preamble. 
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threshold also eliminates the current regulatory uncertainty for cellulosic biofuel producers,

minimizes regulatory burden, and as a consequence should help promote the production of the 

category of renewable fuels that provides the most lifecycle GHG emissions benefits. 

3. Compliance Requirements for Producers of Cellulosic Biofuel made from Feedstocks 

that are not Predominantly Cellulosic 

In the proposal, EPA invited comment on how to determine the appropriate type of RIN

or RINs for fuel that is produced from feedstocks that contain cellulosic material, but where the 

feedstocks are not predominantly cellulosic in content. Based on the comments received, EPA 

believes that the existing regulations at § 80.1426(f)(3)(vi) provide an appropriate mechanism for 

allocation of RINs, both for processes that convert two or more feedstocks simultaneously where 

not all feedstocks are predominantly cellulosic, and for processes using a single feedstock that 

has an average cellulosic content below 75%. However, EPA is amending the regulations, by

adding new registration, recordkeeping, and reporting requirements (“RRR requirements”) to 

allow EPA to verify that the formula in § 80.1426(f)(3)(vi) is being applied appropriately. EPA 

believes that, to relieve regulatory burden and streamline program implementation, it makes 

sense to establish a 75% minimum cellulosic content threshold above which testing and reporting 

of cellulosic content and RIN apportionment is not necessary. However, when fuel is made from 

feedstocks below the 75% cellulosic content threshold, EPA believes that testing of the 

feedstock’s cellulosic content is appropriate, and that RINs should be apportioned according to 

the test results. 
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EPA recognizes that one result of today’s rule is that fuel made from a feedstock meeting 

the 75% minimum cellulosic content threshold will qualify completely for cellulosic RINs, 

whereas fuel made from a feedstock containing 74% cellulosic content would, through the 

apportionment formula, only qualify for at most 74% cellulosic RINs. EPA believes it is 

appropriate to have simplified procedures for fuel made from feedstocks that are predominantly 

cellulosic, and has selected a 75% threshold to identify these feedstocks. At some level of 

content, EPA believes there is less benefit to requiring that manufacturers account for the 

increasingly small non-cellulosic content of the feedstock. EPA has determined that 75% 

cellulosic content is a large enough percentage that it is appropriate to allow full qualification. 

This results in a simplified implementation approach for the large majority of feedstocks 

typically considered “cellulosic” in nature. While this obviously allows significantly greater 

benefits to fuel with feedstock above 75%, compared with fuel from feedstock just below 75%, 

the difference in process and result is the inevitable result of having any sort of threshold level. 

Wherever EPA set the threshold, fuels made from feedstocks that just fail to satisfy the threshold 

will, inevitably, be treated differently. For the reasons provided, EPA believes that the approach 

is reasonable and appropriate.

As one possible approach to addressing the disparity between fuels made from feedstocks 

that meet the 75% minimum cellulosic content threshold and those that do not, EPA considered 

the option of allowing up to an additional 25% of fuel made from non-qualifying feedstock to 

qualify for cellulosic biofuel RINs, beyond levels that are determined to reflect the cellulosic

converted fraction. While this approach could be seen as providing more equitable treatment of 

fuels made from feedstocks that satisfy the 75% cellulosic content threshold and those that do 
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not, EPA determined that it would be inappropriate. The principal objective of the cellulosic 

content approach adopted today is to minimize burdens and streamline program implementation 

for both EPA and producers of cellulosic biofuel and provide incentives for production of fuels 

that are 75% or greater cellulosic content. However, for fuels made from feedstocks that do not 

meet the minimum cellulosic content threshold, testing (either of cellulosic content of feedstock 

or of the proportion of fuel derived from cellulosic content) will be required. In cases where the 

expense and burden of testing is undertaken, EPA believes it is most consistent with the 

objectives of the Act for RIN apportionment to accurately reflect the test results.

4. Testing, Registration, Reporting and Recordkeeping Requirements for Cellulosic 

Biofuel 

The agency requested comment on test methods available to determine what percentage

of a finished biofuel volume was derived from cellulosic or non-cellulosic components. At the 

time of the proposal, we were not aware of any ready test that could be used to identify the 

amount of a finished fuel that was derived from cellulosic versus non-cellulosic components. 

However, we received several comments that suggested there are methods available for this 

purpose.12 Given this new information, we believe it is reasonable to require the use of these 

existing test methods under certain circumstances when fuel is produced from feedstocks that are 

not predominantly cellulosic to verify that the values used in the formula at § 80.1426(f)(3)(vi) 

are as accurate as possible. Therefore, as part of this final rule, we are requiring the use of these 

 

12 Comments suggested various methods to determine the converted fraction, including approaches for performing a 

mass-balance accounting of feedstock components converted to fuel products. As described in the associated memo 

to the docket, a mass balance approach which meets the requirements discussed below is an appropriate method for 

calculating CF. 
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available test methods under certain circumstances described below to help ensure that an 

appropriate number of cellulosic RINs are generated when applying the formula at § 

80.1426(f)(3)(vi). 

As described in more detail below, different feedstocks and processes require more 

information to ensure a high degree of confidence that cellulosic biofuel RINs are appropriately 

generated. These registration, recordkeeping, and reporting requirements, including changes to 

the production process requirements of Table 1 to § 80.1426, are described in the following 

sections. 

a. Additional Registration Requirements for Producers Seeking to Generate 

Cellulosic Biofuel RINs

At registration or during registration updates under § 80.1450(d)(3),13 all producers 

seeking to use a cellulosic biofuel pathway listed in rows K, L, M, and N of Table 1 to §

80.1426, or as otherwise approved by EPA, must demonstrate that their production process has 

the ability to convert cellulosic components to fuel by including (1) a process diagram with all 

relevant unit processes labeled and a designation of which unit process is capable of performing 

cellulosic treatment; (2) a description of the cellulosic biomass treatment process; and (3) a 

description of the mechanical, chemical, and biochemical mechanisms by which cellulosic 

materials can be converted to fermentable sugars or biofuel products. In addition, an 

independent professional engineer must verify that the equipment to perform each of the relevant 

 

13 These requirements apply to all future registrations and registration updates for producers making renewable fuel 

using a cellulosic biofuel pathway, including cellulosic biofuel pathways approved pursuant to a § 80.1416 petition

process. 
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unit processes required to convert cellulosic biomass to biofuel is in place as part of registration, 

in order to demonstrate that the conversion process will derive the finished fuel from cellulosic 

components. 

b. Additional Registration Requirements for Renewable Fuel Produced from Energy

Cane

Energy cane is derived from sugarcane, which can be and is bred for a variety of uses and 

a wide range of fiber and sugar contents.

14

 Prior to this rule, energy cane was defined in 40 CFR 

80.1401 as “a complex hybrid in the Saccharum genus that has been bred to maximize cellulosic 

rather than sugar content.” This definition did not include any specific requirements regarding 

cellulosic content. However, some cultivars15 of energy cane are bred to have a high sugar

content and therefore have a lower percent cellulosic content. For example, two cultivars 

released by USDA, which are commonly referred to as energy cane,16 have cellulosic contents of 

approximately 50% on a dry matter basis.17 Fuel produced from these cultivars would not be 

 

14 Tew, Thomas L. and Robert M. Cobill. 2008. Genetic improvement of sugarcane (Saccharum spp.) as an energy 

crop. p. 249-272. In: W. Vermerris (ed.) Genetic Improvement of Bioenergy Crops. Springer.

15 A cultivar is a subset of a species. USDA has provided a list of sugarcane cultivars (including energy cane). This 

list, “USDA ARS Sugarcane Release Notices 1999 to 2012,” is included in the docket.

16 Ho 00-961 and HoCP 91-552; Tew, Thomas L. and Robert M. Cobill. 2008. Genetic improvement of sugarcane 

(Saccharum spp.) as an energy crop. p. 249-272. In: W. Vermerris (ed.) Genetic Improvement of Bioenergy Crops. 

Springer.

17 Tew, T. L. et al, 2007. “Notice of release of high-fiber sugarcane variety Ho 00-961.” Sugar Bulletin, 85(10) 23-

24. Tew, T. L. et al, 2007. “Notice of release of high-fiber sugarcane variety HoCP 91-552.” Sugar Bulletin, 85(10) 

25-26. Ho 00-961 has a Brix value of 17-19% cane, and HoCP 91-552 has a Brix value of 15-18% cane, where Brix 

is a measure of the total soluble solids, including sugar. These Brix values are similar to the Brix value of a 

traditional sugarcane cultivar presented in these papers. Ho 00-961 has a percent cellulosic content of 47%, and 

HoCP 91-552 has a percent cellulosic content of 48%. The percent cellulosic content is calculated using the fiber 

content (as a measure of the cellulosic content) presented in the papers, divided by the total solids content (Brix + 

fiber). By contrast, energy cane cultivar L 79-1002, which has a higher fiber content, has a Brix value of 8-12% 

cane, as reported by Bischoff, K.P. et al, 2008. “Registration of ‘L 79-1002’ sugarcane.” Journal of Plant 

Registrations, 2(3) 211-217, and Hale, A.L. 2010, “Notice of release of a high fiber sugarcane variety Ho 02-113.” 

Sugar Bulletin, 88(10) 28-29.
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derived predominantly from cellulose, hemicellulose, and lignin; instead, the fuel would largely 

be derived from sugar. Therefore, in this rule EPA is amending the definition of energy cane to 

specify that it means cultivars that have, on average, at least 75% adjusted cellulosic content on a 

dry matter basis. Cultivars that do not meet the 75% adjusted cellulosic content threshold will be 

considered sugarcane. With this clarification, only cultivars that have predominantly cellulosic 

content are included in the definition of energy cane and are qualified to generate cellulosic RINs 

for the entire volume of finished fuel produced. When cultivars containing less than 75% 

adjusted cellulosic content are used to make fuel, we consider those cultivars to be sugarcane and 

eligible to generate advanced biofuel RINs for the portion of fuel that is derived from sugar. If 

the bagasse is converted to renewable fuel, cellulosic RINs could be generated for the amount of 

fuel derived from the bagasse (under the existing crop residue pathway).

Upon registration, fuel producers seeking to produce cellulosic biofuel using energy cane 

feedstocks will need to submit data showing that the average adjusted cellulosic content of each 

energy cane cultivar they intend to use is at least 75%, based on the average of at least three

representative samples of each cultivar.

18

 Cultivars must be grown under normal growing 

conditions and consistent with accepted farming practices. Samples must come from a feedstock 

supplier that the fuel producer intends to use when operating their production process and must 

represent the feedstock supplier’s range of growing conditions and locations. Producers that

decide after initial registration to use energy cane or a new energy cane cultivar will need to 

update their registration and provide data to EPA demonstrating the average adjusted cellulosic 

 

18 As described above and in the Memorandum to the Docket, “Cellulosic Content of Various Feedstocks,” Docket 

EPA-HQ-OAR-2012-0401, adjusted cellulosic content is the percent of organic (non-ash) material that is cellulose, 

hemicellulose, and lignin. Therefore, a calculation of the adjusted cellulosic content requires a measurement of the 

cellulosic content, as well as a measurement of the ash content of a feedstock. 
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content for each cultivar they intend to use. Cellulosic content data must come from an 

analytical method certified by a voluntary consensus standards body (VCSB) or a non-VCSB 

method that would produce reasonably accurate results.19 Producers using a non-VCSB 

approved method will need to show that the method used is an adequate means of providing 

reasonably accurate results by providing peer reviewed references to the third party engineer 

performing the engineering review at registration. Because energy cane can be bred for a variety 

of uses, and different cultivars of energy cane can have different amounts of cellulosic material, 

these registration requirements will help ensure that fuel producers know whether or not the 

cultivars they intend to use meet the 75% adjusted cellulosic content threshold and are qualified 

to generate RINs for the entire volume of finished fuel. EPA expects to require similar 

registration requirements for producers seeking to produce cellulosic biofuel using feedstocks

that will be evaluated in the future that could similarly be bred for a wide range of uses and fiber 

content. 

c. Additional Registration, Recordkeeping, and Reporting Requirements for 

Producers of Cellulosic Fuels Derived from the Simultaneous Conversion of Feedstocks

that are Predominantly Cellulosic and Feedstocks that are Not Predominantly Cellulosic

Under § 80.1426(f)(3)(vi), if a renewable fuel producer produces a single type of 

renewable fuel (e.g., ethanol) using two or more different feedstocks which are processed 

simultaneously, and at least one of the feedstocks does not have a minimum 75% average 

 

19 For example, AOAC 2002.04 “Amylase-Treated Neutral Detergent Fiber in Feeds” or ASTM E1758 

“Determination of Carbohydrates in Biomass by High Performance Liquid Chromatography.” Voluntary consensus 

standards bodies are defined as “domestic or international organizations which plan, develop, establish, or 

coordinate voluntary standards using agreed-upon procedures.” See “Federal Use of Standards,” Office of 

Management and Budget, http://www.whitehouse.gov/omb/fedreg_a119rev.
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adjusted cellulosic content, the producer would have to determine how much of the finished fuel 

is derived from the cellulosic versus non-cellulosic components of the feedstocks and assign 

RINs to the finished fuel based on the relative “converted fractions” (CF).20 Given variations in 

individual conversion processes, enzymes used, and other differences, the amount of finished 

fuel that is derived from the cellulosic components can vary. For example, the process and 

enzymes used may do a better job of converting the sugars and starches in a feedstock than the 

cellulose or hemicellulose. In such a case the cellulosic content of the feedstock may not be a 

good indicator of the amount of finished biofuel that is derived from cellulosic materials. 

Furthermore, depending on the conversion process used, the amount of information needed to 

determine how much of the finished fuel is derived from cellulosic components will also vary. 

Therefore, EPA believes it is prudent to include specific requirements related to 

calculating the cellulosic converted fraction and to specify appropriate registration, 

recordkeeping, and reporting requirements for producers seeking to generate cellulosic RINs 

using two or more feedstocks21 which are processed simultaneously. EPA has attempted to 

minimize additional requirements, so has limited certain provisions to circumstances where a 

producer seeks to generate cellulosic RINs for fuel produced by “in situ” biochemical hydrolysis 

treatment where cellulosic and non-cellulosic components of feedstocks (at least one of which is 

not predominantly cellulosic) are simultaneously hydrolyzed to fermentable sugars (e.g., corn 

starch and a crop residue). These additional registration, recordkeeping, and reporting 

requirements will also apply to producers that combine cellulosic- and non-cellulosic-derived 

 

20 See § 80.1426(f)(3)(vi). Converted fraction (CF) refers to the portion of the feedstock converted into renewable 

fuel by the producer and is used in calculating cellulosic RIN volumes generated.

21 As described in section IV.A.4, if a future feedstock does not meet the 75% threshold, we would expect to create 

two separate feedstocks and pathways. 
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sugars from separate hydrolysis units prior to fermentation. In the latter case, the cellulosic 

conversion factor can be obtained by analyzing feedstock conversion in the cellulosic hydrolysis 

unit.

A fundamental distinction relevant to verifying conversion of cellulosic components is 

whether or not a process converts the entire organic fraction into fuel. Thermochemical 

conversion is an example of a process that converts the entire organic fraction. Thermochemical 

processes mainly consist of (1) pyrolysis: a process in which cellulosic biomass is decomposed 

with temperature to bio-oils that can be further processed to produce a finished fuel or (2) 

gasification: a process in which cellulosic biomass is decomposed to synthesis gas (“syngas”) 

that with further catalytic processing can produce a finished fuel product. Thermochemical 

processes typically convert all of the organic components of the feedstock into finished fuel, thus 

the finished fuel produced from the thermochemical process is proportional to the cellulosic 

content of the organic fraction of the feedstock material. 

Alternatively, biochemical conversion is an example of a non-thermochemical type of 

process that does not convert the entire organic fraction into fuel. Biochemical processes convert 

different fractions of the cellulosic and non-cellulosic carbohydrates to finished fuel. During this 

process, enzymatic hydrolysis releases sugars from feedstock carbohydrates and employs

microorganisms to convert those sugars into fuels. 

Since thermochemical processes typically convert all of the organic components of the 

feedstock into finished fuel, fewer recordkeeping and reporting requirements are necessary to 
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verify appropriate cellulosic biofuel RIN generation for producers using thermochemical 

conversion processes. In addition, since the finished fuel produced from the thermochemical 

process is proportional to the cellulosic content of the organic fraction of the feedstock material, 

demonstration of the cellulosic content of the feedstock is the only additional registration 

requirement that is necessary for thermochemical processes. In contrast, biochemical conversion 

does not convert the entire organic fraction into fuel and the converted fraction is variable and 

not proportional to the cellulosic content of the organic fraction of the feedstock material. 

Therefore, we believe it is prudent to require additional registration, reporting, and 

recordkeeping requirements for in situ biochemical conversion processes to ensure that cellulosic 

RINs are appropriately generated for the finished fuel. 

In the proposal, EPA requested comment on conversion technologies, and we also 

requested comment on whether to allow 100% of the fuel produced via biochemical processes to 

generate cellulosic RINs. EPA received comments supporting our proposal to allow biochemical

processes to generate 100% cellulosic RINs but, as discussed above, biochemical processes will 

also typically convert portions of the sugar and starch components of the feedstock. If 

feedstocks containing significant amounts of starches and sugars are used in a biochemical 

process, the resulting fuel may not be predominantly of cellulosic origin. Therefore, EPA is not 

finalizing this aspect of its proposal. Instead, EPA has finalized the cellulosic threshold 

approach which will allow cellulosic biofuel RIN generation for all fuel produced by cellulosic 

conversion processes using feedstocks determined to have an average adjusted cellulosic content 

of at least 75%. 

 
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i. Registration Requirements

As explained in section IV.A.3.a, at registration, producers seeking to use a cellulosic 

biofuel pathway listed in rows K, L, M, and N of Table 1 to § 80.1426, or as otherwise approved 

by EPA, must demonstrate the ability to convert cellulosic components of their feedstock to fuel. 

In addition, producers seeking to generate cellulosic RINs (D code of 3 or 7) using two or more 

different feedstocks (at least one of which does not have at least 75% average adjusted cellulosic 

content) which are processed simultaneously using a thermochemical conversion process will be 

able to allocate cellulosic RINs using the formula in § 80.1426(f)(3)(vi) where the cellulosic 

fraction is proportional to the cellulosic content of the feedstock. The average adjusted cellulosic 

composition of the feedstock will have to be reported at registration, based on the average of at 

least three representative samples, and cellulosic content data must come from an analytical 

method certified by a voluntary consensus standards body (VCSB) or a non-VCSB method that 

would produce reasonably accurate results.22 Producers using a non-VCSB approved method 

will need to show that the method used is an adequate means of providing reasonably accurate 

results by providing peer reviewed references to the third party engineer performing the 

engineering review at registration. Producers that later want to change their feedstock will need 

to update their registration. 

Producers generating RINs with a D code of 3 or a D code of 7 using two or more 

different feedstocks (at least one of which does not have at least 75% average adjusted cellulosic 

content) which are processed simultaneously through an in situ biochemical hydrolysis treatment 

 

22 For example, AOAC 2002.04 “Amylase-Treated Neutral Detergent Fiber in Feeds” or ASTM E1758 

“Determination of Carbohydrates in Biomass by High Performance Liquid Chromatography.” 
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will similarly have additional registration requirements to help ensure that cellulosic RINs are 

being generated accurately. At the time of registration, such a producer must submit (1) the 

overall fuel yield (total fuel volume / total feedstock mass)23, including supporting data 

demonstrating this yield and a discussion of the possible variability in overall fuel yield that 

could be expected between reporting periods; (2) the cellulosic converted fraction (CF) that will 

be used for generating RINs under § 80.1426(f)(3)(vi), including chemical analysis data

(described in more detail below) supporting the calculated cellulosic CF and a discussion of the 

possible variability that could be expected between reporting periods; and (3) a description of 

how the cellulosic CF is determined and calculations showing how the data were used to 

determine the cellulosic CF. 

Data used to calculate the cellulosic CF by producers using in situ biochemical hydrolysis 

treatment who seek to generate cellulosic RINs must be representative and obtained using an 

analytical method certified by a voluntary consensus standards body (VCSB) or using a nonVCSB method that would produce reasonably accurate results. If using a non-VCSB approved 

method to generate the data required to calculate the cellulosic CF for a given fuel, then the 

producer will need to show that the method used is an adequate means of providing reasonably 

accurate results by providing peer reviewed references to the third party engineer performing the 

engineering review at registration. A full description of the formulas in § 80.1426(f)(3) used to 

calculate RINs for renewable fuel described by two or more pathways, including methods used 

to calculate CF, can be found in the associated memo to the docket.

24

 

 

23 The overall fuel yield is determined to be the total volume of fuel produced (e.g., cellulosic plus non-cellulosic 

fuel volume) divided by the total feedstock mass (sum of all feedstock masses).

24 INSERT CITE TO MTD ON HOW TO CALCULATE THE CF
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ii. Additional Cellulosic Converted Fraction (CF) Reporting and Recordkeeping 

Requirements

Producers generating cellulosic RINs using two or more different feedstocks (at least one 

of which does not have at least 75% average adjusted cellulosic content) which are processed 

simultaneously using an in situ biochemical hydrolysis treatment will also have additional 

recordkeeping and reporting requirements to provide ongoing verification that the cellulosic 

RINs are being accurately allocated. 

The converted fraction provides a comprehensive accounting of the portion of a feedstock 

that is converted into cellulosic fuel. The formula in § 80.1426(f)(3)(vi) requires producers to 

calculate a CF for each category of RINs generated. That CF is then used to determine the 

appropriate number and type of RINs to assign to a batch of renewable fuel. 

Comments suggested calculating the amount of the finished fuel derived from the 

cellulosic and non-cellulosic components could create an administrative burden if required on a 

batch-by-batch basis. EPA is structuring applicable registration, recordkeeping, and reporting 

requirements in a manner intended to result in accurate accounting while also avoiding overly

burdensome requirements. Therefore the final rule provides that the cellulosic CF will initially

be based on the data submitted at registration.

 

This upfront CF determination will apply to RINs produced until a new CF allocation is

available and reported. The interval at which a new CF must be reported is similarly intended to 
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avoid unnecessary burden on producers. EPA is requiring that low volume producers calculate 

the cellulosic CF annually. However, for higher volume producers, we believe more frequent 

calculating and reporting is prudent and are requiring that the cellulosic CF be recalculated

within 10 business days of every 500,000 gallons of cellulosic RINs generated. This information 

will be reported in the quarterly report. Low-volume producers may report the current CF value 

used to generate RINs on their quarterly reports if they have not produced 500,000 cellulosic 

gallons in the calendar year. Periodic cellulosic CF determinations will be made by collecting 

new process data and performing the same chemical analysis approved at registration, using 

representative data. If at any point new data show that the CF is different from that reported in 

the previous period, the formula used to generate RINs at § 80.1426(f)(3)(vi) must be updated as 

soon as practical but no later than 5 business days after the producer receives the new data. If

new testing data results in a change to the cellulosic CF, only RINs generated after the new 

testing data were received would be affected. In addition if a renewable fuel producer changes 

their process (for example, stops using enzymes in their cellulosic hydrolysis or changes the 

enzymes used), the producer must calculate a new CF and update their registration consistent 

with § 80.1450(d). 

Given the natural variation in cellulosic content and conversion efficiencies, EPA 

recognizes some variation will exist in the amount of cellulosic fuel that is derived from the 

cellulosic components of a feedstock. However, certain circumstances raise significant concerns 

with respect to cellulosic RIN generation. While we believe that variation within 10% of the 

previously calculated numbers may result under normal operating conditions, larger variations 

raise concerns that the process or feedstock has significantly changed from what was approved at 
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registration. If the cellulosic CF deviates from the previously calculated cellulosic converted 

fraction by 10% or more, it is appropriate for the producer to alert EPA to this change and update 

the formula used to calculate RIN allocations as soon as possible. The producer must (1) notify

EPA within 5 business days and (2) adjust the formula used to generate RINs at § 

80.1426(f)(3)(vi) for all fuel generated as soon as practical but no later than 5 business days after 

the producer receives the new data. As explained above, if new testing data results in a change 

to the cellulosic CF, only RINs generated after the new testing data were received would be 

affected.

5. Determining the Average Adjusted Cellulosic Content of Feedstocks Evaluated in the 

Future

EPA will apply the minimum average adjusted cellulosic content threshold framework 

described above for feedstocks evaluated in the future. If these feedstocks meet the 75% average 

adjusted cellulosic threshold, we will allow the fuel producer using them in approved cellulosic 

biofuel pathways to generate cellulosic RINs for all of the finished fuel volume. If the feedstock 

does not meet the 75% threshold, we would expect to create two separate regulatory pathways –

one involving “cellulosic components of [feedstock X]” and another involving “non-cellulosic 

components of [feedstock X]”). A producer using both of these feedstocks which are processed 

simultaneously, would allocate cellulosic and non-cellulosic RINs using the formula in § 

80.1426(f)(3)(vi). Fuel producers using feedstocks evaluated in the future would also be subject 

to the appropriate registration, reporting, and recordkeeping requirements described in section 

IV.A.3. 
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EPA anticipates that it will determine the cellulosic composition of newly evaluated 

feedstocks that might be used to produce cellulosic biofuel up front when it conducts a lifecycle 

analysis of a pathway involving the new feedstock. For example, EPA will calculate the average 

adjusted cellulosic composition of feedstocks such as energy sorghum and energy beets at the 

same time that we evaluate the lifecycle GHG emissions associated with these feedstocks. As 

with lifecycle analyses, EPA may undertake the evaluation of the cellulosic content of feedstocks 

either in the context of a rulemaking to amend Table 1 to § 80.1426, or in response to an 

individual petition submitted pursuant to § 80.1416. In either case, EPA will clarify whether the 

feedstock meets the 75% cellulosic content threshold allowing cellulosic RINs to be generated 

for the entire fuel volume produced, or if the producer should use the apportionment method in §

80.1426(f)(3)(vi). Future petitioners pursuant to the process in § 80.1416 should submit peerreviewed data on the average cellulosic content of their feedstock as well as their own estimate 

of cellulosic content based on these data. 

In the proposal, EPA sought comment on whether individual producers should be 

responsible for submitting data on the cellulosic content of their feedstock, or whether EPA 

should determine whether feedstocks meet the threshold based on existing published data. We 

received comments that EPA should determine whether feedstocks meet the threshold and should 

use existing published data. In addition, we received a range of opinions on whether the 

producer should also be required to provide data. Some comments suggested that EPA should 

use both existing published data and data from the producer, because academic publications may

not be up to date with industry. Some comments said fuel producers should be allowed to 
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present data if their feedstocks have higher cellulosic content than published data. One comment 

said that if no peer-reviewed data exist, the producers should provide data. Some comments 

suggested that producers should be required to maintain documentation of cellulosic content, as 

well as evidence that the cellulosic content was the primary source of biofuels production. 

Others commented that producers should not be required to measure, submit and certify

feedstock composition. In the future, producers should submit data regarding cellulosic content 

in order to ensure a determination is made on the most up to date data. EPA will evaluate this 

information, together with other available information, on a case by case basis to.... 

6. Other Comments Received

EPA considered a range of alternative approaches for determining appropriate cellulosic 

RIN generation with different types of feedstocks. These approaches were discussed in the 

NPRM and also evaluated in public comments. This section discusses these alternative 

approaches and comments. 

a. Treatment of Cellulosic Feedstocks Currently Listed in Table 1 to 40 CFR 

80.1426

In the NPRM, EPA sought comment on multiple approaches for determining the volume 

of cellulosic RINs from currently approved cellulosic feedstocks listed in Table 1 to § 80.1426.

Many commenters preferred allowing feedstock sources listed in Table 1 to § 80.1426 to 

generate cellulosic RINs without applying a threshold, although some commenters asserted a 
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minimum content threshold could be used in conjunction with the proposed approach. As 

discussed above, EPA is finalizing the cellulosic content threshold approach that generally 

qualifies all fuel produced from predominantly cellulosic feedstocks pursuant to existing 

cellulosic biofuel pathways listed in Table 1 for cellulosic RINs. In addition, the approach will 

guide EPA evaluation of future feedstocks not currently included in Table 1 to §80.1426. 

Some commenters asserted EPA should adopt a plurality approach to determining 

whether cellulosic RINs could be generated when using particular feedstocks.

25

 Instead of 

requiring that the cellulosic content make up a predominant percentage of the organic material 

from which the fuel is derived, under this approach, feedstocks would be deemed cellulosic if a 

plurality of the contained material is cellulosic. EPA acknowledges that such an approach would 

likely lead to larger production volumes of cellulosic biofuels. However, as discussed above, the 

statutory definition of cellulosic biofuel provides that they are “derived from cellulose, 

hemicellulose, or lignin.” EPA believes that to effectuate Congressional intent in promoting 

fuels derived from these sources, it is appropriate to require that qualifying fuels be 

predominantly cellulosic in content. Therefore the 75% cellulosic content threshold approach 

adopted today is preferable in this regard to the commenter’s suggestion. 

Other commenters contended EPA should establish a minimum cellulosic content for 

individual feedstocks and assign RINs based only on this content, instead of allowing feedstocks 

currently listed in Table 1 to § 80.1426 to generate cellulosic RINs for their entire fuel volume.26 

 

25 Comments provided by Smithfield Foods (EPA-HQ-OAR-2012-0401-0103) and the National Association of 

Clean Water Agencies (EPA-HQ-OAR-2012-0401-0178). 

26 Comments provided by AFPM/API (EPA-HQ-OAR-2012-0401-0128) and Chevron (EPA-HQ-OAR-2012-0401-

0171).
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EPA believes this approach would create unnecessary administrative and regulatory burden. 

Instead of setting a minimum content for each individual feedstock, EPA is finalizing a single 

cellulosic content threshold. EPA has determined that most of the feedstocks listed in Table 1 to 

80.1426 for cellulosic biofuel pathways satisfy the 75% cellulosic content threshold adopted 

today. In addition, as described in section IV.A.4, EPA will assess the cellulosic content of 

future individual feedstocks as part of the lifecycle analysis process and determine whether the 

feedstock exceeds this threshold. Therefore, individual feedstocks will be analyzed to determine 

if they meet the minimum cellulosic content threshold, and different regulatory provisions apply

depending on the result. 

Several commenters stated that the emphasis should be placed on whether a feedstock 

meets the 60 percent reduction in greenhouse gas emissions relative to the baseline petroleum 

fuel they replace,27 particularly where a feedstock is predominantly cellulosic.28 One commenter 

also noted the agency should emphasize whether the feedstock has similar overall environmental 

qualities as a feedstock that is entirely cellulosic, such as the potential to avoid competition with 

food, the potential to require less fertilizer, pesticides, and irrigation, and the potential for a 

lower fossil fuel energy input requirement.29 In response, EPA notes that it is required to 

implement the statutory requirements, and that the CAA is clear that a cellulosic biofuel must be 

both derived from cellulosic materials and meet the 60 percent GHG emission reduction 

threshold. Therefore, EPA is not free to establish regulations focusing exclusively on attainment 

of the 60% GHG reduction threshold, while ignoring the cellulosic content of the feedstock used 

 

27 Comments provided by BP (EPA-HQ-OAR-2012-0401-0130), Iowa Corn Growers Association (EPA-HQ-OAR2012-0401-0131), and NRDC (EPA-HQ-OAR-2012-0401-0136).

28 Comments provided by BP (EPA-HQ-OAR-2012-0401-0130) and NRDC (EPA-HQ-OAR-2012-0401-0136).

29 Comment provided by NRDC (EPA-HQ-OAR-2012-0401-0136).
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to produce the fuel. In addition, EPA notes that in determining whether or not the fuel produced 

pursuant to a particular pathway satisfies the minimum 60 percent GHG reduction threshold for 

cellulosic biofuel, EPA does take into consideration a number of factors of concern to the 

commenter, including use of fertilizer and amount of fuels consumed in the production process. 

The Agency will continue to evaluate lifecycle emissions for feedstocks and require this 

reduction in greenhouse gas emissions for cellulosic pathways.

EPA also sought comment on a specified percentage approach, under which fuels 

produced from feedstocks listed in Table 1 to § 80.1426 would be eligible to generate cellulosic 

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

RINs. This percentage was based on data that suggested that the average adjusted cellulosic 

content of the predominantly cellulosic feedstocks currently listed in Table 1 for cellulosic 

biofuel pathways was approximately 85%. Commenters generally opposed the specified 

percentage approach, asserting that it would create administrative burden to track two classes of 

RINs, that a partial loss of cellulosic RINs could hurt the financial viability of producers, and 

that there is the possibility of RIN generation errors.

30

EPA has concluded that this approach would significantly increase the complexity of the 

program without providing additional environmental benefits. EPA believes the additional 

precision the method would provide is not justified in light of the administrative and regulatory

 

30 Comments provided by National Sorghum Producers (EPA-HQ-OAR-2012-0401-0065), the Renewable Fuels 

Association (EPA-HQ-OAR-2012-0401-0123), Weyerhaeuser (EPA-HQ-OAR-2012-0401-0140), NexSteppe (EPAHQ-OAR-2012-0401-0153), the Independent Fuel Terminal Operators Association (EPA-HQ-OAR-2012-0401-

0165) and Global Renewable Strategies and Consulting, LLC (EPA-HQ-OAR-2012-0401-0184). Some commenters 

expressed support for the specified percentage approach. See comments provided by the AFPM/API (EPA-HQOAR-2012-0401-0128), Phillips 66 (EPA-HQ-OAR-2012-0401-0102), Chevron (EPA-HQ-OAR-2012-0401-0171), 

and Camco (EPA-HQ-OAR-2012-0401-0183)
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burden associated with it, and that overall the cellulosic content threshold approach we are 

adopting today provides an appropriate balance of the competing considerations of precision and 

adopting a workable approach. Therefore, for the reasons described above, EPA is finalizing the 

content threshold approach. 

b. Feedstocks with Lower Average Cellulosic Content than Feedstocks Currently

Listed in Table 1 to § 80.1426 

In the proposal, EPA also invited comment on how to treat feedstocks that had lower 

average cellulosic content than the feedstocks currently listed in Table I to § 80.1426. Some 

commenters suggested using an approach with multiple thresholds, where fuel made from 

feedstocks that meet the highest cellulosic content threshold would receive 100% cellulosic 

RINs, and fuel made from feedstocks meeting lower thresholds would receive a fixed percentage 

of cellulosic RINs, with the remaining fuel receiving advanced RINs. Other commenters stated 

that the existing regulations in § 80.1426(f)(3) were sufficient to handle the allocation of RINs 

for the cellulosic and non-cellulosic portions of the finished fuel.31 They noted that these 

regulations already provide a way to assign RINs for a mixture of fuel types with different Dcodes. After evaluating these comments, EPA has concluded that the approach provided by the 

existing regulations in § 80.1426(f)(3) to allocating cellulosic and non-cellulosic RINs is 

preferable. This system is already established, and is designed to accurately apportion the 

finished fuel to account for cellulosic biofuel conversion, potentially allowing for a greater 

 

31 Comments provided by the National Corn Growers Association (EPA-HQ-OAR-2012-0401-0071), Novozymes 

North America, Inc. (EPA-HQ-OAR-2012-0401-0088), and the Renewable Fuels Association (EPA-HQ-OAR2012-0401-0123), the Iowa Corn Growers Association (EPA-HQ-OAR-2012-0401-0131), and Edeniq (EPA-HQOAR-2012-0401-0159).
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proportion of cellulosic RIN generation than would be allowed in establishing a series of 

thresholds with fixed percentages of cellulosic RIN generation. 

B. Lifecycle Greenhouse Gas Emissions Analysis and Cellulosic Determinations for 

Pathways Using Biogas as a Feedstock

In the March 2010 RFS final rule, EPA established biogas as an advanced fuel type (D 

code of 5) when derived from landfills, sewage waste treatment plants, and manure digesters. 

Based on questions from companies, EPA proposed to: 1) modify the existing biogas pathway to 

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

from landfills, waste treatment plants, and waste digesters is the feedstock; 2) allow fuels derived 

from landfill biogas to qualify for cellulosic RINs rather than just advanced RINs; 3) add a 

landfill biogas to renewable electricity pathway; and 4) add a Fischer-Tropsch landfill biogas 

pathway. 

Based on comments and new data received, in this rule we are: 1) finalizing the proposed 

change to make CNG and LNG the fuel and biogas from specified sources the feedstock; 2) 

expanding the cellulosic pathways to include biogas from landfills, municipal wastewater 

treatment facility digesters, agricultural digesters, and separated MSW digesters; 3) finalizing the 

proposed change to add an advanced pathway for fuels from waste digester biogas; and 4) 

expanding the renewable electricity pathway to include biogas from landfills, wastewater 

treatment plants, agricultural digesters, MSW digesters, and waste digesters. Due to time 
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constraints, we are not finalizing a Fischer-Tropsch landfill biogas pathway at this time. 

However, we expect to address this pathway in a future action. 

Our determinations regarding biogas derived renewable CNG, LNG and electricity are 

discussed more fully in the following sections. This section discusses:

 Changes Applicable to the Revised CNG/LNG pathway from Biogas

 Determination of the Cellulosic Composition of Biogenic Waste Derived Biogas

o Landfill gas and MSW waste digester biogas as cellulosic

o Municipal wastewater treatment facility digester biogas as cellulosic

o Agricultural digester biogas as cellulosic

o Biogas from Waste Digesters 

 Consideration of Lifecycle GHG Emissions Associated with Biogas Pathways

o Upstream GHG Analysis of Biogas as a Renewable Fuel Feedstock

o Flaring Baseline Justification

o Lifecycle GHG Analysis for Electricity from Biogas

 Alternative Biogas Options and Comments

The following section, “Regulatory Amendments Related to Biogas” will discuss 

additional clarifications and changes to the regulations associated with the biogas pathways. 

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

Prior to this rulemaking, an approved fuel pathway in Table 1 to § 80.1426(f)(1) allowed

biogas from landfills, manure digesters or sewage treatment plants to qualify as an advanced
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biofuel. We received many requests about what fuel qualifies under this pathway, including what

renewable fuel types qualify under the term “biogas,” and what are the eligible sources of biogas. 

In response, EPA proposed to make several changes to the regulations related to biogas. 

EPA is now characterizing biogas as a transportation fuel feedstock and is amending the 

existing biogas pathway in Table 1 to § 80.1426 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).” EPA is also changing the feedstock type of “landfills, 

manure digesters or sewage waste treatment plants” to “biogas from landfills, municipal 

wastewater treatment facility digesters, agricultural digesters, and separated MSW digesters” for 

a pathway producing cellulosic biofuels. Finally, EPA is adding a new advanced biofuel 

pathway for fuels produced using “biogas from waste digesters” as the feedstock type. 

In this final rule, we are changing the term “sewage waste treatment plants” to 

“municipal wastewater treatment facility digesters” since “sewage waste treatment plants” is not 

a commonly used term and to clarify that the digester is the source of the biogas. We are also 

defining an “agricultural digester” as an anaerobic digester that processes predominantly

cellulosic materials including animal manure, crop residues, and/or separated yard waste. 

The existing biogas pathway in Table 1 to § 80.1426 refers to “biogas” as the renewable 

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

Several companies raised questions about whether the term “biogas” in this pathway could refer 

to the unprocessed or raw gas from the landfills, manure digesters or sewage treatment plants, or 
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processed “biogas” that has been upgraded and could be used directly for transportation fuel. 

Companies also asked about use of biogas as an ingredient in the production of transportation 

fuel, as an energy source used in the production of transportation fuel, and 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, dimethyl ether or naphtha). These

companies further inquired whether the various forms of biogas discussed above could qualify

under this pathway and therefore be eligible for RIN generation under the RFS program. 

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 § 80.1426(f)(10) and (11), only biogas that is used for transportation fuel can 

qualify as renewable fuel for RIN generation under the RFS program, and thus we believe it is

appropriate to view raw biogas as a feedstock rather than a transportation fuel itself. EPA 

recognizes that raw biogas cannot be used directly in the transportation sector and must be 

physically or chemically treated to generate a finished transportation fuel eligible for RIN 

generation. Raw biogas can be put through a physical process in which it is compressed or 

liquefied to produce CNG or LNG. Because these fuels can be used directly for transportation 

purposes, it seems appropriate to identify these products as “fuels” that are produced using 

biogas from sources. 

We are finalizing revisions to the definition of biogas and new definitions for renewable 

CNG, renewable LNG, and agricultural digester to § 80.1401 to read as follows:
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Biogas: a mixture of hydrocarbons that is a gas at 60 degrees Fahrenheit and 1 

atmosphere of pressure that is produced through the anaerobic digestion of organic 

matter. 

Renewable compressed natural gas (“renewable CNG”) means biogas or biogas-derived 

pipeline quality gas that is compressed for use as transportation fuel. 

Renewable liquefied natural gas (“renewable LNG”) means biogas or biogas-derived 

pipeline quality gas that goes through the process of liquefaction in which it is cooled 

below its boiling point. 

Agricultural digester means an anaerobic digester that processes predominantly cellulosic 

materials, including animal manure, crop residues, and/or separated yard waste. 

These finalized definitions reflect comments we received that supported our changes to 

the “biogas” pathway as discussed above, namely changing fuel to CNG/LNG and adding a

description of the applicable biogas feedstocks. The finalized definitions for CNG/LNG also 

reflect comments we received suggesting that we clarify whether biogas used on-site and not sent 

through a pipeline would fall within the pathway. In order to clarify that biogas used on-site and 

not sent through a pipeline would also qualify, the proposed definitions of renewable CNG and 

LNG were modified to indicate that either biogas or pipeline-quality gas can be compressed to 

make renewable CNG and LNG. 
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2. Determination of the Cellulosic Composition of Biogenic Waste-Derived Biogas

In order for fuels produced from biogas as a feedstock to qualify for cellulosic RINs (D 

code of 3 or D code of 7), the renewable fuel must be derived predominantly from cellulosic 

materials and must meet a 60% GHG emissions reduction threshold, as described in the 

following sections. 

EPA proposed to allow renewable fuel derived from landfill biogas to qualify as 

cellulosic biofuel and solicited comment on whether biogas from other sources should also be 

qualified as cellulosic biofuel. Based on new data and comments received during our public 

review process, EPA has determined that biogas generated by landfills, municipal wastewater 

treatment facility digesters, agricultural digesters, and separated MSW digesters are

predominantly cellulosic in origin, and that biogas derived from waste digesters processing noncellulosic renewable biomass therefore qualifies as an advanced biofuel feedstock. Data 

supporting these determinations are discussed in more detail in an associated memo to the 

docket32, and the main findings are provided forthwith. 

a. Landfill Biogas and MSW Digester Biogas as Cellulosic in Origin

In the June 2013 NPRM, EPA proposed to classify renewable fuels produced from 

landfill biogas as derived from cellulose, hemicellulose or lignin, and therefore eligible to 

generate cellulosic RINs (D code of 3 and D code of 7). EPA cited a 1989 study that concluded 

 

32 “Support for Cellulosic Determination for Waste Derived Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels Produced from Waste Derived Biogas,” which has been placed in docket 

EPA-HQ-2014-####.
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that not only was the average cellulosic content of the organic fraction of municipal solid waste 

(OFMSW)33 approximately 90%, but that roughly 90% of the methane generated in landfills was 

derived from the cellulose and hemicellulose34 portions of the OFMSW as the basis for this 

proposal. 

Some commenters argued that MSW landfill gas was not cellulosic because a large 

portion of the waste disposed is food waste which contains some non-cellulosic components. 

We do not believe this affects our determination for several reasons. Our cellulosic content 

determination is based on an average mixture of MSW components that includes food waste. 

Since the average cellulosic content of the organic fraction of MSW is approximately 90%, EPA 

believes that organic matter in MSW landfills is predominantly cellulosic in origin. 

Furthermore, many of the non-cellulosic components of food waste are oxidized in the early

stages of waste decomposition during the collection, handling and transportation and released as 

CO2 instead of CH4. Therefore, a greater proportion of the biogas produced from anaerobic 

digestion (and subsequently used as a transportation fuel) comes from the remaining cellulosic 

components.

Some commenters stated that only about 27% of MSW landfill gas can be considered to 

be derived from renewable biomass, and thus, the gas cannot even be considered to be eligible 

for RIN generation. However, EPA determined in the March 2010 RFS rule that biogas from 

MSW landfills is derived from renewable biomass, namely separated yard and food wastes, and 

 

33 The study specifies the “volatile solids” of the MSW to be 90% cellulosic. Volatile solids refer to organic 

compounds of plant or animal origin that have caloric value and are susceptible to bioconversion during anaerobic 

digestion.

34 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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EPA did not propose to change that finding. Thus, this comment is not relevant to the current 

rulemaking. 

EPA invited comment and data on the proposed approach to treat landfill biogas as being 

derived from cellulose, hemicellulose and lignin. Some commenters argued that landfill biogas 

should not be considered as cellulosic,35 others supported considering landfill biogas as 

cellulosic,36 and still others requested that EPA expand the proposed determination to include

biogas derived from additional sources processing biogenic wastes as cellulosic.

37

 Commenters 

that opposed considering landfill gas as cellulosic pointed to the EPA proposal that relied on a 

single study to justify this approach. This was not, in fact, the case, and EPA had reviewed, 

discussed and cited numerous studies to support this determination.38 Moreover, subsequent to 

the June 2013 proposal, EPA updated its literature review and found additional peer reviewed 

studies that support our proposed assessment that biogas from landfills is predominantly derived 

from cellulosic components. The studies considered a broad spectrum of landfills, including 

studies comparing differences among landfill design, operating practices, regional influence, and 

typical waste loadings throughout the United States over more than two decades. Therefore, our 

 

35 See “Comment submitted by Friends of the Earth, Sierra Club, Center for a Competitive Waste Industry”, docket 

number EPA-HQ-OAR-2012-0401-0164.

36 See for example, “Comment submitted by Kerry Kelly, Director, Federal Public & Regulatory Affairs, Waste 

Management (WM)”, docket number EPA-HQ-OAR-2012-0401-0112 and “Comment submitted by Stewart T. 

Leeth, Assistant Vice President, Environmental and Corporate Affairs and Senior Counsel, Smithfield Foods, Inc.”

docket number EPA-HQ-OAR-2012-0401-0103.

37 See “Comment submitted by Stewart T. Leeth, Assistant Vice President, Environmental and Corporate Affairs 

and Senior Counsel, and Dennis Treacy, Executive Vice President and Chief Sustainability Officer, Smithfield 

Foods, Inc.”, docket number EPA-HQ-OAR-2012-0401-0111, and “Comment submitted by Cynthia A. Finley, 

Director, Regulatory Affairs, National Association of Clean Water Agencies (NACWA)”, docket number EPA-HQOAR-2012-0401-0178. 

38 “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-OAR-2012-

0401.
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determination that the biogas generated in landfills is predominantly derived from cellulose and 

hemicellulose is well supported.

39

 

Since separated MSW digesters would use the same biogenic materials that are present in 

landfills, and generate biogas by the same anaerobic processes, a logical extension of the 

reasoning and data described above justifies treating the biogas generated by MSW digesters

processing separated MSW or the organic fraction of MSW kept from landfills as part of organic 

diversion programs as cellulosic as well. Therefore, we have included biogas from separated

MSW digesters as a feedstock in cellulosic biofuel pathway Q in Table 1 to § 80.1426. 

b. Municipal Wastewater Treatment Facility Digester Biogas as Cellulosic

For purposes of this rule, the term “municipal wastewater treatment facility digester” 

means an anaerobic digester that processes the sludge, undissolved solids, and biosolids derived 

from municipal wastewater whether or not the facility is owned by a municipality. While there 

are substantial data characterizing the solids composition of municipal wastewater, there are

somewhat less data on the composition of materials entering the digesters specifically. The 

average cellulosic content of the unprocessed wastewater that enters a municipal wastewater 

treatment facility is approximately 50-60% cellulosic, once it has been dewatered (not adjusted 

 

39 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.

Mehta, R., Barlaz, M.A., Yazdani, R., Augenstein, D. Bryars, M. and Sinderson, L. 2002, “Refuse Decomposition in 

the Presence and Absence of Leachate Recirculation,” J. Environ. Eng., 128, 3, 228-236

Staley, B. F. and M. A. Barlaz, 2009, Composition of Municipal Solid Waste in the U.S. and Implications for 

Carbon Sequestration and Methane Yield,” J. Environ. Eng. 135, 10, 901-909

Additional citations were offered in comments from Waste Management
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for the volatile fraction).40 However, the data characterizing the unprocessed wastewater does 

not adequately represent the material entering the digester for several reasons. 

The undissolved solids that are skimmed from the primary clarification tank and sent to 

the digester are more likely to be cellulosic, since cellulosic materials are not very soluble. What 

is left behind are the more soluble materials (e.g., sugars), which are then oxidized aerobically. 

After the aerated oxidation step, solids are allowed to settle out and that material is also sent to 

the digester. Again, this pre-treated biosolid is more likely to consist of cellulosic components 

since they are less likely to oxidize. Therefore, the material that actually enters the digesters at 

wastewater treatment facilities is more likely to consist of cellulose, hemicellulose and lignin 

than untreated wastewater. For these reasons, we have used the subset of peer-reviewed data that 

analyzes the pre-treated biosolids for the purposes of calculating the average adjusted cellulosic 

content of materials entering the wastewater treatment facility digesters. Based on this data, this 

material is on average composed of 25% cellulose, 18% hemicellulose, and 20% lignin.41 When 

divided by the organic fraction (minus the percent organic nitrogen, which does not convert to 

methane), we estimate that the material used to generate the biogas through anaerobic digestion 

from wastewater treatment facilities is, on average, greater than 75% cellulosic. These data and 

analyses are described in more detail in a memo to the docket.

42

 

40 Wang, Xue. 2008. Feasibility of Glucose Recovery from Municipal Sewage Sludges as Feedstocks Using Acid 

Hydrolysis. Masters Thesis Queen's University, Ontario, Canada. Champagne, P. & Li, C. 2009 "Enzymatic 

hydrolysis of cellulosic municipal wastewater treatment process residuals as feedstocks for the recovery of simple 

sugars. Bioresource Technology. Vol 100 pp 5700 – 5706. See memo to the docket: “Support for Classification of 

Biofuel Produced from Waste Derived Biogas as Cellulosic Biofuel and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels Produced from Waste Derived Biogas.”

41Wang, Xue. 2008. Feasibility of Glucose Recovery from Municipal Sewage Sludges as Feedstocks Using Acid 

Hydrolysis. Masters Thesis Queen's University, Ontario, Canada. Sun & Cheng. 2002. "Hydrolysis of 

lignocellulosic materials for ethanol production: a review. Bioresource Technology. Vol 83 pp 1-11.

42 Data available for pre-digested biosolids and methods for estimating the aggregate adjusted cellulosic content is 

presented in the memo to the docket: “Support for Classification of Biofuel Produced from Waste Derived Biogas as 
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c. Agricultural Digester Gas as Cellulosic

In this rule we are defining “agricultural digesters” to be “anaerobic digesters that process

predominantly cellulosic materials, including animal manure, crop residues, and/or separated 

yard waste,” and have identified biogas from such digesters as a feedstock for the production of 

cellulosic biofuel. Based on EPA’s AgSTAR data, we have estimated that animal manure, crop 

residues and yard wastes represent over 90% of the materials being processed in agricultural 

digesters. As discussed in section IV.A, EPA has determined that crop residues and yard wastes 

are predominantly cellulosic. As to animal manure, we received in response to our proposal data 

indicating that animal manure is predominantly cellulosic.43 Based on this data, this material is 

on average composed of 25% cellulose, 21% hemicellulose, and 17% lignin. When divided by

the organic fraction (minus the percent organic nitrogen, which does not convert to methane), we 

estimate that the material used to generate the biogas through anaerobic digestion from 

agricultural digesters is, on average, greater than 75% cellulosic.44 Therefore, in this rule we are 

including biogas from agricultural digesters in the cellulosic biofuel pathway in row Q of Table 1 

to § 80.1426. Note that digesters that primarily process food wastes that cannot be demonstrated 

to be cellulosic in origin would fall in the general waste digester category discussed in the 

following section.

d. Biogas from Waste Digesters

 

Cellulosic Biofuel and Summary of Lifecycle Analysis Assumptions and Calculations for Biofuels Produced from 

Waste Derived Biogas”

43 Chen, S., et. al., 2003, Value Added Chemicals from Animal Manure. Pacific Northwest Laboratory, PNNL –

14495. December 2003

44 See memo to the docket. 
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The current regulations identify biogas from manure digesters as an advanced biofuel. 

As described above, we have determined that animal manure is predominantly cellulosic, and 

therefore have determined that fuel made from biogas derived from agricultural digesters 

processing predominantly cellulosic feedstocks (such as animal manure, crop residues, and yard 

wastes) qualifies for cellulosic biofuel RINs. However, additional types of renewable biomass 

may be processed in anaerobic waste digesters. For example, non-manure animal wastes and 

separated food wastes containing predominantly starches and sugars may be processed in waste 

digesters that produce biogas. Based on our analyses of biogas from other sources of anaerobic 

decomposition, described in Section 3, below, we are confident that fuel made from biogas from 

waste digesters will satisfy the 50% greenhouse gas reduction threshold for advanced biofuels. 

Therefore, we are including in Row T of Table 1 to § 80.1426, an advanced biofuel pathway for 

fuel made from biogas derived from waste digesters. 

3. Consideration of Lifecycle GHG Emissions Associated with Biogas Pathways

Biogas, consisting primarily of methane and carbon dioxide (with trace amounts of other 

gases), is produced during the microbial mediated decomposition of organic wastes. In 

anaerobic environments with available organic material such as landfills, organic conversion to 

biogas proceeds slowly over decades producing large amounts of methane. While methane is a 

potent greenhouse gas, it is also a combustible gas and valuable feedstock for the production of 

other fuels. Biogas collection systems are currently used at landfills to recover and destroy

methane by flaring or to recover methane for energy generation or fuel production. Further, the 

natural anaerobic decomposition of organic wastes occurring in landfills can be exploited and 
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optimized in controlled systems (such as waste digesters) to convert organic wastes to biogas for 

energy generation or fuel production. In this section we will discuss our GHG analysis of fuels 

made from waste derived biogas. 

a. Upstream GHG Analysis of Biogas as a Renewable Fuel or Fuel Feedstock

The March 2010 RFS final rule concluded that municipal solid waste has no agricultural 

or land use change GHG emissions associated with its production. In the NPRM, we proposed to 

add a new pathway to Table 1 to § 80.1426 that used biogas from landfills to produce renewable

electricity, CNG or LNG as transportation fuels. In the NPRM, we proposed that no new 

renewable feedstock production modeling was required, and that no GHG emissions would be 

attributed to feedstock production, which was consistent with the analysis we had done for the 

landfill biogas pathway included in the March 2010 RFS final rule. In addition, as described in 

more detail below, EPA believes that the GHG emissions assumptions for biogas generated at 

MSW landfills applies to biogas from municipal wastewater treatment facility digesters

agricultural digesters, separated MSW digesters, and waste digesters. 

We received several comments supporting this approach for landfills, including one that 

cited consistency with other Agency analysis conducted for the annual Inventory of US GHG 

Emissions and Sinks, which assumes that MSW poses no land use or carbon stock changes.

45

 

However, we also received comment opposing this approach on the grounds that it would 

incentivize landfilling over other more GHG-beneficial waste disposal methods. 

 

45 Cite commenter “A Life-Cycle Assessment of Emissions and Sinks.” 
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Commenters did not provide new data or analysis that supported the assertion that 

allowing biogas-derived fuels from landfills to generate cellulosic rather than advanced RINs or 

adding new biogas-to-biofuel pathways would significantly reduce recycling and reuse rates. If 

waste management methods were impacted by use of biogas for transportation fuel, there could 

be indirect GHG emissions impacts. However, waste management policies are typically 

controlled by state and local governments, and there are many unique factors that influence these 

decisions. We have not seen any evidence or data to suggest that the RFS in general has had or 

will have a substantial impact on existing waste disposal practices across the U.S., and therefore 

we believe that there will not be significant GHG impacts associated with the biogas-based 

pathways adopted in this rule. In fact, MSW landfilling rates over the past 50 years have 

continuously decreased even as both recycling rates and biogas collection have increased 

significantly. Over the past 10 years as both the per capita and overall MSW generation rates 

have decreased slightly, the percentage of total trash diverted for recycling has increased.46

Moreover, energy from waste technologies, such as fuels derived from landfill biogas, can be 

viewed as a form of waste reuse itself. Incentivizing the use of biogas for fuel production 

establishes biogas recovery as an operating parameter to be actively optimized – promoting 

technology that reduces fugitive emissions from landfills. 

Other commenters argued that we should begin our lifecycle GHG analysis at the point of 

waste generation, in which case our comparison would be to an alternative disposal method like 

recycling of waste paper, composting, or anaerobic digestion. This approach is not being 

employed because, as mentioned previously, we do not believe that the biogas pathways adopted 

 

46 INSERT CITE to EPA’s Annual Waste Trends Report.
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today will have a substantial impact on existing waste disposal methods, and therefore no 

significant GHG impacts from waste disposal changes are anticipated as a result of this rule. 

EPA does not believe that allowing landfill biogas to generate cellulosic rather than 

advanced RINs will incentivize landfilling, and we are therefore not changing our assumptions 

regarding the upstream analysis of feedstocks as part of this final rule. However, we will 

reevaluate our lifecycle GHG baseline assumptions in subsequent rule makings if new evidence 

and supporting data suggest that changes in the waste management system are occurring as a 

result of these policies. 

b. Flaring Baseline Justification 

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

(MSW) landfills are required by EPA regulations to capture and control their biogas if they are 

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.

47

 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 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 for other purposes, including to generate electricity, in which 

case the electricity produced may displace electricity from other, higher GHG-emitting sources 

 

47 Standards of Performance for New Stationary Sources and Guidelines for Control of Existing Sources: Municipal 

Solid Waste Landfills, 61 FR 9905, Federal Register Volume 61, Issue 49 (March 12, 1996). 
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(such as gas-fired power plants) once it enters the grid.

48

 Many smaller, unregulated landfills do 

not collect their biogas, and this methane is “vented” to the atmosphere. Larger regulated 

landfills do collect the biogas and are assumed to have an average biogas collection efficiency of 

75%.

49 In 2012, 14,089 Gg of methane was generated at all landfills (regulated and unregulated), 

of which 4,608 Gg (33%) was collected and combusted in gas-to-energy projects, 4,040 Gg 

(29%) was collected and flared, and the rest was either uncollected or collected and vented.

50

For the landfill gas-to-electricity pathway, we proposed to use landfills that flare their 

biogas as providing the baseline GHG emissions for use in comparison to scenarios involving 

production of electricity from the landfill biogas. We chose this baseline because these landfills 

are the ones most likely to convert to gas-to-energy projects, since they already have gas 

collection systems in place and are relatively larger landfills producing higher quantities of 

biogas. Small unregulated landfills might be unable to generate enough biogas to justify the 

expense of collecting it for conversion to renewable fuels. However, if such small landfills were 

to capture and use their biogas in transportation fuels, there would be a significantly greater 

reduction in GHG emissions than would be occasioned by the shift from a flaring landfill to a 

gas-to-energy project, since a flaring system represents a significant improvement in GHG 

emissions over a landfill that simply vents its methane. Therefore, if the shift from a flaring 

 

48 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.

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

Annex 3: Methodological Descriptions for Additional Source or Sink Categories. 

http://epa.gov/climatechange/emissions/usinventoryreport.html. As of December 2012, landfills produced 1913 

MW of electricity based on figures from LMOP. This electricity would be almost entirely sold for use on the grid. 

From http://www.epa.gov/lmop/projects-candidates/index.html. 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.

50 National Greenhouse Gas Emissions Data. 2011. Chapter 8: Waste. 

http://epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-Chapter-8-Waste.pdf
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landfill to a gas-to-energy project results in a 50% reduction in GHG emissions, the shift of a 

venting landfill to a gas-to-energy project also would. Since landfills that currently have gas-toenergy 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 

proposed 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.51 We received comments in support of our flaring baseline 

approach. We did not receive any comments that justified revising this baseline for the pathway

in Table 1, therefore EPA is finalizing flaring as our baseline as proposed. We received 

comment on the use of alternative baselines for specific projects that we discuss below. 

Other commenters addressed the case of a landfill that is already generating renewable 

electricity from landfill gas. The commenters stated that with the increasing availability of plugin hybrid electric vehicles (PHEVs) and electric vehicles (EVs), it is likely that at least some of 

the electricity that is currently being generated by these landfills is going to charge these 

vehicles. The commenter argued that if the landfill now signs contracts with these users, there 

will be no change in GHG emissions, and fuel from this landfill biogas will not achieve a 60% 

GHG reduction as required for cellulosic biofuels. Although EPA considered the possibility of 

differentiating between existing and new biogas projects,

52 we believe that such an approach 

would inappropriately punish “early actors” that have previously made the decision to install 

gas-to-energy equipment, either to replace flaring or as an alternative to installing flares. That 

 

51 “Support for Cellulosic Determination for Waste Derived Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels Produced from Waste Derived Biogas,” which has been placed in docket 

EPA-HQ-2014-####.

52 See memo to the docket, entitled XXX
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these facilities made the upgrade to gas-to-energy production prior to the availability of an RFS 

incentive to do so should not disqualify them. These facilities are already leading performers, 

and their fuel should be credited with the GHG reductions occasioned by the move away from 

the flaring alternative even if that move happened in the past. This approach is consistent with 

how we have treated the early implementation of advanced technologies for all biofuels 

producers in the past. 

We also believe that it is appropriate to use a flaring baseline when considering emissions 

related to biogas production from municipal wastewater treatment facility digesters, agricultural 

digesters, separated MSW digesters, and waste digesters. Similar to landfills, biogas from these 

sources could be vented, flared or used for beneficial purposes. According to the American 

Biogas Council website, of the 1,500 municipal wastewater treatment facility digesters that 

produce biogas, about 250 use the biogas; for the other 1,250, the biogas is flared. For 

agricultural digesters the alternative to beneficial use of the biogas is typically that the methane 

would have been emitted. Separated MSW digesters are similar to landfills and would therefore 

have a similar baseline. For waste digesters, one alternative is that the waste would have gone to 

a landfill and resulted in a similar baseline. Furthermore, these waste digesters are often similar 

to wastewater treatment facility digesters in that they are processing wastewater containing 

organic materials and would likely have a similar flaring baseline for the biogas produced. 

Assuming that the biogas is flared generally provides a worst case baseline. If sources that are 

using flaring will achieve a 60% GHG reduction when converting to electricity production, 

sources that are venting their methane will certainly do so as well. 
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c. Lifecycle GHG Analysis for Electricity from Biogas

The previous section discussed the baseline EPA has selected for use in comparison to 

the biogas pathways under consideration. This section discusses the lifecycle GHG emissions 

analyses of the pathways adopted today, which are then compared to the baseline to determine if 

the requisite GHG reductions are achieved. 

As part of the proposed rule, EPA prepared a proposed assessment of the lifecycle GHG 

emissions of renewable electricity produced from landfill biogas. In doing so, we examined two 

main factors. The first involved determining by how much emissions at a landfill employing 

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

emission factors from the GREET model.53 The second involved calculation of the decrease in 

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

electricity produced on-site rather than grid electricity upon installation of a gas-to-energy

project at the landfill. This calculation used data from the EPA Landfill Methane Outreach 

Project (LMOP).54 For this analysis, we calculated how much electricity could be generated and 

how much could be delivered off-site to the consumer including consideration of on-site parasitic 

losses and on-site use. We used values from LMOP to provide 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 

 

53 Argonne National Laboratory (2011) Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation 

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

54 EPA LMOP Data.
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Agency to estimate distribution losses. Values used are discussed in more detail in a memo to 

the docket.

55

We calculated GHG emissions in two ways, per mmBtu electricity and per mmBtu fuel 

equivalent which accounted for the drivetrain efficiency of electric vehicles. In both cases we 

found that renewable electricity produced from landfill gas meets the 60% GHG emission

reduction threshold required by the CAA, and thus qualifies as a cellulosic biofuel. Compared 

with the gasoline that it would replace, 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%. 

We did not receive any comment on our lifecycle calculations and are therefore finalizing 

our determination that renewable electricity produced onsite from landfill gas meets the 60% 

reduction in GHG emissions required by the CAA. This determination also applies to a pathway

where the electricity is generated off-site. The main differences are removal of the credit 

associated with using biogas electricity in on-site blowers, and adding emissions associated with 

scrubbing the gas to pipeline quality, shipping it via pipeline, and removing it from the pipeline 

to make electricity. Removing the credit associated with use of biogas-derived electricity for 

onsite blowers still results in a 75% reduction in GHG emissions when normalized per mmBtu 

electricity, and the emissions associated with other aspects of a pathway involving off-site 

electricity generation (e.g., scrubbing the gas to pipeline quality, shipping it via pipeline, 

removing it to make electricity) are not expected to change the result significantly. 

 

55 “Support for Cellulosic Determination for Waste Derived Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels Produced from Waste Derived Biogas,” which has been placed in docket 

EPA-HQ-2014-####.
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We believe that GHG emissions related to electricity produced with biogas from 

municipal wastewater treatment facility digesters, agricultural digesters, separated MSW 

digesters, and waste digesters would be similar to those for landfill biogas production. The 

analysis for landfill biogas to electricity considered two main components: an increase in 

emissions due to converting from flaring to electricity generation and a credit associated with 

reduced grid electricity purchased to run blowers. The change in emissions due to converting 

from flaring to electricity generation that we assumed for landfill biogas can be considered the 

same for other sources of biogas. In all cases the emissions are based on the properties of the 

biogas itself, and its combustion products, which are independent of the biogas source. For other 

biogas sources there may be less need for purchased grid electricity to run blowers since other 

biogas sources are generally less distributed than gas collection at landfills. However, even if the 

credit associated with the reduction in purchased grid electricity for blowers is not considered for 

municipal wastewater treatment facility digesters, agricultural digesters, separated MSW 

digesters and waste digesters, compared with the gasoline baseline GHG emissions of 98 kg 

CO2-eq/mmBtu, these projects would still be accompanied by a 75% reduction in GHG 

emissions when normalized per mmBtu electricity. The calculated reduction would be even 

greater if we accounted for the improved efficiency of EV drivetrains. Therefore, we have 

determined that pathways involving electricity production from biogas derived from these other 

sources also meet the 60% lifecycle GHG reduction threshold and can be qualified as cellulosic 

biofuel (assuming all other definitional and regulatory requirements are satisfied). It is important 

to note that RINs may only be generated for electricity from biogas that can be tracked to use in 

the transportation sector, such as by an electric vehicle.
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4. Alternative Biogas Options and Comments

a. Alternative Baseline Approaches

We received comments in support of our flaring baseline approach. However, we also 

received several comments arguing for alternative approaches. Several commenters wanted EPA 

to allow parties to use a non-flaring baseline where it can be shown that the landfill providing 

biogas is not required to have a flare or other methane controls. For the basis of our electricity 

pathway in Table 1, EPA is not changing the baseline comparison of flaring for the reasons 

stated above, that on average it is the baseline landfill condition that would be replaced. In 

addition, EPA had determined that the biogas to energy pathways evaluated are all calculated to 

achieve at least a 60% reduction in GHG emissions required by the CAA when a change from 

landfill flaring is assumed. Assuming venting instead of flaring as a baseline landfill condition 

would improve the calculated benefits of the projects, but would not change the applicable RFS 

GHG threshold determination. Accordingly, there is no purpose served by these comments for 

purposes of today’s rule. 

b. Additional Comments on Lifecycle Analysis for Renewable Electricity

In addition to the comments discussed above, we also received comment suggesting that 

we include electricity from biomass sources such as woody biomass as a pathway in Table 1 to § 

80.1426. However, evaluation of the lifecycle GHG emissions associated with generating 

electricity from woody biomass or other biomass sources would involve substantially different 

considerations from our analysis of electricity production from biogas sources, and is beyond the 
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scope of this rule. Therefore EPA is not finalizing an electricity pathway from other types of 

biomass at this time. We also received comments on adding pathways for biogas to 

transportation fuels other than CNG/LNG and electricity. These other fuel types included 

dimethyl ether (DME) and hydrogen (H). However, assessing emissions associated with these 

production processes is also beyond the scope of this rule.

We received comment seeking clarification of whether electricity from landfill biogas or 

other approved biogas sources that was used in trains would qualify for RIN generation. EPA 

has determined that electricity used in trains is not a “transportation fuel” as defined in the Clean 

Air Act. Electricity from RFS-approved biogas sources that is used in trains does not “replace or 

reduce the use of fossil fuel present in transportation fuel”, and therefore does not meet the 

statutory definition of a “renewable fuel” eligible for RIN generation in the RFS program. 

Commenters also asked whether electricity from landfill biogas or other approved biogas 

sources that was used to compress natural gas would be eligible for RIN generation, if the natural 

gas was used for transportation purposes. EPA has determined that electricity used to compress 

natural gas does not qualify for RIN generation, since the electricity will not reduce the amount 

of fossil fuel present in the natural gas, which is the transportation fuel in this situation. 

C. Regulatory Amendments Related to Biogas

Prior to this rule making, an approved fuel pathway in Table 1 to § 80.1426 allowed

biogas from landfills, manure digesters or sewage waste treatment plants to qualify as an 
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advanced biofuel. We have received questions related to some of the details of this pathway that 

are also relevant to the biogas-related pathways approved today. The questions include the

following: 1) what company along the production chain of biogas from generation to end user is 

considered the producer that qualifies to register under this pathway and generate RINs, and 2) 

what are the contract requirements to track the biogas from generation to end use. 

We proposed revising and adding new contracting, registration, reporting and 

recordkeeping requirements at locations along the production chain from biogas generation to 

finished transportation fuel use. We also proposed to specify which company along the 

production chain is considered the “producer” and eligible to generate RINs under the RFS 

program. In the following sections, we will detail the changes being finalized. 

1. Changes Applicable to Renewable Electricity from Biogas Sources

In the NPRM, EPA requested comment on a number of potential changes intended to 

clarify the process for generating RINs for renewable electricity. We received a number of 

comments on these proposed changes, but have decided that in general the existing regulations 

are sufficient for present purposes and only minor clarifications are warranted at this time. To 

the extent that these modifications do not resolve all questions, EPA’s intent is to address them 

through a combination of guidance documents and future rulemaking.

a. Registration and RIN Generation Requirements
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Section 80.1426 paragraphs (f)(10) and (11) describe the requirements for generating 

RINs for renewable electricity and biogas which are either introduced into a dedicated renewable 

distribution system (§ 80.1426(f)(10)) or introduced into a commercial distribution system (§ 

80.1426(f)(11)). EPA requested comment on the provisions and suggestions for alternative 

requirements. Several commenters provided background information related to actual renewable 

electricity generation and transportation use to aid in the development of more detailed 

provisions. This information included specific detail on how individual companies are currently 

using biogas to generate electricity for transportation purposes, and what these companies are 

doing to comply with state regulatory programs. These comments illustrated a number of 

significant challenges faced by parties wishing to generate biogas electricity RINs under the RFS 

program. 

Most commenters agreed that the electricity distribution system is complex, and that 

detailed and clear regulatory requirements specific to renewable electricity are needed. EPA 

agrees that the electricity generation system is complex, and EPA intends to take more time to 

evaluate the options and their implications. We believe that the regulatory changes made in this 

final rulemaking to section 80.1426 paragraphs (f)(10) and (f)(11) should help address some of 

those challenges. EPA and stakeholders will benefit from additional experience in implementing 

the current provisions before adopting significant modifications. 

b. Distribution and Tracking Requirements
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Tracking and verifying the production and use of the renewable electricity are of 

particular concern. Each state regulates electricity individually and so there is a wide variety of 

systems and requirements that must be accounted for in establishing a robust system for 

electricity accounting. In addition, several states have renewable portfolio standards and

“renewable electricity

56 credit” (REC) programs. Further, most states do not allow private 

electricity generators to sell electricity directly to consumers. Therefore we cannot rely solely on 

written contracts for tracking of renewable electricity to transportation use. An alternative 

tracking and verification system must be established. The alternative adopted in this final rule is 

described in the next section. 

It was suggested by commenters that EPA leverage existing state renewable electricity 

portfolio programs to track and validate RINs generated for RFS-qualified renewable electricity. 

These programs rely on defined environmental attributes which can be owned and transferred 

independently of the actual electricity. Ownership of these environmental attributes allows 

regulated parties to demonstrate compliance with the renewable electricity portfolio programs. 

Given the variety of renewable electricity programs managed by a multitude of states, this does 

not seem workable for the RFS program. In addition, EPA does not intend for the RFS to 

interfere with existing state programs. Therefore we have made the decision to match generation 

to use, and not require the purchase or definition of related environmental attributes. This does 

not preclude RIN generators from participating in state renewable electricity programs or from 

using that information to support their RFS registration and reporting documentation.

 

56 When referring to various state “renewable electricity” programs in this preamble, we are using that term 

as defined in the state programs, and do not intend to suggest that the electricity in question necessarily satisfies the 

RFS regulatory definition of “renewable electricity.”
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2. Regulatory Changes Applicable to all Biogas Related Pathways 

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 to end use, and regarding what company along the production chain is considered the 

“producer” and eligible to generate RINs under the RFS program. In this rulemaking, we have 

revised the documentation requirements slightly, to better track the biogas as it moves into and 

out of the distribution system and to document the final use as a transportation fuel. Provisions 

related to registration, reporting and recordkeeping were revised as well. These provisions allow 

for the use of signed affidavits, when written contracts are not available, to prove the use or sale 

of renewable electricity and renewable CNG/LNG for transportation purposes. It is assumed that 

these affidavits would be signed by fleet managers or vehicle operators, verifying the use of the 

renewable transportation fuel. These affidavits would then be matched, by the registered fuel 

producer, to the delivery or sale of an equivalent amount of qualifying renewable electricity or 

renewable CNG/LNG. These amended requirements are applicable to all pathways related to 

biogas.

 We proposed that the “producer” of renewable CNG/LNG be the company that 

compresses or liquefies the gas and distributes the CNG/LNG for transportation fuel, and for 

renewable electricity, we proposed that the “producer” would be the company that distributes the 

electricity for use as transportation fuel. Numerous commenters indicated that limiting RIN 

generation to the CNG/LNG or electricity distributor would revoke current RIN generation 

ability from those who have invested significant resources in developing biogas projects. Some
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commenters also stated that the company first injecting the pipeline quality biogas into the grid 

would be intimately familiar with the responsibilities in tracking distribution, and should be 

eligible to act as the RIN generator. Given the complexities of the situation involving the 

production, transportation and use of biogas-derived fuels, we are not finalizing the definition of 

“producer” for renewable CNG/LNG and renewable electricity. EPA believes a more 

appropriate approach at this time is to examine registrations on a case by case basis in the short 

term, and to learn from this experience prior to issuing any final rule addressing the subject.

The processing and distribution train from raw biogas to final transportation fuel use can 

be 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, wastewater treatment

plants), to where it is processed, converted into biofuel and distributed to consumers. In some 

cases the fuel may be cleaned at a biogas scrubbing facility to pipeline quality specifications for 

distribution, and then withdrawn from the commercial pipeline to be processed further at another 

production facility into renewable CNG/LNG or renewable electricity. The company registering 

to generate RINs is responsible for providing all the required information and supporting 

documentation in their registration, and for satisfying reporting and recordkeeping requirements 

to track and verify the movement of gas from point of extraction of the raw biogas from its 

original source, through all the processing steps and distribution steps 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 biogas production facility covered by the producer’s registration that 

is located prior to the point of injection into a common carrier pipeline, or in the case of on-site 
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distribution, prior to the point of distribution for transportation usage. The third-party engineer

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. EPA does not specifically define where the producer must lie on the value chain, as any

company in a position to oversee the entire process and provide all necessary documentation may

act as the RIN generator. These requirements will help ensure that the company registering to 

generate RINs will only generate RINs for fuel that is fully compliant with all regulatory

requirements. The registration, reporting and recordkeeping requirements are in §§ 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 and can be located in 

§ 80.1426(f)(10), (11), and (13). 

D. Clarification of the Definition of “Crop Residue” and Clarification of Feedstocks 

that EPA Considers Crop Residues

1. Clarification of the Definition of “Crop Residue”

In today’s FRM, EPA is amending “crop residue” in the RFS regulations to more clearly 

describe the characteristics of products that should fall within the definition.57 The final 

amendments are identical to those proposed. EPA proposed in the NPRM to include this 

amendment to provide more detailed guidance regarding the types of feedstocks that EPA 

 

57 See § 80.1401.
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considers crop residues. In our preexisting regulations, “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.”

58

 

In the NPRM, we proposed to amend the definition to specify that 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. We also noted 

that crop residue must come from crop production or processing for some other primary purpose 

(e.g., refined sugar, corn starch ethanol) or be removed to facilitate crop management, 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.”

59

 We stated further that 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. 

We sought comment on this revision to the crop residue definition, specifically inviting

comments regarding what ought to constitute a “significant” increase or decrease in GHG 

emissions in the context of this definition.

 

58 Ibid.

59 Ibid.
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We received significant comment supporting and opposing this change. At least one 

commenter who supported the change also stated that EPA should amend the definition of crop 

residues to more explicitly exclude non-cellulosic components of crop residues.60 We address 

the question of the cellulosic content of feedstocks in Section IV.A of this rulemaking. 

Information available to EPA indicates that crop residue as a class more than satisfies the 75% 

cellulosic content threshold we have adopted today to identify feedstocks which are eligible to 

generate cellulosic biofuel RINs for the entire produced volume.61 For this reason, we are not 

modifying the definition as suggested by the commenter. 

Those opposed to the proposed change were uniformly clear that they supported the crop 

residue pathway in general.62 Opposition stemmed from concerns that our proposed clarification 

would be overly limiting and would exclude feedstocks that rightfully ought to be considered 

crop residues under the RFS. Several commenters stated that very few products have no market 

value and that most will find some sort of beneficial use. These commenters expressed concern 

over our statement in the preamble of the NPRM that, in order to meet the definition of crop 

residue, a crop product must generally not have a significant market in its own right. In their 

estimation, the fact that most crop products have a non-zero market value might cause them to be 

disqualified from the crop residue pathway.

63

 EPA acknowledges that many crop residues have 

some non-zero market value. We also acknowledge that most could find some sort of beneficial 

 

60 Comments submitted by AFPM/API (EPA-HQ-OAR-2012-0401-0128).

61 See Memorandum to the Docket, “Cellulosic Content of Various Feedstocks,” Docket EPA-HQ-OAR-2012-

0401.

62 See, for example, comments submitted by the Renewable Fuels Association, (EPA-HQ-OAR-2012-0401-0123), 

the National Corn Growers Association (EPA-HQ-OAR-2012-0401-0065), and Growth Energy (EPA-HQ-OAR2012-0401-0173).

63 Here as well, several commenters expressed similar opinions. See, for example, comments submitted by the 

Renewable Fuels Association, (EPA-HQ-OAR-2012-0401-0123).
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use, albeit a low value use in many cases. This in turn may have some non-zero impact on the 

total revenue a farmer receives for a crop. However, we do not believe that a crop product must 

necessarily be completely useless in order to qualify under the crop residue pathway. Rather, as 

indicated in our amendment to the definition of crop residue and our statements in the NPRM 

preamble, the use of the crop product to produce renewable fuel should not significantly impact 

demand for the feedstock crop and associated products and should not lead to a significant 

increase in GHG emissions. It is our judgment that a crop product need not be completely 

devoid of value to meet these criteria, though there should be a notable difference in the value of 

the primary product and the value of the residue.

Other commenters stated that the use of a crop residue as biofuel feedstock gives it value 

and that this use itself may increase the total value of the primary crop.64 Several commenters 

expressed concern that this approach may create a chilling effect on investment in crop residuebased fuels.65

 EPA acknowledges the possibility that, if used as biofuel feedstock in large 

enough quantities, demand for a crop product may begin to affect the value of the primary crop. 

EPA noted in the NPRM that, if significant facts change over time, it is possible that EPA would 

modify its assessment regarding whether particular crop products meet the definition of crop 

residue. However, if EPA were to revise our assumptions or analysis concerning the 

qualification of certain crop products as crop residue, this change would be done after public 

notice and an opportunity for comment. Therefore, industry would have adequate opportunity to 

provide data to EPA prior to any potential changes to our interpretation regarding any of the 

feedstocks listed in Table IV.D.3-1. It is important to note that even if a particular feedstock 

 

64 See comments submitted by the National Corn Growers Association (EPA-HQ-OAR-2012-0401-0065) and the 

Iowa Corn Growers Association (EPA-HQ-OAR-2012-0401-0124), among others.

65 See, for example, comments submitted by the American Coalition for Ethanol (EPA-HQ-OAR-2012-0401-0147).
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evolved to the point where it had a significant market as a commodity and EPA were required to 

revisit the lifecycle GHG emissions analysis, this feedstock would most likely still meet the 

definition of renewable biomass. EPA would therefore be able to establish a new pathway for 

the feedstock upon completion of a lifecycle GHG analysis, even if the feedstock no longer fit 

under the crop residue pathway. In sum, we do not believe that the possibility of EPA 

reconsidering past LCA determinations, including those for crop residue pathways, should create

any undue uncertainty for the private sector, nor that the possibility of reconsideration will 

materially affect production of cellulosic renewable fuels under pathways allowing for the use of 

crop residue as a feedstock.

Most commenters who opposed the change also argued that the key consideration ought 

to be whether the residue meets the 60 percent GHG reduction threshold for establishing a 

pathway to generate RINs with a D code of 3 and/or a D code of 7 and that, as long as a crop 

product meets this threshold, it ought to be considered a crop residue.66 EPA believes that the 

term crop residue should be defined in a manner that ensures that materials within the definition 

satisfy the 60 percent GHG reduction threshold. This is one of the reasons why EPA is 

finalizing the proposed amended definition. Materials that do not meet the definition of crop 

residue, and do not qualify as other feedstocks listed in Table 1, may be independently evaluated 

to determine if they satisfy the 60 percent GHG reduction threshold, or other thresholds 

applicable to other types of biofuels. Parties questioning whether an agricultural product meets 

the current definition of crop residue must determine if the product is “left over.” Our proposed 

and final definitional change is intended to clarify what this means.

 

66 See, for example, comments submitted by Novozymes North America, Inc. (EPA-HQ-OAR-2012-0401-0088) and 

Growth Energy (EPA-HQ-OAR-2012-0401-0173).
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However, the current regulations do not provide stakeholders with much guidance 

regarding what EPA considers to be the meaning of “left over.” The current definition has 

created significant confusion and uncertainty among stakeholders. Our goal in clarifying the

definition of crop residue is to more transparently define the criteria that must be met for a 

feedstock to qualify under the existing crop residue pathway. Stakeholders who are considering 

whether or not to use a given feedstock will be able to consider these criteria, rather than relying 

on the current regulatory text that does not specify the meaning of “left over.”

Those opposed to the amendment to the definition of crop residue also generally argued 

that the word “significant” was used vaguely in our proposed clarification, and that this might 

create undue hurdles for producers seeking to use low-GHG crop products under the crop residue 

pathway.

67

 As stated previously, EPA sought comment on the proposed change and specifically 

regarding what ought to constitute a “significant” change in GHG emissions. Commenters who 

opposed the proposed clarification declined to offer alternative interpretations of the terms “left 

over” and “significant.” However, several of these commenters did state that EPA’s proposal did 

not sufficiently describe what might constitute a “significant increase,” a “significant market,” or 

a “significant impact.”

68

It is true that EPA did not provide specific criteria for meeting these significance 

thresholds. However, in our NPRM discussion concerning corn kernel fiber, we discussed this 

 

67 See, for example, comments submitted by the National Biodiesel Board (EPA-HQ-OAR-2012-0401-0166) and 

Novozymes North America Inc. (EPA-HQ-OAR-2012-0401-0088).

68 See, for example, comments submitted by the National Biodiesel Board (EPA-HQ-OAR-2012-0401-0166) and 

Novozymes North America Inc. (EPA-HQ-OAR-2012-0401-0088).
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question contextually. In that discussion, we described why we believe that corn kernel fiber

would not cause a significant increase in demand for corn, why we believe that corn kernel fiber

does not have a significant market in its own right, and why its removal from distillers’ grains to 

produce biofuel will not have a significant impact on direct or indirect GHG emissions. 

Stakeholders who wish to better understand how to evaluate whether other feedstocks meet the 

definition of crop residue should consult that discussion and the comparable discussion in 

Section IV.D.2 of this preamble.

Few commenters offered opinions regarding what might constitute a “significant market” 

for a crop product. However, comments submitted by the Iogen Corporation did provide one 

potential framework for understanding when a crop product might be considered to have a 

significant market. In their comments, Iogen stated that “EPA should not consider potential for 

significant crop shifting unless the farmer revenue per acre for raw unprocessed crop residue 

(i.e., before fees for collection, baling, stacking, transport, etc.) is more than 15 [percent] of the 

grain crop revenue per acre. We believe the volatility of the grain crop revenues is much larger 

than 15 [percent] of the grain price, and that the incremental revenue will not affect crop planting 

decisions.”

69

EPA has not utilized this methodology to identify which crop products we consider crop 

residues for the purposes of this final rulemaking. We acknowledge that this type of 

methodology could potentially be useful for evaluating whether future feedstocks meet our 

definition of crop residue, including non-grain crops. While we have not performed sufficient 

analysis to determine whether it is appropriate to adopt such an approach today, we may

 

69 Comments submitted by Iogen Corporation (EPA-HQ-OAR-2012-0401-0135).
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reconsider it in the future. Regardless, we do believe that it provides a useful consideration for 

stakeholders who are unsure whether a crop product might qualify as crop residue.

In Table IV.D.3-1 of this preamble, EPA identifies several crop products that we consider 

crop residues. In addition, we have provided greater transparency to stakeholders regarding the 

criteria for qualifying as a crop residue under the RFS in this preamble and in the clarified 

definition of crop residue. As a general principle, if a product meets the regulatory definition of 

crop residue as described above and is similar to a feedstock that we identify as a crop residue in 

IV.D.3-1, then it is likely that EPA would consider it as qualifying as a crop residue. 

Conversely, if it is not clear that a product meets the regulatory definition of crop residue as 

described above, or if the feedstock is not similar to any of the feedstocks identified in Table 

IV.D.3-1, then there is greater uncertainty that it will qualify.

70

EPA acknowledges that it may not always be straightforward for a stakeholder to 

determine for themselves whether a crop product is likely to qualify under the crop residue 

pathway, even with the guidance provided in this preamble and in the revised definition. In light 

of this, and to promote accurate identification of feedstocks that do and do not qualify as crop 

residues, EPA is implementing additional registration, recordkeeping, and reporting requirements 

for producers intending to use crop residue as a feedstock. These additional requirements will 

help to ensure that producers of renewable fuel do not inadvertently attempt to generate RINs 

 

70 It is important to keep in mind that not qualifying under the crop residue pathway does not in any way exclude 

fuel produced from a given feedstock from qualifying to generate RINs with a D code of 3 or a D code of 7 more 

generally. It only means that a new pathway would need to be established, were EPA to find that the fuel produced 

from that feedstock meets the 60 percent threshold.
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under a crop residue pathway utilizing a feedstock that EPA does not consider to be a crop 

residue. See section IV.D.4 of this final rulemaking for more details on these requirements.

 

2. Consideration of Corn Kernel Fiber as a Crop Residue

We also proposed in the NPRM that corn kernel fiber be considered a crop residue. Corn 

kernel fiber has not been specifically mentioned as a type of crop residue in any previous RFS 

rulemaking. However, EPA has received several requests to consider corn kernel fiber to be a 

crop residue. Because it had not been considered a crop residue previously, EPA conducted an 

evaluation that assessed whether corn kernel fiber should be considered a crop residue. This 

analysis focuses on whether corn kernel fiber can be considered “left over from the harvesting or 

processing of planted crops”, whether it has “no significant impacts on demand for the feedstock 

crop, products produced from that crop, or any substitutes for the crop and its products” nor “any 

other impact that would result in a significant increase in direct or indirect GHG emissions.”

We requested comment on our proposed analysis. We received significant comment 

supporting our analysis and our proposal that corn kernel fiber should be considered a crop 

residue.71 We did not receive any comments opposing our analysis or our conclusions. 

Accordingly, we have decided based on the assumptions, facts and analysis described below that 

corn kernel fiber should be considered crop residue as proposed. Should relevant facts described 

in our analysis change, a re-evaluation of the issue may be warranted. Our analysis of corn 

kernel fiber can serve as one of many possible illustrative examples of how crop products can be 

 

71 Several commenters expressed extremely similar opinions on this point. But see, for example, comments 

submitted by the Renewable Fuels Association, (EPA-HQ-OAR-2012-0401-0123), the National Corn Growers 

Association (EPA-HQ-OAR-2012-0401-0065), and Growth Energy (EPA-HQ-OAR-2012-0401-0173).
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evaluated for qualification as crop residues, in addition to our previous considerations of other

feedstocks that we consider to be crop residue, such as corn stover.

72

a. Analysis of Corn Kernel Fiber as a Crop Residue

The amended definition of crop residue requires us to consider any potential “significant 

impact on demand for the feedstock crop, products produced from that feedstock crop, and all 

substitutes for the crop and its products, [and] any other impact that would result in a significant 

increase in direct or indirect GHG emissions.” To determine whether the use of corn kernel fiber 

to produce renewable fuel would lead to increased direct or indirect GHG emissions stemming 

from any of these sources, 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. In our analytical judgment, any impacts on corn, corn products, or substitutes for corn 

or corn products would come from impacts on the feed market for dried distillers grains (DDG)

or from some other impact on overall demand for corn. We did not identify any other potential 

sources of significant increased GHG emissions in our proposed analysis, and no commenter 

suggested that any such source might exist. Therefore, we are confident that the analysis we 

have conducted below adequately addresses all aspects of the definition of crop residue, 

excepting questions regarding the source of the biomass, which will be evaluated in the context 

of each individual producer registration pursuant to 40 CFR 80.1450.

Producers acquire corn kernel fiber for ethanol feedstock as a part of the whole corn 

feedstock stream entering into a corn starch ethanol plant. This fiber stream may then be 

 

72 For our analysis of corn stover in the context of the crop residue pathway, see 75 FR 14670, March 26, 2010.
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accessed for ethanol production in one of two general ways. One option is for producers to

extract it from matter that would otherwise be converted to DDG during the dry mill corn ethanol 

production process. This step can be performed either before or after that matter has been 

separated from the corn starch ethanol. In either case, the corn fiber is processed into ethanol via 

a separate stream from corn starch ethanol production. A second option is for producers to

access and convert the fiber in situ along with the corn starch that is converted to ethanol. In 

order to meet the definition of a crop residue, the source of corn kernel fiber must be a corn

starch ethanol plant that is procuring whole kernels of corn for some other primary purpose (e.g.,

corn starch ethanol production). An ethanol producer utilizing corn kernel fiber as a feedstock 

cannot purchase whole corn for the primary purpose of generating corn fiber ethanol and still 

qualify their feedstock as crop residue. 

Consequently, this analysis relied significantly on the assessment of corn starch ethanolderived DDG that was conducted for the March 2010 RFS final rule, adjusting the analysis to 

account for the extraction of fiber from this product.73 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 that helped 

EPA evaluate the lifecycle GHG emissions of corn kernel fiber.

It is important to note that all animal feed products must be approved by the U.S. Food 

and Drug Administration (FDA) before they can be sold in the United States. EPA’s analysis 

makes observations and draws conclusions about the characteristics and likely uses of LF-DDG 

based on the available literature regarding LF-DDG that has been fed to livestock in research 

 

73 See 75 FR 14670, March 26, 2010
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settings. However, at this time the FDA has not approved LF-DDG for use in commercial 

animal feed. Nothing in EPA’s analysis should be construed as an official federal government 

position regarding the approval or disapproval of LF-DDG as an animal feed. Only FDA is 

authorized to make that determination. Our analysis proceeds from the assumption that 

producers of LF-DDG will be able to gain FDA approval for these feed products and that they

will do so before commencing production and sale of this feed product. If however FDA does 

not approve LF-DDG as an animal feed, there will be implications for the LCA of corn kernel 

fiber, and EPA will revisit its determination.

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.74 This means that, even though the physical volume of the LF-DDG produced by

ethanol plants using corn kernel fiber extraction technology will be somewhat smaller than the 

volume of DDG produced by plants not extracting corn kernel fiber, the nutritional content of 

LF-DDG for swine and poultry will be equivalent to or greater than DDG.

 

74 See, e.g., 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 as 

EPA-HQ-OAR-2012-0401-0002. See also additional studies cited within Kim et al 2010.
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Conversely, LF-DDF is an inferior feed for cattle compared to standard DDG, since 

ruminants benefit from ingesting corn fiber in DDG.75 Therefore, EPA expects swine and 

poultry producers to absorb the supply of LF-DDG, while the cattle and dairy industry will 

continue to consume standard DDG. With this dynamic in place, fiber extraction from DDG 

should not significantly affect feed markets, since there will be no reduction in the overall supply

of DDG in terms of nutritional content nor will there be any impact on aggregate demand for 

other animal feed sources.

If enough corn ethanol producers adopt fiber extraction technology, LF-DDG could 

saturate swine and poultry demand and spill over into dairy and cattle feed markets. If a 

situation arises where LF-DDG begin to replace standard DDG in dairy and/or cattle markets, 

this could lead to an increase in aggregate feed demand, most likely in the form of increased 

demand for fiber supplements in dairy and cattle feed. This theoretically could cause an increase 

in GHG emissions. However, we do not expect this to occur. 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, if significant facts change, it may be appropriate for EPA to reexamine corn kernel 

fiber as a crop residue in the future.

 

75 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 as EPA-HQ-OAR-2012-0401-0003.
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EPA’s analysis indicates that producing ethanol from corn kernel fiber is unlikely to 

increase overall demand for corn, in addition to having no significant impact on feed markets. It 

is our judgment, based on the analysis above, that the primary purpose of procuring whole corn 

for processing in a corn starch ethanol plant is to produce corn starch ethanol, since more than 

90% of the ethanol produced will be from the starch. The plant would most likely procure that 

same quantity of whole corn regardless of whether they were converting the fiber into ethanol or 

sending it to some other end use. The diversion of corn kernel fiber from the DDG stream to an 

ethanol production stream will not materially affect the value of the feed products produced by a 

corn starch ethanol plant per bushel of corn processed. Because of this, there will be no 

significant incentive for the plant that is producing ethanol from corn kernel fiber to procure 

more or less corn than they would if they were selling the fiber as part of their DDG product. 

We can find no evidence to support a claim that production of ethanol from corn kernel fiber has 

any significant impact on demand for corn, products produced from corn, or the substitutes for 

corn and its products. Further, we find that if corn kernel fiber is not used to produce ethanol, it 

will be left over from the corn starch ethanol production process, because its presence or absence 

in DDG products does not materially impact the value of those DDGs or the overall market for 

DDGs and feed products. Finally, we were unable to identify any other potentially significant 

impacts associated with utilizing corn kernel fiber to produce renewable fuel that might lead to

significant GHG emissions, nor were any such impacts identified during public notice and 

comment. Based on these factors, we find that utilizing corn kernel fiber to produce renewable 

fuel would have no significant impacts on GHG emissions. These findings support a 

determination that corn kernel fiber meets the definition of a crop residue. Therefore, corn 
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kernel fiber may be used as a feedstock in those pathways in Table 1 to § 80.1426 that specify

crop residue as a feedstock.

b. Treatment of Corn Starch that Adheres to Corn Kernel Fiber After Separation from DDG

EPA sought comment on whether the definition of crop residue should be amended to 

explicitly exclude the corn starch component, since some corn starch may still adhere to the corn 

kernel after separation. Additionally, EPA invited comment on how RINs should be allocated 

for fuel derived from corn fiber, including comment on the sufficiency of current RFS

regulations with regards to the assignment of RINs to batches of corn starch ethanol and corn 

kernel fiber ethanol produced via consolidated bioprocessing and whether producers have the 

technological capability to adequately demonstrate the volume of fuel produced under each 

pathway.

Commenters confirmed that some starch may adhere to the unconverted fiber, even after 

most of the starch has been processed into ethanol.76 However, many of those same commenters 

also supported considering this starch as “de minimis” under our current regulations.77 Those 

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.”

78

 We received several comments noting that corn kernels undergo a 

rigorous mechanical process designed to separate the starch from the rest of the corn kernel 

 

76 See, for example, comments submitted by Edeniq, Inc. (EPA-HQ-OAR-2012-0401-0159).

77 Numerous commenters supported this position. See, for example, comments submitted by Edeniq, Inc. (EPAHQ-OAR-2012-0401-0159), the American Coalition for Ethanol (EPA-HQ-OAR-2012-0401-0147), and Growth 

Energy (EPA-HQ-OAR-2012-0401-0173).

78 See specifically § 80.1426 (f) (1).
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before processing that starch into ethanol. Despite this process, some starch adheres to the 

fibrous portions of the kernel and, in a standard corn starch ethanol plant, ends up in the DDG.79 

Commenters argued that this adhering starch is indeed impractical to remove and is 

present only in small quantities.80 In the preamble of the NPRM for this rulemaking, EPA stated 

that we believed that starch might compose up to 20 percent of the separated mass used to 

produce corn kernel fiber ethanol via a separate stream. We received comment that the actual 

amount of starch that adheres to the fiber after separation from the rest of the corn kernel is 

typically less than 5 percent of the total mass of the separated corn kernel fiber feedstock, much 

lower than we initially believed.81 

In light of the small quantity of starch involved, typically less than 5 percent of the mass,

and the impracticability of separating the starch which adheres to the fiber, we believe that this 

starch component can appropriately be considered a de minimis contaminant. Like all plant 

fibers, the fibrous portion of corn kernel fiber is composed of nearly 100 percent cellulose, 

hemicellulose, and lignin. Taken together with the small quantity of adhering corn starch, corn 

kernel fiber is clearly above the 75 percent threshold we have established in today’s rulemaking 

for determining when a feedstock is predominantly cellulosic, and this is also consistent with our 

finding, discussed in Section IV.A of the preamble, that crop residue as a class has at least 75

percent cellulosic content. To be clear, this de minimis determination only applies to starch 

adhering to corn kernel fiber that is being processed into ethanol separately from corn starch 

 

79 See comments submitted by Quad County Corn Processors (EPA-HQ-OAR-2012-0401-0063), by Edeniq, Inc. 

(EPA-HQ-OAR-2012-0401-0159), and the American Coalition for Ethanol (EPA-HQ-OAR-2012-0401-0147).

80 See, for example, comments submitted by Edeniq, Inc. (EPA-HQ-OAR-2012-0401-0159).

81 Ibid.
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ethanol. Processes that convert corn starch and corn kernel fiber to ethanol in situ (as is 

described in detail in the next section) may not consider any portion of the corn starch to be de 

minimis.

c. Processing Corn Kernel Fiber 

Corn kernel fiber may be used for biofuel production in multiple ways. As detailed 

above in Section IV.A.3, renewable fuel can be produced pursuant to biochemical conversion 

processes that simultaneously hydrolyze and/or ferment cellulosic and non-cellulosic material 

into sugars and/or fuel. Corn kernel fiber as a crop residue may be converted into qualifying 

renewable fuel via biochemical methods in one of two ways.83 First, it may be converted via a 

consolidated bioprocessing method that converts cellulosic and non-cellulosic corn material into 

sugars and/or fuel products simultaneously. Second, corn kernel fiber may be converted to sugar 

and/or fuel via a separate stream from the corn starch sugar and fuel conversion streams.

The first method may include simultaneous hydrolysis of the starch and cellulosic 

components of the corn kernel into sugars, followed by simultaneous conversion of those sugars 

into fuel products. In other cases, the cellulosic and non-cellulosic portions of the corn kernel 

may be hydrolyzed separately but fermented together in a single vessel. In either case, EPA 

considers this process technology to be a method of simultaneous conversion. We discuss the 

requirements for using a simultaneous conversion process in Sections IV.A.3 of this preamble.

 

83 Corn kernel fiber may also be converted to fuel via thermochemical methods. See Sections A.5 and A.6 for 

details on the requirements for renewable fuel production via thermochemical pathways.
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Alternatively, producers may hydrolyze and ferment the cellulosic and non-cellulosic 

portions of the corn kernel via separate streams. This may be accomplished in at least one of two 

ways. A producer might separate the starch from the corn kernel fiber before the hydrolysis step, 

sending each set of material through separate hydrolysis, fermentation, and distillation streams. 

A producer might also perform a conventional corn starch ethanol fermentation process, yielding 

corn starch ethanol, and then hydrolyze and ferment the residual solids (which typically become 

DDG at the end of the process) a second time, using enzymes designed to convert cellulosic 

material to sugars. If a producer uses a process that hydrolyzes and ferments the corn kernel 

fiber separately from the corn starch, either in a parallel but separate process or in a sequential 

process that extracts the fiber from the residual solids after corn starch ethanol fermentation, then 

the producer is not considered to be performing simultaneous conversion, and all of the resulting 

corn kernel fiber-derived fuel may appropriately be considered derived from predominantly

cellulosic biomass. As discussed above, some starch may adhere to the fiber after the separation 

step or may remain in the residual solids output of a conventional corn starch ethanol 

fermentation process. However, we believe this small amount of corn starch contaminant fits 

under EPA’s de minimis feedstock contaminant provision in the existing regulations, and should 

be disregarded.

84

 This is the case even if a producer were to add enzymes which might convert 

starch adhering to the corn kernel fiber to ethanol.

3. Identification of Feedstocks EPA Considers Crop Residues

To provide additional guidance on the definition of crop residue, EPA is identifying 

several feedstocks that we consider to be crop residues. In the NPRM, we provided a table that 

 

84 See specifically § 80.1426 (f) (1).
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included feedstocks which we have previously identified as crop residues in public documents 

and which we believed fit the definition of crop residue.85 That table included corn stover, corn 

kernel fiber (see Section IV.D.2 above for further discussion), citrus residue, rice straw, 

sugarcane bagasse, and wheat straw. All of these feedstocks were identified as crop residues in 

the preamble of the March 2010 RFS final rulemaking, with the exception of corn kernel fiber. 

For example, EPA analyzed the agricultural sector GHG emissions of using corn stover for 

biofuels in the final March 2010 RFS final rulemaking and found that fuel produced from this 

feedstock met the 60% GHG reduction threshold for cellulosic biofuels.86 Since the direct and 

indirect impacts of several other crop products, including citrus residue, rice straw, and wheat 

straw, were expected to be similar to those of corn stover, EPA also applied the land use change 

impacts associated with corn stover to those products as well. Based on that analysis, EPA found 

that fuels produced from these products 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 crop residue. 

EPA sought comment on whether these feedstocks should be considered crop residues, 

whether these feedstocks would have direct and indirect GHG impacts similar to corn stover, and 

whether additional feedstocks should also be considered crop residues. We received numerous 

 

85 See Table IV.D.-1 – Feedstocks That May Qualify as Crop Residue, 78 FR, 36056-57, June 14, 2013.

86 See EPA-HQ-OAR-2005-0161-3173.2, EPA-HQ-OAR-2005-0161-3173.3, and 

EPA-HQ-OAR-2005-0161-3173.4, under the Lifecycle Results Docket for the March 2010 RFS Final Rulemaking.
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comments that supported considering all of these feedstocks as crop residues.87 We did not 

receive any comments that opposed considering any of the feedstocks identified in the NPRM as 

crop residues, nor did we receive any comments that disputed our reasons for considering them 

crop residues. 

In addition, several commenters identified other crop products which are extremely

similar to those that we proposed to consider crop residues. Commenters noted that we have 

identified sugarcane bagasse as a crop residue in multiple rulemakings, including the March 

2010 RFS final rule and the NPRM of this rule, but have not previously considered sweet 

sorghum bagasse.88 The processes for separating bagasse from simple sugars is very similar 

between sugarcane and sweet sorghum and the market and other potential GHG impacts of 

utilizing that bagasse to produce renewable fuel are also considered to be similar. Therefore we 

are today identifying both as feedstocks which we consider crop residues. 

Commenters noted that we identified corn stover as a crop residue in the NPRM, but have 

not previously considered grain sorghum stover.89 Since the composition, methods of 

production, methods of collection, market potential, and implications for other relevant markets

for these two types of stover are nearly identical, these two stovers would reasonably seem to 

have similar GHG impact profiles. 

 

87 Several commenters expressed extremely similar opinions on this point. But see, for example, comments 

submitted by the Renewable Fuels Association, (EPA-HQ-OAR-2012-0401-0123), the National Corn Growers 

Association (EPA-HQ-OAR-2012-0401-0065), and Growth Energy (EPA-HQ-OAR-2012-0401-0173).

88 See comments submitted by NexSteppe Inc. (EPA-HQ-OAR-2012-0401-0153). See also 75 FR 14692, March 26, 

2010 and 78 FR 36042, June 14, 2013.

89 See comments submitted by the National Sorghum Producers (EPA-HQ-OAR-2012-0401-0065), Iogen 

Corporation (EPA-HQ-OAR-2012-0401-0135), NexSteppe Inc. (EPA-HQ-OAR-2012-0401-0153).
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Commenters also noted that, in the NPRM, we did not list grain fibers other than corn 

kernel fiber. To the extent that other grain kernel fibers are extracted and used for biofuel 

feedstock in the same manner as we lay out for corn kernel fiber in Section IV.D.2 above (i.e., 

during the processing of grain feedstock into ethanol), these products would reasonably seem to 

have similar GHG impact profiles to corn kernel fiber.90 To the extent that these grain fibers are 

obtained in the same manner that we have laid out for corn kernel fiber, their alternative fate 

would also be distillers grains. The impacts of fiber on the digestion of ruminants, swine, and 

poultry are extremely similar, regardless of what grain that fiber came from, because all grain 

fiber is virtually 100 percent cellulosic. Therefore, we are confident that diverting that fiber to a 

fuel production stream would have similarly insignificant market and other GHG impacts to 

those of corn kernel fiber, and we similarly consider them to be crop residues under those 

circumstances. 

Commenters also pointed out that we identified wheat straw and rice straw as crop 

residues in the NPRM but did not identify other grain straws (e.g., oat straw, barley straw) as 

residues, even though these products would reasonably seem to have similar GHG impact 

profiles to wheat straw and rice straw.91 EPA has determined that these straws do indeed have 

similar GHG impacts to those of wheat straw and rice straw. All of them have similarly

insignificant markets, insignificant effects on demand for the crop from which they are derived, 

and insignificant impacts on other crop products and substitutes. Further they are processed into 

 

90 See comments submitted by Novozymes North America Inc. (EPA-HQ-OAR-2012-0401-0088), ICM (EPA-HQOAR-2012-0401-0114), NexSteppe Inc. (EPA-HQ-OAR-2012-0401-0153), Growth Energy (EPA-HQ-OAR-2012-

0401-0173),

91 See comments submitted by Iogen Corporation (EPA-HQ-OAR-2012-0401-0135), 
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renewable fuel in nearly identical ways. Therefore, we consider all of the grain straws listed in 

Table IV.D.3-1 below to be crop residues.

Finally, while we proposed to identify “citrus residue” as a crop residue in the NPRM, 

several stakeholders have suggested that this label is rather vague. Citrus oils have significant 

existing markets in their own right in the cosmetic and food industries, among others. Because of 

this, we generally consider only citrus peels from which oils have been extracted to be crop 

residues. In general, we consider other residues from the processing of citrus fruit, such as seeds

or pulp leftover from the juicing process, to be citrus residues. Further, we do not generally 

consider tree matter which is not part of the fruit, such as fallen leaves or branches, to be crop 

residue. However, these byproducts may fit the definition of “tree residue” in our regulations 

and could potentially be used to produce qualifying renewable fuel under tree residue pathways.

In Table IV.D.3-1we are identifying several crop products that EPA considers to be crop 

residues.

92

 This table is meant to be illustrative, not exhaustive, of the types of crop products 

that EPA considers to be crop residues. It is included here to provide guidance and greater 

clarity to stakeholders; it should not be considered a definitive list. It will not appear in our 

regulations, though EPA may publish a table similar to Table IV.D.3-1 on our website for the 

convenience and education of stakeholders. We acknowledge that there may be other crop 

products which were not brought to our attention during this rulemaking process and which are 

not included in Table IV.D.3-1, but which may meet the definition of crop residue as we are 

clarifying it in today’s final rulemaking. Further details regarding how EPA may evaluate these 

crop products can be found in Section IV.D.1 and Section IV.D.2 of this final rulemaking. 

 

92 Our analysis of corn kernel fiber as a crop residue is discussed in Section IV.D.2 of this preamble. 
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Additionally, stakeholders may also want to consult Section IV.D.4 of this final rulemaking, 

which describes new RRR requirements for producers who wish to use crop residue as a 

feedstock for renewable fuel production.

Table IV.D.3-1 – Feedstocks That EPA Considers Crop Residues

Sugarcane and Sweet Sorghum Bagasse

Kernel Fiber from Barley, Corn, Oats, Rice, Rye, Grain Sorghum, and Wheat

Stover from Corn and Grain Sorghum

Straw from Barley, Oats, Rice, Rye, Soybeans, and Wheat

Citrus Residues from Fruit Processing 

4. Registration, Recordkeeping, and Reporting Requirements Associated with Using Crop 

Residue as a Feedstock

Under current regulations, producers registering to generate RINs using the crop residue 

pathway are not required to specify exactly which crop products they intend to use. This could 

potentially lead to a situation where a producer inadvertently generates invalid RINs by 

producing a batch of fuel from a crop product that does not meet the crop residue definition. In 

order to ensure that producers only utilize crop products which EPA considers to be crop 

residues and thereby generate valid RINs when using a crop residue pathway, we are 

implementing additional RRR requirements for producers using crop residue as feedstock under 

any approved pathway. 
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a. Registration Requirements for Producers Utilizing Crop Residue as a Feedstock

EPA acknowledges that the regulatory definition adopted today may be difficult to 

interpret in some respects. On the other hand, EPA believes that the proposed revised definition 

appropriately describes crop products that should qualify as crop residues. In order to reduce 

uncertainty and confusion in the application of the revised definition, we are implementing a new 

registration requirement for those seeking to use crop residues as a feedstock. Any entity

registering to use crop residue as a feedstock must, as a part of their registration package 

submitted pursuant to 40 CFR 80.1450, include a list of all crop materials they intend to use that 

they consider to be crop residue, and a justification for their belief that the listed crop materials 

meet the regulatory definition of crop residue. These regulatory amendments appear in 40 CFR 

80.1450.

If the crop product is one that EPA has previously identified as meeting the regulatory

definition of crop residue, then referencing the relevant EPA document will likely be sufficient

justification. However, if a crop product is not one that EPA has previously identified as a crop 

residue, then EPA intends to evaluate whether that feedstock meets the regulatory definition

prior to accepting the facility’s registration. If the feedstock is very similar to one that EPA has 

already evaluated, this may be a relatively brief process. See the discussion in Section IV.D.3

above for some examples of how this comparison could be performed by EPA. However, if the 

feedstock markedly differs from those we have evaluated previously, as corn kernel fiber did 

before this final rulemaking, then a more extensive analysis, even including lifecycle GHG 

analysis, may be required. Each feedstock presents its own sets of questions. Stakeholders may
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wish to consult our analysis of corn kernel fiber in Section IV.D.2 of this rulemaking for an

example of such an analysis.

If EPA decides that further analysis of a particular feedstock is needed, the registrant will 

have the option of removing the crop product from its registration package, in order to allow the 

remainder of the package to be processed more quickly and to allow the producer to be registered 

and begin production using other feedstocks pending EPA’s analysis. If EPA later determines 

that the crop product in question meets the regulatory definition of crop residue, then the 

registrant could update their registration to include that feedstock. However, in order to avoid 

delay, stakeholders may wish to consult EPA’s website and rulemakings regarding the definition 

of crop residue before submitting their registration. Should a stakeholder discover that a 

feedstock they are planning to utilize has not been previously identified by EPA as a crop 

residue, it may be beneficial and expedient for them to consult EPA before submitting their 

registration. We are not finalizing any requirement that stakeholders take this affirmative step 

before submitting their registration. However, we believe that taking this step may lead to a 

more streamlined process for entities who wish to utilize a new crop product as feedstock in 

pathways providing for use of crop residue.

Entities who are already registered to generate renewable fuel using crop residue as a 

feedstock will not be required to immediately update their registration to conform to these new 

requirements. However, when these entities perform periodic updates to their registration 

pursuant to 40 CFR 80.1450(d)(3), they will be required to include the information described in 

these new requirements at that time.
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b. Recordkeeping and Reporting Requirements for Producers Utilizing Crop Residue as a 

Feedstock

In addition to the registration requirements outlined above, EPA is also requiring that any 

entity registered to generate RINs using crop residue as a feedstock keep records of the quantities 

of each specific crop product they utilize, and that they report the quantities used to generate 

qualifying renewable fuel over the past three months in each quarterly report to EPA.93 This 

requirement is somewhat different from the feedstock reporting requirement associated with 

reporting RIN generation in EMTS. In EMTS, the RIN generator is only required to report the 

total quantity of crop residue used to produce the batch of fuel for which RINs are generated. 

These new recordkeeping and quarterly reporting requirements go a step further by requiring 

specific accounting of the exact quantities of individual crop products used by the producer over 

a three-month period. The exact regulatory requirements of this new provision are detailed in the 

amendments to 40 CFR 80.1451 and 80.1454 below.

E. Amendments to Various RFS Compliance Related Provisions

We are finalizing a number of changes to the RFS regulations related to compliance,

except for the definition of “responsible corporate officer” (RCO), which was proposed but is not 

being finalized. 

 

93 At the time of this rulemaking, RIN generators would report this information via quarterly report number 

RFS0801. See http://www.epa.gov/otaq/fuels/reporting/rfs.htm for further details.
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1. Changes to Definitions

“Responsible Corporate Officer”

EPA is not finalizing the definition of “responsible corporate officer.” The existing RFS 

regulations at §§ 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” had not been defined in 

the RFS regulations. 

Several commenters requested that EPA review its existing policy on acceptable position 

titles and what registration updates have to be approved by an RCO. These comments were 

directed at EPA’s administrative procedures and registration system, rather than the regulatory

responsibilities of the RCO with regard to compliance with RFS standards. EPA needs to 

evaluate the registration process, which may include potential modifications to the registration 

system, for opportunities to minimize burden on RCOs and to better differentiate an RCO’s roles 

with respect to program compliance versus administrative roles in our registration system. Based 

on these comments and the potential for registration system modifications, EPA is not finalizing 

the RCO definition at this time. Regulated parties should continue to follow existing regulations

and registration procedures. 

 

“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 under CAA 

211(o)(9)(B). In EPA’s March 26, 2010 regulations implementing the EISA amendments to the 

RFS program 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 proposed 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 proposed specifying in § 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 § 80.1401 for all full calendar years between 2006 and the date of submission of the 

petition for an extension of the exemption. 

We proposed that that these changes would not affect any existing exemption extensions 

under CAA 211(o)(9)(B); rather, they would apply at such time as any approved exemption 
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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. 

We received two comments on our proposed small refinery revisions, both supporting 

EPA’s proposed change. We received no negative comments on our proposed small refinery

revisions. Therefore, we are finalizing these revisions as proposed.

2. Provisions for Small Blenders of Renewable Fuels

The RFS regulations at § 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 requested input on what a more appropriate gallon threshold should be

and indicated in the proposed rule they might change the gallon threshold based on received 

input. 

EPA received two comments agreeing with the idea to increase the threshold and one 

comment suggesting it remain at the current amount of 125,000 gallons. Of the two commenters 

suggesting the amount should be increased, one suggested an increased amount of 250,000 

gallons, and the other suggested an increased amount of 3 to 4 million gallons. Based on 
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comments received from stakeholders previously and based on comments received on the 

proposed rule, EPA believes it is reasonable to increase the threshold for small blenders of 

renewable fuels (those that are not obligated parties or exporters) to help relieve burden from 

managing RINs. However, EPA is cautious not to increase the threshold beyond what is 

reasonable and beyond an amount that would be considered “small.” EPA generally agrees with 

one of the commenter’s suggested amount of 250,000 gallons. Doubling the threshold from 

125,000 gallons to 250,000 gallons will provide additional relief to the smallest renewable fuel 

blenders. Therefore, EPA is adjusting the gallon threshold for small blenders of renewable fuels 

(and who are not obligated parties or exporters) that want to delegate their RIN-related 

responsibilities to the party directly upstream from them who supplied the renewable fuel for 

blending. The threshold is being changed from 125,000 gallons to 250,000 gallons in today’s

final rule. 

3. Changes to Section 80.1450 – Registration Requirements

EPA is adding a new paragraph (h) to § 80.1450 that describes the circumstances under 

which EPA may deactivate a company registration. In addition to describing the circumstances, 

EPA is also laying out an administrative process to initiate a deactivation that provides any

company the opportunity to respond to and/or timely submit the required information.

EPA originally proposed deactivating a company that had no activity in EMTS for one 

calendar year (January 1 through December 31). Commenters noted that there may be valid 

reasons for a break in use of EMTS within a calendar year. To avoid this scenario, EPA is 
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modifying this provision to specify that if a company has reported no activity in EMTS under §

80.1452 for over twenty-four calendar months, EPA will send a written notice addressed to the 

company contacts. A company will have 14 days to respond to this letter stating whether or not 

they wish to remain in the EMTS system. If a company responds that they wish to remain as a 

current registered party in EMTS, EPA will not deactivate their registration. If there is no 

satisfactory response received, then EPA may deactivate the registration.

Using the same process described above, EPA may also deactivate a company

registration if a party fails to comply with any registration requirement of § 80.1450, if the party 

fails to submit any required compliance report under § 80.1451, if the party fails to meet the 

requirements related to EMTS under § 80.1452, or if the party fails to meet the requirements 

related to attest engagements under § 80.1454. If any required report, including the attest 

engagement, is thirty (30) or more days overdue, EPA will provide written notice to the owner or 

responsible corporate officer (RCO) that it intends to deactivate 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 may deactivate the registration.

Reactivation will be possible following the submission or updating of all required information 

and reports.

4. Changes to Facility’s Baseline Volume to Allow “Nameplate 

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

Reduction Threshold
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As a requirement of registration under the RFS program, each renewable fuel producer 

and foreign ethanol producer must establish and provide documents to support its facility’s 

baseline volume as defined in § 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 RFS 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 RFS program. There were no adverse comments 

regarding this proposal. Therefore, in this rulemaking we are finalizing our decision to allow a 

facility to use its “nameplate capacity” to establish its facility’s baseline volume for the purposes 

of registration. The “nameplate capacity” may be used only if the facility 1) does not have a 

permit or there is no limit stated in the permit to establish their permitted capacity; 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 finalizing our decision

that the extension of this option not be available to facilities claiming an exemption under § 

80.1403. Additionally, by this stage in the RFS program, the facilities that would qualify for 
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registration under § 80.1403 would be very few, if any. We are also finalizing the revision of 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. 

5. Changes to Section 80.1463 – What Penalties Apply Under the RFS Program?

Preventing the generation and use of invalid RINs and encouraging rapid retirement and 

replacement of invalid RINs is crucial to the integrity of the RFS program. The RFS regulations 

include various provisions related to prohibited acts, liability for violations, and penalties for 

those violations. 

Section 80.1460 sets forth the prohibited acts for the renewable fuels program. Section 

80.1461(a) states that any person who violates a prohibition in § 80.1460 (a) through (d) is liable 

for the violation of that prohibition, and § 80.1461(b) provides the liability provisions for failure 

to meet other provisions of the regulations. The penalty provisions of the regulations at § 

80.1463(a) state that any person who is liable for a violation under § 80.1461 is subject to a civil 

penalty as specified in § 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.’’ 

As described in the proposal, EPA interprets these statutory and regulatory penalty

provisions to give the Agency the authority to seek penalties against parties generating, 
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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 RFS program to acquire and retire RINs. For example, for a RIN 

generator, this time period typically runs from the date of invalid RIN generation until either 

corrective action is taken by the RIN generator to remove the invalid RIN from the marketplace 

or a party uses the RIN to satisfy an RVO or other requirement to retire RINs such as would 

apply under today’s proposal to exporters of renewable fuel. 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 § 80.615), and will encourage renewable fuel producers 

that generate invalid RINs to promptly take corrective action. 

EPA received comments from two parties in opposition of the proposed regulation in §

80.1463. Both commenters identified that a party who generates or transfers a RIN may be kept 

in another party’s inventory outside of the generator’s or transferor’s control. Therefore, if that 

RIN is later identified as invalid the generator and transferor could be held to substantial 

penalties based on actions by other parties beyond their control. One of the commenters stated 

they believe that finalizing this regulation will “cause confusion and may create disincentives for 

producers to self-report and take corrective actions, rather than promote compliance”. While 

EPA acknowledges that the RIN generator or subsequent transferor cannot force another party to 

retire RINs, the regulations at § 80.1431(b)(1) state that “Upon determination by any party that 

RINs owned are invalid, the party must ...retire the invalid RINs in the applicable RIN 

transaction reports...for the quarter in which the RINs were determined to be invalid”. 

Therefore, EPA believes that finalizing EPA’s existing interpretation of per day violations for the 
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generation or transfer of invalid RINs will minimize potential penalties and incentivize parties 

who committed a prohibited act at § 80.1460 (b)(1)-(4) and (b)(6) to identify invalid RINs to 

those owning parties so they can retire RINs as required in § 80.1431(b)(1) prior to an obligated 

party or renewable fuel exporter using those RINs for compliance purposes. 

One commenter stated that EPA should continue to use its enforcement discretion to 

assign appropriate penalties instead of finalizing this regulation. In the proposal, EPA explained 

that this regulation would simply codify our existing practice and interpretation and that we 

would continue to evaluate the appropriate penalties for each violation on a case by case basis. 

Although EPA is finalizing this regulation to make it clear to the regulated industry that EPA has 

the authority to seek the maximum statutory penalty for each day of violation, the Agency will 

continue to evaluate appropriate penalties on a case by case basis.

As described above, EPA is finalizing the addition of the new paragraph (d) to § 80.1463 

which more explicitly incorporates EPA’s interpretation of these penalty provisions into the 

regulations. The language has been modified from the proposal to follow the existing format and 

language in § 80.1463. The amendments state that any person liable under § 80.1461(a) for a 

violation of § 80.1460(b)(1)-(4) and (b)(6) for RIN generation or transfer violations 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. 

F. Minor Corrections to RFS Provisions 
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We are finalizing a number of corrections to address minor definitional issues that have 

been identified in implementing the RFS program.

Renewable Biomass

We are finalizing an amendment to the definition of “renewable biomass” in § 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 RFS 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 provides additional clarity to the regulations. 

English Language Translations

We are finalizing the addition of a new paragraph (i) to § 80.1450 stating that any

registration materials submitted to EPA must be in English or accompanied by an English 

language translation. Similarly, we are finalizing the addition of a new paragraph (h) to §

80.1451, which states that any reports submitted to EPA must be in English or accompanied by 

an English language translation. We are also finalizing the addition of a new paragraph (q) to §

80.1454, which states 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 RFS program.
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Correction of Typographical Errors 

We are finalizing typographical and grammatical corrections in § 80.1466 as proposed. 

Specifically, we are amending 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 are also 

amending paragraph (d)(3)(ii) to correct a typographical error. The current regulation cites §

80.65(e)(2)(iii), which does not exist. The correct citation is § 80.65(f)(2)(iii). 

V. Amendments to the E15 Misfueling Mitigation Rule 

In the NPRM, we proposed several minor corrections and other changes to the E15 

misfueling mitigation rule (E15 MMR) found at 40 CFR part 80, subpart N. 

A. Changes to Section 80.1501 – Label

We proposed to correct several minor errors in the description of the E15 label required 

by the E15 MMR at § 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), but there were some minor typographical errors 

in the regulations.
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We received a number of comments on the E15 label changes, and most were supportive 

of the corrections to the regulations to make the label consistent with the picture of the E15 label 

in the E15 MMR. However, some comments expressed concerns about the potential costs to 

retail stations already lawfully selling E15 with labels produced under the current regulations. 

We recognize this concern; however, we do not believe that this is an issue since EPA has 

worked closely with the limited number of retail stations that have lawfully offered E15 to date 

to ensure that their labels met the intent of the E15 MMR (i.e., were consistent with the label 

pictured in the E15 MMR).

We also received several comments requesting that EPA make substantive changes to the 

E15 label (e.g., change the word “ATTENTION” to “WARNING”). The Agency thoroughly 

explained its rationale for its label design in the E15 MMR and was not intending to make 

substantive changes to the E15 label in this rulemaking. We also received comments suggesting 

additional labeling requirements for blender pumps. We believe that these comments are outside 

of the scope of this rulemaking.

Therefore, we are finalizing the changes to the E15 labeling regulations at § 80.1501 as 

proposed.

B. Changes to Section 80.1502 – E15 Survey

We proposed two changes to the survey requirements found at § 80.1502. First, we 

proposed to clarify that E15 surveys need to sample for Reid vapor pressure (RVP) only during 
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the high ozone season as defined in § 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 proposed 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. 

Comments received on these two changes to the E15 survey requirements were 

overwhelmingly supportive. Therefore, EPA is finalizing the changes to the E15 survey

requirements in § 80.1502 as proposed.

C. Changes to Section 80.1503 – Product Transfer Documents 

In the NPRM, we proposed certain minor changes to the product transfer document 

(PTD) requirements found in § 80.1503. Specifically, we proposed to allow the use of product 

codes for conventional blendstock/gasoline upstream of an ethanol blending facility, since 
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historically, the codes have been allowed to be used for conventional blendstock/gasoline 

upstream of an ethanol blending facility in other fuels programs. We noted that this was an 

unintentional omission from the original regulation. 

Commenters unanimously supported including language that allowed the use of product 

codes for conventional blendstock/gasoline upstream of an ethanol blending facility. Some 

commenters pointed out that maintaining the current language allowing the use of product codes 

downstream of an ethanol blending facility did not make sense since product codes have not 

typically been used in that part of the gasoline distribution chain. Therefore, we are finalizing 

the flexibility for parties upstream of an ethanol blending facility to use product codes and 

removing the extraneous language for product code use downstream of an ethanol blending 

facility. 

We also received comment on whether this proposed change was in response to a petition 

for reconsideration from the American Fuel and Petrochemical Manufacturers (AFPM) (formerly 

the National Petroleum Refiners Association, or NPRA), which raised a number of questions 

regarding the E15 MMR PTD requirements.94 Today’s regulatory change only addresses one of 

the questions that AFPM raised regarding the E15 MMR PTD requirements in its petition. 

Today’s action was not meant to address all of the questions raised by AFPM regarding the E15 

MMR PTD requirements. It should be noted that most of the questions raised in AFPM’s 

petition did not require changes to the regulations and were simply questions on the 

implementation and applicability of the E15 MMR requirements. For example, AFPM was 

 

94 See September 15, 2011 letter from AFPM entitled, “Request for Partial Reconsideration of EPA’s “Misfueling 

Rule” 76 Fed. Reg. 44,406 (July 25, 2011),” Docket EPA-HQ-OAR-2012-0401-0041. 
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unclear on what the wintertime PTD requirements for gasoline/blendstocks upstream of an 

ethanol blending facility are under the E15 MMR. These types of questions are typically 

addressed through guidance provided to affected parties (either directly or via guidance letters or 

the Fuels Program Frequent Questions web page) and do not necessitate a change to our 

regulations. However, we may consider further changes to the E15 MMR PTD requirements in a 

future rulemaking that address some or all of the remaining questions raised in AFPM’s petition 

for reconsideration.

We also sought comment on potential ways of streamlining the PTD language required at 

§ 80.1503. We received one comment that suggested substantial changes to the PTD language 

requirements. For example, the commenter suggested removing most of the downstream RVP 

language requirements that were intended to inform retail stations of their summertime RVP 

requirements. The commenter pointed out that such a streamlining of the PTD requirements in 

the E15 MMR would significantly reduce compliance costs for industry. We feel that these 

suggested changes would significantly alter the PTD language in such a way that may no longer 

carry out our intent, which is to inform parties throughout the gasoline distribution chain all the

way down to the retail station of their applicable regulatory requirements. Such changes are 

outside the scope of today’s rulemaking, which includes only a minor technical change to the 

E15 MMR PTD requirements. Therefore, we are not finalizing such changes at this time. 

Although we are not engaging in a substantial streamlining of the PTD language required at § 

80.1503 in today’s action, we may revisit the streamlining of E15 MMR PTD language in a 

future rulemaking.
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D. Changes to Section 80.1504 – Prohibited Acts

In the NPRM, we proposed a slight rewording of § 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, July 25, 2011). 

We received no direct comments on this specific proposed change. We did, however, 

receive comments suggesting that we expand the prohibited activities language in § 80.1504 to 

allow for the better enforcement of ethanol content requirements at blender pumps. The addition 

of new prohibited activities to § 80.1504 is outside the intended scope of today’s action. 

Therefore we are finalizing the slight rewording of the prohibited activities language of §

80.1504(g) as proposed.

E. Changes to Section 80.1500 – Definitions 

In response to the August 17, 2011 petition for reconsideration submitted by NPRA, now 

AFPM, which requested the Agency, under CAA section 307(d)(7)(B), reconsider certain 

portions of the E15 MMR, we granted AFPM’s petition for reconsideration on the issue of the 

definitions of E10 and E15 in the E15 MMR. AFPM expressed concern that the Agency had 

defined E10 and E15 in the E15 MMR in a way that would change how ethanol concentrations 
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are determined for regulatory purposes. While EPA did not intend the definitions of E10 and 

E15 in the E15 MMR to have this effect, we proposed changes to the regulations to avoid this 

perceived impact. Specifically, we proposed to add a new section, § 80.1509, containing

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 § 80.9. We also proposed modifications to language 

throughout 40 CFR part 80, subpart N, to better reflect our intentions in defining E10 and E15 in 

the E15 MMR, including a small revision to § 80.1508.

Comments received on this issue generally supported EPA’s approach to continue to 

allow the rounding of test results to determine whether fuel samples had adhered to applicable 

ethanol content samples under § 80.9. One commenter suggested that EPA remove the 

remaining decimal points to make the point more clearly that rounding applied to the testing of 

fuels samples for ethanol content. Another commenter argued that making such a change would 

allow parties to manufacture gasoline-ethanol blended fuels containing more than 10 volume 

percent ethanol without taking appropriate measures to ensure that vehicles and engines not 

covered by the E15 partial waiver decisions were not misfueled by gasoline-ethanol blended 

fuels containing more than 10 volume percent ethanol. 

We continue to believe that it is necessary to make our intent clear that parties that blend 

gasoline-ethanol blended fuels with more than 10 volume percent ethanol and up to 15 volume 

percent ethanol must adhere to the requirements for such fuels under the E15 MMR. Our 

approach will continue to enforce ethanol content standards as we have in the past, through the 
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appropriate use of rounding procedures specified in the regulations under § 80.9. We do not 

believe we need to remove the decimal points from the proposed regulatory text since we were 

careful to ensure that such language only appeared in places where the blending of gasolineethanol blended fuels containing greater than 10 volume percent ethanol would necessitate 

further action by the party manufacturing such fuel. Therefore, we are finalizing the changes to 

the definitions of the E15 MMR and the new language under § 80.1509 as proposed. 

Additionally, in order to remain consistent with requirements for evidence used to determine 

compliance with requirements in other fuels programs, we are not finalizing the proposed 

changes to § 80.1508.

VI. Amendments to the Ultra Low Sulfur Diesel Survey (ULSD)

In the NPRM, EPA proposed a reduction in the minimum sample size for the ULSD 

survey program from 5,250 annual samples to 1,800 samples.95 We argued that compliance with 

the ULSD sulfur content standard has been extremely high; less than 1% of the samples have 

been in violation in recent years, and the use of the statistical formula in the regulations would 

result in a sampling rate of several hundred samples per quarter for each of the past several years, 

instead of 5,250 samples required annually. The cost difference between taking several hundred 

 

95 The ULSD rule includes a provision that deems branded refiners liable for violations of the ULSD sulfur standard 

that are found at retail outlets displaying the refiner’s brand (40 CFR 80.612). The regulations include defense 

provisions. One element of a branded refiner’s defense to such violations is that it must have a periodic sampling 

and testing program at the retail level (40 CFR 80.613(b) and (d)). The regulations also set forth an alternative 

sampling and testing defense element provision for branded refiners. This alternative defense element provision (40 

CFR 80.613(e)) allows a branded refiner to meet the company-specific downstream periodic sampling and testing 

element of its defense by participating in a survey consortium that pays an independent surveyor to sample diesel 

fuel at retail outlets nationwide. 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 of 5,250 

samples that must be taken in an annual survey cycle regardless of the sample number that would be calculated 

using the regulatory formula.
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samples a quarter versus taking over 5,000 samples annually is significant. For these reasons we 

believed that the high compliance rate and the substantial discrepancy between the sampling rate 

calculated by the formula in the regulations and the minimum sampling size justified our 

proposal of a minimum annual sampling rate of 1,800 samples. 

Public comments received on the proposed reduction in sampling rate were 

overwhelming supportive. Most comments suggested that EPA reduce the minimum sampling 

rate for the ULSD program to the proposed rate of 1,800. However, some commenters suggested 

that we reduce the sample size even further. Consistent with most comments, we are finalizing 

the proposed rate of 1,800 samples per year. Since the program is based on conducting four 

quarterly surveys, only about 450 samples are collected to represent all retail stations offering 

diesel fuel, over 60,000 stations, nationwide each quarter. A further reduction in the sample size 

may compromise the robustness of the survey program’s ability to detect non-compliance, even 

taking into account today’s high compliance rates. Although we acknowledge that a further 

reduction in the sample size could reduce costs even further, there is a point where the number of 

samples per year would be so few that the survey would be meaningless relative to robust 

sampling and testing programs conducted by each refiner individually. We feel that a rate of 

1,800 samples strikes the correct balance of ensuring compliance with ULSD standards 

downstream while controlling costs for branded refiners that choose to utilize the ULSD survey

program as an alternative affirmative defense.

Additionally, one commenter, citing high costs, suggested that we remove the alternative 

affirmative defense altogether. It is important to note that participation in the consortium that 
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conducts the ULSD survey is completely voluntary and the program provides each branded 

refiner an alternative to conducting individual downstream sampling and testing programs. We 

believe that as long as there is continued interested by some branded refiners to take advantage 

of the ULSD survey program alternative affirmative defense, we should maintain the flexibility

to allow those parties the ability to conduct such a survey in lieu of individual downstream 

sampling and testing programs to establish an affirmative defense to potential downstream 

violations. 

Therefore, today we are reducing the minimum annual sampling size for the ULSD 

survey program from 5,250 samples to 1,800 samples. However, we will continue to closely

monitor national ULSD compliance rates and branded refiner interest in maintaining the ULSD 

survey program to determine whether further reduction in sample sizes is necessary.

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.
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B. Paperwork Reduction Act 

The information collection requirements in this rule 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 has been 

assigned EPA ICR number 2469.01. A supporting statement for the ICR has been placed in the 

docket. The information collection is described in the following paragraphs. 

This action contains recordkeeping and reporting that may affect the following parties 

under the RFS 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 information collection. We estimate an annual recordkeeping and reporting burden of 3.1 

hours per respondent. This action contains recordkeeping and reporting that may affect the 

following parties under the E15 regulation: gasoline refiners, gasoline and ethanol importers, 

gasoline and ethanol blenders (including terminals and carriers). We estimate that 2,000 

respondents may be subject to the 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 
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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. When this ICR is 

approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the 

Federal Register to display the OMB control number for the approved information collection 

requirements contained in this final rule.

 

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) 
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a small organization that is any not-for-profit enterprise which is independently owned and 

operated and is not dominant in its field.

After considering the economic impacts of this action on small entities, I certify that this 

action will not have a significant economic impact on a substantial number of small entities. The 

amendments to the RFS provisions in this final rule allow for additional opportunities for parties 

to participate in the RFS program by producing qualifying fuel if they choose to, clarify existing 

provisions, remove the possibility of exemptions for entities that are no longer small entities due 

to growth in their business, or make relatively minor corrections and modifications to these 

regulations. The various changes to the E15 misfueling mitigation regulations are relatively 

minor corrections and should not place any additional burden on small entities. The reduction in 

the required sample size for the voluntary ULSD survey program should reduce the burden of 

any small entity that elects to participate in the ULSD survey program.

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.
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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 fuel, and renewable fuel producers, importers, 

distributors and marketers and makes relatively minor corrections and modifications to the RFS

and diesel regulations.

E. Executive Order 13132 (Federalism)

This action does not have federalism implications. It will not have substantial direct 

effects on the States, on the relationship between the national government and the States, or on 

the distribution of power and responsibilities among the various levels of government, as 

specified in Executive Order 13132. This action only applies to gasoline, diesel, and renewable 

fuel producers, importers, distributors and marketers. 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 

solicited comment on the proposed action from State and local officials. 

F. Executive Order 13175 (Consultation and Coordination with Indian Tribal 

Governments)

This action does not have tribal implications, as specified in Executive Order 13175 (65 

FR 67249, November 9, 2000). It applies to gasoline, diesel fuel, and renewable fuel producers, 

importers, distributors and marketers. This action does not impose any enforceable duties on 
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communities of Indian tribal governments. Tribal governments would be affected only to the 

extent they purchase and use regulated fuels. Although Executive Order 13175 does not apply to 

this action, EPA specifically solicited comment from tribal officials in developing this action.

G. Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks

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-low sulfur diesel. We have concluded that this rule is not likely to 

have any adverse energy effects. In fact, we expect this rule may result in positive effects, 

because many of the changes we are finalizing will facilitate the introduction of new renewable 
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fuels under the RFS 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

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. 

The regulations permit the use of an analytical method certified by a voluntary consensus

standard body in order for certain producers to comply with applicable registration requirements. 

Producers of renewable fuel made from energy cane and producers of renewable fuel made using 

two or more feedstocks converted simultaneously, when at least one of the feedstocks does not 

have a minimum 75% average adjusted cellulosic content, and at least one of which is a pathway

producing RINs with a D code of 3 or a D code of 7 using a process described in § 

80.1426(f)(15)(i)(A) or § 80.1426(f)(15)(i)(B), must obtain data used to calculate the cellulosic 

converted fraction using an analytical method certified by a voluntary consensus standards body 

or using a method that would produce reasonably accurate results as demonstrated through peer 

reviewed references provided to the third party engineer performing the engineering review at 
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registration. The Agency therefore believes this rulemaking is consistent with the requirements 

of the NTTAA. 

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. 

EPA has determined that this rule will not have disproportionately high and adverse 

human health or environmental effects on minority or low-income populations because it does 

not affect the level of protection provided to human health or the environment. These technical 

amendments do not relax the control measures on sources regulated by the RFS regulations and 

therefore will not cause emissions increases from these sources.

K. Congressional Review Act 

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business 

Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take 
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effect, the agency promulgating the rule must submit a rule report, which includes a copy of the 

rule, to each House of the Congress and to the Comptroller General of the United States. EPA 

will submit a report containing this rule and other required information to the U.S. Senate, the 

U.S. House of Representatives, and the Comptroller General of the United States prior to 

publication of the rule in the Federal Register. A Major rule cannot take effect until 60 days after 

it is published in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 

804(2). This rule will be effective [INSERT DATE 30 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER].

L. Clean Air Act Section 307(d)

This rule is subject to Section 307(d) of the CAA. Section 307(d)(7)(B) provides that 

“[o]nly an objection to a rule or procedure which was raised with reasonable specificity during 

the period for public comment (including any public hearing) may be raised during judicial 

review.” This section also provides a mechanism for the EPA to convene a proceeding for 

reconsideration, “[i]f the person raising an objection can demonstrate to the EPA that it was 

impracticable to raise such objection within [the period for public comment] or if the grounds for 

such objection arose after the period for public comment (but within the time specified for 

judicial review) and if such objection is of central relevance to the outcome of the rule.” Any 

person seeking to make such a demonstration to the EPA should submit a Petition for 

Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 

1200 Pennsylvania Ave., NW, Washington, 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 
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Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 

Pennsylvania Ave., NW, Washington, D.C. 20460.

IX. Statutory Provisions and Legal Authority

Statutory authority for this action comes from section 211 of the Clean Air Act, 42 

U.S.C. 7545. Additional support for the procedural and compliance related aspects of this 

proposal, including the recordkeeping requirements, comes from sections 114, 208, and 301(a) of 

the Clean Air Act, 42 U.S.C. sections 7414, 7542, and 7601(a).
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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: _____________________________

____________________________________

Gina McCarthy,

Administrator
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For the reasons set forth in the preamble, title 40, chapter 1 of the Code of Federal Regulations is 

amended as follows:

PART 80 – REGULATION OF FUELS AND FUEL ADDITIVES

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

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

Subpart I—[Amended]

 

2. Section 80.613 is amended by revising the “Where” statement defining the value of “n” 

in paragraph (e)(4)(v)(A) to read as follows:

§ 80.613 What defenses apply to persons deemed liable for a violation of a prohibited 

act under this subpart? 

* * * * *

(e) * * *

(4) * * *

(v) * * *

(A) * * *

Where:

n = minimum number of samples in a year-long survey series. However, in no case shall 

n be larger than 9,600 or smaller than 1,800.

* * * * *

3. Section 80.1401 is amended as follows:

a. By adding the definitions of “Adjusted cellulosic content”, “Agricultural 

digester,” “Nameplate capacity”, “Renewable compressed natural gas”, “Renewable fuel

producer”, and “Renewable liquefied natural gas” in alphabetical order.

b. By revising the definitions of “Biogas”, “Crop residue”, “Energy cane”, 

“Naphtha”, “Renewable biomass”, and “Small refinery” in alphabetical order. 

§ 80.1401 Definitions.

* * * * *

Adjusted cellulosic content means the percent of organic material that is cellulose, 

hemicellulose, and lignin.

* * * * *

Agricultural digester means an anaerobic digester that processes predominantly

cellulosic materials, including animal manure, crop residues, and/or separated yard waste. 

* * * * *
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Biogas means a mixture of hydrocarbons that is a gas at 60 degrees Fahrenheit and 1 

atmosphere of pressure that is produced through the anaerobic digestion of organic matter. 

* * * * *

Crop residue means 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.

* * * * *

Energy cane means a complex hybrid in the Saccharum genus that has been bred to 

maximize cellulosic rather than sugar content. For the purposes of this section:

(1) Energy cane excludes the species Saccharum spontaneum, but includes hybrids 

derived from S. spontaneum that have been developed and publicly released by USDA; and 

(2) Energy cane only includes cultivars that have, on average, at least 75% adjusted 

cellulosic content on a dry mass basis.

* * * * *

Nameplate capacity means the peak design capacity of a facility for the purposes of 

registration of a facility under § 80.1450(b)(1)(v)(C). 

Naphtha means a blendstock or fuel blending component falling within the boiling range 

of gasoline which is composed of only hydrocarbons, is commonly or commercially known as 

naphtha and is used to produce gasoline through blending.

* * * * *

Renewable biomass means each of the following (including any incidental, de minimis 

contaminants that are impractical to remove and are related to customary feedstock production 

and transport):

(1) Planted crops and crop residue harvested from existing agricultural land cleared or 

cultivated prior to December 19, 2007 and that was nonforested and either actively managed or 

fallow on December 19, 2007.

(2) Planted trees and tree residue from a tree plantation located on non-federal land 

(including land belonging to an Indian tribe or an Indian individual that is held in trust by the 

U.S. or subject to a restriction against alienation imposed by the U.S.) that was cleared at any

time prior to December 19, 2007 and actively managed on December 19, 2007.
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(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 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 (CNG) means biogas or biogas-derived pipeline 

quality gas that is compressed for use as transportation fuel and meets the definition of 

renewable fuel.

* * * * *

Renewable liquefied natural gas (LNG) means biogas or biogas-derived pipeline quality

gas that goes through the process of liquefaction in which it is cooled below its boiling point, and 

which meets the definition of renewable fuel. 

* * * * *

Small refinery means a refinery for which the average aggregate daily crude oil 

throughput for calendar year 2006 and subsequent years (as determined by dividing the 

aggregate throughput for the calendar year by the number of days in the calendar year) does not 

exceed 75,000 barrels. 

* * * * *

4. Section 80.1415 is amended by revising paragraphs (b)(5) and (c)(1) to read as follows:

§ 80.1415 How are equivalence values assigned to renewable fuel?

(b) * * *

(5) 77,000 Btu (lower heating value) of compressed natural gas (CNG) or liquefied 

natural gas (LNG) shall represent one gallon of renewable fuel with an equivalence value 

of 1.0.
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* * * * *

(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. 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 80.1416 is amended by revising paragraph (d) to read as follows:

§ 80.1416 Petition process for evaluation of new renewable fuels pathways.

* * * * *

(d) A D code must be approved prior to the generation of RINs for the fuel in 

question. During petition review EPA will evaluate whether a feedstock meets the 75% cellulosic 

content threshold allowing cellulosic RINs to be generated for the entire fuel volume produced. 

The Administrator may ask for additional information to complete this evaluation. 

* * * * *

6. Section 80.1426 is amended as follows:

a. By revising rows K, L, M, N, P, and Q of Table 1 to § 80.1426.

b. By adding a new row T to Table 1 to § 80.1426.

 c. By revising paragraphs (f)(10) and (f)(11).

 d. By adding new paragraphs (f)(15) and (f)(16).

§ 80.1426 How are RINs generated and assigned to batches of renewable fuel by renewable 

fuel producers or importers?

* * * * *

(f) * * *

(1) * * *

Table 1 to § 80.1426—Applicable D Codes for Each Fuel Pathway for Use in Generating 

RINs

Fuel type Feedstock Production process requirements D-Code
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* * * * * * *

K Ethanol Crop residue, slash, 

pre-commercial 

thinning and tree 

residue, switchgrass, 

miscanthus, energy 

cane, Arundo donax,

Pennisetum 

purpureum,

separated yard 

waste, separated 

MSW, cellulosic 

components of 

separated food 

waste; and cellulosic

components of 

annual cover crops, 

Any process that converts cellulosic

biomass to fuel

3

L Cellulosic diesel, jet fuel 

and heating oil

Crop residue, slash, 

pre-commercial 

thinnings and tree 

residue, switchgrass, 

miscanthus, energy 

cane, Arundo donax,

Pennisetum 

purpureum;

separated yard 

waste, separated 

MSW, and cellulosic 

components of 

separated food 

waste; and cellulosic 

components of 

annual cover crops

Any process that converts cellulosic

biomass to fuel

7

M Renewable gasoline and 

renewable gasoline 

blendstock

Crop residue, slash, 

pre-commercial 

thinnings, tree 

residue, separated 

yard waste,

separated MSW,

cellulosic 

components of 

separated food 

waste; and cellulosic 

Catalytic Pyrolysis and Upgrading, 

Gasification and Upgrading, ThermoCatalytic Hydrodeoxygenation and 

Upgrading, Direct Biological Conversion, 

Biological Conversion and Upgrading 

utilizing natural gas, biogas, and/or 

biomass as the only process energy 

sources and that converts cellulosic

biomass to fuel; any process utilizing 

biogas and/or biomass as the only 

3
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components of 

annual cover crops

process energy sources which converts

cellulosic biomass to fuel

N Naphtha Switchgrass, 

miscanthus, energy 

cane, Arundo donax,

and Pennisetum 

purpureum

Gasification and upgrading processes 

that converts cellulosic biomass to fuel

3

* * * * * * *

P Ethanol, renewable diesel, 

jet fuel, heating oil, and 

naphtha

The non-cellulosic 

portions of 

separated food 

waste and noncellulosic 

components of 

annual cover crops

Any 5

Q Renewable Compressed 

Natural Gas, Renewable 

Liquefied Natural Gas, 

Renewable Electricity

Biogas from landfills,

municipal 

wastewater

treatment facility 

digesters, 

agricultural 

digesters, and 

separated MSW 

digesters, and biogas 

from the cellulosic 

components of 

biomass processed in 

other waste 

digesters

Any 3

* * * * * * *

T Renewable Compressed 

Natural Gas, Renewable 

Liquefied Natural Gas, and 

Renewable Electricity

Biogas from waste 

digesters

Any 5

* * * * *
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(10)(i) For purposes of this section, electricity that is only distributed via a closed, private, noncommercial system is considered renewable fuel and the producer may generate RINs if all of 

the following apply:

(A) The electricity is produced from renewable biomass and qualifies for a D code in 

Table 1 to this section or has received approval for use of a D code by the Administrator.

(B) The electricity producer has entered into a written contract for the sale or use of a 

specific quantity of renewable electricity as transportation fuel, or has obtained affidavits from 

all parties selling or using the electricity as transportation fuel.

(C) The electricity is used as a transportation fuel and for no other purposes.

(ii) For purposes of this section, CNG or LNG produced from biogas that is only

distributed via a closed, private, non-commercial system is considered renewable fuel and the 

producer may generate RINs if all of the following apply:

(A) The CNG/LNG 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 CNG/LNG distributor has entered into a written contract for the sale or use of a 

specific quantity of CNG/LNG to be used as for transportation fuel, or obtained affidavits from 

all parties selling or using the CNG/LNG as transportation fuel.

(C) The CNG/LNG is used as a transportation fuel and for no other purposes.

(iii) A producer of 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, electricity that is introduced into a commercial distribution 

system (transmission grid) 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 of this section or has received approval for use of a D code by the Administrator.

(B) The electricity producer has entered into a written contract for the sale or use of a 

specific quantity of renewable electricity with a party that uses electricity taken from a 

commercial distribution system as a transportation fuel, or has obtained affidavits from all parties 

selling or using the electricity taken from a commercial distribution system as a transportation 

fuel; 

(C) The quantity of electricity for which RINs were generated was sold for use as 

transportation fuel and for no other purpose.

(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, CNG or LNG produced from biogas that is introduced 

into a commercial distribution system is considered renewable fuel and the producer may

generate RINs if all the following apply:

(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 CNG/LNG distributor has entered into a written contract for the sale or use of a 

specific quantity of renewable CNG/LNG, taken from a commercial distribution system (e.g., 

physically connected pipeline, barge, truck, rail), for use as a transportation fuel, or has obtained 
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affidavits from all parties selling or using the CNG/LNG taken from a commercial distribution 

system as a transportation fuel;

(C) The quantity of CNG/LNG for which RINs were generated was sold for use as 

transportation fuel and for no other purposes.

(D) The biogas/CNG/LNG was injected into and withdrawn from the same commercial 

distribution system.

(E) The biogas/CNG/LNG that is ultimately withdrawn from the commercial distribution 

system for use as transportation fuel is withdrawn in a manner and at a time consistent with the 

transport of the biogas/CNG/LNG between the injection and withdrawal points.

(F) The volume and heat content of biogas injected into a pipeline and the volume of 

biogas withdrawn to make a transportation fuel are measured by continuous metering.

(iii) The fuel described in paragraphs (f)(11)(i) and (ii) of this section is considered 

produced from renewable biomass if all of the following apply:

(A) The amount of fuel sold for use as transportation fuel corresponds to the amount of 

fuel derived from renewable biomass that the producer contracted to have placed into the 

commercial distribution system.

(B) No other party relied upon the contracted volume of biogas/CNG/LNG 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.

* * * * *

(15) Application of § 80.1426(f)(3)(vi) to producers generating D3 or D7 RINs.

(i) If a producer seeking to generate D code 3 or D code 7 RINs produces a single 

type of renewable fuel using two or more feedstocks converted simultaneously, and at 

least one of the feedstocks does not have a minimum 75% average adjusted cellulosic 

content, one of the following additional requirements apply:

(A)If the producer is using a thermochemical process to convert cellulosic 

biomass into cellulosic biofuel, the producer is subject to additional 

registration requirements under § 80.1450(b)(1)(xii)(A).

(B) If the producer is using any process other than a thermochemical process, 

or is using a combination of processes, the producer is subject to additional 

registration requirements under § 80.1450(b)(1)(xii)(B) and reporting 

requirements under § 80.1451(b)(1)(ii)(U)

(ii) [Reserved]

(16) Renewable fuel produced from crop residue. Producers generating RINs for qualifying 

renewable fuel utilizing crop residue as feedstock under Pathway K or Pathway L must meet all 

of the following conditions (in addition to any other applicable requirements):

(i) Registration requirements under § 80.1450(b)(1)(xiv).

(ii) Reporting requirements under § 80.1451(b)(1)(ii)(V).

(iii)Recordkeeping requirements under § 80.1454 (r).
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7. Section 80.1440 is amended as follows: 

a. By revising the section heading.

b. By revising paragraph (a).

c. By revising paragraph (d).

d. By revising paragraph (e).

§ 80.1440 What are the provisions for blenders who handle and blend less than 250,000 

gallons of renewable fuel per year?

(a) Renewable fuel blenders who handle and blend less than 250,000 gallons of 

renewable fuel per year, and who do not have one or more reported or unreported Renewable

Volume Obligations, are permitted to delegate their RIN-related responsibilities to the party

directly upstream of them who supplied the renewable fuel for blending.

* * * * *

(d) Renewable fuel blenders who handle and blend less than 250,000 gallons of 

renewable fuel per year and delegate their RIN-related responsibilities under paragraph (b) of 

this section must register pursuant to § 80.1450(e), and may not own RINs.

(e) Renewable fuel blenders who handle and blend less than 250,000 gallons of 

renewable fuel per year and who do not opt to delegate their RIN-related responsibilities, or own 

RINs, will be subject to all requirements stated in paragraph (b) of this section, and all other 

applicable requirements of this subpart M.

8. 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.

* * * * *

9. Section 80.1450 is amended as follows:

a. By revising paragraph (b)(1)(ii).

b. By revising paragraphs (b)(1)(v)(C) and (b)(1)(v)(D), and by adding paragraph 

(b)(1)(v)(E).

c. By adding paragraphs (b)(1)(xii) through (xiv).

d. By revising paragraph (d)(2).

e. By amending paragraph (g).

f. By adding paragraph (h) 
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§ 80.1450 What are the registration requirements under the RFS program?

* * * * *

(b) * * *

(1) * * *

(ii) A description of the facility’s renewable fuel or ethanol production processes. 

(A) For registrations indicating production of D code 3 or D code 7 RINs using 

feedstocks listed in rows K, L, M, and N of Table 1 to § 80.1426, the producer 

must demonstrate the ability to convert cellulosic components of feedstock into 

fuel by providing all of the following:

(1) A process diagram with all relevant unit processes labeled and a designation 

of which unit process is capable of performing cellulosic treatment, including 

required inputs and outputs at each step.

(2) A description of the cellulosic biomass treatment process, including required 

inputs and outputs used at each step.

(3) A description of the mechanical, chemical and biochemical mechanisms by

which cellulosic materials can be converted to biofuel products.

(B) [Reserved]

* * * * *

(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 not 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 documents demonstrating the facility’s nameplate 

capacity, as defined in § 80.1401. 

(D) For all facilities producing renewable electricity or fuel from biogas, submit all 

relevant information in § 80.1426(f)(10) or (11), including copies of all contracts or affidavits, as 

applicable, that track the biogas/CNG/LNG 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 CNG/LNG 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. 

* * * * *

(xii) (A) A producer of renewable fuel or a foreign ethanol producer seeking to 

generate D code 3 or D code 7 RINs that produces a single type of renewable fuel 

using two or more feedstocks converted simultaneously, where at least one of the 

feedstocks does not have a minimum 75% average adjusted cellulosic content, 
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and who uses only a thermochemical process to convert feedstock into renewable 

fuel, must provide all the following:

(1) Data showing the average adjusted cellulosic content of the feedstock(s) to be 

used to produce fuel, based on the average of at least three representative samples. 

Cellulosic content data must come from an analytical method certified by a 

voluntary consensus standards body or using a method that would produce 

reasonably accurate results as demonstrated through peer reviewed references 

provided to the third party engineer performing the engineering review at 

registration. Samples must be of representative feedstock from the primary

feedstock supplier that will provide the fuel producer with feedstock subsequent 

to registration. 

(2) Producers that want to change or add new feedstock(s) after initial 

registration, must update their registration and provide EPA with data in 

accordance with paragraph (b)(1)(xii)(A) of this section indicating the average 

adjusted cellulosic content of the new feedstock.

(B) A producer of renewable fuel or a foreign ethanol producer seeking to 

generate D code 3 or D code 7 RINs that produces a single type of renewable fuel 

using two or more feedstocks converted simultaneously, where at least one of the 

feedstocks does not have a minimum 75% adjusted cellulosic content, and who 

uses a process other than a thermochemical process or a combination of processes 

to convert feedstock into renewable fuel, must provide all the following:

(1)The expected overall fuel yield, based on available data, which shall be 

calculated according to the following formula: 

Where:

Y = Overall fuel yield.

VRIN, CB = RIN volume, in gallons, for use in determining the number of 

gallon-RINs that shall be generated for the cellulosic biofuel portion of the 

batch with a D code of 3.

VRIN, BBD = RIN volume, in gallons, for use in determining the number of 

gallon-RINs that shall be generated for the biomass-based diesel portion of the 

batch with a D code of 4.

VRIN, AB = RIN volume, in gallons, for use in determining the number of 

gallon-RINs that shall be generated for the advanced biofuel portion of the 

batch with a D code of 5.

VRIN, RF = RIN volume, in gallons, for use in determining the number of 

gallon-RINs that shall be generated for the renewable fuel portion of the batch 

with a D code of 6.

VRIN, CD = RIN volume, in gallons, for use in determining the number of 

gallon-RINs that shall be generated for the cellulosic diesel portion of the 

batch with a D code of 7.

M = Mass of all feedstock, in pounds, measured on a per-batch basis.
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(2) The cellulosic Converted Fraction (CF) that will be used for generating RINs 

under § 80.1426(f)(3).

(3) Chemical analysis data supporting the calculated cellulosic Converted 

Fraction and a discussion of the possible variability that could be expected 

between reporting periods per § 80.1451(b)(1)(ii)(U)(1). Data used to calculate 

the cellulosic CF must be representative and obtained using an analytical method 

certified by a voluntary consensus standards body, or using a method that would 

produce reasonably accurate results as demonstrated through peer reviewed 

references provided to the third party engineer performing the engineering review 

at registration. 

(4) A description and calculations showing how the data were used to determine 

the cellulosic Converted Fraction. 

(xiii) For a producer of renewable fuel made from energy cane: 

(A) Data showing that the average adjusted cellulosic content of each energy cane 

cultivar they intend to use is at least 75%, based on the average of at least three 

representative samples of each cultivar. Cultivars must be grown under normal 

growing conditions and consistent with acceptable farming practices. Samples 

must be of feedstock from a feedstock supplier that the fuel producer intends to 

use to supply feedstock for their production process and must represent the 

feedstock supplier’s range of growing conditions and locations. Cellulosic content 

data must come from an analytical method certified by a voluntary consensus 

standards body or using a method that would produce reasonably accurate results 

as demonstrated through peer reviewed references provided to the third party

engineer performing the engineering review at registration. 

(B) Producers that want to change or add new energy cane cultivar(s) after initial 

registration must update their registration and provide EPA with data in 

accordance with paragraph (b)(1)(xiii)(A) of this section demonstrating that the 

average adjusted cellulosic content for any new cultivar is at least 75%. Cultivars 

that do not meet this requirement are considered sugarcane for purposes of Table 

1 to § 80.1426.

 

(xiv) For a producer of renewable fuel made from crop residue or a foreign renewable 

fuel producer making ethanol from crop residue and seeking to have it sold as 

renewable fuel, provide all the following information:

(A)A list of all feedstocks the producer intends to utilize as crop residue.

(B) A written justification which explains why each feedstock a producer lists 

according to § 80.1450(b)(1)(xiv)(A) meets the definition of “crop residue” 

per § 80.1401.

* * * * *
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(g) Registration Procedures. (1) Registration shall be on forms, and following policies, 

established by the Administrator.

(2) English language registrations–Any document submitted to EPA under this 

section 80.1450 must be submitted in English, or shall include an English translation.

(h) Inactivation of Company Registration. (1) EPA may inactivate a company’s 

registration, using the process in paragraph (h)(2) of this section, if any of the following criteria 

are met:

(i) The company has reported no activity in EMTS for twenty-four consecutive 

months.

(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 days of the 

required submission date under § 80.1451.

(iv) The attest engagement required under § 80.1454 has not been received within 

thirty days of the required submission date.

(2) EPA will use the following process whenever it decides to inactivate the registration 

of a company:

(i) EPA will provide written notification to the responsible corporate officer identifying 

the reasons or deficiencies of why EPA intends to inactivate the company’s registration. The 

company will have fourteen 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 inactivate registration is the absence of 

EMTS activity, a stated intent to engage in activity reported through EMTS will be sufficient to 

avoid inactivation of registration. 

(iii) If the company does not respond, does not correct identified deficiencies, or does 

not provide an adequate explanation regarding why such correction is not necessary within the 

time allotted for response, EPA may inactivate the company’s registration within further notice 

to the party.

(3) Impact of registration inactivation. 

(i) A company whose registration is inactivated shall still be liable for violation of any

requirements of this subpart. 

(ii) A company whose registration is inactivated will not be listed on any public list of 

actively registered companies that is maintained by EPA. 

(iii) A company whose registration is inactivated 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). 

(iv) A company whose registration is inactivated must submit any corrections of 

deficiencies to EPA on forms, and following policies, established by EPA. 

(v) If a company whose registration has been inactivated wishes to re-register, they may

initiate that process by submitting a new registration, consistent with paragraphs (a) through(c) 

of this section.

10. Section 80.1451 is amended to read as follows:
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a. By revising paragraph (b)(1)(ii)(Q).

b. By redesignating paragraph (b)(1)(ii)(U) as paragraph (b)(1)(ii)(W).

c. By adding a new paragraph (b)(1)(ii)(U).

d. By adding paragraph (b)(1)(ii)(V).

e. By adding paragraph (i).

§ 80.1451 What are the reporting requirements under the RFS program?

* * * * *

(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. 

* * * * *

(U) Producers generating D code 3 or D code 7 RINs using feedstocks listed in rows 

K, L, M, and N of Table 1 to § 80.1426, for fuel produced from two or more feedstocks 

converted simultaneously, at least one of which has less than 75% average adjusted cellulosic 

content, and using a process other than a thermochemical process or a combination of processes 

shall report all of the following: 

(1) The cellulosic converted fraction as determined by collecting new representative 

process data and performing the same chemical analysis method accepted at 

registration. Producers shall calculate this information on an annual basis or 

within 10 business days of generating every 500,000 gallons of cellulosic fuel, 

whichever is more frequent, and report quarterly. Reports shall include all values 

used to calculate feedstock energy according to § 80.1426(f)(3)(vi). If new data 

shows that the cellulosic Converted Fraction is different than previously 

calculated, the formula used to generate RINs at § 80.1426(f)(3) must be updated 

as soon as practical but no later than 5 business days after the producer receives 

the updated data. 

(2) If the cellulosic Converted Fraction deviates from the previously calculated

cellulosic Converted Fraction by 10% or more then the producer must notify EPA 

within 5 business days of receiving the new data and must adjust the formula used 

to generate RINs at § 80.1426(f)(3) for all fuel generated as soon as practical but 

no later than 5 business days after the producer receives the new data. If new 

testing data results in a change to the cellulosic CF, only RINs generated after the 

new testing data were received, subject to the 5-day allowance, would be affected.

(V) Producers of renewable fuel using crop residue as a feedstock shall report all of the 

following according to the schedule specified in paragraph (f)(2) of this section:
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(1) The specific feedstock(s) utilized to produce renewable fuel under a pathway

allowing the use of crop residue as feedstock.

(2) The total quantity of each specific feedstock used to produce renewable fuel.

(3) The total amount of qualifying renewable fuel produced under the crop residue 

pathway(s) in that quarter.

(W) Any additional information the Administrator may require.

* * * * *

(i) English language reports. Any document submitted to EPA under § 80.1451 must be 

submitted in English, or shall include an English translation.

12. Section 80.1454 is amended as follows:

a. By revising paragraph (b)(4)(i).

b. By adding paragraph (b)(9).

c. By revising paragraph (f)(3)(i).

d. By revising paragraph (k)(1).

e. By adding a new paragraph (q).

f. By adding a new paragraph (r).

§ 80.1454 What are the recordkeeping requirements under the RFS program?

* * * * *

(b) * * *

(4) * * *

(i) A list of the RINs owned, purchased, sold, separated, retired, or reinstated.

* * * * *

 (9) 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.

* * * * *

(k)(1) Biogas and electricity in pathways involving feedstocks other than grain sorghum. 

A renewable fuel producer that generates RINs for renewable CNG, renewable LNG or 

renewable electricity pursuant to § 80.1426(f)(10) or (11), or that uses process heat from biogas 

to produce renewable fuel pursuant to § 80.1426(f)(12) shall keep all of the following additional 

records:

(i) Contracts and documents memorializing the sale of renewable CNG, renewable LNG 

or renewable electricity for use as transportation fuel relied upon in § 80.1426(f)(10), §

80.1426(f)(11), or for use of biogas for process heat to make renewable fuel as relied upon in §
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80.1426(f)(12) and the transfer of title of the biogas/CNG/LNG or renewable electricity from the 

point of biogas production to the facility which sells or uses the fuel for transportation purposes.

(ii) Documents demonstrating the volume and energy content of biogas/CNG/LNG, 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.

(iii) Documents demonstrating the volume and energy content of biogas/CNG/LNG, 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 commercial distribution.

(iv) Documents demonstrating the volume and energy content of biogas relied upon 

under § 80.1426(f)(12) at the point of distribution.

(v) Affidavits or data from a real-time electronic monitoring system, confirming that title 

of the biogas/CNG/LNG or renewable electricity relied upon under § 80.1426(f)(10) and (11) 

were used for transportation purposes only, and for no other purpose. The renewable fuel 

producer shall obtain affidavits or monitoring system data under this paragraph (k), at least once 

per calendar quarter. 

(vi) The biogas or renewable electricity producer's Compliance Certification required 

under Title V of the Clean Air Act.

(vii) 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.

(viii) 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.

(r) Producers of renewable fuel using crop residue shall keep records of all of the 

following:

(1) The specific crop residue feedstock(s) utilized to produce renewable fuel for each 

batch of renewable fuel produced.

(2) The total quantity of each specific crop residue feedstock used for each batch.

(3) Total amount of fuel produced under the crop residue pathway for each batch.

13. Section 80.1463 is amended by adding paragraph (d) to read as follows:

§80.1463 What penalties apply under the RFS program? 

* * * * *

(d) Any person liable under § 80.1461(a) for a violation of § 80.1460(b)(1)-(4) or (6) is 

subject to a separate day of violation for each day that an invalid RIN remains available for an 

obligated party or renewable fuel exporter to demonstrate compliance with the RFS program.

Subpart N—ADDITIONAL REQUIREMENTS FOR GASOLINE-ETHANOL BLENDS

15. Section 80.1500 is amended by revising the definitions of “E10”, “E15”, and “EX” to 

read as follows: 
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§ 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. 

* * * * *

16. Section 80.1501 is amended as follows:

a. By revising the section heading.

b. By revising paragraph (a) introductory text.

c. By revising paragraphs (b)(3)(i), (b)(3)(iv), and (b)(4)(ii).

§ 80.1501 What are the labeling requirements that apply to retailers and wholesale 

purchaser-consumers of gasoline-ethanol blends that contain greater than 

10volume 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 paragraph (b)(4)(iii) of this section.

* * * * *

(iv) The words “Use only in” shall be in 20-point, left-justified, black, Helvetica Bold 

font in the bottom 1.875 inches of the label.

(4) * * *

(ii) The background of the bottom 1.875 inches of the label shall be orange.

* * * * *

17. Section 80.1502 is amended as follows:

a. By revising paragraphs (b)(3)(iii)(A), (b)(3)(iv) introductory text, (b)(4)(iv)(B), 

and (b)(4)(v)(A).

b. By revising paragraphs (c)(4) and (c)(6).

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

* * * * *
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(b) * * * 

(3) * * *

(iii) * * * 

(A) Samples collected at retail outlets shall be shipped the same day the samples are 

collected via ground service to the laboratory and analyzed for oxygenate content. 

Samples collected at a dispenser labeled E15 in any manner, or at a tank serving such a 

dispenser, shall also be analyzed for RVP during the high ozone season defined in § 

80.27(a)(2)(ii) or any SIP approved or promulgated under §§ 110 or 172 of the Clean Air 

Act. Such analysis shall be completed within 10 days after receipt of the sample in the 

laboratory. Nothing in this section shall be interpreted to require RVP testing of a sample 

from any dispenser or tank serving it unless the dispenser is labeled E15 in any manner.

* * * * *

(iv) In the case of any test that yields a result that does not match the label 

affixed to the product (e.g., a sample greater than 15 volume percent ethanol dispensed 

from a fuel dispenser labeled as “E15” or a sample containing greater than 10 volume 

percent ethanol and not more than 15 volume percent ethanol dispensed from a fuel 

dispenser not labeled as “E15”), or the RVP standard of § 80.27(a)(2) or any SIP 

approved or promulgated under §§ 110 or 172 of the Clean Air Act, 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) or any SIP approved or promulgated under §§ 110 or 172 of the Clean 

Air Act, 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 = 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.

   n a b n

n  Z  Z (4*[arc sin( )  arc sin( )] )  St  F  F  Su 2

1 0

2

   
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1 = The maximum proportion of non-compliant stations for a region to

be deemed compliant. 

In this test, the parameter needs to be 5% or greater, i.e., 5% or 

more of the stations, within a stratum such that the region is 

considered non-compliant. For this survey, 1 will be 5%.

o = The underlying proportion of non-compliant stations in a sample. 

For the first survey plan, o will be 2.3%. For subsequent survey

plans, o will be the average of the proportion of stations found to 

be non-compliant over the previous four surveys.

Stn = Number of sampling strata. For purposes of this survey program, 

Stn equals 3.

Fa = Adjustment factor for the number of extra samples required to 

compensate for collected samples that cannot be included in the 

survey, based on the number of additional samples required during 

the previous four surveys. However, in no case shall the value of 

Fa be smaller than 1.1. 

Fb = Adjustment factor for the number of samples required to resample 

each retail outlet with test results exceeding the labeled amount 

(e.g., a sample greater than 15 volume percent ethanol dispensed 

from a fuel dispenser labeled as “E15”, a sample with greater than 

10 volume percent ethanol and not more than 15 volume percent 

ethanol dispensed from a fuel dispenser not labeled as “E15”), or a 

sample dispensed from a fuel dispenser labeled as “E15” with 

greater than the applicable seasonal and geographic RVP pursuant 

to § 80.27, based on the rate of resampling required during the 

previous four surveys. However, in no case shall the value of Fb

be smaller than 1.1.

Sun = Number of surveys per year. For purposes of this survey program, 

Sun equals 4.

* * * * *

(c) * * *

(4) The survey program plan must be sent to the following address: Director, 

Compliance Division, U.S. Environmental Protection Agency, 1200 Pennsylvania 

Ave., N.W. Mail Code 6506J, Washington, D.C. 20460.

* * * * *

(6) The approving official for a survey plan under this section is the Director of the 

Compliance Division, Office of Transportation and Air Quality. 

* * * * *

18. Section 80.1503 is amended as follows:

a. By revising paragraphs (a)(1)(vi)(B) and (a)(1)(vi)(C).

b. By revising paragraphs (b)(1)(vi)(B) through (D).

§ 80.1503 What are the product transfer document requirements for gasoline-ethanol 
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blends, gasolines, and conventional blendstocks for oxygenate blending 

subject to this subpart?

(a) * * * 

 (1) * * *

 (vi) * * *

 (B) * * *

(1) “Suitable for the special RVP provisions for ethanol blends that contain 

between 9 and 10 vol % ethanol.”.

(2) “The RVP of this blendstock/gasoline for oxygenate blending does not exceed 

[Fill in appropriate value] psi.”.

(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)(1) For gasoline not described in paragraph (a)(1)(vi)(B) of this section, information 

regarding the suitable ethanol content, stated in the following format: “Suitable 

for blending with ethanol at a concentration of no more than 15 vol % ethanol.”.

 (2) The requirements in paragraph (a)(1) of this section 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 purchaserconsumers, 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.”.

* * * * *

19. Section 80.1504 is amended by revising paragraphs (a)(1), (a)(3), (e), and (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 
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light-duty gasoline motor vehicle, any heavy-duty gasoline motor vehicle or engine, any highway

or off-highway motorcycle, or any gasoline-powered nonroad engines, vehicles or equipment.

* * * * *

(3) Notwithstanding paragraphs (a)(1) and (a)(2) of this section, no person shall be 

prohibited from manufacturing, selling, introducing, or causing or allowing the sale or 

introduction of gasoline containing greater than 10 volume percent ethanol into any flex-fuel 

vehicle. 

* * * * *

(e)(1) Improperly blend, or cause the improper blending of, ethanol into conventional 

blendstock for oxygenate blending, gasoline or gasoline already containing ethanol, in a manner 

inconsistent with the information on the product transfer document under § 80.1503(a)(1)(vi) or 

§ 80.1503(b)(1)(vi).

(2) No person shall produce a fuel designated as 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 a fuel designated as 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.

* * * * *

(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. A new section 80.1509 is added to subpart N to read as follows:

§ 80.1509 Rounding a test result for purposes of this subpart N.

The provisions of § 80.9 apply for purposes of determining the ethanol content of 

a gasoline-ethanol blend under this subpart.