38844 Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 80 

[EPA–HQ–OAR–2010–0133; FRL–9324–3] 

RIN 2060–AQ76 

Regulation of Fuels and Fuel 

Additives: 2012 Renewable Fuel 

Standards 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: Under the Clean Air Act 

Section 211(o), the Environmental 

Protection Agency is required to set the 

renewable fuel standards each 

November for the following year. In 

general the standards are designed to 

ensure that the applicable volumes of 

renewable fuel specified in the statute 

are used. However, the statue specifies 

that EPA is to project the volume of 

cellulosic biofuel production for the 

upcoming year and must base the 

cellulosic biofuel standard on that 

projected volume if it is less than the 

applicable volume set forth in the Act. 

EPA is today proposing a projected 

cellulosic biofuel volume for 2012 and 

annual standards for cellulosic biofuel, 

biomass-based diesel, advanced biofuel, 

and renewable fuels that would apply to 

all gasoline and diesel produced or 

imported in year 2012. In addition, 

today’s action proposes an applicable 

volume of biomass-based diesel that 

would apply in 2013. This action also 

presents a number of proposed changes 

to the RFS2 regulations that are 

designed to clarify existing provisions 

and to address several unique 

circumstances that have come to light 

since the RFS2 program became 

effective on July 1, 2010. Finally, 

today’s rule also proposes to make a 

minor amendment to the gasoline 

benzene regulations regarding inclusion 

of transferred blendstocks in a refinery’s 

early benzene credit generation 

calculations. 

DATES: Comments must be received on 

or before August 11, 2011. 

Hearing: We intend to hold a public 

hearing on July 12, 2011 in the 

Washington, DC area, Details of the time 

and location of the hearing be 

announced in a separate notice. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2010–0133, by one of the 

following methods: 

• http://www.regulations.gov: Follow 

the on-line instructions for submitting 

comments. 

• E-mail: asdinfo@epa.gov. 

• Mail: Air and Radiation Docket and 

Information Center, Environmental 

Protection Agency, Mailcode: 2822T, 

1200 Pennsylvania Ave., NW., 

Washington, DC 20460. 

• Hand Delivery: EPA Docket Center, 

EPA West Building, Room 3334, 1301 

Constitution Ave., NW., Washington, 

DC 20460. 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–2010– 

0133. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http:// 

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 http:// 

www.regulations.gov or e-mail. The 

http://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 e-mail comment directly 

to EPA without going through http:// 

www.regulations.gov your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. For additional information 

about EPA’s public docket visit the EPA 

Docket Center homepage at http:// 

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

For additional instructions on 

submitting comments, go to Section I.B 

of the SUPPLEMENTARY INFORMATION

section of this document. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the Air and Radiation Docket and 

Information Center, 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 Docket is (202) 566– 

1742. 

FOR FURTHER INFORMATION CONTACT: Julia 

MacAllister, Office of Transportation 

and Air Quality, Assessment and 

Standards Division, Environmental 

Protection Agency, 2000 Traverwood 

Drive, Ann Arbor MI 48105; Telephone 

number: 734–214–4131; Fax number: 

734–214–4816; E-mail address: 

macallister.julia@epa.gov, or 

Assessment and Standards Division 

Hotline; telephone number 734 214– 

4636; E-mail address asdinfo@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 

A. Does this action apply to me? 

Entities potentially affected by this 

proposed rule are those involved with 

the production, distribution, and sale of 

transportation fuels, including gasoline 

and diesel fuel or renewable fuels such 

as ethanol and biodiesel. Potentially 

regulated categories include: 

Category NAICS1

codes 

SIC 2

codes Examples of potentially regulated entities 

Industry ................................................. 324110 2911 Petroleum Refineries. 

Industry ................................................. 325193 2869 Ethyl alcohol manufacturing. 

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

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. 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 38845 

Category NAICS1

codes 

SIC 2

codes Examples of potentially regulated entities 

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

1 North American Industry Classification System (NAICS). 2 Standard Industrial Classification (SIC) system code. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this proposed action. This 

table lists the types of entities that EPA 

is now aware could potentially be 

regulated by this proposed action. Other 

types of entities not listed in the table 

could also be regulated. To determine 

whether your activities would be 

regulated by this proposed action, you 

should carefully examine the 

applicability criteria in 40 CFR part 80. 

If you have any questions regarding the 

applicability of this proposed action to 

a particular entity, consult the person 

listed in the preceding section. 

B. What should I consider as I prepare 

my comments for EPA? 

1. Submitting CBI 

Do not submit confidential business 

information (CBI) to EPA through 

http://www.regulations.gov or e-mail. 

Clearly mark the part or all of the 

information that you claim to be CBI. 

For CBI information in a disk or CD 

ROM that you mail to EPA, mark the 

outside of the disk or CD ROM as CBI 

and then identify electronically within 

the disk or CD ROM the specific 

information that is claimed as CBI. In 

addition to one complete version of the 

comment that includes information 

claimed as CBI, a copy of the comment 

that does not contain the information 

claimed as CBI must be submitted for 

inclusion in the public docket. 

Information so marked will not be 

disclosed except in accordance with 

procedures set forth in 40 CFR part 2. 

2. 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. 

Outline of This Preamble 

I. Executive Summary 

A. Standards For 2012 

1. Assessment Of 2012 Cellulosic Biofuel 

Volume 

2. Advanced Biofuel And Total Renewable 

Fuel In 2012 

3. Proposed Percentage Standards For 2012 

B. Proposed 2013 Biomass-Based Diesel 

Volume 

C. Proposed Regulatory Changes 

D. Petition For Reconsideration 

II. Projection Of Cellulosic Volume 

Production And Imports For 2012 

A. Statutory Requirements 

B. Cellulosic Biofuel Volume Assessment 

1. Existing Cellulosic Biofuel Facilities 

2. Potential New Facilities In 2012 

3. Imports Of Cellulosic Biofuel 

4. Summary Of Volume Projections 

C. Potential Limitations In 2012 

D. Advanced Biofuel And Total Renewable 

Fuel In 2012 

E. Biomass-Based Diesel In 2012 

III. Proposed Percentage Standards For 2012 

A. Background 

B. Calculation Of Standards 

1. How Are The Standards Calculated? 

2. Small Refineries And Small Refiners 

3. Proposed Standards 

IV. Biomass-Based Diesel Volume For 2013 

A. Statutory Requirements 

B. Factors Considered In Assessing 2013 

Biomass-Based Diesel Volumes 

1. Demand For Biomass-Based Diesel 

2. Availability Of Feedstocks To Produce 

1.28 Billion Gallons Of Biodiesel 

3. Production Capacity 

4. Consumption Capacity 

5. Biomass-Based Diesel Distribution 

Infrastructure 

C. Impacts Of 1.28 Billion Gallons Of 

Biomass-Based Diesel 

1. Climate Change 

2. Energy Security 4 

3. Agricultural Commodities And Food 

Prices 

4. Air Quality 

5. Transportation Fuel Cost 

6. Deliverability And Transport Costs Of 

Materials, Goods, And Products Other 

Than Renewable Fuel 

7. Wetlands, Ecosystems, And Wildlife 

Habitats 

8. Water Quality And Quantity 

a. Impacts On Water Quality And Water 

Quantity Associated With Soybean 

Production 

b. Impacts On Water Quality And Water 

Quantity Associated With Biodiesel 

Production 

9. Job Creation And Rural Economic 

Development 

D. Proposed 2013 Volume For BiomassBased Diesel 

E. 2014 And Beyond 

V. Proposed Changes To Rfs2 Regulations 

A. Summary Of Amendments 

B. Technical Justification For Equivalence 

Value Application 

C. Changes To Definitions Of Terms 

1. Definition Of Annual Cover Crop 

2. Definition Of ‘‘Naphtha’’ 

D. Technical Amendments Related To Rin 

Generation And Separation 

1. Rin Separation Limit For Obligated 

Parties 

2. Rin Retirement Provision For Error 

Correction 

3. Production Outlook Reports Submission 

Deadline 

4. Attest Procedures 

5. Treatment Of Canola And Rapeseed 

E. Technical Amendments Related To 

Registration 

1. Construction Discontinuance & 

Completion Documentation 

2. Third-Party Engineering Reviews 

3. Foreign Ethanol Producers 

F. Additional Amendments And 

Clarifications 

1. Third-Party Engineering Review 

Addendum 

2. Rin Generation For Fuel Imported From 

A Registered Foreign Producer 

3. Bond Posting 

4. Acceptance Of Separated Yard Waste 

And Food Waste Plans 

5. Transferred Blendstocks In Early 

Benzene Credit Generation Calculations 

VI. Petition For Reconsideration 

A. Legal Considerations Of Petition 

B. Advanced Biofuel Standard And 

Delayed Rins 

C. 2011 Cellulosic Biofuel Requirement 

VII. Public Participation 

A. How Do I Submit Comments? 

B. How Should I Submit Cbi To The 

Agency? 

VIII. Statutory And Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning And Review And Executive 

Order 13563: Improving Regulation And 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
38846 Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 

1 75 FR 14670. 

F. Executive Order 13175: Consultation 

And Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection Of 

Children From Environmental Health 

Risks And Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, Or Use 

I. National Technology Transfer 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice In 

Minority Populations And Low-Income 

Populations 

IX. Statutory Authority 

I. Executive Summary 

The Renewable Fuel Standard (RFS) 

program began in 2006 pursuant to the 

requirements in Clean Air Act (CAA) 

section 211(o) which were added 

through the Energy Policy Act of 2005 

(EPAct). The statutory requirements for 

the RFS program were subsequently 

modified through the Energy 

Independence and Security Act of 2007 

(EISA), resulting in the promulgation of 

revised regulatory requirements on 

March 26, 2010.1 The transition from 

the RFS1 requirements of EPAct to the 

RFS2 requirements of EISA generally 

occurred on July 1, 2010. 

Under RFS2, EPA is required to 

determine and publish the applicable 

annual percentage standards for each 

compliance year by November 30 of the 

previous year. As part of this effort, EPA 

must determine the projected volume of 

cellulosic biofuel production for the 

following year. If the projected volume 

of cellulosic biofuel production is less 

than the applicable volume specified in 

section 211(o)(2)(B)(i)(III) of the statute, 

EPA must lower the applicable volume 

used to set the annual cellulosic biofuel 

percentage standard to the projected 

volume of production. When we lower 

the applicable volume of cellulosic 

biofuel in this manner, we are also 

authorized to lower the applicable 

volumes of advanced biofuel and/or 

total renewable fuel by the same or a 

lesser amount. Since these evaluations 

will be based on evolving information 

about emerging segments of the biofuels 

industry, and may result in the 

applicable volumes differing from those 

in the statute, we believe that it is 

appropriate to establish the applicable 

volumes through a notice-and-comment 

rulemaking process. Today’s notice 

provides our proposed evaluation of the 

projected production of cellulosic 

biofuel for 2012, our proposed 

evaluation of whether to lower the 

applicable volumes of advanced biofuel 

and total renewable fuel, and the 

proposed percentage standards for 

compliance year 2012. We will 

complete our evaluation based on 

comments received in response to this 

proposal, the estimate of projected 

biofuel volumes that the EIA is required 

to provide to EPA by October 31, and 

other information that becomes 

available, and will make final 

determinations of applicable volumes 

and percentage standards for 2012 by 

November 30, 2011. 

The statute also requires EPA to 

determine and promulgate the 

applicable volume of biomass-based 

diesel that will be required in 2013 and 

beyond, as the statute does not specify 

the applicable volumes for years after 

2012. This determination must be made 

at least 14 months prior to the year in 

which the volume will be required. 

Thus, for the 2013 compliance year, we 

must specify the applicable volume of 

biomass-based diesel by November 1, 

2011. The statute identifies a number of 

factors that EPA must take into 

consideration in establishing the 

applicable volume of biomass-based 

diesel for years after 2012. Today’s 

notice includes our proposed 

assessment of these factors and 

proposed applicable volume of biomassbased diesel for 2013. 

Today’s proposed rule does not 

include an assessment of the 

environmental impacts of the 

percentage standards we are proposing 

for 2012. All of the impacts of the RFS2 

program were addressed in the RFS2 

final rule published on March 26, 2010, 

including impacts of the biofuel 

standards specified in the statute. 

Today’s rulemaking simply proposes the 

standards for 2012 whose impacts were 

already analyzed previously. However, 

as described more fully in Section IV.A, 

we are required to analyze a specified 

set of environmental and economic 

impacts for the biomass-based diesel 

volume we are proposing for 2013. 

Today’s notice also proposes a 

number of changes to the RFS2 

regulations. These changes are designed 

to reduce confusion among regulated 

parties and streamline implementation 

by clarifying certain terms and phrases 

and addressing unique circumstances 

that came to light after the RFS2 

program went into effect on July 1, 

2010. Additionally, this notice also 

proposes to make a minor amendment 

to the gasoline benzene regulations 

regarding inclusion of transferred 

blendstocks in a refinery’s early benzene 

credit generation calculations. Further 

discussion of all of these proposed 

changes can be found in Section V. 

Finally, we note that in the RFS2 final 

rule we also stated our intent to make 

two announcements each year: 

• Set the price for cellulosic biofuel 

waiver credits that will be made 

available to obligated parties in the 

event that we reduce the volume of 

cellulosic biofuel below the volume 

required by EISA. 

• Announce the results of our 

assessment of the aggregate compliance 

approach for verifying renewable 

biomass requirements for U.S. crops and 

crop residue, and our conclusion 

regarding whether the aggregate 

compliance provision will continue to 

apply. 

For both of these determinations, EPA 

will use specific sources of data and a 

methodology laid out in the RFS2 final 

rule. Since the necessary data for these 

determinations are not yet available, 

and the methodology for making them is 

specified by rule or statute, we are not 

including proposed determinations in 

this Notice. We will present the results 

of both of these determinations in the 

final rule without a prior proposal. 

A. Standards for 2012 

1. Assessment of 2012 Cellulosic Biofuel 

Volume 

To estimate the volume of cellulosic 

biofuel that could be made available in 

the U.S. in 2012, we researched all 

potential production sources by 

company and facility. This included 

sources that were still in the planning 

stages, those that were under 

construction, and those that are already 

producing some volume of cellulosic 

ethanol, cellulosic diesel, or some other 

type of cellulosic biofuel. Facilities 

primarily focused on research and 

development work with no intention of 

marketing any fuel produced were not 

considered for this assessment. From 

this universe of potential cellulosic 

biofuel sources we identified the subset 

that had a possibility of producing some 

volume of qualifying cellulosic biofuel 

for use as transportation fuel in 2012. 

For the final rule, we will specify the 

projected available volume for 2012 that 

will be the basis for the percentage 

standard for cellulosic biofuel. To 

determine this final projected available 

volume, we will consider additional 

factors such as the current and expected 

state of funding, the status of the 

technology, and progress towards 

construction and production goals along 

with any other significant factors that 

could potentially impact fuel 

production or the ability of the 

produced fuel to generate cellulosic 

RINs. This information, to the extent 

that it is publically available, is 


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Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 38847 

discussed in further detail in Section 

II.B. 

In our assessment we focused on 

domestic sources of cellulosic biofuel. 

While imports of cellulosic biofuels are 

possible and would be eligible to 

generate RINs, we believe this is 

unlikely due to local demand for 

cellulosic biofuels in the countries in 

which they are produced as well as the 

cost associated with transporting these 

fuels to the U.S. Of the domestic 

sources, we estimated that nine facilities 

have the potential to make volumes of 

cellulosic biofuel available for 

transportation use in the U.S. in 2012. 

These facilities are listed in Table 

I.A.1–1 along with our estimate of the 

potentially available volume. 

TABLE I.A.1–1—POTENTIALLY AVAILABLE CELLULOSIC BIOFUEL PLANT VOLUMES FOR 2012 

Company Location Fuel type 

Potentially 

available 

volume 

(million 

ethanolequivalent 

gallons) 

DuPont Danisco Cellulosic Ethanol ........... Vonore, TN ................................................ Ethanol ...................................................... 0 .25 

Fiberight ..................................................... Blairstown, IA ............................................ Ethanol ...................................................... 3 .0 

Fulcrum Bioenergy ..................................... McCarran, NV ........................................... Ethanol ...................................................... 0 .5 

INEOS Bio .................................................. Vero Beach, FL ......................................... Ethanol ...................................................... 3 .0 

KiOR ........................................................... Houston, TX .............................................. Gasoline, Diesel ........................................ 0 .3 

KiOR ........................................................... Columbus, MS ........................................... Gasoline, Diesel ........................................ 6 .4 

KL Energy Corp. ........................................ Upton, WY ................................................. Ethanol ...................................................... 1 .0 

Terrabon ..................................................... Port Arthur, TX .......................................... Gasoline .................................................... 1 .0 

ZeaChem ................................................... Boardman, OR .......................................... Ethanol ...................................................... 0 .25 

Total .................................................... .................................................................... .................................................................... 15 .7 

The volumes in Table I.A.1–1 for each 

facility represent the volume that would 

be produced in 2012 based upon the 

owner’s expected month of startup and 

an assumed period of production 

rampup to full capacity for testing and 

process validation purposes. However, 

none of the facilities we evaluated are 

currently producing cellulosic biofuel at 

the rates they project for 2012. 

Moreover, there are other uncertainties 

associated with each facility’s projected 

volume that could result in less 

production volume in 2012 than the 

potentially available values shown in 

Table I.A.1–1. Therefore, we are 

proposing a range of volumes for 

cellulosic biofuel for 2012, with 15.7 

million ethanol-equivalent gallons as 

the upper end of the range. For the 

lower end of the range, we believe that 

a volume of 3.55 million ethanolequivalent gallons could be justified 

based on currently available 

information. This volume is based on 

consideration of only those facilities 

that are structurally complete at the 

time of this proposal and that anticipate 

commercial production of cellulosic 

biofuels by the end of 2011. More 

complete information on the progress of 

the industry in 2011 will be available 

for the final rule, and will allow us to 

make a more accurate projection of 

cellulosic biofuel volume for 2012. A 

more detailed discussion of these 

uncertainties is presented in Section 

II.B. 

2. Advanced Biofuel and Total 

Renewable Fuel in 2012 

The statute indicates that we may 

reduce the applicable volume of 

advanced biofuel and total renewable 

fuel if we determine that the projected 

volume of cellulosic biofuel production 

for 2012 falls short of the statutory 

volume of 500 million gallons. As 

shown in Table I.A.1–1, we are 

proposing a determination that this is 

the case. Therefore, we also must 

evaluate the need to lower the 

applicable volumes for the advanced 

biofuel and total renewable fuel. 

To address the need to lower the 

advanced biofuel standard, we first 

consider whether it appears likely that 

the biomass-based diesel volume of 1.0 

billion gallons specified in the statute 

can be met in 2012. As discussed in 

Section II.E, we believe that the 1.0 

billion gallon standard can indeed be 

met. Since biodiesel has an Equivalence 

Value of 1.5, 1.0 billion physical gallons 

of biodiesel would provide 1.5 billion 

ethanol-equivalent gallons that can be 

counted towards the advanced biofuel 

standard of 2.0 billion gallons. Of the 

remaining 0.5 bill gallons, up to 0.016 

bill gallons would be met with the 

proposed volume of cellulosic biofuel. 

Based on our analysis as described in 

Section II.D, it appears likely that there 

will be sufficient volumes of other 

advanced biofuels, such as imported 

sugarcane ethanol, additional biodiesel, 

or renewable diesel, such that the 

standard for advanced biofuel could 

remain at the statutory level of 2.0 

billion gallons. However, uncertainty in 

the potential volumes of these other 

advanced biofuels coupled with the 

range of potential production volumes 

of cellulosic biofuel could provide a 

rationale for lowering the advanced 

biofuel standard. If we lowered the 

applicable volume of advanced biofuel 

without simultaneously lowering the 

applicable volume for total renewable 

fuel, the result would be that additional 

volumes of conventional renewable fuel, 

such as corn-starch ethanol, would be 

produced, effectively replacing some 

advanced biofuels. In today’s NPRM we 

are proposing that neither the required 

2012 volumes for advanced biofuel nor 

total renewable fuel be lowered below 

the statutory volumes. However, we 

request comment on whether the 

advanced biofuel and/or total renewable 

fuel volume requirements should be 

lowered if, as we propose, EPA lowers 

the required cellulosic biofuel volume 

from that specified in the Act. 

3. Proposed Percentage Standards for 

2012 

The renewable fuel standards are 

expressed as a volume percentage, and 

are used by each refiner, blender or 

importer to determine their renewable 

fuel volume obligations. The applicable 

percentages are set so that if each 

regulated party meets the percentages, 

and if EIA projections of gasoline and 

diesel use are accurate, then the amount 

of renewable fuel, cellulosic biofuel, 

biomass-based diesel, and advanced 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
38848 Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 

2The April 2011 issue of STEO was used for 

today’s proposal. 

3 DOE report ‘‘EPACT 2005 Section 1501 Small 

Refineries Exemption Study’’, (January, 2009). 

4 ‘‘Small Refinery Exemption Study: An 

Investigation into Disproportionate Economic 

Hardship,’’ U.S. Department of Energy, March 2011. 

biofuel used will meet the volumes 

required on a nationwide basis. 

To calculate the percentage standard 

for cellulosic biofuel for 2012, we have 

used a potential volume range of 3.55– 

15.7 million ethanol-equivalent gallons 

(representing 3.45–12.9 million physical 

gallons). For the final rule, EPA intends 

to pick a single value from within this 

range to represent the projected 

available volume on which the 2012 

percentage standard for cellulosic 

biofuel will be based. We are also 

proposing that the applicable volumes 

for biomass-based diesel, advanced 

biofuel, and total renewable fuel for 

2012 will be those specified in the 

statute. These volumes are shown in 

Table I.A.3–1. 

TABLE I.A.3–1—PROPOSED VOLUMES FOR 2012 

Actual volume Ethanol equivalent volume a

Cellulosic biofuel ................................................ 3.45–12.9 mill gal ............................................. 3.55–15.7 mill gal. 

Biomass-based diesel ....................................... 1.0 bill gal ......................................................... 1.5 bill gal. 

Advanced biofuel ............................................... 2.0 bill gal ......................................................... 2.0 bill gal. 

Renewable fuel .................................................. 15.2 bill gal ....................................................... 15.2 bill gal. 

aBiodiesel and cellulosic diesel have equivalence values of 1.5 and 1.7 ethanol equivalent gallons respectively. As a result, ethanol-equivalent 

volumes are larger than actual volumes for cellulosic biofuel and biomass-based diesel. 

Four separate standards are required 

under the RFS2 program, corresponding 

to the four separate volume 

requirements shown in Table I.A.3–1. 

The specific formulas we use to 

calculate the renewable fuel percentage 

standards are contained in the 

regulations at § 80.1405 and repeated in 

Section III.B.1. The percentage 

standards represent the ratio of 

renewable fuel volume to projected nonrenewable gasoline and diesel volume. 

The projected volume of gasoline used 

to calculate the standards in today’s 

proposal is provided by EIA’s ShortTerm Energy Outlook (STEO).2 The 

projected volume of transportation 

diesel used to calculate the standards in 

today’s proposal is provided by EIA’s 

2011 Annual Energy Outlook (early 

release version). For the final rule, we 

will use updated projections of gasoline 

and diesel provided by EIA. 

Because DOE’s 2009 analysis 3

concluded that small refineries would 

not be disproportionately harmed by 

inclusion in the RFS program, beginning 

in 2011, small refiners and small 

refineries participated in the RFS 

program as full regulated parties, and 

there was no small refiner/refinery 

volume adjustment to the 2011 standard 

as there was for the 2010 standard. 

However, DOE recently re-evaluated the 

impacts of the RFS program on small 

entities and concluded that some small 

refineries would suffer a 

disproportionate hardship if required to 

participate in the program.4 As a result, 

we are required to exempt these few 

refineries from being obligated parties 

for a minimum of two years, and must 

also exempt their gasoline and diesel 

volumes from the calculation of the 

annual percentage standards. The 

proposed standards for 2012 are shown 

in Table I.A.3–2 and include the 

adjustment for exempt small refineries 

(which constitute about 2.5% of both 

gasoline and diesel pools). Detailed 

calculations can be found in Section III. 

TABLE I.A.3–2—PROPOSED

PERCENTAGE STANDARDS FOR 2012 

Cellulosic biofuel ....... 0.002 to 0.010%. 

Biomass-based diesel 0.91%. 

Advanced biofuel ...... 1.21%. 

Renewable fuel ......... 9.21%. 

B. Proposed 2013 Biomass-Based Diesel 

Volume 

While section 211(o)(2)(B) specifies 

the volumes of biomass-based diesel 

(BBD) through year 2012, it directs the 

EPA to establish the applicable volume 

of BBD for years after 2012 no later than 

14 months before the first year for 

which the applicable volume will apply. 

In today’s action we are proposing an 

applicable volume of 1.28 bill gallons 

for biomass-based diesel (BBD) for 2013. 

This is the volume that was projected 

for 2013 in the RFS2 final rulemaking, 

and we are proposing it for 2013 based 

on consideration of the factors specified 

in the statute, including a consideration 

of biodiesel production, consumption, 

and infrastructure issues. As required 

under the statute, we also assessed the 

likely impact of BBD production and 

use in a variety of areas, including 

climate change, energy security, the 

agricultural sector, air quality, and 

others. Section IV provides additional 

discussion of our assessment of the 

proposed volume of 1.28 bill gallons of 

BBD. 

C. Proposed Regulatory Changes 

In today’s action we are also 

proposing a number of changes to the 

RFS2 regulations. These proposed 

changes are intended to: 

• Clarify certain provisions because 

we have learned that there is some 

confusion among some regulated parties 

• Clarify the application of certain 

provisions to unique circumstances 

• Provide greater specificity in the 

definition of certain terms 

• Correct regulatory language that 

inadvertently misrepresented our intent 

Today’s rule also proposes to make a 

minor amendment to the gasoline 

benzene regulations regarding inclusion 

of transferred blendstocks in a refinery’s 

early benzene credit generation 

calculations. A detailed discussion of 

these proposed regulatory changes is 

provided in Section V. 

D. Petition for Reconsideration 

The American Petroleum Institute 

(API) and the National Petrochemical 

and Refiners Association (NPRA) jointly 

submitted a Petition for Reconsideration 

of EPA’s final rule establishing the RFS 

standards for 2011. The petition 

requests that we lower the 2011 

cellulosic biofuel standard to no more 

than 3.94 mill gallons, lower the 2011 

advanced biofuel standard in concert 

with the reduction in the cellulosic 

biofuel standard from 250 mill gallons, 

and reconsider the regulatory provision 

for delayed RINs. We are proposing to 

deny this petition. See Section VI for 

further discussion. 

II. Projection of Cellulosic Volume 

Production and Imports for 2012 

In order to project production volume 

of cellulosic biofuel in 2012 for use in 

setting the percentage standard, we 

collected information on individual 

facilities that have the potential to 

produce qualifying volumes for 


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consumption as transportation fuel, 

heating oil, or jet fuel in the U.S. in 

2012. This section describes the range of 

volumes that could be produced and 

imported in 2012 as well as some of the 

uncertainties associated with those 

volumes. For today’s NPRM we have 

assessed the range of potentially 

available volumes for 2012. Despite 

significant advances in cellulosic 

biofuel production technology in recent 

years the production of cellulosic 

biofuel remains highly uncertain. While 

we expect that the volume we select in 

the final rule for use in setting the 2012 

cellulosic biofuel percentage standard 

will be within our proposed range of 

volumes, we recognize the possibility 

that updated information at the time of 

the final rule could result in the final 

volume falling outside of the proposed 

range. Section III describes the 

conversion of our proposed range of 

volumes for cellulosic biofuel into a 

range of possible percentage standards. 

While the proposed 2012 volume 

projections in today’s NPRM were based 

on our own assessment of the cellulosic 

biofuel industry, by the time we 

announce the final 2012 volumes and 

percentage standards we will have 

additional information. First, in 

addition to comments in response to 

today’s proposal, we will have updated 

and more detailed information about 

how the industry is progressing in 2011. 

Second, all registered producers and 

importers of renewable fuel must submit 

Production Outlook Reports describing 

their expectations for new or expanded 

biofuel supply for the next five years, 

according to § 80.1449. Finally, by 

October 31, 2011, the Energy 

Information Administration (EIA) is 

required by statute to provide EPA with 

an estimate of the volumes of 

transportation fuel, biomass-based 

diesel, and cellulosic biofuel that they 

project will be sold or introduced into 

commerce in the U.S. in 2012. 

A. Statutory Requirements 

The volumes of renewable fuel to be 

used under the RFS2 program each year 

(absent an adjustment or waiver by EPA) 

are specified in CAA 211(o)(2). These 

volumes for 2012 are shown in Table 

II.A–1. 

TABLE II.A–1—REQUIRED VOLUMES IN

THE CLEAN AIR ACT FOR 2012 (BILL

GAL) 

Actual volume 

Ethanol 

equivalent 

volume 

Cellulosic biofuel 0.5a 0.5 

TABLE II.A–1—REQUIRED VOLUMES IN

THE CLEAN AIR ACT FOR 2012 (BILL

GAL)—Continued 

Actual volume 

Ethanol 

equivalent 

volume 

Biomass-based 

diesel ............. 1.0 1.5 

Advanced 

biofuel ............ 2.0a 2.0 

Renewable fuel 15.2a 15.2 

aThese values assume that the biofuels 

would be ethanol. If any portion of the biofuels 

used to meet these applicable volumes has a 

volumetric energy content greater than that for 

ethanol, these values will be lower. 

By November 30 of each year, the EPA 

is required under CAA 211(o) to 

determine and publish in the Federal 

Register the renewable fuel percentage 

standards for the following year. These 

standards are to be based in part on 

transportation fuel volumes estimated 

by the Energy Information 

Administration (EIA) for the following 

year. The calculation of the percentage 

standards is based on the formulas in 

§ 80.1405(c) which express the required 

volumes of renewable fuel as a volume 

percentage of gasoline and diesel sold or 

introduced into commerce in the 48 

contiguous states plus Hawaii. 

The statute requires that if EPA 

determines that the projected volume of 

cellulosic biofuel production for the 

following year is less than the 

applicable volume shown in Table II.A– 

1, then EPA is to reduce the applicable 

volume of cellulosic biofuel to the 

projected volume available during that 

calendar year. In addition, if EPA 

reduces the required volume of 

cellulosic biofuel below the level 

specified in the statute, the Act also 

indicates that we may reduce the 

applicable volume of advanced biofuels 

and total renewable fuel by the same or 

a lesser volume. 

As described in the final rule for the 

RFS2 program, we intend to examine 

EIA’s projected volumes, comments on 

this proposal, production outlook 

reports, and other available data in 

making a final determination of the 

appropriate cellulosic biofuel volumes 

to require for 2012. 

B. Cellulosic Biofuel Volume 

Assessment 

The task of projecting the volume of 

cellulosic biofuel production for 2012 

remains a difficult one. Currently there 

are very few, if any, facilities 

consistently producing cellulosic 

biofuel for commercial sale. 

Announcements of new projects and 

project funding, changes in project 

plans, project delays, and cancellations 

occur frequently. Biofuel producers face 

not only the challenge of the scale up of 

innovative, first-of-a-kind technology, 

but also the challenge of securing 

funding in a difficult economy. The 

cellulosic biofuel industry also is 

influenced by various tax credits and 

subsidies, and changes to these 

programs could have an impact on 

cellulosic biofuel production. 

In order to project cellulosic biofuel 

production for 2012, EPA has tracked 

the progress of over 100 biofuel 

production facilities. From this list of 

facilities we used publically available 

information, as well as information 

provided by DOE and USDA, to make a 

preliminary determination of which 

facilities are the most likely candidates 

to produce cellulosic biofuel and make 

it commercially available in 2012. Each 

of these companies was investigated 

further in order to determine the current 

status of their facilities and their likely 

cellulosic biofuel production volumes 

for the coming years. Information such 

as the funding status of these facilities, 

announced construction and production 

ramp up periods, and annual fuel 

production targets were taken into 

account. Our projection of the range of 

cellulosic biofuel production in 2012 is 

based on this information as well as our 

own assessment of the likelihood of 

these facilities successfully producing 

cellulosic biofuel in the volumes 

indicated. A brief description of each of 

the companies we believe may produce 

cellulosic biofuel and make it 

commercially available in 2012 can be 

found below. We will continue to gather 

more information to help inform our 

decision on the final cellulosic biofuel 

standard for 2012, and we will specify 

a single volume in the final rule that 

will be the basis for the cellulosic 

biofuel percentage standard for 2012. 

1. Existing Cellulosic Biofuel Facilities 

The rule that established the required 

2011 cellulosic biofuel volume 

identified five production facilities that 

we projected would produce cellulosic 

biofuel and make the fuel commercially 

available in 2011. Each of these 

production facilities are now 

structurally complete, however they are 

in various stages of biofuel production. 

All of these facilities have either 

produced some volume of cellulosic 

biofuel in 2011, or are on schedule to do 

so later in the year. Only Range Fuels, 

however, has completed its registration 

as a cellulosic biofuel production 

facility under the RFS2 program and as 

such they are currently the only facility 

of the five listed here currently eligible 

to generate cellulosic biofuel RINs. For 


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5 75 FR 76790, December 9, 2010. 

more background information on each 

of these facilities see the 2011 standards 

rule.5

DuPont Danisco Cellulosic Ethanol 

(DDCE) successfully started up their 

small demonstration facility in Vonore, 

Tennessee in late 2010. This facility has 

a maximum production capacity of 

250,000 gallons of ethanol per year and 

uses an enzymatic hydrolysis process to 

convert corn cobs into ethanol. In 

conversations with EPA in early 2011 

DDCE indicated that they had not 

encountered any unexpected difficulties 

in their production of cellulosic ethanol 

and were on target to meet their 2011 

production goal of 150,000 gallons of 

cellulosic ethanol. It is likely that in 

2012 cellulosic biofuel production at 

this facility will approach the 

production capacity of 250,000 gallons 

of cellulosic ethanol. 

Fiberight uses an enzymatic 

hydrolysis process to convert the 

biogenic portion of separated municipal 

solid waste (MSW) into ethanol. 

Construction on the first stage of 

Fiberight’s Blairstown, Iowa facility was 

completed in the summer of 2010. The 

production capacity of the first stage of 

this project is 2 million gallons of 

ethanol per year. Fiberight had planned 

to begin production of cellulosic biofuel 

from this facility in late 2010 but poor 

economic conditions, due in part to low 

cellulosic RIN values in 2010, caused 

them to postpone fuel production. 

Fiberight had also planned to begin 

construction on an expansion of this 

facility in late 2010 that would increase 

the production potential to 6 million 

gallons of ethanol per year, but were 

unable to secure funding to carry out the 

construction as planned. They have 

since secured funding and began 

construction on the expansion of their 

Blairstown facility in April 2011. 

Fiberight anticipates that they will begin 

fuel production in the late summer of 

2012 and will ramp up production at 

this facility throughout 2012, producing 

approximately 3 million gallons of 

cellulosic ethanol in 2012. 

KiOR continues to produce a small 

volume of renewable crude from 

agricultural residue at their 

demonstration facility in Houston, 

Texas using a technology they call 

Biomass Catalytic Cracking (BCC). This 

technology uses heat and a proprietary 

catalyst to convert biomass to a 

renewable crude with a relatively low 

oxygen content. This facility currently 

lacks the infrastructure to upgrade this 

renewable crude to finished 

transportation fuel, however KiOR plans 

to add this capability at this facility in 

late 2011. While KiOR has not yet 

registered under the RFS2 program, 

their fuel, if refined to gasoline or diesel 

fuel would be eligible to generate RINs. 

EPA currently projects a production 

volume of 200,000 gallons of cellulosic 

fuel from KiOR, which could potentially 

generate 300,000 RINs. 

KL Energy has developed a process to 

convert cellulose and hemicelluloses 

into cellulosic sugars using a thermalmechanical pretreatment process 

followed by an enzymatic hydrolysis. 

They had initially planned to used 

woody biomass as their feedstock for 

cellulosic biofuel production; however 

their production process is versatile 

enough to allow for a wide variety of 

cellulosic feedstocks to be used. In 

August 2010 KL Energy announced a 

joint development agreement with 

Petrobras America Inc. As part of the 

agreement Petrobras will invest $11 

million to modify KL Energy’s facility in 

Upton, Wyoming to allow it to process 

bagasse and other waste products. These 

modifications are expected to be 

completed in 2011, and fuel production 

is likely to begin soon after. If 

successful, Petrobras and KL Energy 

plan to work together to integrate the 

technology into currently existing 

ethanol production facilities in Brazil. 

KL Energy has also indentified several 

sites in the United States for possible 

future expansion. EPA currently 

projects that KL Energy could produce 

up to 1 million gallons of cellulosic 

ethanol in 2012 in the United States. 

Range Fuels began production of 

methanol at their Soperton, Georgia 

facility in the third quarter of 2010. This 

facility uses a thermochemical 

technology to produce syngas 

(consisting of mostly hydrogen and 

carbon monoxide) from a woody 

biomass feedstock. The syngas is then 

converted into fuel with the aid of a 

chemical catalyst developed by Range. 

Range has developed the capability to 

produce both methanol and ethanol, 

depending on the catalyst used. In 

January 2011, after producing a small 

volume of ethanol from this facility and 

proving this capability, Range Fuels 

shut down the Soperton facility in order 

to work through technical difficulties 

they had been experiencing. No timeline 

has been given for the restart of this 

facility. EPA will continue to gather 

information and monitor progress at the 

Soperton facility. At this time, however, 

since no timeline has been provided for 

production from this facility, we are not 

projecting any volume from this facility 

in 2012. 

2. Potential New Facilities in 2012 

EPA is also aware of five new 

cellulosic biofuel production facilities 

that are currently planning to begin 

commercial production at some point in 

2012. These facilities are at various 

stages in the construction process, and 

as such have various degrees of 

uncertainty associated with any 

projected 2012 commercial production. 

While it is possible that several of these 

facilities will not begin production of 

cellulosic biofuels until 2013, they are 

nevertheless considered here since some 

commercial volumes can potentially be 

produced in 2012. 

Fulcrum Bioenergy is planning to 

build a facility capable of producing 

10.5 million gallons of cellulosic 

ethanol and 16 megawatts of renewable 

electricity per year. They have 

developed a thermochemical technology 

to produce ethanol from separated MSW 

via syngas using a chemical catalyst. In 

November 2010 Fulcrum announced 

that they had received a term sheet for 

a $80 million loan guarantee from DOE 

and were entering into the final phase 

of the loan guarantee program. Prior to 

that Fulcrum had announced that they 

had signed long term feedstock supply 

contracts for this facility as well as 

engineering, procurement, and 

construction contracts. In January 2011 

Fulcrum announced they had closed on 

a $75 million Series C financing that 

would provide the remaining necessary 

capital for the construction of their first 

commercial production facility pending 

the closing of their DOE loan guarantee. 

They announced that they are now 

planning to begin construction in the 

second quarter of 2011 and complete the 

facility by late 2012. EPA currently 

projects a potential production volume 

of up to 0.5 million gallons of cellulosic 

ethanol from this facility in 2012. 

INEOS Bio has developed a process 

for producing cellulosic ethanol by first 

gasifying feedstock material into a 

syngas and then using naturally 

occurring bacteria to ferment the syngas 

into ethanol. In January 2011 USDA 

announced a $75 million loan guarantee 

for the construction of INEOS Bio’s first 

commercial facility to be built in Vero 

Beach, Florida. This facility will be 

capable of producing 8 million gallons 

of cellulosic biofuel as well as 6 

megawatts of renewable electricity from 

a variety of feedstocks including yard, 

agricultural, and wood waste, as well as 

separated MSW. On February 9, 2011 

INEOS Bio broke ground on this facility. 

INEOS Bio expects to complete 

construction on this facility in April 

2012 and plans to begin commercial 

production of cellulosic ethanol soon 


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after construction is complete. EPA 

currently projects a potential production 

volume of up to 3 million gallons of 

cellulosic ethanol from this facility in 

2012. 

After successful operation of their 

demonstration plant in Houston, Texas 

KiOR is planning to begin construction 

on their first commercial scale facility in 

early 2011. This facility, located in 

Columbus, Mississippi, will convert 

biomass to a low oxygen biocrude using 

a process KiOR calls Biomass Catalytic 

Cracking (BCC). BCC uses a catalyst 

developed by KiOR in a process similar 

to Fluid Catalytic Cracking currently 

used in the petroleum industry. KiOR’s 

Columbus facility will also be capable of 

upgrading this biocrude into finished 

gasoline and diesel as well as a small 

quantity of fuel oil. KiOR plans to begin 

production from this facility sometime 

in the first half of 2012. KiOR has also 

announced plans to construct several 

more commercial scale biofuel 

production facilities in Mississippi and 

across the southeastern United States. 

However, it is unlikely any of these 

facilities will begin production of 

biofuel in 2012. Given this timeline EPA 

currently projects a potential production 

of up to 4.0 million gallons of gasoline 

and diesel (6.4 million ethanol 

equivalent gallons) from the Columbus 

facility in 2012. 

Terrabon completed construction of a 

small demonstration scale facility for 

the conversion of MSW and other waste 

materials into gasoline in 2010 and is 

planning to begin production at their 

first commercial scale facility in 2012. 

Terrabon utilizes a unique production 

process that can be used to produce 

gasoline, diesel, or jet fuel. Feedstock is 

first fermented into carboxylic acids by 

a variety of micro organisms. These 

carboxylic acids are then neutralized to 

form carboxylate salts that are 

dewatered, dried, and thermally 

converted to ketones. Finally, the 

ketones are hydrogenated to form 

alcohols which can then be refined into 

gasoline, diesel, or jet fuel. While 

currently no pathway exists for the 

generation of RINs representing 

cellulosic gasoline in the RFS2 

regulations, EPA is planning to initiate 

a rulemaking to create such a pathway 

in our regulations. This would allow for 

facilities such as Terrabon and others 

who may produce cellulosic gasoline in 

the future to register and generate RINs 

under the RFS2 program (provided they 

meet the fuel registration, renewable 

biomass, and other requirements of the 

program as well). EPA currently projects 

the production of up to 0.7 million 

gallons (1.0 million ethanol equivalent 

gallons) of cellulosic gasoline in 2012 

from Terrabon’s first commercial 

facility. 

ZeaChem has begun construction on a 

small demonstration scale facility in 

Boardman, Oregon capable of producing 

250,000 gallons of cellulosic ethanol per 

year. Their production process uses a 

combination of biochemical and 

thermochemical technologies to 

produce ethanol and other renewable 

chemicals from cellulosic materials. The 

feedstock is first fractionated into two 

separate streams containing cellulosic 

sugars and lignin. The cellulosic sugars 

are fermented into ethyl acetate using a 

naturally occurring acetogen, which can 

then be hydrogenated into ethanol. The 

hydrogen necessary for this process is 

produced by gasifying the lignin stream 

from the cellulosic biomass. ZeaChem’s 

process is flexible and is capable of 

producing a wide range of renewable 

chemical and fuel molecules in addition 

to ethanol. ZeaChem plans to begin 

production of cellulosic ethanol from 

their facility in Boardman, Oregon in 

late 2011, and EPA currently projects a 

potential production volume of up to 

0.25 million gallons of ethanol from this 

facility in 2012. 

Another potential source of cellulosic 

biofuel in 2012 is a technology being 

developed by EdeniQ. EdeniQ is 

developing a suite of enzymes capable 

of breaking down cellulose into simple 

sugars that can then be fermented into 

ethanol. Rather than build their own 

production facilities EdeniQ plans to 

license their enzymes to existing corn 

ethanol facilities. Such licensing would 

be accompanied by the Cellunator, an 

advanced milling device they have 

developed to reduce the particle size of 

corn kernels to enable greater 

conversion of starch to ethanol as well 

as the conversion of cellulose to simple 

sugars. EdeniQ claims that their 

technology would allow corn ethanol 

facilities to increase ethanol production 

by 1–2% by converting the cellulosic 

portion of the corn kernel into ethanol. 

They are also working to increase the 

effectiveness of their enzymes in order 

to enable ethanol production increases 

of 3–4% from the cellulose in the corn 

kernel in the future. EdeniQ plans to 

begin commercial trials of their 

technology in the second half of 2011. 

This technology has the potential to be 

implemented rapidly and produce 

significant amounts of cellulosic ethanol 

in 2012 as it requires relatively small 

capital additions to already existing 

corn ethanol facilities. While this 

technology is promising, there is 

currently no pathway in the RFS2 

regulations for the generation of 

cellulosic biofuel RINs using the 

cellulosic portion of the corn kernel as 

a feedstock. Moreover, EdeniQ has not 

announced any agreements with corn 

ethanol producers to install this 

technology to enable the production of 

cellulosic ethanol. For these reasons, 

EPA has not included any cellulosic 

ethanol production from EdeniQ’s 

technology in our 2012 projections. We 

will continue to monitor their process in 

the coming months for signs of progress 

towards commercialization of their 

technology and will consider adding 

production volumes from EdeniQ into 

our final projections if appropriate. 

In addition to the facilities mentioned 

above, EPA is also aware of three 

companies planning to begin the 

production of cellulosic biofuels in 

early 2013. Coskata, Enerkem, and Poet 

are planning on completing 

construction on their first commercial 

scale cellulosic biofuel facilities in late 

2012 or early 2013 and producing 

commercial volumes of biofuels in 2013. 

While it is possible that construction of 

any of these facilities could be 

completed ahead of schedule and a 

small volume of fuel could be produced 

in 2012, history in this industry suggests 

that this is unlikely. EPA has therefore 

not projected that any volume of 

cellulosic biofuel will be produced from 

these facilities in 2012. These facilities, 

along with several other commercial 

cellulosic biofuel facilities planning to 

begin production in 2013, notably the 

first commercial scale facilities from 

Abengoa and Mascoma, indicate that the 

potential exists for the rapid expansion 

of production volumes in future years. 

3. Imports of Cellulosic Biofuel 

While domestically produced 

cellulosic biofuels are the most likely 

source of cellulosic biofuel available in 

the United States, producers and/or 

importers of cellulosic biofuel produced 

in other countries may also generate 

RINs and participate in the RFS2 

program. While the RFS2 program does 

provide a financial incentive for 

companies to import cellulosic biofuels 

into the United States, the combination 

of local demand, financial incentives 

from other governments, and 

transportation costs for the cellulosic 

biofuel has resulted in no cellulosic 

biofuel being imported to the United 

States thus far. EPA believes this 

situation is likely to continue in the 

near future. Additionally, the majority 

of internationally based cellulosic 

biofuel facilities that currently exist or 

plan to complete construction by the 

end of 2012 are small research and 

development or pilot facilities not 

designed for the commercial production 

of fuel. 


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Two notable exceptions, both located 

in Canada, are Enerkem and Iogen. 

Enerkem has a currently existing 

commercial production facility in 

Westbury, Quebec and is expecting to 

complete construction on a second 

facility in Edmonton, Alberta in late 

2011. Iogen has a small demonstration 

facility in Ottawa and is currently 

exploring the possibility of building 

their first commercial facility near 

Prince Albert, Saskatchewan. The large 

expected production volumes and 

relatively small distance this fuel would 

have to be transported to reach the 

United States make these facilities the 

most likely candidates to import 

cellulosic biofuel into the United States. 

In conversations with EPA, however, 

both companies indicated that they had 

no current intentions of importing fuel 

from their Canadian production 

facilities into the United States. On 

September 1, 2010 the government of 

Canada finalized regulations requiring 

all gasoline sold in Canada to have a 

renewable content of 5% and all diesel 

fuel and heating oil to have a renewable 

content of 2%. These regulations will 

further increase local demand for any 

cellulosic biofuel produced from these 

two facilities and decrease the 

likelihood of any of this fuel being 

exported to the United States. For these 

reasons we have not included any 

cellulosic biofuel production from 

foreign facilities in our projections of 

cellulosic biofuel availability in 2012. 

4. Summary of Volume Projections 

The information EPA has gathered on 

the potential cellulosic biofuel 

producers in 2012, described above, 

allows us to identify potential volumes 

that could be achieved by each facility 

in 2012. This information is 

summarized in Table II.B.4–1 below. 

TABLE II.B.4–1—CELLULOSIC BIOFUEL 2012 POTENTIALLY AVAILABLE VOLUME

Company name Location Feedstock Fuel Capacity 

(MGY) 

Earliest production 

2012 Potentially available volume 

(MG) 

Ethanol 

equivalent 

gallons (MG) 

DuPont Danisco Cellulosic Ethanol.Vonore, TN .... Corn Stover ... Ethanol ........... 0.25 Online 0 .25 0 .25 

Fiberight a .................................. Blairstown, IA MSW .............. Ethanol ........... 6 Online 3 .0 3 .0 

Fulcrum Bioenergy .................... McCarran, NV MSW .............. Ethanol ........... 10.5 Late 2012 0 .5 0 .5 

INEOS Bio ................................. Vero Beach, 

FL.

Ag Residue, 

MSW.

Ethanol ........... 8 May 2012 3 .0 3 .0 

KiOR .......................................... Houston, TX ... Ag Residue .... Gasoline, Diesel.0.2 Online 0 .2 0 .3 

KiOR .......................................... Columbus, MS Pulp Wood ..... Gasoline, Diesel.10 Mid 2012 4 .0 6 .4 

KL Energy ................................. Upton, WY ..... Wood Waste .. Ethanol ........... 1.5 Online 1 .0 1 .0 

Terrabon .................................... Port Arthur, TX MSW .............. Gasoline ......... 1.3 2012 0 .7 1 .0 

ZeaChem ................................... Boardman, OR Planted Trees Ethanol ........... 0.25 2011 0 .25 0 .25 

Total ................................... ........................ ........................ ........................ ................ ...................... 12 .9 15 .7 

aBased on company estimate. 

The potentially available volume of 

12.9 million gallons of cellulosic 

biofuel, or 15.7 million ethanol 

equivalent gallons, represents the higher 

end of the range of cellulosic biofuel 

volumes that EPA believes at this time 

could reasonably be expected to be 

produced or imported and made 

available for use as transportation fuel, 

heating oil, or jet fuel in 2012. It 

incorporates reductions from the annual 

production capacity of each facility 

based on when the facilities anticipate 

fuel production will begin and 

assumptions regarding a ramp up period 

to full production. Other factors such as 

the funding status, risks associated with 

new technologies, and the current status 

of project construction were considered 

for each facility. 

For the lower end of the range, we 

believe that a volume of 3.55 million 

ethanol-equivalent gallons could be 

justified based on currently available 

information. This volume is based on a 

consideration of only those facilities 

that are structurally complete at the 

time of this proposal and which have 

indicated that they anticipate 

commercial production of cellulosic 

biofuels by the end of 2011. The 

production facilities meeting these 

criteria include Dupont Danisco 

Cellulosic Ethanol, Fiberight (2 million 

gallon per year first stage), KiOR 

(Houston, TX facility), and KL Energy. 

While there is still some uncertainty 

regarding the projected volumes from 

these facilities, by completing 

construction and anticipating fuel 

production by the end of 2011 there is 

less uncertainty associated with these 

facilities than for the others listed as 

potential cellulosic biofuel producers 

for 2012. 

Therefore, in today’s NPRM we are 

proposing a range of values, from 3.55 

million ethanol equivalent gallons to 

15.7 million ethanol equivalent gallons 

for the 2012 cellulosic biofuel standard. 

The low end of the range represents a 

projection of higher confidence and less 

uncertainty, with greater emphasis 

placed on established/demonstrated 

production capacity. The high end of 

the range represents a projection of less 

confidence and higher uncertainty, with 

greater emphasis placed on productions 

plans. As time progresses and we are 

able to track whether or not the 

cellulosic biofuels producers are able to 

meet the construction and ramp up 

schedules they have presented, and as 

we consider public comments on this 

proposal and the EIA estimated 2012 

volume of cellulosic biofuel production 

that they are required to provide to us 

by October 31 of this year, we will have 

a better idea of the appropriate volume 

of fuel that we can reasonably expect to 

be produced and made commercially 

available in 2012. Congress did not 

specify the degree of certainty that 

should be reflected in our projections of 

cellulosic biofuel volumes. We expect 

that the volume that we project in the 

final rule for 2012 will represent a 

reasonable balance of the degree of 

uncertainty or confidence in the 

projected production volume and the 

risk of unnecessarily reducing the 

applicable volumes set forth in the Act. 

Although we are proposing a range of 

values from 3.55 to 15.7 million ethanol 

equivalent gallons based on information 

available at the time of this NPRM, we 

also request comment on alternative 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 38853 

options for setting the 2012 cellulosic 

biofuel volume requirement at a higher 

level. It is possible that a cellulosic 

biofuel volume requirement which 

reduces less of the 500 mill gallon 

applicable volume from the statute 

could spur additional near and longerterm cellulosic biofuel production 

capacity. We recognize that any method 

must take into account the uncertainty 

in estimating future production 

potential. Nevertheless, the purpose of 

setting a mandate is to stimulate more 

rapid increases in the rate of production 

than the cellulosic biofuel industry 

would likely experience in the absence 

of the mandate. We request comment on 

whether a higher volume requirement 

for cellulosic biofuel than we are 

proposing today would provide 

additional stimulation of production 

volumes of cellulosic biofuel, and the 

basis for setting such a higher volume 

requirement. 

C. Potential Limitations in 2012 

In addition to production capacity, a 

variety of other factors have the 

potential to limit the amount of 

cellulosic biofuel that can be produced 

and used in the U.S. For instance, there 

may be limitations in the availability of 

qualifying cellulosic feedstocks at 

reasonable prices. Most of the cellulosic 

biofuel producers that we anticipate 

will produce commercial volumes in 

2012 have indicated that they will use 

some type of cellulosic waste, such as 

separated municipal solid waste, wastes 

from the forestry industry, and 

agricultural residues. Based on the 

analyses of cellulosic feedstock 

availability in the RFS2 final rule, we 

believe that there will be significantly 

more than enough sources of these 

feedstocks for 2012. For producers that 

intend to use dedicated energy crops, 

we do not believe that the amount of 

qualifying cropland for renewable fuel 

production under RFS2 will limit 

production in 2012. We plan to 

continue to evaluate the availability of 

valid feedstocks in future years as the 

required volumes of cellulosic biofuel 

increase. 

We anticipate that the relatively small 

incremental increase in total biofuel 

volumes in 2012 that would be 

attributed to cellulosic biofuels can be 

accommodated by the fuel distribution 

system. The RFS2 final rule analysis 

concluded that biofuel distribution 

challenges as the RFS2 volume 

requirements ramp up could be 

overcome in a timely fashion. In the 

RFS2 final rule analysis, we assumed 

that most cellulosic biofuel production 

facilities would be constructed in the 

nation’s heartland similar to corn 

ethanol production facilities. Based on 

more recent information, we now 

believe that cellulosic production 

facilities will be more geographically 

dispersed. This is the case for the 

specific cellulosic biofuels production 

facilities that we expect would produce 

fuel in 2012. The greater geographic 

dispersion would tend to lessen the 

distance to transport biofuels to 

petroleum terminals, thereby reducing 

the overall distribution burden. We 

believe that the cellulosic biofuel 

volumes that would be produced in 

2012 could be accommodated by fuel 

retailers without necessitating the 

installation of new refueling 

infrastructure such as that which would 

be needed for E85. 

D. Advanced Biofuel and Total 

Renewable Fuel in 2012 

Under CAA 211(o)(7)(D)(i), EPA has 

the discretion to reduce the applicable 

volumes of advanced biofuel and total 

renewable fuel in the event that the 

projected volume of cellulosic biofuel 

production is determined to be below 

the applicable volume specified in the 

statute. As described in Section II.B 

above, we are indeed projecting the 

volume of cellulosic biofuel production 

for 2012 at significantly below the 

statutory applicable volume of 500 

million gallons. Because cellulosic 

biofuel is used to satisfy the cellulosic 

biofuel standard, the advanced biofuel 

standard, and the total renewable fuel 

standard, any reductions in the 

applicable volume of cellulosic biofuel 

will also affect the means through 

which obligated parties comply with the 

advanced biofuel standard and the total 

renewable fuel standard. Therefore, we 

have considered whether and to what 

degree to propose lowering the 

advanced biofuel and total renewable 

fuel applicable volumes for 2012. 

If the required volume of cellulosic 

biofuel for a given year is less than the 

volume specified in the statute, it is 

important to evaluate whether there 

would be sufficient volume of advanced 

biofuels to satisfy the applicable volume 

of advanced biofuel volume set forth in 

the statute. Even with a reduced volume 

of cellulosic biofuel, other advanced 

biofuels, such as biomass-based diesel, 

sugarcane ethanol, or other biofuels, 

may be available in sufficient volumes 

to make up for the shortfall in cellulosic 

biofuel. We believe that it would be 

consistent with the energy security and 

greenhouse gas reduction goals of EISA 

to not reduce the applicable volume of 

advanced biofuel set forth in the statute 

if there are sufficient volumes of 

advanced biofuels available, even if 

those volumes do not include the 

amount of cellulosic biofuel that 

Congress may have desired. Our 

authority to lower the advanced biofuel 

and/or total renewable fuel applicable 

volumes is discretionary, and in general 

we believe that actions to lower these 

volumes should only be taken if 

insufficient volumes of qualifying 

biofuel can be made available, based on 

such circumstances as insufficient 

production capacity, insufficient 

feedstocks, competing markets, 

constrained infrastructure, or the like. 

As discussed below, we project that 

sufficient volumes of advanced biofuel 

can be made available in 2012 such that 

the 2.0 bill gallon advanced biofuel 

requirement need not be reduced. 

If we were to maintain the advanced 

biofuel, biomass-based diesel, and total 

renewable fuel volume requirements at 

the levels specified in the statute, while 

also lowering the cellulosic biofuel 

standard to 3.55–15.7 million ethanolequivalent gallons, then 1,504–1,516 

million gallons of the 2.0 billion gallon 

advanced biofuel mandate would be 

satisfied automatically through the 

satisfaction of the cellulosic and 

biomass based diesel standards. An 

additional 484–496 million ethanolequivalent gallons of additional 

advanced biofuels would be needed. See 

Table II.D–1. 

TABLE II.D–1—PROJECTED FUEL MIX IF ONLY CELLULOSIC BIOFUEL VOLUME IS ADJUSTED IN 2012 

[Mill gallons] 

Ethanol-equivalent 

volume Physical volume 

Total renewable fuel ................................................................................................................................ 15,200 14,536–14,701 

Conventional renewable fuel a ................................................................................................................. 13,200 13,200 

Total advanced biofuel ............................................................................................................................ 2,000 1,336–1,501 

Cellulosic biofuel ...................................................................................................................................... 3.55–15.7 3.45–12.9 

Biomass-based diesel .............................................................................................................................. 1,500 1,000 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
38854 Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 

6 ‘‘Monthly U.S. Imports of Fuel Ethanol,’’ EIA, 

released 3/30/2011. 

7Lundell, Drake, ‘‘Brazilian Ethanol Export Surge 

to End; U.S. Customs Loophole Closed Oct. 1,’’ 

Ethanol and Biodiesel News, Issue 45, November 4, 

2008. 

8Portal Brasil, Energy Matrix for Ethanol, 

http://www.brasil.gov.br/sobre/economy/energymatrix/ethanol/br_model1?set_language=en. 

9Table 11 of AEO2011 Early Release, Report 

Number DOE/EIA–0383ER(2011). http:// 

www.eia.doe.gov/forecasts/aeo/tables_ref.cfm. 

10Table ‘‘Ethanol trade’’, World Biofuels, FAPRI 

2010 U.S. and World Agricultural Outlook. http:// 

www.fapri.iastate.edu/outlook/2010/. 

11Table ES1 of Electric Power Industry 2009: 

Year in Review. Available online: http:// 

www.eia.doe.gov/cneaf/electricity/epa/epayir.pdf. 

TABLE II.D–1—PROJECTED FUEL MIX IF ONLY CELLULOSIC BIOFUEL VOLUME IS ADJUSTED IN 2012—Continued 

[Mill gallons] 

Ethanol-equivalent 

volume Physical volume 

Other advanced biofuel b ......................................................................................................................... 484–496 c 323–496 

aPredominantly corn-starch ethanol. 

b Rounded to nearest million gallons for simplicity. 

cPhysical volume is a range because other advanced biofuel may be ethanol, biodiesel, or some combination of the two. 

The most likely sources of additional 

advanced biofuel would be imported 

sugarcane ethanol and biomass-based 

diesel, though there may also be some 

volumes of other types of advanced 

biofuel available as discussed below. To 

determine if there are likely to be 

sufficient volumes of these biofuels to 

meet the need for 484–496 million 

gallons of other advanced biofuel, we 

first examined historical data on ethanol 

imports and projections from EIA and 

USDA for 2012. Brazilian imports have 

made up a sizeable portion of total 

ethanol imported into the U.S. in the 

past, and these volumes were 

predominantly produced from 

sugarcane. Ethanol imports averaged 

about 380 million gallons per year over 

the last five years, and reached an alltime high of 730 million gallons in 

2006.6 These historical import volumes 

demonstrate that Brazil has significant 

export potential under the appropriate 

economic circumstances. However, 

ethanol imports were significantly lower 

in 2010 than in previous years. This 

decline in imports may be related to the 

cessation of the duty drawback that 

became effective on October 1, 2008, or 

to changes in world sugar prices.7

However, Brazil continues to be second 

worldwide in the production of ethanol, 

producing a total of 6.9 bill gallons in 

2009.8 By establishing an increased U.S. 

demand for 484–496 million gallons of 

other advanced biofuel in 2012, we 

would be re-establishing an export 

market for Brazillian sugarcane ethanol 

that could compete with the use of 

sugarcane to produce sugar, and thus it 

can once again be economical for 

Brazilian producers to export higher 

volumes of sugarcane ethanol to the 

U.S. Moreover, California’s Low Carbon 

Fuel Standard went into effect in 2010, 

and may result in some refiners 

importing additional volumes of 

sugarcane ethanol from Brazil into 

California in 2012. These same volumes 

could count towards the Federal RFS2 

program as well. 

Future projections from other sources 

also suggest that a large portion of the 

484–496 million gallons of advanced 

biofuel needed could be supplied by 

imported sugarcane ethanol. For 

instance, in the Early Release of its 

Annual Energy Outlook 2011, EIA 

projects ethanol imports of 

approximately 400 million gallons for 

2012.9 Similarly, the university-based 

Food and Agricultural Policy Research 

Institute (FAPRI) released its 2010 U.S. 

and World Agricultural Outlook report 

in which it projects 2012 ethanol 

imports of 317 million gallons.10 The 

volumes of imported ethanol projected 

by both of these sources is very likely 

to be sugarcane ethanol, since this is by 

far the predominant form of imported 

ethanol to date and is expected to 

continue to be so for the foreseeable 

future. 

We also examined the potential for 

excess biodiesel to help meet the need 

for 484–496 million gallons of advanced 

biofuel. The applicable volume of 

biomass based diesel established in the 

statute for 2012 is 1.0 billion gallons 

(which corresponds to 1500 ethanolequivalent gallons). As discussed more 

fully in Section II.E below, we believe 

that the biodiesel industry has the 

potential for producing volumes above 

1.0 billion gallons if demand for such 

volume exists, potentially up to an 

additional several hundred million 

gallons. 

Another potential source of advanced 

biofuels is electricity generated from 

renewable biomass that is used as a 

transportation fuel. EIA data indicates 

that in 2009, the most recent year for 

which data is available, 35.6 million 

megawatt-hours of electricity was 

generated from wood and wood derived 

fuels, and an additional 18.4 million 

megawatt-hours was generated from 

other biomass in the United States.11 If 

all of this electricity were used as a 

transportation fuel it would represent 

nearly 2.4 billion ethanol equivalent 

gallons of advanced biofuel. While not 

all the feedstocks used to generate the 

electricity included in these totals 

would meet the RFS2’s renewable 

biomass definition this remains a very 

large potential source of advanced 

biofuel RINs. 

In addition to verifying that the 

feedstocks used to generate renewable 

electricity meet the renewable biomass 

definition producers would also be 

required to document that the electricity 

they produce is used as a transportation 

fuel in order to be eligible to generate 

RINs. Until recently there were very few 

vehicles capable of using electricity as 

a transportation fuel. Expected increases 

in the number of vehicles with this 

capability, such as electric vehicles and 

plug in hybrids, has the potential to 

dramatically increase the degree to 

which electricity is able to be used as a 

transportation fuel. Verifying that the 

renewable electricity produced is used 

as a transportation fuel would still 

remain a challenge, however the 

potential for capitalizing on the RIN 

value, without the necessity of making 

major changes in the areas of fuel 

production, distribution, or end use, 

may be a large enough incentive to 

overcome this challenge. While the 

many uncertainties associated with the 

generation of advanced biofuel RINs 

from renewable electricity prevent EPA 

from making a quantitative projection 

for 2012, such RINs may nevertheless 

play a role in meeting the advanced 

biofuel standard. 

Finally, there are also other potential 

sources of advanced biofuels. For 

instance, several companies are making 

progress on opening advanced biofuel 

production facilities as early as 2012. 

Gevo purchased a dry mill corn ethanol 

plant in Minnesota and is in the process 

of converting it to produce up to 10 

million gallons of biobutanol per year. 

Solazyme produced over 150,000 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
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12Monthly Energy Review, May 2011. http:// 

www.eia.doe.gov/emeu/mer/pdf/pages/sec10_8.pdf. 

13See question 6.7 in EPA’s ‘‘Questions and 

Answers on Changes to the Renewable Fuel 

Standard Program (RFS2)’’, http://www.epa.gov/ 

otaq/fuels/renewablefuels/compliancehelp/rfs2- 

aq.htm#6. 

gallons of algal oil in 2010–2011 that 

was then converted to jet fuel by UOP 

and is planning for increased 

production in 2012. LS9 purchased a 

fermentation facility in Florida that will 

enable them to produce 50,000 to 

100,000 gallons of diesel fuel per year 

and plan to have this facility full 

operational by 2012. Several other 

companies are also planning on 

producing advanced biofuels using a 

variety of feedstocks, including sugars, 

sweet sorghum, waste cooking oil or 

restaurant grease, algal oils, and many 

others that have the potential to achieve 

commercial production by the end of 

2012. Insofar as such fuels are registered 

under 40 CFR part 79 and meet all the 

requirements for RIN generation under 

the RFS program, they could contribute 

to compliance with the advanced 

biofuels standard in 2012. 

By adding up the potential volumes of 

imported sugarcane ethanol, excess 

biodiesel, and other sources of advanced 

biofuel, there are likely to be sufficient 

volumes of advanced biofuels to meet 

the need for 484–496 million gallons. As 

a result, we do not believe that the 

advanced biofuel standard need be 

lowered below the 2.0 billion gallon 

level specified in the Act. Thus, we are 

not proposing to reduce the applicable 

volume of advanced biofuel for 2012. In 

addition, since we are not proposing to 

lower the advanced biofuel standard for 

2012, we do not believe that there is a 

need to lower the total renewable fuel 

standard. Nevertheless, since there is 

some uncertainty in both the availability 

of advanced biofuels in 2012 and the 

market conditions which would support 

their availability, we request comment 

on whether the advanced biofuel and 

total renewable fuel standards should be 

lowered, and the basis for such a 

reduction in the applicable volumes 

from the statute. 

E. Biomass-Based Diesel in 2012 

As described more fully in Section 

II.D above, we must determine whether 

the required volumes of advanced 

biofuel and/or total renewable fuel 

should be reduced if we reduce the 

required volume of cellulosic biofuel. 

The amount of biomass-based diesel 

that we project will be available directly 

affected our proposed consideration for 

this NPRM of adjustments to the 

volumetric requirements for advanced 

biofuel and total renewable fuel. 

To evaluate whether the applicable 

volume of 1.0 bill gallons for biomassbased diesel is achievable in 2012, and 

whether even greater volumes could be 

produced, we examined recent 

production rates, production capacity of 

the industry, and projections for future 

production. Although there are a variety 

of potential fuel types that can qualify 

as biomass-based diesel, biodiesel is by 

far the predominant type. Thus, our 

assessment focused primarily on 

biodiesel, though we also investigated 

potential volumes of renewable diesel. 

According to the Energy Information 

Administration, biodiesel production in 

2010 reached 311 mill gallons.12

However, we believe that this value 

underestimates the volume of biomassbased diesel actually produced in 2010 

since it is based primarily on feedstocks 

used in the production of biodiesel. 

Based on information from the EPAModerated Transaction System (EMTS) 

and RIN generation reports submitted to 

EPA from producers, we estimate that 

the volume of biomass-based diesel 

produced in 2010 was about 380 mill 

gallons. While this is higher than the 

345 mill gallons that we projected 

would be needed for compliance with 

the 2010 biomass-based diesel 

standard,13 there were also exports of 

biodiesel that would have reduced the 

availability of RINs for compliance 

purposes. To the degree that the volume 

of biomass-based diesel fell short of the 

345 mill gallons that we estimated 

would be needed, obligated parties 

would have needed to carry a deficit 

into 2011. 

However, many of the activities of the 

biodiesel industry in 2010 were due to 

unique circumstances that may not 

apply in 2012. It is likely that a 

contributing factor to the lower 

production volumes in 2010 was the 

expiration of the biodiesel tax credit at 

the end of 2009, and the uncertainty 

throughout 2010 regarding whether and 

when it might be reinstated. This 

situation may have led to hesitation on 

the part of obligated parties for 

establishing binding contracts for 

purchases of biodiesel. 

Historical production of biodiesel has 

varied significantly depending on 

market demand as shown in Figure II.E– 

1 below. 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
38856 Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 

14 2011 RIN Generation and Renewable Fuel 

Volume Production, http://www.epa.gov/otaq/fuels/ 

renewablefuels/compliancehelp/rfsdata.htm. 

15Figures taken from National Biodiesel Board’s 

Member Plant List as of January 27, 2011. http:// 

biodiesel.org/buyingbiodiesel/plants/showall.aspx. 

16Comments from National Biodiesel Board on 

the July 20, 2010 NPRM proposing the RFS 

standards for 2011. See Docket EPA–HQ–OAR– 

2010–0133. 

17USDA Agricultural Projections to 2020, LongTerm Projections Report OCE–2011–1, February 

2011. See Table 24. Assumes 7.68 lb/gal. 

18Soybean Oil and Biodiesel Usage Projections 

and Balance Sheet, updated 2/18/2011. http:// 

www.extension.iastate.edu/agdm/crops/outlook/ 

soybeanbalancesheet.pdf. Values cited are for the 

‘‘High’’ case. 

19Short-Term Energy Outlook, February 2011. 

Table 8. 

20Project status updates are available via the 

Syntroleum Web site, http://dynamicfuelsllc.com/ 

wp-news/. 

The fact that the U.S. biodiesel industry 

has produced higher volumes when 

demand for it existed suggests that the 

industry has the capability to produce 

greater volumes than it did in 2010 

under the appropriate circumstances. 

For instance, information from the EPAModerated Transaction System (EMTS) 

indicates that monthly production 

volumes of biodiesel have increased 

steadily in the first few months of 2011, 

reaching 74 mill gallons by April.14 This 

trend demonstrates that the industry is 

responding to the higher demand 

created by the 800 mill gal biomassbased diesel volume requirement under 

the RFS program in 2011. 

The biodiesel industry’s production 

potential supports the view that it can 

more than satisfy the applicable volume 

of biomass-based diesel specified in the 

statute for 2012. As of January, 2011, the 

aggregate production capacity of 

biodiesel plants in the U.S. was 

estimated at 2.8 billion gallons per year 

across approximately 170 facilities. 15

Of this aggregate production capacity, at 

least 1.8 billion gallons of production 

capacity has been registered under the 

RFS2 program.16 Although some 

facilities are currently idle, and ramping 

up production will require some time 

and potentially some reinvestment, 

based on feedback from industry we 

nevertheless believe that it can occur in 

time to meet a production goal of 1.0 

billion gallons in 2012. 

Projections of production for 2012 

strongly suggest that 1.0 bill gallons of 

biomass-based diesel is achievable. For 

instance, the U.S. Department of 

Agriculture projects that over 400 mill 

gallons of biodiesel will be produced 

from soybean oil in 2012, and adds that 

‘‘Although some other first-use 

vegetable oils are also used to produce 

biodiesel, most of the remaining 

biodiesel production needed to reach 

the 1-billion-gallon mandate of the 2007 

Energy Act uses animal fats or recycled 

vegetable oil as the feedstock.’’ 17 This 

projection is further supported by the 

Agricultural Marketing Resource Center 

at Iowa State University, which projects 

that soy-oil biodiesel production may 

reach as high as 470 mill gallons and 

that non-soy biodiesel may reach as 

high as 460 mill gallons.18 Both of these 

sources project more growth in non-soy 

oil feedstock volumes than soy oil. 

Finally, EIA projects that the total 

volume of biodiesel in 2012 would be 

about 840 mill gallons.19 While all of 

these projections suggest that volumes 

of biodiesel may fall short of 1.0 bill 

gallons, we believe that sufficient 

additional volumes of renewable diesel 

can also be available to meet the 1.0 bill 

gal requirement for biomass-based 

diesel. For instance, Dynamic Fuels has 

constructed one plant in Geismar, 

Louisiana that started production of 

renewable diesel in November, 2010.20

In the final RFS2 rule, we projected that 

annual renewable diesel production 

could reach 150 mill gallons based on 

feedstock availability. Since renewable 

diesel can also be produced at existing 

refineries with little or no modification 

to processing equipment, we believe 


jlentini on DSK4TPTVN1PROD with PROPOSALS2EP01JY11.000</GPH>
Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 38857 

21See Federal Register v. 74 n. 99 p. 24903. 

Comments are available in docket EPA–HQ–OAR– 

2005–0161. 

that 150 mill gallons of renewable diesel 

could be produced in 2012. Thus, we 

currently believe that the total 

production volume of both biodiesel 

and renewable diesel can reach 1.0 bill 

gal in 2012. 

We also believe that there will be 

sufficient sources of qualifying 

renewable biomass to more than meet 

the needs of the biodiesel industry in 

2012. The largest sources of feedstock 

for biodiesel in 2012 are expected to be 

soy oil, canola oil, rendered fats, and 

potentially some corn oil extracted 

during production of fuel ethanol, as 

this technology continues to proliferate. 

Moreover, information we received from 

a large rendering company suggests that 

there will be adequate fats and greases 

feedstocks to supply biofuels 

production as well as other historical 

uses.21

Based on our review of the production 

potential of the biodiesel industry, and 

projections from several sources, and 

our assessment of available feedstocks, 

we believe that the 1.0 billion gallons 

needed to satisfy the applicable volume 

of biomass-based diesel specified in the 

statute can be produced in 2012. 

Therefore, we are not proposing to 

lower the biomass-based diesel standard 

of 1.0 billion gallons that is specified in 

the Act. Moreover, based on production 

capacity and availability of feedstocks, 

we believe that volumes of biomassbased diesel in excess of 1.0 bill gallons 

could be made available given sufficient 

market demand. 

III. Proposed Percentage Standards for 

2012 

A. Background 

The renewable fuel standards are 

expressed as a volume percentage, and 

are used by each refiner, blender or 

importer to determine their renewable 

volume obligations (RVO). Since there 

are four separate standards under the 

RFS2 program, there are likewise four 

separate RVOs applicable to each 

obligated party. Each standard applies 

to the sum of all gasoline and diesel 

produced or imported. The applicable 

percentage standards are set so that if 

each regulated party meets the 

percentages, then the amount of 

renewable fuel, cellulosic biofuel, 

biomass-based diesel, and advanced 

biofuel used will meet the volumes 

required on a nationwide basis. 

As discussed in Section II.B.4, we are 

proposing a required volume of 

cellulosic biofuel for 2012 in the range 

of 3.45–12.9 million gallons (3.55–15.7 

million ethanol equivalent gallons). The 

single volume we select for the final 

rule will be used as the basis for setting 

the percentage standard for cellulosic 

biofuel for 2012. We are also proposing 

that the advanced biofuel and total 

renewable fuel volumes would not be 

reduced below the applicable volumes 

specified in the statute. The proposed 

2012 volumes used to determine the 

four percentage standards are shown in 

Table III.A–1. 

TABLE III.A–1—PROPOSED VOLUMES FOR 2012 

Actual volume Ethanol equivalent 

volume 

Cellulosic biofuel .............................................................................................................................. 3.45–12.9 mill gal ...... 3.55–15.7 mill gal. 

Biomass-based diesel ...................................................................................................................... 1.0 bill gal .................. 1.5 bill gal. 

Advanced biofuel ............................................................................................................................. 2.0 bill gal .................. 2.0 bill gal. 

Renewable fuel ................................................................................................................................ 15.2 bill gal ................ 15.2 bill gal. 

The formulas used in deriving the 

annual renewable fuel standards are 

based in part on estimates of the 

volumes of gasoline and diesel fuel, for 

both highway and nonroad uses, that 

will be used in the year in which the 

standards will apply. Producers of other 

transportation fuels, such as natural gas, 

propane, and electricity from fossil 

fuels, are not subject to the standards, 

and volumes of such fuels are not used 

in calculating the annual standards. 

Since the standards apply to producers 

and importers of gasoline and diesel, 

these are the transportation fuels used to 

set the standards, and then again to 

determine the annual volume 

obligations of an individual gasoline or 

diesel producer or importer. 

B. Calculation of Standards 

1. How are the standards calculated? 

The following formulas are used to 

calculate the four percentage standards 

applicable to producers and importers 

of gasoline and diesel (see § 80.1405): 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
38858 Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 

Where: 

StdCB,i = The cellulosic biofuel standard for 

year i, in percent. 

StdBBD,i = The biomass-based diesel standard 

(ethanol-equivalent basis) for year i, in 

percent. 

StdAB,i = The advanced biofuel standard for 

year i, in percent. 

StdRF,i = The renewable fuel standard for year 

i, in percent. 

RFVCB,i = Annual volume of cellulosic 

biofuel required by section 211(o) of the 

Clean Air Act for year i, in gallons. 

RFVBBD,i = Annual volume of biomass-based 

diesel required by section 211(o) of the 

Clean Air Act for year i, in gallons. 

RFVAB,i = Annual volume of advanced 

biofuel required by section 211(o) of the 

Clean Air Act for year i, in gallons. 

RFVRF,i = Annual volume of renewable fuel 

required by section 211(o) of the Clean 

Air Act for year i, in gallons. 

Gi = Amount of gasoline projected to be used 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

Di = Amount of diesel projected to be used 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

RGi = Amount of renewable fuel blended into 

gasoline that is projected to be consumed 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

RDi = Amount of renewable fuel blended into 

diesel that is projected to be consumed 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

GSi = Amount of gasoline projected to be 

used in Alaska or a U.S. territory in year 

i if the state or territory opts-in, in 

gallons. 

RGSi = Amount of renewable fuel blended 

into gasoline that is projected to be 

consumed in Alaska or a U.S. territory in 

year i if the state or territory opts-in, in 

gallons. 

DSi = Amount of diesel projected to be used 

in Alaska or a U.S. territory in year i if 

the state or territory opts-in, in gallons. 

RDSi = Amount of renewable fuel blended 

into diesel that is projected to be 

consumed in Alaska or a U.S. territory in 

year i if the state or territory opts-in, in 

gallons. 

GEi = The amount of gasoline projected to be 

produced by exempt small refineries and 

small refiners in year i, in gallons, in any 

year they are exempt per §§ 80.1441 and 

80.1442, respectively. For 2012, this 

value is 3.27 bill gal. See further 

discussion in Section III.B.2 below. 

DEi = The amount of diesel projected to be 

produced by exempt small refineries and 

small refiners in year i, in gallons, in any 

year they are exempt per §§ 80.1441 and 

80.1442, respectively. For 2012, this 

value is 1.23 bill gal. See further 

discussion in Section III.B.2 below. 

The four separate renewable fuel 

standards for 2012 are based on the 49- 

state gasoline and diesel consumption 

volumes projected by EIA. The Act 

requires EPA to base the standards on 

an EIA estimate of the amount of 

gasoline and diesel that will be sold or 

introduced into commerce for that year. 

The projected volume of gasoline used 

to calculate the final 2012 percentage 

standards will be provided directly by 

EIA. For the purposes of this proposal, 

we have used the April 2011 issue of 

STEO for the gasoline projection. The 

projected volume of transportation 

diesel used to calculate the final 2012 

percentage standards will be provided 

by EIA. For the purposes of this 

proposal, we have used the Early 

Release version of AEO2011. Gasoline 

and diesel volumes are adjusted to 

account for renewable fuel contained in 

the EIA projections. The projected 

volumes of ethanol and biodiesel used 

to calculate the final percentage 

standards will be provided by EIA; for 

2011, the final values were based on 

EIA’s Short-Term Energy Outlook 

(STEO). For the purposes of this 

proposal, we have used the April 2011 

values for ethanol and biodiesel 

provided in the STEO. Although EIA 

will be providing fuel consumption 

projections for the final rule, using the 

most recent available EIA data for 

purposes of this proposal allows us to 

provide the affected industries with a 

reasonable estimate of the standards for 

planning purposes. 

2. Small Refineries and Small Refiners 

In CAA section 211(o)(9), enacted as 

part of the Energy Policy Act of 2005, 

Congress provided a temporary 

exemption to small refineries (those 

refineries with a crude throughput of no 

more than 75,000 barrels of crude per 

day) through December 31, 2010. In 

RFS1, we exercised our discretion under 

section 211(o)(3)(B) and extended this 

temporary exemption to the few 

remaining small refiners that met the 

Small Business Administration’s (SBA) 

definition of a small business (1,500 

employees or less company-wide) but 

did not meet the statutory small refinery 

definition as noted above. Because EISA 

did not alter the small refinery 

exemption in any way, the RFS2 

program regulations exempted gasoline 

and diesel produced by small refineries 

and small refiners in 2010 from the 


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22 DOE report ‘‘EPACT 2005 Section 1501 Small 

Refineries Exemption Study’’, (January, 2009). 

23 ‘‘Small Refinery Exemption Study: An 

Investigation into Disproportionate Economic 

Hardship,’’ U.S. Department of Energy, March 2011. 

24Since the standards are applied on an annual 

basis, the exemptions are likewise on an annual 

basis even though the determination of which 

refineries would receive an extension to their 

exemption did not occur until after January 1, 2011. 25 75 FR 14716, March 26, 2010. 

26To determine the 49-state values for gasoline 

and diesel, the amounts of these fuels used in 

Alaska is subtracted from the totals provided by 

DOE. The Alaska fractions are determined from the 

most recent (2009) EIA State Energy Data, 

Transportation Sector Energy Consumption 

Estimates. The gasoline and transportation distillate 

fuel oil fractions are approximately 0.2% and 0.8%, 

respectively. Ethanol use in Alaska is estimated at 

8.4% of its gasoline consumption (based on the 

same State data), and biodiesel use is assumed to 

be zero. 

renewable fuels standard (unless the 

exemption was waived), see 40 CFR 

80.1141. 

Under the RFS program, Congress 

provided two ways that small refineries 

can receive a temporary extension of the 

exemption beyond 2010. One is based 

on the results of a study conducted by 

the Department of Energy (DOE) to 

determine if small refineries would face 

a disproportionate economic hardship 

under the RFS program. The other is 

based on EPA determination of 

disproportionate economic hardship on 

a case-by-case basis in response to 

refiner petitions. 

In January 2009, DOE issued a study 

which did not find that small refineries 

would face a disproportionate economic 

hardship under the RFS program.22 The 

conclusions were based in part on the 

expected robust availability of RINs and 

EPA’s ability to grant relief on a case-bycase basis. As a result, beginning in 

2011 small refiners and small refineries 

were required to participate in the RFS 

program as obligated parties, and there 

was no small refiner/refinery volume 

adjustment to the 2011 standard as there 

was for the 2010 standard. 

Following the release of DOE’s 2009 

small refinery study, Congress directed 

DOE to complete a reassessment and 

issue a revised report. DOE recently reevaluated the impacts of the RFS 

program on small entities and 

concluded that some small refineries 

would suffer a disproportionate 

hardship if required to participate in the 

program.23 As a result, these refineries 

will be exempt from being obligated 

parties for a minimum of two additional 

years, 2011 and 2012.24 The proposed 

2012 standards reflect the exemption of 

these refineries. In addition, and 

separate from the DOE determination, 

EPA may extend the exemption for 

individual small refineries on a case-bycase basis if they demonstrate 

disproportionate economic hardship. A 

few refineries have satisfactorily made 

this demonstration, and EPA has acted 

on their requests. The gasoline and 

diesel volumes of those refineries have 

been appropriately accounted for in the 

development of the proposed standards. 

If additional individual refinery 

requests for exemptions are approved 

following the release of this NPRM, the 

final standards will be adjusted to 

account for those exempted volumes of 

gasoline and diesel. However, any 

requests for exemptions that are 

approved after the release of the final 

2012 RFS standards will not affect the 

2012 standards. As stated in the final 

rule establishing the 2011 standards, 

‘‘EPA believes the Act is best 

interpreted to require issuance of a 

single annual standard in November 

that is applicable in the following 

calendar year, thereby providing 

advance notice and certainty to 

obligated parties regarding their 

regulatory requirements. Periodic 

revisions to the standards to reflect 

waivers issued to small refineries or 

refiners would be inconsistent with the 

statutory text, and would introduce an 

undesirable level of uncertainty for 

obligated parties.’’ Thus, after the 2012 

standards are finalized, any additional 

exemptions issued will not affect those 

standards. 

3. Proposed Standards 

As finalized in the March 26, 2010 

RFS2 rule, the standards are expressed 

in terms of energy-equivalent gallons of 

renewable fuel, with the cellulosic 

biofuel, advanced biofuel, and total 

renewable fuel standards based on 

ethanol equivalence and the biomassbased diesel standard based on biodiesel 

equivalence. However, all RIN 

generation is based on ethanolequivalence. More specifically, the 

RFS2 regulations provide that 

production or import of a gallon of 

biodiesel will lead to the generation of 

1.5 RINs. In order to ensure that demand 

for 1.0 billion physical gallons of 

biomass-based diesel will be created in 

2012, the calculation of the biomassbased diesel standard provides that the 

required volume be multiplied by 1.5. 

The net result is a biomass-based diesel 

gallon being worth 1.0 gallons toward 

the biomass-based diesel standard, but 

worth 1.5 gallons toward the other 

standards.25

The levels of the percentage standards 

would be reduced if Alaska or a U.S. 

territory chooses to participate in the 

RFS2 program, as gasoline and diesel 

produced in or imported into that state 

or territory would then be subject to the 

standard. Neither Alaska nor any U.S. 

territory has chosen to participate in the 

RFS2 program at this time, and thus the 

value of the related terms in the 

calculation of the standards is zero. 

Note that the terms for projected 

volumes of gasoline and diesel use 

include gasoline and diesel that has 

been blended with renewable fuel. 

Because the gasoline and diesel volumes 

estimated by EIA include renewable fuel 

use, we must subtract the total 

renewable fuel volume from the total 

gasoline and diesel volume to get total 

non-renewable gasoline and diesel 

volumes. The values of the variables 

described above are shown in Table 

III.B.3–1.26 Terms not included in this 

table have a value of zero. 

TABLE III.B.3–1—VALUES FOR TERMS

IN CALCULATION OF THE STANDARDS

[Bill gal] 

Term Value 

RFVCB,2012 ......................... 0.00355–0.0157 

RFVBBD,2012 ...................... 1.0 

RFVAB,2012 ........................ 2.0 

RFVRF,2012 ......................... 15.20 

G2012 ................................. 139.98 

D2012 .................................. 44.47 

RG2012 ............................... 14.17 

RD2012 ............................... 0.83 

Using the volumes shown in Table 

III.B.3–1, we have calculated the 

proposed percentage standards for 2012 

as shown in Table III.B.3–2. 

TABLE III.B.3–2—PROPOSED

PERCENTAGE STANDARDS FOR 2012 

Cellulosic biofuel ....... 0.002% to 0.010%. 

Biomass-based diesel 0.91%. 

Advanced biofuel ...... 1.21%. 

Renewable fuel ......... 9.21%. 

IV. Biomass-Based Diesel Volume for 

2013 

In today’s action we are proposing an 

applicable volume for biomass-based 

diesel for 2013, based on the statutory 

requirement to establish the applicable 

volume of biomass-based diesel for 

years after 2012 no later than 14 months 

before the first year for which the 

applicable volume will apply. To do 

this, we have reviewed RFS program 

implementation to date and analyzed a 

number of factors specified in the 

statute as part of this effort. We have 

investigated what the demand for 

biomass-based diesel is likely to be in 

2013 taking into consideration the 

applicable advanced biofuel volume 

specified in the statute, the analyses we 


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38860 Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 

27For example, EPA may waive a given standard 

in whole or in part following the provisions at 

211(o)(7). 

conducted in the RFS2 final rulemaking, 

and a consideration of biodiesel 

production, consumption, and 

infrastructure issues. In these 

investigations, biodiesel was the 

primary focus since it is expected to be 

the predominant type of biomass-based 

diesel through at least the next few 

years. However, renewable diesel may 

also play a role in meeting the biomassbased diesel standard. When 

appropriate, we have discussed 

renewable diesel separately from 

biodiesel. 

Note that, in proposing the 2013 

applicable volume of biomass-based 

diesel, we are not at this time proposing 

the percentage standards that would 

apply to obligated parties in 2013. 

Instead, the percentage standards will 

be determined after projections of 

gasoline and diesel volume are provided 

by the Energy Information 

Administration (EIA) in the fall of 2012, 

and will be announced by November 30, 

2012. Moreover, in today’s proposal we 

are not addressing potential exemptions 

for small refineries and/or small refiners 

in 2013, since such exemptions are only 

relevant in the context of specifying the 

percentage standards and their 

applicability. Finally, we are not 

proposing any applicable volumes of 

biomass-based diesel for 2014 or later 

years. 

A. Statutory Requirements 

Section 211(o)(2)(B)(i) of the Clean 

Air Act specifies the applicable volumes 

of renewable fuel on which the annual 

percentage standards must be based, 

unless the applicable volumes are 

waived or adjusted by EPA in 

accordance with specific authority and 

directives specified in the statute.27

Applicable volumes are provided in the 

statute for years through 2022 for 

cellulosic biofuel, advanced biofuel, and 

total renewable fuel. For biomass-based 

diesel, applicable volumes are provided 

through 2012. For years after those 

specified in the statute (i.e. 2013+ for 

biomass-based diesel and 2023+ for all 

others), EPA is required to determine 

the applicable volume, in coordination 

with the Secretary of Energy and the 

Secretary of Agriculture, based on a 

review of the implementation of the 

program during calendar years for 

which the statute specifies the 

applicable volumes, and an analysis of 

the following: 

• The impact of the production and 

use of renewable fuels on the 

environment, including on air quality, 

climate change, conversion of wetlands, 

ecosystems, wildlife habitat, water 

quality, and water supply; 

• The impact of renewable fuels on 

the energy security of the United States; 

• The expected annual rate of future 

commercial production of renewable 

fuels, including advanced biofuels in 

each category (cellulosic biofuel and 

biomass-based diesel); 

• The impact of renewable fuels on 

the infrastructure of the United States, 

including deliverability of materials, 

goods, and products other than 

renewable fuel, and the sufficiency of 

infrastructure to deliver and use 

renewable fuel; 

• The impact of the use of renewable 

fuels on the cost to consumers of 

transportation fuel and on the cost to 

transport goods; and 

• The impact of the use of renewable 

fuels on other factors, including job 

creation, the price and supply of 

agricultural commodities, rural 

economic development, and food prices. 

While EPA is given the authority to 

determine the appropriate volume of 

renewable fuel for those years that are 

not specified in the statute based on a 

review of program implementation and 

analysis of the factors listed above, the 

statute also specifies that the applicable 

volume of biomass-based diesel cannot 

be less than the applicable volume for 

calendar year 2012, which is 1.0 bill 

gallons. 

It is useful to note that the statutory 

provisions described above are silent in 

two important areas. First, the statute 

does not provide numerical criteria or 

thresholds that must be attained in the 

determination of applicable volumes 

(other than specifying a minimum 

volume of 1.0 bill gal), nor does it 

describe any overarching goals such as 

maximizing GHG or energy security 

benefits or minimizing cost. The EPA, in 

coordination with DOE and USDA, is 

thus effectively charged with making a 

determination of the applicable volumes 

based on a judgment of their 

reasonableness in the context of a 

review of program implementation and 

analysis of the factors described above. 

Second, the statute does not provide 

authority to raise the applicable 

volumes of advanced biofuel or total 

renewable fuel above those specified in 

the statute for years up to and including 

2022. Thus, any increase in the biomassbased diesel volume requirement above 

that specified for 2012 would not have 

any impact on the advanced biofuel or 

total renewable fuel volume 

requirements. Rather, increasing the 

biomass-based diesel volume 

requirement above 1.0 bill gallons 

would likely result in a change in the 

makeup of biofuels used to meet the 

advanced biofuel and the total 

renewable fuel standards, but would not 

change the total required volumes of 

those fuels (in terms of ethanolequivalent gallons). 

Finally, the statute also specifies the 

timeframe within which these volumes 

must be promulgated: The rules 

establishing the applicable volumes 

must be finalized no later than 14 

months before the first year for which 

such applicable volume will apply. For 

the biomass-based diesel volume that 

would apply beginning on January 1, 

2013, then, we must finalize the 

applicable volume by November 1, 

2011. 

B. Factors Considered in Assessing 2013 

Biomass-Based Diesel Volumes 

As described in Section IV.A, we are 

required to review the implementation 

of the RFS program for years prior to 

2013, and to use information from this 

review in determining the applicable 

volume of biomass-based diesel for 

2013. However, given the short history 

of the RFS program, we believe this 

review is of limited value. Prior to the 

beginning of the RFS2 program on July 

1, 2010, the RFS1 program had no 

volume requirement specific to biomassbased diesel. Although RINs were 

generated for biodiesel under the RFS1 

program and those RINs were available 

for use in satisfying obligated parties’ 

RFS1 total renewable fuel Renewable 

Volume Obligation (RVO), we do not 

believe that the RFS1 program 

contributed significantly to producers’ 

production decisions. Rather, biodiesel 

production was driven by market 

demand apart from the RFS program 

requirements coupled with a tax credit 

for biodiesel blends. We believe that 

little can be discerned from the RFS1 

history about the operation of the 

biodiesel industry under a future RFS2 

volume mandate. 

In the short time since the RFS2 

program went into effect, biodiesel 

production volumes have not increased 

substantially above historical levels due 

most likely to factors such as the 

availability of carryover RINs from 2008 

and 2009 and the expiration of the 

biodiesel tax credit (which was 

reinstituted at the end of 2010). 

Domestic biodiesel consumption varied 

little in the 2008–2010 timeframe, 

averaging about 330 mill gallons each 

year. 

Given the increases in the biomassbased diesel volumes that are required 

in the statute for 2011 and 2012, we 

expect production and consumption 

volumes of biodiesel to increase 


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28Renewable Fuel Standard Program (RFS2) 

Regulatory Impact Analysis. EPA–420–R–10–006, 

February 2010. See Table 1.2–3. 

29Official Statistics of the U.S. Department of 

Commerce U.S. International Trade Commission. 

Data only available from January–November 2010. 

substantially above these recent historic 

levels. A review of the RFS program 

during 2011 and 2012 will, therefore, 

provide more relevant information 

regarding implementation of the RFS 

program for purposes of helping us to 

evaluate how the industry, as well as 

feedstock supplies and infrastructure, 

can respond to potential requirements 

in 2014 and beyond. For the purposes 

of proposing the 2013 biomass-based 

diesel applicable volume in today’s 

NPRM, however, this information is not 

available. 

With the limited information 

available on the current and historical 

operation of the RFS program, we 

believe it would be prudent for 2013 to 

consider only moderate increases above 

the statutory minimum of 1.0 bill 

gallons. One possible benchmark is 

provided by the increments and growth 

pattern of those increments that 

Congress established for the years 2009– 

2012, shown in Table IV.B–1. 

TABLE IV.B–1—INCREMENTAL INCREASES IN BIOMASS-BASED DIESEL

IN THE STATUTE

[Bill gal] 

Applicable volume of biomass-based 

diesel 

Increment 

from previous 

year 

2009 ............ 0 .5 n/a 

2010 ............ 0 .65 0.15 

2011 ............ 0 .80 0.15 

2012 ............ 1 .0 0.20 

These increments provide a precedent 

for evaluating a reasonable mandatory 

minimum growth pattern for 2013. The 

increments increased in magnitude over 

the four-year period specified in the 

statute, increasing from 0.15 bill gal to 

0.20 bill gal. If this trend were to 

continue, the 2013 volume could be 

more than 0.20 bill gal higher than the 

2012 volume. Thus our intention is to 

consider an incremental increase in the 

applicable volume of biomass-based 

diesel between 2012 and 2013 that is 

not a dramatic change from the trend in 

increments shown above. 

In the final rulemaking establishing 

the RFS2 program, we developed 

renewable fuel volume scenarios for all 

years between 2010 and 2022. For 2013, 

we estimated a biomass-based diesel 

volume of 1.28 bill gallons. This volume 

was based primarily on a projection of 

the qualifying feedstocks that could be 

available. Our analyses of feedstock 

availability in the RFS2 final rule 

concluded that the 2013 minimum 

biomass-based diesel volume of 1.0 bill 

gallons could be met and, indeed, that 

1.28 billion gallons could be reasonably 

produced.28 The value of 1.28 bill 

gallons assumed for 2013 in the RFS2 

final rule appears to roughly follow the 

pattern in incremental growth shown in 

Table IV.B–1 above. Moreover, this 

biomass-based diesel volume has 

already been partially evaluated in the 

RFS2 rule. Therefore, EPA decided to 

evaluate the appropriateness of 

proposing an applicable volume for 

2013 of 1.28 bill gallons. To this end, we 

considered whether 1.28 bill gal of 

biomass-based diesel was reasonable 

given likely market demand, availability 

of feedstocks, production capacity, 

limitations related to storage and 

consumption, infrastructure, and the 

impacts of biomass-based diesel in a 

variety of areas as required under the 

statute. These impacts are discussed in 

the subsequent Section IV.C. 

1. Demand for Biomass-Based Diesel 

The demand for biomass-based diesel 

in 2013 will be a function of not only 

the biomass-based diesel standard, but 

also the advanced biofuel standard, 

since the standards under the RFS2 

program are nested. That is, every RIN 

that is valid for meeting the biomassbased diesel standard is also valid for 

meeting the advanced biofuel standard. 

Moreover, there are currently only a 

small number of biofuels that are likely 

to be available for meeting the advanced 

biofuel standard. In addition to biomassbased diesel, these would include any 

RINs used to meet the cellulosic biofuel 

standard, coprocessed renewable diesel, 

and sugarcane ethanol. To the degree 

that there are limits in these other 

advanced biofuels, additional biomassbased diesel may be needed to make up 

any shortfall. 

Since the advanced biofuel standard 

is an important factor in determining 

the demand for biomass-based diesel in 

2013, we considered how it should be 

treated in light of the fact that we must 

determine the applicable 2013 volume 

for biomass-based diesel this year, but 

we will not set the 2013 standards 

(including the advanced biofuel 

standard for 2013) until next year. EPA 

has the authority to reduce the 

applicable volume of advanced biofuel 

in the event that it reduces the 

applicable volume of cellulosic biofuel. 

EPA will consider using this authority 

at the time it evaluates whether the 2013 

applicable volume of cellulosic biofuel 

set in the statute should be lowered in 

light of projected production volumes. 

In both 2010 and 2011 EPA lowered the 

applicable volume of cellulosic biofuel 

without lowering the applicable volume 

of advanced biofuel. EPA is today 

proposing the same approach for 2012. 

In light of this history, and the fact that 

EPA cannot finally evaluate the issue of 

potentially lowering the applicable 

volume of advanced biofuel for 2013 

until it sets the 2013 standards in 

November of 2012, we assume for 

purposes of today’s evaluation of 

biomass-based diesel demand in 2013 

that the applicable volume of 2.75 bill 

gallons of advanced biofuel specified in 

the statute for 2013 will be used in 

setting the 2013 advanced biofuel 

standard. 

As described in Section II, the 

cellulosic biofuel industry continues to 

develop, with numerous projects under 

development, planned or underway. 

Nevertheless, the actual production 

volumes continue to fall far below the 

applicable volumes specified in the 

statute. For instance, we are proposing 

a cellulosic biofuel volume of 3.55–15.7 

mill gallons for 2012, compared to the 

applicable volume of 500 mill gal 

specified in the statute. In 2013, the 

applicable volume doubles to 1.0 bill 

gallons. While we have not projected 

specific volumes of cellulosic biofuel 

that may be available in 2013, it is 

highly likely that they will fall 

significantly short of 1.0 bill gallons, 

and are likely to comprise only a small 

portion of the 2.75 bill gal applicable 

volume for advanced biofuel in 2013. 

Imported sugarcane ethanol can also 

be used to meet the advanced biofuel 

standard. Between years 2000 and 2009, 

the volume of ethanol imported into the 

U.S. has ranged from 46–730 million 

gallons per year, or on average, 

approximately 200 million gallons per 

year. These volumes were comprised 

almost exclusively of sugarcane ethanol 

from Brazil. In 2010, imports of ethanol 

into the U.S. were among the lowest in 

the past 10 years, reaching only 17 

million gallons.29 Some of this recent 

decline in ethanol imports may be due 

to extremely wet weather in 2009/10 

and dry conditions in 2010/11 which 

cut into Brazilian supplies of sugarcane 

and reduced sugar content. In addition, 

some Brazilian sugarcane mills have the 

ability to switch between producing 

sugars for sweetener markets and 

extracting sugars for ethanol markets. 

The international price of sweetener 

was so attractive in 2010 that mills may 

have given greater priority to sugar. 

Another factor is the expanding sales of 

flex fuel vehicles in Brazil, which has 


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30U.S. Energy Information Administration (EIA). 

‘‘AEO2011 Early Release,’’ December 2010. http:// 

www.eia.doe.gov/forecasts/aeo/index.cfm. 

31Food and Agricultural Policy Research 

Institute. ‘‘FAPRI 2010 U.S. and World Agricultural 

Outlook: World Biofuels,’’ http:// 

www.fapri.iastate.edu/outlook/2010/text/ 

15Biofuels.pdf. 

32Hart Energy Consulting. ‘‘Global Biofuels 

Outlook: 2010–2020,’’ October 2010. 

33Sucres et Denre ́es (S&D), ‘‘Ethanol Report,’’ 

November 2010. 

34 ‘‘Biodiesel Production Prospects for the Next 

Decade,’’ IHS Global Insight, March 11, 2011. 

continued to increase Brazilian 

domestic ethanol demand, thus likely 

limiting amounts available for exports. 

Therefore, history shows that the 

volume of imported ethanol can 

fluctuate greatly due to a variety of 

market influences. 

Longer-term market projections can 

help to better understand the potential 

outlook for imports of sugarcane ethanol 

as a function of international 

agricultural and energy markets. One 

source that evaluates trends and issues 

for U.S. energy markets is the U.S. 

Energy Information Administration’s 

(EIA) Annual Energy Outlook (AEO).30

This report projects U.S. net ethanol 

imports in 2013 to be 332 million 

gallons. Another source for U.S. and 

world commodity projections is the 

Food and Agricultural Policy Research 

Institute’s (FAPRI) U.S. and World 

Agricultural Outlook. The most current 

version of the outlook, the FAPRI 2010 

Agricultural Outlook, projects for the 

year 2013 that the U.S. will have net 

ethanol imports of 333 million 

gallons.31 In comparison, for the RFS2 

final rulemaking, we assumed 190 

million gallons of imported sugarcane 

ethanol could be available in 2013 based 

on EIA’s AEO2007. 

Since ethanol supplies can flow to 

countries other than the U.S., an 

important part of understanding 

potential imports into the U.S. are the 

current and future biofuel mandates and 

goals of other nations. Such mandates 

include, for instance, Canada’s 5% fuel 

ethanol mandate which started in late 

2010, requiring approximately 500 

million gallons per year. Another goal is 

that of the EU, the renewable energy 

directive, which includes a minimum 

target of 10% renewable energy use in 

transport by 2020, a portion of which is 

expected to be met with ethanol. Other 

countries with ethanol mandates and 

goals are India, Indonesia, Philippines, 

Costa Rica, Peru, and Argentina, to 

name a few. According to Hart Energy 

Consulting, most countries will be in a 

potential supply deficit for ethanol by 

2020, and the primary country in a 

position to supply the global ethanol 

market will be Brazil.32 Chief 

competitors for the U.S. to receive 

Brazilian ethanol are expected to be the 

EU, China, and Japan. This increasing 

international demand for biofuels may 

limit export supplies available for the 

U.S. in 2013. 

The demand for ethanol in Brazil is 

also increasing, further limiting volumes 

that will likely be exported. For 

instance, the sales share of flex-fuel 

vehicles (FFVs) in Brazil are reported to 

have risen dramatically in the last 

decade, contributing to an in-use fleet 

that is increasingly capable of operating 

on pure ethanol. By 2014, 70% of the inuse fleet is expected to be FFVs, 

compared to only 33% in 2009. While 

the aforementioned FAPRI report 

projected that 2013 Brazilian demand 

for ethanol could be 7.7 billion gallons, 

S&D estimated that 2013 demand could 

potentially reach as high as 11 billion 

gallons, outpacing Brazilian production 

capacity.33

We believe that given the discussions 

above, it is reasonable to conclude that 

Brazilian sugarcane ethanol will 

continue to provide limited volumes of 

advanced biofuel in the U.S. in the near 

term due to other competitive uses. 

While imports of sugarcane ethanol into 

the U.S. in 2013 could exceed the 190 

million gallons estimated in RFS2, they 

are unlikely to reach the historical high 

of 730 mill gallons for the reasons 

described above. 

In addition to cellulosic biofuel and 

imported sugarcane ethanol, there is 

also some potential for other advanced 

biofuels that could be used to meet the 

advanced biofuel standard of 2.75 bill 

gallons. The most likely of these is 

sugar-based ethanol from domestic 

sugarcane. Several companies have 

announced plans for sugar-based 

ethanol production in California, 

Louisiana, and Florida. Two of these 

companies have announced plans for 

multiple ethanol production facilities, 

however none of these companies have 

yet begun construction. In addition, 

coprocessed renewable diesel is 

uncertain, though there could 

conceivably be up to a hundred million 

gallons by 2013. Potential production of 

other advanced biofuels such as 

renewable butanol or ethanol from noncorn starches in biomass-fueled 

facilities is even less certain for 2013. 

However, as described in Section II.D, 

companies such as Gevo, Solazyme, and 

LS9 are in the process of building or 

converting facilities to produce 

advanced biofuels in the form of 

butanol, jet fuel, and renewable diesel, 

respectively, that may count as 

advanced biofuel. We expect all these 

other sources of advanced biofuel to 

contribute about one or two hundred 

million gallons in 2013. 

In summary, we believe that the total 

volume of cellulosic biofuel, imported 

sugarcane ethanol, and other advanced 

biofuels that may be available in 2013 

is likely to be less than about 1 billion 

gallons. In order to reach an advanced 

biofuel volume of 2.75 billion gallons, 

then, it is likely that more than 1.0 bill 

gallons of biomass-based diesel 

(representing more than 1.5 billion 

ethanol-equivalent gallons) will be 

needed. The volume of biomass-based 

diesel that may be needed in excess of 

1.0 bill gallons could potentially be on 

the order of hundreds of millions of 

gallons. This result is similar to the 

assumption made by IHS Global Insight 

in their recent report, in which they 

assume that an additional 300 million 

gallons of biodiesel will be needed over 

and above the 1.0 billion gallons 

mandate for biomass-based diesel in 

order for the advanced biofuel standard 

to be met.34

As mentioned above, we do not 

believe it would be prudent to set the 

biomass-based diesel applicable volume 

for 2013 such that the increment over 

2012 volumes is excessive in 

comparison to the increments, and 

trajectory of increments, established by 

Congress for the years 2009–2012. As a 

result, we believe that a biomass-based 

diesel volume of 1.28 bill gallons would 

both reflect likely increased demand for 

biomass-based diesel in 2013 and 

provide an increment that is not 

excessive when compared to those 

established by Congress. 

2. Availability of Feedstocks to Produce 

1.28 Billion Gallons of Biodiesel 

As described above, in the final 

rulemaking establishing the RFS2 

program we developed renewable fuel 

volume scenarios for all years between 

2010 and 2022. For 2013, we estimated 

a biomass-based diesel volume of 1.28 

bill gallons. This volume was based 

primarily on a projection of the 

qualifying feedstocks that could be 

available, as summarized in Table 

IV.B.2–1. 

TABLE IV.B.2–1—FEEDSTOCKS CONTRIBUTING TO 2013 VOLUME OF

1.28 BILL GAL

Source Volume 

(mill gal) 

Yellow grease and other rendered 

fats ............................................ 380 

Corn oil ......................................... 300 


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35Current Industrial Reports, U.S. Census Bureau, 

M311K—Fats and Oils: Production, Consumption, 

and Stocks, Table 2b. Assumes 7.5 lb/gal. December 

projection based on the average of January– 

November. http://www.census.gov/manufacturing/ 

cir/historical_data/m311k/index.html. 

36Mueller, Steffen. ‘‘Detailed Report: 2008 

National Dry Mill Corn Ethanol Survey.’’ University 

of Illinois at Chicago Energy Resources Center (May 

4, 2010). Available online: http:// 

ethanolrfa.3cdn.net/ 

2e04acb7ed88d08d21_99m6idfc1.pdf. 

TABLE IV.B.2–1—FEEDSTOCKS CONTRIBUTING TO 2013 VOLUME OF

1.28 BILL GAL—Continued 

Source Volume 

(mill gal) 

Virgin vegetable oil ....................... 600 

Total ....................................... 1,280 

We continue to believe that the 

feedstock volumes shown in Table 

IV.B.2–1 are reasonable projections for 

2013. For instance, according to the U.S. 

Census Bureau, the total volume of 

yellow grease and other greases (most 

likely trap grease) produced in 2010 was 

about 340 mill gallons.35 The volume of 

inedible tallow produced in the same 

period was over 400 mill gallons. Other 

potential sources could include edible 

tallow, lard, and poultry fats. Taken 

together, the total volume of available 

grease and fats for use in producing 

biomass-based diesel is in excess of the 

380 mill gallons we projected in the 

RFS2 final rule. 

The 300 million gallons of biodiesel 

produced from corn oil extracted from 

distillers grains produced at ethanol 

facilities is based on projections of the 

percentage of the ethanol industry using 

corn oil extraction technology and the 

amount of oil extracted per bushel of 

corn in 2013. The RFS2 final rule 

projected that by 2013, 34% of all dry 

mill ethanol facilities would extract 

corn oil from the by-products of ethanol 

production. A recent survey of the 

ethanol industry found that by 2008 

over 30% of all dry mill ethanol plants 

were already extracting corn oil from 

their co-products.36 EPA expects that 

the percentage of dry mill ethanol 

facilities using some form of corn oil 

extraction technology will increase to 

60% by 2013. The corn oil extraction 

technology currently being used at most 

dry mill ethanol facilities is capable of 

extracting approximately one third of 

the oil contained in the corn kernel from 

the whole stillage and/or its derivatives 

(a significantly reduced rate than the 

two thirds of oil extracted assumed to be 

technically feasible by 2022 in the RFS2 

final rule). If 60% of all dry mill corn 

ethanol facilities were extracting one 

third of the oil in the corn kernel in 

2013 the amount of corn oil available for 

biodiesel production would be 

approximately 270 million gallons. As 

corn oil extraction technology develops 

and higher oil extraction rates are 

achieved, corn ethanol producers are 

likely to adopt this new technology. 

EPA expects that by 2013 these 

technology improvements will increase 

corn oil production levels to the 

300 million gallons projected in the 

RFS2 rule. Alternatively, additional 

corn oil could come from ethanol 

production facilities using corn 

fractionation or wet milling technology. 

This corn oil was not considered as a 

biodiesel feedstock in the RFS2 rule, but 

market conditions may result in its 

availability to the biodiesel industry. 

The high adoption rate of corn oil 

extraction and the promise of ever 

increasing oil extraction yields indicate 

that the 300 million gallons of corn oil 

extraction projected in the RFS2 rule in 

2013 remains a reasonable projection. 

With regard to virgin vegetable oil, the 

modeling we conducted for the RFS2 

final rule assumed that it would be 

composed entirely of soybean oil. For 

the purposes of today’s proposal we 

examined recent and historical soybean 

oil production and consumption 

volumes from the U.S. Census Bureau to 

verify that 600 million gallons was a 

reasonable potential volume for 

biodiesel production in 2013. As shown 

in Figure IV.B.2–1, soy oil production 

has increased steadily over the last 

30 years, reaching 2.5 bill gal in 2009. 

If these production trends continue, 

domestic soy oil production could reach 

nearly 2.9 bill gal by 2013. 


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To determine what portion of 

domestically produced soy oil could be 

available for use in the production of 

biomass-based diesel in 2013, we also 

examined recent historical trends for 

domestic consumption and exports. 

Domestic consumption of soy oil for 

purposes other than biofuel has also 

increased steadily over the last 30 years, 

but was notably lower in the period 

2007–2009 compared to previous years. 

If consumption returns to historical 

trends for years after 2009, consumption 

could be as high as 2.5 bill gal by 2013. 

However, as shown in Figure IV.B.2–2 

below, this would require a significant 

increase in consumption from 2009 to 

2010. Thus 2013 consumption could be 

lower than 2.5 bill gal. 


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Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 38865 

37 75 FR 59622. 

38EPA memorandum, ‘‘Summary of Modeling 

Input Assumptions for Canola Oil Biodiesel for the 

Notice of Supplemental Determination for 

Renewable Fuels Produced Under the Final RFS2 

Program,’’ Document # EPA–HQ–OAR–2010–0133– 

0049. 

Based on these projections, then, the 

volume of soy oil that would be 

available for the production of biomassbased diesel would be at least 400 

million gallons (2.9–2.5 bill gal). 

However, soy oil that has historically 

been exported represents another 

potential source of soy oil for biodiesel 

production. Exports of soy oil have 

followed only a very weak increasing 

trend, averaging about 230 mill gal/year 

over the same 30 year period, and about 

250 mill gal/year over the last 10 years. 

If these exports were diverted to the 

production of biomass-based diesel, the 

total volume of soy oil available for the 

production of biodiesel and/or 

renewable diesel would exceed 600 mill 

gallons. 

Although we assumed that all virgin 

vegetable oils used in biomass-based 

diesel production would be soy oil in 

the RFS2 final rule, in fact other seed 

oils may contribute meaningful volumes 

to the pool available for the production 

of biomass-based diesel. For instance, 

on September 28, 2010 we approved a 

RIN-generating pathway for biodiesel 

made from canola oil.37 The volume of 

biodiesel made from canola oil was 96 

mill gallons in 2008.38 In addition, we 

are evaluating other pathways for the 

production of biodiesel from oilseeds, 

such as camelina, which could 

potentially be approved for RIN 

generation by 2013. Algal oil could also 

provide additional feedstocks if 

promising technologies for production 

are commercialized. 

IHS Global Insight recently released 

an independent report in which they 

conducted macroeconomic modeling to 

investigate biodiesel growth scenarios 

and related impacts on commodities 

such as oilseed crops. Their agricultural 

modeling indicated that a slightly more 

diverse mix of feedstocks would be used 

to meet a total domestic biodiesel 

production volume of 1.3 bill gallons in 

2013. These volumes are shown in 

Table IV.B.2–2. 

TABLE IV.B.2–2—FEEDSTOCKS CONTRIBUTING TO 2013 VOLUME OF 1.3 

BILL GAL FROM IHS GLOBAL INSIGHT MODELING

Source Volume 

(mill gal) 

Yellow grease and other rendered 

fats ............................................ 272 

Corn oil ......................................... 185 

Soybean oil ................................... 624 

Canola oil ...................................... 68 

Palm oil ......................................... 7 

Other ............................................. 185 

Total ....................................... 1,340 

Source: Table 2, ‘‘Biodiesel Production 

Prospects for the Next Decade,’’ IHS Global 

Insight, March 11, 2011. 

This modeling concluded that soy oil 

production would be lower than the 

trends shown in Figure IV.B.2–1, with a 

correspondingly lower volume of soy oil 

being used for domestic non-biofuel 

consumption as well. Nevertheless, 

their modeling concluded that soy oil 

availability for biodiesel production 

would be 624 mill gallons, slightly 

higher than what we assumed in the 

RFS2 final rule. While their modeling 


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38866 Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 

39USA Plants, biodieselmagazine.com, as of 

January 27, 2011. 

40 ‘‘Automaker’s’ and Engine Manufacturers’ 

Positions of Support for Biodiesel Blends,’’ 

Biodiesel.org. 

41Annual Energy Outlook (AEO) 2011 Early 

Release, Table 2. 

42U.S. Department of Energy, Alternative Fuels 

and Advanced Vehicles Data Center. 

concluded that the volumes of greases, 

fats, and corn oil would be somewhat 

less than what we assumed in the RFS2 

final rule, they were able to quantify the 

available volumes of other feedstocks 

that we did not explicitly investigate in 

the RFS2 final rule. As a result, this 

report supports our finding that 

sufficient feedstocks will be available to 

produce 1.28 bill gallons of biomassbased diesel in 2013. 

3. Production Capacity 

Total production capacity of the 

biodiesel industry has exceeded 1.28 

bill gallons for a number of years. As of 

January 2011, total production capacity 

was more than 2.8 bill gallons for 168 

plants 39. According to the National 

Biodiesel Board, 90 of these plants had 

registered with the EPA under the RFS2 

program as of February 4, 2011, and 

these plants had a combined production 

capacity of over 1.9 bill gallons. The 

remaining plants are either producing 

extremely low volumes that fall under 

the regulatory threshold for RIN 

generation, are producing products 

other than biodiesel such as soaps or 

cosmetics, or have shut down until such 

time as the demand for biodiesel rises. 

Most of the 90 registered plants are 

currently producing at significantly 

under capacity, as evidenced by the fact 

that total production volumes in 2010 

were 300–400 million gallons, and the 

registered plants have a capacity of over 

1.9 billion gallons. If these plants 

increase production to meet the 800 

million gallon volume requirement for 

2011, on average, then, registered 

biodiesel producers will be producing at 

about half of their capacity this year. 

Nevertheless, we believe based on the 

registered capacity of existing plants 

and the relative ease of expanding 

current production within this capacity 

that the biodiesel industry can produce 

at least 1.28 bill gallons in 2013 with 

little leadtime needed for facilities to 

ramp up to higher production levels, 

and/or for currently idle facilities to 

come back online. 

4. Consumption Capacity 

Biodiesel is registered with the EPA 

under 40 CFR part 79 as a legal fuel for 

use in highway vehicles. Under this 

registration, it can legally be used at any 

blend level, from 1% (B1) to 100% 

(B100). However, other factors typically 

limit the concentration of biodiesel in 

conventional diesel fuel. Since the 

consumption of biodiesel at lower blend 

levels would tend to increase the 

geographic areas where biodiesel must 

be marketed, it is an important 

consideration in how much biodiesel 

can be consumed in the U.S. as a whole 

as well as how the infrastructure may 

need to change to accommodate 1.28 

bill gallons in 2013. 

Most engine manufacturers have 

explicit statements in their engine 

warranties regarding acceptable 

biodiesel blend levels. Although a few 

permit B100 to be used in their engines 

without any adverse impact on their 

warranties, most limit biodiesel blends 

to B20 or less, and about half allow no 

more than B5 40. For specific 

applications where a party knows which 

engines will be using biodiesel blends, 

higher concentrations of biodiesel may 

be possible. However, for general 

distribution such as at retail facilities, 

these warranty conditions create a 

disincentive to blend or sell biodiesel at 

higher concentrations, and would tend 

to drive most blends towards low 

concentrations of biodiesel such as B5. 

Cold weather operability represents 

another reason for preferential use of B5 

and even B2. The most common 

measure of cold weather operability is 

the fuel cloud point. The cloud point is 

the temperature at which gelling begins 

(as indicated by solid crystals beginning 

to form in the fuel), and thus is an 

indicator of when potential engine filter 

plugging issues could arise. The higher 

the cloud point temperature of the fuel, 

the more likely such problems are to be 

experienced in cold weather. Biodiesel 

generally has a higher cloud point than 

conventional, petroleum-based diesel 

fuel, with fat-based biodiesel such as 

tallow having a higher cloud point than 

virgin oil-based biodiesel such as a fuel 

made with soybean and canola oil. 

While cloud point issues with 

conventional, petroleum-based diesel 

are generally mitigated through 

blending with lighter grades (i.e. #1 

diesel fuel), the cloud point of biodiesel 

generally requires more dramatic 

interventions such as heated storage 

tanks, lines, and blending equipment, as 

well as heating rail cars and tank trucks. 

However, some of these biodiesel cloud 

point mitigation efforts may be reduced 

through the use of low biodiesel blend 

levels such as B2 or B5, since cloud 

point is strongly correlated with 

biodiesel concentration in the final 

blend. Insofar as biodiesel is blended 

into conventional diesel before being 

transported to its final destination for 

sale, low biodiesel blend levels may 

reduce the need for heated equipment at 

the final destination. 

Based on highway and nonroad diesel 

consumption projections for 2013 from 

the EIA, a biodiesel volume of 1.28 bill 

gallons would represent about 2.8% of 

all diesel fuel.41 If all biodiesel were to 

be blended as B5, just over half of the 

diesel fuel consumed nationwide in 

2013 would contain biodiesel. However, 

today some biodiesel is blended at 

concentrations higher than B5, and we 

expect that at least these same volumes 

would be blended at concentrations 

higher than B5 in the future. This would 

reduce the amount of diesel fuel that 

would contain some biodiesel, and thus 

would also reduce the geographical 

areas where biodiesel must be 

distributed. 

We believe that distributing and 

consuming 1.28 bill gallons of biodiesel 

in 2013 is achievable. A number of 

states already have mandates for the use 

of biodiesel in 2013, and efforts are 

underway to ensure that these mandates 

can be met. These include Minnesota, 

Oregon, Washington, Pennsylvania, 

New Mexico, and Louisiana. 

Collectively, these states account for 

approximately 13 percent of the 

nationwide consumption of diesel. 

Other states have implemented other 

forms of incentives as shown in Table 

IV.B.4–1. 

TABLE IV.B.4–1—STATES WITH REBATES, REFUNDS, REDUCED TAX

RATES, OR CREDITS FOR BIODIESEL

PRODUCTION OR BLENDING 42

Illinois 

Indiana 

Kansas 

Kentucky 

Maine 

Maryland 

Michigan 

Montana 

North Dakota 

Oklahoma 

Rhode Island 

South Carolina 

South Dakota 

Texas 

Virginia 

Washington 

* Conditions and exemptions for all incentive 

programs vary by state. 

Collectively, these states account for 

approximately 37% of the nationwide 

consumption of biodiesel. A variety of 

states also have requirements for the use 

of biodiesel in state fleets, provisions 

that allow biodiesel to be used as an 

alternative to meeting alternative fuel 

vehicle mandates, and credits/rebates 


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43Biodiesel contamination of jet fuel can 

contribute to fuel gelling and engine deposits which 

can lead to jet engine operability problems. 

44The cloud point refers to the temperature at 

which biodiesel begins to gell. Biodiesel cloud 

points are taken from the NC State University and 

A&T State University Cooperative Extension Web 

page, updated December 9, 2010, http:// 

www.extension.org/pages/ 

Biodiesel_Cloud_Point_and_Cold_Weather_Issues, 

and the Biodiesel cold weather blending study, 

Cold Flow Blending Consortium, National Biodiesel 

Board, 2001, http://www.nrel.gov/vehiclesandfuels/ 

npbf/pdfs/cftr_72805.pdf. 45The ASTM International ‘‘Standard 

Specification for Diesel Fuel Oils’’, ASTM D975, 

contains tenth percentile minimum ambient air 

temperatures for the U.S. 

46Communication from Larry Schafer of the 

National Biodiesel Board, March 2, 2011. 

47Renewable Fuels Standard Program (RFS2), 

Regulatory Impact Analysis (RIA), EPA–420–R–10– 

006, February 2010. 

48Manifest rail refers to the shipment of a product 

in rail cars in a train that includes rail cars 

containing other products. 

49See sections 1.6 and 4.2.3 of the RIA to the 

RFS2 final rule. 

for the installation of biodiesel 

dispensing and blending equipment. 

Altogether, therefore, more than half 

of the states in the U.S. have mandates 

and/or incentives that will induce them 

to address biodiesel infrastructure 

issues. Efforts in these areas will 

directionally help the nation to meet a 

1.28 bill gal biomass-based diesel 

requirement in 2013. 

5. Biomass-Based Diesel Distribution 

Infrastructure 

Biodiesel/petroleum based diesel fuel 

blends have limited ability to be 

transported using the existing petroleum 

product distribution system. There has 

been limited transportation of up to B5 

blends by certain pipelines that do not 

carry jet fuel. However, concerns over 

potential contamination of jet fuel with 

biodiesel currently prevent biodiesel 

blends from being transported by the 

majority of pipelines.43 The 

predominant means of biodiesel 

distribution is to transport it separately 

by rail car, tank truck, or barge to a 

petroleum terminal where it is blended 

with petroleum diesel fuel to make B2, 

B5, B20 blends that are then transported 

by truck to retail or fleet operators. For 

this analysis, we have assumed that all 

biodiesel is transported in a segregated 

fashion to petroleum terminals. To the 

extent that biodiesel is transported by 

pipeline, this may tend to reduce the 

burden on the fuel distribution system. 

Heated and insulated rail cars, tank 

trucks, barges, storage tanks, and 

blending equipment are required for 

biodiesel distribution to protect against 

fuel gelling during the cold season. 

Following are the cloud points of 

biodiesel manufactured from various 

feedstocks: Canola oil biodiesel 32F, soy 

biodiesel 34F, yellow grease biodiesel 

41F, jatropha oil biodiesel 46F, tallow 

biodiesel 54F–63F, and palm oil 

biodiesel 63F.44 Based on a review of 

these properties, climactic data, and the 

likelihood that downstream parties will 

need to accommodate biodiesel 

produced from various feedstocks, we 

believe that heated/insulated biodiesel 

infrastructure would be needed 

throughout most of the U.S.45

Approximately 82 petroleum 

terminals blended biodiesel into 

petroleum-based diesel fuel in 2010.46

Our evaluation of the changes to the fuel 

distribution infrastructure that would be 

needed to support the use of 920 mill 

gallons/yr of biodiesel in 2012 and 

1,200 mill gallons/yr in 2013 is based on 

the analysis conducted for the RFS2 

final rule.47 See Table IV.B.5–1. 

TABLE IV.B.5–1—ADDITIONAL INFRASTRUCTURE NEEDED TO DISTRIBUTE BIODIESEL IN 2012 AND 2013 

Additional 

distribution 

assets needed 

in 2012 

relative to 

2011 

Additional 

distribution 

assets needed 

in 2013 (with 

1.28 bill gal) 

relative to 

2012 

Total 

distribution 

assets needed 

to support the 

2012 biodiesel 

volume 

Total 

distribution 

assets needed 

to support 

1.28 bill gal 

biodiesel 

volume 

Petroleum Product Terminals with Biodiesel Blending Capability * ................. 74 130 428 558 

Rail Cars .......................................................................................................... 131 230 754 984 

Tank Trucks ..................................................................................................... 14 25 83 108 

Barges .............................................................................................................. 4 7 23 29 

* There are approximately 853 petroleum terminals that offer diesel fuel in the U.S. 

The RFS2 final rule estimated that 

additional manifest rail and barge 

receipt facilities would be needed to 

accept shipments of biofuels of all types 

including biodiesel.48 We concluded 

that manifest rail and barge shipments 

of biodiesel would be able to utilize the 

manifest rail and barge receipt facilities 

that were initially constructed to handle 

increased ethanol volumes. 

We assume that terminals adding 

biodiesel capability would install 

segregated biodiesel storage, in-line 

biodiesel blending equipment, and 

facilities to receive shipments of 

biodiesel by tank truck. In-line blending 

refers to the process of blending 

biodiesel into petroleum-based diesel 

fuel in the delivery line that feeds into 

the tank truck from the terminal storage 

tanks. This process ensures an accurate 

blend ratio and a fully mixed biodiesel/ 

petroleum diesel batch. We also assume 

that all equipment at terminals as well 

as the vessels used to transport biodiesel 

would be heated and insulated to 

prevent gelling during the cold season. 

We anticipate that some terminals may 

splash blend biodiesel before installing 

in-line biodiesel injection equipment. 

Splash blending refers to the process of 

first loading petroleum-based diesel fuel 

into a tank truck followed by biodiesel 

so that the final blend meets the desired 

blend ratio. However, we expect that 

this approach will be temporary due to 

the heightened concerns over achieving 

a correct blend ratio and a fully mixed 

biodiesel blend that accompanies splash 

blending. Some terminals may also 

delay the need to install segregated/ 

heated biodiesel storage by storing 50/ 

50 blends of biodiesel/petroleum-based 

diesel fuel that is subsequently used to 

manufacture B2/B5/B20 blends for 

distribution to end users. These 

practices may provide additional 

flexibility if some terminals wish to 

temporarily defer installing in-line 

blending equipment and segregated 

biodiesel storage equipment. 

The RFS2 FRM analysis concluded 

that industry would have the capability 

to add the necessary facilities to 

distribute biodiesel in a timely fashion 

to meet the envisioned volumes.49

Based on industry input, we continue to 

believe that this is the case. Industry 

activities are currently progressing to 

ramp up biodiesel consumption from 

the approximately 380 mill gallons 

estimated to be used in the U.S. in 2010 

to the 760 mill gallons that is estimated 


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38868 Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 

50Biodiesel Magazine, November 17, 2010. http:// 

www.biodieselmagazine.com/articles/4568/chicagoarea-terminal-soon-to-offer-biodiesel. 

51Report to the Legislature, Annual Report on 

Biodiesel, Minnesota Department of Agriculture, 

January 15, 2011. http://www.mda.state.mn.us/en/ 

news/government/∼/media/Files/news/govrelations/ 

legrpt-biodiesel2011.ashx. 

52Colonial Pipeline began allowing shipment of 

5% renewable diesel fuel blends beginning January 

3, 2011. Colonial pipeline codes and specifications: 

http://www.colpipe.com/pdfs/ 

Sect%203%20Prod%20S

pec%20Jan%201%202011%20update%

20ver%202.pdf. 

53Renewable Fuel Standard Program (RFS2) 

Regulatory Impact Analysis, EPA–420–R–10–006, 

February 2010, Table 1.2–3. 

54This is based on each tank truck carrying 7,800 

gallons of renewable diesel fuel making 6 deliveries 

per day. We anticipate that the renewable diesel 

fuel will be blended directly into storage tanks 

containing petroleum-based diesel fuel. 

55To manufacture a renewable diesel fuel blend 

at a petroleum terminal, renewable diesel fuel may 

be delivered directly into storage tanks that contain 

petroleum-based diesel fuel or injected into a 

petroleum-based diesel fuel stream during delivery 

into a tank truck or pipeline. 

to be used in 2011 to meet the biomassbased diesel volume requirement. For 

example, Kinder Morgan and the 

Renewable Energy Group opened a 

substantial biodiesel distribution facility 

to serve the Chicago area in December 

of 2010.50 Magellan also recently 

announced that it plans to complete its 

biodiesel blending facility in Sioux Falls 

Minnesota in 2011.51 In addition, just as 

there has been considerable biodiesel 

production capacity idled due to lack of 

demand which will be brought back on 

line as biodiesel volumes ramp up, we 

believe that there are also substantial 

idled biodiesel distribution assets that 

could be readily brought back into 

service. 

Renewable diesel/petroleum diesel 

fuel blends can be transported in 

existing petroleum product 

transportation infrastructure from the 

point of production to the end-user.52

The production facility that we expect 

will account for the renewable diesel 

produced through 2013 currently ships 

its product short distances by tank truck 

to facilities that produce blends with 

petroleum-based diesel fuel. To estimate 

the infrastructure impacts of renewable 

diesel, we used the estimate from the 

RFS2 final rule of 80 mill gallons of 

renewable diesel in 2013.53 This volume 

is close to the production volume 

estimated for the Dynamic Fuels facility 

in Geismar, Louisiana that we 

referenced in the final rulemaking 

setting the 2011 RFS standards. 

However, more recently the U.S. 

Department of Energy awarded a $241 

million loan guarantee for the 

construction of a renewable diesel 

facility by Diamond Green. Construction 

on this 137 million gallon per year 

project is scheduled to begin in Norco, 

LA this year and fuel production is 

scheduled for the first quarter of 2013. 

EPA does not expect that the production 

from this facility will have a significant 

impact on overall biomass-based diesel 

distribution infrastructure in the U.S. 

given that the renewable diesel blends 

can be transported in existing petroleum 

product transportation infrastructure. 

For the purposes of this analysis we 

assumed 80 mill gallons of renewable 

diesel for consistency with the RFS2 

final rule and the final rule setting the 

RFS standards for 2011. 

We estimate that a total of 5 tank 

trucks will be needed to transport 80 

mill gallons/yr of renewable diesel to 

the locations where it is blended with 

petroleum-based diesel fuel in 2012 and 

2013.54 For the purposes of this 

analysis, we assumed that 

approximately one half of this volume 

will be produced in 2011. We estimate 

that an additional 2–3 tank trucks 

would be needed to transport renewable 

diesel fuel in 2012/2013 compared to 

2011. Once renewable diesel fuel blends 

are created, further distribution is 

accomplished in the same fashion as 

petroleum-based diesel fuel. In the 

future, the renewable diesel fuel 

production facility identified may be 

connected by a short pipeline directly to 

the Colonial pipeline and/or begin 

shipping by barge/rail. If shipment by 

pipeline develops, then no additional 

transportation vessels would be needed 

to ship renewable diesel fuel compared 

to petroleum-based diesel fuel. We 

anticipate that the infrastructure at 

petroleum terminals necessary to blend 

the 80 mill gallons/yr of renewable 

diesel fuel projected for 2012/2013 with 

petroleum-based diesel fuel will have 

been put in place by 2011.55

Based in the above discussion, we 

believe that sufficient fuel distribution 

infrastructure will be available to 

support the use of 1 bill gal of biomassbased diesel in 2012 and 1.28 bill gal in 

2013. 

C. Impacts of 1.28 Billion Gallons of 

Biomass-Based Diesel 

In order to evaluate the impacts of a 

biomass-based diesel volume of 1.28 bill 

gal in the areas required under the 

statute (see Section IV.A), we first 

considered what the appropriate 

reference would be. Since the statute 

requires that the biomass-based diesel 

volume we set for 2013 be no lower than 

1.0 bill gal, this would appear to be a 

reasonable reference point. Therefore, in 

the discussion that follows, we have 

focused on either a volume of 1.28 bill 

gal biomass-based diesel, or an 

increment of 0.28 bill gal biomass-based 

diesel, depending on the specific 

sources of information and analyses 

available. 

As described in Section IV.B.1 above, 

even if we set the applicable volume for 

biomass-based diesel at 1.0 bill gal, the 

demand for biomass-based diesel in 

2013 is likely to be on the order of 1.28 

bill gal or more due to the limited 

projected availability of other advanced 

biofuels (including cellulosic biofuel, 

imported sugarcane ethanol, and 

others). Since the actual demand for 

biomass-based diesel would likely be 

1.28 bill gal or higher regardless of 

whether we set the biomass-based diesel 

requirement at 1.0 or 1.28 bill gal, the 

net impact of setting the biomass-based 

diesel volume requirement at 1.28 bill 

gallons in 2013 could be seen as zero. 

We recognize that this conclusion is 

based on an applicable advanced biofuel 

volume of 2.75 bill gallons. While we 

will be considering the possibility of 

lowering the 2013 advanced biofuel 

applicable volume below 2.75 bill gal in 

next year’s rulemaking, we have not 

presumed any such reduction in today’s 

NPRM. Such reductions in advanced 

biofuel must occur in the context of 

determining the applicable volume of 

cellulosic biofuel for 2013, and using 

information available at that time 

regarding advanced biofuel volumes 

that are projected to be available in 

2013. 

Nevertheless, the statute requires that 

we analyze specified environmental and 

other impacts in deriving an applicable 

biomass-based diesel volume for 2013 

and other years, and these analyses can 

be conducted for 1.28 bill gal biomassbased diesel (or an increment of 0.28 

bill gal). Most of the areas we are 

required to analyze were covered in the 

RFS2 final rule in some form, and we 

believe that we can use this information 

in satisfying our statutory obligations to 

analyze specified factors in determining 

the applicable volume of biomass-based 

diesel for 2013. 

Some of the analyses presented in the 

RFS2 final rule were for the specific 

case of 1.28 bill gallons in 2013. These 

analyses included an investigation of 

the expected annual rate of commercial 

production of biomass-based diesel in 

2013, impacts on agricultural 

commodity supply and price, and the 

cost to consumers of transportation fuel. 

Some of these were discussed in Section 

IV.B above. Most of the analyses in the 

RFS2 final rule, however, were 

conducted to represent full 

implementation of the RFS2 program in 

2022. In these analyses, the biomassbased diesel volume was estimated to be 

1.82 bill gallons, and was compared to 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 38869 

56 (Add reference to FAPRI description document 

used in RFS2 FRM.) 

a reference case in which biodiesel volume was 380 mill gallons. These 

cases are shown in Table IV.C–1. 

TABLE IV.C–1—PRIMARY REFERENCE AND CONTROL CASES FROM RFS2 FINAL RULEMAKING (BILLION GALLONS) 

Advanced biofuel Non-advanced 

biofuel Total 

renewable fuel 

Cellulosic biofuel Biomass-based diesel Other advanced 

biofuel 

Corn 

ethanol Cellulosic 

ethanol 

Cellulosic 

diesel 

FAMEa

biodiesel NCRD b Other biodiesel c

Imported 

ethanol 

Reference ......................................................... 0.25 0 0.38 0 0 0.64 12.29 13.56 

Control .............................................................. 4.92 6.52 0.85 0.15 0.82 2.24 15.00 30.50 

aFatty acid methyl ester (FAME) biodiesel. 

b Non-Co-processed Renewable Diesel (NCRD). 

cOther Biodiesel is biodiesel produced in addition to the amount needed to meet the biomass-based diesel standard. 

The biomass-based diesel volume of 

1.82 bill gallons analyzed for 2022 in 

the RFS2 final rule is higher than the 

1.28 bill gallons we chose to evaluate for 

today’s NPRM for 2013. More 

importantly, the change in biodiesel 

production due to EISA mandates for 

biomass-based diesel plus other diesel 

anticipated to meet the advanced 

biofuel volume (a total increase of 1.44 

billion gallons compared to the 

reference case without the EISA 

mandates) is much larger than the 

change we are evaluating for 2013 (0.28 

billion gallons). Additionally, many of 

the impacts analyzed for the RFS2 final 

rule reflected the whole biofuel 

mandate, not the relatively smaller 

portion just due to biodiesel. Other 

changes in renewable fuels analyzed for 

2022 were also larger than what would 

likely occur in 2013. Therefore, the 

impacts we would expect in 2013 

compared to a case without RFS2 in 

place would likely be similar to or 

smaller than those we estimated for 

2022. Given these considerations, we 

believe that the impacts assessments in 

the RFS2 final rule can be used to 

determine the directional impacts, and 

therefore the reasonableness, of a 1.28 

billion gallon volume requirement for 

biomass-based diesel in 2013. 

1. Climate Change 

Since biodiesel has a GHG benefit 

exceeding 50% compared to the 

petroleum-based diesel it is replacing, 

an increase in biomass-based diesel of 

0.28 Bill gal from 2012 to 2013 would 

lead to a displacement of conventional 

diesel fuel, with corresponding GHG 

emissions reductions. This increased 

use of biomass-based diesel will 

contribute to lower climate change 

impacts in comparison to the 

petroleum-based diesel it is replacing. 

However, due to the nested nature of 

the RFS2 standards, biomass-based 

diesel is also used to meet the advanced 

biofuel standard. Moreover, both 

biomass-based diesel and advanced 

biofuel must meet a GHG reduction 

threshold of 50%. If the 2013 advanced 

biofuel standard were to remain at the 

2.75 bill gal specified in the statute, an 

increase in the biomass-based diesel 

volume requirement from 1.0 to 1.28 bill 

gal would not change the total volume 

of advanced biofuel, and thus the total 

volume of biofuels that must meet a 

50% reduction in GHGs would remain 

unchanged. Under such circumstances, 

a standard of 1.28 bill gal of biomassbased diesel would have essentially no 

impact on climate change in the context 

of the full mix of biofuels used to meet 

the RFS2 requirements. 

2. Energy Security4 

An analysis of the energy security 

impacts of the increased use of 

renewable fuels was conducted in 

support of the RFS2 rulemaking. Based 

on that analysis, increasing usage of 

renewable fuels including biomassbased diesel helps to reduce U.S. 

petroleum imports. A reduction of U.S. 

petroleum imports reduces both 

financial and strategic risks associated 

with a potential disruption in supply or 

a spike in cost of a particular energy 

source. This reduction in risks is a 

measure of improved U.S. energy 

security. In the RFS2 final rule, we 

described in detail the methodology and 

the Agency’s estimate of the energy 

security impacts of the RFS2 rule. While 

EPA’s analysis of energy security 

benefits of the RFS2 volumes 

considered the full volume of biofuels 

mandated by 2022 (of which biodiesel 

was only a part), the production of 

biodiesel is largely from domestic 

feedstocks. In contrast, the diesel fuel 

displaced is produced from petroleum 

sources which are increasingly from 

foreign sources. Therefore biodiesel 

production and use will contribute to a 

U.S. energy security benefit. 

3. Agricultural Commodities and Food 

Prices 

For the RFS2 rule, we examined the 

impacts of increased renewable fuels 

production on commodity prices, food 

prices and trade in agricultural 

products. This analysis considered the 

impacts of all the biofuel feedstock 

sources anticipated to meet the 2022 

biofuel volume requirements, not just 

biodiesel. For the RFS2, EPA used two 

primary models for its agricultural 

economic impacts analysis, the Food 

and Agriculture Sector Optimization 

Model (FASOM), and the Food and 

Agricultural Policy Research InstituteCenter for Agriculture and Rural 

Development (FAPRI–CARD) models. 

The FASOM model is a long-term 

economic model of the U.S. forest and 

agriculture sectors that maximizes the 

net present value of the sum of producer 

and consumer surplus across the two 

sectors over time subject to market, 

technology, and other constraints. The 

FAPRI–CARD models are a system of 

econometric models covering many 

agricultural commodities in the U.S. 

and internationally. They are based on 

historical data analysis, current 

academic research, and a reliance on 

accepted economic, agronomic, and 

biological relationships in agricultural 

production and markets.56

To meet the RFS2 renewable fuel 

volumes, a number of price effects on 

the agricultural commodities were 

estimated for 2022. For instance, 

FASOM estimates that an increase in 

renewable fuel volumes to meet the 

RFS2 would result in an increase in the 

U.S. soybean prices of $1.02 per bushel 

(10.3 percent) above the Reference Case 

price in 2022. FASOM also projected 

the price of soybean oil would increase 

by $183 per ton (37.9 percent) over the 

2022 Reference Case price (all prices are 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
38870 Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 

57 ‘‘Biodiesel Production Prospects for the Next 

Decade,’’ IHS Global Insight, March 11, 2011. 

58 75 FR 14670, March 26, 2010. 

59U.S. EPA 2010, Renewable Fuel Standard 

Program (RFS2) Regulatory Impact Analysis. EPA– 

420–R–10–006. February 2010. Docket EPA–HQ– 

OAR–2009–0472–11332. Section 3.1.1.2.4 

60 In the RFS2 Regulatory Impact Analysis, we 

analyzed the mandated 2022 RFS2 renewable fuel 

volumes relative to volumes required by two 

reference scenarios: RFS1 mandate (7.1 billion 

gallons of renewable fuels) and AEO 2007 (13.6 

billion gallons of renewable fuels). Both reference 

scenarios assumed the same volume of biodiesel, so 

the emission and air quality impacts described in 

this section are the same for both reference 

scenarios. 

61U.S. EPA 2010, Renewable Fuel Standard 

Program (RFS2) Regulatory Impact Analysis. EPA– 

420–R–10–006. February 2010. Docket EPA–HQ– 

OAR–2009–0472–11332. 

in 2007$). Most of the additional 

soybeans needed for increased biodiesel 

production are diverted from U.S. 

exports to the rest of the world. In 

FASOM, soybean exports decrease by 

135 million bushels (¥13.6 percent) in 

2022 relative to the AEO2007 Reference 

Case. This change represents a decrease 

of $453 million (¥4.6 percent) in the 

total value of U.S. soybean exports in 

2022. However, these price effects are 

not attributed to the demand for 

biodiesel feedstocks alone, rather the 

compounding affect of all changes in 

feedstock demand estimated to result 

from the total biofuel mandate in 2022. 

Since the impact on soybeans due to 

biodiesel demand was only a portion of 

this total feedstock impact and since the 

impact in 2013 will be less than 

considered in 2022 (since the 2013 

biodiesel volumes anticipated are less 

than those for 2022), the impact on 

soybean prices and exports from an 

increase to 1.28 bill gall in 2013 could 

also be less. 

A recent report by IHS Global 

Insight 57 also discusses potential 

agricultural and economic impacts from 

increasing vegetable oil demand for 

biodiesel production. According to this 

study, existing soybean yield 

technologies are expected to be applied 

increasingly across the U.S., resulting in 

roughly a 10% higher growth rate in 

soybean yields than USDA’s projections 

from 2010–2016 which were used by 

EPA in its RFS2 analyses. Similarly, 

Global Insight predicts these higher 

yield technologies to be implemented in 

other large soybean-producing 

countries, such as Brazil and Argentina. 

If higher yields than modeled for RFS2 

indeed are realized, then it is likely the 

price increases for soybean oil will be 

less than estimated for RFS2. Likewise, 

other price impacts, such as those on 

food prices, would still move in the 

same direction (i.e., an increase in price 

resulting from an increase in demand) 

but could be smaller than in the RFS2 

analysis. 

For the analyses performed for the 

RFS2 final rule, EPA estimated a $10 

per person per year increase in food 

costs due to the total annual impact of 

the RFS2 program by 2022 compared to 

a Reference case that assumed no RFS2 

renewable fuel requirements. Again, the 

biodiesel impacts would represent only 

a small portion of these overall impacts 

and would like be even smaller in 2013 

due to the smaller volume of feedstock 

required. 

4. Air Quality 

This section discusses our assessment 

of the impacts of 1.28 bill gal of 

biomass-based diesel on emissions and 

air quality. We are relying on the 

analyses of renewable fuel impacts 

conducted in support of the RFS2 rule 58

to qualitatively discuss the expected 

impacts of this biomass-based diesel 

volume. The RFS2 analyses reflect 

EPA’s most current assumptions 

regarding biodiesel emission impacts.59

In the RFS2 rule, we analyzed both 

changes in pollutant emissions 

(measured in tons) and changes in 

ambient air quality associated with the 

changes in pollutant emissions. The 

changes in pollutant emissions were 

calculated by comparing the 2022 RFS2 

renewable fuel volumes to volumes if 

the RFS2 mandate was not in place (the 

reference scenario).60 The analysis 

reflected full implementation of the 

RFS2 program in 2022 and accounted 

for impacts from multiple types of 

renewable fuels, of which biodiesel was 

only one type. Specifically, the RFS2 

emissions inventory analysis assumed 

1.82 bill gal of biodiesel in the RFS2 

scenario compared to 0.38 bill gal of 

biodiesel in the reference scenario, 

reflecting a 1.44 bill gal increase in 

biodiesel with the rule in place. 

Biodiesel emission impacts from the 

RFS2 rule emissions inventory analysis 

are presented in Table IV.C.4–1. A 

complete discussion of the emissions 

inventory analysis conducted for the 

RFS2 rule can be found in Chapter 3 of 

the RFS2 Regulatory Impact Analysis 

(RIA).61 These biomass-based diesel 

emission impacts, which reflect a 1.44 

bill gal increase in biodiesel, are all less 

than 1% of the total U.S. emissions 

inventory for each pollutant. We expect 

the impacts of the 1.28 bill gal of 

biomass-based diesel, as compared to 

the 1.0 bill gal statutory minimum 

volume, to be smaller. 

TABLE IV.C.4–1—BIODIESEL EMISSION IMPACTS OF THE RFS2 RENEWABLE FUEL VOLUMES (1.82 BILL GAL) RELATIVE TO

THE REFERENCE CASE (0.38 BILL GAL) 

Biodiesel impacts of RFS2 rule emissions inventory analysis (D 1.44 bill gal Biodiesel) Percent RFS2 

total U.S. 

Upstream inventory a

(tons) 

Downstream b

(tons) Total (tons) 

VOC ................................................................................................................. ¥1,049 ¥2,422 ¥3,471 ¥0.03% 

CO .................................................................................................................... 913 ¥4,104 ¥3,191 ¥0.01% 

NOx .................................................................................................................. ¥290 1,346 1,056 0.01% 

PM10 ................................................................................................................ 4,268 ¥569 3,699 0.10% 

PM2.5 ............................................................................................................... 632 ¥315 317 0.01% 

SO2 .................................................................................................................. 1,580 0 1,580 0.02% 

NH3 .................................................................................................................. 4,171 0 4,171 0.10% 

Benzene ........................................................................................................... 10 ¥30 ¥20 ¥0.01% 

Ethanol ............................................................................................................. 0 0 0 0.00%

1,3-Butadiene ................................................................................................... 0 ¥16 ¥17 ¥0.10% 

Acetaldehyde ................................................................................................... 2 ¥66 ¥65 ¥0.14% 

Formaldehyde .................................................................................................. 1 ¥182 ¥181 ¥0.21% 

Naphthalene ..................................................................................................... ¥1 0 ¥1 ¥0.01% 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 38871 

62U.S. EPA 2010, Renewable Fuel Standard 

Program (RFS2) Regulatory Impact Analysis. EPA– 

420–R–10–006. February 2010. Docket EPA–HQ– 

OAR–2009–0472–11332. 

63Emissions serve as inputs to the air quality 

modeling analysis. However, the final fuel volume 

assumptions (upon which the emission estimates 

were based) increased between the time that 

emissions were estimated to support the air quality 

modeling analysis and the time emissions were 

estimated to reflect the final rulemaking. 

64 ‘‘Analysis of Fuel Ethanol Transportation 

Activity and Potential Distribution Constraints’’, 

Oakridge National Laboratory, March 9, 2009. To 

simplify the ORNL analysis, biomass-based diesel 

volumes were assumed to originate at the same 

points of production and to be shipped to the same 

petroleum terminals as the ethanol projected to be 

used to meet the RFS2 standards. This may tend to 

overstate the potential impact on the transportation 

system from the shipment of biomass-based diesel 

fuels since biomass-based diesel production plants 

were projected to be more geographically dispersed 

than ethanol production facilities. In any event, the 

simplifying assumption was assessed to have little 

impact on the results from the analysis given that 

biomass-based diesel represented only 8% of the 

total projected biofuel volumes. 

65See sections 1.6.4 and 1.6.5 of the RFS2 RIA. 

TABLE IV.C.4–1—BIODIESEL EMISSION IMPACTS OF THE RFS2 RENEWABLE FUEL VOLUMES (1.82 BILL GAL) RELATIVE TO

THE REFERENCE CASE (0.38 BILL GAL)—Continued 

Biodiesel impacts of RFS2 rule emissions inventory analysis (D 1.44 bill gal Biodiesel) Percent RFS2 

total U.S. 

Upstream inventory a

(tons) 

Downstream b

(tons) Total (tons) 

Acrolein ............................................................................................................ 63 ¥9 54 0.84% 

a U.S. EPA 2010, Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis. EPA–420–R–10–006. February 2010. Docket EPA– 

HQ–OAR–2009–0472–11332. Table 3.2–11. Note: units in Table 3.2–11 were mislabeled as tons/mmBTU. Actual units are tons. b U.S. EPA 2010, Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis. EPA–420–R–10–006. February 2010. Docket EPA– 

HQ–OAR–2009–0472–11332. Table 3.2–9. 

The air quality analysis for the RFS2 

rule used photochemical modeling to 

characterize primary pollutants that are 

emitted directly into the atmosphere 

and secondary pollutants that are 

formed as a result of complex chemical 

reactions within the atmosphere. 

Included in the air quality modeling 

scenarios for the RFS2 rule were large 

volumes of ethanol as well as other 

renewable fuels, and the nature of these 

complex chemical interactions makes it 

difficult to determine the air quality 

impacts of biodiesel alone. Specifically, 

the RFS2 air quality analysis reflects a 

roughly 21 bill gal increase in ethanol, 

far outweighing the volume increase in 

biodiesel (0.43 bill gal). A complete 

discussion of the RFS2 air quality 

analysis and its limitations can be found 

in Chapter 3 of the RFS2 Regulatory 

Impact Analysis (RIA).62

The RFS2 air quality analysis was 

completed earlier than the final 

emissions inventory analysis because of 

the length of time needed to conduct 

photochemical modeling.63 The air 

quality analysis assumed 0.81 bill gal of 

biodiesel in the RFS2 scenario 

compared to 0.38 bill gal of biodiesel in 

the reference scenario, reflecting a 0.43 

bill gal increase in biodiesel use with 

the rule in place. 

Given the small emissions impact of 

a 0.43 bill gal increase in biodiesel on 

the total U.S. emissions inventory (the 

basis for our air quality modeling 

scenarios), we would expect the portion 

of air quality impacts attributable to a 

move from 1.0 to 1.28 bill gal (a 0.28 bill 

gal biodiesel increase) to be small 

enough that on a nationwide basis the 

air quality impact would likely not be 

noticeable. 

We note that Clean Air Act section 

211(v) requires EPA to analyze and 

mitigate, to the greatest extent 

achievable, adverse air quality impacts 

of the renewable fuels required by the 

RFS2 rule. We intend to address any 

potential adverse impacts from 

increased renewable fuel use through 

that study and will promulgate 

appropriate mitigation measures 

separate from today’s NPRM. 

5. Transportation Fuel Cost 

For the RFS2 final rulemaking, we 

estimated the year-by-year per-gallon 

costs for diesel fuel due to the RFS2 

biofuel requirements. For 2013, we 

based our diesel fuel cost estimate on 

the production and use of biodiesel, 

renewable diesel fuel and some 

cellulosic diesel fuel. The unsubsidized 

cost increase is 0.2 cents per gallon, but 

accounting for the subsidy, we 

estimated a cost savings to consumers 

for diesel fuel of 1.7 cents per gallon. 

This assumes a crude oil price of 81 

dollars per barrel, which is within the 

range of crude oil prices over the last 

several years which have ranged from 

$35 per barrel to $147 per barrel. 

6. Deliverability and Transport Costs of 

Materials, Goods, and Products Other 

Than Renewable Fuel 

EPA evaluated in the RFS2 final rule 

the impacts on the U.S. transportation 

network from the distribution of the 

total additional volume of biofuels that 

would be used to meet the RFS2 

standards. Oakridge National Laboratory 

(ORNL) conducted an analysis of biofuel 

transportation activity from production 

plants to petroleum terminals by rail, 

barge, and tank truck to identify 

potential distribution constraints to help 

support the assessment in the RFS2 

final rule.64 The ORNL analysis 

concluded that the increase in biofuel 

shipments due to the RFS2 standards 

would have a minimal impact on U.S. 

transportation infrastructure. The 

majority of biofuel transportation is 

projected to be accomplished by rail. 

Nevertheless, it was estimated that the 

biofuels transport would constitute only 

0.4% of the total freight tonnage for all 

commodities transported by the rail 

system through 2022.65 Given the small 

increase in freight shipments due to the 

transport of biofuels to meet the RFS2 

standards, we believe that the 

distribution of biofuels will not 

adversely impact the deliverability and 

transport costs of materials, goods, and 

products other than renewable fuels. 

7. Wetlands, Ecosystems, and Wildlife 

Habitats 

As directed by CAA section 

211(o)(2)(B)(ii), in setting the 2013 

biodiesel volume requirements, EPA is 

to consider the impacts of biodiesel 

production and use on wetlands, 

ecosystems and wildlife habitat. 

The most complete and up-to-date 

assessment of these impacts is 

contained in the draft analysis prepared 

by EPA in response to the requirements 

set out in CAA section 204. This report 

has been released in draft form in order 

to allow interested parties to provide 

comments on the analyses and policy 

implications. Concluding this review 

and the peer review, updates will be 

made to the report, and then the final 

report will be published in 2012 on the 

EPA Biofuels Web site. Nevertheless, 

since this draft report includes an 

assessment of the impact of biofuels on 

a number of the areas that we are 

required to analyze in the process of 

determining the 2013 biomass-based 


jlentini on DSK4TPTVN1PROD with PROPOSALS2
38872 Federal Register / Vol. 76, No. 127 / Friday, July 1, 2011 / Proposed Rules 

66U.S. EPA. Biofuels and the Environment: the 

First Triennial Report to Congress (External Review 

Draft). U.S. Environmental Protection Agency, 

Washington, DC, EPA/600/R–10/183A, 2011. 

http://cfpub.epa.gov/ncea/cfm/ 

recordisplay.cfm?deid=217443. 

67U.S. Department of Agriculture, Economic 

Research Service. Fertilizer Use and Price. http:// 

www.ers.usda.gov/Data/FertilizerUse. 

68U. S. Department of Agriculture, National 

Agricultural Statistics Service. 2007. Agricultural 

chemical usage 2006 field crops summary. 

Available at: http://usda.mannlib.cornell.edu/usda/ 

nass/AgriChemUsFC//2000s/2007/AgriChemUsFC627 05–16–2007_revision.pdf. 

diesel volume, we believe it is 

appropriate to make use of this 

information as it represents the most 

current EPA assessments available.66

This draft report relies on information 

available as of July 2010. The report 

does not attempt to quantify the impacts 

of biofuel production and use as these 

impacts are dependent on local or 

regional conditions. Nevertheless the 

draft provides qualitative assessments 

and reasonable expectations of trends 

which can be used to consider the 

environmental impacts of increases in 

biodiesel production and use. These 

trends are only summarized here while 

the draft report provides extensive 

detail. 

The draft assessment focuses on the 

use of oil from soy beans as the 

feedstock for biodiesel production. 

Other oil seed feedstock sources 

represent a very small portion of biofuel 

production in 2013 so would be 

expected to have much less of an impact 

than soy oil. Corn oil extracted during 

the ethanol production process is 

increasing, adds a very small increment 

of process GHG and will offset demands 

for soy and other oil seed crops, thus 

reducing potential agricultural impact of 

biodiesel production and adding to the 

net reduction in GHG emissions. 

Finally, waste fats, oils and greases 

would be expected to have negligible 

environmental impact as a feedstock 

since they do not impact agricultural 

land use and would otherwise be used 

for some lower value purpose or simply 

discarded. 

Wetlands can be adversely affected by 

agricultural production through runoff 

that can result in nutrient loading 

(particularly from fertilizers) or from 

sedimentation (from erosion). Soy 

production tends to use less fertilizer 

than corn production (the most likely 

alternative crop) and can reduce the 

amount of fertilizer required for corn 

when planted in rotation with corn. 

However, compared to other crops, 

erosion can be higher from fields 

planted in row crops such as corn and 

soy beans. While the impacts of nutrient 

loading and erosion tend to be site 

specific, good farming practices 

including the optimum fertilizer use 

and the set aside of sensitive lands via 

the CRP program can significantly help 

control these adverse affects. Wetlands 

can also be adversely affected through 

diversion of surface and ground water 

for agricultural irrigation. Soy bean 

production less frequently relies on 

irrigation than corn and some other 

crops. More discussion on water usage 

is included below in the section on 

water use and water quality impacts. 

Ecosystems and wildlife habitat can 

be adversely affected if CRP lands are 

converted to crop production, if row 

crops such as soy beans replace grassy 

crops and in general if new lands with 

diverse vegetation are converted to crop 

production. As noted in the RFS2 rule, 

we do not expect the RFS program 

production to result in an increase in 

total acres of agricultural land under 

production in the US compared to a 

reference case without the impact of the 

RFS2 volumes. The relatively small 

increase of 0.28 bill gall should not 

appreciably affect the amount of land 

devoted to oil seed production. Further, 

since soy beans are traditionally planted 

in rotation with other crops such as 

corn, this small increase in soy oil 

demand for biodiesel production is 

unlikely to replace grassy crops or result 

in the indirect increase in land under 

crop production. Additionally, the 

USDA commitment to support the CRP 

program should minimize the likelihood 

of any significant change in the amount 

of CRP land. Therefore, while some very 

local changes may result due to an 

individual farmer’s planting decisions, 

since no new crop land are expected in 

the U.S. due to this increase in biodiesel 

production and sensitive lands will be 

protected via programs such as CRP, no 

measureable impact in aggregate 

ecosystems or wildlife habitat is 

expected. 

8. Water Quality and Quantity 

The water quality and quantity 

impacts of biodiesel are primarily 

related to the type of feedstock and the 

production practices used to both 

produce the feedstock and to convert 

the feedstock into biodiesel. Soybeans 

are the principal feedstock used for 

biodiesel production and are predicted 

to account for 600 million gallons of the 

1.28 billion gallons evaluated for 2013. 

Non-food grade corn oil extracted 

during ethanol production, animal fats 

and recycled fats account for most of the 

remaining biodiesel feedstocks. Since 

these fats are the byproduct of another 

use and not produced specifically for 

biodiesel manufacture and since corn 

oil extracted is a by-product of corn 

ethanol production, this analysis will 

focus on soybeans. 

From a water quality perspective, the 

primary pollutants of concern from 

soybean production are fertilizers 

(nitrogen and phosphorus) and 

sediment. There are three major 

pathways for these potential pollutants 

to reach water from agricultural lands: 

runoff from the land’s surface, 

subsurface tile drains, or leaching to 

ground water. Climate, hydrological, 

and management factors influence the 

potential for these contaminants to 

reach water from agricultural lands. 

a. Impacts on Water Quality and Water 

Quantity Associated With Soybean 

Production 

After corn, soybeans are the second 

largest agricultural crop in terms of 

acreage in the U.S. As with the 

production of any agricultural crop, the 

impact on water quality depends on a 

variety of factors including production 

practices, use of conservation practices 

and crop rotations by farmers, and 

acreage and intensity of tile drained 

lands. Additional factors outside 

agricultural producers’ control include 

soil characteristics, climate, and 

proximity to water bodies. 

Soybeans are typically grown in the 

same locations as corn since farmers 

commonly rotate between the two crops. 

In 2005, the latest year for which USDA 

collected data, the U.S. average nitrogen 

fertilization rate for soybeans was 16 

pounds per acre. In contrast, the average 

nitrogen fertilization rate for corn was 

138 pounds per acre.67 Soybeans fix 

nitrogen, so they do not require 

substantial added fertilizer for adequate 

yields. Only 18 percent of soybean acres 

are fertilized with nitrogen compared to 

96 percent of corn acres.68 Since 

significantly less nitrogen fertilizer is 

applied to soybeans, less nitrogen is 

available for runoff or leaching into 

water. Water quality generally benefits 

when soybeans are rotated with corn, 

since the next corn crop requires less 

fertilizer and fewer pesticides. 

Therefore, crop rotation is one practice 

that is part of an effective system to 

limit water quality impacts. However, 

soybeans have less residue remaining on 

the field after harvest compared to corn, 

so sediment runoff could be more of a 

concern. 

Agricultural conservation systems can 

reduce the impact of soybean 

production on the environment. The 

systems components include (1) 

controlled application of nutrients and 

pesticides through proper rate, timing, 

and method of application, (2) 

controlling erosion in the field (i.e., 


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69 Dinnes, DL; Karlen, DL; Jaynes, DB; Kaspar, TC; 

Hatfield, JL; Colvin, TS; Cambardella, CA. 220 2002. 

Nitrogen management strategies to reduce nitrate 

leaching in tile-drained 221 midwestern soils. 

Agronomy Journal 94(1): 153–171. 

70U.S. Department of Agriculture, National 

Resources Conservation Service. 2010. Assessment 

of the effects of conservation practices on cultivated 

cropland in the Upper Mississippi River Basin. 

Available at: http://www.nrcs.usda.gov/technical/ 

NRI/ceap/umrb/index.html. 

71U.S. Department of Agriculture. 2010. 2007 

Census of agriculture, Farm and ranch irrigation 

survey (2008). http://www.agcensus.usda.gov/ 

Publications/2007/Online_Highlights/ 

Farm_and_Ranch_Irrigation_Survey/fris08.pdf. 

72U. S. Department of Energy. 2006. Energy 

demands on water resources: Report to Congress on 

the interdependency of energy and water. Available 

at: http://www.sandia.gov/energy-water/docs/121- 

RptToCongress-EWwEIAcomments-FINAL.pdf. 

73U.S. EPA. 2010b. Renewable fuel standard 

program (RFS2) regulatory impact analysis. EPA– 

420–R–10–006. Available at: http://www.epa.gov/ 

otaq/renewablefuels/420r10006.pdf. 

74U.S. EPA. 2010b. Renewable fuel standard 

program (RFS2) regulatory impact analysis. EPA– 

420–R–10–006. Available at: http://www.epa.gov/ 

otaq/renewablefuels/420r10006.pdf. 

75 Kimble, J. n.d. Biofuels and emerging issues for 

emergency responders. U.S. EPA. Available at: 

http://www.epa.gov/oem/docs/oil/fss/fss09/ 

kimblebiofuels.pdf. 

76 Kahn, N; Warith, MA; Luk, G. 2007. A 

comparison of acute toxicity of biodiesel, biodiesel 

blends, and diesel on aquatic organisms. Journal of 

the Air and Waste Management Association 57(3): 

286–296. 

77Renewable Fuels Standard Program (RFS2), 

Regulatory Impact Analysis (RIA). EPA–420–R–10– 

006. Available at: http://www.epa.gov/otaq/ 

renewablefuels/420r10006.pdf. 

78Renewable Fuels Standard Program (RFS2), 

Regulatory Impact Analysis (RIA), EPA–420–R–10– 

006, February 2010. Available at: http:// 

www.epa.gov/otaq/renewablefuels/420r10006.pdf. 

reduced tillage, terraces, or grassed 

waterways), and (3) trapping losses of 

soil and fertilizer runoff at the edge of 

fields or in fields through practices such 

as cover crops, riparian buffers, 

controlled drainage for tile drains, and 

constructed/restored wetlands.69

The effectiveness of conservation 

practices, however, depends upon their 

adoption. The USDA‘s Conservation 

Effects Assessment Project (CEAP) 

quantified the effects of conservation 

practices used on cultivated cropland in 

the Upper Mississippi River Basin. It 

found that, while erosion control 

practices are commonly used, there is 

considerably less adoption of proper 

nutrient management to mitigate 

nitrogen loss to water bodies.70

However, as noted above, the relatively 

low amount of fertilizer used for soy 

bean production tends to lessen the 

potential for nitrogen loss to water 

bodies 

Water for soybean cultivation 

predominately comes from rainfall, 

although about 11 percent of soybean 

acres in the U.S. are irrigated.71 Water 

use for irrigated soybean production in 

the U.S. varies from 0.2 acre-feet per 

acre in Pennsylvania to about 1.4 acrefeet per acre in Colorado, with a 

national average of 0.8 acre-feet of 

water.72

b. Impacts on Water Quality and Water 

Quantity Associated With Biodiesel 

Production 

Biological oxygen demand (BOD), 

total suspended solids, and glycerin 

pose the major water quality concerns in 

wastewater discharged from biodiesel 

facilities. Actual impacts depend on a 

range of factors, including the type of 

feedstock processed, biorefinery 

technology, effluent controls, and water 

re-use/recycling practices, as well as the 

facility location and source and 

receiving water. 

Despite the existing commercial 

market for glycerin and the likely 

expanded uses for glycerin as discussed 

in the RFS2 final rule, the rapid 

development of the biodiesel industry 

has caused a temporary glut of glycerin 

production, resulting in some instances 

of facilities disposing glycerin. Glycerin 

disposal may be regulated under several 

EPA programs, depending on the 

practice. However, there have been 

incidences of glycerin dumping, 

including an incident in Missouri that 

resulted in a large fish kill.73 Some 

biodiesel facilities discharge their 

wastewater to municipal wastewater 

treatment systems for treatment and 

discharge. There have been several cases 

of municipal wastewater treatment plant 

upsets due to high BOD loadings from 

releases of glycerin.74 To mitigate 

wastewater issues, some production 

systems reclaim glycerin from the 

wastewater. Closed-loop systems in 

which water and solvents can be 

recycled and reused can reduce the 

quantity of water that must be 

pretreated before discharge. 

Biodiesel can also impact water 

bodies as a result of spills. However, 

biodiesel degrades approximately four 

times faster than petroleum diesel 

including in aquatic environments.75

Results of aquatic toxicity testing of 

biodiesel indicate that it is less toxic 

than regular diesel.76 Biodiesel does 

have a high oxygen demand in aquatic 

environments, and can cause fish kills 

as a result of oxygen depletion. Water 

quality impacts associated with spills at 

biodiesel facilities generally result from 

discharge of glycerin, rather than 

biodiesel itself. 

Biodiesel facilities use much less 

water than ethanol facilities to produce 

biofuel. The primary consumptive water 

use at biodiesel plants is associated with 

washing and evaporative processes. 

Water use is variable, but is usually less 

than one gallon of water for each gallon 

of biodiesel produced; some facilities 

recycle wash water, which reduces 

overall water consumption.77

9. Job Creation and Rural Economic 

Development 

The RFS2 is anticipated to increase 

employment and spur income 

expansion in rural areas and farming 

communities. Income expansion in rural 

areas from renewable fuel production 

will contribute to rural economic 

development. As mentioned above, 

industry activities are currently 

progressing to ramp up biodiesel 

consumption from the approximately 

380 mill gallons estimated to be used in 

the U.S. in 2010 to the 800 mill gallons 

that is estimated to be used in 2011 to 

meet the RFS2 biomass-based diesel 

volume requirement. In addition, it is 

anticipated that biodiesel production 

capacity idled due to lack of demand 

will be brought back on line as biodiesel 

volumes ramp up. Also, expansions to 

the fuel distribution infrastructure (i.e., 

more fuel terminals, rail cars, tank 

trucks, barges etc.) will be needed to 

support the use of 1 bill gal/yr of 

biodiesel in 2012 and 1.28 bill gal/yr in 

2013 based on the analysis conducted 

for the RFS2 final rule.78 Bringing 

online idle biodiesel plants and 

expanding biodiesel distribution 

infrastructure in the U.S. will increase 

both employment and promote rural 

economic development. These increases 

in employment are similar to what EPA 

anticipated when it analyzed the RFS2 

rule. 

D. Proposed 2013 Volume for BiomassBased Diesel 

We are proposing an applicable 

volume of 1.28 bill gal biomass-based 

diesel for 2013, consistent with our 

projection for 2103 in the RFS2 final 

rule. The 0.28 bill gal increment over 

the 2012 applicable volume that is 

reflected in this proposal does not 

deviate substantially from the trend in 

annual increments that Congress 

established in specifying applicable 

volumes for biomass-based diesel for 

2009 through 2012. As noted in Section 

IV.B, because we are not proposing to 

change the 2013 advanced biofuel 

applicable volume in this rulemaking, 

we have used the 2.75 bill gallon 

applicable volume for the analyses in 

today’s proposal. Given an advanced 

biofuel applicable volume of 2.75 bill 

gallons for 2013, the proposed 1.28 bill 

gal biomass-based diesel volume 

requirement is not expected to force any 

additional biomass-based diesel 


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79 ‘‘Biodiesel Production Prospects for the Next 

Decade,’’ IHS Global Insight, March 11, 2011. 

volumes into the market in 2013. As a 

result, the increase in biomass-based 

diesel from the statutory minimum of 

1.0 bill gal to 1.28 bill gal could be seen 

as not having any impact beyond what 

is anticipated to result from meeting the 

current 2.75 bill gal advanced biofuel 

applicable volume. 

However, compared to a reference 

case without the RFS2 mandates, 1.28 

bill gal of biomass-based diesel will lead 

to displacement of fossil-based fuel, 

which will result in reduced GHG 

emissions from the transportation sector 

and increased energy security. There are 

likely to be some negative consequences 

associated with increased air and water 

pollution, increased food prices, 

impacts to wetlands, etc., as discussed 

above. However, EPA does not believe 

that these impacts outweigh the benefits 

of moving to an applicable volume of 

1.28 bill gal for 2013. By requiring 

somewhat more biomass based diesel 

use in 2013 than the statutory 

minimum, we are also making it more 

likely that we will not need to modify 

the advanced biofuel mandate in 2013 

and, therefore, that the Congressional 

goal for advanced biofuel use in 2013 

can either be satisfied, or at least come 

closer to satisfaction. EPA solicits 

comment on all issues related to this 

proposal. 

E. 2014 and Beyond 

EPA is directed under CAA 211(o)(2) 

to determine the required biomass-based 

diesel volumes no less than 14 months 

ahead of the first year that they would 

be applicable, and thus we could 

propose biomass-based diesel volumes 

for 2014 and beyond in today’s NPRM. 

Doing so would provide certainty for the 

industry and stability for future 

investments and contracts. However, we 

are not proposing biomass-based diesel 

standards for 2014 and beyond in 

today’s NPRM since we believe we will 

be in a better position in the future to 

evaluate all of the factors related to 

establishing an applicable volume for 

2014 and later years. 

We are aware of two sources that 

provide projections of biomass-based 

diesel for years after 2013: the RFS2 

final rulemaking, and a recent report 

released by the IHS Global Insight.79

The projections from both of these 

sources are shown in Table IV.E–1 

TABLE IV.E–1—PROJECTIONS OF BIOMASS-BASED DIESEL AFTER 2012 

(BILL GALLONS) 

RFS2 final 

rule 

IHS global 

insight 

report 

2013 .................. 1.28 1.34 

2014 .................. 1.39 1.50 

2015 .................. 1.53 1.81 

2016 .................. 1.56 2.18 

2017 .................. 1.60 2.53 

2018 .................. 1.64 2.74 

2019 .................. 1.68 3.00 

2020 .................. 1.72 3.14 

2021 .................. 1.77 3.23 

2022 .................. 1.82 3.30 

We will consider these and other 

sources when we determine the 

required biomass-based diesel volumes 

for 2014 and beyond, whether in this or 

a future rulemaking. 

V. Proposed Changes to RFS2 

Regulations 

As the RFS2 program got underway in 

the second half of 2010, we discovered 

that a number of regulatory provisions 

were causing confusion among 

regulated parties. In some cases the 

confusion was due to a lack of 

specificity in terms, while in others it 

was due to unique circumstances that 

were not sufficiently addressed in the 

RFS2 regulations. A few amendments 

are being proposed in order to correct 

regulatory language that inadvertently 

misrepresented our intent as reflected in 

the preamble to the final RFS2 

regulations. Finally, as we have worked 

with regulated parties to ensure that the 

RFS program is operating as intended, 

we identified areas in the regulations 

that could benefit from clarification 

and/or streamlining. We also identified 

one provision in the gasoline benzene 

regulations that misrepresented our 

intent as stated in the preamble. As a 

result, we are proposing a number of 

amendments to the RFS regulations, and 

one amendment to the gasoline benzene 

regulations, in 40 CFR part 80. 

A. Summary of Amendments 

Below is a table listing the provisions 

that we are proposing to amend in 

today’s action. We have provided 

additional explanation for several of 

these amendments in Sections V.B 

through V.F below. 

TABLE V.A–1—SUMMARY OF TECHNICAL AMENDMENTS

Section Description 

80.1275(d)(3) ...................................................... Removed to allow for the inclusion of transferred blendstocks in the calculation of benzene 

early credits. 

80.1401 ............................................................... Amended definition of ‘‘annual cover crop’’ to clarify that the crop has no existing market to 

which it can be sold except for its use as feedstock for the production of renewable fuel. 

80.1401 ............................................................... Amended definition of ‘‘naphtha’’ to clarify that it applies to hydrocarbons only, must be commonly or commercially known as naphtha, and is used for producing gasoline. 

80.1405(a), (b), and (d) ...................................... Amended to state the standards for 2012 and the date of the annual standards calculation. 

80.1405(c) ........................................................... Amended terms ‘‘GEi’’ and ‘‘DEi’’ to reference the amount of gasoline and/or diesel produced 

by small refineries and small refiners that are exempt pursuant to §§ 80.1441 and 80.1442. 

80.1415(c)(2) ...................................................... Amended to state the specific requirements needed for technical justifications for applications 

for Equivalence Values. 

80.1426, Table 1 ................................................. Amended to add ID letters to pathways to facilitate references to specific pathways and to 

change the reference to ‘‘canola’’ to ‘‘canola/rapeseed’’. 

80.1426(f)(1) ....................................................... Corrected typographical error in cross reference to paragraph (f)(6) of § 80.1426. 

80.1426(f)(5)(ii) ................................................... Amended requirements so that the separated yard waste plans and separated food waste 

plans need not be approved by EPA, but instead only need to be accepted by EPA under 

the registration provisions. 

80.1429(b)(2) ...................................................... Amended to clarify that ‘‘fossil-based’’ diesel fuel is different from renewable diesel fuel. 

80.1429(b)(9) ...................................................... Amended to include RIN separation limitations on parties whose non-export RVOs are solely 

related to imports of gasoline and diesel or the use of blendstocks to produce gasoline or 

diesel. 

80.1449(a) ........................................................... Amended Production Outlook Report due date; added allowance for unregistered renewable 

fuel producers and importers to submit Production Outlook Reports. 


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TABLE V.A–1—SUMMARY OF TECHNICAL AMENDMENTS—Continued 

Section Description 

80.1450(b)(1)(vi) ................................................. Amended to require submission of additional evidence as part of registration to verify eligibility 

for exemptions in § 80.1403(c) or (d). 

80.1450(d)(1)–(d)(3) ........................................... Amended to add more specificity on when updates, addenda, or resubmittals are required for 

engineering reviews and to include references to foreign ethanol producers. 

80.1451(a)(1)(xi) ................................................. Amended to clarify that this section references RFS1 RINs retired for compliance. 

80.1452(b)(2) ...................................................... Corrected typographical error. 

80.1452(b)(4) ...................................................... Amended to clarify that a RIN-generating importer must submit to EMTS the EPA facility registration number of the facility at which the renewable fuel producer or foreign ethanol producer produced the batch. 

§ 80.1452(b)(5) .................................................... Amended to clarify that for imports of renewable fuel, the RIN-generator must submit to EMTS 

the EPA facility registration number of the importer that imported the batch. 

80.1460(b)(6) ...................................................... Added to clarify that RINs cannot be generated more than once for a single batch of renewable fuel. 

80.1464(a)(2)(iii), (a)(2)(iv), (b)(2)(iii), (b)(2)(iv), 

(c)(1)(iii), and (c)(1)(iv).

Added to clarify that auditors must verify that product transfer documents for RIN transactions 

contain the required information for obligated parties/exporters and for renewable fuel producers/importers. 

80.1464(a)(2)(i), (a)(3)(ii), (b)(2)(i), (b)(3)(ii) ....... Amended to clarify that auditors must validate RIN separations for obligated parties/exporters 

and for renewable fuel producers/importers; amended to correct typographical error. 

80.1465(h)(2); 80.1466(h)(2); and 

80.1467(e)(1), (e)(2), and (g)(2).

Amended to remove the option of using an alternative commitment in lieu of paying a bond 

and to clarify the amount of bond a foreign entity must post. 

B. Technical Justification for 

Equivalence Value Application 

A producer or importer of renewable 

fuels is required to submit an 

equivalence value (EV) application in 

accordance with § 80.1415(c) for any 

renewable fuel that does not have an EV 

listed in § 80.1415(b). In addition, a 

producer or importer could apply for an 

alternative EV if the producer or 

importer has reason to believe that a 

different EV than that listed in 

§ 80.1415(b) is warranted. Section 

80.1415(c) provides the calculation 

equation for the EV of the renewable 

fuel and the requirements for the 

technical justification to be submitted in 

the EV application. 

We have received many inquiries 

from producers and importers of 

renewable fuels requesting clarification 

of the specific requirements for the 

technical justification listed in 

§ 80.1415(c). In addition, based on the 

many EV applications we have 

evaluated, we have found that we 

needed to request additional 

information from producers and 

importers to better understand the 

composition of the renewable fuel they 

produced, such as intermediate steps 

and energy inputs in production 

process, sources of renewable and nonrenewable feedstock, and so forth, to 

better evaluate and assign the correct EV 

to the producer or importer’s renewable 

fuel. 

Therefore, we are proposing to amend 

§ 80.1415(c)(2) to provide clarification 

to the current requirements and to 

include additional requirements for the 

technical justification to be submitted in 

the EV application. The proposed 

amendments to § 80.1415(c)(2) include: 

—A calculation for the requested 

equivalence value according to the 

equation in § 80.1415(c)(1), including 

supporting documentation for the 

energy content (EC) of the renewable 

fuel such as a certificate of analysis 

from a laboratory that verifies the 

lower heating value in Btu per gallon 

of the renewable fuel produced. 

—For each feedstock, component or 

additive used to make the renewable 

fuel, provide a description, the 

percent input and identify whether or 

not it is renewable biomass or is 

derived from renewable biomass. 

—For each feedstock that could 

independently qualify as a renewable 

fuel, state whether or not RINs have 

been previously generated for the 

feedstock. 

—A description of renewable fuel and 

the production process, including a 

block diagram that shows quantities 

of all inputs and outputs required at 

each step of the production process 

for the production of one batch of 

renewable fuel. 

C. Changes to Definitions of Terms 

1. Definition of Annual Cover Crop 

As explained in the preamble of the 

RFS2 final rulemaking, EPA extended 

modeling for cellulosic biofuel made 

from corn stover and biodiesel/ 

renewable diesel made from waste oils/ 

fats/greases to annual cover crops, based 

on the expectation that cultivation of 

annual cover crops, as defined in 

§ 80.1401, will have little impact on the 

agricultural commodity markets and 

therefore little or no land use impact 

associated with them. Therefore, certain 

fuels (as specified in Table 1 to 

§ 80.1426) derived from annual cover 

crop feedstocks qualify for D-codes 

under the advanced biofuel, biomassbased diesel, and cellulosic renewable 

fuel categories. 

Section 80.1401 of the final RFS2 rule 

defines ‘‘annual cover crop.’’ We are 

proposing to amend the definition of 

annual cover crop in order to more 

clearly define those feedstocks that meet 

the intent of including cover crops in 

several pathways in Table 1 to 

§ 80.1426. 

In order to extend our modeling to 

cover crops, we used the rationale that 

annual cover crops would have no land 

use impact since they are planted on 

land otherwise used for crop 

production. Greenhouse gas emissions 

would only be associated with growing, 

harvesting and transporting the cover 

crop, and then processing into biofuel. 

(See 75 FR 14794 col. 3.) Thus, we 

assumed that no additional land would 

be required to plant annual cover crops, 

that cover crops would not displace 

primary crop production, and that the 

use of the cover crop as a feedstock for 

renewable fuels would not have 

secondary impacts on other agricultural 

commodity markets. This implies that 

annual cover crops would not be 

planted and harvested for the purpose of 

being sold to existing markets. If a cover 

crop already had an existing market, 

then the increased use of cover crops as 

feedstocks for renewable fuel 

production could potentially impact the 

existing markets. Therefore, we propose 

to amend the current definition for 

‘‘annual cover crop’’ to clarify that for 

purposes of the RFS program the term 

only includes crops that have no 

existing market to which they can be 

sold except for the use of the feedstock 


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for renewable fuel. This will ensure that 

no unintended land use or significant 

indirect effects result from the use of 

annual cover crops as feedstocks for 

renewable fuel production. 

EPA recognizes that there may be 

additional fuel pathways requiring 

lifecycle greenhouse gas (GHG) 

assessments and the assignment of 

appropriate RIN D–Codes, including 

those using feedstocks that do not meet 

the proposed amended definition of 

annual cover crop. For further guidance 

on the process for requesting EPA 

evaluation of new fuel pathways, please 

refer to the following sites: 

http://www.epa.gov/otaq/fuels/ 

renewablefuels/compliancehelp/rfs2- 

lca-pathways.htm. 

http://www.epa.gov/otaq/fuels/ 

renewablefuels/compliancehelp/lcapetition-instructions.htm#1. 

2. Definition of ‘‘Naphtha’’ 

In the RFS2 final rule, we included 

several RIN-generating pathways in 

Table 1 for naphtha made from 

renewable biomass. We also provided a 

definition of naphtha in § 80.1401. 

However, the definition we finalized 

was overly broad and did not 

adequately represent our intent to limit 

naphtha to gasoline blendstocks. As a 

result, some biofuel producers have 

expressed interest in interpreting the 

term ‘‘naphtha’’ to include materials 

that, while falling within the boiling 

range of gasoline, are not used as a 

blendstock to produce gasoline. 

To remedy this situation, we are 

proposing to revise the definition of 

naphtha to also specify that it applies 

only to blendstocks which are 

composed of only hydrocarbons, are 

commonly or commercially known as 

naphtha, and are used to produce 

gasoline. 

D. Technical Amendments Related to 

RIN Generation and Separation 

1. RIN Separation Limit for Obligated 

Parties 

We propose to amend section 80.1429 

to limit the amount of RINs a company 

who is an obligated party solely by 

virtue of importation of obligated fuel 

can separate to their Renewable Volume 

Obligation (RVO). This change would 

address the instance where a party may 

import a small amount of obligated 

volumes and then separate all the RINs 

that it owns. This change is designed to 

prevent abuse of the obligated party RIN 

separation provision by a company that 

imports a relatively small amount of an 

obligated volume, but then separates a 

large amount of RINs. The proposed 

provision is also designed to help 

prevent the hoarding of RINs by parties 

that do not need them for compliance 

purposes, and to generally increase 

liquidity of RINs.. EPA structured the 

original RFS1 separation regulations 

around facilitating compliance by 

obligated parties meeting their RVOs. 

The proposed change keeps with the 

original design and also ensures that 

importers can separate enough RINs to 

meet their obligations. 

2. RIN Retirement Provision for Error 

Correction 

In some instances, renewable fuel 

producers or importers may improperly 

generate RINs in EMTS as a result of 

calculation errors, meter malfunctions 

or clerical errors. Pursuant to 

§ 80.1431(a), improperly generated RINs 

are invalid, and cannot be used to 

achieve compliance with any 

Renewable Volume Obligations (RVOs). 

The regulations also prohibit any party 

from creating or transferring invalid 

RINs. These invalid RIN provisions 

apply regardless of the good faith belief 

of a party that the RINs are valid. 

Because of the ‘‘buyer beware’’ aspect of 

the RIN program, RIN generators should 

take all appropriate actions to ensure 

that they are properly generating RINs, 

and all parties in the RIN distribution 

system should take all appropriate 

actions to ensure that they are not 

trading invalid RINs or using invalid 

RINs for compliance purposes. 

The ‘‘buyer beware’’ aspect of the RIN 

program provides an important 

incentive for the regulated community 

to comply with the regulations. 

Although EPA believes that these selfpolicing mechanisms are a critical 

component of the RFS2 regulations, we 

seek comment on the possibility of 

amending § 80.1431 to provide the 

regulated community with limited 

flexibility to allow certain RINs that 

were improperly generated to 

nevertheless be transferred and used for 

compliance. We envision that this type 

of flexibility could reduce disruptions to 

the RIN market while, if appropriately 

limited, continuing to apply appropriate 

pressure on parties that generate, 

transfer and use RINs to comply with 

the regulations. Parties that improperly 

generate RINs would remain liable for 

generating invalid RINs. 

We believe that the following general 

limitations should apply to any 

flexibility to allow improperly generated 

RINs to be transferred and used for 

compliance: (1) The RINs must have 

been improperly generated as a result of 

an inadvertent error, (2) the improperly 

generated RINs must have the correct D 

code, (3) the RIN generator must correct 

the information submitted to EMTS and 

retire an equivalent number and type of 

any excess RINs that were generated as 

a result of the error within fixed time 

period, (4) the flexibility to allow 

improperly generated RINs to be used 

for compliance would only apply if the 

number of excess RINs generated for a 

particular batch exceeds the number of 

RINs that should have been generated 

by some fixed percentage, and (5) the 

flexibility to allow improperly generated 

RINs to be used for compliance could 

not be repeatedly used by a renewable 

fuel producer. 

We are seeking comment on whether 

EPA should amend the regulations to 

include this flexibility, whether the 

conditions set forth above are 

appropriate, and whether there are 

additional or alternative conditions that 

should be imposed if the flexibility is 

granted. We seek comment on 

specifying a 60-day time period for a 

RIN-generator to correct RIN 

information submitted to EMTS and 

limiting the availability of this 

flexibility to situations where the 

number of excess RINs generated for a 

particular batch exceeds the number of 

RINs that should have been generated 

by no more than 2%. In addition, we 

seek comment on the possibility of 

establishing a limit on the number of 

times this flexibility could be used 

within a compliance period by a given 

RIN generator. Such a limitation could 

encourage RIN generators to take 

appropriate measures to avoid 

generating invalid RINs, and limit the 

possibility that RIN generators would 

intentionally generate invalid RINs to 

take advantage of short term RIN price 

spikes. EPA seeks comment on all 

aspects of this proposal 

3. Production Outlook Reports 

Submission Deadline 

In the final RFS2 regulations, in 

§ 80.1449(a), EPA set the annual 

deadline for submitting Production 

Outlook Reports as March 31 of each 

year. However, EPA has determined 

that, in order for the information 

contained in the Production Outlook 

Reports to be most useful when setting 

the RFS2 volume requirements and 

associated percentage standards for the 

following calendar year, the reports 

should contain the most accurate 

projections possible. Since the accuracy 

of projections tends to increase the 

closer those projections are made to the 

following calendar year, we believe that 

the March 31 deadline should be moved 

to June 1. This revised deadline would 

still allow the information contained in 

the Production Outlook Reports to be 

used in the development of the final 


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rulemaking setting the standards for the 

following year. 

4. Attest Procedures 

In the final RFS2 regulations, EPA 

required in § 80.1464(c)(1)(i) and 

(c)(2)(ii) that RIN owners conduct attest 

procedures for RIN transaction and RIN 

activity reports that involve RIN 

separations. This requirement was 

intended to be included in the attest 

procedures for obligated parties and 

exporters as well as for renewable fuel 

producers and RIN-generating 

importers, in order to confirm that RINs 

are being properly separated by all 

parties participating in the RIN market. 

Thus, today’s rule proposes 

amendments to § 80.1464(a)(2)(i) and 

(a)(3)(ii) for obligated parties and 

exporters as well as to § 80.1464(b)(2)(i) 

and (3)(ii) for renewable fuel producers 

and RIN-generating importers to include 

attest procedures concerning 

verification of RIN separation. 

Additionally, in the final RFS2 

regulations, EPA required in § 80.1464 

that auditors of RIN generation reports 

verify that product transfer documents 

(PTDs) include the required 

information. EPA believes it would be 

beneficial for auditors to verify the 

required information is present on PTDs 

for RIN transactions for all parties, 

including obligated parties, renewable 

fuel producers and importers and RIN 

owners. Thus, today’s rule proposes 

amendments to § 80.1464(a)(2), (b)(2) 

and (c)(1) to require auditors to verify 

that the PTDs for a representative 

sample of RINs sold and purchased 

contains the information required in 

§ 80.1453. 

5. Treatment of Canola and Rapeseed 

On September 28, 2010, EPA 

published a ‘‘Supplemental 

Determination for Renewable Fuels 

Produced Under the Final RFS2 

Program from Canola Oil’’ (FR Vol. 75, 

No. 187, pg 59622–59634). We are 

proposing to clarify two aspects of the 

supplemental determination. First we 

propose to amend the regulatory 

language in Table 1 to 40 CFR 80.1426 

to clarify that the currently-approved 

pathway for canola also applies more 

generally to rapeseed. While ‘‘canola’’ 

was specifically described as the 

feedstock evaluated in the supplemental 

determination, we had not intended the 

supplemental determination to cover 

just those varieties or sources of 

rapeseed that are identified as canola, 

but to all rapeseed. We currently 

interpret the reference to ‘‘canola’’ in 

Table 1 to 40 CFR 1426 to include any 

rapeseed. To eliminate ambiguity 

caused by the current language, 

however, we propose to replace the term 

‘‘canola’’ in that table with the term 

‘‘canola/rapeseed’’. Canola is a type of 

rapeseed. While the term ‘‘canola’’ is 

often used in the American continent 

and in Australia, the term ‘‘rapeseed’’ is 

often used in Europe and other 

countries to describe the same crop. We 

believe that this change will enhance 

the clarity of the regulations regarding 

the feedstocks that qualify under the 

approved canola biodiesel pathway. 

Second, we wish to clarify that 

although the GHG emissions of 

producing fuels from canola feedstock 

grown in the U.S. and Canada was 

specifically modeled as the most likely 

source of canola (or rapeseed) oil used 

for biodiesel produced for sale and use 

in the U.S., we also intended that the 

approved pathway cover canola/ 

rapeseed oil from other countries, and 

we interpret our regulations in that 

manner. We expect the vast majority of 

biodiesel used in the U.S. and produced 

from canola/rapeseed oil will come from 

U.S. and Canadian crops. Incidental 

amounts from crops produced in other 

nations will not impact our average 

GHG emissions for two reasons. First, 

our analyses considered world-wide 

impacts and thus considered canola/ 

rapeseed crop production in other 

countries. Second, other countries most 

likely to be exporting canola/rapeseed 

or biodiesel product from canola/ 

rapeseed are likely to be major 

producers which typically use similar 

cultivars and farming techniques. 

Therefore, GHG emissions from 

producing biodiesel with canola/ 

rapeseed grown in other countries 

should be very similar to the GHG 

emissions we modeled for Canadian and 

U.S. canola, though they could be 

slightly (and insignificantly) higher or 

lower. At any rate, even if there were 

unexpected larger differences, EPA 

believes the small amounts of feedstock 

or fuel potentially coming from other 

countries will not impact our threshold 

analysis. Therefore, EPA interprets the 

approved canola pathway as covering 

canola/rapeseed regardless of country 

origin. 

E. Technical Amendments Related to 

Registration 

1. Construction Discontinuance & 

Completion Documentation 

The registration requirements in 

§ 80.1450(b)(1)(vi) state that for facilities 

claiming the exemption described in 

§ 80.1403(c) or (d), evidence must be 

submitted demonstrating the date that 

construction commenced. However, the 

registration requirements do not 

explicitly require the submission of 

evidence demonstrating that they meet 

certain of the other requirements 

described in § 80.1403(c)(1) and (2) or 

(d)(1), (2) and (3). 

In order to verify that facilities which 

claim to qualify for an exemption under 

§ 80.1403(c) or (d) in fact meet all of the 

qualification requirements for such an 

exemption, we are proposing to amend 

§ 80.1450(b)(1)(vi) to include 

requirements that the owner or operator 

of facilities claiming exemption under 

§ 80.1403(c) submit evidence 

demonstrating that construction was not 

discontinued for a period of 18 months 

after construction began, and that 

construction was completed by 

December 19, 2010. Similarly, we are 

proposing that for facilities claiming the 

exemption under § 80.1403(d), evidence 

be submitted demonstrating that 

construction was not discontinued for a 

period of 18 months after construction 

began and that construction was 

completed within 36 months of the date 

that construction commenced. 

In addition, we are proposing to add 

a general provision in 

(§ 80.1450(b)(1)(vi)(D) requiring the 

submission of additional documentation 

and information as requested by the 

Administrator. This authority would be 

used in the event that documents 

submitted in accordance with 

requirements § 80.1450(b)(1)(vi)(A) and 

(B) are not sufficient for EPA to verify 

that the facility has met all requirements 

described in § 80.1403(c) or (d). 

2. Third-Party Engineering Reviews 

The regulations stipulate that 

producers of renewable fuels and 

foreign ethanol producers are required 

to update their registration information, 

and submit an updated independent 

third-party engineering review, every 3 

years after their initial registration in 

accordance with § 80.1450(d)(3). We 

have received many inquiries regarding 

the start date that EPA uses to determine 

the 3 year period after which the 

producer must submit an updated 

independent third party engineering 

review (such as the registration 

acceptance date, the third-party 

professional engineer’s signature date 

on the engineering review report, or 

when the engineering review is due for 

grandfathered and non-grandfathered 

facilities). 

Given the lack of clarity in the current 

regulations, we are proposing 

amendments to specify the time frame 

for submission of updated independent 

third-party engineering reviews. We are 

proposing, a simplified method that 

would group producers according to the 

calendar year they were or will be 

registered, and setting a fixed time 


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frame for registration updates for each 

group. Therefore, we are proposing to 

amend § 80.1450(d)(3), to stipulate that 

for all producers of renewable fuel and 

foreign ethanol producers in which their 

registration was accepted by EPA in 

calendar year 2010, that the updated 

registration information and 

independent third-party engineering 

review shall be submitted to EPA within 

the three months prior to January 1, 

2014, and within three months prior to 

January 1 of every third calendar year 

thereafter. For all producers of 

renewable fuel and foreign ethanol 

producers registered in any calendar 

year after 2010, the updated registration 

information and independent thirdparty engineering review shall be 

submitted to EPA within three months 

prior to January 1 of every third 

calendar year after the first year the 

producer’s registration was accepted by 

EPA. For example, a producer registered 

in 2011 would be required to submit an 

updated independent third-party 

engineering review by January 1, 2015, 

and by January 1 every three calendar 

years thereafter. 

3. Foreign Ethanol Producers 

We are proposing that the 

amendments to the registration 

requirements in § 80.1450 also apply to 

foreign ethanol producers. As defined in 

§ 80.1401, foreign ethanol producers are 

foreign producers that produce ethanol 

for use in transportation fuel, heating oil 

or jet fuel but who do not add 

denaturant to their product. Therefore, 

foreign ethanol producers do not 

technically produce ‘‘renewable fuel’’ as 

defined in our regulations. As discussed 

in the preamble to the Direct Final Rule 

published on May 1, 2010 (see 75 FR 

26032), the result of the amendments 

made in the Direct Final Rule is to 

require foreign ethanol facilities that 

produce ethanol that ultimately 

becomes part of a renewable fuel for 

which RINs are generated to provide 

EPA the same registration information 

as foreign renewable fuel facilities that 

export their product to the United 

States. In both cases the required 

registration information is important for 

enforcement purposes, including 

verifying the use of renewable biomass 

as feedstock and the assignment of 

appropriate D codes. Therefore, we 

believe amendments to the registration 

requirements that we make in this 

proposed rule should also be applicable 

to foreign ethanol producers for same 

reasons. 

F. Additional Amendments and 

Clarifications 

1. Third-Party Engineering Review 

Addendum 

We have received many inquires as to 

whether an addendum to the existing 

independent third-party engineering 

review is sufficient to meet the 

requirement that all producers of 

renewable fuel and foreign ethanol 

producers submit an updated 

independent third-party engineering 

review if they make changes to their 

facility that will qualify the renewable 

fuel that is produced for a renewable 

fuel category or D code that is not 

already reflected in the producer’s 

registration information. In some 

circumstances the majority of the 

information verified in the existing 

independent third-party engineering 

review would remain the same, and 

duplicating the entire effort does not 

appear necessary. We believe the 

concept of allowing the submission of 

an addendum in lieu of a updated 

independent third-party engineering 

review is reasonable and therefore we 

are proposing to amend the 

requirements in § 80.1450(d)(1) to state 

that a producer of renewable fuel or 

foreign ethanol producer may submit an 

addendum to the existing independent 

third-party engineering review on file 

with EPA provided the addendum 

meets all the requirements in 

§ 80.1450(b)(2) and verifies for EPA the 

most up-to-date information at the 

producer’s existing facility. The updated 

independent third-party engineering 

review or addendum shall be submitted 

at least 60 days prior to producing the 

new type of renewable fuel and must 

meet all the same requirements 

stipulated in § 80.1450(b)(2) for the 

independent third-party engineering 

review, including a new site visit 

conducted by the third-party to verify 

any changes to the facility that allows it 

to produce a different renewable fuel 

that is not currently reflected in their 

registration on file with EPA. 

2. RIN Generation for Fuel Imported 

From a Registered Foreign Producer 

In RFS2, EPA finalized provisions 

allowing importers to generate RINs for 

renewable fuel imported from a foreign 

producer only under certain 

circumstances. The importer may only 

generate RINs for fuel imported from a 

foreign renewable fuel producer or 

foreign ethanol producer if that 

producer is registered with EPA and has 

received EPA company and facility 

identification numbers pursuant to 

§ 80.1450. Pursuant to § 80.1426(c)(4), 

the importer is prohibited from 

generating RINs for fuel imported from 

a foreign producer that is not registered 

with EPA. In today’s rule, EPA is 

clarifying that when an importer is 

generating RINs for fuel imported from 

a registered foreign renewable fuel 

producer or foreign ethanol producer, 

the importer must submit to EPA via 

EMTS the importer’s company 

identification number, the facility 

identification number of the import 

facility where the batch was imported, 

and the facility identification number 

for the foreign renewable fuel or ethanol 

producer that produced the batch of fuel 

for which the importer is generating 

RINs. These clarifications are being 

made in § 80.1452(b)(4) and (5). 

3. Bond Posting 

We are proposing to amend 

paragraphs (e)(1), (e)(2) and (g)(2) of 

§ 80.1467 to make them consistent with 

§ 80.1467(g)(1). These amendments 

attempt to clarify that the amount of the 

posted bond must post must cover the 

number of gallon RINs that are sold and/ 

or transferred, and also those RINs held 

and/or obtained by the foreign entity, 

including those held and/or obtained to 

comply with a foreign importer’s RVO 

requirements. We are also proposing to 

amend §§ 80.1465–80.1467 by striking 

§§ 80.1465(h)(2)(iii), 80.1466(h)(2)(iii) 

and 80.1467(e)(2)(iii), which allowed 

entities to make alternative 

commitments in lieu of posting bonds. 

EPA believes that this method is vague, 

unnecessary, and unenforceable. 

4. Acceptance of Separated Yard Waste 

and Food Waste Plans 

We are proposing to amend 

§ 80.1426(f)(5)(ii)(A) to remove the 

requirement that the separated yard 

waste plan and separated food waste 

plan must be approved by EPA, and 

instead only require that these two 

plans be submitted and accepted by 

EPA under the registration procedures 

specified in § 80.1450(b)(1)(vii). The 

details and information required to be 

submitted in the separated yard waste 

plan and separated food waste plan are 

not overly burdensome or complex, and 

therefore we believe it does not warrant 

a specific EPA approval, but that EPA 

acceptance of these plans through the 

registration procedures is sufficient. 

5. Transferred Blendstocks in Early 

Benzene Credit Generation Calculations 

Today’s rule also proposes one minor 

correction to the gasoline benzene 

regulations which would clarify how 

refiners should account for transferred 

blendstocks in their early benzene credit 

generation calculations. Under current 

rules, refineries which generated early 


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80Early credit generation periods were July 1, 

2007 through December 31, 2007, and calendar 

years 2008, 2009 and 2010. 

81Refineries produce gasoline by combining 

several different blendstocks produced by various 

refinery processing units. Reformate is a blendstock 

which contains approximately 80% of all benzene 

found in gasoline, per the MSAT2 regulatory impact 

analysis. 82 75 FR 76790, December 9, 2010. 

benzene credits are required to reduce 

gasoline benzene during an early credit 

generation period by at least 10% 

compared to the refinery’s benzene 

baseline, and are also required to make 

specific operational changes and/or 

improvements in benzene control 

technology to reduce gasoline benzene 

levels.80 Refineries which reduce their 

gasoline benzene by at least 10%, in 

part by transferring reformate to another 

refinery, could also generate early 

benzene credits, provided the transferee 

refinery treated the reformate in specific 

benzene-reduction processing units.81

See 72 FR 8486–87 (Feb. 26, 2007). 

However, the gasoline benzene 

regulations also contain an additional 

provision that requires all blendstock 

streams transferred to, from or between 

refineries to be excluded from a 

refinery’s early credit generation 

calculations (except for reformate as 

described previously). This led to an 

inconsistent comparison of a refinery’s 

benzene during an early credit 

generation period with a refinery’s 

benzene baseline (which included 

blendstocks transferred to the refinery), 

which was not EPA’s intent. 

As described in the preamble of the 

gasoline benzene final rule, EPA 

intended that refineries not be allowed 

to generate early benzene credits 

exclusively through blendstock trading, 

without making any other qualifying 

reductions (see 72 FR 8487), but that 

refineries could generate early benzene 

credits in part through qualifying 

reductions and ‘‘in part’’ through other 

means such as blendstock transfers (see 

72 FR 8496–97). However, the current 

regulations do not allow this approach, 

and this inconsistency has caused 

confusion among refiners about how to 

calculate the amount of early credits 

generated. Refiners have generally 

followed the approach set out in the 

preamble (as EPA in fact intended), and 

included all blendstocks transferred to a 

refinery in the refinery’s early credit 

generation calculations. Refiners 

typically keep records on transferred 

blendstocks for 1–2 years, and thus do 

not have sufficient data to exclude 

transferred blendstocks from their early 

credit generation calculations. 

EPA recently became aware of this 

inconsistency and is proposing to 

change the regulations to make them 

consistent with EPA’s intent as 

described in the preamble. Today’s 

proposed rule would amend the 

gasoline benzene regulations at 40 CFR 

80.1275(d)(3) by deleting that provision. 

This would allow a refinery to include 

blendstocks transferred to the refinery 

in the refinery’s early benzene credit 

generation calculations (all other 

conditions, including treatment which 

removes benzene in transferred 

reformate streams still applying, of 

course). Consistent with EPA’s original 

intent, today’s rule also allows a 

refinery to include transferred 

blendstocks in past early credit 

generation calculations, provided the 

refinery met all of the other 

requirements for generating early 

benzene credits. EPA is proposing to 

include transferred blendstocks in past 

early credit generation calculation not 

only because this was EPA’s intent at 

the time of the benzene gasoline 

rulemaking, but because some refiners 

have reasonably relied upon that stated 

intent in devising their compliance 

strategies. 

VI. Petition for Reconsideration 

On February 7, 2011, the American 

Petroleum Institute (API) and the 

National Petrochemical and Refiners 

Association (NPRA) jointly submitted a 

Petition for Reconsideration of EPA’s 

final rule establishing the RFS standards 

for 2011.82 EPA is proposing to deny the 

petition for the reasons described below, 

and solicits comment on this proposal. 

The petition is available in docket 

EPA HQ OAR 2010–0133. It makes three 

primary assertions: 

1. EPA’s 2011 cellulosic biofuel 

volume requirement of 6.6 million 

gallons (6.0 million ethanol-equivalent 

gallons) is unrealistically high. At the 

most, EPA should have used the 

estimate of 3.94 mill gallons provided 

by the Energy Information 

Administration (EIA). 

2. EPA’s determination that there are 

sufficient sources of advanced biofuel to 

warrant not reducing the advanced 

biofuel standard lacks adequate factual 

support. 

3. EPA’s treatment of delayed RINs 

injects undesirable uncertainty into the 

regulatory environment, and is contrary 

to the basic regulatory framework 

established by Congress. 

The petition requests that EPA 

reconsider the regulatory requirements 

in all three areas. 

A. Legal Considerations of Petition 

The API/NPRA petition was 

submitted under the reconsideration 

provisions of section 307(d)(7)(B) of the 

Clean Air Act (CAA). This section 

strictly limits petitions for 

reconsideration both in time and scope. 

It states that: 

Only 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. If the person raising 

an objection can demonstrate to the 

Administrator that it was impracticable to 

raise such objection within such time 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, the Administrator shall 

convene a proceeding for reconsideration of 

the rule and provide the same procedural 

rights as would have been afforded had the 

information been available at the time the 

rule was proposed. If the Administrator 

refuses to convene such a proceeding, such 

person may seek review of such refusal in the 

United States court of appeals for the 

appropriate circuit (as provided in subsection 

(b)). Such reconsideration shall not postpone 

the effectiveness of the rule. The 

effectiveness of the rule may be stayed during 

such reconsideration, however, by the 

Administrator or the court for a period not 

to exceed three months. 

Thus the requirement to convene a 

proceeding to reconsider a rule is based 

on the petitioner demonstrating to EPA: 

(1) That it was impracticable to raise the 

objection during the comment period, or 

that the grounds for such objection arose 

after the comment period but within the 

time specified for judicial review (i.e., 

within 60 days after publication of the 

final rulemaking notice in the Federal 

Register, see CAA section 307(b)(1); and 

(2) that the objection is of central 

relevance to the outcome of the rule. 

Regarding the first procedural 

criterion for reconsideration, a 

petitioner must show why the issue 

could not have been presented during 

the comment period, either because it 

was impracticable to raise the issue 

during that time or because the grounds 

for the issue arose after the period for 

public comment (but within 60 days of 

publication of the final action). Thus, 

CAA section 307(d)(7)(B) does not 

provide a forum to request EPA to 

reconsider issues that actually were 

raised, or could have been raised, prior 

to promulgation of the final rule. 

Regarding the second procedural 

criterion for reconsideration, in EPA’s 

view, an objection is of central 

relevance to the outcome of the rule 

only if it provides substantial support 


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83See Denial of Petitions to Reconsider 

Endangerment and Cause or Contribute Findings for 

Greenhouse Gases under section 202(a), 75 FR 

49556, 49560 (August 13, 2010); Denial of Petition 

to Reconsider, 68 FR 63021 (November 7, 2003), 

Technical Support Document for Prevention of 

Significant Deterioration (PSD) and Nonattainment 

New Source Review (NSR): Reconsideration at 5 

(Oct. 30, 2003) (EPA–456/R–03–005) (available at 

http://www.epa.gov/nsr/documents/ 

petitionresponses10-30-03.pdf); Denial of Petition to 

Reconsider NAAQS for PM, 53 FR 52698, 52700 

(December 29, 1988), citing Denial of Petition to 

Revise NSPS for Stationary Gas Turbines, 45 FR 

81653–54 (December 11, 1980), and decisions cited 

therein. Also see EPA’s February 17, 2011 denial of 

petitions by Clean Air Taskforce, World Wildlife 

Fund, National Wildlife Federation, and Friends of 

the Earth’s to reconsider certain elements of the 

RFS2 program. 

84 74 FR 24966. 

85 74 FR 24970. 

86 75 FR 14726. See also 75 FR 14729 (production 

outlook reports ‘‘will help EPA set the annual 

cellulosic biofuel standard * * * ’’ and ‘‘essential 

to our annual cellulosic biofuel standard setting 

* * *’’). 

87 75 FR 42240. 

88 Ibid. 

89 Ibid. 

90 75 FR 42246. 

for the argument that the regulation 

should be revised.83

B. Advanced Biofuel Standard and 

Delayed RINs 

For the concerns raised in the petition 

related to the treatment of the advanced 

biofuel requirement for 2011 and the 

provision for delayed RINs, API and 

NPRA essentially restate the positions 

that they took in their comments in 

response to the 2010 NPRM. For 

instance, with regard to advanced 

biofuels, the petitioners did not 

reference any new data on imports of 

sugarcane ethanol or the production 

potential of biodiesel to demonstrate 

that the statutory applicable volume of 

1.35 bill gallons of advanced biodiesel 

cannot be met in 2011. Likewise with 

regard to delayed RINs, the petitioners 

did not cite new circumstances or new 

information in their assertion that this 

provision will inject uncertainty into 

the regulatory system and RIN market. 

Thus the petition does not provide new 

information with regard to these two 

issues or assert arguments that could not 

have been raised during the comment 

period. As a result, we do not believe 

that the petition’s request for a 

reconsideration of these regulatory 

requirements is justified under CAA 

307(d)(7)(B), and we propose to deny 

the petition with respect to these two 

issues. We believe that our approach to 

these matters in the final rulemaking 

establishing the 2011 RFS standards was 

appropriate, for the reasons described in 

the preamble to that rule. 

C. 2011 Cellulosic Biofuel Requirement 

Regarding the 2011 cellulosic biofuel 

requirement of 6.0 million ethanolequivalent gallons, petitioners make two 

principal arguments: (1) That the 

statutory requirement that the cellulosic 

biofuel requirement be ‘‘based on’’ the 

estimate provided by the EIA requires 

EPA to use the 3.94 million ethanolequivalent gallon EIA estimate 

regardless of any other information, and 

(2) that EPA lacked a reasonable basis 

for its projection of 6.0 million ethanolequivalent gallons. 

The first issue raised by petitioners 

was discussed in the RFS2 proposed 

rule. In the preamble to the 2010 RFS2 

Notice of Proposed Rulemaking, we 

stated that when projecting cellulosic 

biofuel production volumes annually 

‘‘[w]e intend to examine EIA’s projected 

volumes and other available data 

including the production outlook 

reports * * * ’’ that EPA proposed to 

require renewable fuel producers to 

submit annually.84 EPA further 

explained that the production outlook 

reports ‘‘would be used * * * to set the 

annual cellulosic biofuel’’ standard.85

Neither API nor NPRA submitted 

comments stating, as they do now, that 

EPA must in all cases rely on the EIA 

projection and cannot consider or rely 

upon other information in establishing 

the annual cellulosic biofuel standard. 

After evaluating the comments that EPA 

did receive, we issued a final rule, 

including applicable volumes and 

corresponding percentage standards 

consistent with the proposal. We stated 

in the preamble to the final rule that 

‘‘[w]e will examine EIA’s projected 

volumes and other available data 

including the required production 

outlook reports to decide the 

appropriate standard for the following 

year. The outlook reports from all 

renewable fuel producers will assist 

EPA in determining what the cellulosic 

biofuel standard should be * * * ’’ 86

Petitioners had another opportunity to 

raise this same issue in the context of 

the rulemaking establishing the 2011 

standards. EPA again made it clear in its 

proposed rule that the projection that 

would be provided to us by the EIA 

would only be one of several sources of 

information we would use to determine 

the applicable cellulosic biofuel volume 

for 2011: 

We will complete our evaluation based on 

comments received in response to this 

proposal, the Production Outlook Reports 

due to the Agency on September 1, 2010, the 

estimate of projected biofuel volumes that the 

EIA is required to provide to EPA by October 

31, and other information that becomes 

available, and will finalize the standards for 

2011 by November 30, 2010.87

These standards are to be based in part on 

transportation fuel volumes estimated by the 

Energy Information Administration (EIA) for 

the following year.88

As described in the final rule for the RFS2 

program, we intend to examine EIA’s 

projected volumes and other available data 

including the Production Outlook Reports 

required under § 80.1449 in making the 

determination of the appropriate volumes to 

require for 2011.89

* * * each year by October 31 EIA is 

required to provide an estimate of the volume 

of cellulosic biofuel they expect to be sold or 

introduced into commerce in the United 

States in the following year. EPA will 

consider this information as well when 

finalizing a single volume for use in setting 

the 2011 cellulosic biofuel standard.90

After considering all of the information 

before it, EPA proposed a level for the 

cellulosic biofuel volume that was 

different from that contained in the EIA 

projections. Once again, neither API nor 

NPRA provided comments in response 

to the 2010 NPRM on this subject. 

Accordingly, EPA proposes to deny the 

petition with respect to the contention 

that EPA must rely exclusively on the 

EIA projections in establishing the 

annual cellulosic biofuel volumes. That 

argument does not satisfy the criteria for 

a petition for reconsideration specified 

under CAA 307(d)(7)(B) since the issue 

could have been raised during the 

comment period of the 2010 standards 

rule, but was not. 

As a substantive matter, even if the 

petitioners were not foreclosed from 

raising this argument at this time, EPA 

would propose to deny their claim 

because the statute specifies that it is 

EPA, not EIA, that is to make the 

determination of projected cellulosic 

biofuel volumes. EPA’s decision is to be 

‘‘based on’’ the EIA estimate (as, indeed 

it was), but EPA interprets the statute to 

allow it to consider other available 

information as well in making its 

determination. EPA looked at all 

available information, including public 

comments on its proposal, and decided 

that 6.0 million ethanol-equivalent 

gallons was a reasonable projection for 

2011. This is a reasonable interpretation 

of an ambiguous statutory provision, 

where Congress said ‘‘based on’’ the 

estimate provided by EIA but did not 

mandate that the determination be 

based solely upon this information. EPA 

carefully considered EIA’s projection 

and explained why EPA’s determination 

was different. See, for example, Nuclear 

Energy Institute v. EPA, 373 F.2d 1251, 

1269 (DC Cir. 2004). 

The petition also contends that EPA is 

required to project the volume of 

cellulosic biofuel that will ‘‘actually’’ be 


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91 75 FR 42245. 92 75 FR 76794. 

sold or introduced into commerce in the 

following year, but that EPA instead 

established the cellulosic biofuel 

volume at an ‘‘aspirational’’ level. EPA 

believes that petitioners’ allegations are 

not supported by either the statute or 

the facts. Under CAA 211(o)(7)(D)(i), for 

any calendar year for which EPA 

determines that the projected volume of 

cellulosic biofuel production is less 

than the minimum applicable volume 

established under the statute, EPA is to 

reduce the applicable volume of 

cellulosic biofuel to the volume that is 

projected to be available. The statute 

specifies that the projection of cellulosic 

biofuel production is to be ‘‘determined 

by the Administrator based on the 

estimate provided by [EIA],’’ and that it 

must be made in time to set the annual 

standards by November 30 preceding 

the applicable compliance year. To 

fulfill its mandate under this provision, 

EPA undertook an exhaustive 

evaluation of every existing and 

potential cellulosic biofuel production 

facility that could potentially supply 

cellulosic biofuel for use in the U.S., 

and projected a production volume for 

2011 that reflected a balance between 

the uncertainty inherent in the 

projections and the objective of avoiding 

unnecessary reductions in the 

applicable volume set forth in the 

statute. 

The requirement to make a projection 

of cellulosic biofuel volumes for the 

following year necessarily means that 

the projection will be an estimate, and 

may not be exactly the volume that is 

‘‘actually’’ produced. As described in 

the 2010 NPRM, there are many factors 

that may result in the actual volume 

deviating from the projected volume: 

• Difficulty/delays in securing 

necessary funding. 

• Delays in permitting and/or 

construction. 

• Difficulty in scale up, especially for 

1st of their kind technologies. 

• Volumes from pilot and 

demonstration plants may not be sold 

commercially. 

• Not all feedstocks may qualify to 

produce cellulosic Renewable 

Identification Numbers (RINs); some 

still awaiting evaluation of lifecycle 

impacts. 

• Likelihood that fuels produced 

internationally will be exported to the 

United States rather than consumed 

locally.91

We do not believe that the statute 

requires our projection to be 100% 

accurate, or that it requires that EPA 

project only what is absolutely or highly 

certain of production, as the petitioners 

would prefer. Rather, as described in 

Section II.B.4, we believe that our 

projection must be reasonable based on 

the information that is available at the 

time that the cellulosic biofuel standard 

is set. The applicable volume 

established by Congress for cellulosic 

biofuel is 250 mill gallons for 2011, and 

in projecting 6 mill gallons of 

production we lowered the applicable 

volume by about 98%. The volume of 

3.94 mill gallons projected by EIA, and 

favored by petitioners, also represents a 

reduction of about 98% from the 

statutory applicable volume of 250 mill 

gallons. Moreover, with only one 

exception (Range Fuel, discussed 

below), the petitioners do not present 

any new evidence to refute the projected 

production estimates that EPA made for 

the various facilities it anticipated 

would produce fuel in 2011. Their 

primary arguments are that we are 

compelled to use EIA’s projection 

which, as noted above, the statute does 

not require, and that we are required to 

project a level with a high degree of 

certainty. 

As discussed in the rule that set the 

2011 cellulosic standard, we believe 

that the volume of cellulosic biofuel 

actually produced in a given year is 

likely to be strongly influenced by the 

standard we set. At this early point in 

the RFS program, the volume of 

cellulosic biofuel actually made 

available will in general not exceed the 

standard that we set, and there is no 

recourse for increasing the cellulosic 

biofuel standard if our projection were 

to fall short of actual production. 

Therefore, setting a standard that is 

lower than what the industry could 

reasonably achieve could strand 

investments and/or further delay the 

industry’s ability to move towards the 

higher levels of commercial production 

envisioned in the statute. We believe it 

is appropriate to consider these factors 

in projecting production volumes, and 

that we are not compelled to rely solely 

on volumes actually in production at 

the time we make our decision, as 

petitioners would prefer. 

In the final rule establishing the 2011 

projected volume of cellulosic biofuel, 

we explained our approach to 

recognizing and accounting for 

uncertainty in the projections: 

In directing EPA to project cellulosic 

biofuel production for purposes of setting the 

annual cellulosic biofuel standard, Congress 

did not specify what degree of certainty 

should be reflected in the projections. We 

believe that the cellulosic biofuel standard 

should provide an incentive for the industry 

to grow according to the goals that Congress 

established through EISA. However, we also 

believe that the cellulosic biofuel standard 

that we set should be within the range of 

what can be attained based on projected 

domestic production and import potential. 

Any estimate we use to set the biofuel 

standard for 2011 will have some uncertainty 

in terms of actual attainment, and the level 

of such uncertainty generally rises with the 

volume mandate. Our intention is to balance 

such uncertainty with the objective of 

providing an incentive for growth in the 

industry. To this end we explored the 2011 

volumes for individual companies as 

projected by EIA to determine not only what 

volumes might be anticipated, but more 

importantly what volumes were potentially 

attainable. Our final projected available 

volume of cellulosic biofuel for 2011 reflects 

these considerations. 92

Thus, our projection was not 

‘‘aspirational,’’ as petitioners allege. 

Instead, we projected a volume that we 

believed could be reasonably achieved 

based on the information available at 

the time the standard was finalized. We 

acknowledged there were uncertainties, 

but balanced our consideration of that 

uncertainty against the goal of avoiding 

unnecessarily lowering the applicable 

volume in the statute. This is a 

reasonable approach to achieving 

Congress’ goal of promoting the growth 

of the use of cellulosic biofuel, taking 

into account the interests of both the 

obligated parties and the producers of 

cellulosic biofuels. 

The API/NPRA petition does not 

suggest that the projection of 6.0 mill 

ethanol-equivalent gallons of cellulosic 

biofuel was not achievable or was not a 

reasonable balance as discussed above, 

based on the information available at 

the time of the final rule. Instead, the 

petition focuses on balancing these 

interests in a manner that places the 

highest priority on achieving a low or 

very low degree of uncertainty in 

whether the projected volumes will in 

fact be produced. The petition focuses 

almost solely on the uncertainties 

associated with this volume and 

requests that the uncertainties be 

reduced by lowering the applicable 

volume of cellulosic biofuel to no more 

than the EIA projection of 3.94 mill 

gallons. Little if any priority or 

emphasis is placed on the importance of 

establishing conditions that reasonably 

can promote the growth in the 

production of cellulosic renewable fuel. 

EPA disagrees that this would be the 

appropriate balance to draw in 

implementing this provision, at least in 

these early years of the RFS2 program. 

In arguing for a lower volume based 

on the uncertainties, the petition 

highlights the recent history for three 

companies: Bell BioEnergy, Cello 

Energy, and Range Fuels. The 


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93See NPRA v. EPA, (DC Cir., No 10–1071). slip 

op. at 37–39. 

discussion of Bell BioEnergy and Cello 

Energy in the petition is an update of 

the discussion of these same two 

companies in API’s comments 

submitted in response to the 2010 

NPRM. As the petition points out, while 

the information available at the time of 

the 2010 NPRM suggested that these two 

companies could produce cellulosic 

biofuel in 2011, by the time of the final 

rulemaking we had obtained updated 

information and determined that it 

would not be reasonable to project any 

2011 volume from these two companies. 

At the same time, we added two 

companies in the final rule that were 

not included in the 2010 NPRM list of 

companies that we projected could 

produce volume in 2011: KiOr and 

Range Fuels. The changes between the 

proposed and final lists of companies on 

which we based our projections for 2011 

highlight the fact that, in the emergent 

cellulosic biofuel industry, any 

projection of cellulosic biofuel 

production is highly dependent upon 

the information available at the time of 

the projection, and that for any given 

company this information may change 

in one direction or another. 

Nevertheless, changes in the projected 

volume from one company may be 

counterbalanced or mitigated by 

production changes for other 

companies. 

With regard to Range Fuels, we 

reasonably projected a 2011 volume 

production of 2.3 mill ethanolequivalent gallons out of the 6.0 mill 

ethanol-equivalent gallon volume that 

we determined was achievable in 2011. 

Information made available since 

issuance of the final rule indicates that 

the facility was idled early in 2011. 

Nevertheless, this fact does not 

invalidate the projection of 6.0 mill 

gallons we made in December 2010, 

since their facility was complete, 

operational, and had produced some 

volume at that time. As indicated by the 

removal of Bell BioEnergy and Cello 

Energy from the list of companies we 

considered in the final rule, and the 

addition of KiOr and Range Fuels to this 

same list, it is clear that projections 

made at any point in time for some 

companies may ultimately prove too 

high while the projections for other 

companies may ultimately prove too 

low. 

This petition for reconsideration 

under CAA section 307(d) should be 

considered in the context of the specific 

statutory provisions related to the 

annual standard-setting process for the 

RFS program and the compliance 

flexibilities in the program. Congress 

established a standard-setting process 

for cellulosic biofuel that creates a 

considerably shorter leadtime than in 

most other EPA programs, and a 

standard that applies for only a single 

year. We are required to project volumes 

of cellulosic biofuel and determine the 

applicable percentage standard by 

November 30 of the year before the 

annual standard applies. This structure 

is well designed to facilitate use of the 

most up-to-date information available 

before the standard goes into effect. In 

other contexts, API and NPRA have 

argued that it is important that EPA not 

miss this November 30 deadline for 

setting the annual standards, so as to 

provide industry with all of the lead 

time in advance of the compliance year 

that is afforded by the statute.93 Since 

the standard only applies for one year, 

a petition to reconsider can in practice 

affect only that single year’s obligation, 

and given the late date at which it is 

established, necessarily would involve a 

modification of the annual standard 

during the year in which it is 

applicable. Importantly, the statute 

contains a number of safeguards in the 

event that an annual standard cannot be 

achieved. Under CAA section 

211(o)(7)(D)(ii) and (iii), Congress 

established a mechanism through which 

obligated parties can purchase credits 

from the EPA in lieu of acquiring 

cellulosic biofuel RINs. Obligated 

parties can also carry a deficit for 

cellulosic biofuel into 2012 under 

certain conditions as stipulated in 

§ 80.1427(b). Finally, up to 20% of the 

2011 cellulosic biofuel standard (1.2 

million gallons) can be met with excess 

cellulosic biofuel RINs from 2010 under 

the rollover provisions of 

§ 80.1427(a)(5). Indeed, we have 

determined that at least 1.2 million 

excess cellulosic biofuel RINs from 2010 

do exist, based on reports of renewable 

fuel production in the first half of 2010 

under the RFS1 regulations. 

The panoply of compliance 

flexibilities provided in the statute 

provides meaningful options for 

industry in the event that that actual 

production of cellulosic biofuel in 2011, 

or any year, falls below EPA projected 

levels. This, combined with the 

relatively short period of time at issue 

for a petition to reconsider a one-year 

volume standard, and the fact that any 

change in the standards would occur 

within the year in which it applies, 

impacts the kind of circumstances 

under which it would be appropriate to 

reconsider the standard. The 

compliance flexibilities, the short time 

period at issue, and the disruption that 

would occur from a change in the 

standard within the compliance year, 

indicate that a relatively larger change 

in circumstances with respect to 

cellulosic production would need to 

occur before EPA would determine that 

new circumstances provide substantial 

support for revising the volume 

standard for cellulosic biofuel for a 

specific year. 

EPA believes that the single change 

that petitioners have identified in their 

petition, closure of the Range Fuels 

plant, is not of a sufficiently large 

magnitude to warrant a standard 

revision. It may be a substantial 

percentage of the volume standard, but 

it remains a relatively minor change 

compared to the total volume that 

Congress mandated for 2011. After 

reducing that volume by 98%, the 

remaining change in circumstances 

amounts to a generally small change in 

an absolute sense, compared to the total 

volume of renewable fuel and the 

transportation fuel covered by the RFS2 

program. In addition, it can be 

reasonably addressed by industry 

through utilization of program 

flexibilities, including use of carry over 

credits from 2010, use of cellulosic 

biofuel RINs for 2011, and deficit 

carryover into 2012. This approach will 

avoid the disruption and lack of 

certainty in the program that could 

follow if EPA readily re-opened the 

annual standard to revision during the 

single year it applied based on relatively 

small modifications resulting from an 

individual company’s plans. For all of 

the reasons described above, EPA 

proposes to deny the petition for 

reconsideration of the 2011 cellulosic 

biofuel standard. EPA requests comment 

on this proposal. 

While we are proposing to deny the 

petition to reconsider the cellulosic 

biofuel volume requirement for 2011, 

we nevertheless must take into account 

the current status of the cellulosic 

biofuel industry when making our 

projections for 2012. This includes a 

review of the progress being made in 

2011 by the five companies we used to 

project the cellulosic biofuel volume of 

6.0 mill gallons, including Range Fuels. 

As noted in Section II.B.1, based on the 

information we have obtained to date on 

the status of their facility in Soperton, 

Georgia, we have not included Range 

Fuels in the list of companies that we 

project could produce cellulosic biofuel 

in 2012. We do not believe that this is 

inconsistent with our proposal to deny 

the API/NPRA petition for 

reconsideration. Our proposal to deny 

the petition is based on the availability 

of program flexibilities to allow industry 

to comply with the unadjusted 2011 

standard, the relative magnitude of the 


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change, and the desire to avoid 

disruption in program implementation 

that would follow from EPA too readily 

re-opening the standard based on 

modifications in individual companies’ 

operation plans. Our proposed 2012 

projections, on the other hand, are based 

on the best information available to us 

at this time, which includes the fact that 

the Range Fuel facility is not currently 

operating and we have been unable to 

confirm its future operational status. 

In a similar fashion, we do not believe 

that identifying the low end of the range 

of 2012 projected cellulosic biofuel 

volumes as 3.55 mill gallons is 

inconsistent with our proposal to deny 

the API/NPRA petition for 

reconsideration. As described in Section 

II.B, we based the low end of the range 

for applicable 2012 volumes on 

consideration of only those facilities 

that are structurally complete at the 

time of this proposal and which 

anticipate commercial production of 

cellulosic biofuels by the end of 2011. 

While Range Fuel is structurally 

complete, they have not explicitly 

provided information to date indicating 

that they anticipate commercial 

production in 2011. Absent such 

information, for today’s proposal we 

have excluded Range Fuels from the low 

end of the range of potential volumes for 

2012. 

VII. Public Participation 

We request comment on all aspects of 

this proposal. This section describes 

how you can participate in this process. 

A. How do I submit comments? 

We are opening a formal comment 

period by publishing this document. We 

will accept comments during the period 

indicated under DATES in the first part 

of this proposal. If you have an interest 

in the proposed standards and technical 

amendments to the RFS regulations 

described in this document, we 

encourage you to comment on any 

aspect of this rulemaking. We also 

request comment on specific topics 

identified throughout this proposal. 

Your comments will be most useful if 

you include appropriate and detailed 

supporting rationale, data, and analysis. 

Commenters are especially encouraged 

to provide specific suggestions for any 

changes that they believe need to be 

made. You should send all comments, 

except those containing proprietary 

information, to our Air Docket (see 

ADDRESSES in the first part of this 

proposal) before the end of the comment 

period. 

You may submit comments 

electronically, by mail, or through hand 

delivery/courier. To ensure proper 

receipt by EPA, identify the appropriate 

docket identification number in the 

subject line on the first page of your 

comment. Please ensure that your 

comments are submitted within the 

specified comment period. Comments 

received after the close of the comment 

period will be marked ‘‘late.’’ EPA is not 

required to consider these late 

comments. If you wish to submit 

Confidential Business Information (CBI) 

or information that is otherwise 

protected by statute, please follow the 

instructions in Section VII.B. 

B. How should I submit CBI to the 

agency? 

Do not submit information that you 

consider to be CBI electronically 

through the electronic public docket, 

http://www.regulations.gov, or by 

e-mail. Send or deliver information 

identified as CBI only to the following 

address: U.S. Environmental Protection 

Agency, Assessment and Standards 

Division, 2000 Traverwood Drive, Ann 

Arbor, MI, 48105, Attention Docket ID 

EPA–HQ–OAR–2010–0133. You may 

claim information that you submit to 

EPA as CBI by marking any part or all 

of that information as CBI (if you submit 

CBI on disk or CD ROM, 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 CBI). Information so 

marked will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. 

In addition to one complete version of 

the comments that include any 

information claimed as CBI, a copy of 

the comments that does not contain the 

information claimed as CBI must be 

submitted for inclusion in the public 

docket. If you submit the copy that does 

not contain CBI on disk or CD ROM, 

mark the outside of the disk or CD ROM 

clearly that it does not contain CBI. 

Information not marked as CBI will be 

included in the public docket without 

prior notice. If you have any questions 

about CBI or the procedures for claiming 

CBI, please consult the person identified 

in the FOR FURTHER INFORMATION

CONTACT section. 

VIII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

Under Executive Order 12866 (58 FR 

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

‘‘significant regulatory action.’’ 

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. 

The economic impacts of the RFS2 

program on regulated parties, including 

the impacts of the required volumes of 

renewable fuel, were already addressed 

in the RFS2 final rule promulgated on 

March 26, 2010 (75 FR 14670). This 

action proposes the percentage 

standards applicable in 2012 based on 

the volumes that were analyzed in the 

RFS2 final rule. This action also 

proposes technical amendments to the 

RFS2 regulations that have been 

determined to have no adverse 

economic impact on regulated parties 

since they generally clarify existing 

requirements. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. While 

there are three proposed regulatory 

changes in today’s NPRM that affect the 

recordkeeping and reporting burdens for 

regulated parties, we believe that the 

information collections already 

approved for the RFS2 program’s 

general recordkeeping and reporting 

requirements, or the information 

collection already under review, would 

also cover the proposed changes in 

today’s NPRM. 

The proposed regulatory changes are 

listed in Table VIII.B–1. 

TABLE VIII.B–1—PROPOSED TECHNICAL AMENDMENTS AFFECTING RECORDKEEPING AND REPORTING

Section Description 

80.1449(a) ........................................................... Amended Production Outlook Report due date; added allowance for unregistered renewable 

fuel producers and importers to submit Production Outlook Reports. 

80.1450(b)(1)(vi) ................................................. Amended to require submission of additional evidence as part of registration to verify eligibility 

for exemptions in § 80.1403(c) or (d). 


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94See ‘‘Agency Information Collection Activities; 

Submission to OMB for Review and Approval; 

Comment Request; Production Outlook Reports for 

Un-Registered Renewable Fuel Producers (New 

Collection),’’ 76 FR 6781 (February 8, 2011). The 

document identification number for this notice is 

EPA–HQ–OAR–2005–0161–3221. The document 

identification number for the supporting statement 

is EPA–HQ–OAR–2005–0161–3222. 

TABLE VIII.B–1—PROPOSED TECHNICAL AMENDMENTS AFFECTING RECORDKEEPING AND REPORTING—Continued 

Section Description 

80.1450(d)(1)–(d)(3) ........................................... Amended to add more specificity on when updates, addenda, or resubmittals are required for 

engineering reviews and to include references to foreign ethanol producers. 

With regard to production outlook 

reports, the change in due date is not 

expected to have any impact on the 

reporting burden. In addition, EPA 

recently prepared an Information 

Collection Request (ICR) document to 

permit the submission of voluntary 

production outlook reports by domestic 

and foreign renewable fuels producers. 

The parties affected by the ICR are not 

regulated parties under the RFS2 

program. The ICR has been submitted 

for approval to OMB under the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. and may be identified by 

EPA ICR number 2409.01. Documents 

related to the ICR have been placed in 

docket number EPA–HQ–OAR–2005– 

0161, which is accessible at http:// 

www.regulations.gov. 

On October 14, 2010, EPA published 

a notice in the Federal Register 

announcing our intent to submit the 

proposed ICR for voluntary production 

outlook reports to OMB for approval. 

(See 75 FR 63173). The 60-day comment 

period closed on December 14, 2010. No 

comments were received. On February 

8, 2011, EPA published a Federal 

Register notice announcing submission 

of the ICR to OMB. Additional 

comments were solicited via an 

additional comment period through 

March 10, 2011.94

The Office of Management and Budget 

(OMB) has previously approved the 

information collection requirements 

contained in the existing regulations at 

40 CFR part 80, Subpart M under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. This would 

include the following approved 

information collections (with OMB 

control numbers and expiration dates 

listed in parentheses): ‘‘Renewable 

Fuels Standard Program: Petition and 

Registration’’ (OMB Control Number 

2060–0367, expires March 31, 2013); 

‘‘Renewable Fuels Standard (RFS2)’’ 

(OMB Control Number 2060–0640, 

expires July 31, 2013); ‘‘Regulations of 

Fuels and Fuel Additives: 2011 

Renewable Fuels Standard—Petition for 

International Aggregate Compliance 

Approach’’ OMB Control Number 2060– 

0655, expires February 28, 2014). 

Detailed and searchable information 

about these and other approved 

collections may be viewed on the Office 

of Management and Budget (OMB) 

Paperwork Reduction Act Web site, 

which is accessible at http:// 

www.reginfo.gov/public/do/PRAMain. 

With regard to the proposed changes in 

§ 80.1450, we believe that these 

information collections already 

approved for the RFS2 program’s 

general recordkeeping and reporting 

requirements would also cover the 

proposed changes in today’s NPRM. 

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 today’s proposed rule on 

small entities, we certify that this 

proposed action will not have a 

significant economic impact on a 

substantial number of small entities. 

This rule proposes the annual standard 

for cellulosic biofuels for 2012 and 

biomass-based diesel for 2013, 

regulatory provisions for new RINgenerating pathways, and clarifying 

changes and minor technical 

amendments to the regulations. 

However, the impacts of the RFS2 

program on small entities were already 

addressed in the RFS2 final rule 

promulgated on March 26, 2010 (75 FR 

14670). Therefore, this proposed rule 

will not impose any additional 

requirements on small entities. 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. Thus, this action is not subject 

to the requirements of sections 202 or 

205 of UMRA. 

This action 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. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This action only 

applies to gasoline, diesel, and 

renewable fuel producers, importers, 

distributors and marketers and makes 

relatively minor corrections and 

modifications to the RFS2 regulations. 

Thus, Executive Order 13132 does not 

apply to this rule. 

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 rule from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have Tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). This proposed rule will be 

implemented at the Federal level and 

impose compliance costs only on 


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transportation fuel refiners, blenders, 

marketers, distributors, importers, 

exporters, and renewable fuel producers 

and importers. Tribal governments 

would be affected only to the extent 

they purchase and use regulated fuels. 

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 and 

because it implements specific 

standards established by Congress in 

statutes. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This rule is not a ‘‘significant energy 

action’’ as defined in Executive Order 

13211, ‘‘Actions Concerning Regulations 

That Significantly Affect Energy Supply, 

Distribution, or Use’’ (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. 

I. National Technology Transfer 

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 proposed rulemaking does not 

involve technical standards. Therefore, 

EPA is not considering the use of any 

voluntary consensus standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (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. This action does not 

relax the control measures on sources 

regulated by the RFS2 regulations and 

therefore will not cause emissions 

increases from these sources. 

IX. Statutory Authority 

Statutory authority for this action 

comes from section 211 of the Clean Air 

Act, 42 U.S.C. 7545. Additional support 

for the procedural and compliance 

related aspects of today’s proposal, 

including the proposed recordkeeping 

requirements, come from sections 114, 

208, and 301(a) of the Clean Air Act, 42 

U.S.C. 7414, 7542, and 7601(a). 

List of Subjects in 40 CFR Part 80 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Confidential 

business information, Diesel fuel, Fuel 

additives, Gasoline, Imports, Labeling, 

Motor vehicle pollution, Penalties, 

Petroleum, Reporting and recordkeeping 

requirements. 

Dated: June 21, 2011. 

Lisa P. Jackson, 

Administrator. 

For the reasons set forth in the 

preamble, 40 CFR part 80 is proposed to 

be amended as follows: 

PART 80—REGULATION OF FUELS 

AND FUEL ADDITIVES 

1. The authority citation for part 80 

continues to read as follows: 

Authority: 42 U.S.C. 7414, 7542, 7545, and 

7601(a). 

§ 80.1275 [Amended] 

2. In § 80.1275, remove paragraph 

(d)(3). 

Subpart M [Amended] 

3. Section 80.1401 is amended by 

revising the definitions of ‘‘Annual 

cover crop’’ and ‘‘Naphtha’’ to read as 

follows: 

§ 80.1401 Definitions. 

* * * * * 

Annual cover crop means an annual 

crop, planted as a rotation between 

primary planted crops, or between trees 

and vines in orchards and vineyards, 

typically to protect soil from erosion 

and to improve the soil between periods 

of regular crops. An annual cover crop 

has no existing market to which it can 

be sold except for its use as feedstock 

for the production of renewable fuel. 

* * * * * 

Naphtha means a blendstock 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. 

* * * * * 

4. Section 80.1405 is amended by 

revising paragraphs (a) through (c) to 

read as follows: 

§ 80.1405 What are the Renewable Fuel 

Standards? 

(a) (1) Renewable Fuel Standards for 

2011. 

(i) The value of the cellulosic biofuel 

standard for 2011 shall be 0.003 percent. 

(ii) The value of the biomass-based 

diesel standard for 2011 shall be 0.69 

percent. 

(iii) The value of the advanced biofuel 

standard for 2011 shall be 0.78 percent. 

(iv) The value of the renewable fuel 

standard for 2011 shall be 8.01 percent. 

(2) Renewable Fuel Standards for 

2012. 

(i) The value of the cellulosic biofuel 

standard for 2012 shall be 0.002–0.010 

percent. 

(ii) The value of the biomass-based 

diesel standard for 2012 shall be 0.91 

percent. 

(iii) The value of the advanced biofuel 

standard for 2012 shall be 1.21 percent. 

(iv) The value of the renewable fuel 

standard for 2012 shall be 9.21 percent. 

(b) EPA will calculate the value of the 

annual standards and publish these 

values in the Federal Register by 

November 30 of the year preceding the 

compliance period. 

(c) EPA will calculate the annual 

renewable fuel percentage standards 

using the following equations: 


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Where: 

StdCB,i = The cellulosic biofuel standard for 

year i, in percent. 

StdBBD,i= The biomass-based diesel standard 

for year i, in percent. 

StdAB,i= The advanced biofuel standard for 

year i, in percent. 

StdRF,i= The renewable fuel standard for year 

i, in percent. 

RFVCB,i= Annual volume of cellulosic biofuel 

required by 42 U.S.C. 7545(o)(2)(B) for 

year i, or volume as adjusted pursuant to 

42 U.S.C. 7545(o)(7)(D), in gallons. 

RFVBBD,i= Annual volume of biomass-based 

diesel required by 42 U.S.C. 7545 

(o)(2)(B) for year i, in gallons. 

RFVAB,i= Annual volume of advanced biofuel 

required by 42 U.S.C. 7545(o)(2)(B) for 

year i, in gallons. 

RFVRF,i= Annual volume of renewable fuel 

required by 42 U.S.C. 7545(o)(2)(B) for 

year i, in gallons. 

Gi= Amount of gasoline projected to be used 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

Di= Amount of diesel projected to be used in 

the 48 contiguous states and Hawaii, in 

year i, in gallons. 

RGi= Amount of renewable fuel blended into 

gasoline that is projected to be consumed 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

RDi= Amount of renewable fuel blended into 

diesel that is projected to be consumed 

in the 48 contiguous states and Hawaii, 

in year i, in gallons. 

GSi= Amount of gasoline projected to be used 

in Alaska or a U.S. territory, in year i, if 

the state or territory has opted-in or optsin, in gallons. 

RGSi= Amount of renewable fuel blended 

into gasoline that is projected to be 

consumed in Alaska or a U.S. territory, 

in year i, if the state or territory opts-in, 

in gallons. 

DSi= Amount of diesel projected to be used 

in Alaska or a U.S. territory, in year i, if 

the state or territory has opted-in or optsin, in gallons. 

RDSi= Amount of renewable fuel blended 

into diesel that is projected to be 

consumed in Alaska or a U.S. territory, 

in year i, if the state or territory opts-in, 

in gallons. 

GEi= The amount of gasoline projected to be 

produced by exempt small refineries and 

small refiners, in year i, in gallons in any 

year they are exempt per §§ 80.1441 and 

80.1442. 

DEi= The amount of diesel fuel projected to 

be produced by exempt small refineries 

and small refiners in year i, in gallons, 

in any year they are exempt per 

§§ 80.1441 and 80.1442. 

* * * * * 

5. Section 80.1415 is amended by 

revising paragraph (c)(2) to read as 

follows: 

§ 80.1415 How are equivalence values 

assigned to renewable fuel? 

* * * * * 

(c) * * * 

(2) The application for an equivalence 

value shall include a technical 

justification that includes all the 

following: 

(i) A calculation for the requested 

equivalence value according to the 

equation in paragraph (c)(1) of this 

section, including supporting 

documentation for the value of EC used 

in the calculation such as a certificate of 

analysis from a laboratory that verifies 

the lower heating value in Btu per 

gallon of the renewable fuel produced. 

(ii) For each feedstock, component, or 

additive that is used to make the 

renewable fuel, provide a description, 

the percent input, and identify whether 

or not it is renewable biomass or is 

derived from renewable biomass. 

(iii) For each feedstock that also 

qualifies as a renewable fuel, state 

whether or not RINs have been 

previously generated for such feedstock. 

(iv) A description of the renewable 

fuel and the production process, 

including a block diagram that shows all 

inputs and outputs at each step of the 

production process with a sample 

quantity of all inputs and outputs for 

one batch of renewable fuel produced. 

* * * * * 

6. Section 80.1426 is amended as 

follows: 

a. By revising paragraph (f)(1). 

b. By revising Table 1 to § 80.1426. 

c. By revising paragraphs (f)(5)(ii)(A) 

and (f)(5)(ii)(B). 

§ 80.1426 How are RINs generated and 

assigned to batches of renewable fuel by 

renewable fuel producers or importers? 

* * * * * 

(f) * * * 

(1) Applicable pathways. D codes 

shall be used in RINs generated by 

producers or importers of renewable 

fuel according to the pathways listed in 

Table 1 to this section, paragraph (f)(6) 

of this section, or as approved by the 

Administrator. In choosing an 

appropriate D code, producers and 

importers may disregard any incidental, 

de minimis feedstock contaminants that 

are impractical to remove and are 

related to customary feedstock 

production and transport. Tables 1 and 

2 to this section do not apply to, and 

impose no requirements with respect to, 

volumes of fuel for which RINs are 


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generated pursuant to paragraph (f)(6) of 

this section. 

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 

A ...... Ethanol .................................. Corn starch .................................................... All of the following: Dry mill process, using 

natural gas, biomass, or biogas for process energy and at least two advanced 

technologies from Table 2 to this section.

6 

B ...... Ethanol .................................. Corn starch .................................................... All of the following: Dry mill process, using 

natural gas, biomass, or biogas for process energy and at least one of the advanced technologies from Table 2 to this 

section plus drying no more than 65% of 

the distillers grains with solubles it markets annually.

6 

C ...... Ethanol .................................. Corn starch .................................................... All of the following: Dry mill process, using 

natural gas, biomass, or biogas for process energy and drying no more than 50% 

of the distillers grains with solubles it markets annually.

6 

D ...... Ethanol .................................. Corn starch .................................................... Wet mill process using biomass or biogas 

for process energy.

6 

E ...... Ethanol .................................. Starches from crop residue and annual 

covercrops.

Fermentation using natural gas, biomass, or 

biogas for process energy.

6 

F ...... Biodiesel, and renewable diesel.Soy bean oil; Oil from annual covercrops; 

Algal oil; Biogenic waste oils/fats/greases; 

Non-food grade corn oil.

One of the following: Trans-Esterification 

Hydrotreating Excluding processes that 

co-process renewable biomass and petroleum.

4 

G ...... Biodiesel ................................ Canola/Rapeseed oil ..................................... Trans-Esterification using natural gas or biomass for process energy.4 

H ...... Biodiesel, and renewable diesel.Soy bean oil; Oil from annual covercrops; 

Algal oil; Biogenic waste oils/fats/greases; 

Non-food grade corn oil.

One of the following: Trans-Esterification 

Hydrotreating Includes only processes that 

co-process renewable biomass and petroleum.

5 

I ........ Ethanol .................................. Sugarcane ..................................................... Fermentation ................................................. 5 

J ....... Ethanol .................................. Cellulosic Biomass from crop residue, slash, 

pre-commercial thinnings and tree residue, annual covercrops, switchgrass, and 

miscanthus; cellulosic components of separated yard waste; cellulosic components 

of separated food waste; and cellulosic 

components of separated MSW.

Any ................................................................ 3 

K ...... Cellulosic Diesel, Jet Fuel 

and Heating Oil.

Cellulosic Biomass from crop residue, slash, 

pre-commercial thinnings and tree residue, annual covercrops, switchgrass, and 

miscanthus; cellulosic components of separated yard waste; cellulosic components 

of separated food waste; and cellulosic 

components of separated MSW.

Any ................................................................ 7 

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

M ...... Cellulosic Naphtha ................ Cellulosic Biomass from crop residue, slash, 

pre-commercial thinnings and tree residue, annual covercrops, switchgrass, and 

miscanthus; cellulosic components of separated yard waste; cellulosic components 

of separated food waste; and cellulosic 

components of separated MSW.

Fischer-Tropsch process ............................... 3 

N ...... Ethanol, renewable diesel, jet 

fuel, heating oil, and naphtha.

The non-cellulosic portions of separated 

food waste.

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

O ...... Biogas .................................... Landfills, sewage waste treatment plants, 

manure digesters.

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

* * * * * 

(5) * * * 

(ii)(A) A feedstock qualifies under 

paragraph (f)(5)(i)(A) or (f)(5)(i)(B) of 

this section only if it is collected 

according to a plan submitted to and 

accepted by U.S. EPA under the 

registration procedures specified in 

§ 80.1450(b)(1)(vii). 

(B) A feedstock qualifies under 

paragraph (f)(5)(i)(C) of this section only 

if it is collected according to a plan 

submitted to and approved by U.S. EPA. 

* * * * * 

7. Section 80.1429 is amended by 

revising paragraphs (b)(2) and (b)(9) 

introductory text to read as follows: 


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§ 80.1429 Requirements for separating 

RINs from volumes of renewable fuel. 

* * * * * 

(b) * * * 

(2) Except as provided in paragraph 

(b)(6) of this section, any party that 

owns a volume of renewable fuel must 

separate any RINs that have been 

assigned to that volume once the 

volume is blended with gasoline or 

fossil-based diesel to produce a 

transportation fuel, heating oil, or jet 

fuel. A party may separate up to 2.5 

RINs per gallon of blended renewable 

fuel. 

* * * * * 

(9) Except as provided in paragraphs 

(b)(2) through (b)(5) and (b)(8) of this 

section, parties whose non-export 

renewable volume obligations are solely 

related to either the importation of 

products listed in § 80.1407(c) or 

§ 80.1407(e) or to the addition of 

blendstocks into a volume of finished 

gasoline, finished diesel fuel, RBOB, or 

CBOB, can only separate RINs from 

volumes of renewable fuel if the number 

of gallon-RINs separated in a calendar 

year is less than or equal to a limit set 

as follows: 

* * * * * 

8. Section 80.1449 is amended by 

revising paragraph (a) introductory text 

to read as follows: 

§ 80.1449 What are the Production Outlook 

Report requirements? 

(a) By June 1 of each year (September 

1 for the report due in 2010), a 

registered renewable fuel producer or 

importer must submit and an 

unregistered renewable fuel producer 

may submit all of the following 

information for each of its facilities, as 

applicable, to EPA: 

* * * * * 

9. Section 80.1450 is amended as 

follows: 

a. By revising paragraph (b)(1)(vi). 

b. By revising paragraphs (d)(1)– 

(d)(3). 

§ 80.1450 What are the registration 

requirements under the RFS program? 

* * * * * 

(b) * * * 

(1) * * * 

(vi) For facilities claiming the 

exemption described in § 80.1403(c) or 

(d), evidence demonstrating all of the 

following: 

(A) The date that construction 

commenced (as defined in 

§ 80.1403(a)(1)), including all the 

following: 

(1) Contracts with construction and 

other companies. 

(2) Applicable air permits issued by 

the U.S. Environmental Protection 

Agency, state, local air pollution control 

agencies, or foreign governmental 

agencies that governed the construction 

and/or operation of the renewable fuel 

facility during construction and when 

first operated. 

(B) That construction was not 

discontinued for a period of 18 months 

after commencement of construction. 

(C) That construction was completed 

by December 19, 2010, for facilities 

claiming an exemption pursuant to 

§ 80.1403(c); or within 36 months of 

commencement of construction for 

facilities claiming an exemption 

pursuant to § 80.1403(d). 

(D) Other documentation and 

information as requested by the 

Administrator. 

* * * * * 

(d) * * * 

(1) Any producer of renewable fuel, 

and any foreign ethanol producer who 

makes changes to his facility that will 

allow him to produce renewable fuel, as 

defined in § 80.1401 that is not reflected 

in the producer’s registration 

information on file with EPA must 

update his registration information and 

submit a copy of an updated 

independent third-party engineering 

review on file with EPA at least 60 days 

prior to producing the new type of 

renewable fuel. The producer may also 

submit an addendum to the 

independent third-party engineering 

review on file with EPA provided the 

addendum meets all the requirements in 

paragraph (b)(2) of this section and 

verifies for EPA the most up-to-date 

information at the producer’s existing 

facility. 

(2) Any producer of renewable fuel 

and any foreign ethanol producer who 

makes any other changes to a facility 

that will affect the producer’s 

registration information but will not 

affect the renewable fuel category for 

which the producer is registered per 

paragraph (b) of this section must 

update his registration information 7 

days prior to the change. 

(3) All producers of renewable fuel 

and foreign ethanol producers must 

update registration information and 

submit an updated independent thirdparty engineering review according to 

the schedule in paragraph (d)(3)(i) or 

(d)(3)(ii) of this section, and including 

the information specified in paragraph 

(d)(3)(iii) of this section: 

(i) For all producers of renewable fuel 

and foreign ethanol producers registered 

in calendar year 2010, the updated 

registration information and 

independent third-party engineering 

review shall be submitted to EPA by 

October 1, 2013, and by October 1 of 

every third calendar year thereafter; or 

(ii) For all producers of renewable 

fuel and foreign ethanol producers 

registered in any calendar year after 

2010, the updated registration 

information and independent thirdparty engineering review shall be 

submitted to EPA by October 1 of every 

third calendar year after the first year of 

registration. 

(iii) In addition to conducting the 

engineering review and written report 

and verification required by paragraph 

(b)(2) of this section, the updated 

independent third-party engineering 

review shall include a detailed review 

of the renewable fuel producer’s 

calculations used to determine VRIN of 

a representative sample of batches of 

each type of renewable fuel produced 

since the last registration. The 

representative sample shall be selected 

in accordance with the sample size 

guidelines set forth at § 80.127. 

* * * * * 

10. Section 80.1451 is amended by 

revising paragraph (a)(1)(xi) to read as 

follows: 

§ 80.1451 What are the reporting 

requirements under the RFS program? 

(a) * * * 

(1) * * * 

(xi) A list of all RINs generated prior 

to July 1, 2010 that were retired for 

compliance in the reporting period. 

* * * * * 

11. Section 80.1452 is amended 

revising paragraphs (b)(2), (b)(4), and 

(b)(5) to read as follows: 

§ 80.1452 What are the requirements 

related to the EPA Moderated Transaction 

System (EMTS)? 

* * * * * 

(b) * * * 

(2) The EPA company registration 

number of the renewable fuel producer 

or foreign ethanol producer, as 

applicable. 

* * * * * 

(4) The EPA facility registration 

number of the facility at which the 

renewable fuel producer or foreign 

ethanol producer produced the batch, as 

applicable. 

(5) The EPA facility registration 

number of the importer that imported 

the batch, if applicable. 

* * * * * 

12. Section 80.1460 is amended by 

adding a new paragraph (b)(6) to read as 

follows: 

§ 80.1460 What acts are prohibited under 

the RFS program? 

* * * * * 

(b) * * * 


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(6) Generate a RIN for fuel for which 

RINs have previously been generated. 

* * * * * 

13. Section 80.1464 is amended as 

follows: 

a. By revising paragraphs (a)(2) 

introductory text and (a)(2)(i). 

b. By adding paragraphs (a)(2)(iii) and 

(a)(2)(iv). 

c. By revising paragraph (a)(3)(ii). 

d. By revising paragraphs (b)(2) 

introductory text and (b)(2)(i). 

e. By adding paragraphs (b)(2)(iii) and 

(b)(2)(iv). 

f. By revising paragraph (b)(3)(ii). 

g. By revising paragraph (c)(1) 

introductory text. 

h. By adding paragraphs (c)(1)(iii) and 

(c)(1)(iv). 

§ 80.1464 What are the attest engagement 

requirements under the RFS program? 

* * * * * 

(a) * * * 

(2) RIN Transaction Reports and 

Product Transfer Documents. 

(i) Obtain and read copies of a 

representative sample, selected in 

accordance with the guidelines in 

§ 80.127, of each RIN transaction type 

(RINs purchased, RINs sold, RINs 

retired, RINs separated, RINs reinstated) 

included in the RIN transaction reports 

required under § 80.1451(a)(2) for the 

compliance year. 

* * * * * 

(iii) Verify that the product transfer 

documents for the representative 

samples under paragraph (a)(2)(i) of this 

section of RINs sold and the RINs 

purchased contain the applicable 

information required under § 80.1453 

and report as a finding any product 

transfer document that does not contain 

the required information. 

(iv) Verify the accuracy of the 

information contained in the product 

transfer documents reviewed pursuant 

to paragraph (a)(2)(iii) of this section 

and report as a finding any exceptions. 

(3) * * * 

(ii) Obtain the database, spreadsheet, 

or other documentation used to generate 

the information in the RIN activity 

reports; compare the RIN transaction 

samples reviewed under paragraph 

(a)(2) of this section with the 

corresponding entries in the database or 

spreadsheet and report as a finding any 

discrepancies; compute the total 

number of current-year and prior-year 

RINs owned at the start and end of each 

quarter, purchased, separated, sold, 

retired and reinstated, and for parties 

that reported RIN activity for RINs 

assigned to a volume of renewable fuel, 

the volume and type of renewable fuel 

(as defined in § 80.1401) owned at the 

end of each quarter; as represented in 

these documents; and state whether this 

information agrees with the party’s 

reports to EPA. 

(b) * * * 

(2) RIN Transaction Reports and 

Product Transfer Documents. 

(i) Obtain and read copies of a 

representative sample, selected in 

accordance with the guidelines in 

§ 80.127, of each transaction type (RINs 

purchased, RINs sold, RINs retired, RINs 

separated, RINs reinstated) included in 

the RIN transaction reports required 

under § 80.1451(b)(2) for the compliance 

year. 

* * * * * 

(iii) Verify that the product transfer 

documents for the representative 

samples under paragraph (b)(2)(i) of this 

section of RINs sold and the RINs 

purchased contain the applicable 

information required under § 80.1453 

and report as a finding any product 

transfer document that does not contain 

the required information. 

(iv) Verify the accuracy of the 

information contained in the product 

transfer documents reviewed pursuant 

to paragraph (b)(2)(iii) of this section 

and report as a finding any exceptions. 

(3) * * * 

(ii) Obtain the database, spreadsheet, 

or other documentation used to generate 

the information in the RIN activity 

reports; compare the RIN transaction 

samples reviewed under paragraph 

(b)(2) of this section with the 

corresponding entries in the database or 

spreadsheet and report as a finding any 

discrepancies; report the total number of 

each RIN generated during each quarter 

and compute and report the total 

number of current-year and prior-year 

RINs owned at the start and end of each 

quarter, purchased, separated, sold, 

retired and reinstated, and for parties 

that reported RIN activity for RINs 

assigned to a volume of renewable fuel, 

the volume of renewable fuel owned at 

the end of each quarter, as represented 

in these documents; and state whether 

this information agrees with the party’s 

reports to EPA. 

* * * * * 

(c) * * * 

(1) RIN Transaction Reports and 

Product Transfer Documents. 

* * * * * 

(iii) Verify that the product transfer 

documents for the representative 

samples under paragraph (c)(1)(i) of this 

section of RINs sold and RINs 

purchased contain the applicable 

information required under § 80.1453 

and report as a finding any product 

transfer document that does not contain 

the required information. 

(iv) Verify the accuracy of the 

information contained in the product 

transfer documents reviewed pursuant 

to paragraph (c)(1)(iii) of this section 

and report as a finding any exceptions. 

* * * * * 

14. Section 80.1465 is amended by 

revising paragraph (h)(2) to read as 

follows: 

§ 80.1465 What are the additional 

requirements under this subpart for foreign 

small refiners, foreign small refineries, and 

importers of RFS–FRFUEL? 

* * * * * 

(h) * * * 

(2) Bonds shall be posted by any of 

the following methods: 

(i) Paying the amount of the bond to 

the Treasurer of the United States. 

(ii) Obtaining a bond in the proper 

amount from a third party surety agent 

that is payable to satisfy United States 

administrative or judicial judgments 

against the foreign refiner, provided 

EPA agrees in advance as to the third 

party and the nature of the surety 

agreement. 

* * * * * 

15. Section 80.1466 is amended by 

revising paragraph (h)(2) to read as 

follows: 

§ 80.1466 What are the additional 

requirements under this subpart for RINgenerating foreign producers and importers 

of renewable fuels for which RINs have 

been generated by the foreign producer? 

* * * * * 

(h) * * * 

(2) Bonds shall be posted by any of 

the following methods: 

(i) Paying the amount of the bond to 

the Treasurer of the United States. 

(ii) Obtaining a bond in the proper 

amount from a third party surety agent 

that is payable to satisfy United States 

administrative or judicial judgments 

against the foreign producer, provided 

EPA agrees in advance as to the third 

party and the nature of the surety 

agreement. 

* * * * * 

16. Section 80.1467 is amended by 

revising paragraphs (e)(1), (e)(2), and 

(g)(2) to read as follows: 

§ 80.1467 What are the additional 

requirements under this subpart for a 

foreign RIN owner? 

* * * * * 

(e) * * * 

(1) The foreign entity shall post a 

bond of the amount calculated using the 

following equation: 

Bond = G * $ 0.01 

Where: 

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

G = The total of the number of gallon-RINs 

the foreign entity expects to obtain, sell, 

transfer or hold during the first calendar 


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year that the foreign entity is a RIN 

owner, plus the number of gallon-RINs 

the foreign entity expects to obtain, sell, 

transfer or hold during the next four 

calendar years. After the first calendar 

year, the bond amount shall be based on 

the actual number of gallon-RINs 

obtained, sold, or transferred so far 

during the current calendar year plus the 

number of gallon-RINs obtained, sold, or 

transferred during the four calendar 

years immediately preceding the current 

calendar year. For any year for which 

there were fewer than four preceding 

years in which the foreign entity 

obtained, sold, or transferred RINs, the 

bond shall be based on the total of the 

number of gallon-RINs sold or 

transferred so far during the current 

calendar year plus the number of gallonRINs obtained, sold, or transferred 

during any immediately preceding 

calendar years in which the foreign 

entity owned RINs, plus the number of 

gallon-RINs the foreign entity expects to 

obtain, sell or transfer during subsequent 

calendar years, the total number of years 

not to exceed four calendar years in 

addition to the current calendar year. 

(2) Bonds shall be posted by any of 

the following methods: 

(i) Paying the amount of the bond to 

the Treasurer of the United States. 

(ii) Obtaining a bond in the proper 

amount from a third party surety agent 

that is payable to satisfy United States 

administrative or judicial judgments 

against the foreign RIN owner, provided 

EPA agrees in advance as to the third 

party and the nature of the surety 

agreement. 

* * * * * 

(g) * * * 

(2) Any RIN that is obtained, sold, 

transferred, or held that is in excess of 

the number for which the bond 

requirements of this section have been 

satisfied is an invalid RIN under 

§ 80.1431. 

* * * * * 

[FR Doc. 2011–16018 Filed 6–30–11; 8:45 am] 

BILLING CODE 6560–50–P 


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