Vol. 78 Friday, 

No. 115 June 14, 2013 

Part II 

Environmental Protection Agency 

40 CFR Part 80 

Regulation of Fuels and Fuel Additives: RFS Pathways II and Technical 

Amendments to the RFS 2 Standards; Proposed Rule 

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36042 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 80 

[EPA–HQ–OAR–2012–0401; FRL–9816–3] 

RIN 2060—AR21 

Regulation of Fuels and Fuel 

Additives: RFS Pathways II and 

Technical Amendments to the RFS 2 

Standards 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: In this Notice of Proposed 

Rulemaking, EPA is proposing 

amendments to three separate sets of 

regulations relating to fuels. First, EPA 

is proposing to amend certain of the 

renewable fuels standard (RFS2) 

program regulations. We believe these 

proposals will facilitate the introduction 

of new renewable fuels as well as 

improve implementation of the 

program. This proposal includes various 

changes related to biogas, including 

changes related to the revised 

compressed natural gas (CNG)/liquefied 

natural gas (LNG) pathway and 

amendments to various associated 

registration, recordkeeping, and 

reporting provisions. This proposed 

regulation includes the addition of new 

pathways for renewable diesel, 

renewable naphtha, and renewable 

electricity (used in electric vehicles) 

produced from landfill biogas. Adding 

these new pathways will enhance the 

ability of the biofuels industry to supply 

advanced biofuels, including cellulosic 

biofuels, which greatly reduce the 

greenhouse gas emissions (GHG) 

compared to the petroleum-based fuels 

they replace. It also addresses 

‘‘nameplate capacity’’ issues for certain 

production facilities that do not claim 

exemption from the 20% greenhouse gas 

(GHG) reduction threshold. In this 

notice, EPA addresses issues related to 

crop residue and corn kernel fiber and 

proposes an approach to determining 

the volume of cellulosic RINs produced 

from various cellulosic feedstocks. We 

also include a lifecycle analysis of 

advanced butanol and discuss the 

potential to allow for commingling of 

compliant products at the retail facility 

level as long as the environmental 

performance of the fuels would not be 

detrimental. Several other amendments 

to the RFS2 program are included. 

Second, EPA is also proposing various 

changes to the E15 misfueling 

mitigation regulations (E15 MMR). 

Among the E15 changes proposed are 

technical corrections and amendments 

to sections dealing with labeling, E15 

surveys, product transfer documents, 

and prohibited acts. We also propose to 

amend the definitions in order to 

address a concern about the rounding of 

test results for ethanol content 

violations. 

Lastly, EPA is proposing changes to 

the survey requirements associated with 

the ultra-low sulfur diesel (ULSD) 

program. 

DATES: Comments must be received on 

or before July 15, 2013. We do not 

expect a request for a public hearing. 

However, if we receive a request for a 

public hearing by July 1, 2013 we will 

publish information related to the 

timing and location of the hearing and 

the timing of a new deadline for public 

comments. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2012–0401, by one of the 

following methods: 

• http://www.regulations.gov. Follow 

the on-line instructions for submitting 

comments. 

• Email: a-and-r-docket@epa.gov, 

Attention Air and Radiation Docket ID 

No. EPA–HQ–OAR–2012–0401. 

• Mail: Air and Radiation Docket, 

Docket No. EPA–HQ–OAR–2012–0401, 

Environmental Protection Agency, Mail 

code: 6406J, 1200 Pennsylvania Ave. 

NW., Washington, DC 20460. Please 

include a total of two (2) copies. 

• Hand Delivery: EPA Docket Center, 

EPA/DC, EPA West, Room 3334, 1301 

Constitution Ave. NW., Washington, DC 

20460, Attention Air and Radiation 

Docket, ID No. EPA–HQ–OAR–2012– 

0401. Such deliveries are only accepted 

during the Docket’s normal hours of 

operation, and special arrangements 

should be made for deliveries of boxed 

information. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2012– 

0401. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through www.regulations.gov 

or email. The www.regulations.gov Web 

site is an ‘‘anonymous access’’ system, 

which means EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to EPA without going 

through www.regulations.gov, your 

email address will be automatically 

captured and included as part of the 

comment that is placed in the public 

docket and made available on the 

Internet. If you submit an electronic 

comment, EPA recommends that you 

include your name and other contact 

information in the body of your 

comment and with any disk or CD–ROM 

you submit. If EPA cannot read your 

comment due to technical difficulties 

and cannot contact you for clarification, 

EPA may not be able to consider your 

comment. Electronic files should avoid 

the use of special characters, any form 

of encryption, and be free of any defects 

or viruses. For additional information 

about EPA’s public docket visit the EPA 

Docket Center homepage at http:// 

www.epa.gov/epahome/dockets.htm. 

Docket: All documents in the docket 

are listed in the www.regulations.gov 

index. Although listed in the index, 

some information is not publicly 

available, e.g., CBI or other information 

for which disclosure is restricted by 

statute. Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

either electronically in 

www.regulations.gov or in hard copy at 

the Air and Radiation Docket, EPA/DC, 

EPA West, Room 3334, 1301 

Constitution Ave. NW., Washington, 

DC. The Public Reading Room is open 

from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding legal 

holidays. The telephone number for the 

Public Reading Room is (202) 566–1744, 

and the telephone number for the Air 

and Radiation Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: 

Joseph Sopata, Chemist, Office of 

Transportation and Air Quality, Mail 

Code: 6406J, U.S. Environmental 

Protection Agency, 1200 Pennsylvania 

Avenue NW., 20460; telephone number: 

(202) 343–9034; fax number: (202) 343– 

2801; email address: 

sopata.joe@epa.gov. 

SUPPLEMENTARY INFORMATION: This 

preamble follows the following outline: 

I. Why is EPA taking this action? 

II. Does this action apply to me? 

III. What should I consider as I prepare my 

comments for EPA? 

IV. Executive Summary 

V. Renewable Fuel Standard (RFS2) Program 

Amendments 

A. Approving Cellulosic Volumes From 

Cellulosic Feedstocks 

1. Variability in Cellulosic Content 

Estimates of Feedstocks 

2. Characteristics of the Amount of the 

Final Fuel Derived From Cellulosic 

Materials 

3. Previous Precedents 

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4. Alternative Approaches 

B. Lifecycle Greenhouse Gas Emissions 

Analysis for Renewable Electricity, 

Renewable Diesel and Naphtha Produced 

From Landfill Biogas 

1. Feedstock Production 

2. Determination of the Cellulosic 

Composition of Landfill Biogas 

3. Fuel Production—General 

Considerations 

4. Fuel Production for Renewable 

Electricity 

5. Fuel Production, Transport and Tailpipe 

Emissions for Renewable Diesel and 

Naphtha 

C. Proposed Regulatory Amendments 

Related to Biogas 

1. Changes Applicable to the Revised CNG/ 

LNG Pathway From Biogas 

2. New Registration (Contract 

Requirements) for Renewable Electricity 

and Fuels Produced From Biogas That 

Qualify as Renewable Fuel and That are 

Registered for RIN Generation 

3. Changes Applicable to all Biogas Related 

Pathways for RIN Generation 

4. Changes Applicable To Process 

Electricity Production Requirement for 

the Biogas-Derived Cellulosic Diesel and 

Naphtha Pathways 

D. Amendment to the Definition of ‘‘Crop 

Residue’’ and Definition of a Pathway for 

Corn Kernel Fiber 

E. Consideration of Advanced Butanol 

Pathway 

1. Proposed New Pathway 

2. Butanol, Biobutanol, and Volatility 

Considerations 

F. Amendments to Various RFS2 

Compliance Related Provisions 

1. Proposed Changes to Definitions 

2. Provisions for Small Blenders of 

Renewable Fuels 

3. Proposed Changes to Section 80.1450— 

Registration Requirements 

4. Proposed Changes to Section 80.1452— 

EPA Moderated Transaction System 

(EMTS) Requirements—Alternative 

Reporting Method for Sell and Buy 

Transactions for Assigned RINs 

5. Proposed Changes to Section 80.1463— 

Confirm That Each Day an Invalid RIN 

Remains in the Market is a Separate Day 

of Violation 

6. Proposed Changes to Section 80.1466— 

Require Foreign Ethanol Producers, 

Importers and Foreign Renewable Fuel 

Producers That Sell to Importers to be 

Subject to U.S. Jurisdiction and Post a 

Bond 

7. Proposed Changes to Section 

80.1466(h)—Calculation of Bond 

Amount for Foreign Renewable Fuel 

Producers, Foreign Ethanol Producers 

and Importers 

8. Proposed Changes to Facility’s Baseline 

Volume To Allow ‘‘Nameplate Capacity’’ 

for Facilities not Claiming Exemption 

From the 20% GHG Reduction 

Threshold 

G. Minor Corrections to RFS2 Provisions 

VI. Amendments to the E15 Misfueling 

Mitigation Rule 

A. Proposed Changes to Section 80.1501— 

Label 

B. Proposed Changes to Section 80.1502— 

E15 Survey 

C. Proposed Changes to Section 80.1503— 

Product Transfer Documents 

D. Proposed Changes to Section 80.1504— 

Prohibited Acts 

E. Proposed Changes to Section 80.1500— 

Definitions 

VII. Proposed Amendments to the ULSD 

Diesel Survey 

VIII. Statutory and Executive Order Reviews 

I. Why is EPA taking this action? 

EPA is taking this action to amend 

various provisions in its regulations 

pertaining to fuels and fuel additives. 

First, EPA is proposing to amend 40 

CFR part 80, subpart M related to the 

renewable fuels standard (RFS2). The 

RFS2 program was required by the 

Energy Independence and Security Act 

of 2007 (EISA 2007), which amended 

the Clean Air Act (CAA). The final 

regulations for RFS2 were published in 

the Federal Register on March 26, 2010 

(75 FR 14670). In this notice, references 

to the ‘‘RFS2 final rule’’ refer to the 

March 26, 2010 Federal Register notice 

unless otherwise noted. Second, EPA is 

proposing to amend provisions of 40 

CFR part 80, subpart N, related to 

misfueling mitigation for 15 volume 

percent (%) ethanol blends (E15). The 

final regulations for E15 were published 

in the Federal Register on July 25, 2011 

(76 FR 44422). Several items in this 

proposed action will assist regulated 

parties in complying with RFS2 and E15 

requirements. This action is not 

expected to result in significant changes 

in regulatory burdens or costs associated 

with the RFS2 and E15 programs. Third, 

EPA is proposing a change to the ultra 

low sulfur diesel (ULSD) program of 40 

CFR part 80, subpart I. Specifically, EPA 

is proposing an amendment to the 

survey provisions that would likely 

result in decreasing the number of 

samples that must be taken, and as such 

would be expected to result in a 

decrease in regulatory burdens or costs. 

II. Does this action apply to me? 

Entities potentially affected by this 

action include those involved with the 

production, distribution and sale of 

transportation fuels, including gasoline 

and diesel fuel, or renewable fuels such 

as ethanol and biodiesel. Regulated 

categories and entities affected by this 

action include: 

Category NAICS 

Codes a SIC Codes b Examples of potentially regulated parties 

Industry ............................................................. 324110 2911 Petroleum refiners, importers. 

Industry ............................................................. 325193 2869 Ethyl alcohol manufacturers. 

Industry ............................................................. 325199 2869 Other basic organic chemical manufacturers. 

Industry ............................................................. 424690 5169 Chemical and allied products merchant wholesalers. 

Industry ............................................................. 424710 5171 Petroleum bulk stations and terminals. 

Industry ............................................................. 424720 5172 Petroleum and petroleum products merchant wholesalers. 

Industry ............................................................. 454319 5989 Other fuel dealers. 

a North American Industry Classification System (NAICS). 

bStandard Industrial Classification (SIC) system code. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this action. This table lists 

the types of entities that EPA is now 

aware could be potentially regulated by 

this action. Other types of entities not 

listed in the table could also be 

regulated. To determine whether your 

entity is regulated by this action, you 

should carefully examine the 

applicability criteria of Part 80, subparts 

I, M and N of Title 40 of the Code of 

Federal Regulations. If you have any 

question regarding applicability of this 

action to a particular entity, consult the 

person in the preceding FOR FURTHER

INFORMATION CONTACT section above. 

III. What should I consider as I prepare 

my comments for EPA? 

A. Submitting CBI. Do not submit this 

information to EPA through 

www.regulations.gov or email. Clearly 

mark the part or all of the information 

that you claim to be CBI. For CBI 

information in a disk or CD–ROM that 

you mail to EPA, mark the outside of the 

disk or CD–ROM as CBI and then 

identify electronically within the disk or 

CD–ROM the specific information that 

is claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

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36044 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. 

B. Tips for Preparing Your Comments. 

When submitting comments, remember 

to: 

• Identify the rulemaking by docket 

number and other identifying 

information (subject heading, Federal 

Register date and page number). 

• Follow directions—The agency may 

ask you to respond to specific questions 

or organize comments by referencing a 

Code of Federal Regulations (CFR) part 

or section number. 

• Explain why you agree or disagree; 

suggest alternatives and substitute 

language for your requested changes. 

• Describe any assumptions and 

provide any technical information and/ 

or data that you used. 

• If you estimate potential costs or 

burdens, explain how you arrived at 

your estimate in sufficient detail to 

allow for it to be reproduced. 

• Provide specific examples to 

illustrate your concerns, and suggest 

alternatives. 

• Explain your views as clearly as 

possible, avoiding the use of profanity 

or personal threats. 

• Make sure to submit your 

comments by the comment period 

deadline identified. 

C. Docket Copying Costs. You may be 

charged a reasonable fee for 

photocopying docket materials, as 

provided in 40 CFR part 2. 

IV. Executive Summary 

EPA is proposing amendments to 

three sets of regulations. First, EPA is 

proposing to amend certain of the 

renewable fuels standard (RFS2) 

program regulations at 40 CFR part 80, 

Subpart M. Section V of this preamble 

includes several proposed amendments 

to the RFS2 regulations of 40 CFR part 

80. The final regulations for RFS2 were 

published in the Federal Register on 

March 25, 2010 (75 FR 14670). EPA has 

issued technical corrections in the past. 

We have identified several additional 

changes. Some of the proposed changes 

in this notice are of a substantive nature; 

others are more in the nature of 

technical corrections, including 

corrections of obvious omissions and 

errors in citation. Among the more 

substantive modifications are various 

proposed changes related to biogas, 

including changes related to the revised 

compressed natural gas (CNG)/liquefied 

natural gas (LNG) pathway and 

amendments to various associated 

registration, recordkeeping, and 

reporting provisions. These fuels have 

the potential to add notable volumes of 

advanced biofuel including cellulosic 

biofuel to the existing renewable fuel 

volumes already being produced. Many 

of these changes are being proposed in 

order to facilitate the introduction of 

new renewable fuels under the RFS2 

program and have come at the 

suggestion of industry stakeholders. 

This preamble includes the addition 

of new pathways for renewable diesel, 

and renewable naphtha, and renewable 

electricity (used in electric vehicles) 

produced from landfill biogas. It 

includes a proposal to address 

‘‘nameplate capacity’’ issues for certain 

production facilities that do not claim 

exemption from the 20% greenhouse gas 

(GHG) reduction threshold. EPA 

proposes to address issues related to 

crop residue and corn kernel fiber. We 

propose an approach for approving the 

cellulosic volumes from cellulosic 

feedstocks. We include a lifecycle 

analysis of advanced butanol and 

discuss the potential to allow for 

commingling of compliant products at 

the retail facility level as long as the 

environmental performance of the fuels 

would not be detrimental when 

compared to existing practices. We 

specifically discuss this consideration 

for commingling in regards to the 

volatility associated with butanol 

gasoline and ethanol gasoline blends. 

We state when and how EPA may 

cancel a company registration. Of a 

more minor scope, this preamble 

includes proposed amendments that 

would define terminology used for 

registration and reporting purposes and 

propose changes to registration and 

reporting requirements. This preamble 

also discusses some minor corrections, 

including adding language to 

registration, recordkeeping and 

reporting sections requiring English 

language translation of documents. We 

have also proposed to correct obvious 

omissions and errors in citation in the 

existing RFS2 regulation. 

Second, EPA is also proposing various 

changes to the E15 misfueling 

mitigation regulations (E15 MMR) at 40 

CFR part 80, subpart N. The final E15 

MMR was published in the Federal 

Register on July 25, 2011 (76 FR 44406). 

Among the E15 changes proposed are 

technical corrections and amendments 

to sections dealing with labeling, E15 

surveys, product transfer documents, 

and prohibited acts. We also propose to 

amend the definitions in order to 

address a concern about the rounding of 

Reid Vapor Pressure (RVP) test results, 

in response to a question raised by some 

industry stakeholders. 

Third, in response to questions 

received from regulated parties, we 

propose to amend the ultra low sulfur 

diesel (ULSD) survey provisions in a 

manner that will likely reduce the 

number of samples required. This may 

mean a reduction in costs and burdens 

associated with compliance for 

regulated parties, with no expected 

degradation in the highly successful 

environmental performance of the 

program. 

V. Renewable Fuel Standard (RFS2) 

Program Amendments 

The RFS2 program was required by 

the Energy Independence and Security 

Act of 2007 (EISA 2007), which 

amended the Clean Air Act (CAA). The 

final regulations for RFS2 were 

published in the Federal Register on 

March 26, 2010 (75 FR 14670). The rule 

took effect on July 1, 2010. In this 

notice, we are proposing several new 

renewable fuel pathway options for 

advanced biofuels including new 

cellulosic biofuel pathways. This 

proposed regulation would also provide 

modifications and technical 

amendments to the existing RFS2 

program. 

A. Approving Cellulosic Volumes From 

Cellulosic Feedstocks 

Since the inception of the RFS 

program, EPA has qualified several fuel 

pathways that are able to generate 

cellulosic biofuel RINs (D codes 3 and 

7). See 40 CFR 80.1426. Each of the 

qualified cellulosic feedstocks listed in 

section 80.1426 contain other 

components such as starches, sugars, 

lipids, and proteins. To date, EPA has 

not provided detailed information on 

how other components should be 

treated. This has led to uncertainty 

amongst renewable fuel producers about 

whether their entire volume of fuel 

produced from a cellulosic feedstock 

would be eligible to generate cellulosic 

RINs. In this rulemaking, EPA proposes 

to allow 100% of the volume of 

renewable fuel produced from certain 

specified, currently approved cellulosic 

feedstocks to generate cellulosic (D–3 or 

D–7) RINs. We also take comment on 

two alternative approaches for how to 

treat non-cellulosic components of 

cellulosic feedstocks. 

For purposes of the RFS program, 

cellulosic biofuel is defined as 

‘‘renewable fuel derived from any 

cellulose, hemicellulose, or lignin that 

is derived from renewable biomass and 

that has lifecycle greenhouse gas 

emissions, as determined by the 

Administrator, that are at least 60 

percent less than the baseline lifecycle 

greenhouse gas emissions.’’ This 

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Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 36045 

1See Memorandum to Docket, ‘‘Cellulosic 

Content of Various Feedstocks,’’ Docket EPA–HQ– 

OAR–2012–0401. 

2Peplinski et al. (1992) Physical, chemical and 

dry-mill properties of corn of varying density and 

breakage susceptibility. Cereal Chemistry, 69(4), 

397–400. 

3 Illinois Soybean Association. Facts and 

Statistics for the Illinois Soybean Industry. http:// 

www.ilsoy.org/_data/mediaCenter/files/1290.pdf. 

4 Values have been adjusted to account for the 

presence of inorganic ash, which will not produce 

fuel, as described in the Memorandum to the 

Docket, ‘‘Cellulosic Content of Various Feedstocks,’’ 

Docket EPA–HQ–OAR–2012–0401. 

5See, e.g., the Standard Biomass Analytical 

Procedures developed by the National Renewable 

Energy Laboratory, http://www.nrel.gov/biomass/

analytical_procedures.html. 

6Compositional Analysis of Lignocellulosic 

Feedstocks. 2. Method Uncertainties, David W. 

Templeton, Christopher J. Scarlata, Justin B. Sluiter, 

And Edward J. Wolfrum, J. Agric. Food Chem. 2010, 

58, 9054–9062 

7Relative standard deviations (RSD) of 5–8% are 

reported for cellulose, hemicelluloses and lignin 

with the other minor components showing 16–22% 

RSD. 

8Composition of Herbaceous Biomass Feedstocks, 

DoKyoung Lee, Vance N. Owens, Arvid Boe, Peter 

Jeranyama, Plant Science Department, South Dakota 

State University, SGINC1–07, June 2007. 

9EPA only considered the organic components of 

the materials when determining cellulosic content. 

Inorganic materials are not likely to end up in the 

final fuel product and would not contribute to the 

fuel heating content in the event that they remained 

in the final fuel. This methodology is consistent 

with how RINs are determined. In this section, EPA 

refers to this as ‘‘adjusted cellulosic.’’ Adjusted 

cellulosic content does not consider other material 

that is not converted into biofuel such as minerals 

or other components that would show up as part 

of the ash remaining after a thermo-chemical 

conversion process. 

10See Memorandum to Docket, ‘‘Cellulosic 

Content of Various Feedstocks,’’ Docket EPA–HQ– 

OAR–2012–0401. 

definition was added in Section 

211(o)(1)(E) by the Energy 

Independence and Security Act (EISA) 

of 2007, where Congress specified four 

different categories of renewable fuel 

and their associated volume 

requirements. The threshold for 

reduction in greenhouse gases is set at 

a higher percentage for cellulosic 

biofuel than the reduction for the other 

categories of renewable fuels. While the 

volume requirements for cellulosic 

biofuel start at a relatively low volume, 

Congress specified large volume 

increases over time such that the main 

growth in the use of renewable fuels 

comes from cellulosic biofuels. This 

reflects a strong Congressional intention 

to promote the use of cellulosic biofuel 

and achieve the associated greenhouse 

gas emissions reductions. 

However, no plant matter can ever 

consist entirely of cellulose, 

hemicellulose and lignin. Plants require 

proteins, DNA, carbohydrates and many 

other types of compounds in order to 

grow and function. Even feedstocks 

such as switchgrass, corn stover, and 

woody materials which are the most 

commonly cited ‘‘cellulosic’’ feedstocks, 

contain measurable proportions of other 

types of organic molecules. However, 

these ‘‘cellulosic’’ feedstocks contain 

much more cellulose, hemicellulose and 

lignin than do other types of biomass. 

As shown in Table V.A.–1, most 

‘‘cellulosic’’ feedstocks consist of 

approximately 80–95% cellulose, 

hemicellulose, or lignin.1 In contrast, 

corn kernels contain roughly 75% starch 

and less than 10% fiber (which includes 

the cellulosic components, as well as 

other materials),2 and soybeans are 

roughly 60% oil and protein and only 

about 15% fiber.3

TABLE V.A.–1—AVERAGE CELLULOSIC

COMPOSITION OF DIFFERENT TYPES

OF FEEDSTOCKS4

Feedstock type 

Average 

adjusted cellulosic 

composition 

(percent) 

Crop Residue .................. 90 

TABLE V.A.–1—AVERAGE CELLULOSIC

COMPOSITION OF DIFFERENT TYPES

OF FEEDSTOCKS4—Continued 

Feedstock type 

Average 

adjusted cellulosic 

composition 

(percent) 

Switchgrass .................... 85 

Miscanthus ...................... 85 

Other Grasses ................ 81 

Wood and Branches ....... 92 

EPA is proposing to allow 100% of 

the volume of renewable fuel produced 

from specific cellulosic feedstock 

sources found in Table 1 of section 

80.1426 to generate D–3 or D–7 RINs 

(depending on the type of finished fuel). 

However separated food waste, 

separated yard waste, and separated 

MSW would continue to be treated as 

before, as discussed below. There are 

three major justifications for this 

determination: (1) There can be 

significant variation in the amount of 

cellulosic content in any feedstock, 

which varies within a growing season, 

across samples, and across sites. 

Attempting to account for this 

variability would impose a significant 

administrative burden on producers and 

EPA; (2) The amount of the final fuel 

that is produced from the cellulosic 

portion of the feedstock is likely to be 

very high, particularly for fuels 

produced using a biochemical reaction; 

(3) EPA has already made previous 

determinations in which a single RIN 

value was assigned to the fuel produced 

since it came primarily from one source 

even though it was also produced from 

incidental amounts of other sources. 

This determination is based on the 

view that the statutory requirement does 

not mandate that in all cases the 

renewable fuel must be produced solely 

from the cellulosic material in the 

renewable biomass. EPA considers the 

statutory definition of cellulosic biofuel 

to be flexible on this point. Given these 

factors cited above, the Agency believes 

this interpretation of ‘‘derived from’’ is 

consistent with the Congressional intent 

to require increased use of cellulosic 

biofuels while ensuring that the 

program can be implemented in a 

reasonable way. Details on the 

variability in feedstocks, characteristics 

of the final fuel, previous precedents, 

and alternative proposals are included 

in the following sections. 

1. Variability in Cellulosic Content 

Estimates of Feedstocks 

The cellulosic components of 

feedstock consist of the major structural 

components; cellulose; hemicellulose; 

and lignin. EPA has reviewed research 

characterizing the different components 

of feedstocks, mainly focused on how 

the materials could be broken down and 

converted into fuel. There has been 

work also in defining standardized 

procedures and test methods for 

analyzing the different components of 

biomass; 5 however, the studies 

considered all employ slightly different 

methods. For the purposes of this rule, 

EPA considered the amount of the 

feedstocks that is composed of 

cellulosic components i.e., how much 

comes from the cellulose, hemicellulose 

or lignin, as opposed to any other 

components of the feedstock. There is 

significant variation in the data reported 

on feedstock component compositions. 

The variation is due to a number of 

causes, such as measurement 

methods,6 7 variety within a generic 

feedstock type, and storage time.8

Although there are many factors that 

contribute to the large variability in 

assessments of cellulosic content, all 

studies confirm that the feedstocks in 

Table 1 of section 80.1426 have an 

adjusted cellulosic content of at least 

70%, with an average content of around 

85% cellulosic.9 A memorandum to the 

docket provides more information on 

cellulosic terminology, percent 

composition of various feedstocks, and 

the variability of different feedstock 

components.10 From this data, EPA 

concludes that each of the qualified 

feedstocks listed in section 80.1426 are 

comprised predominantly of cellulose, 

hemicellulose and lignin. 

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36046 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

11 75 FR 14670, 14706 (March 26, 2010). 12 75 FR at 14706. 

2. Characteristics of the Amount of the 

Final Fuel Derived From Cellulosic 

Materials 

Process technology plays a key role in 

how much of the final fuel product is 

actually produced from cellulose, 

hemicellulose, or lignin. There are two 

basic processes for converting cellulosic 

feedstocks into fuel: thermo-chemical 

and biochemical. Thermo-chemical 

processes mainly consist of pyrolysis— 

in which cellulosic biomass is 

decomposed with temperature to biooils and could be further processed to 

produce a finished fuel—and 

gasification—in which cellulosic 

biomass is decomposed to synthesis gas 

(‘‘syngas’’) with further catalytic 

processing to produce a finished fuel 

product. The biochemical process 

requires the release of sugars from 

biomass and the use of microorganisms 

to convert sugars into fuels. Thermochemical processes can accept a more 

heterogeneous mix of feedstock and 

typically convert all of the organic 

components of the feedstock into 

finished fuel. The biochemical process 

generally accepts a more homogeneous 

mix of feedstocks and typically converts 

only the cellulosic and hemicellulosic 

components of the feedstock into the 

final fuel product. Therefore, regardless 

of the feedstock used, the final fuel 

produced from the biochemical process 

will typically only come from the 

cellulosic or hemicellulosic portions of 

feedstock, while the final fuel produced 

from the thermo-chemical process could 

come from cellulosic and non-cellulosic 

components. 

For thermo-chemical production in 

which the non-cellulosic components of 

the feedstock can contribute to the 

volume of fuel produced in addition to 

the cellulosic components, the percent 

of fuel produced from the non-cellulosic 

portion can vary due to such factors as 

feedstock type and the time and location 

of feedstock harvest. Regardless, we 

believe that the majority of the fuel 

produced will be from the cellulosic 

components. As a practical matter, there 

is no simple test that can be used to 

measure the amount of fuel end product 

that originated from cellulosic materials. 

For fuel produced via the biochemical 

process, 100% of the fuel produced is 

directly the result of conversion of the 

cellulosic content. 

In selecting a cellulosic process, 

whether based on biochemical or 

thermo-chemical design, the fuel 

producer is clearly demonstrating that 

its primary intent is to convert the 

cellulosic portions of the feedstock. 

Cellulosic fuel producers invest in 

expensive process technologies with the 

intent of converting the cellulosic 

components of a feedstock into fuel; 

conversion of the non-cellulosic 

components can be achieved much 

more easily with less of a capital 

investment. Furthermore, since the fuel 

produced will be primarily the result of 

the direct conversion of cellulosic 

content of the feedstock and considering 

the relatively small range of noncellulosic portion of feedstock that 

could contribute to the volume of fuel 

produced, EPA believes it is reasonable 

to consider all the fuel produced when 

relying on cellulosic conversion 

processes to be cellulosic biofuel. 

3. Previous Precedents 

EPA has already considered instances 

where one RIN value was assigned to 

the fuel produced since it came 

primarily from one source even though 

it was also produced from some amount 

of other chemical compounds. In the 

March 2010 RFS rulemaking, EPA 

discussed two different situations for 

fuel produced from separated yard 

waste and food waste as the renewable 

biomass feedstock. The first involved 

food waste or yard waste that was kept 

separate, from generation, from 

municipal solid waste (MSW). EPA 

determined that both of these feedstocks 

could be considered renewable biomass. 

With respect to separated yard waste, 

EPA determined that the yard waste was 

expected to be composed almost 

entirely of woody material or leaves, 

and this would be deemed to be 

cellulosic material and would generate 

cellulosic biofuel RINs. Separated food 

waste, however, was likely to be 

composed of both cellulosic and noncellulosic materials, and in certain cases 

would likely be composed primarily of 

non-cellulosic materials, such as sugars 

and starches from the food. EPA 

determined that separated food waste 

would be deemed to be non-cellulosic 

material, and would generate advanced 

biofuel RINs and not cellulosic RINs, 

unless the renewable fuel producer 

demonstrated the part of the food waste 

that was cellulosic. This portion would 

then generate cellulosic RINs.11

The second situation EPA previously 

addressed involved separated MSW. 

EPA determined that separated MSW 

that met certain regulatory requirements 

would qualify as a renewable biomass 

for purposes of producing renewable 

fuel. EPA recognized that the biogenic 

portion of this feedstock would be 

composed of a ‘‘variety of materials, 

including yard waste (largely cellulosic) 

and food waste (largely starches and 

sugar), as well as incidental materials 

remaining after reasonably practicable 

separation efforts such as plastic and 

rubber of fossil origin.’’ Testing could 

identify the portion of the fuel produced 

from biogenic materials, and these 

biogenic materials ‘‘will likely be largely 

derived from cellulosic materials (yard 

waste, textiles, paper, and construction 

materials), and to a much smaller extent 

starch-based materials (food wastes).’’ 

However, EPA was not aware of a test 

method to distinguish between 

renewable fuel produced from the 

cellulose and fuel produced from the 

starch and under those circumstances 

determined that it was appropriate to 

base the assignment of RINs on the 

‘‘predominant’’ component of the 

biogenic material. EPA thus determined 

that all of the fuel generated from the 

biogenic portion of separated MSW 

would be considered cellulosic 

biofuel.12

Thus, EPA has interpreted the 

definition of cellulosic biofuel as 

including in some cases a renewable 

fuel that is produced from both the 

cellulosic and incremental amounts of 

non-cellulosic components of the 

feedstock. EPA has treated the resulting 

fuel as all derived from cellulosic 

material where the feedstock is 

composed almost entirely of woody 

materials and leaves, or where the 

predominant component of the 

feedstock is likely cellulosic. The fuel 

will be largely derived from this 

cellulosic material and to a much 

smaller extent from non-cellulosic 

materials. There currently is no ready 

test to identify the portion of fuel 

produced from non-cellulosic materials. 

EPA has not considered the fuel as 

cellulosic in cases where the feedstock 

was likely to be largely non-cellulosic 

materials. In all of these cases, EPA has 

recognized that the fuel would be 

produced from both the cellulosic and 

non-cellulosic materials in the 

feedstock, and has determined in some 

cases to consider the fuel entirely 

cellulosic biofuel based on the relative 

amounts of the cellulosic and noncellulosic materials and, for fuel made 

from the biogenic portion of separated 

MSW, on the lack of availability of a test 

procedure to differentiate how much of 

the fuel came from the cellulosic 

materials. 

These determinations have been 

based on the view that the statutory 

requirement that cellulosic biofuel be 

‘‘derived from cellulose, hemicellulose, 

or lignin’’ does not mandate that in all 

cases the renewable fuel must be 

produced solely from the cellulosic 

material in the renewable biomass. EPA 

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13By predominant, EPA means the very high 

percentages for adjusted cellulosic content 

discussed in section V.A.1. above for the feedstocks 

at issue in this proposal. 

14See Bot v. IRS, 353 F.3d 595 (8th Cir. 2003), 

Wuebker v. IRS, 205 F.2d 897 (6th Cir. 2000), 

Milligan v. IRS, 38 F.3d 1094 (9th Cir. 1994). See 

also Hecla Mining Company v. US, 909 F.2d 1371 

(10th Cir. 1990) (DOE’s interpretation of the term 

‘‘derived from’’ in the Uranium Mill Tailings 

Radiation Control Act of 1978 accepted as a 

reasonable interpretation under Chevron). 

15 In addition, in section B of this proposal, EPA 

is also proposing to include corn fiber, CNG, LNG, 

electricity, and renewable diesel and naphtha from 

landfill biogas as cellulosic pathways for the 

reasons discussed therein. 

considers the statutory definition of 

cellulosic biofuel to be ambiguous on 

this point, providing EPA the discretion 

to reasonably determine under what 

circumstances a fuel appropriately 

could be considered cellulosic biofuel 

when the fuel is produced from a 

feedstock that is a mixture of cellulosic 

and non-cellulosic materials. To date, 

EPA has specified certain circumstances 

where the entire fuel will be considered 

cellulosic biofuel. EPA has taken this 

action in cases where the cellulosic 

material is almost entirely woody 

materials or leaves, or the fuel is 

produced from materials that are 

predominantly composed of cellulosic 

materials and to a much smaller extent 

non-cellulosic materials, with no 

current test to identify the differing 

portions. There have been two elements 

present in these decisions. One involves 

a determination that the feedstock is 

composed almost entirely or largely of 

cellulosic materials. EPA has also 

considered whether or not there is a test 

method to identify the actual portion of 

the fuel produced from cellulosic 

materials. In this rulemaking EPA is 

proposing an approach that is consistent 

with and an outgrowth of the approach 

taken in the RFS2 rulemaking. EPA is 

proposing to approve certain fuels as 

cellulosic biofuel where the cellulosic 

components account for a predominant 

percentage of the biogenic material in 

the renewable biomass feedstock used to 

produce the fuel, even where the noncellulosic components of the renewable 

biomass could be reasonably identified 

or estimated.13

EPA is proposing to classify all of the 

biofuel as cellulosic in the fuel 

pathways proposed today, where the 

cellulosic material makes up a 

predominant percentage of the organic 

material from which the fuel is 

produced. This approach will avoid the 

administrative and technical burden on 

producers and EPA of trying to 

determine the specific amounts of 

cellulosic and non-cellulosic materials 

in the specified high-cellulosic 

feedstock sources, removing potential 

difficult and potentially timeconsuming and expensive impediment 

to expansion of the cellulosic biofuel 

industry. The growth in cellulosic 

biofuel volumes promoted by today’s 

proposal is expected to result in greater 

reductions in GHGs, as all of the biofuel 

qualified as cellulosic would have to 

achieve the minimum 60% reduction in 

GHG emissions specified in the Act. 

EPA’s application of this approach to 

the specific fuel pathways and 

feedstocks discussed in this proposal is 

intended to ensure that cellulosic 

materials are the predominant portion of 

the biogenic materials used to produce 

cellulosic biofuel. This approach avoids 

administrative, technical and cost 

burdens on EPA and industry and 

promotes the volume and greenhouse 

gas objectives of Congress. EPA 

proposes that this is a reasonable 

interpretation of the definition of 

cellulosic biofuels, and invites comment 

on this approach.14

EPA is proposing that biofuel made 

from the following cellulosic feedstocks 

will be able to generate applicable 

cellulosic RINs for 100% of the volume 

produced: crop residue; slash; precommercial thinnings and tree residue; 

annual cover crops; switchgrass; 

miscanthus; and energy cane. EPA’s 

prior treatment of separated yard waste, 

separated food waste, and separated 

MSW is discussed above and is not 

being changed. On January 5, 2012, EPA 

proposed to qualify napier grass and 

Arundo donax as new feedstocks that 

would be eligible to generate cellulosic 

RINs. If those pathways are approved 

before this rule is final, EPA is 

proposing to apply the approach 

discussed above to these feedstocks as 

well.15 To the extent that additional 

cellulosic pathways are approved in the 

future, we would expect to apply this 

same methodology to those feedstocks 

as well, but will evaluate them on a 

case-by-case basis. 

EPA requests comments on this 

proposed approach to allow 100% of the 

volume of renewable fuel produced 

from the specified cellulosic feedstock 

sources found in Table 1 of section 

80.1426 to generate cellulosic RINs. We 

also take comment on the cellulosic 

content values presented for different 

feedstocks. In addition, we request 

comments about any analytical methods 

that may exist to determine what 

percent of a finished biofuel product 

may have derived from cellulosic versus 

non-cellulosic components, and what 

the costs may be associated with these 

test methods. We also request comment 

on the alternative approaches outlined 

below. 

4. Alternative Approaches 

EPA seeks comment on two 

alternative approaches to assigning 

cellulosic RINs to fuels produced from 

the cellulosic feedstocks discussed 

above. Separate from the specific 

pathways addressed in this proposal, 

EPA also seeks comment on potential 

approaches for assigning cellulosic RINs 

for anticipated future pathways for 

renewable fuels produced from 

feedstocks that contain lower cellulosic 

content than those discussed in this 

rulemaking. 

Cellulosic Content Threshold Approach 

An alternative approach for handling 

the variability in cellulosic content 

would be for EPA to set a minimum 

threshold of cellulosic content in the 

feedstock. Fuels produced from 

feedstocks with a cellulosic content 

above this minimum threshold would 

be eligible to generate cellulosic RINs 

for 100% of their volume. Thresholds 

under consideration would range from 

70% to 99.9%. A higher percentage 

would place more emphasis on the 

feedstock content having a higher actual 

cellulosic component, whereas the 

lower percentages would place more 

emphasis on promoting the volume of 

fuels that could be categorized as 

cellulosic biofuel. EPA invites comment 

on this approach, and also invites 

comment on the most appropriate value 

to use as the threshold. Furthermore, 

EPA invites comment on whether 

individual producers should be 

responsible for submitting data that 

their feedstock meets this threshold, or 

whether EPA should determine whether 

feedstocks meet this threshold based on 

existing published data. 

Since biochemical processes generally 

only convert the cellulosic, 

hemicellulosic, or lignin components of 

the feedstock to fuel, EPA believes 

under this alternative approach, it may 

still be appropriate to allow fuel 

producers using biochemical processes 

to generate RINs for 100% of the fuel 

produced from cellulosic feedstocks. 

EPA requests comments on our 

assumption that biochemical processes 

will be specific for the cellulosic 

components, and we also request 

comment on whether to allow 100% of 

the fuel produced via biochemical 

processes to generate cellulosic RINs. 

Specified Percentage Approach 

As noted above, examining the range 

of feedstock data compiled by EPA, it 

appears that 85% would be a reasonable 

approximation for the average adjusted 

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36048 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

16U.S. Environmental Protection Agency. 2013. 

Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990–2011, Chapter 8: Waste. EPA 430–R– 

13– 001, available at http://www.epa.gov/ 

climatechange/Downloads/ghgemissions/US-GHGInventory-2013-Main-Text.pdf. 

cellulosic content across a range of 

assessments of the specific feedstocks 

that are qualified to produce cellulosic 

fuel. Under this approach, fuels 

produced from the cellulosic feedstocks 

discussed above would be eligible to 

generate cellulosic RINs for 85% of their 

volume, and the remaining 15% would 

be eligible to generate advanced RINs. 

The specified percentage approach 

would reduce administrative burden but 

also incentivize renewable fuel 

production. For this approach, EPA 

would effectively be treating 85% of the 

fuel produced from all of these 

feedstock sources as being derived from 

cellulosic material. However, EPA 

would consider allowing a larger 

percentage of the fuel to qualify for 

cellulosic RINs if the producer could 

submit data that demonstrates a 

consistently higher cellulosic content in 

their feedstock. Under this approach, 

producers could submit a written plan 

for approval under the registration 

procedures in 40 CFR 80.1416(b)(vii). 

The plan would need to detail the 

cellulosic content of the feedstock, the 

method used for quantifying the 

cellulosic and non-cellulosic contents, 

and the production process used. 

Since biochemical processes generally 

only convert the cellulose, 

hemicellulose, or lignin components of 

the feedstock to fuel, EPA believes 

under this alternative approach it would 

be appropriate to allow fuel producers 

using biochemical processes to generate 

RINs for 100% of the fuel produced 

from cellulosic feedstocks. EPA requests 

comments on our assumption that 

biochemical processes will be specific 

for the cellulosic components, and we 

also request comment on whether to 

allow 100% of the fuel produced via 

biochemical processes to generate 

cellulosic RINs. 

Request for Comment on Potential 

Approaches for Fuels Produced From 

Feedstocks With Lower Cellulosic 

Content 

Finally, EPA anticipates that in the 

future, we may address biofuels that are 

produced from feedstocks that contain 

lower cellulosic content than those 

discussed in this rulemaking. 

Accordingly, we request comment on 

how EPA should assign RINs to the 

fuels produced from feedstocks with 

lower cellulosic content than those 

presented in this rulemaking but for 

which some of the fuel is produced from 

the cellulosic components. One possible 

example would be a feedstock that 

contained in the range of 40–60% 

cellulose, hemicellulose and lignin, 

where the fuel was produced using 

thermochemical methods such that the 

same percentage of the fuel may come 

from cellulosic materials. EPA invites 

comments about what approaches could 

be taken for assigning cellulosic RINs to 

the biofuel. For example, would one or 

more of the approaches outlined above 

be appropriate for assigning RINs to this 

fuel? Are there variations on these 

approaches that EPA should consider? 

EPA also invites comments on how to 

assign cellulosic RINs where processes 

other than thermochemical methods are 

used. 

B. Lifecycle Greenhouse Gas Emissions 

Analysis for Renewable Electricity, 

Renewable Diesel and Naphtha 

Produced from Landfill Biogas 

EPA has received several facilityspecific petitions under § 80.1416 to 

allow renewable electricity, renewable 

diesel and naphtha produced from 

landfill biogas to qualify as renewable 

fuels under the RFS program. Since 

these new pathways could be more 

broadly applicable, EPA is proposing to 

add these pathways to Table 1 to 

§ 80.1426 through this rulemaking 

process. Based on questions from 

companies, EPA is also modifying the 

existing biogas pathway to specify that 

compressed natural gas (CNG) or 

liquefied natural gas (LNG) is the fuel 

and biogas is the feedstock. For this 

proposal, EPA considered both the 

cellulosic origin of landfill biogas and 

the lifecycle GHG impacts of three types 

of fuel produced from landfill-derived 

biogas. In the final RFS2 rule, EPA 

established biogas as a fuel type when 

derived from landfills, sewage waste 

treatment plants, and manure digesters. 

This biogas was classified as an 

advanced biofuel eligible to generate 

D-Code 5 RINs. EPA also established 

cellulosic diesel and cellulosic naphtha 

as cellulosic biofuels eligible to generate 

D-Code 7 and 3 RINs, respectively. The 

eligible feedstocks for these biofuels 

include cellulosic components of 

separated municipal solid waste but did 

not include biogas from landfills. 

Based in part on additional 

information received through the 

petition process for EPA approval of 

renewable electricity and renewable 

diesel and naphtha produced from 

landfill biogas, EPA has evaluated these 

pathways and is proposing to include 

renewable electricity produced from 

landfill biogas feedstock in Table 1 to 

§ 80.1426 as a cellulosic fuel type. It is 

important to note that RINs may only be 

generated for electricity from biogas that 

can be tracked to use in the 

transportation sector, such as by an 

electric vehicle. We are also proposing 

to add renewable diesel produced from 

landfill biogas via the Fischer-Tropsch 

process as an approved advanced and/ 

or biomass-based diesel biofuel and 

naphtha produced from landfill biogas 

via the Fischer-Tropsch process as an 

approved advanced biofuel. If the 

Fischer-Tropsch facilities produce at 

least 20% of their electricity demand at 

the facility from certain allowed 

sources, we are proposing that the 

renewable diesel and naphtha produced 

would further qualify as cellulosic 

biofuels. We are also proposing to 

amend the existing biogas pathway to 

list renewable CNG/LNG as the fuel 

types instead of biogas since the biogas 

is converted into CNG or LNG before 

being used as a transportation fuel, as 

discussed below. Renewable CNG/LNG 

produced from biogas from waste 

treatment plants and waste digesters is 

still classified as an advanced biofuel. 

However, renewable CNG/LNG 

produced from biogas from landfills 

now qualifies as a cellulosic pathway. 

The changes to the renewable CNG/LNG 

pathway are described in section C.1. 

‘‘Changes Applicable to the Revised 

CNG/LNG pathway from Biogas’’ below. 

1. Feedstock Production 

When waste materials are buried in a 

landfill, decomposition of the organic 

materials consumes all of the oxygen 

present within roughly one year, leaving 

the bulk of the material to undergo 

slower, anaerobic decomposition. This 

process produces large amounts of 

methane for several decades, as well as 

other products, with the gases released 

as ‘‘biogas.’’ Biogas from landfills 

typically contains approximately 50% 

methane and 50% carbon dioxide, with 

small or trace amounts of other gases. 

Methane is a potent greenhouse gas 

(GHG), with a global warming potential 

of 21 times that of carbon dioxide, and 

landfills are the third-largest 

anthropogenic source of methane to the 

atmosphere in the United States.16

The methane present in biogas is also 

a potential energy source that may be 

purified and compressed to be used 

directly in CNG or LNG vehicles, 

combusted to produce electricity or 

converted to renewable diesel and 

naphtha via the Fischer-Tropsch 

process. The March 2010 RFS final rule 

concluded that municipal solid waste 

has no agricultural or land use change 

GHG emissions associated with its 

production. Furthermore, the feedstock 

for these fuels is landfill biogas, which 

already appears in Table 1 of 

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Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 36049 

17Barlaz, M.A., R.K. Ham, and D.M. Schaefer. 

1989. Mass-balance analysis of anaerobically 

decomposed refuse. Journal of Environmental 

Engineering, 15(6) 1088–1102. 

18 ‘‘Support for Cellulosic Determination for 

Landfill Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels 

Produced from Landfill Biogas,’’ which has been 

placed in docket EPA–HQ–2012–0401. 

19Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing 

Sources: Municipal Solid Waste Landfills, 61 FR 

9905, 9944 (March 12, 1996). 

20Some 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. 

21Environmental 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. 

22Environmental Protection Agency, Landfill 

Methane Outreach Program. 2010. LFG Energy 

Project Development Handbook: Chapter 2. Landfill 

Gas Modeling. http://epa.gov/lmop/publicationstools/handbook.html. 

§ 80.1426(f) of the RFS2 regulations and 

has already been evaluated as part of the 

RFS2 final rule lifecycle GHG 

determinations. Therefore no new 

renewable feedstock production 

modeling was required, no GHG 

emissions were attributed to feedstock 

production for any of these renewable 

fuel pathways, and EPA focused our 

analysis on the new fuel production 

processes. 

2. Determination of the Cellulosic 

Composition of Landfill Biogas 

In order for fuels produced from 

landfill biogas as a feedstock to qualify 

to generate D-Code 3 or 7 (cellulosic) 

RINs, the renewable fuel must be 

derived from cellulosic materials and 

must meet a 60% GHG emissions 

reduction threshold, as described in the 

following sections. In this section, we 

discuss our determination that biogas 

derived from landfills is derived from 

cellulose, hemicellulose or lignin. 

CAA 211(o) specifies ‘‘separated yard 

waste or food waste’’ as a type of 

renewable biomass, and in the March 

2010 RFS final rule, EPA stated: 

As a result of the intermixing of wastes, the 

fact that biogas is formed only from the 

biogenic portion of landfill material, and the 

fact that landfill material is as a practical 

matter inaccessible for further separation, 

EPA believes that no further practical 

separation is possible for landfill material 

and biogas should be considered as produced 

from separated yard and food waste for 

purposes of EISA. 

The March 2010 RFS final rule stated 

that all landfill-derived biogas was 

therefore eligible to generate RINs. 

An in-depth study of methane 

production from different chemical 

components of municipal solid waste 

found that roughly 90% of the methane 

generated in landfills derived was from 

cellulose and hemicellulose.17

Accordingly, EPA is proposing to 

classify renewable fuels produced from 

landfill biogas as derived from cellulose, 

hemicellulose or lignin. This 

determination is discussed in more 

detail in a memo to the docket.18

Consistent with the discussion in the 

section above, ‘‘Approving Cellulosic 

Volumes from Cellulosic Feedstock,’’ 

we are classifying all of the biofuel 

volume produced from landfill biogas as 

cellulosic in origin. Therefore the entire 

volume of renewable fuels using landfill 

biogas as a feedstock will be eligible to 

generate cellulosic RINs (D-Codes 3 and 

7) if the fuel also meets the required 

60% GHG emissions reductions. EPA 

invites comment and data on the 

cellulosic component of biogas. 

3. Fuel Production—General 

Considerations 

Landfills currently treat their methane 

in one of several ways. Municipal solid 

waste (MSW) landfills designed to 

collect at least 2.5 million megagrams 

(Mg) and 2.5 million cubic meters of 

waste and emitting at least 50 Mg of 

non-methane organic compounds per 

year are required by EPA regulations to 

capture and control their biogas.19

These large, regulated landfills 

represent a small percentage of all 

landfills by number but are responsible 

for the majority of biogas emissions 

from landfills. To comply with the 

regulations, these landfills must at a 

minimum combust their biogas in a 

flare, converting the methane to carbon 

dioxide, a less potent GHG. They may 

also use it to generate electricity from 

combustion of the methane, in which 

case, the electricity produced may 

displace electricity from other sources 

(such as gas-fired power plants) once it 

enters the grid. If displacing other 

sources of electricity that on average 

have greater GHG emissions, landfills 

that generate electricity may reduce 

GHG emissions and are using the ‘‘best 

practices’’ in the industry.20 Many 

smaller, unregulated landfills do not 

collect their biogas, and this methane is 

‘‘vented’’ to the atmosphere. In 2010, 

29% of the methane generated at 

landfills was flared and 29% of the 

methane was used to generate 

electricity.21 Accounting for the 25% 

average collection efficiency of biogas 

collection systems,22 we estimate that 

approximately 38% of the methane 

generated is derived from landfills that 

flare their gas and another 38% is 

derived from landfills with gas-toelectricity projects. By mass balance, 

this suggests that 24% of the landfill 

methane generated is from landfills that 

vent their methane. 

In our lifecycle GHG analysis of these 

biofuels we need to consider what 

would have happened to the landfill gas 

if it was not used to produce 

transportation fuels. This is the baseline 

for comparison to calculate the GHG 

impacts of the fuels in question. Once 

we have chosen a baseline for 

comparison, we propose to treat biogas 

from all landfills the same regardless of 

how the biogas is processed at that 

landfill. This approach is consistent 

with how we have treated the 

implementation of advanced 

technologies for all biofuels producers. 

For the landfill gas-to-electricity 

pathway we use landfills that flare their 

biogas as the baseline GHG emissions 

with which we compare scenarios 

involving production of electricity from 

the landfill biogas. We chose this 

baseline because these landfills are the 

ones most likely to convert to gas-toenergy projects, since they already have 

gas collections systems in place. They 

are also the ones most likely to be the 

alternative to gas to energy projects 

since these projects will likely go into 

larger landfills that are required by 

regulation to collect and treat the biogas. 

We expect that small, unregulated 

landfills would be unlikely to generate 

enough biogas to justify collecting it for 

conversion to renewable fuels. 

Furthermore, we expect that the capital 

costs for such small landfills would 

preclude them from making such 

changes. However, if such small 

landfills were to capture and use their 

biogas in transportation fuels, this 

would result in significantly greater 

reductions in GHG emissions at each 

landfill than assumed for landfills 

already capturing biogas because of the 

decrease in methane release, so that 

biofuels produced from such facilities 

would easily meet the required 

emissions reduction thresholds. Since 

landfills that currently have gas-toenergy projects in place at one point 

either replaced flaring with a gas-toenergy project or installed a gas-toenergy project as an alternative to the 

minimal compliance route of flaring, we 

are proposing to treat the emissions 

from these landfills compared to the 

same flaring baseline. We show lifecycle 

results calculated using alternative 

baselines and discuss our choice of 

baseline in more depth in a memo to the 

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36050 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

23 ‘‘Support for Cellulosic Determination for 

Landfill Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels 

Produced from Landfill Biogas,’’ which has been 

placed in docket EPA–HQ–2012–0401. 24Argonne National Laboratory (2011) 

Greenhouse Gases, Regulated Emissions, and 

Energy Use in Transportation Model (GREET), 

Version 1 2011, http://greet.es.anl.gov/. 

25EPA LMOP Data. 

26 ‘‘Support for Cellulosic Determination for 

Landfill Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels 

Produced from Landfill Biogas,’’ which has been 

placed in docket EPA–HQ–2012–0401. 

27All values are derived from information 

provided by the EPA Landfill Methane Outreach 

Program except the distribution loss number, which 

is from the U.S. Energy Information Agency. 

Parasitic losses were calculated by apportioning the 

gross electricity generation to different types of 

generators and using parasitic loss values for that 

particular type of generator. 

28Note that in order to determine the number of 

RINs generated from a given amount of renewable 

electricity, section 80.1415(b)(6) of the regulations 

states that 22.6 kW-hr of electricity shall represent 

one gallon of renewable fuel with an equivalence 

value of 1.0. 

docket.23 We invite comment on our 

baseline assumptions for the electricity 

pathway. If commenters believe a 

different baseline is appropriate, EPA 

specifically invites the submission of 

data supporting this alternative 

baseline. 

For gas to liquids projects we also use 

landfills that flare their biogas as the 

baseline GHG emissions with which we 

compare scenarios involving production 

of gas to liquids, for the same reasons 

outlined above. We further consider that 

landfills that have already invested the 

capital to generate electricity are 

unlikely to stop doing so in order to 

generate liquid fuels from the biogas, 

which would require considerable 

additional capital investments. These 

facilities are therefore an unlikely 

baseline for the pathways generating 

renewable diesel and naphtha. We 

invite comment on our baseline 

assumptions for the liquids pathway 

and whether a different baseline would 

be more appropriate. If commenters 

believe a different baseline is 

appropriate, EPA specifically invites the 

submission of data supporting this 

alternative baseline. 

4. Fuel Production for Renewable 

Electricity 

Landfills can generate electricity by 

combustion of the methane in their 

biogas. Generating electricity at landfills 

requires collection of the biogas (using 

wells, piping and blowers), purification 

and compression of the biogas and 

electricity generation. Most landfills use 

internal combustion engines to generate 

the electricity, but a significant 

proportion also use gas or steam 

turbines or combined cycle systems. 

Once generated, the electricity enters 

the electrical grid. 

In determining the lifecycle GHG 

analysis of renewable electricity, we 

examined two main factors. The first 

involved determining by how much 

emissions at the landfill (from flaring) 

would change upon installation of a gasto-energy project. For this calculation, 

we used emission factors from the 

GREET model.24 The second involved 

calculation of the decrease in GHG 

emissions caused by powering the gas 

blowers already in use with biogasderived electricity rather than grid 

electricity upon installation of a gas-toenergy project. This calculation used 

data from the EPA Landfill Methane 

Outreach Project (LMOP).25 For each 

factor, we needed to first calculate how 

much electricity could be generated and 

delivered to the consumer. We used 

values from LMOP as estimates of the 

relative shares of different types of 

engines or turbines, the electricity 

generation efficiency, parasitic losses, 

energy use in collecting and preparing 

the biogas, and a value from the U.S. 

Energy Information Agency to estimate 

distribution losses. Values used are 

shown in Table V.B.–1, and the 

assumptions and calculations are 

discussed in more detail in a memo to 

the docket.26

TABLE V.B.–1—CALCULATION OF THE NET AMOUNT OF ELECTRICITY DELIVERED TO THE CONSUMER PRODUCED FROM A

GIVEN AMOUNT OF LANDFILL BIOGAS 27

Value Units 

Electricity generation efficiency ........................................................................................................... 11700 Btu/kWh. 

Gross electricity production ................................................................................................................. 0.292 mmBtu/mmBtu biogas. 

Electricity produced after parasitic losses ........................................................................................... 0.267 mmBtu/mmBtu biogas. 

Energy used for blowers ..................................................................................................................... 0.014 mmBtu/mmBtu biogas. 

Distribution losses ............................................................................................................................... 0.017 mmBtu/mmBtu biogas. 

Net electricity delivered to consumer .................................................................................................. 0.236 mmBtu/mmBtu biogas. 

We used the value for the net city 

yield from biogas to calculate how GHG 

emissions from the landfill itself would 

change upon conversion from flaring to 

a gas-to-energy project. We first 

calculated emissions per mmBtu 

electricity (Table V.B.–2). However, the 

drivetrains of electric vehicles are 

roughly three times as efficient as those 

of conventional gasoline-powered 

vehicles, meaning that any given EV 

would be able to travel about three 

times as far per Btu of input. To account 

for this difference, we also calculated 

emissions per mmBtu fuel equivalent. It 

would take roughly three times the 

amount of energy from liquid fuel to 

drive a conventional vehicle a given 

distance compared to an EV powered by 

electricity, so the emissions per mmBtu 

fuel equivalent are approximately one 

third as large as the emissions per 

mmBtu electricity. EPA invites 

comments on the assumptions regarding 

electricity equivalence.28

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Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 36051 

29Argonne National Laboratory, ‘‘Greenhouse 

Gases, Regulated Emissions, and Energy Use in 

Transportation Model (GREET),’’ Version 1 2011, 

http://greet.es.anl.gov/. 

30 Department of Energy: National Energy 

Technology Laboratory. (2009) NETL: PetroleumBased Fuels Life Cycle Greenhouse Gas Analysis— 

2005 Baseline Model. www.netl.doe.gov/energyanalyses. 

TABLE V.B.–2—FUEL GHG EMISSIONS FOR THE RENEWABLE ELECTRICITY PATHWAY, CALCULATED PER MMBTU

ELECTRICITY AND PER MMBTU FUEL EQUIVALENT COMPARED TO THE 2005 GASOLINE BASELINE

Lifecycle stage 

GHG emissions 

Renewable 

electricity 

2005 Gasoline 

baseline 

U.S. Average 

grid electricity 

kg CO2-eq/ 

mmBtu 

electricity 

kg CO2-eq/ 

mmBtu fuel 

equivalent 

kg CO2-eq/ 

mmBtu 

fuel 

kg CO2-eq/ 

mmBtu 

electricity 

On-site emissions ............................................................................................ 25 8 ........................ ........................

Upstream (electricity production for blowers) .................................................. ¥13 ¥4 ........................ ........................

Total Emissions: ....................................................................................... 12 4 98 220 

% Change from Gasoline Baseline ................................................................. ¥87% ¥96% ........................ ........................

% Change from Grid Electricity ....................................................................... ¥94% N/A ........................ ........................

On-site emissions of facilities that 

generate electricity would be slightly 

higher than emissions from facilities 

that flare because reciprocating engines, 

which are the dominant technology 

used to generate electricity from biogas, 

are less efficient at destroying methane 

than flares. Facilities that originally 

flared their biogas are assumed to have 

been purchasing electricity from the 

grid to power the blowers needed to 

collect the biogas. Upon conversion to 

gas-to-energy projects, the facilities 

would now generate that electricity 

themselves and thus no longer need to 

purchase this electricity from the grid. 

The calculations above include a credit 

in GHG emissions for the avoided 

purchase of grid electricity (Table V.B.– 

2). Unlike traditional transportation 

fuels, there are no GHG emissions 

involved in transportation or 

distribution of renewable electricity 

(distribution losses are accounted for 

above), nor are there any tailpipe 

emissions from the direct use of the 

fuel. Therefore, the only emissions 

considered are those from production of 

the fuel, as outlined in Table V.B.–2. 

The total GHG emissions for conversion 

from flaring to a gas-to-energy project 

are 12 kg CO2-eq/mmBtu electricity, or 

4 kg CO2-eq/mmBtu fuel equivalent. 

Compared with the gasoline baseline 

GHG emissions of 98 kg CO2-eq/mmBtu, 

these projects would be accompanied by 

an 87% reduction in GHG emissions 

when normalized per mmBtu electricity. 

Accounting for the improved efficiency 

of EV drivetrains increases the GHG 

emissions reductions to 96%. 

Renewable electricity therefore meets 

the statutory baseline of 60% reductions 

in GHG emissions relative to the 

gasoline baseline and qualifies as a 

cellulosic biofuel. EPA invites 

comments on the assumptions and 

calculations of GHG emissions related to 

renewable electricity from landfill gas. 

5. Fuel Production, Transport and 

Tailpipe Emissions for Renewable 

Diesel and Naphtha 

Renewable diesel and naphtha can be 

made from landfill biogas by a 

combination of methane reforming and 

the Fischer-Tropsch gas-to-liquids (GTL) 

process. For methane reforming, the 

biogas must first be purified and then be 

reformed to create synthesis gas, known 

as ‘‘syngas,’’ which is composed of a 

mixture of carbon monoxide and 

hydrogen gas. This process may occur 

via either steam methane reforming or 

autothermal reforming. The syngas is 

next purified and then sent to a FischerTropsch (F–T) system in which the 

carbon monoxide and hydrogen are 

combined in the presence of a catalyst 

to form a range of hydrocarbons. This 

reaction produces relatively short-chain 

(naphtha), medium-length (diesel) and 

long-chain (wax) hydrocarbons. The 

wax can subsequently be upgraded by 

hydroprocessing to form naphtha and 

diesel fuels. The different products are 

then separated by simple distillation. 

Heat generated by the reaction can be 

used to preheat gases in the system and 

to generate electricity for use in the 

system or for export. Unconverted 

syngas from the F–T process and fuel 

gas from hydroprocessing can also be 

combusted to generate electricity. GTL 

plants may have substantially different 

lifecycle GHG impacts depending on 

whether they upgrade their waxes and 

whether they generate electricity as a 

side product of the reaction. Electricity 

generation can add to the capital costs 

of a facility but also greatly reduces the 

lifecycle GHG emissions of a plant. 

In determining the lifecycle GHG 

impacts of GTL fuels, we considered 

two main factors: on-site emissions at 

the landfill and upstream emissions 

from electricity production to power the 

plant. Additionally, a facility that 

produced wax was assigned a coproduct credit for the wax generated. 

We did the calculations assuming the 

facility did not generate any electricity 

and then calculated what fraction of 

their electricity demands they would 

need to generate internally to meet the 

60% emissions reduction threshold to 

qualify for cellulosic RINs. 

To determine the lifecycle GHG 

emissions, we used confidential 

business information (CBI) data 

provided in a petition submitted to EPA. 

This process did not involve upgrading 

of wax to liquid fuels. For this scenario, 

we used the supplied information about 

inputs of biogas, outputs of fuel and coproduct and electrical demand for the 

lifecycle analysis. We first determined 

how many GHG emissions would be 

avoided on-site at the landfill by 

changing from the baseline scenario of 

flaring to collecting the biogas for 

conversion to liquid fuels. This 

calculation was similar to that described 

above for renewable electricity and 

relied on values from GREET29 for the 

emissions factor for flaring. To calculate 

the emissions from electricity required 

by the process, we used the emissions 

factors for average U.S. electrical 

production used in the RFS2 final rule. 

To assign a co-product credit to the 

fuels, we assumed that the wax 

produced during the Fischer-Tropsch 

process would enter a market in which 

it would displace wax derived from 

petroleum. To determine the effects of 

such a displacement on GHG emissions, 

we used data from a model by the 

Department of Energy’s National Energy 

Technology Laboratory (NETL) 30 for the 

yields and GHG emissions attributable 

to wax production from petroleum 

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36052 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

31 Kline Group (2011) Global Wax Industry 2010: 

Market Analysis and Opportunities. http:// 

www.klinegroup.com/reports/brochures/y635a/ 

brochure.pdf. 32 ‘‘Support for Cellulosic Determination for 

Landfill Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels 

Produced from Landfill Biogas,’’ which has been 

placed in docket EPA–HQ–2012–0401. 

33 ‘‘Support for Cellulosic Determination for 

Landfill Biogas and Summary of Lifecycle Analysis 

Assumptions and Calculations for Biofuels 

Produced from Landfill Biogas,’’ which has been 

placed in docket EPA–HQ–2012–0401. 34Skone, T.J. and Gerdes, K. (2008) NETL: 

Development of Baseline Data and Analysis of Life 

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

35Spath, P.M. and Mann, M.K. (2001) Lifecycle 

Assessment of Hydrogen Production via Natural 

Gas Steam Reforming. NREL Technical Report 

NREL/TP–570–27637, http://www.nrel.gov/docs/ 

fy01osti/27637.pdf. 

36Contadini, J.F., Diniz, C.V., Sperling, D., and 

Moore, R.M. (2000) Hydrogen production plants: 

emissions and thermal efficiency analysis. ITSDavis. Presented at the Second International 

Symposium on Technological and Environmental 

Topics in Transports, October 26–27, 2000. Milan, 

Italy. Publication No. UCD–ITS–RR–00–16. 

feedstock. These values only include 

production emissions and do not 

include any emissions from combustion 

of the wax in, for example, candles 

because we do not have information 

about what fraction of wax is 

combusted. If combustion emissions 

were included, the co-product credit 

would be even larger. The global wax 

market is growing, with demand 

expected to outpace supply in the next 

few years.31 As such, it is unlikely that 

F–T waxes would in reality displace 

petroleum-derived waxes. Instead, 

waxes from both sources are likely to be 

used in parallel to fulfill demand, and 

such waxes would replace any 

substitutes that might be used to fill the 

gap between supply and demand. The 

nature of these alternatives is presently 

unknown to EPA, as are their lifecycle 

GHG emissions. As an alternative to 

assigning a displacement credit, we 

could allocate emissions to the waxes 

along with the renewable diesel and 

naphtha products. In this case, the coproduct credit disappears but total fuel 

production emissions decrease to 30 kg 

CO2-eq/mm Btu, leading to overall GHG 

emissions reductions of 68%. Our use of 

the displacement approach is 

conservative compared to the allocation 

approach, which would have resulted in 

a larger credit for the wax co-product. 

We welcome comment regarding what 

kinds of materials these new waxes 

might replace, as well as how to best 

account for them in our lifecycle GHG 

analysis. 

The results of this analysis are shown 

on the ‘‘Fuel Production’’ line of Table 

V.B.–3, and the assumptions and 

calculations are discussed in more 

detail in a memo to the docket.32

Emissions from electricity production 

used to power the F–T plant is the 

greatest contributor to the overall fuel 

production emissions. In addition to 

emissions from fuel production, there 

were minor GHG emissions attributable 

to fuel transport and tailpipe emissions 

of non-CO2 GHGs (Table V.B.–3). 

Overall, renewable diesel and naphtha 

produced from landfill biogas via this 

process showed 52% and 51% 

reductions in GHG emissions, 

respectively, relative to the diesel or 

gasoline baseline (Table V.B.–3). These 

fuels would therefore qualify as 

advanced biofuels but not qualify as 

cellulosic biofuels. However, if the 

facility produced roughly 15% of its 

process electricity internally, using 

either waste heat from the reaction or 

combustion of unreacted chemicals, 

emissions from purchased electricity 

would drop enough to reach the 60% 

GHG reduction threshold, qualifying 

these fuels as cellulosic. Because 

emissions from production of these 

biofuels (without internal production of 

electricity) fall so close to the 50% 

threshold to qualify as advanced 

biofuels, the assumptions used to make 

the calculations are especially important 

and could potentially change the 

classification of these fuels. 

Accordingly, we request comments 

about the assumptions and values used 

in the calculations, which are detailed 

in a memo to the docket.33 In particular, 

we request comment about the estimate 

for the on-site GHG emissions at the 

Fischer-Tropsch facility. Data regarding 

fugitive emissions from Fischer-Tropsch 

facilities using methane as a feedstock 

appear to be limited, however, the 

GREET model assumed a loss factor of 

1.0000 for the production of F–T diesel, 

indicating their estimate that no 

methane is lost during this process. 

Several studies mentioned emissions 

from the steam methane reforming of 

natural gas to produce hydrogen, and 

we assumed emissions would be similar 

from a Fischer-Tropsch facility using 

steam methane reforming. Two of these 

studies 34 35 found or estimated that 

losses of methane from such facilities 

were negligible, agreeing with the 

GREET estimate. Accordingly, we 

assumed no emissions of methane from 

F–T facilities. However, another study 36

estimated losses of 0.125% of the 

natural gas processed. Using this last 

value, the GHG emissions reductions for 

renewable diesel and naphtha would 

decrease to 49% for both fuels, meaning 

that the biofuels would no longer 

qualify as advanced fuels. We request 

comments and information about our 

estimates of fugitive emissions from 

Fischer-Tropsch facilities. 

TABLE V.B.–3—TOTAL GHG EMISSIONS FOR RENEWABLE DIESEL AND NAPHTHA PRODUCED FROM LANDFILL BIOGAS AND

COMPARED TO THE APPROPRIATE PETROLEUM BASELINE

Lifecycle stage 

GHG emissions (kg CO2-eq/mmBtu) 

Biofuels Petroleum baselines 

Renewable 

diesel Naphtha 2005 diesel baseline 

2005 gasoline 

baseline 

Fuel Production ................................................................................................ 44 44 18 19 

Fuel Transport ................................................................................................. 1 2 * * 

Tailpipe Emissions ........................................................................................... 1 2 79 79 

Total Emissions ........................................................................................ 47 48 97 98 

% Change from Petroleum Baseline ............................................................... ¥52% ¥51% ........................ ........................

* Emissions included in fuel production stage. 

For this lifecycle analysis, we have 

only examined a facility that does not 

upgrade its wax and therefore produces 

wax as a co-product. It is likely that 

other facilities may produce F–T 

renewable diesel and naphtha by a 

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37Swanson, R.M., Satrio, J.A., Brown, R.C., 

Platon, A., and Hsu, D.D. (2010) Techno-Economic 

Analysis of Biofuels Production Based on 

Gasification. NREL Technical Report NREL/TP– 

6A20–46587, http://www.nrel.gov/docs/fy11osti/ 

46587.pdf. 

38Skone, T.J. and Gerdes, K. (2008) NETL: 

Development of Baseline Data and Analysis of Life 

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

39Emissions estimates are conservatively high. 

process that does involve upgrading 

waxes to increase the yield of the liquid 

fuels. Accordingly, we used assessments 

from other analyses of theoretical F–T37

or steam methane reforming 38 plants 

using wax upgrading to estimate the 

lifecycle GHG emissions from such 

products. Based on this analysis (not 

shown), these facilities should 

theoretically have GHG emissions that 

are as low as or lower than those 

calculated above. For this reason, we 

believe that the lifecycle analysis shown 

above is a reasonable, if slightly 

conservative,39 representation of 

expected landfill biogas-to-liquids 

projects. We accordingly classify all 

renewable diesel and naphtha produced 

via the F–T process from landfill biogas 

as advanced biofuel. 

The lifecycle analysis for these fuels 

considered that the renewable diesel 

product produced from the FischerTropsch process would be used as 

conventional diesel fuel. EPA does not 

have sufficient information to evaluate 

the lifecycle greenhouse gas emissions 

for jet fuel or heating oil produced from 

landfill biogas using the FischerTropsch process. Because the lifecycle 

analysis results for this process fell so 

close to the threshold for advanced 

biofuels, in this pathway, we are 

proposing to only allow renewable 

diesel for use as conventional diesel fuel 

to qualify under the RFS program. We 

invite comments and supporting data 

about whether we should also allow jet 

fuel and heating oil produced from 

landfill biogas to qualify. 

Our lifecycle analysis showed that if 

the evaluated facility meets 

approximately 15% of its electricity 

demand with internally produced 

electricity from eligible sources, it will 

meet the 60% threshold to qualify as 

cellulosic. Because other facilities are 

likely to be somewhat different, and 

because this analysis relies on a number 

of assumptions, we are using a slightly 

more conservative threshold of 20% of 

electrical generation. Accordingly, we 

are proposing that if a biogas-to-liquids 

facility produces at least 20 percent of 

its process electricity internally as 

discussed above, these biofuels will 

qualify as cellulosic. These 

requirements are discussed in greater 

length in Section C.4. ‘‘Changes 

Applicable to Process Electricity 

Production Requirement for the BiogasDerived Cellulosic Diesel and Naphtha 

Pathways’’ below. Facilities that can 

supply data that demonstrate they meet 

the 60% GHG emissions reduction 

threshold without production of 20% 

electricity are welcome to petition the 

EPA individually under section 

80.1416. 

EPA invites comment and data on the 

GHG emissions associated with landfill 

biogas renewable fuel pathways. We 

also welcome comment on the 

methodology and assumptions 

underlying this analysis. We do not at 

this point have sufficient information to 

evaluate the lifecycle greenhouse gas 

emissions for production of renewable 

electricity or renewable diesel and 

naphtha from biogas from waste 

treatment plants or waste digesters. 

Accordingly, we invite comments 

providing information about these 

potential pathways. 

C. Proposed Regulatory Amendments 

Related to Biogas 

1. Changes Applicable to the Revised 

CNG/LNG Pathway From Biogas 

In the existing RFS2 regulations, an 

approved fuel pathway in Table 1 to 

section 80.1426(f)(1) allows biogas from 

landfill gas, manure digesters or sewage 

treatment plants to qualify as an 

advanced biofuel and generate a D code 

of 5 for the biofuel produced under the 

RFS2 program. Since the promulgation 

of the final rule, we have received many 

requests about what fuel qualifies under 

this pathway, including: (1) The 

renewable fuel type that is qualified 

under the term ‘‘biogas,’’ (2) what are 

the eligible sources of biogas, (3) what 

company along the production chain of 

biogas from generation to end user is 

considered the producer that qualifies to 

register under this pathway and 

generate RINs, and (4) what are the 

contract requirements to track the biogas 

from generation to end use. 

In response, EPA is proposing in this 

rulemaking to amend the existing biogas 

pathway in Table 1 to section 80.1426(f) 

by changing the renewable fuel type in 

the pathway from ‘‘biogas’’ to 

‘‘renewable compressed natural gas 

(renewable CNG) and renewable 

liquefied natural gas (renewable LNG)’’ 

and to replace the feedstock type of 

‘‘landfills, manure digesters or sewage 

waste treatment plants’’ with ‘‘biogas 

from landfills, waste treatment plants or 

waste digesters.’’ We are also proposing 

to revise the definition of biogas and 

add definitions for CNG and LNG to 

section 1401 to provide additional 

clarity. In addition, we are proposing to 

revise and add new contracting, 

registration, reporting and 

recordkeeping requirements along the 

production chain. Furthermore, we are 

specifying which company along the 

production chain is considered the 

‘‘producer’’ and eligible to generate 

RINs under the RFS2 program. These 

proposed compliance requirements are 

applicable to this revised CNG/LNG 

pathway, and all the newly proposed 

pathways for renewable fuels produced 

from landfill gas in this rulemaking. The 

details of the proposed new 

requirements for contract, registration, 

reporting and recordkeeping are 

discussed below in the section titled 

‘‘Changes Applicable to All BiogasRelated Pathways for RIN Generation.’’ 

The existing biogas pathway in Table 

1 to section 80.1426(f) refers to ‘‘biogas’’ 

as the renewable fuel type and 

‘‘landfills, manure digesters and sewage 

waste treatment plants’’ as the 

feedstock. Companies have raised 

questions whether the term ‘‘biogas’’ in 

this pathway could refer to the 

unprocessed or raw gas from the 

landfills, manure digesters or sewage 

treatment plants, or processed ‘‘biogas’’ 

that has been upgraded and could be 

used directly for transportation fuel or 

as an ingredient in the production of 

transportation fuel or as an energy 

source used in the production of 

transportation fuel, or other fuel types 

that can be produced from the raw 

biogas either through a physical or 

chemical process (such as CNG, LNG, 

renewable electricity, renewable diesel 

or naphtha). The companies further 

inquire if the various forms of biogas 

discussed above could qualify under 

this pathway, and therefore be eligible 

for RIN generation under the RFS2 

program. 

We agree that the term ‘‘biogas’’ in 

this pathway is used broadly in the 

industry to refer to various raw and 

processed forms of the biogas from 

various sources. However, under the 

existing requirements in sections 

80.1426(f)(10) and (11), only biogas that 

is used for transportation fuel can 

qualify as renewable fuel for RIN 

generation under the RFS2 program. We 

believe the stipulations in sections 

80.1426(f)(10) and (11) are clear that 

biogas used for non-transportation fuel 

purposes, such as an energy source for 

providing process heat would not 

qualify under this biogas pathway for 

RIN generation. Similarly, raw biogas 

would also not qualify under this 

pathway since unprocessed biogas 

cannot be used as transportation fuel. 

With regard to the fuel types that can be 

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36054 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

40For this rulemaking, we conducted lifecycle 

analysis for renewable electricity, renewable diesel, 

naphtha produced from landfill gas, and are 

proposing new fuel pathways to Table 1 to Section 

80.1426 for these fuel types. Please see section 

titled, ‘‘Lifecycle Greenhouse Gas Emissions 

Analysis for Renewable Electricity, Renewable 

Diesel and Naphtha Produced from Landfill Biogas’’ 

for the lifecycle analysis discussion in this 

rulemaking. 

41EPA notes that currently, producers of 

renewable electricity that may qualify as a 

renewable fuel cannot register and generate RINs 

because there is no approved pathway in Table 1 

for renewable electricity from any approved 

feedstock. But in the event that an approved 

pathway for renewable electricity is added to Table 

1, EPA notes there are existing requirements such 

as tracking and distribution requirements 

recordkeeping and reporting that are applicable for 

the registration of renewable electricity for RIN 

generation. 

42 Distribution and registration requirements for 

biogas used as process heat, and not for RIN 

generation as renewable fuel is detailed in Section 

1426(f)(12) and 1450(b)(1)(iv), respectively. 

produced from the raw biogas such as 

CNG, LNG, renewable electricity, 

renewable diesel, or naphtha, the 

pathway determinations for the final 

rule did not account for all factors 

relevant for the additional fuel types 

such as renewable electricity, renewable 

diesel or naphtha produced from the 

raw biogas through a chemical process. 

Therefore, renewable electricity, 

renewable diesel and naphtha produced 

from biogas do not qualify under the 

existing pathway.40 For CNG and LNG, 

we concluded that these types of fuels 

were close enough to the physical 

molecules of biogas since these fuels 

only go through a physical process in 

which the biogas is compressed or 

liquefied, and that because CNG and 

LNG can be used directly for 

transportation purposes, thus meeting 

the provisions in sections 80.1426(f)(10) 

and (11), we concluded that CNG and 

LNG could qualify under the existing 

pathway. For the reasons discussed 

above, we are proposing to amend the 

existing biogas pathway to clearly state 

that only CNG and LNG produced from 

biogas from landfills, waste treatment 

plants and waste digesters, and used as 

transportation fuel, qualify as a 

cellulosic or advanced biofuel for RIN 

generation under the RFS2 program. 

The current regulations provide a 

pathway for biogas produced from a biodigester which uses manure. We are also 

proposing to expand the type of 

materials that may be used to produce 

CNG/LNG in a digester to include 

animal wastes, biogenic waste oils/fats/ 

greases, separated food and yard wastes, 

and crop residues. These feedstock 

sources are already eligible in the 

existing rules pathways and therefore 

should reasonably be added to the biodigester pathway. We are doing so in 

response to a petition request to 

generate RINs from biogas which is 

produced from bio-feedstock sources in 

addition to the already allowed manure, 

either individually or in combination 

with manure in a bio-digester. As with 

other LCA pathways using these 

materials, EPA is proposing to assume 

these waste materials do not have 

emissions associated with feedstock 

production, and therefore qualify as 

cellulosic or advanced renewable fuels 

when used to produce CNG/LNG. 

To provide improvement for this 

revised pathway, we are proposing to 

revise the definition of biogas and add 

new definitions for renewable CNG and 

renewable LNG to section 80.1401 to 

read as follows: 

We are proposing Biogas would mean a 

mixture of hydrocarbons that is a gas at 60 

degrees Fahrenheit and 1 atmosphere of 

pressure that is produced through the 

conversion of organic matter. We are also 

proposing that Biogas would include landfill 

gas, gas from waste digesters, and gas from 

waste treatment plants. Waste digesters 

would include digesters processing animal 

wastes, biogenic waste oils/fats/greases, 

separated food and yard wastes, and crop 

residues. Waste treatment plants would 

include wastewater treatment plants and 

publicly owned treatment works. 

We are proposing that Renewable 

compressed natural gas (‘‘renewable CNG’’) 

would mean biogas that is processed to the 

standards of pipeline natural gas as defined 

in 40 CFR 72.2 and that is compressed to 

pressures up to 3600 psi. We are also 

proposing that only renewable CNG that 

qualifies as renewable fuel and is used for 

transportation fuel can generate RINs. 

We are proposing that Renewable liquefied 

natural gas (‘‘renewable LNG’’) would mean 

biogas that is processed to the standards of 

pipeline natural gas as defined in 40 CFR 

72.2 and that goes through the process of 

liquefaction in which the biogas is cooled 

below its boiling point and weighs less than 

half the weight of water so it will float if 

spilled on water. We are also proposing that 

only renewable LNG that qualifies as 

renewable fuel and is used for transportation 

fuel can generate RINs. 

2. New Registration (Contract 

Requirements) for Renewable Electricity 

and Fuels Produced From Biogas That 

Qualify as Renewable Fuel and That Are 

Registered for RIN Generation 

The regulations as currently written 

allow a producer of biogas or renewable 

electricity 41 that qualifies as renewable 

fuel and has an approved fuel pathway 

in Table 1 of section 1426(f)(1) to 

register and generate RINs for the 

volume it produces under the RFS2 

program. We modified the existing 

regulations to state that biogas is the 

feedstock used to produce renewable 

fuel, as described above. The revised 

regulations in sections 1426(f)(10) and 

(11) detail the requirements for 

distribution and tracking for renewable 

electricity and biogas used to produce 

fuel that qualifies as renewable fuel that 

can either be distributed in a dedicated 

pipeline or transmission line or 

distributed in a shared pipeline or 

power grid system. The purpose of these 

requirements is to provide EPA 

assurance and verification that once the 

biogas or renewable electricity is put 

into a dedicated or shared distribution 

system that in fact an equivalent volume 

of biogas or renewable electricity will be 

used for transportation fuel, and for no 

other purposes. The requirements are 

also meant to address concerns of 

double counting of the biogas or 

renewable electricity, especially in 

situations that the biogas or renewable 

electricity is placed in or loaded onto 

shared distribution systems that contain 

gas or electricity from non-renewable 

biomass sources. EPA intended to 

require producers to submit the 

information and contract requirements 

in sections 1426(f)(10) and (11) as part 

of the registration requirements for 

renewable electricity and renewable 

fuels produced from biogas that are used 

for transportation 42 fuel, but had not 

done so in the prior rulemakings. 

Therefore, as a natural outgrowth of the 

regulations for implementation and 

compliance purposes, we are proposing 

in this rulemaking to incorporate the 

requirements in sections 1426(f)(10) and 

(11) as part of registration requirements 

for producers of renewable electricity 

and renewable fuels produced from 

biogas that qualify as renewable fuel 

under the regulations under section 

1450(b)(1)(iv)(C). 

Section 1426(f)(11)(ii) of the 

regulations requires that, in order for 

renewable fuel made from biogas 

withdrawn from a commercial 

distribution system for use as a 

transportation fuel to generate RINs, the 

biogas introduced into the system must 

have been added to a common carrier 

pipeline. We propose to add a similar 

provision to section 1426(f)(11)(i) for 

renewable electricity, requiring a 

company to load the renewable 

electricity to a power grid shared by the 

second company that withdraws the 

electricity, such that the two companies 

must be physically connected to the 

same grid or located within the same 

area. 

EPA is requesting comments about 

whether the other existing requirements 

in sections 1426(f)(10) and (11) for 

renewable electricity and renewable 

fuels from biogas used for transportation 

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43Refer to preamble discussion for these various 

biogas pathways in section titled, ‘‘Lifecycle 

Greenhouse Gas Emissions Analysis for Renewable 

Electricity, Renewable Diesel and Naphtha 

Produced from Landfill Biogas.’’ 

fuel are sufficient to provide assurance 

and verification for the following 

situations. First, do the proposed 

requirements provide assurance and 

verification that the same amount of 

biogas or renewable electricity is in fact 

delivered to the renewable fuel 

producer or end user who will actually 

use the biogas or renewable electricity 

for transportation purposes? If the 

proposed requirements are not 

sufficient, what alternative requirements 

should be considered? Second, are the 

proposed requirements sufficient to 

ensure that double counting does not 

occur, e.g., to ensure that the biogas or 

renewable electricity once it is loaded 

into a shared pipeline or power grid is 

not sold to multiple clients or for 

purposes other than for transportation 

purposes? Similarly, if the proposed 

requirements are not sufficient, what 

alternative requirements could be 

considered to ensure double counting 

does not occur? 

3. Changes Applicable to All Biogas 

Related Pathways for RIN Generation 

As discussed above, we have had 

many inquiries related to the ‘‘biogas’’ 

pathway, specifically regarding contract 

requirements for tracking the biogas 

through the distribution system and 

regarding what company along the 

production chain is considered the 

‘‘producer’’ and eligible to generate 

RINs under the RFS2 program. In this 

rulemaking, we are proposing to revise 

and add new requirements for contracts 

to track the biogas as it moves into and 

out of the distribution system, as well as 

provisions on registration, reporting and 

recordkeeping. These proposed 

amended requirements are applicable to 

all pathways related to biogas that are 

eligible for RIN generation that are 

existing or proposed in this rulemaking. 

In response to the question of what 

company is considered the producer of 

renewable fuel and eligible to generate 

RINs under the RFS program, we 

propose to clarify who is the ‘‘producer’’ 

for renewable CNG/LNG and renewable 

electricity. We propose that the 

‘‘producer’’ of renewable CNG/LNG is 

the company that compresses or 

liquefies the gas and distributes the 

CNG/LNG for transportation fuel, and 

for renewable electricity, the 

‘‘producer’’ is the company that 

distributes the electricity for use as 

transportation fuel. There are two 

registration situations that this 

clarification will address: (1) The 

owner/operator of a landfill collects 

biogas and processes it to a qualifying 

renewable CNG/LNG/electricity for 

transportation use and distributes on 

site and (2) the owner/operator of a 

landfill collects biogas and it is 

processed into a qualifying renewable 

CNG/LNG/electricity for transportation 

use by a contracted third party and 

distributed by this third party. The party 

that converts the biogas to renewable 

CNG/LNG/electricity and distributes for 

use as a transportation fuel is 

responsible for RIN generation. Under 

the first scenario, the registration 

package, including the engineering 

review, would cover the biogas source 

(landfill, waste digester, etc.) as well as 

the distribution that is occurring on site. 

Under the the second scenario, the 

registration package, including 

engineering review, would cover the 

biogas source (landfill, waste digester, 

etc.) the pipeline (common carrier or 

dedicated) and each distribution 

facility. By requiring the party that is 

responsible for conversion and 

distribution to register as the RIN 

generator, we can prevent RINs from 

being generated for a batch or renewable 

CNG/LNG/electricity prior to use as a 

qualifying transportation fuel. For any 

of the fuels, the company designated as 

the ‘‘producer’’ will be required to 

register under the RFS2 program. We 

seek comment on our proposed 

definition of producer regarding 

renewable CNG/LNG and renewable 

electricity. 

We acknowledge that the process 

train from raw biogas to the final 

transportation fuel is complex, and may 

include many companies and 

processing steps from the point when 

the raw biogas is withdrawn from its 

source (such as landfills, waste 

digesters, waste treatment plants), 

processed and converted into biofuel 

and distributed to consumers. 

Alternatively, the fuel may be cleaned at 

a biogas facility to pipeline quality 

specifications for distribution, and then 

withdrawn from the commercial 

pipeline to be processed further at 

another production facility into 

renewable CNG/LNG or renewable 

electricity. Due to the complexity of the 

many entities potentially involved in 

this process train, we are proposing that 

the company deemed as the ‘‘producer’’ 

under the qualifications described above 

also be responsible for providing all the 

required information and supporting 

documentation in their registration, 

reporting and recordkeeping to track 

and verify the information from point of 

extraction of the raw biogas from its 

original source, and all the processing 

steps and distribution in between, to the 

last step where the actual fuel is used 

for transportation purposes. In the 

engineering review report required for 

registration, the producer must include 

documentation that the professional 

engineer performed site visits at each 

production facility, including the biogas 

facility and the facility that produces 

the final fuel (if these are not the same 

facility). The producer must also review 

and verify all related supporting 

documents such as design documents, 

calculations, regulatory permits, and 

contracts between facilities that track 

the raw biogas from the point of 

withdrawal from its source, the various 

injection/withdraw points into the 

distribution pipeline, the various 

production facilities, and the final step 

for use as transportation fuel. We 

believe these requirements will ensure 

that producers will perform due 

diligence that the fuel for which they 

generate RINs under the RFS2 program 

are in compliance with all the 

regulatory requirements for renewable 

fuel. The proposed registration, 

reporting and recordkeeping 

requirements are in sections 80.1426(f), 

80.1450, 80.1451 and 80.1454 in this 

rulemaking. Additional changes 

regarding the contract requirements for 

distribution of the biogas in shared 

commercial pipelines are discussed 

below, and can be located in sections 

80.1426(f)(10), (11), and (13). 

4. Changes Applicable To Process 

Electricity Production Requirement for 

the Biogas-Derived Cellulosic Diesel and 

Naphtha Pathways 

In this proposed rulemaking, EPA 

conducted greenhouse gas (GHG) 

lifecycle analysis for various renewable 

fuels produced from landfill gas as new 

or revised advanced and cellulosic 

biofuel pathways that will be added to 

Table 1 to section 80.1426(f).43 For some 

of these pathways, we are proposing to 

add various registration, recordkeeping 

and reporting requirements to the 

regulations to ensure that the facilities 

using these pathways meet the 

parameters stipulated in the lifecycle 

analysis. The additional registration, 

recordkeeping and reporting 

requirements are discussed in detail 

below. 

For the proposed fuel pathways for 

cellulosic diesel and cellulosic naphtha 

produced from landfill gas, we are 

proposing to require the renewable fuel 

production facility to produce a 

minimum of 20 percent of the process 

electricity used at the facility on a 

calendar year basis, from raw landfill 

gas, waste heat from the production 

process, unconverted syngas from the 

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36056 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

44See specifically § 80.1401 Definitions. 

F–T process, fuel gas from the 

hydroprocessing or combined heat and 

power (CHP) units that use non-fossil 

fuel based gas or other renewable 

sources. We propose that if less than 20 

percent (on an annual average basis) of 

process energy comes from one of these 

alternative sources, then no cellulosic 

RINs can be generated for that year. 

For the renewable fuel production 

facility applying to use the proposed 

fuel pathway with the requirement to 

internally produce at least 20 percent of 

the total amount of process electricity 

used at its facility, we are proposing the 

facility submit to EPA the information 

described below to demonstrate 

compliance with this requirement. For 

registration purposes, we are proposing 

that producers submit the following 

additional information in the process 

fuel supply plan that is currently 

required as part of the registration 

process (estimated summaries are to be 

reported on an annual/calendar year 

basis): 

—Estimated amount of total electricity 

used at the facility 

—Estimated amount of total electricity 

purchased for the facility 

—Estimated amount of total renewable 

electricity produced on-site, including 

the source of the energy and the 

equipment and/or process used to 

generate the renewable electricity 

—Calculation that verifies the facility 

meets the specified 20 percent 

minimum electricity production 

requirement based on the reported 

total amount of electricity used at the 

facility, total amount of electricity 

purchased, and total amount of 

renewable electricity produced 

For reporting purposes, we are 

proposing for producers to submit the 

following additional information as part 

of their existing quarterly and annual 

reporting obligations (reported amounts 

should be provided as monthly 

summaries on an annual/calendar year 

basis, and must be obtained from a 

utility meter that is continuously 

measured): 

—Actual total amount of electricity used 

at the facility 

—Actual total amount of electricity 

purchased for the facility 

—Actual amount of total renewable 

electricity produced on-site, including 

source of energy and the equipment or 

process used to generate the 

renewable electricity 

—Calculation that verifies the facility 

meets the specified 20 percent 

minimum electricity production 

requirement based on the reported 

total amount of electricity used at the 

facility, total amount of fossil-fuel 

based electricity purchased, and total 

amount of renewable electricity 

produced 

For recordkeeping purposes, we are 

proposing that producers retain the 

additional information, calculations and 

supporting documents required for 

registration and reporting as discussed 

above. The regulatory requirements for 

registration, reporting and 

recordkeeping as discussed in this 

proposed rulemaking can be located in 

the following applicable regulatory 

sections 80.1450, 80.1451 and 80.1454, 

respectively. 

D. Amendment to the Definition of 

‘‘Crop Residue’’ and Definition of a 

Pathway for Corn Kernel Fiber 

We propose to amend the definition 

of ‘‘crop residue’’ so that this category 

includes only feedstock sources that are 

determined by EPA would not result in 

a significant increase in direct or 

indirect GHG emissions. ‘‘Crop residue’’ 

is the biomass left over from the 

harvesting or processing of planted 

crops from existing agricultural land 

and any biomass removed from existing 

agricultural land that facilitates crop 

management (including biomass 

removed from such lands in relation to 

invasive species control or fire 

management), whether or not the 

biomass includes any portion of a crop 

or crop plant. Biomass is considered 

crop residue only if the use of that 

biomass for the production of renewable 

fuel has no significant impact on 

demand for the feedstock crop, products 

produced from that feedstock crop, and 

all substitutes for the crop and its 

products including the residue, nor any 

other impact that would result in a 

significant increase in direct or indirect 

GHG emissions. 

EPA is amending the definition of 

‘‘crop residue’’ to confirm the meaning 

of the term ‘‘left over’’ in the text of this 

definition. The phrase ‘‘left over’’ in our 

original definition of ‘‘crop residue’’ is 

meant to indicate that the use of a 

residue as a biofuel feedstock should 

not increase demand for the crop it is 

derived from, should not induce further 

crop production, and should not result 

in additional direct or indirect GHG 

emissions. The residue must come from 

crop production or processing for some 

other primary purpose (e.g., refined 

sugar, corn starch ethanol), such that the 

crop residue is not the reason the crop 

was planted. The residue must also 

come from existing agricultural land, 

the exact definition of which is laid out 

in our current regulations that define 

‘‘renewable biomass’’.44 Further, the 

residue should generally not have a 

significant market in its own right, to 

the extent that removing it from that 

market to produce biofuels instead will 

result in increased GHG emissions. EPA 

is seeking comments on this revision to 

the crop residue definition. EPA invites 

all comments regarding this revision, 

but specifically invites comments 

regarding the potential for the revision 

to create a significant shift in direct or 

indirect GHG emissions and what ought 

to constitute a ‘‘significant’’ increase or 

decrease in GHG emissions in the 

context of this definition. 

EPA has previously identified several 

potential feedstocks that we believe 

meet the criteria of crop residue. Table 

IV.D.–1 lists feedstocks which may fit 

the definition of crop residue. Most of 

these feedstocks were discussed in the 

final RFS2 rulemaking. For example, 

EPA analyzed the agricultural sector 

GHG emissions of using corn stover for 

biofuels in the final RFS2, and found 

that fuel produced from this feedstock 

met the 60% GHG reduction threshold 

for cellulosic biofuels. Since the direct 

and indirect impacts of citrus residue, 

rice straw, and wheat straw removal 

were expected to be similar to corn 

stover, EPA also applied the land use 

change impacts associated with corn 

stover to citrus residue, rice straw, and 

wheat straw. Based on that analysis, 

EPA found that fuels produced from 

citrus residues, rice straw, and wheat 

straw also met the 60% reduction 

threshold. EPA further determined that 

fuels produced from materials left over 

after the processing of a crop into a 

useable resource had land use impacts 

sufficiently similar to agricultural 

residues to also meet the 60% threshold. 

EPA specifically cited bagasse left over 

from sugarcane processing as an 

example of this type of residue. EPA is 

seeking comment on whether the 

feedstocks on this list should be 

considered crop residues, if these 

feedstocks would have similar direct 

and indirect impacts as corn stover, and 

whether additional feedstocks should 

also be included in this list. 

TABLE IV.D.–1—FEEDSTOCKS THAT

MAY QUALIFY AS CROP RESIDUE

Feedstock D Code 

Sugarcane Bagasse.D–3 Cellulosic biofuel. 

Corn Kernel Fiber 

(excluding the 

corn starch component).

D–3 Cellulosic biofuel. 

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45See specifically § 80.1426(f)(1). 

46See specifically § 80.1426(f)(3). 

47See, e.g., Kim, E.J., C.M. Parsons, R. Srinivasan, 

and V. Singh. 2010. Nutritional composition, 

nitrogen-corrected true metabolizable energy, and 

amino acid digestibilities of new corn distillers 

dried grains with solubles produced by new 

fractionation processes. Poultry Science 89, p. 44, 

available on the docket for this rulemaking. See also 

additional studies cited within Kim et al 2010. 

48See Shurson, G.C. 2006. The Value of HighProtein Distillers Coproducts in Swine Feeds. 

Distillers Grains Quarterly, First Quarter, p. 22, 

available on the docket for this rulemaking. 

TABLE IV.D.–1—FEEDSTOCKS THAT

MAY QUALIFY AS CROP RESIDUE— 

Continued 

Feedstock D Code 

Corn Stover ........... D–3 Cellulosic biofuel. 

Citrus Residue ...... D–3 Cellulosic biofuel. 

Rice Straw ............. D–3 Cellulosic biofuel. 

Wheat Straw ......... D–3 Cellulosic biofuel. 

While EPA believes that, under 

current conditions, generation of RINs 

for batches of renewable fuel produced 

from the feedstocks listed in Table 

IV.D.–1 above would not result in a 

significant increase in direct or indirect 

GHG emissions, we also acknowledge 

the potential for this assessment to 

change in the future based on 

unforeseeable factors. For example, 

some new use for one of these products 

could be developed which would 

change our assessment that the 

feedstock has no significant market in 

its own right. Further, it is possible that, 

at some point in the future, large enough 

quantities of renewable fuel could be 

produced from one of these fuels to 

create demand pull for the feedstock, 

potentially altering the behavior of 

producers of the residue and leading to 

significant increases in direct or indirect 

GHG emissions. To our knowledge, this 

is not currently the case for any of the 

feedstocks listed above. However, EPA 

will continue to monitor RIN generation 

from fuel produced using each of these 

feedstocks and the general use of these 

feedstocks in the marketplace. We 

further reserve the right to revisit the 

status of any feedstock that we have 

determined qualifies under the crop 

residue pathway. Should any feedstock 

qualifying as a crop residue be used to 

generate significant quantities of ethanol 

in the future, or should a significant 

market emerge for the product such that 

there is demand pull for it in excess of 

the demand pull for the planted crop 

from which it is a derived byproduct, 

we will revisit whether that feedstock 

should remain under the crop residue 

pathway or be subjected to further 

scrutiny. EPA is seeking comment on 

this approach and on the potential for 

significant demand pull to emerge for 

the feedstocks we are proposing to 

consider as crop residues. 

We also propose that this definition of 

‘‘crop residue’’ includes corn kernel 

fiber. Corn kernel fiber is not 

specifically mentioned as a type of crop 

residue under the Renewable Fuel 

Standard (RFS2) regulations. Per the 

RFS2 definition of ‘‘crop residue’’, EPA 

must evaluate whether corn kernel fiber 

is ‘‘left over from the harvesting or 

processing of planted crops’’ and that it 

has no ‘‘impact that would result in a 

significant increase in direct or indirect 

GHG emissions’’ for this feedstock to 

qualify as a residue. 

One additional consideration in the 

classification of corn kernel as a crop 

residue is the fact that some amount of 

corn starch might still adhere to the 

corn kernel after separation. The 

percentage of contamination will vary, 

but as much as 20% of the final fuel 

could be derived from corn starch. By 

definition, corn starch ethanol can only 

qualify as a renewable fuel, not as an 

advanced fuel. However, our current 

regulations state that ‘‘producers and 

importers may disregard any incidental, 

de minimis feedstock contaminants that 

are impractical to remove and are 

related to customary feedstock 

production and transport’’.45 Therefore, 

EPA is seeking comment on whether the 

definition of crop residue should be 

amended to explicitly exclude the corn 

starch component. 

EPA also invites comment on how 

RINs should be allocated for ethanol 

derived from corn fiber. EPA has 

existing regulations that define 

procedures for generating RINs from 

batches of fuel that contain multiple 

feedstocks, including feedstocks that 

generate RINs of different D codes.46 We 

believe that these regulations provide 

sufficient guidance to producers and 

importers regarding how to assign RINs 

to batches of renewable fuel that can be 

described by two or more pathways 

(e.g., corn starch ethanol and corn 

kernel fiber ethanol). However, we 

invite comment on the sufficiency of 

these regulations with regards to the 

assignment of RINs to coprocessed 

batches of corn starch ethanol and corn 

kernel fiber ethanol, including whether 

producers have the technological 

capability to adequately demonstrate 

volume produced under each pathway. 

To determine whether the use of corn 

kernel fiber to produce ethanol would 

lead to increased direct or indirect GHG 

emissions, EPA conducted a detailed 

assessment of the two major potential 

sources of emissions from this 

feedstock, namely effects on feed 

markets and effects on demand for corn. 

The proposed method of acquiring corn 

kernel fiber is to extract it from matter 

that is otherwise converted to dried 

distillers grains (DDG) during the dry 

mill corn ethanol process. 

Consequently, this analysis relied 

significantly on the assessment of corn 

starch ethanol-derived DDG that was 

conducted for the RFS2 final rule, 

adjusting the analysis to account for the 

extraction of fiber from this product. 

The analysis also drew substantially on 

the available scientific literature on low 

fiber DDG (LF–DDG), as well as the 

expertise of the U.S. Department of 

Agriculture. Potential producers also 

submitted important data to EPA that 

helped determine whether producing 

cellulosic ethanol from corn kernel fiber 

would result in a significant increase in 

GHG emissions. This included a full 

nutritional analysis of LF–DDG for 

swine, poultry, and cattle. 

EPA found that extracting the fiber 

from corn matter used to produce 

standard DDG would not have a 

significant effect on feed markets. 

Processors who extract the fiber from 

corn produce a feed product known as 

LF–DDG, as opposed to standard DDG 

which retains the fiber. The scientific 

literature on LF–DDG animal nutrition 

has found that this product has at least 

equal, and perhaps even slightly 

superior, nutritional value for swine and 

poultry compared to standard DDG.47

This means that, even though the 

physical volume of the DDG produced 

by ethanol plants using corn kernel fiber 

extraction technology will be somewhat 

smaller, its nutritional content for swine 

and poultry will be equivalent to or 

greater than their output without fiber 

extraction. 

Conversely, LF–DDF is an inferior 

feed for cattle compared to standard 

DDG, since ruminants benefit from 

ingesting corn fiber in DDG.48 Therefore, 

EPA expects swine and poultry 

producers to absorb the supply of LF– 

DDG, while the cattle and dairy industry 

will continue to consume standard 

DDG. With this dynamic in place, fiber 

extraction from DDG should not 

significantly affect feed markets, since 

there will be no reduction in the overall 

supply of DDG in terms of nutritional 

content nor will there be any impact on 

aggregate demand for other animal feed 

sources. 

If enough corn ethanol producers 

adopt fiber extraction technology, LF– 

DDG could saturate swine and poultry 

demand and spill over into dairy and 

cattle feed markets. If a situation arises 

where LF–DDG begin to replace 

standard DDG in cattle markets, this 

could lead to an increase in feed 

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36058 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

demand, most likely in the form of 

increased demand for fiber supplements 

in dairy and cattle feed. This could 

cause an increase in GHG emissions. If 

swine and poultry demand for LF–DDG 

becomes saturated, demand for standard 

DDG in the cattle and dairy industries 

should create sufficient market 

incentives for the remaining corn starch 

ethanol producers to decide against 

adopting corn fiber ethanol production. 

EPA believes this will prevent a 

situation where there is insufficient 

supply of standard DDG in the cattle 

and dairy industries. However, as noted 

above, EPA reserves the right to 

reexamine corn kernel fiber as a 

feedstock in the future. 

EPA’s analysis indicates that 

producing cellulosic ethanol from corn 

kernel fiber is unlikely to increase 

overall demand for corn. In order to 

meet the definition of a crop residue, 

the source of corn kernel fiber must be 

a crop processing facility (e.g., a corn 

starch ethanol plant). A corn kernel 

fiber ethanol producer cannot purchase 

whole corn specifically for the 

generation of corn fiber ethanol and still 

qualify their feedstock as crop residue. 

EPA is seeking comment on this 

analysis. 

Based on our assessment, EPA 

proposes that corn kernel fiber would 

meet the definition of a crop residue, 

and qualify for Cellulosic Ethanol and 

Advanced Biofuel (D-codes 3 & 5, 

respectively) RINs under the RFS2. EPA 

is seeking comment on whether corn 

kernel fiber should be considered a crop 

residue. 

E. Consideration of Advanced Butanol 

Pathway 

1. Proposed New Pathway 

EPA is proposing to add a new 

pathway to Table 1 to section 80.1426 

that allows butanol made from corn 

starch using a combination of advanced 

technologies to meet the 50% GHG 

emissions reduction needed to qualify 

as an advanced renewable fuel. This 

pathway applies to dry mill 

fermentation facilities that use natural 

gas and biogas from an on-site thin 

stillage anaerobic digester for process 

energy with combined heat and power 

(CHP) producing excess electricity of at 

least 40% of the purchased natural gas 

energy of the facility (the proposed 

‘‘advanced butanol pathway’’). 

GEVO Incorporated submitted a 

petition requesting authorization to 

generate D-code 5 RINs for fuel 

produced through the GEVO butanol 

pathway. A petition is required because 

the proposed process utilizes a high 

yield butanol fermentation process that 

is different from those analyzed as part 

of the RFS2 corn ethanol pathways, and 

does not use the approved advanced 

technologies shown in Table 2 to 

section 80.1426 of the RFS2 regulations. 

EPA’s evaluation of the lifecycle GHG 

emissions of the advanced butanol 

pathway under this petition request is 

consistent with EISA’s applicable 

requirements, including the definition 

of lifecycle GHG emissions and 

threshold evaluation requirements. It 

was based on information regarding 

GEVO’s production process that was 

submitted under a claim of Confidential 

Business Information (CBI) by GEVO on 

April 11, 2011. The information 

provided included the mass and energy 

balances necessary for EPA to evaluate 

the lifecycle GHG emissions of the 

advanced butanol pathway. 

The lifecycle GHG emissions of fuel 

produced pursuant to the advanced 

butanol pathway were determined as 

follows: 

Feedstock production—The advanced 

butanol pathway uses corn starch as a 

feedstock. Corn starch is one of the 

feedstocks already listed in Table 1 to 

section 80.1426 of the RFS2 regulations. 

Since corn starch has already been 

evaluated as part of the RFS2 final rule, 

no new feedstock production modeling 

was required. 

The FASOM and FAPRI models were 

used to analyze the GHG impacts of the 

feedstock production portion of the 

fuel’s lifecycle. The same FASOM and 

FAPRI results representing the 

emissions from an increase in corn 

production that were generated as part 

of the RFS2 final rule analysis of the 

existing corn butanol pathways were 

used in this analysis of the advanced 

butanol pathway. These results 

represent agriculture/feedstock 

production emissions for a certain 

quantity of corn produced. For the RFS2 

analysis, this was roughly 960 million 

bushels of corn used to produce 2.6 

billion gallons of fuel. We have 

calculated GHG emissions from 

feedstock production for that amount of 

corn. EPA does not believe the 

advanced butanol process for converting 

corn into butanol will materially affect 

the total amount of corn used for 

biofuels and modeled as part of the 

RFS2 final rule. Based on information 

provided by industry, the technologies 

to produce corn butanol are primarily 

being targeted at retrofitting existing 

corn ethanol facilities, where the 

infrastructure to produce renewable 

fuels already exists and the capital 

expenditures would be relatively small. 

Therefore, the existing agricultural 

sector modeling analyses for corn as a 

feedstock remain valid for use in 

estimating the lifecycle impact of 

renewable fuel produced using the 

advanced butanol pathway. The Agency 

is seeking comment on whether there is 

any research to suggest that converting 

corn into an advanced butanol pathway 

would materially affect the total amount 

of corn used. 

GEVO provided, as part of the 

information claimed CBI, their process 

yield in terms of gallons of fuel 

produced per bushel of corn. Based on 

the data, GEVO’s process yield is 

slightly more efficient than the 

pathways modeled as part of the RFS2 

rulemaking. Therefore, compared to the 

corn butanol pathways already 

analyzed, the GEVO process results in 

0.93% more Btus of fuel produced for 

the same amount of corn feedstock. 

Fuel production—The fuel production 

method included in this advanced 

butanol pathway involves the 

production of butanol from corn starch 

in a dry mill. The amount and type of 

energy used in this analysis is different 

than production methods that were 

analyzed under the final rule. While 

there were slight differences in the total 

amount of natural gas and electricity 

used in this analysis, the main 

difference was the use of biogas and 

production of excess electricity. To 

analyze the GHG impacts of the 

advanced butanol pathway, EPA 

utilized the same approach that was 

used to determine the impacts of 

processes in the RFS2 corn butanol 

pathways. 

The amount and type of energy used 

was taken from GEVO’s mass balance & 

energy balance submitted to EPA. GEVO 

submitted energy data on natural gas 

and biogas (in Btus) and electricity (in 

kWhs) inputs, as well as gallons of fuel 

produced. Biogas and natural gas are 

used in combination, while the RFS2 

corn butanol analyses only considered 

natural gas or biogas used 

independently, not in combination. 

The emissions from the use of energy 

were calculated by multiplying the 

amount of energy by emission factors for 

fuel production and combustion, based 

on the same method and factors used in 

the RFS2 final rulemaking. The 

emission factors for the different fuel 

types are from GREET and were based 

on assumed carbon contents of the 

different process fuels. 

One area where EPA is soliciting 

comments is on the most appropriate 

energy content assumption to use for 

butanol (lower heating value). As part of 

this analysis, EPA used the GREET 

value for the energy content of butanol, 

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Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 36059 

49The GREET value is based on: Guibet, J.-C., 

1997, Carburants et Moteurs: Technologies, Energie, 

Environnement, Publication de l’Institut Franc ̧ais 

du Pe ́trole, ISBN 2–7108–0704–1. 

which is 99,837 Btus per gallon.49

Differences in the measurement of the 

energy content of butanol can occur for 

a number of reasons including 

variations amongst isomers (t-butanol, 

n-butanol, isobutanol, and sec-butanol), 

and differences in testing 

methodologies. EPA is seeking comment 

on whether there are any reasons why 

EPA should change its assumptions and 

use a different energy content of 

butanol. 

The RFS2 corn butanol pathways 

included an estimate for DDGs coproduct production which we similarly 

applied to the advanced butanol 

production process. Since DDGs impact 

the agricultural markets, production of 

DDGs was already included as part of 

the FASOM and FAPRI modeling 

already described in the feedstock 

production section, above. Thus no 

additional co-product credits for the 

DDGs are applied for the fuel 

production stage of the analysis. 

The advanced butanol production 

process analyzed here also results in 

excess electricity production. As per the 

pathway description the process 

produces excess electricity of at least 

40% of the purchased natural gas energy 

of the facility. The onsite emissions of 

the electricity production are accounted 

for in the facility natural gas and biogas 

use. The co-product credit of the excess 

electricity is accounted for by assuming 

the electricity offsets average grid 

electricity production and results in 

associated emission reductions. 

The estimated production emissions 

from the advanced butanol process are 

shown below in Table V.F.–1. 

TABLE V.F.–1—FUEL PRODUCTION EMISSIONS FOR THE ADVANCED BUTANOL PROCESS

Fuel production source GEVO isobutanol 

(g CO2-eq./mmBtu) 

On-Site Emissions ............................................................................................................................................................... 15,273 

Upstream (natural gas and electricity production) .............................................................................................................. 2,424 

Emissions Credit from Offset Electricity .............................................................................................................................. ¥17,448 

Total Fuel Production Emissions ..................................................................................................................................... 249 

Fuel and feedstock distribution—We 

used the same feedstock distribution 

emissions assumption considered for 

corn butanol under the RFS2 final rule 

for the advanced butanol pathway corn 

feedstock. The fuel type, butanol, and 

hence the fuel distribution for butanol, 

was already considered as part of the 

RFS2 final rule. Therefore, the existing 

feedstock and fuel distribution lifecycle 

GHG impacts for corn butanol were 

applied to the advanced butanol 

pathway analysis. 

Use of the fuel—The advanced 

butanol pathway produces a fuel that 

was analyzed as part of the RFS2 final 

rule. Thus, the fuel combustion 

emissions calculated as part of the RFS2 

final rule for butanol were applied to 

our analysis of the advanced butanol 

pathway. 

The advanced butanol fuel was then 

compared to baseline petroleum 

gasoline, using the same value for 

baseline gasoline as in the RFS2 final 

rule analysis. The results of the analysis 

indicate that the advance butanol 

pathway would result in a GHG 

emissions reduction of 51.3% compared 

to the gasoline fuel it would replace. 

Based on our LCA, we are proposing 

to add a new pathway to Table 1 to 

section 80.1426 that includes butanol 

from corn starch using the butanol 

process described here as an advanced 

biofuel (D–5 RINs). EPA invites 

comments on the assumptions used in 

this analysis. 

Table V.F.–2 below breaks down by 

stage the lifecycle GHG emissions for 

the RFS2 corn butanol pathway, the 

advanced butanol pathway and the 2005 

gasoline baseline. This table 

demonstrates the contribution of each 

stage in the fuel pathway and its relative 

significance in terms of GHG emissions. 

TABLE V.F.–2—LIFECYCLE GHG EMISSIONS FOR THE ADVANCED BUTANOL PATHWAY, 2022 

[Kg CO2-eq./mmBtu] 

Fuel type 

RFS2 corn 

ethanol, natural 

gas fired dry mill 

63% dry DDGS 

GEVO butanol 

RFS2 

2005 gasoline 

baseline 

Net Domestic Agriculture (w/o land use change) ............................................................ 4 4 ............................

Net International Agriculture (w/o land use change) ....................................................... 12 12 ............................

Domestic Land Use Change ........................................................................................... ¥4 ¥4 ............................

International Land Use Change, Mean (Low/High) ......................................................... 32 (21/46) 31 ............................

Fuel Production ................................................................................................................ 28 0 19 

Fuel and Feedstock Transport ........................................................................................ 4 4 * 

Tailpipe Emissions ........................................................................................................... 1 1 79 

Total Emissions, Mean ............................................................................................. 77 (66/91) 48 98 

% Reduction .................................................................................................................... ¥21% ¥51% ............................

* Emissions included in fuel production stage. 

Table V.F.–3 lists the proposed DCodes by fuel type (butanol), 

considering the feedstock (corn starch) 

and different production process 

requirements. 

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36060 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

TABLE V.F.–3—PROPOSED D CODES FOR BUTANOL

Fuel type Feedstock Production process requirements D-Code 

Butanol ............. Corn starch ....... Fermentation; dry mill using natural gas, biomass, or biogas for process energy ............... 6 

Butanol ............. Corn starch ....... Fermentation; dry mill using natural gas and biogas from on-site thin stillage anaerobic 

digester for process energy w/CHP producing excess electricity of at least 40% of the 

purchased natural gas energy used by the facility.

5 

2. Butanol, Biobutanol, and Volatility 

Considerations 

Butanol is a flammable colorless 

liquid that is used as a fuel and as an 

industrial solvent. Butanol is composed 

of the chemical elements hydrogen, 

oxygen, and carbon. It can be made from 

petroleum or renewable biomass, such 

as corn, grasses, agricultural waste and 

other renewable sources. It can be used 

in internal combustion engines as an 

additive to gasoline and is currently 

registered under the Fuel and Fuel 

Additives Registration System (FFARS) 

for use at up to 12 volume percent. A 

higher blend level would require a new 

FFARS registration that would include 

meeting Tier 1 and Tier 2 health effects 

testing requirements. Biobutanol is the 

common name for butanol made from 

renewable sources. 

There has been an increased interest 

in the use of biobutanol as a direct 

result of the requirements for increased 

use of renewable fuel volumes, adopted 

in EISA 2007. These provisions require 

an increase in the use of renewable 

fuels, with 36 billion gallons of 

renewable fuel to be used in the U.S. by 

2022. Parties required to meet these 

standards are interested in cost effective 

and practical ways to satisfy the 

standards and meet the performance 

needs of the vehicles and engines. 

Biobutanol is one attractive option 

because of its higher energy density, 

lower blending vapor pressure, and 

lower heat of vaporization in 

comparison to ethanol, as well as the 

fact that it can be distributed as a 

gasoline blend throughout the fungible 

gasoline distribution system. 

The Clean Air Act (section 211(h)(4)) 

requires EPA to adopt regulations 

limiting the volatility of gasoline during 

the summer months, when ozone is of 

most concern, including a one pound 

per square inch (psi) Reid Vapor 

Pressure (RVP) increase in the volatility 

limit for blends of gasoline containing 

9–10% ethanol (E10). This allowance 

for a 1 psi increase in allowable 

volatility is commonly called the 1 psi 

waiver. 

EPA’s regulations at 40 CFR 80.27 

adopt RVP standards that apply to the 

gasoline at all points in the distribution 

system, including the retail outlet. 

Under the provisions for the 1 psi 

waiver, blends of gasoline that contain 

from 9 volume percent to 10 volume 

percent ethanol are allowed to have 

volatility 1 psi higher than otherwise 

would be allowed (40 CFR 80.27(d)(2)). 

The chemical characteristics of ethanol 

are such that blends of gasoline with 

less than 9 volume percent to 10 volume 

percent ethanol would still have a 

significant increase in volatility. Thus 

the restriction on the 1 psi waiver to 

blends that have 9 volume percent to 10 

volume percent ethanol has the effect of 

prohibiting the blending of E10 with 

other gasoline/renewable fuel blends at 

any point in the gasoline distribution 

system (wholesale or retail) in 

conventional gasoline areas during the 

summer control season. Blends of E10 

gasoline and gasoline that is not E10 

would have less than 9 volume percent 

or greater than 10 volume percent 

ethanol, would have a resulting increase 

in volatility compared to E0, but would 

not have the 1 psi waiver to allow for 

such an increase. This increase would 

lead to an RVP above the allowable 

limit, unless a sub-RVP gasoline 

blendstock was used. The practical 

effect is a prohibition on commingling 

of E10 and gasoline blends other than 

E10. 

Under the current regulations, EPA 

applies the RVP standard to the 

commingled mixture as a whole, not to 

the components of the commingled 

mixture. Once the ethanol and nonethanol blends are mixed, the 

commingled mixture is treated as the 

gasoline that is tested and compared to 

the RVP standard. A single RVP value 

is determined by testing the volatility of 

the commingled mixture, and this is 

compared to the standard. If the mixture 

has from 9 volume percent to 10 volume 

percent ethanol, then the 1 psi waiver 

applies to the mixture. If the mixture 

has a different percentage of ethanol, 

whether lower or higher, then the 1 psi 

waiver does not apply to the mixture. 

This avoids a situation where there is 

an overall increase in volatility because 

of the commingling of E10 and gasoline 

that is not E10. As discussed below, the 

chemical characteristics of ethanol and 

the nonlinear nature of the volatility 

increase associated with varying 

volumes of ethanol, mean that mixing 

E10 gasoline with gasoline that is not 

E10 typically results in a net overall 

increase in emissions—the mixture has 

a higher volatility and emissions than 

the separate gasolines had on average 

before they were mixed. 

Several parties have identified this as 

an obstacle that currently inhibits the 

opportunity for biobutanol to enter the 

commercial market. The primary issue 

is application of the RVP regulations at 

the final point of fuel dispensing, when 

the biobutanol (Bu) and the ethanol 

blends would be mixed, that is in a 

storage tank at the retail station. When 

a butanol product that complies with 

the RVP standards prior to commingling 

(e.g., a complying Bu12 blend) is 

commingled with a compliant E10 in 

underground storage tanks at fuel 

dispensing facilities, the resulting mix 

generally would exceed the applicable 

RVP standard as EPA’s RVP regulations 

currently apply the standard. Certain 

fuels, including renewable biofuels such 

as butanol, however, do not have a net 

negative impact on RVP when blended 

with E10 at wholesale or retail. That is, 

the RVP and related emissions of the 

commingled blend of butanol and 

ethanol is no higher than the average 

RVP if the fuels had never been 

commingled. Thus, in these kinds of 

circumstances it may be appropriate to 

adopt a modified approach to applying 

the RVP standard to permit the 

commingling of complying E10 blends 

with complying butanol blends at 

wholesale and retail, as there is no 

overall degradation of RVP and the air 

quality impacts compared to what 

would occur if they were not blended. 

Today, the agency is providing some 

additional background on this issue and 

requesting information for use in 

deciding whether EPA can and should 

modify its RVP regulations as discussed 

below. Specifically, we are inviting 

comment on the ability of regulated 

parties to comply with the existing 

regulations by segregating biobutanol 

blends from ethanol blends and whether 

there is a need to change the 

regulations. We are also seeking 

comment on an alternative approach to 

applying the RVP standards to a 

commingled mixture of E10 with 

biobutanol or other approved gasoline 

additives, where the additives have 

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characteristics such that there is no net 

adverse emissions effect from the 

commingling. We are inviting comments 

as to whether the RVP standards can 

and should be applied such that the 

commingled mixture of E10 and 

specified blends of gasoline additives 

such as biobutanol is treated as 

complying with the RVP standard as 

long as the components of that mixture 

complied with the RVP standard prior 

to the commingling. This approach 

would provide a limited modification to 

how the RVP standards are applied, and 

the modification would apply for only 

certain fuel mixtures—those where the 

overall or net volatility of the 

commingled mixture is no higher than 

the weighted average of the original 

blends themselves, such that there is no 

adverse impact on emissions from the 

mixing compared to what would have 

occurred without such mixing. In order 

to assist parties in preparing comments, 

EPA is providing some additional 

background regarding the RVP program 

in the following paragraphs. 

Background and History of Volatility 

Regulations 

Reid Vapor Pressure (RVP) is the most 

common measure of gasoline volatility 

under ambient conditions. In 1989, EPA 

began reducing gasoline volatility by 

limiting its RVP (54 FR 11868, March 

22, 1989) (40 CFR 80.27). Due to the 

presence of gasoline in certain markets 

mixed with about 10 volume percent 

ethanol (known as gasohol at the time), 

and because blending an alcohol into 

gasoline increases the volatility of the 

final product, EPA provided an 

additional 1 psi allowance for such 

blends. In the absence of the 1 psi 

allowance, a special blend stock would 

have been required for such blends to 

comply with the RVP standards and 

such sub-RVP blendstocks did not exist 

at the time. EPA imposed the RVP 

standards at all points in the gasoline 

distribution system, i.e., anywhere 

gasoline is sold, supplied, offered for 

sale or supply or transported, including 

service stations, refinery shipping, 

tanks, importer shipping tanks, pipeline 

and bulk terminals and plants. (40 CFR 

80.28) (1989). In 1990, the agency 

promulgated additional regulations that 

further lowered the RVP standards. (55 

FR 23658, June 11, 1990). EPA 

continued to provide both the 1.0 psi 

allowance to fuel blends containing 

about 10 volume percent ethanol, (40 

CFR 80.27) (1990), and the requirement 

that RVP standards applied at all points 

in the distribution system. 

Congress largely codified the 

approach taken in EPA’s RVP 

regulations by adding a new section 

211(h) in the 1990 CAA amendments. 

Section 211(h)(1) requires EPA to set the 

maximum RVP standard during the high 

ozone season as 9.0 psi. EPA was to 

‘‘promulgate regulations making it 

unlawful for any person during the high 

ozone season to sell, offer for sale, 

dispense, supply, offer for supply, 

transport, or introduce into commerce 

gasoline with a Reid Vapor Pressure in 

excess of 9.0 pounds per square inch 

(psi).’’ Lower RVP standards could be 

set for ozone nonattainment areas. See 

Clean Air Act section 211(h)(1). Section 

211(h)(2) addresses the RVP standard 

that apply in attainment areas, and sets 

the standard at 9.0 psi for attainment 

areas with authority for EPA to set a 

more stringent RVP level under certain 

circumstances. In section 211(h)(2), 

Congress allowed a 1-psi waiver for E10 

gasoline, stating: ‘‘For fuel blends 

containing gasoline and 10 percent 

denatured anhydrous ethanol, the Reid 

vapor pressure limitation under this 

subsection shall be one pound per 

square inch (psi) greater than the 

applicable Reid vapor pressure 

limitations established under paragraph 

(1).’’ Additionally, Congress enacted a 

conditional defense against liability for 

violations of the RVP level allowed 

under the 1 psi waiver by stating that 

‘‘[p]rovided; however, that a distributor, 

blender, marketer, reseller, carrier, 

retailer, or wholesale purchaserconsumer shall be deemed to be in full 

compliance with the provisions of this 

subsection and the regulations 

promulgated there under if it can 

demonstrate that—(A) the gasoline 

portion of the blend complies with the 

Reid vapor pressure limitations 

promulgated pursuant to this 

subsection; (B) the ethanol portion of 

the blend does not exceed its waiver 

condition under subsection (f)(4) of this 

section; and (C) no additional alcohol or 

other additive has been added to 

increase the Reid Vapor Pressure of the 

ethanol portion of this blend.’’ Section 

211(h)(4). 

In a 1991 rulemaking, EPA modified 

the RVP regulations to conform to the 

1990 amendments (56 FR 64704, 

December 12, 1991). These regulations 

addressed the RVP standards in 

attainment areas, required the use of 

denatured anhydrous ethanol as a 

specific condition for the 1-psi waiver 

for fuel blends containing gasoline and 

from 9 volume percent to 10 volume 

percent ethanol, and included a new 

defense against liability for violations of 

the RVP standards for such fuel blends. 

We made no changes to the requirement 

that the RVP standards applied at all 

points in the distribution system. 

What modification is EPA considering 

to the application of the RVP standards 

to certain fuel blends? 

Gasoline and ethanol are mixed or 

blended after the refining process. The 

practice of blending ethanol with 

gasoline increases the RVP of the 

resulting blend by approximately 1.0 

psi. It is a non-linear relationship, most 

of the volatility increase occurs after just 

a few percent of ethanol have been 

added, with the volatility increasing 

more slowly as the gasoline ethanol 

blend increases to 10 volume percent. 

Above 10 volume percent the volatility 

generally does not increase any more, 

and at even higher levels of ethanol the 

volatility starts to decrease again. As 

explained above, section 211(h)(4) 

provides a 1-psi waiver for fuel blends 

containing gasoline from 9 volume 

percent to 10 volume percent ethanol. 

The absence of such a waiver would 

have required the creation of a 

production and distribution network for 

sub-9.0 psi RVP gasoline, to offset the 

increase in volatility associated with 

blending ethanol into the gasoline. At 

the time the costs of producing and 

distributing an additional grade of this 

type of fuel, especially in consideration 

of the low volumes of fuel being 

blended with ethanol at the time, would 

have likely been prohibitive and 

resulted in the termination of the 

availability of ethanol in the 

marketplace. Thus, the 1-psi waiver 

facilitated the participation of ethanol in 

the transportation fuel industry while 

also limiting gasoline volatility resulting 

from ethanol blending. 

But the RVP levels of gasoline 

actually used by consumers are 

dependent on the mixture of alcohol 

blends and gasoline that are 

commingling in either vehicle or storage 

tanks. Depending on the mixture, the 

resulting RVP level could be 

significantly higher than the average 

volatility of the fuels prior to the 

commingling. This is because the 

volatility increase when ethanol is 

added to gasoline is non-linear, with a 

large increase with the first few percent 

and then slowly tapering off as the 

concentration increases (see Illustration 

V.F.–4). In other words, mixing E10 and 

EO gasoline results in a net increase in 

the volatility of the gasoline mixture, 

compared to the average volatility that 

would occur absent such mixing. For 

example, 2000 gallons of 10 psi E10 

added to a service station tank with 

8000 gallons of 9.0 psi E0 would result 

in 10,000 gallons of fuel with a volatility 

of approximately 10 psi. However if the 

fuels had not been mixed, the average 

volatility of the 10000 gallons would 

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36062 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

have been 9.2 psi. The emissions 

associated with the commingled 

mixture (10000 gallons at 10 psi) would 

be significantly higher than the 

emissions associated with the two 

separate blends of 2000 gallons at 10 psi 

and 8000 gallons at 9 psi. The 

commingling thus results in an adverse 

environmental impact compared to 

what would occur absent the 

commingling. EPA’s current RVP 

regulations address this adverse 

emissions impact by applying the RVP 

standard to the commingled mixture as 

a single fuel. In this case the 

commingled mixture has an RVP of 10 

psi. The 1 psi waiver does not apply as 

the mixture is now 2% ethanol, not 

from 9 volume percent to 10 volume 

percent ethanol. The commingled 

mixture thus would not comply with 

the 9.0 psi RVP standard, effectively 

prohibiting such commingling. 

As discussed earlier, the EPAct 2005 

and EISA2007 mandated increased 

volumes of renewable fuel for use in 

gasoline. This has resulted in the 

increased use of ethanol. E10 is now 

present in nearly all gasoline sold in the 

country. Recently, EPA granted a waiver 

from the substantially similar 

requirements under section 211(f)(4) for 

the use of E15 blends in MY2001 and 

newer light-duty vehicles (See 75 FR 

68094, November 4, 2010 and 76 FR 

4662, January 26, 2011). EPA 

interpreted section 211(h) as not 

extending the 1 psi waiver to such 

blends with ethanol levels above 10%. 

Several companies are also developing 

and planning on introducing biobutanol 

into commerce. The characteristics of 

butanol are such that it could be 

beneficial with respect to volatility and 

vehicle evaporative emission 

performance. For example, 2000 gallons 

of 10 psi E10 added to a service station 

tank with 8000 gallons of 9.0 psi Bu12 

would result in 10000 gallons of fuel 

with an RVP of 9.2 psi. The RVP of the 

commingled blend would be the same 

as the average of the separate blends if 

they had never been commingled. There 

is no adverse emissions impact from the 

commingling of the E10 and Bu12 

blends. However the 1-psi waiver would 

not be applicable because the resulting 

blend no longer contains from 9 volume 

percent to 10 volume percent ethanol. 

The RVP level for the resulting blend 

would also be higher than the maximum 

RVP standard of 9.0 psi, making the 

commingled blend noncomplying with 

the RVP standard. However the 

available data indicates that 

commingling of biobutanol blends with 

ethanol blends would not result in any 

net increase in gasoline volatility. This 

is because biobutanol blends and 

gasoline containing from 9 volume 

percent to 10 volume percent ethanol 

blend linearly from a volatility 

perspective, resulting in no net increase 

in volatility compared to what would 

occur without the blending. This means 

that there would be no net degradation 

in environmental performance, as 

indicated in Illustration V.F.–4, below. 

We are inviting comment on an 

alternative approach to applying the 

RVP standard to the gasoline that results 

from commingling of E10 and certain 

other products like biobutanol. We are 

inviting comment as to whether the RVP 

standards could be applied to the 

commingled blend such that the 

commingled blend would be considered 

in compliance as long as the separate 

components of the commingled product 

were in compliance with the RVP 

standards prior to commingling. In 

effect the RVP standard would be 

applied to the commingled mixture by 

treating it as if it still contained two 

separate products, with each product 

required to comply with the RVP 

standard separately. This approach 

would be somewhat artificial but would 

allow for the commingling of specified 

blends of fuels, such as biobutanol, with 

E10 where the resulting commingled 

mixture does not result in a net increase 

in average RVP and associated 

emissions. This would provide more 

flexibility in achieving the RFS 

standards while avoiding adverse 

environmental impacts. This approach 

would provide a limited modification to 

the RVP provisions for only certain fuel 

blends. EPA invites comment on 

whether it would have the authority 

under § 211(h) to adopt such an 

approach, and if so whether it would be 

appropriate to do so and under what 

conditions. 

Specifically, we would consider 

imposing the following conditions on 

such fuel blends: 

(1) Each separate component must 

individually meet the applicable RVP 

standards (e.g., 10 psi for E10 and 9 psi 

for other blends). 

(2) The resulting commingled mixture 

would have to have an RVP that is no 

higher than the weighted average of the 

products or components considered 

separately. This could occur with 

blends that blend linearly with respect 

to RVP (e.g., butanol). 

(3) The burden would be on the 

retailer to show that these conditions 

had been satisfied. If a commingled 

product had volatility above the 

allowable standard, and did not have 

from 9 volume percent to 10 volume 

percent ethanol, then the fuel would be 

considered noncomplying unless the 

regulated party demonstrated that it met 

the limited conditions discussed here. 

The retailer would have to demonstrate 

that the conditions were met for 

application of this modified method of 

determining compliance. This would 

call for at least retaining records of the 

products received (with all required 

regulatory statements and indications 

required) and volumes of the products 

received in order to demonstrate a 

calculation to verify compliance with 

the RVP standard. 

(4) In situations where the RVP of 

retail tank samples exceed 9.0/7.8 psi, 

for defense purposes the retailer would 

need to test the sample for the 

concentration of ethanol, butanol, and 

any other applicable oxygenate in 

addition to the RVP level in order to 

allow for the calculation in (3). The 

resulting blend ratio would need to 

meet or demonstrate better performance 

reductions of such ratio on a linear scale 

as established through regulation. 

Under this approach, we believe there 

would be no adverse environmental 

effects because such mixtures would 

result in no net increase in volatility. 

We also believe this would enable us to 

give effect to the RFS provisions that 

call for increased use of renewable fuels, 

and also be consistent with our rational 

for the treatment of gasohol at the time 

we promulgated the RVP standards. 

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Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 36063 

F. Amendments to Various RFS2 

Compliance Related Provisions 

We are proposing a number of 

changes to the RFS2 regulations. 

1. Proposed Changes to Definitions 

‘‘Responsible Corporate Officer’’ 

The existing RFS2 regulations at 

sections 80.1416, 80.1451 and 80.1454, 

and EPA guidance and instructions 

regarding registration and reporting, 

frequently refer to the responsibilities of 

the ‘‘owner or a responsible corporate 

officer.’’ However, the term ‘‘responsible 

corporate officer’’ is not currently 

defined in the RFS2 regulations. We 

propose that, for purposes of the RFS2 

program, a ‘‘responsible corporate 

officer’’ (RCO) means a corporate officer 

who has the authority and is assigned 

responsibility to provide information to 

EPA on behalf of a company. A 

company may name only one RCO, and 

the RCO may not delegate his/her 

responsibility to any other person. 

However, the RCO may delegate the 

ability to submit information to EPA to 

one or more employees of the company 

or to one or more agents. The RCO 

remains responsible for the information 

submitted to EPA by any employee or 

agent. Adding a definition of RCO will 

codify existing practices and will assist 

regulated parties in understanding roles 

under the RFS2 regulation. 

‘‘Small Refinery’’ 

Section 211(o)(9)(A) of the Clean Air 

Act provides an exemption from RFS 

requirements through 2010 for ‘‘small 

refineries,’’ defined as refineries having 

an average aggregate daily crude oil 

throughput for a calendar year that does 

not exceed 75,000 barrels. It also 

provides for possible extensions of this 

exemption, through individual petitions 

to EPA. CAA 211(o)(9)(B). In EPA’s 

March 26, 2010 regulations 

implementing the EISA amendments we 

specified in the regulatory definition of 

‘‘small refinery’’ that the 75,000 bpd 

threshold determination should be 

calculated based on information from 

calendar year 2006. At the beginning of 

the program, having a single year in 

which to make this determination, 

simplified the calculations, and helped 

to ensure that all refineries were treated 

similarly. However, we no longer 

believe that it is appropriate that 

refineries satisfying the 75,000 bpd 

threshold in 2006 should be eligible for 

extensions to their small refinery RFS 

exemption if they no longer meet the 

75,000 bpd threshold. Allowing such 

facilities to qualify for an exemption 

extension, while not allowing similarly 

sized facilities that have not grown 

since 2006 to qualify for an exemption, 


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does not appear fair, nor does it further 

the objectives of the statute to target 

relief to only truly small facilities. 

Therefore, we propose modifying the 

definition of small refinery so that the 

crude throughput threshold of 75,000 

bpd must apply in 2006 and in all 

subsequent years. We also propose 

specifying in section 80.1441(e)(2)(iii) 

that in order to qualify for an extension 

of its small refinery exemption, a 

refinery must meet the definition of 

‘‘small refinery’’ in section 80.1401 for 

all full calendar years between 2006 and 

the date of submission of the petition for 

an extension of the exemption. 

We proposed that that these changes 

would not affect any existing exemption 

extensions under CAA 211(o)(9)(B); 

rather, they would apply at such time as 

any approved exemption extension 

expires and the refinery at issue seeks 

a further exemption extension. No 

further extension would be permitted 

unless the revised crude oil throughput 

specifications were satisfied. 

2. Provisions for Small Blenders of 

Renewable Fuels 

The RFS2 regulations at section 

80.1440 allow renewable fuel blenders 

who handle and blend less than 125,000 

gallons of renewable fuel per year, and 

who are not obligated parties or 

exporters, to delegate their RIN-related 

responsibilities to the party directly 

upstream from them who supplied the 

renewable fuel for blending. EPA has 

received feedback from several parties 

to the effect that the 125,000 threshold 

is too low, and is a lower threshold than 

what industry considers ‘‘small.’’ EPA 

seeks input on what a more appropriate 

gallon threshold should be. EPA seeks 

comment on the regulated community’s 

experience with the existing gallon 

threshold associated with the 

provisions. EPA may adjust the gallon 

threshold in the final rule based on 

further consideration of this issue and 

evaluation of comments received. 

3. Proposed Changes to Section 

80.1450—Registration Requirements 

We propose to add a new paragraph 

(h) to section 80.1450 that will describe 

the circumstances under which EPA 

may cancel a company registration. EPA 

proposes to initiate a process to cancel 

a company registration if the company 

has reported no activity in the EPA 

Moderated Transaction System (EMTS) 

under section 80.1452 for one year. EPA 

also proposes to initiate a process to 

cancel a company registration if a party 

fails to comply with any registration 

requirement of section 80.1450, if the 

party fails to submit any required 

compliance report under section 

80.1451, if the party fails to meet the 

requirements related to the EPA 

Moderated Transaction System (EMTS) 

under section 80.1452, or if the party 

fails to meet the requirements related to 

attest engagements under section 

80.1454. If any required report, 

including the attest engagement, is 

thirty (30) or more days overdue, EPA 

would provide written notice to the 

owner or responsible corporate officer 

(RCO) that it intends to cancel the 

company’s registration and would allow 

the company fourteen (14) days from the 

date of the letter’s issuance to respond. 

If there is no satisfactory response 

received, then EPA would cancel the 

registration. Re-registration would be 

possible following the standard 

registration procedures. 

4. Proposed Changes to Section 

80.1452—EPA Moderated Transaction 

System (EMTS) Requirements— 

Alternative Reporting Method for Sell 

and Buy Transactions for Assigned RINs 

Reporting and product transfer 

document (PTD) requirements, found in 

sections 80.1452 and 80.1453, 

respectively, currently state that the 

reportable event for a RIN purchase or 

sale occurs on the date of transfer. 

Sellers must report the sale of RINs 

within five (5) business days of the 

reportable event via the EPA Moderated 

Transaction System (EMTS). Buyers 

must report the purchase of RINs within 

ten (10) business days of the reportable 

event via EMTS. The date of transfer is 

the date on which title of RINs is 

transferred from the seller to the buyer. 

Some buyers and sellers of assigned 

RINs have expressed concerns with 

these requirements stating they have 

difficulty determining the date of 

transfer since title of the renewable fuel 

is not transferred until the fuel 

physically reaches the buyer. Some 

transactions, for example those by rail 

or barge, may take several weeks, and 

their current accounting systems do not 

include a means for capturing the 

buyer’s receipt date. 

EPA understands this concern, but 

also recognizes that some regulated 

parties have modified their accounting 

systems to address the current reporting 

and PTD requirements in RFS2. We also 

believe that for parties separating, 

retiring, and selling or buying separated 

RINs, the current reporting and PTD 

requirements are effective and should 

remain unchanged. Therefore, at this 

time EPA is not proposing to replace 

existing requirements, but is instead 

proposing an additional, alternative 

method for reporting sell and buy 

transactions involving assigned RINs 

only. 

The proposed alternative method for 

sell and buy transactions of assigned 

RINs would redefine the reportable 

event for both the seller and the buyer, 

introduce a unique identifier that the 

seller must provide to the buyer, and 

require the buyer to report the date of 

transfer. Buyers and sellers would need 

to agree on which method they would 

be using to report transfers of assigned 

RINs; either the current method or the 

alternative method. EPA believes that 

this alternative would provide the 

regulated community with the 

flexibility to address their reporting 

concerns and also provide EPA with the 

data necessary to effectively administer 

and enforce transactions of assigned 

RINs. EPA welcomes comment on this 

proposed alternative method for 

reporting assigned RIN buy and sell 

transactions. 

We propose that sellers of assigned 

RINs under the alternative method be 

required to do the following: 

• Within five (5) business days of 

shipping renewable fuel with assigned 

RINs, report a sell transaction, using the 

alternative method, via EMTS; 

• Include in the EMTS sell 

transaction report other required 

information per section 80.1452; and 

• Provide a PTD to the assigned RIN 

buyer with a unique identifier, also 

reported via EMTS, in addition to the 

information in section 80.1453. The date 

of transfer is not required for the 

alternative method. 

We propose that buyers of assigned 

RINs under the alternative method be 

required to do the following: 

• Within five (5) business days of 

receiving a shipment of renewable fuel 

with assigned RINs, report a buy 

transaction, indicating use of the 

alternative method, via EMTS; 

• Include in the EMTS buy 

transaction report other required 

information per section 80.1452; 

• Include in the EMTS buy 

transaction report the unique identifier 

provided by the seller; and 

• Include in the EMTS buy 

transaction report the date the 

renewable fuel was received, i.e. the 

date of transfer. 

If this proposed alternative method is 

finalized, the EMTS would be modified 

to accept such transactions. EPA would 

provide additional instruction and 

guidance at the time of the new EMTS 

version release. EPA invites comment 

on all aspects of this proposal. 

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5. Proposed Changes to Section 

80.1463—Confirm That Each Day an 

Invalid RIN Remains in the Marketplace 

Is a Separate Day of Violation 

Preventing the generation and use of 

invalid RINs and encouraging rapid 

retirement and replacement of invalid 

RINs is crucial to the integrity of the 

RFS2 program. The RFS regulations 

include various provisions related to 

prohibited acts and liability for 

violations. Section 80.1460(a) sets forth 

the prohibited acts for the renewable 

fuels program. Section 80.1460(b)(2) 

prohibits parties from creating or 

transferring invalid RINs. Section 

80.1461(a) states that the person who 

violates a prohibited act is liable for the 

violation of that prohibition. Section 

80.1461(b) provides the liability 

provisions for failure to meet other 

provisions of the regulations. The 

penalty provisions of the regulations at 

section 80.1463(a) state that any person 

who is liable for a violation under 

section 80.1461 is subject to a civil 

penalty as specified in sections 205 and 

211(d) of the Clean Air Act (CAA), for 

every day of each such violation and the 

amount of economic benefit or savings 

resulting from each violation. Section 

80.1463(c) provides that ‘‘any person 

. . . is liable for a separate day of 

violation for each day such a 

requirement remains unfulfilled.’’ 

EPA interprets these statutory and 

regulatory penalty provisions to give the 

Agency the authority to seek penalties 

against parties generating, transferring 

or causing another person to generate or 

transfer invalid RINs for each day 

subsequent to the party’s action that an 

invalid RIN is available for sale or use 

by a party subject to an obligation under 

the RFS2 program to acquire and retire 

RINs. For example, for a RIN generator, 

this time period typically runs from the 

date of invalid RIN generation until 

either corrective action is taken by the 

RIN generator to remove the invalid RIN 

from the marketplace or a party uses the 

RIN to satisfy an RVO or other 

requirement to retire RINs (such as 

would apply under today’s proposal to 

exporters of renewable fuel or parties 

using fuel produced as renewable fuel 

for a use other than as transportation 

fuel, heating oil or jet fuel). This is 

consistent with the CAA approach of 

assessing penalties for every day of a 

violation, consistent with EPA’s historic 

approach under the fuels regulations 

(See Section 80.615), and will encourage 

renewable fuel producers that generate 

invalid RINs to promptly take corrective 

action. 

We are proposing to amend section 

80.1463 to more explicitly incorporate 

EPA’s interpretation of these penalty 

provisions into the regulations. The 

amendments would state that any 

person liable for a violation of section 

80.1460(b) for creating or transferring an 

invalid RIN, or for causing another 

person to create or transfer and invalid 

RIN, is subject to a separate day of 

violation for each day that the invalid 

RIN remains available for use for 

compliance purposes, and EPA has the 

authority to seek the maximum statutory 

penalty for each day of violation. EPA 

will apply the statutory factors in 

sections 211(c) and 205(b) of the CAA 

to evaluate the appropriate penalties for 

each violation on a case by case basis. 

6. Proposed Changes to Section 

80.1466—Require Foreign Ethanol 

Producers, Importers and Foreign 

Renewable Fuel Producers That Sell to 

Importers To Be Subject to U.S. 

Jurisdiction and Post a Bond 

The current regulations include 

requirements that foreign renewable fuel 

producers that generate RINs agree to be 

subject to a number of additional 

requirements at section § 80.1466, 

including, but not limited to, 

designation, foreign producer 

certification, product transfer document, 

load port independent testing and 

producer identification, submission to 

U.S. jurisdiction and posting of a bond. 

We are proposing to require the same 

requirements for foreign renewable fuel 

producers, and foreign ethanol 

producers that produce biofuel for 

which importers ultimately generate 

RINs, and for importers of renewable 

fuel. 

In order to evaluate whether a fuel 

qualifies as RIN generating renewable 

fuel (including determining the proper 

renewable fuel category and RIN type 

for the imported fuel), EPA must be able 

to evaluate the feedstocks and processes 

used to produce the renewable 

components of the fuel. This is a 

particular challenge for fuel produced at 

foreign facilities; unlike our other fuels 

programs, EPA cannot determine 

whether a particular shipment of 

renewable fuel is eligible to generate 

RINs under the RFS program by testing 

the fuel itself. Furthermore, significant 

opportunity for fraud and noncompliance with the regulations exists 

where EPA is not able to ensure that 

RINs entering the U.S. are valid, and 

where enforcement of the regulations 

may be hampered due to a facility’s 

foreign location. We believe that the 

same safeguards that apply to foreign 

RIN generating renewable fuel 

producers should apply to other foreign 

producers whose product is used by 

importers to generate RINs, and to those 

importers themselves. Accordingly, we 

propose that foreign renewable fuel 

producers and foreign ethanol 

producers who do not themselves 

generate RINs for their product, and 

importers of renewable fuel, be required 

to comply with the safeguards of section 

80.1466. Given the challenges 

associated with EPA’s ability to 

determine whether a fuel qualifies as 

RIN generating renewable fuel, and the 

potential for fraud, we believe these 

additional safeguards are necessary for 

all foreign produced renewable fuel, 

regardless of who generates the RINs. 

However, we seek comment on the 

reasonability of expanding these 

additional requirements onto foreign 

renewable fuel producers, and foreign 

ethanol producers that produce biofuel 

for which importers ultimately generate 

RINs, and for importers of renewable 

fuel. We further propose to amend 

section 80.1426(a)(4) to prohibit 

importers from generating RINs for 

renewable fuel imported from a foreign 

renewable fuel producer or foreign 

ethanol producer, unless and until the 

foreign renewable fuel producer or 

foreign ethanol producer has satisfied 

all requirements of section 80.1466. 

7. Proposed Changes to Section 

80.1466(h)—Calculation of Bond 

Amount for Foreign Renewable Fuel 

Producers, Foreign Ethanol Producers 

and Importers 

EPA proposes two changes to section 

80.1466 regarding calculation of bonds. 

EPA proposes to amend the procedures 

for calculating the bond amount for 

foreign renewable fuel producers, 

foreign ethanol producers and importers 

to require that the bond amount be the 

larger of: (1) One cent times the largest 

volume of renewable fuel produced by 

the foreign producer and exported to the 

United States, in gallons, during a single 

calendar year among the five preceding 

calendar years, or the largest volume of 

renewable fuel that the foreign 

producers expects to export to the 

Unites States during any calendar year 

identified in the Production Outlook 

Report required by section 80.1449, or 

(2) the sum of the following calculation 

for each RIN type: 0.25 times the largest 

volume of renewable fuel produced by 

the foreign producer and exported to the 

United States, in gallons, during a single 

calendar year among the five preceding 

calendar years, or the largest volume of 

renewable fuel that the foreign 

producers expects to export to the 

Unites States during any calendar year 

identified in the Production Outlook 

Report required by section 80.1449, 

times a ‘‘RIN multiplier D code’’ 

established by EPA in the regulations. 

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The proposed ‘‘RIN multiplier D codes’’ 

vary from $.02 for D code 6 to $1.30 for 

D code 4. When the original renewable 

fuels standard regulations (RFS1) were 

written, an RFS1 RIN was worth 

pennies. With the implementation of 

RFS2, the price of some RINs has 

increased significantly, in part because 

of the demand for certain categories of 

fuel such as biomass-based diesel. In 

order to keep up with these market 

conditions, the bond amount needs to 

be increased; a penny per gallon of fuel 

may no longer be a fair valuation of a 

foreign renewable fuel producer’s 

potential penalty for RFS violations. 

Bonds are used to satisfy any judicial 

judgment that results from an 

administrative or judicial enforcement 

action for conduct in violation of this 

subpart. Therefore, we propose to 

amend section 80.1466(h)(1) to include 

the calculation described above, that 

reflects current market valuation for 

different types of RINs. We seek 

comment on whether the proposed bond 

calculation procedures are appropriate, 

and in particular whether they are 

sufficiently large to cover potential 

liability. 

EPA also proposes to amend 

paragraph (h) of section 80.1466 to be 

consistent with paragraph (j)(4), which 

prohibits generating RINs in excess of 

the number for which the bond 

requirements have been satisfied. 

Paragraph (h) regulates the size of the 

bond a foreign renewable fuel producer 

must post in order to generate RINs. 

This formula takes into account the 

volume of renewable fuel a foreign 

renewable fuel producer has exported or 

intends to export to the United States. 

Section 80.1466(h) states, in part: ‘‘If the 

volume of renewable fuel exported to 

the United States increases above the 

largest volume identified in the 

Production Outlook Report during any 

calendar year, the foreign producer shall 

increase the bond to cover the shortfall 

within 90 days.’’ This conflicts with the 

stricter language in paragraph (j)(4) of 

the same section, which prohibits a 

foreign producer of renewable fuel from 

generating RINs in excess of the number 

for which the bond requirements of 

section 80.1466 have been satisfied. 

EPA interprets the stricter provision at 

section 80.1466(j)(4) to be controlling, 

and we propose to change the language 

in section 80.1466(h) accordingly. 

8. Proposed Changes to Facility’s 

Baseline Volume To Allow ‘‘Nameplate 

Capacity’’ for Facilities Not Claiming 

Exemption From the 20% GHG 

Reduction Threshold 

As a requirement of registration under 

the RFS2 program, each renewable fuel 

producer and foreign ethanol producer 

must establish and provide documents 

to support its facility’s baseline volume 

as defined in section 80.1401. This is 

either the permitted capacity or, if 

permitted capacity cannot be 

determined, the actual peak capacity of 

a specific renewable fuel production 

facility on a calendar year basis. After 

the promulgation of the March 26, 2010 

RFS2 rule, we have received many 

requests from companies to allow them 

to use their nameplate or ‘‘design’’ 

capacity to establish their facility’s 

baseline volume due to either the 

facility being exempt from obtaining a 

permit, and thus not able to determine 

their permitted capacity, or the facility 

not starting operations, or not being 

operational for a full calendar year to 

produce actual production records to 

establish actual peak capacities. Because 

the regulations currently only allow a 

facility’s baseline volume to be 

established by a limit stated in a permit 

or actual production records for at least 

one calendar year, facilities that had 

neither a permit or sufficient production 

records had difficulty registering under 

the RFS2 program. To allow facilities 

that fall under this predication to 

register under the RFS2 program, we are 

proposing in this rulemaking to allow a 

facility to use its ‘‘nameplate capacity’’ 

to establish its facility’s baseline volume 

for the purposes of registration, only if 

(1) the facility does not have a permit or 

there is no limit stated in the permit to 

establish their permitted capacity, and 

(2) has not started operations or does 

not have at least one calendar year of 

production records, and (3) does not 

claim exemption from the 20 percent 

GHG threshold under § 80.1403. Due to 

the complexity of the exemption 

provision provided under § 80.1403, 

and the added flexibility that facilities 

claiming this exemption are allotted 

under the program, we are not 

proposing to extend this option to 

facilities claiming an exemption under 

§ 80.1403. Additionally, by this stage in 

the RFS2 program, the facilities that 

would qualify for registration under 

§ 80.1403 would be very few, if any. 

This proposal would revise the 

definition of baseline volume to include 

‘‘nameplate capacity,’’ add a new 

definition for ‘‘nameplate capacity’’ to 

§ 80.1401, and include conforming 

amendments to the registration 

requirements of § 80.1450. 

G. Minor Corrections to RFS2 Provisions 

We are proposing a number of 

corrections to address minor 

definitional issues that have been 

identified as we have been 

implementing the RFS2 program. 

Renewable Biomass 

We propose to amend the definition 

of ‘‘renewable biomass’’ in section 

80.1401 to make clear that biomass 

obtained in the vicinity of buildings 

means biomass obtained within 200 feet 

of the buildings. The preamble for the 

March 26, 2010 RFS2 final rule cites the 

distance of 200 feet (see 75 FR 14696), 

but EPA did not include a reference to 

this value in the regulations. We believe 

doing so would provide additional 

clarity to the regulations. 

English Language Translations 

We propose to add a new paragraph 

(i) to section 80.1450 to state that any 

registration materials submitted to EPA 

must be in English or accompanied by 

an English language translation. 

Similarly, we propose to add a new 

paragraph (h) to section 80.1451 that 

will state that any reports submitted to 

EPA must be in English or accompanied 

by an English language translation and 

add a new paragraph (q) to section 

80.1454 that will state that any records 

submitted to EPA must be in English or 

accompanied by an English language 

translation. The translation and all other 

associated documents must be 

maintained by the submitting company 

for a period of five (5) years, which is 

already the established time period for 

keeping records under the existing RFS2 

program. 

Correction of Typographical Errors 

We propose to correct various 

typographical errors in section 80.1466. 

Specifically, we propose to amend 

paragraph (o) to correct a typographical 

error in the last sentence of the 

affirmation statement, by changing the 

citation from § 80.1465 to § 80.1466. We 

also propose to amend paragraph 

(d)(3)(ii) to correct a typographical error. 

The current regulation cites section 

80.65(e)(2)(iii), which does not exist. 

The correct citation is to section 

80.65(f)(2)(iii). 

VI. Amendments to the E15 Misfueling 

Mitigation Rule 

We propose the following minor 

corrections and other changes to the E15 

misfueling mitigation rule (E15 MMR) 

found at 40 CFR Part 80, subpart N. 

A. Proposed Changes to Section 

80.1501—Label 

We propose to correct several minor 

errors in the description of the E15 label 

required by the E15 MMR at section 

80.1501, including corrections in the 

dimensions of the label and ensuring 

that the word ‘‘ATTENTION’’ is 

capitalized. The Agency intended the 

label required by the regulations to look 

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identical to that pictured in the Federal 

Register notice for the final E15 MMR 

(see 76 FR 44406, 44418, July 25, 2011). 

B. Proposed Changes to Section 

80.1502—E15 Survey 

We are proposing two changes to the 

survey requirements found at section 

80.1502. First, we propose to clarify that 

E15 surveys need to sample for Reid 

vapor pressure (RVP) only during the 

high ozone season as defined in section 

80.27(a)(2)(ii) or during any time RVP 

standards apply in any state 

implementation plan approved or 

promulgated under the Clean Air Act. 

EPA did not intend to require RVP 

sampling and testing during the rest of 

the year, when RVP standards do not 

apply. 

Second, we propose to change when 

the results of surveys that detect 

potential noncompliance must be 

reported to the Agency. As originally 

drafted, the regulations require the 

independent survey association 

conducting a survey to notify EPA of 

potentially noncompliant samples 

within 24 hours of the laboratory 

receiving this sample (see 76 FR at 

44423, July 25, 2011). EPA has since 

learned that more time may be needed 

for reporting of noncompliant samples 

since it may take several days for 

analysis of the sample to be completed. 

We are therefore requiring that 

noncompliant samples be reported to 

EPA within 24 hours of being analyzed. 

C. Proposed Changes to Section 

80.1503—Product Transfer Documents 

EPA is proposing certain minor 

changes to the product transfer 

document (PTD) requirements found at 

section 80.1503. Specifically, we are 

proposing to allow the use of product 

codes for conventional blendstock/ 

gasoline upstream of an ethanol 

blending facility, since historically, the 

codes have been allowed to be used for 

conventional blendstock/gasoline 

upstream of an ethanol blending facility 

in other fuels programs. This was an 

omission from the original regulation. 

We are also seeking comment on 

potential ways of streamlining the PTD 

language required at section 80.1503. 

D. Proposed Changes to Section 

80.1504—Prohibited Acts 

EPA is slightly rewording section 

80.1504(g) to state that blending E10 

that has taken advantage of the statutory 

1.0 psi RVP waiver during the 

summertime RVP control period with a 

gasoline-ethanol fuel that cannot take 

advantage of the 1.0 psi RVP waiver 

(i.e., a fuel that contains more than 10.0 

volume percent ethanol (e.g., E15) or 

less than 9 volume percent ethanol) 

would be a violation of the E15 MMR. 

As originally written, the language does 

not clearly describe the prohibited 

activity (see 76 FR 44435, 44436, Jult 25, 

2011). 

E. Proposed Changes to Section 

80.1500—Definitions 

On August 17, 2011, the National 

Petroleum Refiners Association, now 

called American Fuel and 

Petrochemical Manufacturers (AFPM), 

filed a petition for reconsideration with 

the Agency under CAA section 

307(d)(7)(B) asking EPA to reconsider 

certain portions of the E15 MMR. A 

copy of the petition has been placed in 

the docket. The petition fundamentally 

focuses on one issue—AFPM expressed 

concern that the Agency had defined 

E10 and E15 in the E15 MMR in a way 

that would change how ethanol 

concentrations are determined for 

regulatory purposes. Today we grant 

AFPM’s request for reconsideration of 

this issue as explained in their August 

17, 2011 petition. As explained below, 

while EPA did not intend the 

definitions of E10 and E15 in the E15 

MMR to have this effect, we are 

proposing changes to the regulations to 

avoid this perceived impact. 

On April 6, 1979, fuel containing 90% 

unleaded gasoline and 10% ethyl 

alcohol received a waiver under section 

211(f)(4) by operation of law (see 44 FR 

20777, April 6, 1979). Later, EPA issued 

an interpretative ruling that stated the 

April 6, 1979 waiver covered gasolineethanol blends that contained up to 10 

vol% ethanol content (see 47 FR 14596, 

April 5, 1982). Finally, in the context of 

regulations limiting the Reid vapor 

pressure (RVP) of gasoline, EPA has 

defined E10 as gasoline containing 

between 9 and 10 volume percent 

ethanol. Under the RVP regulations and 

the Clean Air Act, the RVP of E10 is 

allowed to be 1 pound per square inch 

(psi) higher than it is for gasoline or 

gasoline-ethanol blends containing less 

than 9 and more than 10 vol% ethanol 

(often referred to as the ‘‘1.0 psi 

waiver’’). 

In the E15 MMR, EPA defined E10 as 

gasoline containing at least 9.0 and no 

more than 10.0 vol% ethanol and 

defined E15 as a gasoline-ethanol blend 

containing greater than 10.0 and no 

more than 15.0 vol% ethanol. EPA 

included those definitions in the E15 

MMR so that fuels blended to contain 

more than 10.0 vol% ethanol were 

subject to the misfueling mitigation 

requirements for E15. After publication 

of the E15 MMR, stakeholders including 

AFPM expressed concern that by 

defining E10 as E10.0, the Agency may 

have effectively made the ethanol 

concentration limits specified in the E10 

and the E15 waiver decisions and the 

RVP regulations more stringent, which 

in turn would impact whether a party 

must comply with the E15 MMR 

requirements and whether a fuel 

qualifies for the RVP 1.0 psi waiver. 

In its petition, AFPM noted that under 

existing EPA regulations at 40 CFR 80.9, 

the results of compliance testing for the 

ethanol concentration in gasoline are 

‘‘rounded down’’ when the results 

indicate that gasoline-ethanol fuel may 

contain slightly more than 10 vol% 

ethanol. AFPM further stated that in 

view of this rounding procedure, fuel 

that compliance testing indicates has an 

ethanol concentration of between 10.0 

and 10.4 should be considered E10. 

AFPM argued that the E15 MMR 

definition of E10 as containing no more 

than 10.0 vol% ethanol constituted a 

‘‘substantive change’’ to the proposed 

E15 MMR that would also alter the 

implementation of other EPA fuels 

regulations without a required 

rulemaking. 

As part of the E15 MMR proposed 

rule, we identified prospective 

responsible parties for each misfueling 

mitigation measure, including 

requirements related to labeling E15 fuel 

dispensers, compliance surveys, and 

product transfer documents. We 

received a number of comments from 

many affected stakeholders, including 

AFPM, that asked us to clarify which 

party or parties would be responsible for 

each misfueling mitigation measure and 

when each party or parties would be 

subject to those requirements. In the 

final E15 MMR, we added the 

significant digit to the definitions of E10 

and E15 in order to provide a 

delineation between E10 and E15 and 

consequently the parties subject to one 

or more of the E15 misfueling mitigation 

measures. 

AFPM argued in their petition that by 

defining E10 as containing no more than 

10.0 vol% ethanol, EPA effectively 

made a substantive change to the way 

test results used for determining 

compliance with fuel requirements are 

rounded. For example, for a gasolineethanol blend to be considered E10, it 

could no longer contain up to 10.4 vol% 

ethanol; it could only contain up to 

10.04 vol% ethanol. AFPM asserted that 

there is a tolerance for blending ethanol 

that allows blends containing up to 10.4 

vol% ethanol to be considered E10. 

While we do not agree that there is a 

blending tolerance for ethanol, we agree 

that test results are rounded utilizing 

the procedures identified in section 80.9 

when compared to applicable standards, 

in this case the ethanol concentrations 

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50See 74 FR 25018 (May 26, 2009). 

51See 74 FR 25018 (May 26, 2009). 

52See 75 FR 14762–14764 (March 26, 2010). 

53For an explanation of the rounding procedures 

outlined in § 80.9 and the rationale the Agency used 

to adopt those procedures, see 71 FR 16496 (April 

3, 2006). 

specified in the E10 and the E15 

waivers. 

The Agency specifically addressed the 

issue of blending tolerances versus 

testing tolerances for gasoline-ethanol 

blends in the RFS2 NPRM.50 At the 

time, some stakeholders had suggested 

that the implementation of a blending 

tolerance for the ethanol content of 

gasoline could be allowed to help 

obligated parties satisfy RFS 

requirements without the need for a 

CAA section 211(f)(4) waiver. In 

response, we argued that although the 

test methods used to measure ethanol 

concentration (ASTM D 5599 and 

ASTM D 4815) include some variability, 

ethanol is different than other fuel 

properties and components that are 

controlled in other fuel programs.51 Fuel 

properties such as RVP, and 

components such as sulfur and benzene, 

are natural characteristics of gasoline as 

a result of the chemical nature of crude 

oil and the refining process. Their levels 

or concentrations in gasoline are 

unknown until measured and are 

dependent upon the accuracy of the test 

method. In contrast, ethanol is 

intentionally added in known amounts 

using equipment designed to ensure a 

specific concentration within a very 

narrow range. Parties that blend ethanol 

into gasoline normally have precise 

control over the final concentration. 

Therefore, a blending tolerance for 

ethanol would not be appropriate. 

During the comment period for the 

RFS2 NPRM, EPA received a number of 

comments from stakeholders that argued 

that the volume percentage of ethanol in 

gasoline is readily determined using 

very accurate volumetric ratio blending 

facilities now in place at most blending 

terminals; therefore, the Agency should 

not allow a blending tolerance. In the 

final RFS rule, we did not include a 

blending tolerance for ethanol blends.52

We continue to believe that blending 

tolerances for ethanol are not 

appropriate, and the definitions of E10 

and E15 in the E15 MMR are consistent 

with this view. The E10 waiver is for 

gasoline containing ‘‘up to’’ 10 vol% 

ethanol, not for gasoline containing ‘‘up 

to’’ 10.4 vol% ethanol, and the E15 

partial waivers are for fuel designed to 

contain ‘‘greater than 10 vol% ethanol 

and not more than 15 vol% ethanol.’’ In 

the case of both waivers, the ‘‘10’’ and 

the ‘‘15’’ are exact numbers, not 

approximations, and they express how 

much ethanol can be lawfully added to 

fuel. Testing by the Department of 

Energy utilized in making the E15 

partial waiver decisions was blended as 

precisely as possible to contain the 

relevant percentage of ethanol, not that 

percentage plus ‘‘0.49.’’ Testing for 

registration of E10 and E15 fuel and fuel 

additives under 40 CFR part 79 was also 

done with fuels blended as precisely as 

possible to contain the relevant 

percentage of ethanol. Similarly, EPA 

regulations provide that only fuel with 

an ethanol concentration of between 9 

and 10 vol%, not more or less, may 

lawfully use the statutory 1.0 psi RVP 

waiver. 

At the same time, we did not intend 

to change the definition of E10 in a way 

that impacts the rounding of test results 

for ethanol concentrations.53 If a 

manufacturer blends in a way designed 

to result in a gasoline-ethanol fuel 

containing no more than 10.0 vol% 

ethanol, but compliance testing 

indicates a concentration of 10.4 vol%, 

we will still round down the test result 

in accordance with procedures in 

section 80.9. The purpose of the E15 

MMR definitions state that if a 

manufacturer blends ethanol into 

gasoline in a way designed to result in 

a gasoline-ethanol fuel containing 

greater than 10.0 vol% and no more 

than 15.0 vol% ethanol, it will be 

subject to applicable E15 MMR 

requirements. For example, bills of 

lading for an E10 fuel manufacturer that 

indicates the manufacturer has 

purchased and blended more ethanol 

than 10.0 vol% ethanol may indicate 

that a fuel does not meet the definition 

of E10 for E15 MMR purposes. 

AFPM also argued that the E15 MMR 

definitions of E10 would alter the 

implementation of other EPA fuels 

regulations without a required 

rulemaking, specifically the application 

of the 1.0 psi RVP waiver to E10. Since 

the Agency intended the E15 MMR 

definition of E10 to only apply for 

purposes of determining the 

applicability of E15 MMR requirements, 

the Agency does not believe these 

definitions affect the implementation 

and enforcement of others fuels 

programs, including the applicability of 

the 1.0 psi RVP waiver. The 

introductory language to the definitions 

at 40 CFR part 80, subpart N clearly 

states that definitions in section 80.1500 

are ‘‘[f]or purposes of this subpart only.’’ 

In order to clarify that these 

definitions only apply in the context of 

the E15 MMR, EPA is proposing to add 

a new section 80.1509, which contains 

language that clearly states that when 

ethanol concentrations are measured for 

compliance testing purposes for 40 CFR, 

Part 80, Subpart N, the applicable 

ethanol concentration value will be 

rounded using the rounding procedures 

at section 80.9. EPA is also proposing 

new prohibited acts language in section 

80.1504 that should make it clear that 

only those parties that (1) produce 

gasoline, blendstocks for oxygenate 

blending (BOBs), or ethanol designed to 

be used in the manufacture of E15 as 

currently defined (i.e., E15.0); (2) that 

manufacture E15 to be introduced into 

commerce; or (3) that dispense E15 from 

a retail outlet. The Agency specifically 

seeks comments on this proposed 

language. 

VII. Proposed Amendments to the 

ULSD Diesel Sulfur Survey 

EPA is requesting comment 

concerning whether to amend a 

provision of the ultra-low sulfur diesel 

(ULSD) rule. The ULSD rule includes a 

provision that deems branded refiners 

liable for violations of the ULSD sulfur 

standard that are found at retail outlets 

displaying the refiner’s brand (40 CFR 

80.612). The regulations include defense 

provisions. One element of a branded 

refiner’s defense to such violations is 

that it must have a periodic sampling 

and testing program at the retail level 

(40 CFR 80.613(b) and (d)). The 

regulations also set forth an alternative 

sampling and testing defense element 

provision for branded refiners. 

This alternative defense element 

provision (40 CFR 80.613(e)) allows a 

branded refiner to meet the companyspecific downstream periodic sampling 

and testing element of its defense by 

participating in funding a survey 

consortium that samples diesel fuel at 

retail outlets nationwide. This sampling 

and testing of fuel to determine 

compliance with the ULSD sulfur 

standard is carried out by an 

independent survey association. EPA 

reviews and approves the annual survey 

plan submitted by the survey 

association. The number of samples that 

are taken each year is determined by a 

statistical formula that is based in part 

on the previous year’s compliance rate. 

In addition, the regulations set a floor 

and a ceiling for the number of samples 

that must be taken in an annual survey 

cycle regardless of the sample number 

that would be calculated using the 

regulatory formula. Therefore, the 

number of samples required to be taken 

can potentially be less than the formula 

would require, or it can be more. 

Compliance with the ULSD sulfur 

content standard has been extremely 

high; less than 1% of the samples have 

been in violation in recent years. The 

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minimum number of samples currently 

required to be taken annually is set by 

the regulation at 5,250 regardless of this 

high compliance rate. Due to the high 

compliance rate, use of the statistical 

formula would result in a sampling rate 

of several hundred samples for each of 

the past several years, instead of 5,250 

samples. The cost difference between 

taking several hundred samples versus 

taking over 5,000 samples is significant. 

For these reasons we believe the 

continued high compliance rate, and the 

substantial discrepancy between the 

sampling rate calculated by the formula 

and the minimum sampling rate, argue 

for lowering the minimum sampling 

rate. However, we believe there is a 

point where the number of samples per 

year would be so few that the survey 

would be meaningless relative to robust 

sampling and testing programs 

conducted by each refiner individually. 

Balancing these concerns, we believe 

minimum sampling rate of about 1,800 

samples is appropriate. We are 

requesting comment on reducing the 

minimum number of samples to some 

rate below 2,000 samples. 

VIII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under Executive Order 12866 (58 FR 

51735, October 4, 1993), this action is a 

‘‘significant regulatory action’’ because 

it raises novel legal or policy issues. 

Accordingly, EPA submitted this action 

to the Office of Management and Budget 

(OMB) for review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011) and any changes made 

in response to OMB recommendations 

have been documented in the docket for 

this action. 

B. Paperwork Reduction Act 

The information collection 

requirements in this notice of proposed 

rulemaking have been submitted for 

approval to the Office of Management 

and Budget (OMB) under the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. 

The Information Collection Request 

(ICR) document prepared by EPA 

related to this proposal has been 

assigned EPA ICR number 2469.01. A 

supporting statement for the proposed 

ICR has been placed in the docket. The 

proposed information collection is 

described in the following paragraphs. 

This action contains recordkeeping 

and reporting that may affect the 

following parties under the RFS2 

regulation: RIN generators (producers, 

importers), obligated parties (refiners), 

exporters, and parties who own or 

transact RINs. We estimate that 670 

parties may be subject to the proposed 

information collection. We estimate an 

annual recordkeeping and reporting 

burden of 3.1 hours per respondent. 

This action contains recordkeeping and 

reporting that may affect the following 

parties under the E15 regulation: 

gasoline refiners, gasoline and ethanol 

importers, gasoline and ethanol 

blenders (including terminals and 

carriers). We estimate that 2,000 

respondents may be subject to the 

proposed information collection. We 

estimate an annual recordkeeping and 

reporting burden of 1.3 hours per 

respondent. Burden means the total 

time, effort, or financial resources 

expended by persons to generate, 

maintain, retain, or disclose or provide 

information to or for a Federal agency. 

This includes the time needed to review 

the instructions; develop, acquire, 

install, and utilize technology and 

systems for the purpose of collecting, 

validating, and verifying information, 

processing and maintaining 

information, and disclosing and 

providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transit or otherwise 

disclose the information. Burden is as 

defined at 5 CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR Part 9. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, EPA has established 

a public docket for this proposed rule, 

which includes the ICR described 

above, under Docket ID number EPA– 

HQ–OAR–2012–0401. Submit any 

comments related to the ICR to EPA and 

OMB. See the ADDRESSES section at the 

beginning of this notice for where to 

submit comments to EPA. Send 

comments to OMB at the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, 725 

17th Street NW., Washington, DC 20503, 

Attention: Desk Office for EPA. Since 

OMB is required to make a decision 

concerning the ICR between 30 and 60 

days after June 14, 2013, a comment to 

OMB is best assured of having its full 

effect if OMB receives it by July 15, 

2013. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this action on small entities, 

I certify that this action will not have a 

significant economic impact on a 

substantial number of small entities. 

The amendments to the RFS2 provisions 

in this direct final rule will not impose 

any requirements on small entities that 

were not already considered under the 

final RFS2 regulations, as it makes 

relatively minor corrections and 

modifications to those regulations. We 

continue to be interested in the 

potential impacts of the proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

This rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for State, local, 

and tribal governments, in the aggregate, 

or the private sector in any one year. We 

have determined that this action will 

not result in expenditures of $100 

million or more for the above parties 

and thus, this rule is not subject to the 

requirements of sections 202 or 205 of 

UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. It 

only applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers and makes 

relatively minor corrections and 

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36070 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

modifications to the RFS2 and diesel 

regulations. 

E. Executive Order 13132 (Federalism) 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This action only 

applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers and makes 

relatively minor corrections and 

modifications to the RFS2 and diesel 

regulations. Thus, Executive Order 

13132 does not apply to this action. In 

the spirit of Executive Order 13132, and 

consistent with EPA policy to promote 

communications between EPA and State 

and local governments, EPA specifically 

solicits comment on this proposed 

action from State and local officials. 

F. Executive Order 13175 (Consultation 

and Coordination With Indian Tribal 

Governments) 

This proposed rule does not have 

tribal implications, as specified in 

Executive Order 13175 (65 FR 67249, 

November 9, 2000). It applies to 

gasoline, diesel, and renewable fuel 

producers, importers, distributors and 

marketers. This action makes relatively 

minor corrections and modifications to 

the RFS and diesel regulations, and does 

not impose any enforceable duties on 

communities of Indian tribal 

governments. Thus, Executive Order 

13175 does not apply to this action. EPA 

specifically solicits additional comment 

on this proposed action from tribal 

officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying only 

to those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it does not establish 

an environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ as defined in Executive 

Order 13211 (66 FR 28355, (May 22, 

2001)), because it is not likely to have 

a significant adverse effect on the 

supply, distribution, or use of energy. 

This action amends existing regulations 

related to renewable fuel, E15, and 

ultra-lower sulfur diesel. We have 

concluded that this rule is not likely to 

have any adverse energy effects. In fact, 

we expect this proposed rule may result 

in positive effects, because many of the 

changes we are proposing will facilitate 

the introduction of new renewable fuels 

under the RFS2 program and have come 

at the suggestion of industry 

stakeholders. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. 

This action does not involve technical 

standards. Therefore, EPA did not 

consider the use of any voluntary 

consensus standards. EPA welcomes 

comments on this aspect of the 

proposed rulemaking and, specifically, 

invites the public to identify 

potentially-applicable voluntary 

consensus standards and to explain why 

such standards should be used in this 

regulation. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this 

proposed rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it does not affect the level of 

protection provided to human health or 

the environment. These technical 

amendments do not relax the control 

measures on sources regulated by the 

RFS regulations and therefore will not 

cause emissions increases from these 

sources. 

K. Clean Air Act Section 307(d) 

This rule is subject to Section 307(d) 

of the CAA. Section 307(d)(7)(B) 

provides that ‘‘[o]nly an objection to a 

rule or procedure which was raised with 

reasonable specificity during the period 

for public comment (including any 

public hearing) may be raised during 

judicial review.’’ This section also 

provides a mechanism for the EPA to 

convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to the EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule.’’ Any person 

seeking to make such a demonstration to 

the EPA should submit a Petition for 

Reconsideration to the Office of the 

Administrator, U.S. EPA, Room 3000, 

Ariel Rios Building, 1200 Pennsylvania 

Ave. NW., Washington, DC 20460, with 

a copy to both the person(s) listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section, and the Director of the 

Air and Radiation Law Office, Office of 

General Counsel (Mail Code 2344A), 

U.S. EPA, 1200 Pennsylvania Ave. NW., 

Washington, DC 20460. 

List of Subjects in 40 CFR Part 80 

Environmental protection, 

Administrative practice and procedure, 

Agriculture, Air pollution control, 

Confidential business information, 

Energy, Forest and Forest Products, Fuel 

additives, Gasoline, Imports, Motor 

vehicle pollution, Penalties, Petroleum, 

Reporting and recordkeeping 

requirements. 

Dated: May 20, 2013. 

Bob Perciasepe, 

Acting Administrator. 

For the reasons stated in the 

preamble, the Environmental Protection 

Agency proposes to amend 40 CFR 

chapter I as set forth below: 

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PART 80—REGULATION OF FUELS 

AND FUEL ADDITIVES 

■ 1. The authority citation for part 80 

continues to read as follows: 

Authority: 42 U.S.C. 7414, 7521, 7542, 

7545 and 7601(a). 

■ 2. Section 80.613 is amended by 

revising paragraph (e)(4)(v)(A) 

definition ‘‘n’’ as follows: 

§ 80.613 What defenses apply to persons 

deemed liable for a violation of a prohibited 

act under this subpart? 

* * * * * 

(e) * * * 

(4) * * * 

(v) * * * 

(A) * * * 

Where: 

n= minimum number of samples in a yearlong survey series. However, in no case 

shall n be larger than 9,600 nor smaller 

than 1,800. 

* * * * * 

■ 3. Section 80.1401 is amended by 

adding the definitions of ‘‘Nameplate 

capacity’’, ‘‘Renewable compressed 

natural gas’’, ‘‘Renewable fuel 

producer’’, ‘‘Renewable liquefied 

natural gas’’, ‘‘Responsible corporate 

officer’’, in alphabetical order and 

revising the definitions of ‘‘Biogas’’, 

‘‘Crop residue’’, ‘‘Naphtha’’, 

‘‘Renewable biomass’’, and ‘‘Small 

refinery’’ in to read as follows: 

§ 80.1401 Definitions. 

* * * * * 

Biogas means a mixture of 

hydrocarbons that is a gas at 60 degrees 

Fahrenheit and 1 atmosphere of 

pressure that is produced through the 

conversion of organic matter. Biogas 

includes landfill gas, gas from waste 

digesters, and gas from waste treatment 

plants. Waste digesters include digesters 

processing animal wastes, biogenic 

waste oils/fats/greases, separated food 

and yard wastes, and crop residues, and 

waste treatment plants include 

wastewater treatment plants and 

publicly owned treatment works. 

* * * * * 

Crop residue is the biomass left over 

from the harvesting or processing of 

planted crops from existing agricultural 

land and any biomass removed from 

existing agricultural land that facilitates 

crop management (including biomass 

removed from such lands in relation to 

invasive species control or fire 

management), whether or not the 

biomass includes any portion of a crop 

or crop plant. Biomass is considered 

crop residue only if the use of that 

biomass for the production of renewable 

fuel has no significant impact on 

demand for the feedstock crop, products 

produced from that feedstock crop, and 

all substitutes for the crop and its 

products, nor any other impact that 

would result in a significant increase in 

direct or indirect GHG emissions. 

* * * * * 

Nameplate capacity means the peak 

design capacity of a facility for the 

purposes of registration of a facility 

under § 80.1450(b)(1)(V)(E). 

Naphtha means a blendstock or fuel 

blending component falling within the 

boiling range of gasoline which is 

composed of only hydrocarbons, is 

commonly or commercially known as 

naphtha and is used to produce gasoline 

through blending. 

* * * * * 

Renewable biomass means each of the 

following (including any incidental, de 

minimis contaminants that are 

impractical to remove and are related to 

customary feedstock production and 

transport): 

(1) Planted crops and crop residue 

harvested from existing agricultural 

land cleared or cultivated prior to 

December 19, 2007 and that was 

nonforested and either actively managed 

or fallow on December 19, 2007. 

(2) Planted trees and tree residue from 

a tree plantation located on non-federal 

land (including land belonging to an 

Indian tribe or an Indian individual that 

is held in trust by the U.S. or subject to 

a restriction against alienation imposed 

by the U.S.) that was cleared at any time 

prior to December 19, 2007 and actively 

managed on December 19, 2007. 

(3) Animal waste material and animal 

byproducts. 

(4) Slash and pre-commercial 

thinnings from non-federal forestland 

(including forestland belonging to an 

Indian tribe or an Indian individual, 

that are held in trust by the United 

States or subject to a restriction against 

alienation imposed by the United 

States) that is not ecologically sensitive 

forestland. 

(5) Biomass (organic matter that is 

available on a renewable or recurring 

basis) obtained from the immediate 

vicinity (i.e., obtained within 200 feet) 

of buildings and other areas regularly 

occupied by people, or of public 

infrastructure, in an area at risk of 

wildfire. 

(6) Algae. 

(7) Separated yard waste or food 

waste, including recycled cooking and 

trap grease, and materials described in 

§ 80.1426(f)(5)(i). 

Renewable compressed natural gas 

means biogas as defined in this section, 

that is processed to the standards of 

pipeline natural gas as defined in 40 

CFR 72.2 and that is compressed to 

pressures up to 3600 psi. Only 

renewable CNG that qualifies as 

renewable fuel and is used for 

transportation purposes can generate 

RINs. 

* * * * * 

Renewable fuel producer means a 

person who operates or directly 

supervises the operation of a facility 

where renewable fuel is produced. 

* * * * * 

Renewable liquefied natural gas 

means biogas as defined in this section, 

that is processed to the standards of 

pipeline natural gas as defined in 40 

CFR 72.2 and that goes through the 

process of liquefaction in which the 

biogas is cooled below its boiling point 

and weighs less than half the weight of 

water so it will float if spilled on water. 

Only renewable LNG that qualifies as 

renewable fuel and is used for 

transportation fuel can generate RINs. 

Responsible Corporate Officer, or 

RCO, for this subpart only, means a 

corporate officer who has the authority 

and is assigned responsibility to provide 

information to EPA on behalf of a 

company. A company may name only 

one Responsible Corporate Officer. A 

Responsible Corporate Officer may not 

delegate his or her responsibility to any 

other person. The Responsible 

Corporate Officer may delegate the 

ability to submit information to EPA, 

but the Responsible Corporate Officer 

remains responsible for the actions of 

such employees or agents. 

* * * * * 

Small Refinery, for this subpart only, 

means a refinery for which the average 

aggregate daily crude oil throughput for 

calendar year 2006 and subsequent 

years (as determined by dividing the 

aggregate throughput for the calendar 

year by the number of days in the 

calendar year) does not exceed 75,000 

barrels. 

■ 4. Section 80.1415 is amended by 

revising paragraphs (b)(5) and (c)(1) to 

read as follows: 

§ 80.1415 How are equivalence values 

assigned to renewable fuel? 

(b) * * * 

(5) 77,000 Btu (lower heating value) of 

compressed natural gas (CNG) or 

liquefied natural gas (LNG) shall 

represent one gallon of renewable fuel 

with an equivalence value of 1.0. 

(c) * * * 

(1) The equivalence value for 

renewable fuels described in paragraph 

(b)(7) of this section shall be calculated 

using the following formula: 

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

Where: 

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36072 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

EV = Equivalence Value for the renewable 

fuel, rounded to the nearest tenth. 

R = Renewable content of the renewable fuel. 

Except as provided in § 80.1426(f)(4)(iii), 

this is a measure of the portion of a 

renewable fuel that came from renewable 

biomass, expressed as a fraction, on an 

energy basis. 

EC = Energy content of the renewable fuel, 

in Btu per gallon (lower heating value). 

■ 5. Section 80.1426 is amended by: 

■ a. Revising Table 1 of paragraph (f)(1) 

by: 

■ 1. Revising the entry for ‘‘Q’’; and 

■ 2. Adding new entries for T through 

AA to the end of the table; 

■ b. Revising paragraphs (f)(10) and 

f(11); and 

■ c. Adding paragraph (f)(14). 

The revisions and additions read as 

follows: 

§ 80.1426 How are RINs generated and 

assigned to batches of renewable fuel by 

renewable fuel producers or importers? 

(f) * * * 

(1) * * * 

TABLE 1 TO § 80.1426—APPLICABLE D CODES FOR EACH FUEL PATHWAY FOR USE IN GENERATING RINS

Fuel type Feedstock Production process requirements D-Code 

* * * * * * * 

Q ............... Renewable Compressed Natural 

Gas, Renewable Liquefied Natural 

Gas.

Biogas from waste treatment plants and 

waste digesters.

Any ........................................................................ 5 

* * * * * * * 

T ............... Butanol .............................................. Corn starch .................... Fermentation; dry mill using natural gas and 

biogas from on-site thin stillage anaerobic digester for process energy w/CHP producing 

excess electricity of at least 40% of the purchased natural gas energy used by the facility.

5 

U ............... Renewable Compressed Natural 

Gas, Renewable Liquefied Natural 

Gas.

Biogas from Landfills ..... Any ........................................................................ 3 

V ............... Renewable Electricity ........................ Biogas from landfills ...... Any ........................................................................ 3 

W .............. Cellulosic Naphtha ............................ Biogas from landfills ...... Fischer-Tropsch process; Facilities must produce 

at least 20% of their electricity usage at the facility.

3 

X ............... Cellulosic Diesel for use as conventional diesel fuel.Biogas from landfills ...... Fischer-Tropsch process; Facilities must produce 

at least 20% of their electricity usage at the facility.

7 

Y ............... Naphtha ............................................. Biogas from landfills ...... Fischer-Tropsch process ....................................... 5 

Z ............... Renewable Diesel for use as conventional diesel fuel.Biogas from landfills ...... Fischer-Tropsch process; Excluding processes 

that co-process renewable biomass and petroleum.

4 

AA ............. Renewable Diesel for use as conventional diesel fuel.Biogas from landfills ...... Fischer-Tropsch process; Includes only processes that co-process renewable biomass and 

petroleum.

5 

* * * * * 

(10)(i) For purposes of this section, 

renewable electricity that is not 

introduced into a distribution system 

with electricity derived from nonrenewable feedstocks is considered 

renewable fuel and the producer may 

generate RINs if all of the following 

apply: 

(A) The electricity is produced from 

renewable biomass and qualifies for a D 

code in Table 1 to this section or has 

received approval for use of a D code by 

the Administrator; 

(B) The fuel producer has entered into 

a written contract for the sale of a 

specific quantity of renewable 

electricity as transportation fuel; and 

(C) The renewable electricity is used 

as a transportation fuel. 

(ii) For purposes of this section, fuels 

produced from biogas that is not 

introduced into a distribution system 

with gas derived from non-renewable 

feedstocks is considered renewable fuel 

and the producer may generate RINs if 

all of the following apply: 

(A) The fuel is produced from 

renewable biomass and qualifies for a D 

code in Table 1 to this section or has 

received approval for use of a D code by 

the Administrator; 

(B) The fuel producer has entered into 

a written contract for the sale of a 

specific quantity of biogas to be used as 

a feedstock for transportation fuel; and 

(C) The fuel produced from the biogas 

is used as a transportation fuel. 

(iii) A producer of renewable 

electricity that is generated by co-firing 

a combination of renewable biomass 

and fossil fuel may generate RINs only 

for the portion attributable to the 

renewable biomass, using the procedure 

described in paragraph (f)(4) of this 

section. 

(11)(i) For purposes of this section, 

renewable electricity that is introduced 

into a commercial distribution system 

(transmission grid) may be considered 

renewable fuel and the producer may 

generate RINs if: 

(A) The electricity is produced from 

renewable biomass and qualifies for a D 

code in Table 1 of this section or has 

received approval for use of a D code by 

the Administrator; 

(B) The fuel producer has entered into 

a written contract for the sale of a 

specific quantity of electricity derived 

from renewable biomass sources with a 

party that uses electricity taken from a 

commercial distribution system for use 

as a transportation fuel, and such 

electricity has been introduced into that 

commercial distribution system 

(transmission grid); 

(C) The quantity of renewable 

electricity for which RINs were 

generated was sold for use as 

transportation fuel and for no other 

purposes; and 

(D) The renewable electricity was 

loaded onto and withdrawn from a 

physically connected transmission grid 

as defined by the North American 

Electrical Reliability Corporation 

(NERC) regions. 

(ii) For purposes of this section, fuel 

produced from biogas that is introduced 

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into a commercial distribution system 

may be considered renewable fuel and 

the producer may generate RINs if: 

(A) The fuel is produced from 

renewable biomass and qualifies for a D 

code in Table 1 of this section or has 

received approval for use of a D code by 

the Administrator; 

(B) The fuel producer has entered into 

a written contract for the sale of a 

specific quantity of fuel derived from 

renewable biomass sources with a party 

that uses fuel taken from a commercial 

distribution system for transportation 

fuel, and such fuel has been introduced 

into that commercial distribution 

system (e.g., pipeline); 

(C) The quantity of fuel produced 

from the biogas for which RINs were 

generated was sold for use as 

transportation fuel and for no other 

purposes; 

(D) The biogas was injected into and 

withdrawn from a physically connected 

carrier pipeline; 

(E) The gas that is ultimately 

withdrawn from that pipeline for use in 

a transportation fuel is withdrawn in a 

manner and at a time consistent with 

the transport of gas between the 

injection and withdrawal points; and 

(F) The volume and heat content of 

biogas injected into the pipeline and the 

volume of gas withdrawn to make a 

transportation fuel are measured by 

continuous metering. 

(iii) The fuel sold for use in 

transportation fuel is considered 

produced from renewable biomass only 

to the extent that: 

(A) The amount of fuel sold for use as 

transportation fuel matches the amount 

of fuel derived from renewable biomass 

that the producer contracted to have 

placed into the commercial distribution 

system; and 

(B) No other party relied upon the 

contracted volume of biogas or 

renewable electricity for the creation of 

RINs. 

(iv) For renewable electricity that is 

generated by co-firing a combination of 

renewable biomass and fossil fuel, the 

producer may generate RINs only for the 

portion attributable to the renewable 

biomass, using the procedure described 

in paragraph (f)(4) of this section. 

* * * * * 

(14) For purposes of verification, in 

order for facilities to meet the renewable 

electricity production requirement for 

the biogas-derived cellulosic diesel and 

cellulosic naphtha pathways, all 

conditions below apply. 

(i) The quantity of process electricity 

produced on-site must be measured by 

continuous metering. 

(ii) The electricity must be used to 

provide power to process units or 

process equipment at the facility. 

(iii) The electrical energy must derive 

from raw landfill gas, waste heat from 

the production process, unconverted 

syngas from the F–T process, fuel gas 

from the hydroprocessing or combined 

heat and power (CHP) units that use 

non-fossil fuel based gas or other 

renewable sources. 

■ 6. Section 80.1427 is amended by: 

■ a. Revising paragraphs (a)(1), (a)(1)(i) 

definition ‘‘RVOCB,i’’, (a)(1)(ii) definition 

‘‘RVOBBD,i’’, (a)(1)(iii) definition 

‘‘RVOAB,i’’, (a)(1)(iv) definition 

‘‘RVORF,i, (a)(5) introductory text, and 

(a)(6); and 

■ b. Adding paragraph (a)(1)(v), 

(a)(1)(vi), (a)(1)(vii), (a)(1)(viii), 

The additions and revisions read as 

follows: 

§ 80.1427 How are RINs used to 

demonstrate compliance? 

(a) Renewable Volume Obligations 

and Exporter Renewable Volume 

Obligations. (1) Except as specified in 

paragraph (b) of this section or 

§ 80.1456, each party that is an obligated 

party under § 80 1406 and is obligated 

to meet the Renewable Volume 

Obligations under § 80.1407, or is an 

exporter of renewable fuel that is 

obligated to meet the Exporter 

Renewable Volume Obligations under 

§ 80.1430, must demonstrate pursuant to 

§ 80.1451(a)(1) that it is retiring for 

compliance purposes a sufficient 

number of RINs to satisfy the following 

equations. 

(i) * * * 

RVOCB,i = The renewable Volume Obligation 

for cellulosic biofuel for the obligated 

party for calendar year i, in gallons, 

pursuant to § 80.1407. 

(ii) * * * 

RVOBBD,i = The renewable Volume 

Obligation for biomass-based diesel for 

the obligated party for calendar year i, in 

gallons, pursuant to § 80.1407. 

(iii) * * * 

RVOAB,i = The renewable Volume Obligation 

for advanced biofuel for the obligated 

party for calendar year i, in gallons, 

pursuant to 80.1407. 

(iv) * * * 

RVORF,i = The renewable Volume Obligation 

for renewable fuel for the obligated party 

for calendar year i, in gallons, pursuant 

to 80.1407. 

(v) Cellulosic biofuel—Exporter. 

(SRINNUM)CB,i+ (SRINNUM)CB,i¥1= 

ERVOCB,i

Where: 

(SRINNUM)CB,i= Sum of all owned gallonRINs that are valid for use in complying 

with the cellulosic biofuel ERVO, were 

generated in year i, and are being applied 

towards the ERVOCB,i, in gallons. 

(SRINNUM)CB,i-1= Sum of all owned gallonRINs that are valid under subparagraph 

(6) of this paragraph for use in 

complying with the cellulosic biofuel 

ERVO, were generated in year i-1, and 

are being applied towards the ERVOCB,i, 

in gallons. 

ERVOCB, k= The Exporter Renewable Volume 

Obligation for cellulosic biofuel for the 

renewable fuel exporter for an export of 

renewable fuel k, in gallons, pursuant to 

§ 80.1430. 

(vi) Biomass-based diesel—Exporter. 

(SRINNUM)BBD,i+ (SRINNUM)BBD,i-1= 

ERVOBBD,i

Where: 

(SRINNUM)BBD,i= Sum of all owned gallonRINs that are valid for use in complying 

with the biomass-based diesel ERVO, 

were generated in year i, and are being 

applied towards the ERVOBBD,i, in 

gallons. 

(SRINNUM)BBD,i-1= Sum of all owned 

gallon-RINs that are valid under 

subparagraph (6) of this paragraph for 

use in complying with the biomass-based 

diesel ERVO, were generated in year i-1, 

and are being applied towards the 

ERVOBBD,i, in gallons. 

ERVOBBD,i= The Exporter Renewable Volume 

Obligation for biomass-based diesel for 

the renewable fuel exporter for an export 

of renewable fuel I after 2010, in gallons, 

pursuant to § 80.1430. 

(vii) Advanced biofuel—Exporter. 

(SRINNUM)AB,i+ (SRINNUM)AB,i-1= 

ERVOAB,i

Where: 

(SRINNUM)AB,i= Sum of all owned gallonRINs that are valid for use in complying 

with the advanced biofuel ERVO, were 

generated in year i, and are being applied 

towards the ERVOAB,i, in gallons. 

(SRINNUM)AB,i-1= Sum of all owned gallonRINs that are valid under subparagraph 

(6) of this paragraph for use in 

complying with the advanced biofuel 

ERVO, were generated in year i-1, and 

are being applied towards the ERVOAB,i, 

in gallons. 

ERVOAB,i= The Exporter Renewable Volume 

Obligation for advanced biofuel for the 

renewable fuel exporter for an export of 

renewable fuel i, in gallons, pursuant to 

§ 80.1430. 

(viii) Renewable fuel—Exporter. 

(SRINNUM)RF,i+ (SRINNUM)RF,i-1= 

ERVORF,i

Where: 

(SRINNUM)RF,i= Sum of all owned gallonRINs that are valid for use in complying 

with the renewable fuel (D code 6) E 

ERVORF,i, in gallons. 

(SRINNUM)RF,i-1= Sum of all owned gallonRINs that are valid under subparagraph 

(6) of this paragraph for use in 

complying with the renewable fuel (D 

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36074 Federal Register / Vol. 78, No. 115 / Friday, June 14, 2013 / Proposed Rules 

1, and are being applied towards the 

ERVORF,i, in gallons. 

ERVORF,i= The exporter Renewable Volume 

Obligation for renewable fuel for the 

renewable fuel exporter for an export of 

renewable fuel i, in gallons, pursuant to 

§ 80.1430. 

* * * * * 

(5) The value of (SRINNUM)i-1 may 

not exceed values determined by the 

following inequalities as provided in 

paragraph (a)(7)(iii) of this section and 

80.1442(d), for obligated parties only. 

* * * * * 

(6) Except as provided in paragraph 

(a)(7) of this section: 

(i) For obligated parties, RINs may 

only be used to demonstrate compliance 

with the RVOs for the calendar year in 

which they were generated or the 

following calendar year. 

(ii) [Reserved.] 

(iii) For Renewable Fuel Exporters, 

RINs generated in calendar year i, must 

be used to demonstrate compliance with 

the ERVOs from renewable fuel 

export(s) in calendar year i, except as 

provided in paragraph (a)(6)(iv) of this 

section. 

(iv) For Renewable Fuel Exporters, 

RINs generated in calendar year i-1, may 

only be used to demonstrate compliance 

with the ERVOs from renewable fuel 

exports in January of calendar year i. 

* * * * * 

■ 7. Section 80.1441 is amended by 

adding paragraph (e)(2)(iii) to read as 

follows: 

§ 80.1441 Small refinery exemption. 

* * * * * 

(e) * * * 

(2) * * * 

(iii) In order to qualify for an 

extension of its small refinery 

exemption, a refinery must meet the 

definition of ‘‘small refinery’’ in 

§ 80.1401 for all full calendar years 

between 2006 and the date of 

submission of the petition for an 

extension. 

* * * * * 

■ 8. Section 80.1450 is amended by: 

■ a. Adding paragraph (b)(1)(iv)(C); 

■ b. Revising paragraphs (b)(1)(v)(C), 

(b)(1)(v)(D); and adding (b)(1)(v)(E); and 

■ c. Adding paragraphs (h) and (i). 

The additions and revisions read as 

follows: 

§ 80.1450 What are the registration 

requirements under the RFS program? 

* * * * * 

(b) * * * 

(1) * * * 

(iv) * * * 

(C) To demonstrate compliance with 

the renewable electricity production 

requirement for the biogas-derived 

cellulosic diesel and cellulosic naphtha 

pathways, provide all the following 

information: 

(1) The energy source, equipment 

and/or process used to generate the 

electricity. Permitted sources are raw 

landfill gas, waste heat from the 

production process, unconverted syngas 

from the Fischer-Tropsch process, fuel 

gas from the hydroprocessing, or 

combined heat-and-power (CHP) units 

that use non-fossil fuel based gas or 

other renewable sources. 

(2) Estimates of the total amount of 

electricity to be used, the total amount 

of grid electricity to be purchased, the 

total amount of renewable electricity to 

be produced, and a calculation of the 

percent of total process electricity use to 

be produced from allowed sources at the 

facility. 

(v) * * * 

(C)(1) For all facilities, copies of 

documents demonstrating each facility’s 

actual peak capacity as defined in 

§ 80.1401 if the maximum rated annual 

volume output of renewable fuel is not 

specified in the air permits specified in 

paragraphs (b)(1)(v)(A) and (b)(1)(v)(B) 

of this section, as appropriate. 

(2) For facilities claiming the 

exemption described in § 80.1403 (c) or 

(d) which are exempt from air permit 

requirements and for which insufficient 

production records exist to establish 

actual peak capacity, copies of 

document demonstrating the facility’s 

nameplate capacity, as defined in 

§ 80.1401. 

(D) For all facilities producing 

renewable electricity or fuel from biogas 

that qualifies as renewable fuel, submit 

all relevant information in 

§ 80.1426(f)(10) or (11), and copies of all 

contracts that the track the biogas or 

renewable electricity from its original 

source, to the producer that processes it 

into renewable fuel, and finally to the 

end user that will actually use the 

renewable electricity or the renewable 

fuel derived from biogas for 

transportation purposes. 

(1) Specific quantity and the heat 

content, percent efficiency of transfer, if 

applicable, and any conversion factors 

of the biogas or renewable biomass. 

(2) Specific quantity and the heat 

content and percent efficiency of 

transfer, if applicable, and any 

conversion factors for the renewable 

fuel derived from biogas or renewable 

electricity. 

(E) Such other records as may be 

requested by the Administrator. 

* * * * * 

(h) Cancellation of Company 

Registration. (1) EPA may cancel a 

company’s registration, using the 

process in paragraph (h)(2) of this 

section, if any of the following 

circumstances exist: 

(i) The company has reported no 

activity in EMTS for one calendar year 

(January 1 through December 31) or has 

failed to meet any EMTS requirement 

under § 80.1452; 

(ii) The company has failed to comply 

with the registration requirements of 

this section; 

(iii) The company has failed to submit 

any required report within thirty (30) 

days of the required submission date 

under § 80.1451; or 

(iv) The attest engagement required 

under § 80.1454 has not been received 

within thirty (30) days of the required 

submission date. 

(2) EPA will use the following process 

whenever it decides to cancel the 

registration of a company: 

(i) EPA will notify the company’s 

owner or Responsible Corporate Officer 

(RCO), in writing, that it intends to 

cancel the company’s registration, and 

identifying the reasons for that proposed 

action. The company will have fourteen 

(14) calendar days from the date of the 

notification to correct the deficiencies 

identified or explain why there is no 

need for corrective action. 

(ii) If the basis for EPA’s notice of 

intent to cancel registration is the 

absence of EMTS activity for one 

calendar year, a stated intent to engage 

in activity reported through EMTS 

within the next calendar year will be 

sufficient to avoid cancellation of 

registration. 

(iii) If the company does not respond, 

does not correct identified deficiencies, 

or does not explain why such correction 

is not necessary within the time allotted 

for response, EPA may cancel the 

company’s registration within further 

notice to the party. 

(3) Impact of registration cancellation. 

(i) A company whose registration is 

cancelled shall still be liable for 

violation of any requirements of this 

subpart. 

(ii) A company whose registration is 

cancelled will not be listed on any 

public list of actively registered 

companies that is maintained by EPA. 

(iii) If the company whose registration 

is cancelled is a renewable fuel 

producer or foreign ethanol producer, it 

will not be listed on any public list of 

registered producers maintained by 

EPA. 

(iv) A company whose registration is 

cancelled will not have access to any of 

the electronic reporting systems 

associated with the renewable fuel 

standard program, including the EPA 

Moderated Transaction System (EMTS). 

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(v) A company whose registration is 

canceled must submit any corrections of 

deficiencies to EPA on forms, and 

following policies, established by EPA. 

(vi) If a company whose registration 

has been canceled wishes to re-register, 

they may initiate that process by 

submitting a new registration, consistent 

with paragraphs (a)–(c) of this section. 

(vii) English language registrations. 

Any document submitted to EPA under 

§ 80.1450 must be submitted in English, 

or shall include an English translation. 

■ 9. Section 80.1451 is amended by 

revising paragraphs (a)(1)(vi) and 

(b)(1)(ii)(Q), and by adding paragraph 

(h) to read as follows: 

§ 80.1451 What are the reporting 

requirements under the RFS program? 

(a) * * * 

(1) * * * 

(vi) The RVOs for obligated parties, as 

defined in § 80.1427(a) and for exporters 

of renewable fuel, as defined in 

§ 80.1427(a) and 80.1430(b), for the 

reporting year. 

* * * * * 

(b) * * * 

(1) * * * 

(ii) * * * 

(Q) Producers or importers of 

renewable fuel produced at facilities 

that use biogas for process heat as 

described in § 80.1426(f)(12), shall 

report the total energy supplied to the 

renewable fuel facility, in MMBtu based 

on metering of gas volume. Producers or 

importers of renewable fuel produced at 

facilities that meet the renewable 

electricity production requirement for 

the biogas-derived cellulosic diesel and 

cellulosic naphtha pathways as 

described in § 80.1426(f)(13), shall 

report the total renewable electricity 

produced by the renewable facility, in 

kilowatt-hour (kWh) or megawatt-hour 

(MWh), the total amount of electricity 

used, the total amount of grid electricity 

purchased, and a calculation verifying 

the percent of total process electricity 

from allowed sources produced on-site. 

* * * * * 

(h) English language reports. Any 

document submitted to EPA under 

§ 80.1451 must be submitted in English, 

or shall include an English translation. 

■ 10. Amend Section 80.1452 to revise 

paragraph (c) introductory text and add 

paragraphs (e) and (f) to read as follows: 

§ 80.1452 What are the requirements 

related to the EPA Moderated Transaction 

System (EMTS)? 

* * * * * 

(c) Starting July 1, 2010, each time 

any party sells, separates, or retires RINs 

generated on or after July 1, 2010, all of 

the following information must be 

submitted to EPA via the submitting 

party’s EMTS account within five (5) 

business days of the reportable event, 

except as provided in § 80.1430(f). 

Starting July 1, 2010, each time any 

party purchases RINs generated on or 

after July 1, 2010, all the following 

information must be submitted to EPA 

via the submitting party’s EMTS 

account within ten (10) business days of 

the reportable event. The reportable 

event for a RIN separation occurs on the 

date of separation as described in 

§ 80.1429. The reportable event for a 

RIN retirement occurs on the date of 

retirement as described in this subpart. 

* * * * * 

(e) [Reserved.] 

(f) [Reserved.] 

■ 11. Amend Section 80.1454 by 

■ a. Adding paragraph (a)(7); 

■ b. Revising paragraph (b)(4)(i); 

■ c. Adding paragraph (b)(7); 

■ d. Revising paragraph (f)(3)(i) and 

adding paragraph (f)(5); and 

■ e. Revising paragraph (k)(1); and 

■ f. Adding paragraph (q). 

The additions and revisions read as 

follows: 

§ 80.1454 What are the recordkeeping 

requirements under the RFS program? 

* * * * * 

(a) * * * 

(7) Records related to any volume of 

renewable fuel that was disqualified by 

the party pursuant to § 80.1433: 

(b) * * * 

(4) * * * 

(i) A list of the RINs owned, 

purchased, sold, separated, retired, or 

reinstated. 

* * * * * 

(7) Records related to any volume of 

renewable fuel where RINs were not 

generated by the renewable fuel 

producer or importer pursuant to 

§ 80.1426(c): 

* * * * * 

(f) * * * 

(3) * * * 

(i) A list of the RINs owned, 

purchased, sold, separated, retired, or 

reinstated. 

* * * * * 

(5) Records related to any volume of 

renewable fuel that was disqualified by 

the party pursuant to § 80.1433. 

* * * * * 

(k)(1) Biogas and electricity in 

pathways involving feedstocks other 

than grain sorghum. A renewable fuel 

producer that generates RINs for 

renewable CNG/LNG or renewable 

electricity produced from renewable 

biomass for fuels that are used for 

transportation pursuant to 

§ 80.1426(f)(10) and (11), or that uses 

process heat from biogas to generate 

RINs for renewable fuel pursuant to 

§ 80.1426(f)(12) or that meets the 

renewable electricity production 

requirement for the biogas-derived 

cellulosic diesel and cellulosic naphtha 

pathways pursuant to § 80.1426(f)(13) 

shall keep all of the following additional 

records: 

(i) Documents demonstrating the 

kilowatt-hours (kWh) of allowable 

electricity relied upon under 

§ 80.1426(f)(13) that was generated at 

the facility, if applicable. 

(ii) The energy source, equipment 

and/or process used to generate the 

electricity relied upon under 

§ 80.1426(f)(13), if applicable. Permitted 

sources are raw landfill gas, waste heat 

from the production process, 

unconverted syngas from the FischerTropsch process, fuel gas from the 

hydroprocessing, or combined heat-andpower (CHP) units that use non-fossil 

fuel based gas or other renewable 

sources. 

(iii) Contracts and documents 

memorializing the sale of renewable 

CNG/LNG or renewable electricity for 

use as transportation fuel relied upon in 

§ 80.1426(f)(10), § 80.1426(f)(11), or for 

use of biogas for use as process heat to 

make renewable fuel as relied upon in 

§ 80.1426(f)(12) and the transfer of title 

of the biogas or renewable electricity 

and all associated environmental 

attributes from the point of generation to 

the facility which sells or uses the fuel 

for transportation purposes. 

(iv) Documents demonstrating the 

volume and energy content of biogas, or 

kilowatts of renewable electricity, relied 

upon under § 80.1426(f)(10) that was 

delivered to the facility which sells or 

uses the fuel for transportation 

purposes. 

(v) Documents demonstrating the 

volume and energy content of biogas, or 

kilowatts of renewable electricity, relied 

upon under § 80.1426(f)(11), or biogas 

relied upon under § 80.1426(f)(12) that 

was placed into the common carrier 

pipeline (for biogas) or transmission line 

shared power grid (for renewable 

electricity). 

(vi) Documents demonstrating the 

volume and energy content of biogas 

relied upon under § 80.1426(f)(12) at the 

point of distribution. 

(vii) Affidavits from the biogas or 

renewable electricity producer and all 

parties that held title to the biogas or 

renewable electricity confirming that 

title and environmental attributes of the 

biogas or renewable electricity relied 

upon under § 80.1426(f)(10) and (11) 

were used for transportation purposes 

only, and that the environmental 

attributes of the biogas or process 

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electricity relied upon under 

§ 80.1426(f)(12) or § 80.1426(f)(13) were 

used for process heat or electricity at the 

renewable fuel producer’s facility, and 

for no other purpose. The renewable 

fuel producer shall create and/or obtain 

these affidavits at least once per 

calendar quarter. 

(viii) The biogas or renewable 

electricity producer’s Compliance 

Certification required under Title V of 

the Clean Air Act. 

(ix) Documents demonstrating the 

total amount of grid electricity 

purchased and calculations showing the 

percent of total electricity usage 

provided by allowable electricity 

production at the facility, if applicable. 

(x) Such other records as may be 

requested by the Administrator. 

* * * * * 

(q) English language records. Any 

document requested by the 

Administrator under this section must 

be submitted in English, or shall include 

an English translation. 

■ 12. Section 80.1463 is amended by 

adding paragraph (d) to read as follows: 

§ 80.1463 What penalties apply under the 

RFS program? 

* * * * * 

(d) Any person violating 

§ 80.1460(b)(1)–(4) or (6) engages in a 

separate violation for each day that an 

invalid RIN remains available for use in 

RFS compliance, and each such daily 

violation is punishable by the maximum 

daily penalty allowed under the Clean 

Air Act. 

■ 13. Section 80.1466 is amended by 

revising the section heading and 

paragraphs (a), (d)(1), (d)(1)(vi), 

(d)(3)(ii), (e)(1)(i), (f) introductory text, 

(h), (h)(1), and (o)(2) and adding 

paragraph (p) as follows: 

§ 80.1466 What are the additional 

requirements under this subpart for RINgenerating foreign producers, non RINgenerating foreign producers, foreign 

ethanol producers and importers of 

renewable fuels? 

(a) Foreign producer of renewable 

fuel. For purposes of this subpart, a 

foreign producer of renewable fuel is a 

person located outside the United 

States, the Commonwealth of Puerto 

Rico, the Virgin Islands, Guam, 

American Samoa, and the 

Commonwealth of the Northern Mariana 

Islands (collectively referred to in this 

section as ‘‘the United States’’) that has 

been registered with EPA as a renewable 

fuel producer or foreign ethanol 

producer, regardless of whether the 

foreign renewable fuel producer 

generates RINs or an importer of 

renewable fuel generates RINs for the 

fuel. Hereinafter referred to as a ‘‘foreign 

producer’’ under this section. 

(d) * * * (1) On each occasion that 

RFS–FRRF is loaded onto a vessel for 

transport to the United States the 

foreign producer shall have an 

independent third party do all the 

following: 

* * * * * 

(vi) Review original documents that 

reflect movement and storage of the 

RFS–FRRF from the foreign producer to 

the load port, and from this review 

determine all the following: 

* * * * * 

(3) * * * 

(ii) Be independent under the criteria 

specified in § 80.65(f)(2)(iii); and 

* * * * * 

(e) * * * (1)(i) Any foreign producer 

and any United States importer of RFS– 

FRRF shall compare the results from the 

load port testing under paragraph (d) of 

this section, with the port of entry 

testing as reported under paragraph (k) 

of this section, for the volume of 

renewable fuel, standardized per 

§ 80.1426(f)(8), except as specified in 

paragraph (e)(1)(ii) of this section. 

* * * * * 

(f) Foreign producer commitments. 

Any foreign producer shall commit to 

and comply with the provisions 

contained in this paragraph (f) as a 

condition to being approved as a foreign 

producer under this subpart. 

* * * * * 

(h) Bond posting. Any foreign 

producer shall meet the requirements of 

this paragraph (h) as a condition to 

approval as a foreign producer under 

this subpart and on a continuing basis 

if the foreign producer exceeds 

projections used in calculated the bond. 

(1) The foreign producer shall post a 

bond of the amount calculated using 

one of the two following equations 

whichever equation results in a higher 

bond value: 

Bond = G * $0.01 

Or 

Bond = .25 * S(Mi * RINi) 

Where: 

Bond = amount of the bond in U.S. dollars. 

G = the greater of: the largest volume of 

renewable fuel produced by the foreign 

producer and exported to the United 

States, in gallons, during a single 

calendar year among the five preceding 

calendar years, or the largest volume of 

renewable fuel that the foreign producer 

expects to export to the Unites States 

during any calendar year identified in 

the Production Outlook Report required 

by § 80.1449. If the volume of renewable 

fuel anticipated to be exported to the 

United States during any calendar year 

increases above the value used in 

calculating the existing bond amount, 

the foreign producer shall increase the 

bond by using the higher anticipated 

export volume for the calendar year to 

calculate a higher bond amount and 

purchasing the higher bond prior to the 

generation of RINs to reflect the increase 

in export volume. Mi = RIN multiplier 

for specified D code, i, in U.S. dollars, 

as follows: 

The RIN multiplier for a D3 RIN is $0.78 

The RIN multiplier for a D4 RIN is $1.30 

The RIN multiplier for a D5 RIN is $0.80 

The RIN multiplier for a D6 RIN is $0.02 

The RIN multiplier for a D7 RIN is $0.78 

RINi = the greater of: (i) the largest quantity 

of RINs for a specified D code, i, 

produced by the foreign producer and 

exported to the United States, in gallons, 

during a single calendar year among the 

five preceding calendar years, or (ii) the 

largest quantity of RINs that the foreign 

producer expects to export to the United 

States during any calendar year 

identified in the Production Outlook 

Report required by § 80.1449. If the 

volume of renewable fuel anticipated to 

be exported to the United States during 

any calendar year increases above the 

value used in calculating the existing 

bond amount, the foreign producer shall 

increase the bond by using the higher 

anticipated export volume for the 

calendar year to calculate a higher bond 

amount and purchasing the higher bond 

prior to the generation of RINs to reflect 

the increased export volume. 

* * * * * 

(o) 

(2) Signed by the president or owner 

of the foreign producer company, or by 

that person’s immediate designee, and 

shall contain the following declaration: 

‘‘I hereby certify: (1) That I have actual 

authority to sign on behalf of and to 

bind [INSERT NAME OF FOREIGN 

PRODUCER] with regard to all 

statements contained herein; (2) that I 

am aware that the information 

contained herein is being Certified, or 

submitted to the United States 

Environmental Protection Agency, 

under the requirements of 40 CFR part 

80, subpart M, and that the information 

is material for determining compliance 

under these regulations; and (3) that I 

have read and understand the 

information being Certified or 

submitted, and this information is true, 

complete and correct to the best of my 

knowledge and belief after I have taken 

reasonable and appropriate steps to 

verify the accuracy thereof. I affirm that 

I have read and understand the 

provisions of 40 CFR part 80, subpart M, 

including 40 CFR 80.1466 apply to 

[INSERT NAME OF FOREIGN 

PRODUCER]. Pursuant to Clean Air Act 

section 113(c) and 18 U.S.C. 1001, the 

penalty for furnishing false, incomplete 

or misleading information in this 

certification or submission is a fine of 

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up to $10,000 U.S., and/or 

imprisonment for up to five years.’’ 

(p) Foreign Produced Renewable Fuel 

and Foreign Produced Ethanol for 

Which RINs Have Been or Will Be 

Generated by the Importer 

(1) For non-RIN generating foreign 

producers and foreign ethanol 

producers already registered pursuant to 

section § 80.1450, all of the 

requirements in paragraphs (a) through 

(o) of this section must be satisfied no 

later than January 1, 2013. 

(2) For RIN generating foreign 

producers and foreign ethanol 

producers already registered pursuant to 

section § 80.1450 and 80.1466, 

paragraph (h) of this section must be 

satisfied no later than January 1, 2013 if 

the required amount in paragraph (h) of 

this section exceeds the original amount 

of the bond posted when the producer 

was originally approved under 80.1466. 

■ 14. Section 80.1500 is amended by 

revising the definitions of E10, E15, and 

EX to read as follows: 

§ 80.1500 Definitions. 

* * * * * 

E10 means a gasoline-ethanol blend 

that contains at least 9 and no more than 

10 volume percent ethanol. 

E15 means a gasoline-ethanol blend 

that contains greater than 10 volume 

percent ethanol and not more than 15 

volume percent ethanol. 

EX means a gasoline–ethanol blend 

that contains less than 9 volume percent 

ethanol where X equals the maximum 

volume percent ethanol in the gasolineethanol blend. 

* * * * * 

■ 15. Section 80.1501 is amended by 

revising the section 80.1501 heading 

paragraphs (a) introductory text, (b)(3)(i) 

and (iv), and (b)(4)(ii) to read as follows: 

§ 80.1501 What are the labeling 

requirements that apply to retailers and 

wholesale purchaser-consumers of 

gasoline-ethanol blends that contain 

greater than 10 volume percent ethanol and 

not more than 15 volume percent ethanol? 

(a) Any retailer or wholesale 

purchaser-consumer who sells, 

dispenses, or offers for sale or 

dispensing E15 shall affix the following 

conspicuous and legible label to the fuel 

dispenser: 

* * * * * 

(b) * * * 

(3) * * * 

(i) The word ‘‘ATTENTION’’ shall be 

capitalized in 20-point, orange, 

Helvetica Neue LT 77 Bold Condensed 

font, and shall be placed in the top 1.25 

inches of the label as further described 

in (b)(4)(iii) below. 

* * * * * 

(iv) The words ‘‘Use only in’’ shall be 

in 20-point, left-justified, black, 

Helvetica Bold font in the bottom 1.875 

inches of the label. 

(4) * * * 

* * * * * 

(ii) The background of the bottom 

1.875 inches of the label shall be orange. 

* * * * * 

■ 16. Section 80.1502 is amended by 

revising paragraphs (b)(3)(iii)(A), 

(b)(3)(iv), (b)(4)(iv)(B), (b)(4)(v)(A), 

(c)(4), and (c)(6) to read as follows: 

§ 80.1502 What are the survey 

requirements related to gasoline-ethanol 

blends? 

* * * * * 

(b) * * * 

(3) * * * 

(iii) * * * 

(A) Samples collected at retail outlets 

shall be shipped the same day the 

samples are collected via ground service 

to the laboratory and analyzed for 

oxygenate content. Samples collected at 

a dispenser labeled E15 in any manner, 

or at a tank serving such a dispenser, 

shall also be analyzed for RVP during 

the high ozone season defined in 

§ 80.27(a)(2)(ii) or any SIP approved or 

promulgated under §§ 110 or 172 of the 

Clean Air Act. Such analysis shall be 

completed within 10 days after receipt 

of the sample in the laboratory. Nothing 

in this section shall be interpreted to 

require RVP testing of a sample from 

any dispenser or tank serving it unless 

the dispenser is labeled E15 in any 

manner. 

* * * * * 

(iv) In the case of any test that yields 

a result that does not match the label 

affixed to the product (e.g., a sample 

greater than 15 volume percent ethanol 

dispensed from a fuel dispenser labeled 

as ‘‘E15’’ or a sample containing greater 

than 10 volume percent ethanol and not 

more than 15 volume percent ethanol 

dispensed from a fuel dispenser not 

labeled as ‘‘E15’’), or the RVP standard 

of § 80.27(a)(2), the independent survey 

association shall, within 24 hours after 

the laboratory has completed analysis of 

the sample, send notification of the test 

result as follows: 

* * * * * 

(4) * * * 

(iv) * * * 

(B) In the case of any retail outlet from 

which a sample of gasoline was 

collected during a survey and 

determined to have an ethanol content 

that does not match the fuel dispenser 

label (e.g. a sample greater than 15 

volume percent ethanol dispensed from 

a fuel dispenser labeled as ‘‘E15’’ or a 

sample with greater than 10 volume 

percent ethanol and not more than 15 

volume percent ethanol dispensed from 

a fuel dispenser not labeled as ‘‘E15’’) or 

determined to have a dispenser 

containing fuel whose RVP does not 

comply with § 80.27(a)(2), that retail 

outlet shall be included in the 

subsequent survey. 

* * * * * 

(v) * * * 

(A) The minimum number of samples 

to be included in the survey plan for 

each calendar year shall be calculated as 

follows: 

Where: 

n = minimum number of samples in a yearlong survey series. However, in no case 

shall n be smaller than 7,500. 

Za = upper percentile point from the normal 

distribution to achieve a one-tailed 95% 

confidence level (5% a-level). Thus, Za 

equals 1.645. 

Zb = upper percentile point to achieve 95% 

power. Thus, Zb equals 1.645. 

f1 = the maximum proportion of noncompliant stations for a region to be 

deemed compliant. In this test, the 

parameter needs to be 5% or greater, i.e., 

5% or more of the stations, within a 

stratum such that the region is 

considered non-compliant. For this 

survey, f1 will be 5%. 

fo= the underlying proportion of noncompliant stations in a sample. For the 

first survey plan, fo will be 2.3%. For 

subsequent survey plans, fo will be the 

average of the proportion of stations 

found to be non-compliant over the 

previous four surveys. 

Stn = number of sampling strata. For 

purposes of this survey program, Stn

equals 3. 

Fa = adjustment factor for the number of extra 

samples required to compensate for 

collected samples that cannot be 

included in the survey, based on the 


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number of additional samples required 

during the previous four surveys. 

However, in no case shall the value of Fa

be smaller than 1.1. 

Fb = adjustment factor for the number of 

samples required to resample each retail 

outlet with test results exceeding the 

labeled amount (e.g. a sample greater 

than 15 volume percent ethanol 

dispensed from a fuel dispenser labeled 

as ‘‘E15’’, a sample with greater than 10 

volume percent ethanol and not more 

than 15 volume percent ethanol 

dispensed from a fuel dispenser not 

labeled as ‘‘E15’’), or a sample dispensed 

from a fuel dispenser labeled as ‘‘E15’’ 

with greater than the applicable seasonal 

and geographic RVP pursuant to § 80.27, 

based on the rate of resampling required 

during the previous four surveys. 

However, in no case shall the value of Fb

be smaller than 1.1. 

Sun = number of surveys per year. For 

purposes of this survey program, Sun

equals 4. 

* * * * * 

(c) * * * 

(4) The survey program plan must be 

sent to the following address: Director, 

Compliance Division, U.S. 

Environmental Protection Agency, 1200 

Pennsylvania Ave. NW., Mail Code 

6506J, Washington, DC 20460. 

* * * * * 

(6) The approving official for a survey 

plan under this section is the Director 

of the Compliance Division, Office of 

Transportation and Air Quality. 

* * * * * 

■ 17. Section 80.1503 is amended by 

revising paragraphs (a)(1)(vi)(B)(3), 

(a)(1)(vi)(C)(2), adding paragraph 

(a)(1)(vi)(C)(3), and revising paragraphs 

(b)(1)(vi)(B) through (D). 

The revisions and additions read as 

follows: 

§ 80.1503 What are the product transfer 

document requirements for gasolineethanol blends, gasolines, and conventional 

blendstocks for oxygenate blending subject 

to this subpart? 

(a) * * * 

(1) * * * 

(vi) * * * 

(B) * * * 

(3) ‘‘The use of this blendstock/ 

gasoline to manufacture a gasolineethanol blend containing anything other 

than between 9 and 10 volume percent 

ethanol may cause a summertime RVP 

violation.’’ 

(C) * * * 

(2) The requirements in paragraph 

(a)(1) do not apply to reformulated 

gasoline blendstock for oxygenate 

blending, as defined in § 80.2(kk), 

which is subject to the product transfer 

document requirements of § 80.69 and 

§ 80.77. 

(3) Except for transfers to truck 

carriers, retailers, or wholesale 

purchaser-consumers, product codes 

may be used to convey the information 

required under paragraph (a)(1) of this 

section if such codes are clearly 

understood by each transferee. 

(b) * * * 

(1) * * * 

(vi) * * * 

(B) For gasoline containing less than 

9 volume percent ethanol, the following 

statement: ‘‘EX—Contains up to X% 

ethanol. The RVP does not exceed [fill 

in appropriate value] psi.’’ The term X 

refers to the maximum volume percent 

ethanol present in the gasoline. 

(C) For gasoline containing between 9 

and 10 volume percent ethanol (E10), 

the following statement: ‘‘E10: Contains 

between 9 and 10 vol % ethanol. The 

RVP does not exceed [fill in appropriate 

value] psi. The 1 psi RVP waiver applies 

to this gasoline. Do not mix with 

gasoline containing anything other than 

between 9 and 10 vol % ethanol.’’ 

(D) For gasoline containing greater 

than 10 volume percent and not more 

than 15 volume percent ethanol (E15), 

the following statement: ‘‘E15: Contains 

up to 15 vol % ethanol. The RVP does 

not exceed [fill in appropriate value] 

psi;’’ or 

* * * * * 

■ 18. Section 80.1504 is amended by 

revising paragraphs (a)(1), (a)(3), (e), and 

(g) to read as follows: 

§ 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 lightduty gasoline motor vehicle, any heavyduty gasoline motor vehicle or engine, 

any highway or off-highway motorcycle, 

or any gasoline-powered nonroad 

engines, vehicles or equipment. 

* * * * * 

(3) Notwithstanding paragraphs (a)(1) 

and (a)(2) of this section, no person 

shall be prohibited from manufacturing, 

selling, introducing, or causing or 

allowing the sale or introduction of 

gasoline containing greater than 10 

volume percent ethanol into any flexfuel vehicle. 

* * * * * 

(e)(1) Improperly blend, or cause the 

improper blending of, ethanol into 

conventional blendstock for oxygenate 

blending, gasoline or gasoline already 

containing ethanol, in a manner 

inconsistent with the information on the 

product transfer document under 

§ 80.1503(a)(1)(vi) or § 80.1503(b)(1)(vi); 

(2) No person shall produce E10 by 

blending ethanol and gasoline in a 

manner designed to produce a fuel that 

contains less than 9.0 or more than 10.0 

volume percent ethanol. 

(3) No person shall produce E15 by 

blending ethanol and gasoline in a 

manner designed to produce a fuel that 

contains less than 10.0 volume percent 

ethanol or more than 15.0 volume 

percent ethanol. 

(4) No person shall produce EX by 

blending ethanol and gasoline in a 

manner designed to produce a fuel that 

contains less than 9.0 volume percent 

ethanol. 

* * * * * 

(g) For gasoline during the regulatory 

control periods, combine any gasolineethanol blend that qualifies for the 1 psi 

allowance under the special regulatory 

treatment as provided by § 80.27(d) 

applicable to 9–10 volume percent 

gasoline-ethanol blends with any 

gasoline containing less than 9 volume 

percent ethanol or more than 10 volume 

percent ethanol up to a maximum of 15 

volume percent ethanol. 

* * * * * 

■ 19. Section 80.1508 is amended by 

revising paragraph (b) as follows: 

§ 80.1508 What evidence may be used to 

determine compliance with the 

requirements of this subpart and liability for 

violations of this subpart? 

* * * * * 

(b) Determinations of compliance 

with the requirements of this subpart 

and determinations of liability for any 

violation of this subpart may be based 

on information obtained from any 

source or location. Such information 

may include, but is not limited to, 

business records and commercial 

documents. 

■ 20. Section 80.1509 is added to read 

as follows: 

§ 80.1509 Rounding a test result for 

purposes of this Subpart. 

The provisions of Section 80.9 apply 

for purposes of determining the ethanol 

content of a gasoline-ethanol blend 

under this subpart. 

[FR Doc. 2013–12714 Filed 6–13–13; 8:45 am] 

BILLING CODE 6560–50–P 

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