EO12866_RFS standards 2060-AR43 NPRM FRN_20120628.docx

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2010-0133; FRL-9678-8]

RIN 2060-AR43

Regulation of Fuels and Fuel Additives: 2013 Renewable Fuel Standards

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

SUMMARY: Under section 211(o) of the Clean Air Act, 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 2013 that is below the applicable volume 

specified in the Act. Today's action also proposes annual percentage 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 2013. Finally, today's action coproposes two 

options for the applicable volume of biomass-based diesel that would apply in 2014. 

DATES: Comments must be received on or before [insert date 45 days after date of 

publication in the Federal Register].

Hearing: If we receive a request for a public hearing on or before [insert date 7 days after date 

of publication in the Federal Register], we will hold the hearing on XXXdateXXX at 

XXXlocationXXX, beginning at 9:00am local time. If we do not receive a request for a public 

hearing by the deadline, the hearing will be cancelled through an announcement in the Federal 

Register.

ADDRESSES: Submit your comments, identified by

Docket ID No. EPA-HQ-OAR-2010-0133, by one of the following methods:

• www.regulations.gov: Follow the on-line instructions for submitting comments.

• Email: a-and-r-docket@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.
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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 www.regulations.gov, including any personal information provided, 

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

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

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

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

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

you send an e-mail comment directly to EPA without going through www.regulations.gov your 

e-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 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 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 the public information line for the 

Office of Transportation and Air Quality; telephone number (734) 214-4333; E-mail address 

OTAQ@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: 
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Category NAICS1

Codes

SIC2

Codes

Examples of Potentially Regulated Entities

Industry

Industry 

Industry 

Industry 

Industry 

Industry

Industry

324110

325193

325199

424690

424710

424720

454319

2911

2869

2869

5169

5171

5172

5989

Petroleum Refineries

Ethyl alcohol manufacturing

Other basic organic chemical manufacturing

Chemical and allied products merchant wholesalers

Petroleum bulk stations and terminals

Petroleum and petroleum products merchant 

wholesalers

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 

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.
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• 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................................................................................................................ 7

A. Purpose of This Proposed Action ....................................................................................... 8

B. Summary of Major Provisions in This Notice .................................................................... 9

1. Cellulosic Biofuel Volume for 2013............................................................................... 9

2. Advanced Biofuel and Total Renewable Fuel in 2013 ................................................. 11

3. Proposed Standards for 2013 ........................................................................................ 12

4. Biomass-Based Diesel for 2014.................................................................................... 13

C. Impacts of Proposed Actions............................................................................................ 13

II. Projection of Cellulosic Volume for 2013 ............................................................................ 15

A. Statutory Requirements..................................................................................................... 16

B. Status of the Cellulosic Biofuel Industry.......................................................................... 16

C. Cellulosic Biofuel Volume Assessment for 2013............................................................. 19

1. Cellulosic Biofuel Facilities Considered in the 2012 Projections ................................ 20

2. Facilities not Included in 2012 Projections................................................................... 24

3. Other Potential Sources of Domestic Cellulosic Biofuel.............................................. 25

4. Imports of Cellulosic Biofuel........................................................................................ 26

5. Summary of Volume Projections.................................................................................. 27

D. Proposed Cellulosic Biofuel Volume for 2013................................................................. 29

III. Assessment of Advanced Biofuel and Total Renewable Fuel for 2013 ............................... 30

A. Statutory Requirements..................................................................................................... 30

B. Assessment of Available Volumes of Advanced Biofuel................................................. 31

1. Biodiesel ....................................................................................................................... 32

2. Imported Sugarcane Ethanol......................................................................................... 33

3. Domestic Production of Other Advanced Biofuel ........................................................ 34

C. Proposed Volume Requirements for Advanced Biofuel and Total Renewable Fuel in 

2013........................................................................................................................................... 36

IV. Proposed Percentage Standards for 2013......................................................................... 38

A. Background....................................................................................................................... 38

B. Calculation of Standards................................................................................................... 38

1. How Are the Standards Calculated? ............................................................................. 38

2. Small Refineries and Small Refiners............................................................................ 41

3. Proposed Standards....................................................................................................... 42

V. Proposed Volume Requirement for Biomass-Based Diesel in 2014 .................................... 44

A. Statutory Requirements..................................................................................................... 44

B. Factors Considered in Assessing 2014 Biomass-Based Diesel Volumes......................... 46

1. Demand for Biomass-Based Diesel .............................................................................. 47
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2. Availability of Feedstocks ............................................................................................ 48

a. Waste Fats, Oils, and Greases................................................................................... 48

b. Corn Oil .................................................................................................................... 49

c. Soybean Oil............................................................................................................... 49

d. Effects on Food Prices.............................................................................................. 50

3. Production Capacity...................................................................................................... 51

4. Consumption Capacity.................................................................................................. 52

5. Biomass-Based Diesel Distribution Infrastructure ....................................................... 54

C. Impacts of 1.39 billion gallons of Biomass-Based Diesel ................................................ 56

1. Climate Change............................................................................................................. 57

2. Energy Security............................................................................................................. 62

3. Air Quality .................................................................................................................... 65

4. Consideration of Applicable Statutory Economic Factors............................................ 67

a. Monetized Quantifiable Costs................................................................................... 68

b. Transportation Fuel Costs......................................................................................... 71

c. Monetized Quantifiable Benefits.............................................................................. 72

i. Greenhouse Gas Impacts....................................................................................... 72

ii. Energy Security..................................................................................................... 72

iii. Air Quality ............................................................................................................ 72

5. Deliverability and Transport Costs of Materials, Goods, and Products Other Than 

Renewable Fuel..................................................................................................................... 76

6. Wetlands, Ecosystems, and Wildlife Habitats.............................................................. 77

7. Water Quality and Quantity.......................................................................................... 78

a. Soybean Production .................................................................................................. 78

b. Biodiesel Production................................................................................................. 81

8. Job Creation and Rural Economic Development.......................................................... 82

D. Coproposal for 1.28 and 1.39 Billion Gallons.................................................................. 83

VI. Public Participation........................................................................................................... 85

A. How Do I Submit Comments?.......................................................................................... 85

B. How Should I Submit CBI to the Agency?....................................................................... 85

VII. Statutory and Executive Order Reviews........................................................................... 87

A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: 

Improving Regulation and Regulatory Review ........................................................................ 87

B. Paperwork Reduction Act................................................................................................. 87

C. Regulatory Flexibility Act ................................................................................................ 87

D. Unfunded Mandates Reform Act...................................................................................... 88

E. Executive Order 13132: Federalism ................................................................................. 88

F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments

88

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

Safety Risks .............................................................................................................................. 89

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use......................................................................................... 89

I. National Technology Transfer and Advancement Act ..................................................... 89

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

Populations and Low-Income Populations ............................................................................... 89
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VIII. Statutory Authority ........................................................................................................... 91
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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 

major revisions to the regulatory requirements on March 26, 20101. 

The volumes of renewable fuel to be used under the RFS program each year (absent an 

adjustment or waiver by EPA) are specified in CAA 211(o)(2). The volumes for 2013 are shown

in Table I-1.

Table I-1

Required Applicable Volumes in the Clean Air Act for 2013 (bill gal)

Cellulosic biofuel 1.0a

Biomass-based diesel ≥1.0b

Advanced biofuel 2.75a

Renewable fuel 16.55a

a

Ethanol-equivalent volume

b Actual volume

Under the RFS program, EPA is required to determine and publish annual percentage 

standards for each compliance year by November 30 of the previous year. The percentage 

standards are used by obligated parties to calculate their individual compliance obligations. The 

percentage standards are applied to the volume of gasoline and/or diesel fuel that each obligated 

party produces or imports during the specified calendar year to determine the volumes of 

renewable fuel that they must cause to be used as transportation fuel, heating oil, or jet fuel. The 

percentage standards are calculated so as to ensure use in transportation fuel of the “applicable 

volumes” of four types of biofuel (cellulosic biofuel, biomass-based diesel, advanced biofuel, 

and total renewable fuel) that are either set forth in the Clean Air Act or established by EPA in 

accordance with the Act’s requirements.

The cellulosic biofuel industry is transitioning from research and development (R&D) 

and pilot-scale to commercial scale facilities, leading to substantial increases in production 

capacity. Construction has begun on several facilities, and there is a high likelihood that 

cellulosic biofuel will be produced in 2012. Based on detailed information from production 

companies and a consideration of various potential uncertainties, we are projecting that 33 

million gallons of cellulosic biofuel will be available in 2013.

We have evaluated the types of advanced biofuels that can be produced or imported in 

2013 and have determined that there will be sufficient volumes to meet the statutory applicable 

volume of 2.75 billion gallons. Combined with the availability of conventional biofuels such as 

corn ethanol, there will also be sufficient total renewable fuels available in 2013 to meet the 

statutory applicable volume of 16.55 billion gallons.

 

1

75 FR 14670
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In a separate action we are finalizing an applicable volume requirement of 1.28 billion 

gallons of biomass-based diesel for 2013. In today's NPRM we present additional analysis 

suggesting that there may be sufficient feedstocks and production capacity to permit a small 

increase in the applicable volume requirement for biomass-based diesel in 2014 above 1.28 

billion gallons. Moreover, in the longer term the benefits of increased volumes of biomass-based 

diesel are expected to exceed the costs. Nevertheless, it may be prudent to maintain the 2014 

volume requirement at 1.28 billion gallons in order to provide some additional time to evaluate 

how the market is responding. Therefore, we are coproposing both an increase in the biomassbased diesel applicable volume requirement to 1.39 billion gallons in 2014 and maintaining the 

2014 volume requirement at 1.28 billion gallons.

A. Purpose of This Proposed Action

EPA is today proposing volume requirements for cellulosic biofuel, advanced biofuel, 

and total renewable fuel for 2013 and for biomass-based diesel in 2014. Table I.A-1 lists the 

statutory provisions and associated criteria relevant to determining the applicable volumes in 

today’s proposal. We are also proposing percentage standards for all four categories of 

renewable fuel for 2013. 

Table I.A-1

Statutory Provisions for Determination of Proposed Applicable Volumes

Applicable volumes Clean Air Act 

reference

Criteria provided in statute for determination 

of applicable volume

Cellulosic biofuel in 

2013

211(o)(7)(D)(i) Mandatory determination. Required volume 

must be lesser of volume specified in CAA 

211(o)(2)(B)(i)(III) or EPA’s projected 

volume.

Advanced biofuel in 

2013

211(o)(7)(D)(i) If applicable volume of cellulosic biofuel is 

reduced to the projected volume, EPA may 

reduce advanced biofuel by the same or 

lesser volume. No other criteria specified.

Total renewable fuel in 

2013

211(o)(7)(D)(i) If applicable volume of cellulosic biofuel is 

reduced to the projected volume, EPA may 

reduce total renewable fuel by the same or 

lesser volume. No other criteria specified.

Biomass-based diesel in 

2014

211(o)(2)(B)(ii) Mandatory determination for years after 

2012. Required volume must be based on 

review of program implementation to date 

and analysis of a number of factors such as 

costs, feedstock supply, infrastructure, etc. 

EPA must coordinate with DOE and USDA

EPA must annually determine the projected volume of cellulosic biofuel production for 

the following year. If the projected volume of cellulosic biofuel production is less than the 
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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. In today's proposal, we present our analysis of cellulosic biofuel 

production and proposed projected volume for 2013. The analyses that led to the proposed 2013 

applicable volume requirement were based on our evaluation of individual producers’ production 

plans and progress to date. For the final rule, we will also consider comments received in 

response to this notice of proposed rulemaking, the estimate of projected biofuel volumes that 

the Energy Information Administration (EIA) is required to provide to EPA by October 31, 

information from Production Outlook Reports, and other information that becomes available.

When we lower the applicable volume of cellulosic biofuel below the volume specified in 

CAA 211(o)(2)(B)(i)(III), we also have the authority to reduce the applicable volumes of 

advanced biofuel and/or total renewable fuel by the same or a lesser amount. Today's proposal 

includes our consideration of the 2013 volume requirements for these biofuels.

Based on the applicable volumes for cellulosic biofuel, biomass-based diesel, advanced 

biofuel, and total renewable fuel presented in today's proposal, we have calculated proposed 

percentage standards that would apply to all producers and importers of gasoline and diesel in 

2013. The proposed percentage standards are based on an early projection of volumes of 

gasoline and diesel consumption in 2013 from the Energy Information Administration (EIA). 

EPA intends to use updated EIA projections of gasoline and diesel consumption in 2013 in 

calculating the final percentage standards.

While section 211(o)(2)(B) specifies the volumes of biomass-based diesel through year 

2012, it directs the EPA 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. EPA proposed an applicable volume of biomass-based diesel for 2013 on July 1, 2011, 

and is issuing a final rule establishing that applicable volume in a separate notice. In today's 

notice we are coproposing two options for the applicable volume of biomass-based diesel for 

2014.

B. Summary of Major Provisions in This Notice

1. Cellulosic Biofuel Volume for 2013

The cellulosic biofuel industry in the United States continues to make significant 

advances in its progress towards large scale commercial production. Ongoing research and 

development work has resulted in increasing product yields, while at the same time lowering 

enzyme and catalyst costs. New supply chains have been developed, and several companies 

have reached contract agreements to provide the necessary feedstock for large scale cellulosic 

biofuel production facilities. Companies are continuing to invest significant sums of money to 

further refine cellulosic biofuel production technology and to construct the first commercialscale facilities. From 2007 through the second quarter of 2011over $2.4 billion was invested in 
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advanced biofuel production companies by venture capitalists alone.2 For more information on 

the current status of the cellulosic biofuel industry in the United States and the advances being 

made, see Section II.B.

2013 is also expected to be a year of transition for the cellulosic biofuel industry, as many 

companies are shifting their focus from technology development to commercialization. This 

transition began in 2012 with the first commercial production facilities from INEOS Bio and 

KiOR scheduled to come online, and will continue throughout 2013. Two of the largest 

producers of ethanol in the United States, Abengoa and Poet, are planning to begin producing 

cellulosic ethanol at commercial scale in 2013. Several others companies, including BP and 

DuPont, will be constructing their first commercial scale facilities in 2013, with the intention of 

beginning production in 2014. If these facilities are able to operate as anticipated, the 

uncertainty associated with commercial-scale cellulosic biofuel production will be significantly 

decreased, and the expansion of the industry could be rapid.

To estimate the volume of cellulosic biofuel that can be made available in the U.S. in 

2013, 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 were not the focus 

of our assessment; however their production volumes were considered in aggregate. From this 

universe of potential cellulosic biofuel sources we identified the subset that had a possibility of 

producing commercial volumes of qualifying cellulosic biofuel for use as transportation fuel in 

2013. To arrive at this proposed projected volume, we took into consideration factors such as the 

current and expected state of funding, the status of the technology utilized, progress towards 

construction and production goals, and other significant factors that could potentially impact fuel 

production or the ability of the produced fuel to generate cellulosic Renewable Identification 

Numbers (RINs) in 2013. Further discussion of these factors can be found in Section II.B.

In our assessment we focused on domestic sources of cellulosic biofuel. We are not 

aware of any internationally-based cellulosic biofuel production facilities with the intention of 

exporting their fuel into the U.S. in 2013. Of the domestic sources, we estimated that five 

facilities can make commercial-scale volumes of cellulosic biofuel available for transportation 

use in the U.S. in 2013. These facilities are listed in Table I.B.1-1 along with our estimate of the 

projected 2013 volume for each. The table also includes an estimate of the total RIN-generating 

volume of cellulosic biofuel that will be produced from the many small research and 

development and demonstration facilities in the United States in 2013.

 

2

Solecki M, Rickey D, Epstein B. Advanced Biofuel Market Report 2011: Meeting the California LCFS. 

Environmental Entrepreneurs. August 22, 2011. 

<http://www.e2.org/ext/doc/E2%20Advanced%20Biofuel%20Mkt%20Report%202011.pdf>.
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Table I.B.1-1

Projected Available Cellulosic Biofuel Plant Volumes for 2013

Company Location Fuel type

Capacity 

(million gallons 

per year)

Projected 

Start-Up 

Date

Projected available 

volumea

Abengoa Hugoton, KS Ethanol 26 3Q 2013 4

Fiberight Blairstown, IA Ethanol 3.8 1

st Half 2013 1

INEOS Bio Vero Beach, FL Ethanol 8.0 2Q 2012 8

KiOR Columbus, MS Gasoline and 

Diesel

11 2

nd Half 2012 18

Poet-DSM Emmetsburg, IA Ethanol 25 2

nd Half 2013 1

Various Pilot/ 

Demo Plants

N/A N/A N/A N/A 1

Total 73.8 33

a Volumes listed in million ethanol-equivalent gallons

The variation in expected start-up times, along with the facility production capacities, company 

production plans, and a variety of other factors have all been taken into account in projecting the 

available volume of cellulosic biofuel. 

2. Advanced Biofuel and Total Renewable Fuel in 2013

The statute indicates that we may reduce the applicable volume of advanced biofuel and 

total renewable fuel specified in the statute if we determine that the projected volume of 

cellulosic biofuel production for 2013 falls short of the statutory volume of 1.0 billion gallons. 

As shown in Table I.B.1-1, we have proposed a finding that this is the case. Therefore, we have 

also evaluated whether to propose lowering the applicable volumes for advanced biofuel and 

total renewable fuel. Since the statute provides no criteria or direction for making this 

determination, we have focused our evaluation on the availability of renewable fuels that would 

qualify as advanced biofuel.

The CAA specifies an applicable volume of 2.75 billion gallons of advanced biofuel for 

2013. To determine whether to lower this volume, we first considered the contribution that 

biomass-based diesel will make to the advanced biofuel requirement. We have finalized a 

volume of 1.28 bill gal in a separate action. Since biodiesel has an Equivalence Value of 1.5, 

1.28 billion physical gallons of biodiesel would provide 1.92 billion ethanol-equivalent gallons 

that could be counted towards the advanced biofuel standard of 2.75 billion gallons. Of the 

remaining 830 mill gallons, we project that 33 mill gallons would be met with cellulosic biofuel. 

There are three primary sources of other advanced biofuels that, considered together, are 

projected to have the potential to provide significantly more than the approximately 800 mill gal 

needed to meet the statutory 2.75 bill gal advanced biofuel applicable volume, after cellulosic 

biofuel and biomass-based diesel are taken into account. As described in more detail in Section 

III, these sources include domestic advanced biofuels which are expected to grow steadily 

through 2013, imports of sugarcane ethanol, and biodiesel production in excess of 1.28 bill gal. 

In addition, we believe there will be sufficient volumes of conventional renewable fuel to satisfy 

the 16.55 billion gallon applicable volume of total renewable fuel specified in the Act. Since 
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there appears to be adequate supply, we are not proposing to reduce either the advanced biofuel 

volume requirement of 2.75 bill gal, nor the total renewable fuel volume requirement of 16.55 

bill gal.

3. Proposed Standards for 2013

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 for the coming year are accurate, then the amount of 

renewable fuel, cellulosic biofuel, biomass-based diesel, and advanced biofuel actually used will 

meet the volumes required on a nationwide basis. 

To calculate the percentage standards for 2013, we have used the proposed projected 

volume of 33 million ethanol-equivalent gallons of cellulosic biofuel and the volume of biomassbased diesel of 1.28 bill gal that we have finalized in a separate action. The applicable volumes 

used in this proposal for advanced biofuel and total renewable fuel for 2013 are those specified 

in the statute. These volumes are shown in Table I.B.3-1. 

Table I.B.3-1

Proposed Volumes Used to Determine the Proposed 2013 Percentage Standardsa

Cellulosic biofuel 33 mill gal

Biomass-based diesel 1.28 bill gal

Advanced biofuel 2.75 bill gal

Renewable fuel 16.55 bill gal

a All volumes are ethanol-equivalent, except for biomass-based diesel which is 

actual.

Four separate standards are required under the RFS program, corresponding to the four 

separate volume requirements shown in Table I.B.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 IV.B.1. The percentage standards represent the ratio of renewable fuel 

volume to projected non-renewable gasoline and diesel volume. The projected volume of 

transportation gasoline and diesel used to calculate the standards in today's proposed rule was 

derived from available EIA projections. We expect to base the final renewable fuel percentage 

standards on updated projections provided by EIA. At this time EPA has not approved any small 

refinery or small refiner exemptions for 2013, and thus no adjustment has been made to the 

proposed standards to account for such exemptions. The proposed standards for 2013 are shown 

in Table I.B.3-2. Detailed calculations can be found in Section IV.
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Table I.B.3-2

Proposed Percentage Standards for 2013

Cellulosic biofuel 0.020%

Biomass-based diesel 1.18%

Advanced biofuel 1.69%

Renewable fuel 10.15%

4. Biomass-Based Diesel for 2014

While section 211(o)(2)(B) specifies the volumes of biomass-based diesel through year 

2012, it directs the EPA 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. In today's action we are coproposing an applicable volume of either 1.28 bill gallons or 

1.39 bill gallons for biomass-based diesel for 2014. We have analyzed the impacts of increasing 

the biomass-based diesel standard for 2014 beyond the 1.28 bill gal requirement established for 

2013 based on consideration of the factors specified in the statute including biodiesel production 

capacity, consumption, and infrastructure capabilities, as well as impacts on emissions, costs, 

energy security, and other factors. However, the statute also indicates that we should take into 

account a review of the implementation of the program for years prior to 2013. While the 

industry is on track to meet the 1.0 bill gal applicable volume requirement for 2012, and may 

produce a total annual volume of around 1.3 bill gallons in 2012, the market has little experience 

at these production levels. Thus, it may be prudent to leave the 2014 volume requirement at 1.28 

bill gal before considering volume increases in subsequent years. Section V provides additional 

discussion of our assessment of the proposed volume of 1.39 bill gal of biomass-based diesel for 

2014.

C. Impacts of Proposed Actions

The anticipated increase in cellulosic biofuel in comparison to the 2012 volume 

requirement will have directionally beneficial GHG impacts as cellulosic biofuels in general 

have at least a 60 percent GHG emissions improvement compared to the gasoline and diesel fuel 

they will replace. Analyses for the March 26, 2010 RFS2 final rule indicated the GHG benefits 

from cellulosic biofuels compared to the petroleum-based fuels they displace could likely range 

well above the 60 percent threshold. 

We are coproposing to either leave the 2014 volume requirement for biomass-based 

diesel at 1.28 bill gal, or to increase it to 1.39 bill gal. A volume requirement of 1.39 bill gal 

would be 110 mill gallons above the 2013 required volume of 1.28 bill gal that we are finalizing 

in a separate action. The RFS program established by Congress is a long-term program aimed at 

replacing fossil fuels used in the transportation sector with low-GHG renewable fuels over time. 

In the RFS2 final rule, EPA assessed the costs and benefits of this program as a whole when the 

program would be fully mature in 2022. We continue to believe this is the appropriate approach 

to examining the costs and benefits of a long-term program like the RFS2. However, we have 

estimated costs and benefits in 2014 where such estimates can reasonably be made and have 
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provided trends and other information on likely impacts where quantification for just 2014 is not 

possible or would not reflect the continually progressive nature of the program.

The statute requires EPA to consider a number of factors when setting the biomass-based 

diesel mandate for years after 2012. These include environmental impacts (e.g. air quality, 

climate change, conversion of wetlands, etc), energy security impacts, impacts on rural 

development, impacts on job creation, and several other categories. The statute does not require 

EPA to consider these impacts quantitatively. However we have chosen to provide quantified 

estimates for certain impacts for illustrative purposes. 

If the 110 million gallon increment over the 2013 biomass-based diesel standard is met 

solely with soybean oil, we estimate that soybean prices could increase up to 1.5 cents per pound 

in 2014, and that the cost of producing this increment in biodiesel would range from $112 to 

$162 million in 2014. Illustrative of the changing impacts over the duration of the RFS program, 

the cost of this amount of soy-based biodiesel in 2022 would be between -$77 and $45 million. 

Adding the estimate of 2014 costs to the total 2014 fuel pool would suggest a diesel fuel cost 

increase of less than half of 1 cent per gallon. Of course, if less expensive feedstock is used, then 

the cost impacts would be smaller still.

We estimate that the quantifiable benefits from decreased GHG emissions stemming 

from this rule are up to $42 million for the emissions stream beginning in 2014 and between $3 

million and $47 million for the emissions stream beginning in 2022. The estimated benefits of 

increased energy security are about $16 million in 2014 and about $18 million in 2022. The 

estimated air quality disbenefits are between $7.6 and $21 million in 2014 and between $8.3 and 

$22 million in 2022. Benefits increase over time because of the increasing value of the social 

cost of carbon. Simultaneously, costs decrease over time because of increasing oil prices and 

decreasing biodiesel feedstock prices.

For advanced biofuel and total renewable fuel, we are not proposing to reduce the 

applicable volumes below the volumes required in the statute. All of the impacts of the biofuel 

volumes specified in the statute were addressed in the RFS2 final rule published on March 26, 

2010. Today's rulemaking simply proposes the standards for 2013 advanced biofuel and total 

renewable fuel whose impacts were previously analyzed. 
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II. Projection of Cellulosic Volume for 2013

In order to project the available production volume of cellulosic biofuel in 2013 for use in 

setting the percentage standard, we collected information on individual facilities that have the 

potential to produce qualifying volumes for consumption as transportation fuel, heating oil, or jet 

fuel in the U.S. in 2013. This section describes the volumes that could be produced or imported 

in 2013 as well as some of the uncertainties associated with those volumes. 

In the past several years the cellulosic biofuel industry has made many significant 

advances. The production cost of cellulosic biofuels continues to fall as a result of ongoing 

technology development and operating experience gained from many research and development 

and demonstration-scale facilities across the country. These important advances include higher 

biofuel yields per ton of feedstock as well as lower enzyme and catalyst costs. As a result of 

these yield increases, the projected capital costs and energy costs to produce a gallon of 

cellulosic biofuel have decreased. New feedstock supply chains, which will be necessary to 

provide the raw materials for the first commercial facilities, have been established, and in several 

cases companies have signed contracts to obtain significant quantities of feedstocks for their first 

commercial facilities. These developments, along with the increased availability of project 

financing, have resulted in the construction of the first commercial-scale cellulosic biofuel 

production facilities. Two commercial-scale facilities are on schedule to begin producing fuel in 

2012. Three more have plans to start-up in 2013, with several more planning construction in 

2013 and start-up in 2014. If these first facilities are successful and operate as designed it will

significantly decrease the perceived risk associated with similar future facilities and could 

potentially lead to the rapid deployment of cellulosic biofuel production facilities around the 

United States.

Despite significant advances in cellulosic biofuel production technology in recent years, 

RIN-generating cellulosic biofuel production in 2010 and 2011 was zero despite our projections 

that the industry was positioned to produce about 6 million gallons in each of those years.3 A 

discussion of the reasons for this disparity is provided in Section II.B below. 

In today's NPRM we are proposing a volume for 2013 cellulosic biofuel that is based on 

discussions with individual producers. By the time we announce the final 2013 volumes and 

percentage standards in November 2012, 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 2012. Second, all registered producers and 

importers of renewable fuel must submit Production Outlook Reports by June 1 describing their 

expectations for new or expanded biofuel supply for the next five years, according to §80.1449. 

Finally, by October 31, 2012, 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 2013. 

All of this information will be used in setting the final cellulosic biofuel applicable volume and 

percentage standard for 2013.

 

3

 In the first half of 2010 when the RFS1 program was still effective, some cellulosic biomass ethanol was 

produced. However, this biofuel was not made from cellulosic feedstocks, but rather was categorized as cellulosic 

under the limited provisions of §80.1101(a)(2). 
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A. Statutory Requirements

The volumes of renewable fuel to be used under the RFS program each year (absent an 

adjustment or waiver by EPA) are specified in CAA 211(o)(2). For 2013, the statute specifies a 

cellulosic biofuel applicable volume requirement of 1.0 bill gal. 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 volumes of 

advanced biofuels and total renewable fuel by the same or a lesser volume. Our consideration of 

the 2013 volume requirements for advanced biofuels and total renewable fuel is presented in 

Section III.

B. Status of the Cellulosic Biofuel Industry

As in previous years, cellulosic biofuel production in the United States in 2011 was 

limited to small-scale research and development, pilot, and demonstration-scale facilities. 

Companies such as Abengoa, BP, Coskata, DuPont Danisco, KL Energy, KiOR, Poet, and others 

successfully operated small-scale facilities in 2011. Several of these facilities, including all that 

were part of our 2012 volume projections, are discussed in more detail in Section II.C below. 

While there were numerous small-scale facilities producing cellulosic biofuel in 2011, the total 

volume of fuel produced was very small. Because of the R&D nature of these small facilities 

they are neither designed to produce fuel for commercial sale nor required to report the small 

volumes of fuel they produced. No RINs were generated for volumes that were produced in 

2011, despite all of the companies included in the 2011 projections expressing interest and/or 

intent in doing so. Although EPA has not attempted to accurately assess production volumes, 

based on generally available information we believe that total production in the United States in 

2011 was likely less than one million gallons of cellulosic biofuel across the industry.

Each of the companies included in our 2011 projections for cellulosic biofuel production 

had different reasons for not generating cellulosic RINs in 2011. DuPont had concerns about 

their ability to retain the R&D status of their Vonore, TN facility if they generated RINs and sold 

the cellulosic ethanol they produced from this facility. Fiberight was unable to secure the 

funding required to complete the modifications to their facility to allow for cellulosic ethanol 

production. KL Energy finalized an agreement with Petrobras in the second half of 2010 and 

changed the direction of their facility to focus on using bagasse as a primary feedstock. Finally, 

after completing initial production of cellulosic ethanol Range Fuels shut down operations in 

January 2011 and eventually declared bankruptcy. 

While cellulosic biofuel production in the United States remains limited, the industry 

continues to make significant progress towards producing cellulosic biofuel at prices competitive 
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with petroleum fuels. From 2007 through the second quarter of 2011 venture capitalists invested 

over $2.4 billion in advanced biofuel companies in North America4. Recent advancements in 

enzyme and catalyst technologies are allowing cellulosic biofuel producers to achieve greater 

yields of biofuel per ton of feedstock. These advancements have led to lower operational costs 

as they have driven down the cost for feedstock, energy, and other important inputs on a per 

gallon basis. For example, the estimated cost of cellulosic ethanol production using an 

enzymatic hydrolysis process has decreased from $4-$8 per gallon in 2007 to $2-$3.50 per 

gallon by 20125. NREL similarly reports that advancements in cellulosic ethanol technology 

have resulted in a decrease in modeled costs from more than $6.50 per gallon in 2001 to less than 

$2 per gallon in 2010.6 The same technological advances have also lowered the capital costs of 

cellulosic biofuel production facilities per gallon of annual fuel production, as more gallons of 

biofuel can be produced at a facility without additional equipment or increased feedstock 

requirements.

As cellulosic biofuel producers gain experience and continue to progress towards 

commercial-scale biofuel production, it is reasonable to expect that the production costs and 

capital costs will continue to decline. This is a pattern shown by many new technologies, 

including renewable and emerging energy technologies. One example which has several 

similarities to the cellulosic biofuel industry is the experience with the dry mill corn ethanol 

industry. From 1983, the year in which the first commercial volumes of dry mill ethanol were 

produced, to 2005 the processing cost of corn ethanol decreased by 45%, while the capital costs 

of a dry mill ethanol facility decreased by 88%.7 Many of the drivers for this cost reduction, 

such as higher ethanol yields, reduced enzyme costs, and better fermentation technologies8are 

also expected to be factors in the lower cellulosic biofuel costs expected in the future. While the 

cost reduction percentages observed in the dry mill corn ethanol industry are not directly 

applicable to the cellulosic biofuel industry, the trend of decreasing production and capital costs 

over time is expected to hold true.

Another area where significant progress has been made is that of feedstock supply for 

commercial-scale cellulosic biofuel production facilities. This issue has often been raised as a 

factor that could hinder the development of the cellulosic biofuel industry as many of the 

proposed facilities rely on feedstocks, such as agricultural residues or energy crops, for which 

supply chains have not previously existed. BP Biofuels has begun work to establish energy crop 

plantations to provide the necessary feedstock for their first two commercial-scale production 

facilities. Over the past several years both Abengoa and Poet have been reaching out to farmers 

 

4

Solecki M, Rickey D, Epstein B. Advanced Biofuel Market Report 2011: Meeting the California LCFS. 

Environmental Entrepreneurs. August 22, 2011. Available Online 

<http://www.e2.org/ext/doc/E2%20Advanced%20Biofuel%20Mkt%20Report%202011.pdf>.

5 Nielsen, Peder Holk. “The Path to Commercialization of Cellulosic Ethanol – A Brighter Future.” PowerPoint 

Presentation. Conference Call. February 22, 2012. Available Online 

<http://www.novozymes.com/en/investor/events-presentations/Documents/Cellic3_conf_call_220212.pdf>.

6 NREL. Cellulosic Ethanol Technology on Track to being Competitive With Other Transportation Fuels. February 

2011. NREL/FS-2700-50846. Available Online <http://www.nrel.gov/science_technology/pdfs/50846.pdf>.

7 Hettinga WG, Junginger HM, Dekker SC, Hoogwijk M, McAloon AJ, Hicks KB. Understanding the reductions in 

US corn ethanol production costs: An experience curve approach. Energy Policy 37 (2009): 190-203. Available 

Online <http://ddr.nal.usda.gov/bitstream/10113/22550/1/IND44146988.pdf>.

8

IBID
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in the regions surrounding their first commercial-scale facilities to ensure the availability of the 

necessary feedstock. Because corn cobs and stover are only seasonally available, using them as 

a feedstock for a cellulosic biofuel production facility would require significant feedstock storage 

facilities. In the last two years Abengoa and Poet completed construction of large-scale 

feedstock storage facilities to ensure adequate supply to their cellulosic biofuel production 

facilities throughout the year. Both companies successfully completed fall biomass harvests in 

2011 and have contracted with local farmers to provide feedstock for their cellulosic ethanol 

facilities. This supply chain will not only provide feedstock for their first commercial-scale 

facilities, but also a model that can be re-created at future production facilities.

Several cellulosic biofuel producers are planning to use slash, forest thinnings, and forest 

product residue or the cellulosic portions of yard waste as feedstock. This material has many 

qualities that make it desirable as a cellulosic biofuel feedstock. It is generally inexpensive and 

is readily available in some regions of the United States. It is also available year round rather 

than seasonally, significantly reducing the need for large-scale feedstock storage facilities. 

Securing a sufficient quantity of this feedstock for a commercial-scale facility, however, can be 

challenging. In the summer of 2011 KiOR announced it had signed a feedstock agreement with 

Catchlight Energy to provide all the necessary slash, forest thinning, and forest product residue 

for their first commercial-scale facility. While KiOR plans to transition to planted trees for 

future facilities, KiOR now has secured sufficient feedstock such that they can produce cellulosic 

biofuel and cellulosic RINs using an existing pathway at their first commercial-scale facility. 

INEOS Bio also has a long term agreement with Indian River County to provide vegetative 

waste which will serve as the feedstock for their first facility.

Another appealing feedstock for cellulosic biofuel production is separated municipal 

solid waste (MSW). MSW is already being collected and transported to a centralized facility, is 

consistently available throughout the year, and can be obtained for a very low, or even negative 

cost. MSW often contains contaminants, however, that may make it challenging to process for 

some cellulosic biofuel technologies. EPA also requires that waste separation plans be submitted 

and approved prior to any company generating RINs using separated MSW as a feedstock. Near 

the end of 2011 EPA received the first waste separation plan for Fiberight’s facility in 

Blairstown, Iowa. This plan is currently being evaluated, and we anticipate that a decision will 

be made on Fiberight’s separation plan by the time of the final rule.

Significant progress has also been made by some companies towards funding the 

construction of their first commercial-scale facilities. In the early years of the cellulosic biofuel 

industry several small start-up companies announced plans to build large commercial-scale 

facilities that were scheduled to begin production in the past few years. The construction of 

many of these facilities was dependent on the companies raising additional funding, either from 

venture capitalists, government grants, or loans backed by government guarantees. So far few of 

the companies that made these early announcements have been able to successfully raise the 

necessary funds and begin construction. Securing this funding proved difficult, and when it did 

not materialize the projects were delayed or cancelled.

The funding profiles of the companies included in our proposed volume for 2013, as well 

as for many of the companies targeting production in 2014, are markedly different. Many of 
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these projects have already received, and in several cases have closed on loan guarantees offered 

by DOE or USDA. Other companies have filed for and successfully executed IPOs. Several 

cellulosic ethanol projects are being self-financed by large companies such as Abengoa, BP, and 

Poet with significant experience in the biofuel, petrochemical, and specialty chemical markets. 

This solid financial backing has allowed these companies to proceed with construction. With the 

exception of Fiberight, which is retrofitting an existing corn ethanol facility, all of the facilities 

included in our proposed volume for 2013 have already begun the construction of their first 

commercial production facilities. The next section provides additional details on the funding and 

construction status of the projects included in our projected cellulosic biofuel production 

volumes for 2013. 

If these first commercial-scale cellulosic biofuel production facilities are successful, the 

potential exists for a rapid expansion of the industry in subsequent years. Having successful 

commercial-scale facilities would not only provide useful information to help maximize the 

efficiency of future facilities, but would also significantly decrease the technology and scale-up 

risks associated with cellulosic biofuel production facilities and could lead to increased access to 

project funding. Fiberight and ZeaChem both plan to build larger-scale facilities (~25 mill gal 

per year) as soon as they are able to raise the necessary funds. INEOS Bio plans to expand 

production by building additional units near sources of inexpensive feedstock ranging in size 

from 8 to 50 million gallons of ethanol per year. They are currently exploring expansion 

possibilities in the United States and internationally. KiOR has plans for a second commercialscale facility to be built in Natchez, MS, that will be approximately three times larger (~30 mill 

gal per year) than their Columbus, MS, plant and plans to break ground at their second facility 

after their first is fully operational. Abengoa currently anticipates construction of additional 

cellulosic ethanol facilities at multiple locations, likely including co-locating with some of their 

existing starch facilities in the US. Poet has a similar expansion strategy to build cellulosic 

ethanol plants at their grain ethanol facilities, license their technology for use at other grain 

ethanol facilities, and build cellulosic ethanol facilities that use feedstocks such as rice straw, rice 

hulls, woody biomass, or energy crops as a feedstock. Poet’s goal is to be involved in the 

production of 3.5 billion gallons of cellulosic ethanol per year by 2022. Several other 

companies, such as BP, DuPont, and Enerkem are also targeting 2014 for the start-up of 

cellulosic biofuel production facilities and would likely look to build additional facilities 

relatively quickly if successful. While many of these expansion plans are still in the early stages 

and are subject to change, they do point to the potential for cellulosic biofuel production to 

increase rapidly in future years.

C. Cellulosic Biofuel Volume Assessment for 2013

In 2011 no cellulosic biofuel RINs were generated, though some small volumes were 

produced. Announcements of new projects and project funding, changes in project plans, project 

delays, and cancellations occur. Biofuel producers faced 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 uncertainty about these programs may have had an impact on cellulosic biofuel production in 

2011.
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Despite these challenges, there are several factors indicating that significant volumes of 

cellulosic biofuel can be produced in 2013. Commercial-scale cellulosic biofuel projects from 

INEOS Bio and KiOR are expected to begin fuel production in 2012 and plan to produce fuel at 

volumes near their capacities in 2013. Two more commercial-scale facilities backed by large 

companies with significant experience in biofuel production, Abengoa and Poet, are also 

scheduled to begin producing cellulosic biofuel in 2013. These facilities are indicative of a shift 

across the cellulosic biofuel industry from small-scale R&D and demonstration facilities 

operated by small start-up companies to large commercial-scale facilities backed by large 

companies, many of which have substantial experience in related industries. 

In order to project cellulosic biofuel production for 2013, we have tracked the progress of 

more than 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 generate cellulosic biofuel RINs in 2013. Each of these companies was investigated 

further in order to determine the current status of their facilities and their likely cellulosic biofuel 

production and RIN generation volumes for the coming years. Information such as the funding 

status of these facilities, current status of the production technologies, announced construction 

and production rampup periods, and annual fuel production targets were all considered when we 

met with senior level representatives of each company to discuss cellulosic biofuel target 

production levels for 2013. Our projection of the cellulosic biofuel production in 2013 is based 

on the individual production targets that emerged from these discussions. A brief description can 

be found below for each of the companies we believe will produce cellulosic biofuel and make it 

commercially available in 2013. We will continue to gather more information to help inform our 

decision regarding the final cellulosic biofuel volume to be required for 2013, and we will 

specify the final volume in the final rule to be released by November 31, 2012.

In the sections that follow, we first discuss the cellulosic production facilities that were 

part of our volume projections for the 2012 compliance year and the progress that they have 

made. Then we present our consideration of additional facilities that we believe will also 

produce cellulosic biofuel in 2013.

1. Cellulosic Biofuel Facilities Considered in the 2012 Projections

In the January 9, 2012, final rule that established the required 2012 cellulosic biofuel 

volume, we identified six production facilities that we projected would produce cellulosic biofuel 

and make that fuel commercially available in 2012. Two of these production facilities are 

currently structurally complete, three are currently under construction, and one is planning to 

retrofit an existing corn ethanol plant with construction beginning in the second half of 2012. 

None of the facilities have completed the registration process for the RFS program, and they will 

be unable to generate cellulosic RINs until this process is completed. The current status of each 

of these facilities, including target production levels for each facility in 2013, is discussed below.

API
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American Process Inc. (API) is developing a project in Alpena, Michigan capable of 

producing up to 900,000 gallons of cellulosic ethanol per year from woody biomass. This 

facility will use a technology developed by API called GreenPower+TM. This technology 

extracts the hemicellulose portion of woody biomass using hot water and hydrolyzes it into 

sugars. These sugars are then converted to ethanol or other alcohols, while the remaining portion 

of the woody biomass, containing mostly cellulose and lignin, is processed into wood paneling at 

a co-located facility. At future, larger-scale facilities API anticipates burning the residual 

biomass in a boiler to produce renewable steam and electricity as well as cellulosic biofuel. In 

January 2010 API received a grant from DOE for up to $18 million for the construction of their 

demonstration facility. Construction of the Alpena, Michigan facility began in March 2011 and 

API anticipates beginning the production of cellulosic ethanol at this site in the first half of 2012. 

API plans to switch fuel production at their Alpena facility from ethanol to butanol in late 2012 

or early 2013. API is also developing a list of projects and is currently in the process of 

screening for locations for their next project, which will likely produce 10 million gallons of 

cellulosic biofuel per year and be co-located with a biomass pellet or biomass-to-electricity 

facility. Production from API’s Alpena facility has been included in our proposed volume as one 

contributor to the one million gallons from various pilot and demonstration plants in 2013.

Fiberight

Fiberight uses an enzymatic hydrolysis process to convert the biogenic portion of 

separated MSW and other waste feedstocks into ethanol. They have successfully completed five 

years of development work on their technology at their small pilot plant in Lawrenceville, 

Virginia. This facility is currently in the process of being upgraded to an integrated 

demonstration plant with initial production of cellulosic ethanol expected in July 2012. In 2009 

Fiberight purchased an idled corn ethanol plant in Blairstown, Iowa with the intention of making 

modifications to this facility to allow for the production of 3.8 million gallons of cellulosic 

ethanol per year from separated MSW and industrial waste streams. These modifications were 

scheduled to be completed in 2011, but difficulties in securing funding have resulted in 

construction at this facility being delayed. In January 2012 Fiberight was offered a $25 million 

loan guarantee from USDA. Closing on this loan would provide substantially all of the 

remaining funds required for Fiberight to complete the modifications necessary to allow for the 

production of cellulosic ethanol at their Blairstown facility. Construction will begin as soon as 

Fiberight has secured the necessary funds and will take approximately 6 months to complete. 

While this is a much shorter timeline that most cellulosic biofuel production facilities, it is 

reasonable as Fiberight is retrofitting an existing corn ethanol plant and will be able to use much 

of the existing equipment. Additionally, we have received a waste separation plan from 

Fiberight for this facility that if approved would allow Fiberight to generate RINs for the 

production of cellulosic ethanol using MSW as a feedstock. Fiberight plans to produce 1 million 

gallons of cellulosic ethanol in 2013. Fiberight is also currently developing a second 

commercial-scale project based on their MSW “hub and spoke” concept. They anticipate that 

this facility will begin fuel production in 2014 and will produce approximately 25 million gallons 

of cellulosic ethanol per year when fully built out.

INEOS Bio
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INEOS Bio has developed a process for producing cellulosic ethanol by first gasifying 

cellulosic feedstocks 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 

was in addition to the grant of up to $50 million INEOS Bio received from DOE in December 

2009. When completed, this facility will be capable of producing 8 million gallons of cellulosic 

biofuel as well as 6 megawatts (gross) of renewable electricity from a variety of feedstocks 

including yard, agricultural, and wood waste. The facility is also permitted to use a limited 

quantity of separated MSW as a feedstock and plans to do so by late 2012. Their ability to 

generate RINs for any fuel generated using separated MSW would be dependent on having an 

approved waste separation plan.

On February 9, 2011, INEOS Bio broke ground on this facility. Since then significant 

progress has been made, and INEOS Bio remains on target to complete construction on this 

facility in April 2012. Commercial production of cellulosic ethanol is expected to begin soon 

after construction and commissioning of the facility. INEOS Bio has reported that they plan to 

be producing cellulosic ethanol at levels near the facility’s capacity of 8 million gallons per year 

by the end of 2012. For this proposal we project 8 million gallons of cellulosic ethanol from 

INEOS Bio in 2013. INEOS Bio is also exploring several opportunities for additional cellulosic 

biofuel production facilities, both in the United States and internationally. INEOS Bio is 

targeting sources of inexpensive feedstock and see a market for plants with production capacities 

ranging from 8 to 50 million gallons per year.

KiOR

KiOR is working to commercialize a technology capable of converting biomass to a lowoxygen biocrude using a process they call Biomass Fluid Catalytic Cracking (BFCC). BFCC 

uses a catalyst developed by KiOR in a process similar to Fluid Catalytic Cracking currently 

used in the petroleum industry. The first stage of this process produces a renewable crude oil 

with an oxygen content of approximately 10%. This bio-crude is then upgraded to produce 

primarily gasoline, diesel, and jet fuel as well as a small quantity of fuel oil, all of which are 

nearly identical to those produced from petroleum. 

KiOR’s first commercial-scale facility is located in Columbus, Mississippi and is capable 

of producing approximately 11 million gallons of gasoline, diesel, and jet fuel per year. 

Construction on this facility began in May 2011. KiOR expects production of cellulosic biofuel

from this facility in the 2nd half of 2012. This facility is funded, in large part, with funds from 

KiOR’s $150 million IPO in June 2011. They expect to be producing biofuel at a rate consistent 

with the capacity of the Columbus facility by the end of 2012. KiOR has feedstock supply 

agreements in place to supply all of the required feedstock for their Columbus facility with slash 

and pre-commercial thinning. They also have off-take agreements with several companies for all 

of the fuel that will be produced. KiOR has also announced plans to begin work on their second 

commercial-scale biofuel production facility in Natchez, Mississippi upon the successful start-up 

of their first facility. It is unlikely this second facility will begin production of biofuel in 2013. 
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For 2013 our proposed production projection is for 11 million gallons (18 million ethanolequivalent gallons) of cellulosic biofuel from KiOR’s Columbus facility.

KL Energy

KL Energy has developed a process to convert cellulose and hemicellulose into sugars 

and ethanol using a combined chemical/thermal-mechanical pretreatment process followed by 

enzymatic hydrolysis, co-fermentation of C5 and C6 sugars, and distillation to fuel-grade 

ethanol. This production process is versatile enough to allow for a wide variety of cellulosic 

feedstocks to be used, including woody biomass and herbaceous biomass such as sugarcane 

bagasse. In August 2010 KL Energy announced a joint development agreement with Petrobras 

America Inc. As part of the agreement Petrobras has invested $11 million to modify KL 

Energy’s 1.5 million gallons per year demonstration facility in Upton, Wyoming to allow it to 

process bagasse and other biomass feedstocks. The modifications to KL Energy’s facility were 

completed in the spring of 2011. KL Energy is currently producing small volumes of cellulosic 

ethanol from a bagasse feedstock at this facility and plans to continue to do so throughout 2012 

and into 2013. The main purpose of the Upton, Wyoming facility is to further refine KL 

Energy’s technology in preparation for their first commercial facilities which may be located in 

the Brazil or the United States. Cellulosic ethanol production from KL Energy in 2013 has been 

included as a contributor to the one million gallons from various pilot plants and demonstration 

facilities.

ZeaChem

ZeaChem successfully completed construction of the core components of their 

demonstration-scale facility in Boardman, Oregon, in January 2012, allowing for the production 

of ethyl acetate from sugars derived from cellulose and hemi-cellulose. When fully operational, 

ZeaChem expects this facility will be capable of producing 250,000 gallons of cellulosic ethanol 

per year. ZeaChem’s 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, one containing sugars derived from 

cellulose and hemicellulose and the other containing lignin. The sugars are fermented into an 

intermediate chemical, acetic acid, using a naturally occurring acetogen. The acetic acid is then 

converted into ethyl acetate, which can then be hydrogenated into ethanol. The hydrogen 

necessary for this process is produced by gasifying the lignin stream from the cellulosic biomass. 

Construction is currently underway to add the front-end operations, the conversion of cellulosic 

biomass to sugars, and the back-end process, the upgrading of the chemicals produced to 

transportation fuel, to the existing core facility. ZeaChem plans to begin the production of 

ethanol from cellulosic biomass at this facility by the end of 2012. Work is currently underway 

to add additional process modules that will enable ZeaChem to convert the cellulosic ethanol to 

jet and diesel fuel beginning in 2013. 

ZeaChem’s process is flexible and is capable of producing a wide range of renewable 

chemicals and fuels from many different feedstocks. They plan to use both agricultural residues 

and wood waste at their demonstration facility and have contracts in place for these feedstocks, 

as well as purpose-grown wood, at their first commercial-scale facility. In January 2012 
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ZeaChem announced that they had received a $232.5 million conditional loan guarantee offer 

from USDA for the construction of their first commercial-scale facility, which will have a 

capacity of at least 25 million gallons per year. ZeaChem currently has agreements in place to 

provide all of the necessary feedstock for this facility. This facility, however, is not expected to 

begin producing cellulosic biofuel until late 2014 at the earliest. ZeaChem’s only cellulosic 

biofuel production in 2013, therefore, will be from their demonstration-scale facility and has 

been included as a contributor to the one million gallons we are proposing for 2013 from various 

pilot and demonstration-scale facilities.

2. Facilities not Included in 2012 Projections

In addition to the facilities that were included in our cellulosic biofuel volume projections 

for the 2012 compliance year, there are two additional facilities that we believe will produce 

volumes in 2013. These facilities are owned by Abengoa and Poet.

Abengoa

Abengoa, a large international biofuels company, is one of two new cellulosic biofuels 

producers expected to begin the production of cellulosic biofuels and RINs from a commercialscale facility in 2013. Abengoa plans to use an enzymatic hydrolysis technology to convert corn 

stover and other agricultural waste feedstocks into ethanol. After successfully testing and 

refining their technology at a pilot-scale facility in York, Nebraska as well as in a demonstrationscale facility in Salamanca, Spain, Abengoa is now working towards the completion of their first 

commercial-scale cellulosic ethanol facility in Hugoton, Kansas. Abengoa has contracts in place 

to provide the majority of feedstocks necessary for this facility for the next 10 years and 

successfully completed their first biomass harvest in the fall of 2011. Construction at this 

facility, which began in September 2011, is expected to take 24 months and be completed in the 

fourth quarter of 2013. All of the major process equipment for this project has been purchased 

and all of the required permits for construction have been approved. Abengoa’s Hugoton facility 

is being partially funded by a $132 million Department of Energy (DOE) loan guarantee.

When completed, the Hugoton plant will be capable of processing 700 dry tons of corn 

stover per day, with an expected annual ethanol production capacity of approximately 26 million 

gallons. Abengoa plans to begin ramping up production at the facility shortly after completing 

construction in late 2013 and to be producing fuel at rates near the nameplate capacity by the end 

of the year. After successfully proving their technology at commercial-scale in Hugoton, 

Abengoa currently plans to construct additional similar cellulosic ethanol production facilities, 

either on greenfield sites or co-locating these new facilities with their currently existing starch 

ethanol facilities around the United States. We propose that for 2013 cellulosic ethanol 

production from Abengoa’s Hugoton facility could be as much as 4 million gallons. 

Poet

Poet has also developed an enzymatic hydrolysis process to convert cellulosic biomass 

into ethanol. Poet has been investing in the development of cellulosic ethanol technology for 
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more than a decade and began producing small volumes of cellulosic ethanol at pilot-scale at 

their plant in Scotland, SD in late 2008. In January 2012, Poet formed a joint venture with Royal 

DSM of the Netherlands called Poet-DSM Advanced Biofuels to commercialize and license their 

cellulosic ethanol technology. 

The joint venture’s first commercial-scale facility, called Project LIBERTY, will be 

located in Emmetsburg, Iowa. This facility is designed to process 770 dry tons of corn cobs, 

leaves, husks, and some stalk per day into cellulosic ethanol. The facility is projected to have an 

annual production capacity beginning at approximately 20 million gallons per year, increasing 

over time to 25 million gallons per year. In anticipation of the start-up of this facility, Poet 

constructed a 22-acre biomass storage facility and had its first commercial harvest in 2010, 

collecting 56,000 tons of biomass. 

Site prep work for Project LIBERTY began in the summer of 2011, and vertical 

construction of the facility is scheduled to begin in the spring of 2012. Poet was awarded a $105 

million loan guarantee offer for this project from DOE in July 2011, but with the joint venture 

decided to proceed without the loan guarantee. This project is expected to be completed and 

produce commercial volumes of cellulosic ethanol in the second half of 2013. For 2013 we 

project that Project LIBERTY will produce up to 1 million gallons of cellulosic ethanol. After 

the completion of Project LIBERTY, Poet plans to build cellulosic ethanol facilities at all of their 

existing corn ethanol plants. They are also planning to license their technology for use at other 

grain ethanol plants, as well as build additional plants that will process wheat straw, rice hulls, 

woody biomass or herbaceous energy crops. By 2022 Poet has a goal of producing 3.5 billion 

gallons of cellulosic ethanol per year.

Other companies

There are several more companies planning to begin producing cellulosic biofuel from 

commercial-scale facilities in 2014. Companies such as BP, Coskata, DuPont, Enerkem, and 

several others are all currently targeting 2014 for the start-up of their first commercial facilities. 

These facilities represent approximately 100 million gallons of additional cellulosic biofuel 

production capacity. As with the companies discussed above, most of these companies have 

already begun to develop plans for their successive facilities after the successful completion of 

their initial projects. While they will not contribute any volume in 2013, and have therefore not 

been included in our proposed volume, they are a further indication of the potential for the 

significant growth of the cellulosic biofuel industry in the United States in the near future.

3. Other Potential Sources of Domestic Cellulosic Biofuel 

Each of the companies listed in the previous two sections is planning to generate 

cellulosic biofuel RINs using one of the valid RIN-generating pathways listed in Table 1 to 

§80.1426. We are also aware of several companies who may be in a position to produce 

cellulosic biofuel in 2013 but intend to use a production pathway that is not currently approved 

for RIN generation. Three pathways that are currently under evaluation by EPA include the 

following:
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• Compressed natural gas (CNG) derived from biogas, where the biogas is 

produced from the cellulosic portion of MSW

• Cellulosic ethanol produced from corn kernel fiber

• Fuel oil produced from woody biomass

If these or other cellulosic biofuel pathways are approved by EPA, they may be used to generate 

cellulosic biofuel RINs in 2013. Because a final determination on these pathways has not been 

made, however, no volume of cellulosic fuel from these pathways has been included in our 

proposed 2013 cellulosic biofuel projection. The status of these pathways will be reevaluated at 

the time of the final rule and volumes from these pathways may be included in our final 

projection if appropriate.

4. Imports of Cellulosic Biofuel

While domestically produced cellulosic biofuels are the most likely source of cellulosic 

biofuel available in the United States in 2013, imports of cellulosic biofuel produced in other 

countries may also generate RINs and participate in the RFS program. While the RFS 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. We believe this situation is likely to continue in the near future and 

has not included any cellulosic biofuel imports in our projections of available volume in 2013. 

As in the United States, the production of cellulosic biofuels internationally is currently 

limited to small-scale research and development, pilot, and demonstration facilities. This is 

likely to continue to be the case throughout 2013. Two notable exceptions are facilities currently 

being built by Chemtex and Enerkem. Chemtex is planning to complete construction of their 

first commercial-scale facility located in Crescentino, Italy in the summer of 2012. When 

completed, this facility will be capable of producing approximately 12 million gallons of 

cellulosic ethanol per year. Chemtex uses an enzymatic hydrolysis process to produce ethanol 

from local agricultural residues and herbaceous energy crops. 

Enerkem is also in the process of building their first commercial-scale facility in 

Edmonton, Alberta and plans to begin operations in early 2013. Enerkem’s facility will use a 

thermochemical process to produce syngas from MSW and then catalytically convert the syngas 

to methanol. The methanol can then be sold directly or upgraded to ethanol or other chemical 

products. At full capacity this facility will be capable of producing 10 million gallons of 

cellulosic ethanol per year. Neither Chemtex nor Enerkem, however, have plans to import 

cellulosic biofuel into the United States from their first commercial-scale facilities. Both are 

planning to locate additional plants in the United States in the future and are likely to generate 

RINs for production from domestic facilities in future years.
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5. Summary of Volume Projections

The information we have gathered on the potential cellulosic biofuel producers in 2013, 

described above, allows us to project volumes that are reasonably likely to be produced by each 

facility in 2013. For the purposes of this proposed rulemaking we have focused on commercialscale cellulosic biofuel production facilities. In 2013 we expect cellulosic biofuel production 

from five commercial-scale facilities. Each of these facilities is discussed above, and the facility 

production targets for each are summarized in Table II.C.5-1 below. We believe our focus on 

commercial-scale facilities is appropriate as the industry transitions from small-scale R&D and 

pilot facilities to large-scale commercial production. It is likely that several small-scale facilities 

such as API, KL Energy, ZeaChem, and others will also produce some cellulosic biofuel in 2013. 

The volume of fuel produced by each individual facility, however, is expected to small, 

especially in relation to that from the five facilities listed in Table II.C.5-1 below. A combined 

volume of one million gallons from the various pilot and demonstration-scale facilities in 2013 

has been included in this proposal.

When added together, the total projected production volume from commercial-scale 

production facilities in the United States in 2013 is 26 million gallons (33 million ethanolequivalent gallons). This number represents the expected fuel production from each facility, 

taking into account the potential for project delays, difficulty in start-up, and the various other 

factors discussed above. As such, we believe it is an appropriate number for the projected 

available volume in 2013 for this proposal. 
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Table II.C.5-1

Potentially Available Cellulosic Biofuel for 2013

Company 

Name Location Feedstock Fuel Capacity (MGY)

Production 

Start-Up

2013 Potentially 

Available 

Volume (MG)

Ethanol 

Equivalent 

Gallons (MG)

Abengoa Hugoton, KS Corn Stover Ethanol 26 3

rd Quarter 2013 4 4

Fiberight Blairstown, IA MSW Ethanol 3.8 1

st Half 2013 1 1

INEOS Bio Vero Beach, FL Vegetative Waste Ethanol 8.0 2

nd Quarter 2012 8 8

KiOR Columbus, MS Wood Waste Gasoline 

and Diesel

11 2

nd Half 2012 11 18

Poet-DSM Emmetsburg, IA Corn Stover Ethanol 25 2

nd Half 2013 1 1

Various 

Pilot/ Demo 

Plants

N/A N/A N/A N/A N/A 1 1

Total 73.8 26 33
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D. Proposed Cellulosic Biofuel Volume for 2013

In today’s NPRM we are proposing a volume for the 2013 cellulosic biofuel standard that 

is based on production targets developed in consultation with the five companies we expect to 

produce cellulosic biofuel from commercial-scale facilities in 2013. Many factors have been 

taken into consideration in developing these production targets, such as the current status of 

project funding, the status of the production facility, anticipated construction timelines, the 

anticipated start-up date and ramp-up schedule, feedstock supply and many others. We believe 

the sum of these individual production targets (33 million ethanol-equivalent gallons) is a 

reasonable representation of likely production at these. Moreover, all of the companies included 

in our 2013 volume projections have invested a significant amount of time and resources 

developing their technologies at R&D and demonstration-scale facilities prior to the design and 

construction of their first commercial-scale facilities. The projects have solid financial backing, 

and in the case of Abengoa, Fiberight, and INOES Bio are backed by federal loan guarantees. 

By the time of our final rule the facilities owned by KiOR and INEOS Bio are scheduled to have 

already begun fuel production. These two facilities make up a significant majority of the

cellulosic biofuel in our 2013 projection, and their progress towards meeting their production 

goals will be an important piece of information as we consider the appropriate level of the 

cellulosic biofuel standard to finalize.

It is important to note that the final cellulosic biofuel standard for 2013 may be set at a 

volume that differs from the proposed volume. This could happen for a variety of reasons, 

including unexpected project modifications or cancellations or the inclusion of volumes of 

cellulosic biofuel from sources other than those listed above. For example, the proposed 

projected available volume of cellulosic biofuel in 2013 discussed above (33 million ethanolequivalent gallons) does not include potential contributions from cellulosic biofuel produced 

from corn fiber, renewable heating oil, or landfill biogas that is converted to transportation fuel. 

Together, these pathways could generate several tens of millions of gallons of ethanol-equivalent 

renewable fuel. However, since they are currently undergoing an evaluation to determine 

whether they are valid for the generation of cellulosic RINs, we have not included their volumes 

in our 2013 projection in this NPRM. If any of these pathways are approved, additional volume 

from these sources may be added to the target production volumes listed in Table II.C.5-1 for the 

final rule.

We will continue to monitor the progress of the cellulosic biofuel industry, in particular 

the progress of the companies which form the basis of our 2013 volume projection. 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, as we consider public 

comments on this proposal, and as we consider the EIA estimated 2013 volume of cellulosic 

biofuel production that they are required to provide to us by October 31 of this year, we will 

have a clearer idea of the appropriate volume of fuel that we can reasonably expect to be 

produced and made commercially available in 2013.
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III. Assessment of Advanced Biofuel and Total Renewable Fuel for 2013

As described in Section I, 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). 

For 2013, the applicable volume of advanced biofuel is 2.75 bill gal and the applicable volume of 

total renewable fuel is 16.55 bill gal. However, the statute gives EPA the discretion to reduce 

one or both of these volume requirements in the event that the cellulosic biofuel volume 

requirement is reduced. This section discusses our evaluation of these two volume requirements.

A. Statutory Requirements

According to CAA 211(o)(7)(D)(i), if EPA determines that the projected volume of 

cellulosic biofuel production for the following year is less than the applicable volume provided 

in the statute, then EPA must reduce the applicable volume of cellulosic biofuel to the projected 

volume available during that calendar year. Under such circumstances, EPA also has the 

discretion to reduce the applicable volumes of advanced biofuel and total renewable fuel by an 

amount not to exceed the reduction in cellulosic biofuel. 

Since cellulosic biofuel is also used to satisfy 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 these two other standards. 

Congress presumably established the volume requirements for advanced biofuel and total 

renewable fuel under the assumption that the specified cellulosic biofuel volumes would be 

produced and thus available to help meet these two standards. It is therefore logical to consider a 

possible reduction in the advanced biofuel and total renewable fuel applicable volumes when 

EPA reduces the cellulosic biofuel volume below the applicable volume for cellulosic biofuel set 

forth in the statute. 

In 2013 the applicable volume of cellulosic biofuel specified in the statute represents 

more than a third of the advanced biofuel volume (1.0 bill gal out of 2.75 bill gal), a higher 

fraction than in any previous year. A substantial reduction in the applicable volume of cellulosic 

biofuel could potentially also have a substantial impact on the sufficiency of volumes to meet the 

advanced biofuel and total renewable fuel standards. As described in Section II.D above, we are 

indeed proposing a projected available volume of cellulosic biofuel for 2013 at significantly 

below the statutory applicable volume of 1.0 billion gallons. If we were to finalize a cellulosic 

biofuel applicable volume of 33 mill gallons for 2013, we would have the discretion to reduce 

the advanced biofuel and total renewable fuel applicable volumes by up to 967 mill gallons 

(ethanol-equivalent). Therefore, we believe that an investigation into the need for a reduction in 

the applicable volumes of advanced biofuel and/or total renewable fuel is warranted.

The statute does not provide any criteria that must be met or factors that must be 

considered when making a determination as to whether and to what degree to reduce the 

advanced biofuel and/or total renewable fuel applicable volumes when we have the discretion 

under CAA 211(o)(7)(D)(i) to do so. However, in general we believe that it would not be 

consistent with the energy security and greenhouse gas reduction goals of the statute to reduce 
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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. And, if we do not lower the advanced biofuel standard, 

then our reduction of cellulosic biofuel applicable volume has no impact on the amount of nonadvanced biofuel that could be used in attaining the total renewable fuel standard set forth in the 

Act. Therefore, we believe as a general matter that, when we do not exercise our discretion to 

lower the applicable volume of advanced biofuel under CAA 211(o)(7)(D)(i), our action in 

reducing the cellulosic biofuel applicable volume should not in itself justify a modification of the 

total renewable fuel applicable volume.

B. Assessment of Available Volumes of Advanced Biofuel

Renewable fuels that can be used to meet the standard for advanced biofuel include those 

with Renewable Identification Number (RIN) codes of 3, 4, 5, or 7. Table III.B-1 shows the 

number of each of these types of RIN that was generated in 2011.

Table III.B-1

2011 RINs That Qualified to Meet the Advanced Biofuel Standard9

(million ethanol-equivalent gallons)

D 

code Category Ethanol Biodiesel

Renewable 

diesel

Biogas and 

heating oil

3 Cellulosic biofuel 0 0 0 0

4 Biomass-based 

diesel

0 1,600 76 0

5 Advanced biofuel 186 0 27 8

7 Cellulosic diesel 0 0 0 0

Total 1,895

The total of 1,895 mill ethanol-equivalent gallons is significantly higher than the 1,350 mill gal 

required in 2011 and nearly as high as the 2012 advanced biofuel requirement of 2,000 mill gal. 

This result supports our projection in the rulemaking setting the 2012 standards10 that there was 

no need to reduce the 2012 advanced biofuel requirement despite the significant reduction in the 

applicable volume of cellulosic biofuel.

The statutory volume requirement for advanced biofuel in 2013 is 2,750 mill gal, an 

increase of 750 mill gal over the 2012 requirement of 2,000 mill gal. In order to determine the 

sufficiency of advanced biofuel volumes to meet a requirement for 2,750 mill gal in 2013, we 

first accounted for biomass-based diesel and cellulosic biofuels that would be required under the 

standards we are proposing today. As shown in Table III.B-2, the result is that there would need 

to be about 800 mill ethanol-equivalent gallons of other advanced biofuels in order to meet the 

total advanced biofuel requirement of 2,750 mill gal.

 

9

2011 data from the EPA-Moderated Transaction System (EMTS)

10 77 FR 1320, published on January 9, 2012
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Table III.B-2

Necessary Volume of Advanced Biofuel (mill gal ethanol-equivalent)

2013 Advanced biofuel applicable volume 2,750

Cellulosic biofuel requirement 33

Biomass-based diesel requirement 1,920a

Necessary volume of excess biodiesel, other 

domestic advanced biofuels, and/or imported 

sugarcane ethanol

797

a

 In 2011, a substantial majority of biomass-based diesel was biodiesel. 

Moreover, we expect further increases in biomass-based diesel to be met 

primarily with expanded biodiesel. Therefore, for this analysis we have 

assumed that the 1.28 bill gal requirement is composed entirely of biodiesel with 

an equivalence value of 1.5.

We have identified a variety of sources of advanced biofuel that could meet the need for 

about 800 mill gal of additional advanced biofuel, including the following:

• Biodiesel in excess of that required to meet the volume requirement of 1.28 

bill gal

• Imported sugarcane ethanol

• Domestically produce advanced biofuels such as renewable diesel, heating oil, 

and ethanol from separated food wastes

We have investigated each of these sources as discussed below.

1. Biodiesel

In a separate action, we are finalizing a biomass-based diesel volume of 1.28 bill gal for 

2013. However, we believe that biomass-based diesel volumes above 1.28 bill gal are possible. 

Insofar as other sources of advanced biofuel fall short of what is needed to meet the advanced 

biofuel volume requirement, the biodiesel industry has the potential to fill much if not all of the 

gap. As of February 2012, the aggregate production capacity of biodiesel plants in the U.S. is 

estimated to be 2.5 billion gallons per year across 191 facilities.11 We expect the time and 

reinvestment required to ramp up production at existing facilities to be less than the time 

required to build and begin production at new plants, which takes about a year on average.12 

Thus, restarting idled plants is likely to be a cost-effective way of exceeding the applicable 

volumes of 1.28 bill gal in 2013 if a demand for such production exists.

Moreover, the biodiesel industry has demonstrated that it can increase production quickly 

under appropriate circumstances. Total production of biomass-based diesel in 2011 exceeded 1.0 

bill gal, compared to a 2010 production of about 380 mill gallons.13 In response to the NPRM 

 

11 Figures taken from National Biodiesel Board's Member Plant List as of February 7, 2012. 

12 Based on construction times for new plants listed in Biodiesel Magazine from July 2006 through May 2009.

13 All values from EMTS. 2010 estimate consists of approximately 209 mill gallons as recorded through EMTS for 

volume produced under the RFS2 regulations in July through December of 2010, and approximately 171 mill 
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published on July 1, 2011, some stakeholders expressed doubts that such increases could occur 

by 2012.14 Nevertheless, based on the single-year increase of more than 600 mill gal in 2011 and 

the total capacity of existing plants described above, we believe it is reasonable that the industry 

could achieve increases in production of both the 280 mill gallon increment that is reflected in 

the biomass-based diesel requirement for 2013 and an additional "excess" production of several 

hundred million gallons or more.

2. Imported Sugarcane Ethanol 

From the supply perspective, recent production of sugarcane in Brazil has been lower 

than normally expected due to two factors. First, adverse weather conditions have reduced 

production.15 Since the adverse weather conditions are estimated to have reduced cane 

production by about 4%, a return to normal weather conditions should alone restore 

approximately 4% of production. Second, the general economic downturn made credit harder to 

get, delaying the replanting of existing fields. Normally sugarcane fields are replanted every five 

or six years to maximize yield. However, the lack of available credit caused some growers to 

delay the expense of this replanting, with the older fields losing production.16 Nevertheless, in 

2011 Brazil exported around 520 million gallons of which approximately 173 million gallons 

were shipped to the U.S.

The outlook for 2012 and future years suggests a more typical trend in sugarcane ethanol 

with replanted fields beginning to boost sugarcane production in existing plantations and, in 

response to increased worldwide demand, a growth in the acres planted with sugarcane. UNICA, 

a trade association for the sugarcane ethanol industry in Brazil, projects that over the next four 

years, the return to a normal replanting schedule combined with normal weather conditions will 

boost production by 30%. They project that by 2015/2016, ethanol production in Brazil will 

exceed 12 billion gallons of which over 3 billion gallons could be available for export. Even 

assuming only modest increases in 2012 production due to the need to replant fields, using the 

UNICA projection for 2015/2016 and assuming a linear increase in export volumes from 2012 to 

2016, 2013 sugarcane ethanol export volumes could easily double to over 1 billion gallons in 

2013. Increased production is supported by the Brazilian government which announced in 

February 2012 support for a plan to invest over $8 billion annually to boost cane and ethanol 

production.17 Private investment in Brazil is also increasing. For example, Usina de Acucar 

 

gallons as recorded through RIN generation reports submitted by producers for volume produced under the RFS1 

regulations in January through June of 2010.

14 See comments in docket EPA-HQ-OAR-2010-0133 from the American Petroleum Institute, Marathon Petroleum 

Company, and the National Petrochemical Refiners Association.

15 Gain Report BR110016, October 3, 2011, USDA Agricultural Service. See 

http://gain.fas.usda.gov/Recent%20GAIN%20Publications/Sugar%20Semiannual_Sao%20Paulo%20ATO_Brazil_10-3-2011.pdf 

16 On the margin, the high sugar prices may have also encouraged some growers to divert their crop from ethanol 

production to sugar production. But most cane growers do not have this flexibility with sugarcane mills designed 

for fixed amounts of refined sugar or ethanol so high sugar prices was likely a contributing factor but not a major 

cause of reduced sugarcane ethanol production in Brazil.

17 See http://www.platts.com/RSSFeedDetailedNews/RSSFeed/Oil/8987702
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Santa Terezinha, a Brazilian ethanol producer, recently announced plans to invest almost $300 

million in a new mill and sugarcane plantation.18 

Brazil’s sugarcane ethanol production serves both its domestic market as well as the 

export market. The government of Brazil sets a minimum ethanol concentration for its gasoline. 

In 2011, the Brazilian government lowered this concentration to 20%, reflecting the decrease in 

domestic production. Projecting this Brazilian domestic demand into the future can be 

uncertain since the government can reset the minimum ethanol content at any time; in the past 

this adjustment has largely been influenced by the price of ethanol (high prices leading to a 

reduction in the minimum percent). However, these historical changes have typically varied by a 

few percent and have only occurred periodically. Assuming continued tight supplies of 

sugarcane ethanol, we would not expect a near-term increase in the minimum concentration of 

ethanol in gasoline in Brazil and no significant change in demand for ethanol within Brazil over 

the next couple of years. 

Aside from production capability and domestic demand within Brazil, market conditions 

generally determine the availability of sugarcane ethanol imported into the U.S. from Brazil. 

Approved as an advanced biofuel pathway, ethanol produced from sugarcane benefits from the 

RIN value associated with advanced biofuel but also has to compete with other sources of 

ethanol used for blending with gasoline, most notably ethanol made from corn starch (which 

does not qualify as an advanced biofuel). However, the expiration of the tariff applicable to 

imported ethanol has also helped make imported sugarcane ethanol more cost competitive. 

As a result of this investigation, we have concluded that there are no definite barriers to 

the importation of sugarcane ethanol up to the volumes required (considering the availability of 

other advanced biofuels) to meet an advanced biofuel requirement of 2.75 bill gal. 

3. Domestic Production of Other Advanced Biofuel 

Pathways that have been approved for the generation of RINs are provided in the 

regulations in Table 1 to §80.1426. Apart from ethanol made from sugarcane which is permitted 

to generate advanced biofuel RINs, there are currently three pathways through which advanced 

biofuel RINs can be generated. These three are shown in Table III.B.3-1.

 

18 See http://www.bloomberg.com/news/2012-03-08/santa-terezinha-invests-283-million-in-brazil-ethanolprojects.html
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Table III.B.3-1

Pathways for Advanced Biofuel

Fuel type Feedstock Production process 

requirements

Biodiesel, 

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

Ethanol, renewable 

diesel, jet fuel, 

heating oil, and 

naphtha

The non-cellulosic portions of 

separated food waste Any

Biogas Landfills, sewage waste treatment 

plants, manure digesters Any

In addition to producers of biomass-based diesel and cellulosic biofuel, there are many 

companies either producing or developing technologies to produce "other advanced biofuels." In 

order to estimate the volumes of other advanced biofuels that could be produced by these 

companies in 2013, we investigated three sources of data:

Production Outlook Reports. Required under §80.1449 for all registered producers, these 

reports contain projections of renewable fuel production for each of the next five years.19

2011 producers. Data from the EPA-Moderated Transaction System (EMTS) was 

reviewed to identify parties that produced some RIN-generating advanced biofuel in 

2011. Insofar as such parties did not provide a projected 2013 volume in a Production 

Outlook Report, they were contacted to update their 2013 projected production volume.

Additional registered producers. We identified parties that were registered as producers 

of advanced biofuel under the RFS program, but neither produced RIN-generating 

volume in 2011 nor provided a projection of 2013 production volume in a Production 

Outlook Report. We contacted such parties to determine what, if any, volume could be 

expected in 2013.

Based on these investigations, we identified twenty domestic companies that are expected to 

produce some other advanced biofuel in 2013. The total projected production volume for these 

companies in 2013 is about 115 mill actual gallons, or 150 million ethanol-equivalent gallons, as 

shown in Table III.B.3-2.

 

19 While the individual reports have not been published since they include company-specific information that could 

impact the competitive nature of the industry, we are providing aggregate results in this NPRM.
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Table III.B.3-2

Projected Domestic Production of Other Advanced Biofuel in 2013

(million ethanol-equivalent gallons)

Ethanol

Renewable 

diesel Heating oil CNG Total

Production Outlook 

Reports

31 35 4 0 70

2011 producers 18 18 0 5 41

Other registered 

producers

0 15 15 9 39

Total 49 68 19 14 150

A projected volume of 150 mill ethanol-equivalent gallons of other advanced biofuel in 2013 is 

also consistent with a 2011 report released by E2/Environmental Entrepreneurs20 which 

estimated that the production capacity of domestic advanced biofuels in 2012 would be about 

180 mill gal.

We are also currently investigating a variety of other potential RIN-generating pathways 

for advanced biofuel that could result in additional volumes in 2013. In addition to potential new 

pathways for cellulosic biofuel that would also count as advanced biofuel as discussed in Section 

II.D, new pathways for advanced biofuel could include certain butanol processes from corn and 

certain ethanol processes from sorghum. We have not yet determined, either through rulemaking 

or approval of an industry petition, whether the pathways are valid for the generation for 

advanced biofuel RINs. However, approval of such advanced biofuel pathways could potentially 

result in 200 million additional ethanol-equivalent gallons of advanced biofuel being qualified to 

participate in the RFS program. Insofar as any of these pathways are approved in time to be used 

in 2013, we may include projected volumes for them as we prepare the final rulemaking setting 

standards for 2013.

C. Proposed Volume Requirements for Advanced Biofuel and Total Renewable Fuel 

in 2013 

As shown in Table III.B-2, in order for an advanced biofuel requirement of 2.75 bill gal 

to be met, there would need to be about 800 mill gal of advanced biofuels in addition to the 

volumes that would need to be produced to meet the biomass-based diesel and cellulosic biofuel 

requirements. After reviewing the projected availability of advanced biofuel volumes from 

various sources, we have determined that there will be more than sufficient volumes available to 

produce or import this 800 mill gal. Given our estimate of about 150 mill gal of domestic 

"other" advanced biofuel, the remaining volume of about 650 mill gal would likely need to come 

from imported sugarcane ethanol and/or biodiesel in excess of 1.28 bill gal. As discussed above, 

we believe that this volume is achievable through a combination of these sources or potentially 

even through one of these individual sources. Therefore, we believe that there is no reason to 

 

20 Solecki, Mary et al, "Advanced Biofuel Market Report 2011, Meeting the California LCFS" August 22, 2011. 

E2/Environmental Entrepreneurs.
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reduce the required volume of 2.75 bill gal advanced biofuel on the basis of available volumes. 

As noted above, maintaining the 2.75 bill gal advanced biofuel volume set forth in the statute 

will result in the GHG emissions and energy security objectives that Congress envisioned in 

enacting this provision. We are not aware of any reasons why it should choose to forgo these 

benefits when they are physically achievable but we invite comment on this issue.

We also expect that there will be sufficient volumes of corn ethanol to meet the need for 

13.8 bill gallons of conventional renewable fuel since domestic production of corn ethanol 

reached this level in 2011.21 Moreover, corn ethanol production capacity continues to increase. 

Since we are not proposing to lower the advanced biofuel standard for 2013, and the need for 

13.8 bill gallons of conventional renewable fuel can be met, we are not proposing to lower the 

applicable volume of total renewable fuel below 16.55 bill gal.

 

21 EIA Monthly Energy Review, February 2012, Table 10.3.
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IV. Proposed Percentage Standards for 2013

A. Background 

The renewable fuel standards are expressed as volume percentages 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 every obligated 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.D, we are proposing a required volume of cellulosic biofuel for 

2013 of 26 million gallons (33 million ethanol-equivalent gallons). The volume we select for the 

final rule will be used as the basis for setting the percentage standard for cellulosic biofuel for

2013. 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 biomass-based diesel 

volume for 2013 has been established at 1.28 billion gallons through a separate rulemaking. The 

volumes used to determine the four proposed percentage standards are shown in Table IV.A-1. 

Table IV.A-1

Proposed Volumes for Use in Setting the Applicable Percentage Standards for 2013a

Cellulosic biofuel 33 mill gal

Biomass-based diesel 1.28 bill gal

Advanced biofuel 2.75 bill gal

Renewable fuel 16.55 bill gal

a Due to the manner in which the percentage standards are 

calculated, all volumes are given in terms of ethanolequivalent except for biomass-based diesel which is given 

in terms of physical volume

As with previous years’ renewable fuels standards determination, the formulas used in 

deriving the annual standards are based in part on estimates of the volumes of gasoline and diesel 

fuel, for both highway and nonroad uses, that are projected to 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): 
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(Gi RGi) (GSi RGSi) GEi (Di RDi) (DSi RDSi) DEi

RFV Std 100%CB,i

CB,i

(Gi RGi) (GSi RGSi) GEi (Di RDi) (DSi RDSi) DEi

RFV 1.5

Std 100%

BBD,i 

BBD,i

(Gi RGi) (GSi RGSi) GEi (Di RDi) (DSi RDSi) DEi

RFV Std 100%AB,i

AB,i

(Gi RGi) (GSi RGSi) GEi (Di RDi) (DSi RDSi) DEi

RFV Std 100%RF,i

RF,i

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.
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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 = 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 2013, this value is zero. See further discussion in 

Section IV.B.2 below.

DEi = 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 2013, this value is zero. See further discussion in 

Section IV.B.2 below.

The four separate renewable fuel standards for 2013 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 volumes of gasoline and diesel that will be used to 

calculate the final 2013 percentage standards will be provided to EPA by EIA by October 31, 

2012. To estimate the gasoline and diesel projected volumes for the purposes of this proposal, 

we have used EIA's Short-Term Energy Outlook (STEO)22 for the gasoline projection and EIA's 

Annual Energy Outlook 2012 Early Release23 for the diesel projection. 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 to EPA by EIA by October 31, 2012. To estimate the ethanol and biodiesel 

projected volumes for the purposes of this proposal, we have used the February 2012 values24 for 

ethanol and biodiesel provided in the STEO. 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.

 

22 Energy Information Administration/Short-Term Energy Outlook - February 2012, Table 4a, “U.S. Crude Oil and 

Liquid Fuels Supply, Consumption, and Inventories.”

23 Energy Information Administration/Annual Energy Outlook 2012, Early Release (January 23, 2012), Table 2, 

“Energy Consumption by Sector and Source, United States, Reference case.” 

24 Energy Information Administration/Short-Term Energy Outlook - February 2012, Table 8, “U.S. Renewable 

Energy Supply and Consumption (Quadrillion Btu).”
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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 our initial 

rulemaking to implement the new RFS program25, 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. 

40 CFR §§ 80.1141, 80.1142. Because EISA did not alter the small refinery exemption in any 

way, the RFS2 program regulations maintained the exemptions for gasoline and diesel produced 

by small refineries and small refiners through 2010 (unless the exemption was waived). See 40 

CFR §§ 80.1441, 80.1442. 

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 whether 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.26 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 standards as there was for the 2010 standards. 

Following the release of DOE's 2009 small refinery study, Congress directed DOE to 

complete a reassessment and issue a revised report. In March of 2011 DOE re-evaluated the 

impacts of the RFS program on small entities and concluded that some small refineries would 

suffer a disproportionate hardship.27 As a result, EPA exempted these refineries from being 

obligated parties for two additional years, 2011 and 2012.28 The 2012 standards established in 

the January 9, 2012, final rulemaking reflected the exemption of these refineries. 

EPA may extend the exemption for individual small refineries or small refiners on a caseby-case basis if they demonstrate disproportionate economic hardship. 40 CFR §§ 

80.1441(e)(2), 80.1442(h). EPA has granted some exemptions pursuant to this process that 

apply in 2011 and 2012. However, at this time, no exemptions have been approved for 2013. 

 

25 72 FR 23900, May 1, 2007.

26 DOE report “EPACT 2005 Section 1501 Small Refineries Exemption Study”, (January, 2009). 

27 "Small Refinery Exemption Study: An Investigation into Disproportionate Economic Hardship," U.S. Department 

of Energy, March 2011.

28 Since 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.
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Therefore, for this proposal we have calculated the proposed 2013 standards without a small 

refinery/small refiner adjustment.

However, if an individual small refinery or small refiner requests an exemption and is 

approved following the release of this NPRM, the final standards will be adjusted to account for 

the exempted volumes of gasoline and diesel. Any requests for exemptions that are approved 

after the release of the final 2013 RFS standards will not affect the 2013 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 2013 standards are 

finalized, any additional exemptions for small refineries or small refiners that are issued will not 

affect those 2013 standards.

3. Proposed Standards

As specified in the March 26, 2010 RFS2 final rule29, the percentage standards are based 

on energy-equivalent gallons of renewable fuel, with the cellulosic biofuel, advanced biofuel, 

and total renewable fuel standards based on ethanol equivalence and the biomass-based 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 

1.28 billion physical gallons of biomass-based diesel will be created in 2013, the calculation of 

the biomass-based 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 gallon toward the biomass-based 

diesel standard, but worth 1.5 gallons toward the other standards.

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 because the gasoline and diesel volumes estimated by EIA include renewable 

fuel use, we must subtract the total renewable fuel volumes from the total gasoline and diesel 

volumes to get total non-renewable gasoline and diesel volumes. The values of the variables 

described above are shown in Table IV.B.3-1.30 Terms not included in this table have a value of 

zero.

 

29 75 FR 14716, March 26, 2010.

30 To 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 (2010) 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 11.2% of its 

gasoline consumption (based on the same State data), and biodiesel use is assumed to be zero.
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Table IV.B.3-1

Values for Terms in Calculation of the Standards (bill gal)

Term Value

RFVCB,2013 0.033

RFVBBD,2013 1.28

RFVAB,2013 2.75

RFVRF,2013 16.55

G2013 132.94

D2013 46.46

RG2013 13.91

RD2013 1.02

Using the volumes shown in Table IV.B.3-1, we have calculated the proposed percentage 

standards for 2013 as shown in Table IV.B.3-2.

Table IV.B.3-2

Proposed Percentage Standards for 2013

Cellulosic biofuel 0.020%

Biomass-based diesel 1.18%

Advanced biofuel 1.69%

Renewable fuel 10.15%
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V. Proposed Volume Requirement for Biomass-Based Diesel in 2014

In today's action we are coproposing an applicable volume of 1.28 or 1.39 billion gallons 

biomass-based diesel for 2014 in accordance with the statutory requirement in CAA 

211(o)(2)(B)(ii) 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. In the 

course of our 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 biomass-based diesel standard. When 

appropriate, we have discussed renewable diesel separately from biodiesel.

In coproposing the 2014 applicable volume of biomass-based diesel, we are not at this 

time proposing the percentage standards that would apply to obligated parties in 2014. Nor will 

we adopt a final percentage standard when this rule is finalized at the end of 2012. Instead, the 

percentage standards for 2014 will be determined after projections of gasoline and diesel volume 

are provided by the Energy Information Administration (EIA) in the fall of 2013 and will be 

announced by November 30, 2013. We are also not proposing any applicable volumes of 

biomass-based diesel for 2015 or later years in today's action. 

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 statute31. 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 under 211(o)(2)(B)(ii) 

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 on 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 

 

31 For example, EPA may waive a given standard in whole or in part following the provisions at CAA 211(o)(7).
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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. 

The statute envisions annual increases in applicable volumes of renewable fuels leading 

to 36 bill gallons by 2022. In considering potential increases in the applicable volume 

requirement for biomass-based diesel, we believe that certain factors that we must consider under 

the statute are most appropriately analyzed in the longer term, after the full build-up of 

renewable fuel production and use envisioned by the statute are in place. Others factors are more 

appropriately analyzed for the near term, including production capacity, availability of 

feedstocks, and impacts on infrastructure. These are factors that could limit the successful 

implementation of any increment in required applicable volume. We believe that other factors 

are appropriately considered over a longer term, since full build-up of the RFS program is 

expected to generate benefits over many years, and short-term considerations should not impede 

attainment of long term goals and benefits. We believe that greenhouse gas emissions are one 

factor for which taking a long-term view is appropriate. Finally, certain factors, such as energy 

security, may be evaluated for both near- and long-term benefits. Thus for this NPRM, we have 

not simply looked at the impacts of the program in any one year with near term implementation, 

but have also looked at the evolving pattern of impacts through time where it is appropriate to do 

so.

It is useful to note that the statutory provisions described above are silent in two 

important areas. For instance, the statute does not provide numerical criteria or thresholds that 

must be attained when EPA determines the applicable volume of biomass-based diesel for years 

after 2012 (other than specifying a minimum volume of 1.0 bill gal), nor does it describe any 

overarching goals such as maximizing GHG benefits or energy security benefits, maximizing or 

minimizing supply of renewable fuel, or minimizing cost. Since the statute is silent on these 

matters, we believe that EPA, in coordination with DOE and USDA, is simply 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. 

We also note that 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 biomass-based diesel volume requirement above the 

minimum of 1.0 bill gal would not have any impact on the advanced biofuel or total renewable 
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fuel volume requirements. While increasing the biomass-based diesel volume requirement above 

the 1.0 bill gallons minimum value specified in the statute could result in a change in the makeup 

of biofuels used to meet the advanced biofuel and the total renewable fuel standards, doing so 

would not change the total required volumes of those fuels (in terms of ethanol-equivalent 

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. 

B. Factors Considered in Assessing 2014 Biomass-Based Diesel Volumes

As described in Section V.A, we are required to review the implementation of the RFS 

program for prior years and to use information from this review in determining the applicable 

volume of biomass-based diesel for 2014. Ideally we would have information on the 

implementation of the program up through 2013 before determining the appropriate biomassbased diesel volume for 2014. However, since we are required to set the applicable volume 14 

months in advanced, the most recent information we will have available by the time of the final 

rule will be for the implementation of the program in the first half of 2012. For today's NPRM, 

the most recent information we currently have available is for 2011 and early 2012. 

According to data collected through the EPA-Moderated Transaction System (EMTS) 

and the National Biodiesel Board, production of biodiesel in 2011 exceeded 1.0 bill gal.32 This 

demonstrates that the industry was able to meet and exceed the applicable 2011 volume 

requirement of 800 mill gal despite producing only half of this volume requirement in the 

previous year. It also provides strong evidence that the industry will exceed 1.0 bill gal in 2012 

when the applicable volume requirement is 1.0 bill gal, and additional volumes above 1.0 bill gal 

may be used to help meet the advanced biofuel standard. It also supports our finding, made in a 

separate rulemaking, that industry can achieve an applicable volume requirement of 1.28 bill gal 

in 2013. Indeed current production rates in the biodiesel industry are consistent with a total 

production volume of around 1.3 bill gal for 2012. Further discussion of our reasons for 

finalizing a biomass-based diesel volume of 1.28 bill gal for 2013 can be found in the preamble 

to a separate final rule.

In order to investigate the potential for and impacts of volumes of biomass-based diesel 

above 1.28 bill gal in 2014, we considered the volume of 1.39 bill gal that was projected in the 

RFS2 final rule. This volume was based primarily on a projection of the qualifying feedstocks 

that could be available in 2014 and was part of efforts to develop renewable fuel volume 

scenarios for all years between 2010 and 2022. This biomass-based diesel volume has already 

been partially evaluated in the RFS2 final rule. In keeping with the statutory provision regarding 

biomass-based diesel volumes in years after 2012, we considered whether 1.39 bill gal of 

biomass-based diesel was reasonable given likely market demand, availability of feedstocks, 

production capacity, and potential limitations related to blending and consumption, and also 

 

32 Fuels and Fuel Additives 2011 EMTS Data, updated on January 27, 2012.
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considered the impacts such a volume would have in terms of factors specified in the statute, 

GHG emissions, energy security, costs, impacts to wetlands and wildlife, and others.

1. Demand for Biomass-Based Diesel

The demand for biomass-based diesel in 2014 will be a function of not only the biomassbased diesel standard, but also the advanced biofuel standard, since the standards under the RFS2 

program are nested. The applicable volume of advanced biofuel specified in CAA 

211(o)(2)(B)(i) for 2014 is 3.75 bill gal. While we have authority to reduce this advanced 

biofuel applicable volume during next year's rulemaking process if we reduce the cellulosic 

biofuel volume for 2014, we have assumed for the purposes of this proposed rulemaking that this 

3.75 bill gal volume will be used in setting the 2014 advanced biofuel standard. 

To assess the demand for biomass-based diesel in 2014, we first assumed that the 

biomass-based diesel volume requirement would be 1.39 bill gal and that the applicable volume 

of advanced biofuel would be 3.75 bill gal. After accounting for the required biomass-based 

diesel volume (which represents about 2.09 bill gal ethanol-equivalent), there would remain 1.66 

bill gal of advanced biofuel that would be needed to meet the applicable volume of 3.75 bill gal. 

There are a limited number of biofuels that are likely to be available in 2014 to meet the need for 

1.66 bill gal advanced biofuel. These include:

• Cellulosic biofuel

• Other domestically produced advanced biofuels, such as co-processed renewable 

diesel, butanol, or CNG from landfill gas

• Imported sugarcane ethanol

We expect cellulosic biofuel volumes to fall substantially short of the 1.75 bill gal statutory 

applicable volume requirement for cellulosic biofuel in 2014, and thus these biofuels would only 

meet a small portion of the 1.66 bill gal of advanced biofuel needed. With regard to other 

domestically produced other advanced biofuels, we have projected about 150 mill gal for 2013. 

However, the ongoing investigation of additional RIN-generating pathways for advanced biofuel 

could result in additional volumes from these sources in 2014. 

The demand for biomass-based diesel in 2014 is also a function of the volumes of 

sugarcane ethanol that could be imported from Brazil. These import volumes are primarily a 

function of demand generated by RIN prices, and less a function of limitations imposed by 

ethanol demand in Brazil; the minimum legal demand for ethanol in Brazil is currently about 5 

bill gal, considerably less than Brazilian production. Based on a comparison of production 

potential and the minimum legal demand in Brazil, imports into the U.S. of 1.0 bill gal of 

sugarcane ethanol are possible. 

To the degree that limits arise in the volumes of sugarcane ethanol that are imported into 

the U.S. or other domestically-produced advanced biofuels, additional biomass-based diesel 

would be needed to ensure the advanced biofuel standard of 3.75 bill gallons could be met. 

While we are not projecting specific volumes of cellulosic biofuel, imported sugarcane ethanol, 
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and other domestically produced advanced biofuels in today's NPRM, it appears possible that the 

advanced biofuel volume requirement of 3.75 bill gal could drive the production of biodiesel 

higher than 1.39 bill gal. 

2. Availability of Feedstocks

We do not anticipate any shortfall in biodiesel feedstock under a proposed applicable 

volume of 1.39 bill gal for biomass-based diesel in 2014. In a separate action we have addressed 

feedstock availability under the 2013 requirement of 1.28 bill gal. We have assumed in our 

analysis of 1.39 bill gal that the additional 110 mill gal would be produced primarily from 

soybean oil, bringing total soybean-based biodiesel production to 710 mill gal in 2014. We also 

project that 680 mil gal of biodiesel made from corn oil and waste fats, oils, and greases would 

enter the market and contribute to the 1.39 bill gal mandate in 2014 (see Table V.B.2-1).

Table V.B.2-1

Projected Volumes for Feedstock Contributing to the 2014 Biodiesel Mandate

Projected Feedstock Projected Volume

(in million gallons)

Waste Fats, Oils, and Greases 380

Corn Oil 300

Soybean Oil 710

Total 1,390

a. Waste Fats, Oils, and Greases

Waste feedstocks such as oils, fats, and greases are not produced for the purpose of 

biodiesel production. As a result, an increase in the demand for biodiesel would not be expected 

to generate a corresponding increase in their supply. Therefore, an increase in the required 

volume of biomass-based diesel from 1.28 bill gal in 2013 to 1.39 bill gal in 2014 is unlikely to 

cause the supply of these feedstocks to increase. 

In our analysis for the 2013 biomass-based diesel standard, we determined that the U.S. is 

likely to produce over 800 mill gal of potential waste feedstocks in 2013. There is no reason to 

believe that 2014 production levels will be lower. However, these potential feedstocks have 

alternate uses in the oleochemical industry and others, leading us to conclude that a significant 

portion of available waste feedstocks will not be used for biodiesel production. Based on our 

RFS2 final rule analysis, we estimated 380 mill gal of biodiesel to come from waste feedstocks 

in 2013 and we anticipate this same volume of production in 2014.

It is possible that biodiesel production from waste feedstocks could be greater than 380 

mill gal in 2014. Demand from alternate uses could decrease. The production of waste 

feedstocks could also increase for reasons other than demand from the biofuels industry. 

Further, EPA did not include several potential sources of waste feedstocks, such as edible tallow, 

lard, and poultry fats, in our 2013 estimate. While these other potential feedstocks have existing 
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markets, it may become economical for them to be used in the production of biomass-based 

diesel in 2014. However, these additional sources remain uncertain at best. Because of this, we 

are making the conservative assumption that they will not contribute to the 2014 biomass-based 

diesel volumes.

b. Corn Oil

Based on our analysis conducted for the 2013 biomass-based diesel volume requirement 

of 1.28 bill gal, we expect 300 million gallons of biodiesel to be produced from corn oil in 2014. 

Non-food grade corn oil production may increase in 2014 relative to 2013. However, the 

installation rate of this technology has to date exceeded what we had anticipated, meaning that 

this rate may decrease by 2014. Therefore, we are conservatively estimating the volume of 

biodiesel produced from corn oil to remain at 300 mill gal in 2014. 

As with waste feedstocks, several factors could lead biodiesel production from corn oil to 

exceed 300 mill gal in 2014. Corn ethanol producers may increase their adoption of oil 

extraction technologies beyond our expectations for 2014. Extraction yields may also increase 

beyond our projections. Further, our 2013 analysis did not consider any corn oil from 

fractionation at dry mill plants or from any wet milling processes. Production of corn oil from 

these sources may also increase the amount available for biodiesel use. However, like additional 

potential sources of waste feedstocks, these additional sources of corn oil remain uncertain. EPA 

is therefore making the conservative assumption that they will not contribute to the 2014 

biomass-based diesel volumes.

c. Soybean Oil

Since the RFS2 program began, other oilseeds (e.g., canola oil) have emerged as potential 

sources of biodiesel feedstock. However, the U.S. market for soybean oil biodiesel is 

significantly more mature than for biodiesel made from other oilseeds. Because of this, we 

anticipate that soybeans will remain the primary source of U.S. biodiesel from oilseeds in 2014. 

It is possible that biodiesel production from other oilseeds with approved pathways, such as 

canola, could achieve a significant level of production by 2014. If other oilseeds with approved 

pathways are able to contribute to the biodiesel volumes, achieving the biomass-based diesel 

mandate would be facilitated. For the purposes of this analysis, EPA is making the conservative 

assumption that there will be no biodiesel production from other oilseeds in 2014.

We conclude that there will be sufficient supplies of soybean oil to meet the needs of 

both increased biodiesel production and other domestic uses in 2014. EPA is projecting that, 

under the proposed 1.39 bill gal mandate, a total of 710 mill gal of soybean-based biodiesel 

would be produced. This would require 5,361 mill pounds of soybean oil, 7.55 pounds for every 

gallon of soybean-based biodiesel. 

Table V.B.2-2 below lists U.S. Department of Agriculture (USDA) historical data and 

current projections for U.S. supply and use of soybean oil from the 2006/2007 crop year to the 
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2014/2015 year. Since 2006/2007, domestic use of soybean oil for non-biodiesel purposes has 

ranged from 14,134 million pounds to 15,813 million pounds. USDA projects non-biodiesel use 

will stay above 14,000 million lbs through the 2014/2015 year. 

Table V.B.2-2

Historical Supplies and Use of Soybean Oil in the U.S. (in million lbs)

Year Starts 

October 1

Total 

Supplies

Domestic 

Use for NonBiodiesel 

Purposes

Available for 

Biofuel 

Feedstock 

Use or 

Export

Historical 

Exports

Historical 

Biofuel 

Feedstock 

Use

2006/07 23,536 15,813 7,723 1,877 2,762

2007/08 23,730 15,089 8,641 2,911 3,245

2008/09 21,319 14,196 7,123 2,193 2,069

2009/10 22,578 14,134 8,444 3,359 1,680

2010/11 22,452 14,244 8,208 3,233 2,550

2011/12a21,215 14,100 7,115 * *

2012/13a21,075 14,200 6,875 * *

2013/14a21,290 14,400 6,890 * *

2014/15a21,565 14,675 6,890 * *

a Projected volumes.

Source: USDA, Agricultural Marketing Service, Oil Crops Outlook, February 10th, 2012. USDA, Economic 

Research Service, Agricultural Long-Term Projections, February 2012.

USDA projects that 6,890 mill pounds of soybean oil will be available for biofuel 

feedstock use and/or export in the 2013/2014 and 2014/2015 crop years (see Table V.B.2-2). 

This is considerably more than the 5,361 mill pounds needed to meet the proposed 1.39 bill gal 

biodiesel applicable volume requirement. For this reason, we do not anticipate any shortage in 

availability of soybean oil feedstock for biodiesel production in 2014 under the proposed volume 

requirement of 1.39 bill gal.

d. Effects on Food Prices

In order to determine the likelihood of a substantial increase in food prices, EPA 

projected the effects of a 1.39 billion gallon mandate using the CARD stochastic modeling 

framework discussed in Section V.C.4. Assuming that the 110 mil gal increment is met entirely 

with soybean oil biodiesel in 2014, we project that the price of soybean oil would be 

approximately $0.47 per pound under a volume requirement of 1.39 bill gal, compared to 

approximately $0.45 under a 1.28 bill gal volume requirement. We estimate that the real 

increase in price would be 1.5 cents, or about 3.4 percent. The increase in demand for soybean 

oil is also expected to have a small impact on the price of soybeans. We project that the price of 

soybeans would be $10.48 per bushel under a volume requirement of 1.39 bill gal, compared to 

$10.39 per bushel under a 1.28 bill gal volume requirement. This represents a price increase of 9 

cents or about 0.9 percent. These projections for soybeans and soybean oil are within the recent 

historical range of price fluctuations (see Table V.B.2-3).
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Table V.B.2-3

Historical and Projected Prices of Soybeans and Soybean Oil 

(2010 dollars per lb)

Soybean Oil Soybeans

2007-2012 Low Annual Average Price $0.33 per lb $9.70 per bushel

2007-2012 High Annual Average Price $0.54 per lb $12.36 per bushel

2014 Projected Price $0.47 per lb $10.48 per bushel

2022 Projected Price $0.42 per lb $9.36 per bushel

Sources: USDA, Agricultural Marketing Service, Oil Crops Outlook, February 10th, 2012. USDA, Economic 

Research Service, Agricultural Long-Term Projections, February 2012.

The timeframe of this rulemaking did not permit large-scale modeling of the impacts of a 

volume requirement of 1.39 bill gal on the agricultural sector. We therefore cannot predict the 

exact impact that these increases in soybean and soybean oil prices would have on food prices in 

general. However, given that projected prices for soybeans and soybean oil fall within the range 

of recent historical prices, we do not expect a volume requirement of 1.39 bill gal to cause any 

significant variations in food prices. As noted above, these volume and price results assume that 

all 110 mill gal are soybean-based. To the extent that this increment was met with other 

feedstocks, the overall effect of a volume requirement of 1.39 bill gal on the price of soybeans 

and soybean oil would be smaller. Further, USDA currently predicts a long-run decline in 

soybean and soybean oil prices over the next decade. Soybean prices are predicted to decline 

from the historical peak of $12.36 per bushel in 2011 to $9.36 per bushel by the beginning of 

2022 (in 2010 dollars). The price of soybean oil is predicted to decline from a 2010 peak of 

$0.54 per pound to $0.42 per pound by the beginning of 2022. Our projections fit within this 

general decline in prices, further bolstering the assessment that a volume requirement of 1.39 bill 

gal would not significantly affect food prices. Finally, as part of our analysis for the RFS2 final 

rule, we estimated that the total impact of the program on food prices from all sources would be 

about $10 per person.33 Given that an increase of 110 mill gal represents less than 1 percent of 

the 36 bill gal of biofuels analyzed for that rule, this analysis also indicates that the effects on 

food prices stemming from a volume requirement of 1.39 bill gal would be minimal.

3. Production Capacity 

Total potential production capacity of the biodiesel industry has exceeded 1.28 bill 

gallons for a number of years. As of February 2012, total production capacity was more than 2.5 

bill gallons for 191 companies34. According to EPA's registration database, 216 biodiesel 

production facilities have registered with the EPA under the RFS2 program as of March 15, 

2012. Plants that are currently not registered under RFS2 are likely 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.

 

33 Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis, Chapter 5: Economic Impacts and 

Benefits, Section 5.1 Agricultural Impacts, 2010.

34 Plant list from National Biodiesel Board, Feb 7, 2012.
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Most of the production capacity exists at plants that are already producing some volume, 

and many operating biodiesel plants are currently producing at less than their full capacity. As a 

result, if these facilities increased production volumes they typically would not need to go 

through the additional steps that are associated with starting up an idled plant, such as securing 

new financing, establishing contracts with feedstock suppliers and customers, hiring and 

retraining employees, and testing and proving the equipment. Nevertheless, since new plants can 

be built and started within a year or so, we also believe that pre-existing but idled plants can be 

restarted in considerably less time. Actual production of biodiesel in 2011 demonstrates how 

quickly unused capacity can be brought back online. In 2010, the biodiesel industry produced 

about 400 mill gal. In 2011, the volume requirement for biomass-based diesel was 800 mill gal, 

but the industry produced over 1.0 bill gal. Given the time available between now and the 

beginning of the 2014 compliance year, there is no reason to believe that additional unused 

capacity cannot be put into production in time to contribute meaningfully to total volumes in 

2014.

In 2011 just over 45 million gallons of non-ester renewable diesel were produced in the 

United States. We project that by 2014 renewable diesel production could increase to over 210 

million gallons as Dynamic Fuels continues to increase annual production volumes and a second 

facility, Diamond Green Diesel progresses towards full-capacity production. Dynamic Fuels, a 

joint venture between Tyson Foods and Syntroleum, is currently operating a renewable diesel 

facility in Geismar, Louisiana capable of producing 75 million gallons of renewable diesel per 

year from fats, greases, and vegetable oils. Fuel production at this facility started in November 

2010 and continued throughout 2011. By the summer of 2011 production at this facility was 

approaching full capacity. EPA expects renewable diesel production from Dynamic Fuels’ 

Geismar facility to be at or near 75 million gallons in 2014.

Diamond Green Diesel, a joint venture between Valero and Darling International, started 

site construction at their first commercial facility in Norco, Louisiana in January 2012. This 

facility will be located adjacent to an existing refinery, and the construction will be funded by 

Valero. When completed, this facility will have a nameplate capacity of 137 million gallons of 

renewable diesel per year. Waste products from Darling’s rendering process will be provided as 

feedstock for this facility. Construction is expected to be completed in early 2013, which should 

allow Diamond Green Diesel to produce at or near their production capacity in 2014. At this 

time EPA is not aware of any other commercial-scale renewable diesel production facilities with 

plans to produce fuel in 2014.

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) in highway diesel fuel. As there are no equivalent registration 

requirements for non-highway fuels, biodiesel can also legally be used at any blend level in 

nonroad diesel and heating oil. However, other factors (such as engine warranties and the 

possibility of cold weather) typically limit the concentration of biodiesel in conventional diesel 

fuel. To the extent that these factors lead to the consumption of biodiesel at lower blend levels, 
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there would be a corresponding impact on how much biodiesel can be consumed in the U.S. as a 

whole.

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 of 

those, about half allow no more than B535. For specific applications where a party is purchasing 

bulk quantities of diesel fuel for designated engines, purchasing fuel with relatively 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 or less.

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 2014 from the EIA, a 

biodiesel volume of 1.39 bill gallons would represent about 3% of all diesel fuel36. If all 

biodiesel were to be blended as B5, about 60% of the diesel fuel consumed nationwide in 2014 

would contain biodiesel. However, today some biodiesel is blended at concentrations higher 

than B5, and we expect that some blending at these higher concentrations would continue in the 

future in certain markets. Blends above B5 have been sold in recent years despite the cost 

difference between biodiesel and conventional diesel. Thus we believe that the existing markets 

for blends such as B20 are niche markets that will continue into the future. The sale of biodiesel 

blends higher than B5 will reduce the total amount of diesel fuel that will contain some biodiesel. 

Directionally, then, this will also reduce the geographical areas to which biodiesel must be 

distributed. 

 

35 "Automaker's' and Engine Manufacturers' Positions of Support for Biodiesel Blends," Biodiesel.org

36 Assumes total diesel volume consumed in the transportation sector in 2014 is 46.22 bill gal, per Annual Energy 

Outlook (AEO) 2012 Early Release, Table A2.
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Based on the number of retail stations offering different biodiesel blend levels in 2010, 

we estimate that about 30% of biodiesel was sold at retail in blends with biodiesel concentrations 

as high as 20%. Another 17% of biodiesel was sold in blends with biodiesel concentrations 

between 10% and 20%.37 If such trends continued, more than half of all biodiesel would be sold 

in blends higher than B5. However, since even these niche markets may change under a 

nationwide volume requirement for 1.39 bill gallons, we have not quantified the volume of 

biodiesel that is likely to be sold in blends higher than B5 in 2014 for use in highway and 

nonroad engines. We expect that no more than about half of the diesel fuel consumed 

nationwide in 2014 as transportation fuel would contain biodiesel, but it could be less than half 

depending on the prevalence of blends with biodiesel concentrations higher than 5%.

Heating oil represents another opportunity for large volumes of biodiesel to be consumed. 

Moreover, some of the practical issues leading to warranty limits on engines regarding the use of 

biodiesel are less of a concern when burning biodiesel for home heating purposes. Since there 

may be fewer issues associated with consumption of biodiesel in heating oil in comparison to 

biodiesel used as a transportation fuel, significant volumes of biodiesel can be consumed in this 

way and count for compliance purposes under the RFS program.

5. Biomass-Based Diesel Distribution Infrastructure 

In a separate action, we have projected that sufficient distribution infrastructure could be 

put in place to support the use of 1.28 bill gal of biomass-based diesel in 2013. The proposed 

renewable fuel volume requirements in today’s rule would result in the use of either 1.28 bill gal 

(no change from 2013), or 1.39 bill gal of biomass-based diesel in 2014, an increase of 110 mill 

gal. We project that an increase of 110 mill gal of biomass-based diesel in 2014 from 2013 

would be comprised of biodiesel.

Our evaluation of the changes to the fuel distribution infrastructure that would be needed 

to support the use of an additional 110 million gallons of biodiesel in 2014 is based on the 

analysis conducted for the RFS2 final rule.38 See Table V.B.5-1. 

 

37 National Biodiesel Board, Retailing Fueling Sites, as of February 17, 2011. 

http://biodiesel.org/buyingbiodiesel/retailfuelingsites/default.shtm

38 Renewable Fuels Standard Program (RFS2), Regulatory Impact Analysis (RIA), EPA-420-R-10-006, February 

2010. We are projecting that 80 million gallons per year of the biomass-based diesel standard would be satisfied by 

renewable diesel fuel. The distribution of renewable diesel fuel is discussed later in this section. 
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Table V.B.5-1

Additional Infrastructure Needed to Distribute Biodiesel in 2014

Additional Distribution 

Assets Needed in 2014 

Relative to 2013 to Support 

1.39 bill gal of Biodiesel

Total Distribution Assets 

Needed in 2014 to Support 

1.39 bill gal of Biodiesel

Petroleum Product 

Terminals with Biodiesel 

Blending Capabilitya

50 610

Rail Cars 90 1,075

Tank Trucks 10 120

Barges 3 32

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

The RFS2 final rule projected that a new 8,000 gallon tank truck to transport biodiesel 

would cost $198,000, a new 25,600 gallon rail car to transport biodiesel would cost $99,000, and 

a new 10,000 barrel barge to transport biodiesel would cost $1.54 million.39 The cost to install 

new segregated biodiesel storage, blending, receipt, and other miscellaneous biodiesel handling 

equipment was estimated at $1.6 million per terminal. The estimated total cost of the additional 

biodiesel distribution assets that would be needed in 2014 relative to 2013 to support an 

additional 110 mill gal of biodiesel is $95.51 million.

We believe that distributing the 1.39 bill gallons of biodiesel in 2014 is achievable. As 

described in a separate action finalizing an applicable volume requirement of 1.28 bill gal for 

2013, a number of states already have mandates for the use of biodiesel, and efforts are 

underway by the production and distribution industries to meet these mandates. Other states 

have implemented other forms of incentives that will also help to increase demand for and 

marketability 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 for the installation of biodiesel dispensing and blending 

equipment. Altogether, more than half of the states in the U.S. have mandates and/or incentives 

that will induce them to address biodiesel infrastructure issues. Consequently, we believe that 

the distribution infrastructure would be capable of accommodating 1.39 bill gal of biomass based 

diesel in 2013 with the modest additions discussed above.

Our estimate of the number of additional tank trucks that would be needed is based on the 

assumption that each truck could make 6 deliveries per day. The estimate of biodiesel trucking 

distances assumes a mature biodiesel production and distribution system. Under such a 

scenario, biodiesel production plants are projected to be more geographically dispersed and the 

volume of biodiesel produced at existing plants is projected to increase to allow the shipment by 

rail of biodiesel volumes that were previously shipped long distances by truck. It is possible that 

as biodiesel volumes ramp up the optimization of the biodiesel distribution system may lag 

behind. Under such a scenario, additional tank trucks may be needed to facilitate the transport of 

a volume requirement of 1.39 bill gal in 2014. To provide an outer-bound estimate of the 

additional tank trucks that might be needed under such a scenario, we assumed that each truck 

 

39 All costs are expressed in 2007 dollars as estimated in the RFS2 RIA.
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could only make 2 deliveries per day. This corresponds to an additional 20 tank trucks to 

facilitate the transport of the projected increase in biodiesel volume in 2014 relative to 2013. 

Even under this extreme case, the addition of 20 tank trucks would represent only 0.07% of the 

total U.S. fleet of petroleum products tank trucks (estimated at 27,000). Consequently, the 

possibility that biodiesel shipping distances might be longer than we projected would not 

materially affect our conclusions about the ability to accommodate the additional tank trucks 

needed. 

C. Impacts of 1.39 billion gallons of Biomass-Based Diesel 

In the RFS program, Congress established a schedule of renewable fuel volumes that 

gradually increases over time. While the schedule in the statute for biomass-based diesel ends in 

2012, the schedule of increasing volumes for advanced biofuels continues through 2022. Subject 

to a consideration of a number of factors as described in Section V.A, we believe that it is 

appropriate to consider biomass-based diesel as playing an increasing role in supplying advanced 

biofuels to the market for years after 2012.

In today's NPRM we are coproposing an applicable volume of either 1.28 bill gal or 1.39 

bill gal for biomass-based diesel in 2014. As described below, we are proposing findings that an 

increment of 110 mill gal of biodiesel over the 2013 applicable volume of 1.28 bill gal could 

help to support rural economic growth and job creation, increase energy security, and reduce 

emissions of GHGs. While the quantifiable benefits of an increase of 110 mill gal of biodiesel 

are unlikely to exceed the quantifiable costs in 2014, the benefits are more likely to exceed costs 

by 2022 and the years following, especially if future oil prices are high. Thus by establishing an 

applicable volume for biomass-based diesel in 2014 that exceeds the 2013 applicable volume of 

1.28 bill gal, we would be helping to establish the industry as a substantial contributor to the 

required volumes of advanced biofuel anticipated after full implementation of the RFS program. 

A described above, we have also determined that there will be sufficient feedstock and 

production capacity to meet a 1.39 bill gal volume requirement, and there are no clear 

impediments to meeting this volume requirement in terms of distribution, blending, or dispensing 

infrastructure.

The CAA section 211(o)(2)(B)(ii) requires that we analyze specified environmental and 

other impacts in deriving an applicable biomass-based diesel volume for years after 2012. 

Most of the areas we are required to analyze were already analyzed as part of the RFS2 final 

rule, so those analyses serve as the basis for assessing the impacts of biomass-based diesel for 

2014. Some of the analyses presented in the RFS2 final rule were for the specific case of 1.39 

bill gallons in 2014. These analyses included an investigation of the expected annual rate of 

commercial production of biomass-based diesel in 2014, impacts on agricultural commodity 

supply and price, and the cost to consumers of transportation fuel. Some of these were discussed 

in Section V.B above. Many of the analyses in the RFS2 final rule were conducted to represent 

full implementation of the RFS2 program in 2022. In these analyses, the biomass-based diesel 

volume was estimated to be 1.82 bill gallons and was compared to a reference case in which 

biodiesel volume was 0.38 bill gallons. These cases are shown in Table V.C-1.
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Table V.C-1

Primary Reference and Control Cases from RFS2 Final Rulemaking (billion gallons)

Advanced Biofuel NonAdvanced 

Biofuel

Total 

Renewable 

Fuel

Cellulosic Biofuel Biomass-Based 

Diesel

Other Advanced 

Biofuel

Cellulosic 

Ethanol

Cellulosic 

Diesel

FAMEa

Biodiesel NCRDb

Other 

Biodieselc

Imported 

Ethanol

Corn 

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

a

Fatty acid methyl ester (FAME) biodiesel

b Non-Co-processed Renewable Diesel (NCRD)

c Other 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 1.39 bill gallons we have evaluated in today's proposed rule for 2014. More 

importantly, the change in biodiesel production in 2022 due to the statutory 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 2014 (0.11 bill gal increment above the 2013 

applicable volume of 1.28 bill gal). Many of the impacts analyzed for the RFS2 final rule 

reflected the whole biofuel mandate, not the relatively smaller portion just due to biodiesel. 

However, as in the rulemaking establishing the 1.28 bill gal applicable volume for 

biomass-based diesel in 2013, we continue to believe that it is appropriate to use the analyses in 

the RFS2 final rule for 2022 in evaluating the impacts of an additional increment of 0.11 bill gal 

in 2014. Our intent in using the analyses from the RFS2 final rule is only to determine whether 

an increase in biomass-based diesel of 0.11 bill gal is reasonable given the magnitude of the 

potential impacts. Given that the RFS2 final rule analyzed the impacts of an increase in 

biomass-based diesel that was about thirteen times larger than the volume increment we are 

proposing for 2014, we continue to believe that the impacts of increasing the biomass-based 

diesel standard from 1.28 bill gallons in 2013 to 1.39 bill gallons in 2014 would likely be similar 

to or smaller than the impacts we estimated for the much larger change in biomass-based diesel 

in the RFS2 final rule. 

1. Climate Change

Since biodiesel has a GHG benefit compared to the petroleum-based diesel it is replacing, 

an increase in biomass-based diesel of 0.11 bill gal from 2013 to 2014 would lead to a 

displacement of conventional diesel fuel, with corresponding GHG emissions reductions. This 

increased use of biomass-based diesel would contribute to lower climate change impacts in 

comparison to the petroleum-based diesel it is replacing. 

EPA estimates the social benefits of regulatory actions that have a small or “marginal” 

impact on cumulative global CO2 emissions using the social cost of carbon dioxide (SC-CO2). 

The SC-CO2 is an estimate of the net present value of the flow of monetized damages from a one 

metric ton increase in CO2 emissions in a given year. Alternatively, this represents the benefit to 
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society of reducing CO2 emissions by one ton.40 The SC-CO2 includes, but is not limited to, 

climate damages due to changes in net agricultural productivity, human health, property damages 

from flood risk, and ecosystem services. 

The SC-CO2 estimates currently used by the Agency were developed through an 

interagency process that included EPA and other executive branch entities and concluded in 

February 2010. The Technical Support Document: Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866 for the final joint EPA/Department of Transportation 

Rulemaking to establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate 

Average Fuel Economy Standards provides a complete discussion of the methods used to 

develop the SC-CO2 estimates (Interagency Working Group on Social Cost of Carbon, 2010) 

(hereafter, “2010 TSD”). 

To monetize global social benefits of reduced CO2 emissions, the interagency group 

selected four SC-CO2 estimates for use in regulatory analyses. In 2014, these are: $6, $24, $39, 

and $74 per metric ton of CO2 emissions in 2013 (in 2010 dollars). The first three values are 

based on the average SC-CO2 from three integrated assessment models, at discount rates of 5, 3, 

and 2.5 percent, respectively. SC-CO2s at several discount rates are included because the 

literature shows that the SC-CO2 is quite sensitive to assumptions about the discount rate, and 

because no consensus exists on the appropriate rate to use in an intergenerational context. The 

fourth value is the 95th percentile of the SC-CO2 from all three models at a 3 percent discount 

rate. It is included to represent higher-than-expected impacts from temperature change further 

out in the tails of the SC-CO2 distribution. The “central value” is the average SCC across models at 

the 3 percent discount rate. For purposes of capturing the uncertainties involved in regulatory impact 

analysis, we emphasize the importance and value of considering the full range. Low-probability, highimpact events are incorporated into all of the SC-CO2 values through explicit consideration of 

their effects in two of the three models as well as the use of a probability density function for 

equilibrium climate sensitivity. Treating climate sensitivity probabilistically allows the 

exploration of the full range of uncertainty over future temperature changes, which generally 

results in higher damages estimates than when the SC-CO2 is evaluated only at the mean climate 

sensitivity. 

The 2010 interagency SCC technical support report discusses a number of important 

limitations for which additional research is needed. In particular, the document highlights the 

incomplete way in which the integrated assessment models capture catastrophic and noncatastrophic impacts, their incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk 

aversion. The limited amount of research linking climate impacts to economic damages makes 

this modeling exercise even more difficult. The interagency group recommended that the SCC 

estimates used for regulatory analysis by the Federal government be revisited and continue to 

evolve with improvements in modeling.

The SC-CO2 increases over time because future emissions are expected to produce larger 

incremental damages as physical and economic systems become more stressed in response to 

 

40 In the absence of direct model estimates of the social cost of non-CO2 GHGs, the social cost of CO2 can be used to 

estimate those benefits on a CO2-e basis, as discussed further below.
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greater climatic change. For example, by 2022 the four estimates increase to $8, $29, $45, and 

$88 per metric ton of CO2 emissions (in 2010 dollars). Note that the interagency group 

estimated the growth rate of the SCC directly using the three integrated assessment models rather 

than assuming a constant annual growth rate. This helps to ensure that the estimates are 

internally consistent with other modeling assumptions. The table below presents the four 

estimates for the years 2014 through 2050, with a conservative EPA estimate of the value in the 

year 2051.

Table V.C.1-1

Benefit per Metric Ton of CO2 Reduced, 2014-2051 ($2010)a

YEAR

Discount Rate (Statistic)

5% (Avg) 3% (Avg) 2.5% (Avg) 3% (95th %ile)

2014 $6 $24 $39 $74

2015 $6 $25 $40 $76

2016 $6 $25 $41 $78

2017 $6 $26 $42 $79

2018 $7 $26 $42 $81

2019 $7 $27 $43 $83

2020 $7 $28 $44 $84

2021 $7 $28 $45 $86

2022 $8 $29 $45 $88

2023 $8 $29 $46 $90

2024 $8 $30 $47 $92

2025 $9 $31 $48 $94

2026 $9 $31 $49 $96

2027 $9 $32 $50 $98

2028 $10 $33 $50 $100

2029 $10 $33 $51 $102

2030 $10 $34 $52 $104

2031 $10 $35 $53 $106

2032 $11 $35 $54 $108

2033 $11 $36 $55 $110

2034 $11 $37 $56 $112

2035 $12 $37 $56 $114

2036 $12 $38 $57 $116

2037 $12 $39 $58 $118

2038 $13 $39 $59 $120

2039 $13 $40 $60 $122

2040 $13 $41 $61 $124

2041 $14 $41 $62 $126

2042 $14 $42 $62 $128

2043 $14 $43 $63 $130

2044 $14 $43 $64 $131

2045 $15 $44 $64 $133
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2046 $15 $44 $65 $135

2047 $15 $45 $66 $137

2048 $16 $46 $66 $138

2049 $16 $46 $67 $140

2050 $16 $47 $68 $142

2051b$16 $47 $68 $142

a The SC-CO2 values vary depending on the year of CO2 emission and are defined in real terms. The change from 

year to year is not obvious in this table because estimates are rounded to the nearest dollar.

b The Interagency Working Group on Social Cost of Carbon did not estimate SCC-CO2 values beyond 2050. 

However, to estimate the monetized impact of a 30 year stream of emissions beginning in 2022, we must have some 

estimate for the year 2051. SCC-CO2 values increase incrementally every year under the projections presented 

above. However, since monetized impacts for the year 2051 have not yet been established by the Interagency 

Working Group, we assume for the purposes of this analysis that they are equal to the 2050 impacts to avoid 

overestimation.

Today’s rulemaking also analyzes reductions in non-CO2 GHGs. The 2010 interagency 

group, however, did not directly estimate the social cost of non-CO2 GHGs. In the absence of 

direct model estimates from the interagency analysis, EPA has used a “global warming potential 

(GWP) approach” to estimate the dollar value of this rule’s non-CO2 GHG benefits.41 This 

approach is consistent with the methodology used in the final RFS2 rulemaking, which was 

finalized prior to the 2010 interagency work group process. Specifically, EPA converted 

methane and nitrous oxide to CO2 equivalents using the GWP of these gases, then multiplied 

these CO2-equivalent emission reductions by the interagency social cost of carbon dioxide 

estimates. Furthermore, EPA has used the 100-year GWP estimates from the IPCC Second 

Assessment Report (SAR) to estimate the methane and nitrous oxide benefits for this proposed 

rule. The use of the SAR GWP values allows comparability of data collected in this final rule to 

the national GHG inventory that EPA compiles annually to meet U.S. commitments to the 

United Nations Framework Convention on Climate Change (UNFCCC).

As discussed in a recent working paper (Marten and Newbold, 2011)42, the GWPweighted benefit estimates for methane and nitrous oxide are likely to be lower than those that 

would be derived using a directly modeled social cost of the non-CO2 GHGs for a variety of 

reasons.43 In sum, the authors find that an integrated assessment model produces higher 

estimates of the social cost of methane and nitrous oxide than the GWP approach because the 

model captures the effect of temperature changes on economic output over time, whereas GWP 

is based only on physical impacts. 

 

41 For a longer discussion of the GWP approach, see the Regulatory Impact Analysis associated with the New 

Source Performance Standards and Amendments to the National Emissions Standards for Hazardous Air Pollutants 

for the Oil and Natural Gas Industry, issued on April 17, 2012. See 

http://www.epa.gov/airquality/oilandgas/actions.html. 

42 Marten, A. and S. Newbold. 2011. “Estimating the Social Cost of Non-CO2 GHG Emissions: Methane and 

Nitrous Oxide.” NCEE Working Paper Series # 11-01. 

http://yosemite.epa.gov/ee/epa/eed.nsf/WPNumber/2011-01?opendocument

43 As discussed in Marten and Newbold, the discount rate influences whether directly modeled social cost estimates 

are higher than those estimated with the GWP approach. Methane is a short-lived gas and therefore direct modeling 

results in higher social costs at higher discount rates than the GWP approach. 
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We established in the RFS2 final rule that a gallon of soybean-based biodiesel results in 

an annualized GHG emission reduction of approximately 57 percent compared to the 2005 

petroleum baseline (approximately 0.0065 tons of CO2 equivalent per gallon). This GHG 

reduction is calculated by estimating the annualized emissions streams over 30 years, starting in 

2022, (the year when the RFS2 program will be fully implemented). For this reason, it may not 

be appropriate to include any benefits from GHG reductions in our 2014 calculations. This is not 

because we believe that the GHG benefits in 2014 will be zero, but rather because it may not be 

consistent to cite them for an interim year of the program using lifecycle biofuel assessments 

based on a 2022 analyses.44 

To monetize the global SC-CO2 value, we use the same stream of emissions for both 

2014 and 2022 that were estimated for the RFS2 final rulemaking. We then apply the 

appropriate SC-CO2 dollar values to each year (i.e., we apply the 2015 SC-CO2 value to a stream 

in 2015, the 2028 value to a stream in 2028). These benefits are then totaled, discounted to net 

present value using the applicable discount rate, and divided by 30 to place the estimate back on 

a per gallon basis. The resulting estimates are provided in the table below for 2014 and 2022. 45

Table V.C.1-2

Monetized per Gallon CO2-eq Annualized Benefits of Biomass-Based Diesel in 2014 and 2022 

($2010)a

Year Annualized 

Emissions 

reduction 

(Tons of 

CO2-

eq/gallon)

Benefits

5% (Avg) 3% (Avg) 2.5% (Avg) 3% (95th 

%ile)

2014 0.0065 $0.03 $0.12 $0.21 $0.38 

2022b0.0065 $0.03 $0.14 $0.23 $0.43 

a Estimates represent the CO2-eq. estimate of carbon dioxide, methane, and nitrous oxide reductions multiplied by 

the SCC estimates (“GWP approach”). CO2-eq. for methane calculated using the GWP of 21 (SAR). These cobenefit estimates are not the same as would be derived using a social cost of methane directly computed from 

integrated assessment models. See Marten and Newbold (2011) for discussion of the limitations of the GWP 

approach.

b We estimate monetary values for the years 2022-2051 based on the values established by the Interagency Working 

Group on Social Cost of Carbon. See Table IV.A.1-1 for further details.

 

44 We analyzed the GHG benefits of the renewable fuels in the context of full implementation of the RFS2 program 

in 2022. The 2022 analysis represents an assumption for the purposes of modeling, to best capture the lifecycle 

GHG emissions for the required volumes of renewable fuel at full implementation. Emissions in other years will 

differ; for example, our analysis for 2022 assumes that soybean yields will continue to increase from today’s levels 

because of technological innovation. 

45 Tables IV.A.1-1 and IV.A.1-2 provide summary details about the global SC-CO2 values and emissions streams 

used in our calculations. Additional details are included in a Memorandum to the Docket, Docket ID XXX, Dated 

May XX, 2012.
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2. Energy Security

Increasing the biomass-based diesel mandate to 1.39 bill gal would help to ensure an 

increased use of biomass-based diesel in the U.S. and help to improve U.S. energy security. 

Reducing U.S. petroleum imports and increasing the diversity of U.S. liquid fuel supplies lowers 

both the financial and strategic risks caused by potential sudden disruptions in the supply of 

imported petroleum to the U.S. The economic value of reductions in these risks provides a 

measure of improved U.S. energy security. This section summarizes EPA’s estimates of U.S. oil 

import reductions and energy security benefits from this proposed rule. 

In 2010, U.S. petroleum import expenditures represented 14 percent of total U.S. imports 

of all goods and services.46 These expenditures rose to 18 percent by April of 2011.47 In 2010, 

the United States imported 49 percent of the petroleum it consumed48, and the transportation 

sector accounted for 71 percent of total U.S. petroleum consumption. This compares to 

approximately 37 percent of total U.S. petroleum supplied by imports and 55 percent of U.S. 

petroleum consumption in the transportation sector in 1975. Requiring higher volumes of 

renewable fuels to be used in the U.S. is expected to lower U.S. oil imports. 

An increase in the biomass-based diesel volume requirement to 1.39 bill gal of biomassbased diesel from 1.28 billion gal in 2013 would help to reduce U.S. petroleum imports by 

displacing about 100 mill gal of diesel equivalent.49 Based on an analysis of historical and 

projected future variation in U.S. petroleum consumption and imports, we estimate that 

approximately 50 percent of the reduction in fuel consumption resulting from adopting 

renewable fuels is likely to be reflected in reduced U.S. imports of refined fuel, while the 

remaining 50 percent is expected to be reflected in reduced domestic fuel refining. Of this latter 

figure, 90 percent is anticipated to reduce U.S. imports of crude petroleum for use as a refinery 

feedstock, while the remaining 10 percent is expected to reduce U.S. domestic production of 

crude petroleum. Thus, on balance, each gallon of fossil-based fuel saved as a consequence of 

the renewable fuel standards is anticipated to reduce total U.S. imports of petroleum by 0.95 

gallons.50 Therefore, by raising the applicable volume requirement of biomass-based diesel from 

1.28 bill gal to 1.39 bill gal in 2014, petroleum imports into the U.S. would be reduced by 95 

million gallons (95% x 100 mill gal increment). Table V.C.2-1 below compares EPA’s estimates 

of the reduction in imports of U.S. crude oil and petroleum-based products from this program to 

projected total U.S. imports for the years 2014 and 2022.

 

46 http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WTTIMUS2&f=W 47 http://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_ep00_im0_mbblpd_a.htm

48 http://www.eia.gov/dnav/pet/pet_pri_rac2_dcu_nus_m.htm

49 100 mill gal diesel is roughly equivalent to 110 mill gal biodiesel on an energy-equivalent basis.

50This figure is calculated as 0.50 + 0.50*0.9 = 0.50 + 0.45 = 0.95.
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Table V.C.2-1

Projected Import Reductions from 1.39 Bill Gal Biomass-Based Diesel and Total U.S. 

Petroleum-Based Imports in 2014 and 2022 (Millions of Barrels )

U.S. Petroleum-Based 

Import Reductions

from 1.39 Bill Gal 

Biomass-Based Diesel

(million barrels/yr)

U.S. Total PetroleumBased Imports without 

1.39 Bill Gal BiomassBased Diesel

(million barrels/yr)

2014 2.3 3,402

2022 2.3 2,964

In order to understand the energy security implications of reducing U.S. petroleum 

imports, EPA worked with Oak Ridge National Laboratory (ORNL), which has developed 

approaches for evaluating the economic costs and energy security implications of oil use. The 

energy security estimates provided below are based upon a methodology developed in a peerreviewed study entitled, ”The Energy Security Benefits of Reduced Oil Use, 2006-2015,” 

completed in March 2008. This study is included as part of the docket for this proposal.51,52

When conducting its analysis, ORNL considered the full economic cost of importing petroleum 

into the United States. 

The economic cost of importing petroleum into the U.S. is defined to include two 

components in addition to the purchase price of petroleum itself. These are: (1) the higher costs 

for oil imports resulting from the effect of increasing U.S. import demand on the world oil price 

and on the market power of the Organization of Petroleum Exporting Countries (i.e., the 

“demand” or “monopsony” costs); and (2) the risk of reductions in U.S. economic output and 

disruption of the U.S. economy caused by sudden disruptions in the supply of imported 

petroleum to the U.S. (i.e., “macroeconomic disruption/adjustment costs”). 

An often-identified component of the full economic costs of U.S. oil imports is the costs 

to the U.S. taxpayers of existing U.S. energy security policies. The two primary components of 

this cost are likely to be (1) the expenses associated with maintaining a U.S. military presence –

in part to help secure a stable oil supply – in potentially unstable regions of the world; and (2) 

costs for maintaining the U.S. Strategic Petroleum Reserve (SPR). The SPR is the largest 

stockpile of government-owned emergency crude oil in the world. 

The EPA recognizes that potential national and energy security risks exist due to the 

possibility of tension over oil supplies. Much of the world’s oil and gas supplies are located in 

countries facing social, economic, and demographic challenges, thus making them even more 

vulnerable to potential local instability. Because of U.S. dependence on oil, the military could be 

called on to protect energy resources through such measures as securing shipping lanes from 

 

51 Leiby, Paul N., "Estimating the Energy Security Benefits of Reduced U.S. Oil Imports" Oak Ridge National 

Laboratory, ORNL/TM-2007/028, Final Report, 2008. (Docket EPA-HQ-OAR-2010-0162)

52 The ORNL study “The Energy Security Benefits of Reduced Oil Use, 2006-2015," completed in March 2008, is an

update version of the approach used for estimating the energy security benefits of U.S. oil import reductions. 

developed in an ORNL 1997 Report by Leiby, Paul N., Donald W. Jones, T. Randall Curlee, and Russell Lee, 

entitled “Oil Imports: An Assessment of Benefits and Costs." (Docket EPA-HQ-OAR-2010-0162)
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Page 64 of 92

foreign oil fields. Thus, to the degree to which this proposed rule increases the diversity of 

sources of liquid fuel for U.S. consumption and/or reduces reliance upon imported energy 

supplies, the United States could expect benefits related to national security and increased energy 

supply. Although the Agency recognizes that there clearly is a benefit to the United States from 

reducing dependence on foreign oil, the Agency has been unable to calculate the monetary 

benefit that the United States will receive from the improvements in national security expected to 

result from this program. 

Also, while the costs of building and maintaining the SPR are clearly related to U.S. oil 

use and imports, these costs have not varied historically in response to U.S. oil import levels. 

Thus, the costs of maintaining the SPR are excluded from this analysis. In addition, given the 

redistributive nature of this monopsony effect from a global perspective, it is excluded in the 

energy security benefits calculations for this proposal. In contrast, the other portion of the 

energy security premium, the U.S. macroeconomic disruption and adjustment cost that arises 

from U.S. petroleum imports, does not have offsetting impacts outside of the U.S. and, thus, is 

included in the energy security benefits estimated for this proposal. To summarize, EPA has 

included only the macroeconomic disruption portion of the energy security benefits to estimate 

the monetary value of the total energy security benefits of this program. 

The U.S. is projected to be a net exporter of diesel fuel in 2014.53 Increased biodiesel 

production would likely result in less domestic consumption of petroleum-based diesel fuel in 

the U.S., which in turn may be reflected in increased exports of diesel by the U.S. However, 

regardless of the incremental effect of this rule on net imports, increasing the diversification of 

the U.S. and global diesel fuel pools would likely confer some reduction in the severity of a 

future potential disruption in the world oil market. 

The energy security premiums for the year 2014 and 2022 are presented in Table V.C.2-2 

as well as a breakdown of the components of the energy security premiums for each year. These 

energy security premiums are recorded on a dollar per barrel of oil imported reduced from this 

rule. However, on a gallon of biodiesel fuel basis, these translate into an estimated $0.15/gallon 

benefit in 2014 and a $0.16/gallon benefit in 2022 (in 2010$).

Table V.C.2-2

Energy Security Premiums in 2014 and 2022 (2010$/Barrel) Based on ORNL 

Methodology

Monopsony Macroeconomic 

Disruption/Adjustment Costs

Total Mid-Point

2014 $11.60

($3.91-$19.74)

$7.29

($3.49-$10.58)

$18.90

($10.26-$27.26)

2022 9.82

($3.27-$16.77)

7.84

($3.80-$11.30)

17.66

($9.88-$24.99)

Note: Values in parentheses represent a 90% confidence interval around the central value.

 

53 U.S. Energy Information Administration (EIA). “Short-Term Energy Outlook”, Table 4a, June 2012. 

http://205.254.135.7/forecasts/steo/tables/pdf/4atab.pdf
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Using EPA’s fuel consumption analysis in conjunction with ORNL’s energy security 

premium estimates, the agency has developed estimates of the total energy security benefits for 

the years 2014 and 2022 in Table V.C.2-3. 

Table V.C.2-3

Estimated Energy Security Benefits in 2014 and 2022 for 1.39 Bill Gal Biomass-Based Diesel 

(2010$)

U.S. Oil 

Imports 

Reduced

(million 

barrels/yr)

Benefits

($Millions)

2014 2.3 $17

2022 2.3 $18

3. Air Quality 

We are relying on the analyses of renewable fuel impacts conducted in support of the 

RFS2 final rule54 to qualitatively discuss the expected air quality impacts of a biomass-based 

diesel volume of 1.39 bill gallons. The RFS2 analyses reflect EPA’s most current assumptions 

regarding biodiesel emission impacts.55

In the RFS2 final rule, we analyzed both changes in pollutant emissions (measured in 

tons) and changes in ambient air quality associated with the changes in pollutant emissions. As 

described in the introduction to Section V.C above, 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).56 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 final rule emissions inventory analysis are

presented in Table IV.C.3-1. A complete discussion of the emissions inventory analysis 

conducted for the RFS2 final rule can be found in Chapter 3 of the RFS2 Regulatory Impact 

Analysis (RIA).57 The 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 

 

54 75 FR14670, March 26, 2010

55 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. Section 3.1.1.2.4

56 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.

57 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.
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pollutant.58 We expect the impacts of a 1.39 bill gal volume requirement of biomass-based 

diesel relative to the 1.28 bill gal applicable volume established in a separate action for 2013 

(which reflect a 0.11 bill gal increase) to be considerably smaller. 

Table V.C.3-1

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 final rule Emissions 

Inventory Analysis (Δ 1.44 bill gal Biodiesel) Percent RFS2 Total 

U.S. Inventoryc

Upstreama

(tons)

Downstreamb

(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%

Acrolein 63 -9 54 0.84%

aU.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. 

bU.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.

cWhile the national-level emissions and air quality impacts may be small, there may still be local and regional 

impacts that are larger in percentage terms. Our analysis is unable to capture this local and regional variability.

The air quality analysis for the RFS2 final 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 final 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 

 

58 While the national-level emissions and air quality impacts may be small, there may still be local and regional 

impacts that are larger in percentage terms. Our analysis is unable to capture this local and regional variability.
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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).59 

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.60,61 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. We use the 0.43 bill gal increase in biodiesel assumed in the RFS2 air quality 

analysis to qualitatively discuss the potential impacts of a 0.11 bill gal increase in biodiesel that 

would result from 1.39 bill gal of biomass-based diesel.

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 1.28 to 1.39 bill gal (a 0.11 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 final rule. We intend to investigate any potential adverse impacts from increased 

renewable fuel use through that study and will promulgate appropriate mitigation measures 

separate from today's proposed rule.

4. Consideration of Applicable Statutory Economic Factors

The RFS program established by Congress is primarily a long-term program aimed at 

replacing substantial volumes of fossil-based transportation fuels with low GHG renewable fuels 

over time. Congress established a list of factors to be considered in setting the annual biomassdiesel mandate, and these factors include consideration of some aspects of economic costs and 

some aspects of economic benefits (among other impacts and factors), though there is no explicit 

net benefit criterion required by the statute. In the final rulemaking establishing the RFS2 

program, EPA assessed the costs and benefits of this program as a whole when the program was 

fully mature, which we continue to believe is the appropriate approach to examining the costs 

and benefits of a long term program like RFS2. However, the annual standard-setting process is 

part of the program, and it encourages consideration of the program on a piecemeal (i.e., year to 

year) basis, which may not reflect the long-term economic effects of the program. 

In this section, we provide general estimates of some costs and benefits of 1.39 bill gal of 

biomass-based diesel for the year 2022, when the RFS2 legislative requirements are fully 

 

59 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.

60 Emissions 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.

61 The RFS2 air quality analysis reflects EPA’s most recent air quality analysis applicable to changes in renewable 

fuel types and volumes.
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implemented and the program is more mature. We also provide estimates of the costs and 

benefits of 1.39 bill gal for the year 2014, the year in which such a requirement could be 

implemented. The statute is forward-looking in that it created a program whose energy and 

environmental benefits are intended to grow over time; to evaluate the program on the basis of 

only one early year’s impacts, as part of near-term implementation, would be to paint an 

unbalanced and incomplete picture. For example, as we examine the costs of the program 

through time, we see that these costs fall steadily. This is due to two key factors: the cost of 

petroleum, the basic raw material of diesel fuel, rises through time. Meanwhile, the principal 

cost of soybean-based biodiesel, the soybean oil feedstock, tends to fall though time. For 

example, the AEO 2012 Early Release (AEO2012 ER) projects that oil prices will rise from 

roughly $110 per barrel in 2014 to $129 per barrel in 2022, a 7 percent increase.62 The AEO 

2011 High Oil Price case (AEO2011 HOP), projects that oil prices will increase to about $179 

per barrel, a 62 percent increase.63 According to EPA’s projections performed for this rule and 

USDA long-term projections, soy oil prices will decrease from $0.47/lb in 2014 to $0.42/lb in 

2022, a 9 percent decrease.64 As a result, the relative cost difference between diesel and 

biodiesel fuel tends to narrow through time as the program reaches maturity. Thus, we do not 

just look at the impacts of the program in any one year, but also look at the impacts at a point of 

greater program maturity.

a. Monetized Quantifiable Costs

Our analysis of costs focuses on the sector most likely to be impacted by an increase in 

biomass-based diesel volumes - the agricultural commodity market. A similar analysis was 

conducted for the final 2013 biomass-based diesel volume requirement in response to comments 

received. This analysis uses a stochastic economic model developed by the Center for 

Agricultural and Rural Development (CARD) at Iowa State University. The CARD stochastic 

model approximates U.S. and Brazilian biofuel production, consumption, and trade. The model 

provides the probability of different outcomes by running 500 different potential scenarios. This 

modeling approach provides a range of estimates which helps bound the uncertainty about 

possible impacts on the biofuels sector.

Producing an additional 110 mill gal of biodiesel would displace approximately 100 mill 

gal of petroleum-based diesel. Since biodiesel costs more to produce in the U.S. than diesel, 

there are costs associated with this displacement. For the final rule setting the 2013 biomassbased diesel volume requirement of 1.28 bill gal, we compared the cost of biodiesel and 

petrodiesel at the wholesale stage on an energy equivalent basis, since that is when the two fuels 

are blended together. To form our basic estimate for this proposed rule, we modified this 

analysis to project the impact of a 1.39 bill gal volume requirement on biodiesel and fuel costs.

 

62 U.S. Department of Energy, Energy Information Administration. 2012. Annual Energy Outlook 2012 (Early 

Release). Available at: http://www.eia.gov/forecasts/aeo/er/.

63 U.S. Department of Energy, Energy Information Administration. 2011. Annual Energy Outlook 2011. Available 

at: http://www.eia.gov/forecasts/aeo/data.cfm#enprisec.

64 U.S. Department of Agriculture, Economic Research Service, Agricultural Long-Term Projections, February 

2012.
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As we outline in Section V.B.2 of this proposed rule, we assume that 680 mill gal of 

biofuel feedstock would come from corn oil and waste oils, fats, and greases. The remaining 710 

mill gal of feedstock needed to meet a 1.39 bill gal volume requirement in 2014, including the 

110 mil gal of additional biodiesel we are coproposing to mandate under this rule, is assumed to 

be soy oil. Because soybean oil feedstocks are more expensive than corn oil or waste feedstocks, 

the cost impact of the extended volume requirement would decrease if biodiesel production from 

these other sources expands. We therefore consider the cost projections presented below to be 

potentially high estimates.

The main component of the increase in fuel costs associated with extending the biomassbased diesel mandate comes from an increase in the price of soybean oil. We project the price of 

soybean oil would be approximately $0.47 per pound (in 2010 dollars) under the proposed 1.39 

billion gallon volume requirement, compared to prices of approximately $0.45 under a 1.28 

billion gallon volume requirement (see Section V.B.2 for further discussion of feedstock 

availability and prices). A gallon of soybean-based biodiesel requires 7.55 pounds of soybean 

oil, meaning that this projected increase in the price of soybean oil increases the feedstock costs 

of soybean-based biodiesel by about $0.12/gallon in 2014.

Given that the CARD stochastic model is not designed to estimate long-run impacts, we 

did not attempt to estimate the impacts of a 2014 biomass-based biodiesel volume requirement of 

1.39 bill gal on the price of soybean oil in 2022. In Section V.B.2.d we estimate that 1.39 bill gal 

would raise soybean oil prices by approximately 3.4 percent in 2014. The international market 

for vegetable oils is large and diverse, with considerable capacity to absorb short-term demand 

increases. It is therefore unlikely that an increase in U.S. demand for soybean oil of this size in 

2014 would significantly affect prices eight years in the future. Therefore, in lieu of projecting 

soybean oil prices in 2022, we are instead utilizing USDA’s 2012 Long-Term Agricultural 

Projections of soybean oil prices to estimate the cost of an additional 110 mill gal in 2022. This 

is consistent with our analysis for the 2013 biomass-based diesel volume requirement final rule. 

USDA estimates that the price of soybean oil would be $0.42 per pound (in 2010$) for the 

2021/2022 crop year (the last year for which USDA provides estimates in their long-term 

projections as of this writing).

Estimating the cost to produce biodiesel and transport it to the blender presents 

considerable uncertainties, even in the near term. Unforeseen fluctuations in the prices of oil, for 

example, could have a very significant effect. Therefore, instead of presenting a point estimate, 

we have chosen to present a range of estimates for 2014 and 2022 that bounds uncertainty about 

oil and feedstock prices if we were to establish a biomass-based diesel volume requirement of 

1.39 bill gal in 2014.

Table V.C.4-2 presents our estimates for the increase in the cost of incremental volumes 

of biodiesel resulting from a volume requirement of 1.39 bill gal. Using the same methodology 

utilized in the final rulemaking for the 2013 biomass-based diesel mandate, we estimate the 

increase in the cost for an additional 110 million gallons of biodiesel in 2014 would be between 

$1.02 and $1.48 per gallon compared to the petroleum-based diesel that would otherwise be 

consumed. The range of cost increases in 2014 represents different estimates of oil prices. In 

2014, costs are on the low-end of the range if we use the wholesale diesel estimate from DOE’s 
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most recent Short-Term Energy Outlook (STEO).65 The high-end estimate utilizes DOE’s 

AEO12 ER wholesale diesel estimate.66 This translates into total cost estimates of $112 million 

to $162 million from increased fuel cost in 2014.

Table V.C.4-2

Estimated Increase in Wholesale Cost of Biodiesel in Comparison to Petrodiesel in 2014 and 

2022(2010 dollars)

Estimate for 2014 Estimate for 2022

Petroleum Assumption STEO March 

2012

AEO 2012 

Early Release

AEO 2011 

High Oil Price

AEO 2012 

Early Release

Difference in biodiesel 

production cost (per gallon) $1.02 $1.48 -$0.70 $0.41

Cost of 280 million gallons $112 million $162 million -$77 million $45 million

We also present a range of cost estimates for the year 2022. Similar to our 2014 analysis, 

the upper estimate utilizes the AEO 2012 ER. The lower estimate utilizes the AEO 2011 High 

Oil Price (HOP) case’s wholesale diesel estimate. The STEO does not provide projections out 

through 2022 and the AEO 2012 Early Release does not include the high oil price case (at the 

time of this writing the full AEO 2012 has not been released). Therefore, the AEO 2011 HOP is 

the best available estimate of a higher diesel cost in 2022. Based on this range of diesel costs 

and on USDA’s long-term projection of soybean oil prices, we estimate the incremental increase 

in biodiesel costs associated with an increase of 110 mill gal of biodiesel would be between -

$0.70 and $0.41 per gallon in 2022. This translates to a cost of -$77 million to $45 million in 

2022. The low end of this estimate is negative because with higher crude oil costs, biodiesel is 

less expensive than petrodiesel.

Consistent with our previous work in this area, our quantifiable cost methodology is a 

“bottom-up” engineering cost analysis that estimates the cost to produce a gallon of soybeanbased biodiesel and then compares that cost to the production cost of an energy-equivalent gallon 

of petroleum-based diesel. In certain situations, it may also be useful to use a “top down” 

analyses to estimate the potential cost of a program to society. In the case of the biomass-based 

diesel standard, one suggestion was to look at the RIN price as a proxy for the societal cost of the 

program. 

RIN prices reflect the incremental private marginal cost of blending BBD into the diesel 

fuel pool. As noted by Professor Bruce Babcock, of the Iowa State University: 

“The market for RINs is an effective and efficient way to enforce the mandates. Motor 

fuel producers who find that biofuel is too difficult to access or to blend buy RINs 

instead. Fuel producers who have ready access to biofuels and find it profitable to blend 

 

65 U.S. Department of Energy, Energy Information Administration. 2012. Short Term Energy Outlook, March 

2012. Available at: http://www.eia.gov/forecasts/steo/index.cfm.

66 U.S. Department of Energy, Energy Information Administration. 2012. Annual Energy Outlook 2012 (Early 

Release). Available at: http://www.eia.gov/forecasts/aeo/er/.
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biofuels sell their excess RINs. By making RINs tradable, the mandates are met at the 

lowest possible cost.”67

However, we have concerns with using RIN prices to estimate the costs to society of the 

biomass-based diesel RFS2 requirement. First, RIN prices are more representative of marginal 

costs. If producers have different costs of production, as they do in the biodiesel market, using 

the marginal cost of compliance as a proxy for cost of production will significantly overestimate 

the cost to society. Second, it is difficult to have confidence in the use of historical RIN price 

trends as an indicator of future program cost. Key factors limiting EPA’s confidence in RIN 

price as a proxy measure for social cost include the effect of observed instability and 

uncertainties in U.S. tax policy, import tariff policies, and other possible inefficiencies in RIN 

markets.68 Finally, other factors, such as the existence of multiple RIN vintages in any given 

year and the aforementioned uncertainties, can create significant incentives for potential 

speculation in the RIN markets. In their 2011 report on RINs, USDA observed that this 

speculation results in RIN prices that are somewhat higher than the cost of biodiesel, though the 

exact amount of this increment is extremely difficult to quantify.69 

b. Transportation Fuel Costs

The estimates described in Section V.C.4.a above represent the quantifiable costs to 

society as a whole stemming from an increase in the biomass-based diesel volume requirement 

from 1.28 bill gal to 1.39 bill gal. These estimates do not include certain transfers, such as those 

between buyers and sellers of diesel fuel. For this reason, the increase in the cost of 

transportation fuel from a societal perspective is different from the increase from the perspective 

of individual buyers and sellers. However, these costs do impact the retail price of diesel and 

associated economic impacts for fuel consumers.

To estimate the increase in the cost of transportation fuel associated with a mandate for 

1.39 bill gal in 2014 and 2022, we took our projections for the quantifiable program costs 

reported in Section V.C.4.a and compared them to projected fuel consumption. The AEO 

projects that the U.S. transportation sector will consume approximately 46.3 bill gal of blended 

diesel in 2014 and 50.3 bill gal in 2022.70 Averaged over the transportation diesel pool, the 

quantifiable costs of a 1.39 bill gal mandate translate into a per gallon cost of between $0.002 

and $0.004 in 2014 and between -$0.002 and $0.001 in 2022.71

 

67 Babcock, B, Mandates, Tax Credits, and Tariffs: Does the U.S. Biofuels Industry Need Them All? Iowa State 

University, Center for Agricultural and Rural Development, Policy Brief 10-PB-1, March 2010. p. 4-5

69 McPhail, L, P Westcott, and H Lutman, The Renewable Identification Number System and U.S. Biofuel Mandates, 

United States Department of Agriculture, November 2011.

70 U.S. Department of Energy, Energy Information Administration. 2012. Annual Energy Outlook 2012 (Early 

Release). Available at: http://www.eia.gov/forecasts/aeo/er/.

71 If current RIN prices were used to gauge social cost in lieu of the bottom-up engineering cost approach applied 

herein, the estimate of transportation fuel costs would be higher.
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c. Monetized Quantifiable Benefits 

Many of the benefits and impacts that Congress asked EPA to examine when evaluating 

whether to increase the volume requirement for biomass-based biodiesel are difficult to fully 

quantify. In this section, we present a selection of quantifiable benefits from increased biodiesel 

production, including increased energy security, improved air quality, and reduced greenhouse 

gas emissions. We are proposing to either leave the 2014 biomass-based diesel volume 

requirement at 1.28 bill gal in 2014, or to increase it to 1.39 bill gal, but this extended volume 

requirement would continue to provide benefits throughout the life of the program. As observed 

above, it is most appropriate to consider these benefits within the context of full program 

implementation (i.e., the year 2022). However, we also present benefits for 110 million gallons 

of additional biodiesel produced in the year 2014 for comparison purposes. 

i. Greenhouse Gas Impacts

In the RFS2 final rule we determined that a gallon of soybean-based biodiesel results in 

an annualized GHG emission reduction of approximately 57 percent compared to the 2005 

petroleum baseline. This GHG reduction calculation is based on the annualized emissions 

stream over a 30 year period, starting in 2022 (the year when the RFS2 program will be fully 

implemented). On this basis, we estimate that the GHG benefits of 1.39 bill gal will be between 

$3 and $47 million in 2022 depending on the assumed discount rate. As described in Section 

V.C.1 of this final rulemaking, it may not be appropriate to include these GHG benefit reductions 

in our 2014 calculations. Again, this is not because EPA believes that the GHG benefits in 2014 

will be zero, but rather because it may not be consistent to cite them for an interim year of the 

program using lifecycle biofuel assessments based on a 2022 analyses. As a sensitivity, 

however, if we were to apply the 2022 GHG emissions reductions to a 1.39 bill gal biomassbased diesel mandate, the monetized GHG benefits would be from $3 million up to $42 million 

in 2014..

ii. Energy Security

Quantified energy security benefits were taken from the estimates reported in Section 

V.C.2 of this proposed rule. As noted there, we consider only the macroeconomic disruption and 

adjustment effect in its estimates of energy security benefits. Based on application of the ORNL 

methodology, we estimate that the energy security benefits of an additional 110 mill gal 

increment of biodiesel are $0.15 per gallon in 2014 and $0.16 per gallon in 2022. This translates 

to a total program benefit of about $16 million in 2014 and $18 million in 2022.

iii. Air Quality

We discuss air quality impacts qualitatively in Section V.C.3 of this proposal and expect 

an additional 110 mill gal of biodiesel (in years 2014 and 2022) would have a relatively small 

impact on ambient air quality. That said, we do expect the production and combustion of 

biodiesel to have a slightly different emissions impact relative to petroleum-based diesel. As 

presented in Table V.C.3-1, we estimated that in 2022, increased production of biodiesel would 
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impact both downstream and upstream emissions, with increases in some pollutants and 

decreases in others.

Ideally, the monetized impacts of changes in air quality related to 1.39 bill gal of 

biomass-based diesel would be estimated based on changes in ambient pollution concentrations 

and population exposure, as determined by complete air quality and exposure modeling. 

However, conducting such detailed modeling was not possible within the timeframe for this 

proposal. 

Instead, our analysis of PM2.5-related health impacts associated with 110 additional 

gallons of biodiesel (in both 2014 and 2022) uses a “dollar-per-ton” method to estimate selected 

PM2.5-related health impacts. These PM2.5-related dollar-per-ton estimates provide the total 

monetized human health impacts (the sum of premature mortality and premature morbidity) of 

reducing one ton of directly emitted PM2.5, or one ton of a pollutant that contributes to 

secondarily-formed PM2.5 (such as NOx and SOx) from a specified source.72 The dollar-per-ton 

technique has been used in previous analyses, including the 2012-2016 Light-Duty Greenhouse 

Gas Rule,73 the Ozone National Ambient Air Quality Standards (NAAQS) RIA,74 the Portland 

Cement National Emissions Standards for Hazardous Air Pollutants (NESHAP) RIA,75 and the 

final NO2 NAAQS.76

 

The analysis of 1.39 bill gal of biomass-based diesel did not estimate the direct emissions 

impacts to which we could apply the “dollar-per-ton” estimates. Instead, we converted “dollarsper-ton” to “dollars-per-gallon” by transferring the biodiesel tons-to-emissions relationship 

observed in the RFS2 analysis to the current analysis (dividing emissions in Table V.C.3-1 by 

1.44 bill gallons of biodiesel) and multiplying that by each pollutant-specific dollar-per-ton 

estimate.

 

72 Due to analytical limitations, the estimated dollar-per-ton values do not include comparable impacts related to 

reductions in other ambient concentrations of criteria pollutants (such as ozone, NO2 or SO2) or toxic air pollutants, 

nor do they monetize all of the potential health and welfare effects associated with PM2.5 or the other criteria 

pollutants. 

73 U.S. Environmental Protection Agency (U.S. EPA), 2010. Regulatory Impact Analysis, Final Rulemaking to 

Establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy 

Standards. Office of Transportation and Air Quality. April. Available at 

http://www.epa.gov/otaq/climate/regulations/420r10009.pdf. EPA-420-R-10-009

74 U.S. Environmental Protection Agency (U.S. EPA). 2008. Regulatory Impact Analysis, 2008 National Ambient 

Air Quality Standards for Ground-level Ozone, Chapter 6. Office of Air Quality Planning and Standards, Research 

Triangle Park, NC. March. Available at <http://www.epa.gov/ttn/ecas/regdata/RIAs/6-ozoneriachapter6.pdf>. 

EPA-HQ-OAR-2009-0472-0238

75 U.S. Environmental Protection Agency (U.S. EPA). 2010. Regulatory Impact Analysis: National Emission 

Standards for Hazardous Air Pollutants from the Portland Cement Manufacturing Industry. Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. August. Available on the Internet at < 

http://www.epa.gov/ttn/ecas/regdata/RIAs/portlandcementfinalria.pdf >. EPA-HQ-OAR-2009-0472-0241

76 U.S. Environmental Protection Agency (U.S. EPA). 2010. Final NO2 NAAQS Regulatory Impact Analysis

(RIA). Office of Air Quality Planning and Standards, Research Triangle Park, NC. April. Available on the Internet 

at http://www.epa.gov/ttn/ecas/regdata/RIAs/FinalNO2RIAfulldocument.pdf. Accessed March 15, 2010. EPA-HQOAR-2009-0472-0237
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The dollar-per-ton estimates used to monetize the emissions impacts from each gallon of 

biodiesel are provided in Table V.C.4-3.

Table V.C.4-3

PM2.5-related Dollar-per-ton Values (2010$) a

Year All 

Sourcesc

Upstream (Non-EGU) 

Sourcesd

Mobile Sources

SO2 NOX Direct 

PM2.5

NOX Direct 

PM2.5

Dollar-per-ton Derived from American Cancer Society Analysis (Pope et al., 

2002) Using a 3 Percent Discount Rateb

2015 $30,000 $4,900 $230,000 $5,100 $280,000

2020 $33,000 $5,400 $250,000 $5,600 $310,000

Dollar-per-ton Derived from American Cancer Society Analysis (Pope et al., 

2002) Estimated Using a 7 Percent Discount Rateb

2015 $27,000 $4,500 $210,000 $4,600 $250,000

2020 $30,000 $4,900 $230,000 $5,100 $280,000

Dollar-per-ton Derived from Six Cities Analysis (Laden et al., 2006) Estimated 

Using a 3 Percent Discount Rateb

2015 $73,000 $12,000 $560,000 $12,000 $680,000

2020 $80,000 $13,000 $620,000 $14,000 $750,000

Dollar-per-ton Derived from Six Cities Analysis (Laden et al., 2006) Estimated 

Using a 7 Percent Discount Rateb

2015 $66,000 $11,000 $510,000 $11,000 $620,000

2020 $72,000 $12,000 $560,000 $12,000 $680,000

a Total dollar-per-ton estimates include monetized PM2.5-related premature mortality and morbidity endpoints. 

Range of estimates are a function of the estimate of PM2.5-related premature mortality derived from either the ACS 

study (Pope et al., 2002) or the Six-Cities study (Laden et al., 2006).

b The dollar-per-ton estimates presented in this table assume either a 3 percent or 7 percent discount rate in the 

valuation of premature mortality to account for a twenty-year segmented cessation lag. 

c Note that the dollar-per-ton value for SO2 is based on the value for Stationary (Non-EGU) sources; no SO2 value 

was estimated for mobile sources. 

d Non-EGU denotes stationary sources of emissions other than electric generating units (EGUs).

For certain PM2.5-related pollutants (such as direct PM2.5 and NOx), we estimate different 

per-ton values for reducing mobile source emissions than for reductions in emissions of the 

same pollutant from stationary sources such as fuel refineries and storage facilities. These reflect 

differences in the typical geographic distributions of emissions of each pollutant by different 

sources, their contributions to ambient levels of PM2.5, and resulting changes in population 

exposure. We apply these separate values to estimates of changes in emissions from vehicle use

and from fuel production and distribution to determine the net change in total economic impacts 

from emissions of those pollutants. Total monetized PM2.5-related health impacts associated 

with the proposal can be found in Table V.C.4-4 and per gallon impacts can be found in Table 

V.C.4-5.

Table V.C.4-4

Total Ambient PM2.5-related Monetized Health Impacts (millions 2010$)a
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2014 Monetized Impacts (7% 

Discount Rate – 3% Discount 

Rate)

2022 Monetized Impacts (7% 

Discount Rate – 3% Discount 

Rate)

Using Dollar-per-ton Derived from American Cancer Society Analysis (Pope et al., 2002)

Downstream $5.6 - $6.2 $6.2 - $6.8

Upstream -$13 - -$15 -$14 - -$16

Net Impacts -$7.6 - -$8.4 -$8.3 - -$9.1

Using Dollar-per-ton Derived from Six Cities Analysis (Laden et al., 2006)

Downstream $14 - $15 $15 - $17

Upstream -$32 - -$36 -$35 - -$39

Net Impacts -$19 - -$21 -$20 - -$22

a Note: Negative values indicate disbenefits associated with decrements in ambient air quality.

Table V.C.4-5

Per Gallon Ambient PM2.5-related Monetized Health Impacts (2010$ per gallon)a

2014 Monetized Impacts (7% 

Discount Rate – 3% Discount 

Rate)

2022 Monetized Impacts (7% 

Discount Rate – 3% Discount 

Rate)

Using Dollar-per-ton Derived from American Cancer Society Analysis (Pope et al., 2002)

Downstream $0.05-$0.06 $0.06b

Upstream -$0.12- -$0.13 -$0.13- -$0.14

Net Impacts -$0.07 - -$0.08 -$0.08- -$0.08b

Using Dollar-per-ton Derived from Six Cities Analysis (Laden et al., 2006)

Downstream $0.12 - $0.14 $0.14 - $0.15

Upstream -$0.29 - -$0.33 -$0.32 - -$0.35

Net Impacts -$0.17 - -$0.19 -$0.18 - -$0.20

a Note: Negative values indicate disbenefits associated with decrements in ambient air quality.

bVariations in this category are less than one cent per gallon.

The method used in this analysis to estimate the monetized PM2.5-related impacts of an 

increase in biodiesel production are subject to a number of assumptions and uncertainties. 

The method does not reflect local variability in population density, meteorology, 

exposure, baseline health incidence rates, or other local factors that might lead to 

an overestimate or underestimate of the actual benefits of controlling fine 

particulates in specific locations. This is particularly a problem for the 

monetization of upstream emissions since those have a very specific geographic 

profile different to that associated with mobile source emissions.

Transferring the biodiesel tons-to-emissions relationship derived from the RFS2 

mandate in 2022 to the current analysis (in both 2014 and 2022) assumes that the 

incremental production of biodiesel associated with a 2014 increase of 110 

million gallons would yield the same relative emissions impacts, which we cannot 

say with certainty.
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This analysis assumes that all fine particles, regardless of their chemical 

composition, are equally potent in causing premature mortality. PM2.5 produced 

via transported precursors emitted from stationary sources may differ significantly 

from direct PM2.5 released from engines and other industrial sources. At the 

present time, however, no clear scientific grounds exist for supporting differential 

effects estimates by particle type. 

This analysis assumes that the health impact function for fine particles is linear 

within the range of ambient concentrations under consideration. Thus, the 

estimates include health benefits from reducing fine particles in areas with varied 

initial concentrations of PM2.5, including both regions that are in attainment with 

fine particle standard and those that do not meet the standard, down to the lowest 

modeled concentrations. This is an appropriate assumption because the scientific 

literature provides no evidence of a threshold below which health effects 

associated with exposure to fine particles - including premature death - would not 

occur.

There are several health benefits categories that we are unable to quantify due to 

limitations associated with using dollars-per-ton estimates, several of which could 

be substantial. Because NOX and VOC emissions are also precursors to ozone, 

changes in NOX and VOC would also impact ozone formation and the health 

effects associated with ozone exposure. Dollars-per-ton estimates for ozone do 

not exist due to issues associated with the complexity of the atmospheric air 

chemistry and nonlinearities associated with ozone formation. The PM-related 

benefits-per-ton estimates also do not include any human welfare or ecological 

benefits. 

5. 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. Oak Ridge 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.77 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 

 

77 “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 under the RFS2 final rule.
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estimated that the biofuels transport would constitute only 0.4% of the total freight tonnage for 

all commodities transported by the rail system through 2022.78 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. 

6. Wetlands, Ecosystems, and Wildlife Habitats

As directed by CAA section 211(o)(2)(B)(ii), in setting the 2014 biomass-based diesel 

volume requirements, EPA is to consider the impacts of production and use on wetlands, 

ecosystems and wildlife habitat. 

The most complete and up-to-date assessment of these impacts is contained in the

analysis prepared by EPA in response to the requirements set out in CAA section 204. This 

report to congress considers a range of impacts but the focus of the discussion here is on 

wetlands, ecosystems and wildlife habitats as directed by the CAA amendments. This 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 analyses contained in the report 

provide 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 final report provides extensive detail.79

This assessment focuses on the use of oil from soybeans as the feedstock for biodiesel 

production. Other oil seed feedstock sources represent a very small portion of biofuel production 

in 2014 so would be expected to have much less of an impact than soy oil. Corn oil extracted 

during the ethanol production process is increasing, and adds a small increment of supply for 

biofuel production by 2014 that will offset demands for soy and other oil seed crops, thus 

reducing potential agricultural impact of biodiesel production. Corn oil as a feedstock for 

biofuel production is driven primarily by the demand for corn ethanol, not the demand for the 

corn ethanol co-product of extracted, non-food grade corn oil. Therefore the impact of the 

relatively small supply of extracted corn oil is not considered here. 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). 

Soybean 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 soybeans. While the impacts of nutrient loading and erosion tend to be site 

specific, good farming practices including optimum fertilizer use and the set aside of sensitive 

 

78 See sections 1.6.4 and 1.6.5 of the RFS2 RIA.

79U.S. EPA (Environmental Protection Agency). February 2012. “Biofuels and the Environment: First Triennial 

Report to Congress.” Office of Research and Development, Washington, DC. EPA/600/R-10/183F
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lands via the Conservation Reserve Program (CRP) can significantly help control these adverse 

affects. Wetlands can also be adversely affected through diversion of surface and ground water 

for agricultural irrigation. Soybean 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 soybeans replace grassy crops and in general if new lands 

with diverse vegetation are converted to crop production. As noted in the RFS2 final rule, we do 

not expect the RFS program production to result in an increase in total acres of agricultural land 

under production in the U.S. compared to a reference case without the volumes required under 

the RFS2 program. The relatively small increase of 0.11 billion gallons should not appreciably 

affect the amount of land devoted to oil seed 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 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 due to cropland expansion would 

be expected.

Increased water withdrawals for soy biodiesel production can lead to more frequent lowflow conditions that reduce the availability for aquatic habitat. Additionally, waste water from 

biodiesel production can adversely affect surface water quality if not properly treated.

7. 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 both to produce the feedstock and to convert the 

feedstock into biodiesel. Soybeans are the principal feedstock used for biodiesel production 

today. They are predicted to account for 710 million gallons of the 1.39 billion gallons evaluated 

for 2014 and all of the 110 mill gal increment in biodiesel production above the 1.28 bill gal 

volume requirement for 2013. Non-food grade corn oil extracted during ethanol production, 

animal fats and recycled fats account for most of the remaining biodiesel feedstock. 

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. Soybean Production
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After corn, soybeans are the second largest agricultural crop in terms of acreage in the 

U.S. In 2010, American farmers planted 77.7 million acres of soybeans and harvested 3.4 billion 

bushels. 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. Nutrients are applied to fewer soybean acres than corn and at 

much lower rates because soybean is a legume. Legumes have associations in their roots with 

bacteria that can acquire atmospheric nitrogen and convert it into bio-available forms, reducing 

the need for external addition of nitrogen fertilizer. However, losses of nitrogen and phosphorus 

from soybeans can occur at quantities that can degrade water quality. 80 In 2006, USDA’s NASS 

estimated that nitrogen was applied to 18 percent of the 2006 soybean planted acres in the 

Program States at an average rate of 16 pounds per acre per year. Phosphate was applied to 23 

percent of the planted acres, at an average rate of 46 pounds per acre (NASS, 2007).81 The 

quantity of nitrogen fertilizer applied to soybean fields ranged from 0 to 20 pounds per acre, 

while the quantity of phosphate ranged from 0 to 80 pounds per acre. As with corn, the 

conversion of idled acreage to soybeans is estimated to result in losses of nitrogen and 

phosphorus from the soil through cultivation.82

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., 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.83

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 

 

80 Dinnes, DL; Karlen, DL; Jaynes, DB; Kaspar, TC; Hatfield, JL; Colvin, TS; Cambardella, CA. 2002. Nitrogen 

management strategies to reduce nitrate leaching in tile-drained midwestern soils. Agronomy Journal 94(1): 153-

171.

81 NASS (United States Department of Agriculture, National Agricultural Statistics Service). 2007. Agricultural 

chemical usage 2006 field crops summary. Ag Ch 1 (07)a. Available at: 

http://usda.mannlib.cornell.edu/usda/nass/AgriChemUsFC//2000s/2007/AgriChemUsFC-05-16-2007_revision.pdf.

82 Simpson, TW; Sharpley, AN; Howarth, RW; Paerl, HW; Mankin, KR. 2008. The new gold rush: Fueling ethanol 

production while protecting water quality. Journal of Environmental Quality 37(2): 318-324.

83 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.
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nutrient management to mitigate nitrogen loss to water bodies.84 However, as noted above, the 

relatively low amount of fertilizer used for soybean production tends to lessen the potential for 

nitrogen loss to water bodies. Additionally, soybean production can reduce the amount of 

biomass left on the field compared to a corn case where much of the stover is left to protect the 

soil and enhance biomass content. In such a case, there could be more soil erosion with soybean 

production compared to corn production and potentially greater nutrient runoff. Proper soil 

management can reduce this erosion concern. 

Water for soybean cultivation predominately comes from rainfall, although about 11 

percent of soybean acres in the U.S. are irrigated.85 Water use for irrigated soybean production 

in the U.S. varies from 0.2 acre-feet per acre in Pennsylvania to about 1.4 acre-feet per acre in 

Colorado, with a national average of 0.8 acre-feet of water.86 Water used for irrigation is at least 

temporarily not available for other uses and if pumped from deep aquifers, may not return to 

those aquifers for centuries

There is some concern that the demand for corn and soybeans as biofuel feedstocks may 

lead to high prices of these commodities, inducing farmers with land currently enrolled in 

USDA’s CRP to return to intensive agricultural production (e.g., Secchi et al., 2009).87 The CRP 

provides farmers with financial incentives to set aside a certain portion of their cropland in order 

to conserve or improve wildlife habitat, reduce erosion, protect water quality, and support other 

environmental goals. Biomass produced from CRP lands is considered “renewable biomass” as 

defined under the RFS regulations and is therefore eligible for use in the production of 

renewable fuel under the RFS program. The Food, Conservation, and Energy Act of 2008 

(known as the Farm Bill) capped CRP acreage at 32 million acres, reducing enrollment by 7.2 

million acres from the 2002 Farm Bill with the potential for making more acreage available for 

the production of row crops. However, even if the aggregate total of CRP protected lands does 

not change significantly, individual farmers have the opportunity to move specific land in and 

out of CRP such that the specific lands in the program do not necessarily remain fixed. 

Historically, land entering and exiting the CRP program has been more vulnerable to erosion 

than other cultivated land, but also less productive. 88 So while the conversion of CRP land to 

intensive feedstock production is possible, the likelihood of such a land use conversion is 

uncertain given practical economic and agronomic considerations.

 

84 U.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 .

85U.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

86 U. 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-RptToCongressEWwEIAcomments-FINAL.pdf 

87 Secchi, S; Gassman, PW; Williams, JR; Babcock, BA. 2009. Corn-based ethanol production and environmental 

quality: A case of Iowa and the conservation reserve program. Environmental Management 44(4): 732-744.

88 ERS (United States Department of Agriculture, Economic Research Service). 2008. 2008 farm bill side-by-side. 

Available at: http://www.ers.usda.gov/FarmBill/2008/Titles/TitleIIConservation.htm#conservation.
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b. 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, bio-refinery technology, 

effluent controls, and water re-use/recycling practices, as well as the facility location and source 

and receiving water. Discharge water quality requirements of local and regional governments 

can help assure best control practices and reduce water quality concerns.

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.89 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.90 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.91 BOD can lead to methane emissions during the water treatment process. 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. Others employ anaerobic digesters to mitigate the 

release of methane to the atmosphere.

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.92 

Results of aquatic toxicity testing of biodiesel indicate that it is less toxic than regular diesel.93 

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.94

 

89 Research continues on alternative, higher value uses of glycerin, so this excess supply may be reduced or perhaps 

not exist in 2014.

90 U.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..

91 U.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..

92 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 . 

93 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. 

94 Renewable Fuels Standard Program (RFS2), Regulatory Impact Analysis (RIA). EPA-420-R-10-006. Available 

at: http://www.epa.gov/otaq/renewablefuels/420r10006.pdf.
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8. Job Creation and Rural Economic Development

In the RFS2 final rule, we anticipated employment to increase and income to expand in 

rural areas and farming communities as a result of the increased use of renewable fuel. Income 

expansion in rural areas from renewable fuel production will contribute to rural economic 

development. As mentioned above, industry activities are currently progressing, ramping up 

biodiesel production from the approximately 0.38 bill gallons estimated to have been used in the 

U.S. in 2010 to over 1.0 bill gallons that was produced in 2011. This increase in biodiesel 

production was in large part due to bringing on line existing capacity idled due to lack of 

demand, a trend that we expect will continue into the near future. 

Employment impacts of federal rules are of particular concern in the current economic 

climate of sizeable unemployment. The recently issued Executive Order 13563, “Improving 

Regulation and Regulatory Review” (January 18, 2011), states, “Our regulatory system must 

protect public health, welfare, safety, and our environment while promoting economic growth, 

innovation, competitiveness, and job creation” (emphasis added). EPA is accordingly providing 

estimates of the effects of this proposal on domestic employment.

When the economy is at full employment, an environmental regulation is unlikely to have 

much impact on net overall U.S. employment; instead, labor would primarily be shifted from one 

sector to another. These shifts in employment impose an opportunity cost on society, 

approximated by the wages of the employees, as regulation diverts workers from other activities 

in the economy. In this situation, any effects on net employment are likely to be transitory as 

workers change jobs (e.g., some workers may need to be retrained or require time to search for 

new jobs, while shortages in some sectors or regions could bid up wages to attract workers). 

On the other hand, if a regulation comes into effect during a period of high 

unemployment, a change in labor demand due to regulation may affect net overall U.S. 

employment because the labor market is not in equilibrium. Schmalansee and Stavins point out 

that net positive employment effects are possible in the near term when the economy is at less 

than full employment due to the potential hiring of idle labor resources by the regulated sector to 

meet new requirements (e.g., to install new equipment) and new economic activity in sectors 

related to the regulated sector.95 In the longer run, the net effect on employment is more difficult 

to predict and will depend on the way in which the related industries respond to the regulatory 

requirements. For this reason, they urge caution in reporting partial employment effects since it 

can “paint an inaccurate picture of net employment impacts if not placed in the broader 

economic context.”

An increase in the volume requirement for biomass-based diesel would be expected to 

primarily affect employment in the United States through the biodiesel plants and distributors, 

and through several related sectors, specifically, industries that supply inputs in the production of 

biodiesel. Assuming the current average of 30 to 40 people to operate a biodiesel plant of 30 

 

95 Schmalensee, Richard, and Robert N. Stavins. “A Guide to Economic and Policy Analysis of EPA’s Transport 

Rule.” White paper commissioned by Excelon Corporation, March 2011 (Docket EPA-HQ-OAR-2010-0799).
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million gallons (a typical capacity for a standalone transesterification plant), an expansion of 110 

million gallons is the equivalent of adding about 4 plants representing the addition of around 138 

direct jobs for biodiesel production96. Expansions to the fuel distribution infrastructure (i.e., 

more fuel terminals, rail cars, tank trucks, barges etc.) would also be needed to support the use of 

an additional 110 million gallon increase in the 2014 volume requirement for biomass-based 

diesel. This would require an estimated 47 additional truck trips per day or an addition of 47 

delivery drivers per day assuming one trip per delivery truck per day to account for driving and 

loading / unloading time.97 Necessary support to a functioning biodiesel plant such as the 

delivery of methanol to allow processing of vegetable oil into biodiesel as well as additional 

handling at biodiesel distribution centers will also add directly to the employment impacts. 

Most large biodiesel plants in the U.S. are located in rural communities near feedstock 

(soybean or corn oil) sources. Urban biodiesel plants tend to be smaller with more diffuse 

feedstock suppliers. In 2011, approximately 71 percent of biodiesel producers were located in 

rural areas, defined as towns of less than 50,000. A 30 million gallon per year (MGY) biodiesel 

plant will spend nearly $140 million on goods and services with feedstocks accounting for more 

than 80 percent of expenditures.98 The size of the economic impact on the local economy of 

spending by an individual biodiesel plant will depend on location (e.g., State) and how much 

feedstock is sourced locally. Indirect employment is also expected to increase in rural areas as 

idled plants are brought on line and the general economy improves in response to this increase in 

production. 

In addition to the employment effects from increased biodiesel production, this proposal 

would also result in reductions in diesel fuel use, which could affect employment in the diesel 

fuel supply chain. The loss of expenditures to diesel fuel suppliers throughout the diesel fuel 

supply chain, from the petroleum refiners to diesel fuel distributors, is likely to result in some 

loss in employment in these sectors. The potential impacts on the diesel industry and other 

sectors of the economy are outside the scope of this analysis. 

To summarize, we anticipate that bringing idle biodiesel plants back online and 

expanding biodiesel distribution infrastructure in the U.S. will increase employment in the 

renewable fuels and related industries and promote rural economic development. These 

increases in employment are similar to what we anticipated when we analyzed the volume 

requirements in RFS2 final rule. 

D. Coproposal for 1.28 and 1.39 Billion Gallons 

The discussion above considers various impacts from increasing the volume requirement 

for biomass-based diesel to 1.39 bill gal in 2014. For example, there are likely to be sufficient 

feedstocks and production capacity to permit an increase of 110 mill gal over the 2013 volume 

requirement of 1.28 bill gal, and in the longer term the benefits of increased volumes of biomass-

 

96 Presentation from National Biodiesel Board, “Biodiesel Forecasts, Infrastructure, and Economic Impacts”, 

February 14, 2012.

97 Ibid.

98 Ibid.
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based diesel are expected to exceed the costs. Other impacts that we evaluated would be 

expected to be small. Moreover, current production rates in the biodiesel industry are consistent 

with a total production volume of around 1.3 bill gal for 2012. 

However, the statute also indicates that we should take into account a review of the 

implementation of the program in setting future standards. While the biodiesel industry has 

clearly demonstrated that it can produce the increasing volumes of biomass-based diesel up to 

and beyond that required by the statute, we nevertheless have limited experience at these 

productions levels in terms of impacts on various markets. For instance, the collection of 

facilities that have produced biodiesel has been highly variable over the few years since the start 

of the RFS2 program. Data collected through EMTS indicates that fourteen facilities that were 

producing biodiesel in the second half of 2010 stopped producing biodiesel by the end of 2011, 

despite the fact that nationwide production volume was increasing over this timeframe. Twentysix facilities produced biodiesel sporadically between July 2010 and May 2012, while another 34 

facilities had gaps in their production that lasted for 3 months or more. If this variability 

continued, it is unclear how it would affect markets for biodiesel.

The impacts on food prices is another area that may benefit from additional experience 

prior to raising the volume requirement of biomass-based diesel above 1.28 bill gal. While we 

projected in Section V.B.2 that the impact of an additional 110 mill gal of biodiesel on soybean 

prices would be small, soybean prices were significantly higher in 2011 than in 2010 and 2009, 

and have been steadily increasing in the first few months of 2012. Many different factors are 

known to influence food prices. However, the actual conditions of the markets for soybean oil 

and other biodiesel feedstocks under the 2012 and 2013 volume requirements of 1.0 and 1.28 bill 

gal, respectively, could be an important consideration in determining whether it is appropriate to 

increase the biomass-based diesel volume requirement above 1.28 bill gal.

It may also be beneficial to gain additional experience in how the infrastructure is 

responding to an increasing demand for biodiesel. While we do not have concrete concerns 

about the ability of the system to distribute, store, blend, and dispense biodiesel, it is possible 

that as biodiesel volumes ramp up the optimization of the biodiesel distribution system may lag 

behind. If so, additional time may be needed for the industry to find the most cost-effective 

solutions.

For these reasons, it may be prudent to leave the 2014 volume requirement at 1.28 bill gal 

before considering volume increases in subsequent years. Therefore, we are coproposing both an 

increase in the biomass-based diesel applicable volume requirement to 1.39 billion gallons in 

2014 and maintaining the 2014 volume requirement at 1.28 billion gallons. The 1.39 bill gal 

level would reflect a view that the implementation issues noted above are likely to be minor 

concerns for the 2014 year, while the 1.28 bill gal level would reflect a view that a more cautious 

approach is warranted before increasing levels above 1.28 bill gal. With regard to impacts, 

although we have estimated the impacts of increasing the volume requirement by 110 mill gal in 

2014, we would expect that there would be no attributable impacts in 2014 if we left the volume 

requirement at 1.28 bill gal. We request comment on both of these volume requirements for 

2014.
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VI. 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 the DATES section above. If you have an interest 

in the proposed standards, 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 section 

above) by 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 VI.B below.

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, 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 
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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.
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VII. 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” because it raises novel legal or policy issues arising out of legal 

mandates, the President’s priorities, or the principles set forth in the Executive Order. 

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). With the exception of cellulosic biofuel, this 

action proposes the percentage standards applicable in 2013 based on the volumes that were 

analyzed in the RFS2 final rule.

B. Paperwork Reduction Act

This action does not impose an information collection burden under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 3501 et seq. Burden is defined at 5 CFR 1320.3(b). This 

proposed rule does not impose any additional reporting requirements on regulated parties beyond 

those already required under the RFS program; therefore, there will not be any additional 

reporting burdens on entities impacted by this regulation. This action merely proposes, as 

required by section 211(o) of the Clean Air Act, the RFS annual standards for 2013.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice and comment rulemaking 

requirements under the Administrative Procedure Act or any other statute unless the agency 

certifies that the rule will not have a significant economic impact on a substantial number of 

small entities. Small entities include small businesses, small organizations, and small 

governmental jurisdictions.

For purposes of assessing the impacts of today's rule on small entities, small entity is 

defined as: (1) a small business as defined by the Small Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a 

city, county, town, school district or special district with a population of less than 50,000; and (3) 

a small organization that is any not-for-profit enterprise which is independently owned and 

operated and is not dominant in its field.
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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 biofuel for 2013 

and biomass-based diesel for 2014. 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), and this 

proposed rule will not impose any additional requirements on small entities. However, 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 proposed action contains no Federal mandates under the provisions of Title II of the 

Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531-1538 for State, local, or tribal 

governments or the private sector. This action implements mandate(s) specifically and explicitly 

set forth by the Congress in Clean Air Act section 211(o) without the exercise of any policy 

discretion by EPA. Therefore, this action is not subject to the requirements of sections 202 or 

205 of the 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. This proposed rule only applies to gasoline, diesel, and renewable fuel producers, 

importers, distributors and marketers and merely proposes the 2013 annual standards for the RFS 

program.

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 proposes the 2013 annual standards for the RFS 

program and only applies to gasoline, diesel, and renewable fuel producers, importers, 

distributors and marketers. 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 

affects transportation fuel refiners, blenders, marketers, distributors, importers, exporters, and 
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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 

(section 211(o) of the Clean Air Act). 

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use

This action is not a “significant energy action” as defined in Executive Order 13211, 

“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. This action simply proposes the annual standards for 

renewable fuel for 2013.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(‘‘NTTAA’’), Public Law 104–113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary 

consensus standards in its regulatory activities unless to do so would be inconsistent with 

applicable law or otherwise impractical. Voluntary consensus standards are technical standards 

(e.g., materials specifications, test methods, sampling procedures, and business practices) that are 

developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations when the Agency decides not to use available and 

applicable voluntary consensus standards.

This 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
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Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive 

policy on environmental justice. Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental justice part of their mission by 

identifying and addressing, as appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and activities on minority populations and lowincome populations in the United States. 

EPA has determined that this 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 RFS regulations and therefore 

will not cause emissions increases from these sources.
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VIII. 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, come from Sections 114, 208, and 301(a) of the Clean Air Act, 42 

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

List of Subjects in 40 CFR Part 80

Administrative practice and procedure, Air pollution control, Diesel fuel, Environmental 

protection, Fuel additives, Gasoline, Imports, Oil imports, Petroleum.

Dated: 

Lisa P. Jackson,

Administrator.
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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).

2. Section 80.1405 is amended by adding paragraph (a)(4) to read as follows:

§ 80.1405 What are the Renewable Fuel Standards?

(a) * * *

(4) Renewable Fuel Standards for 2013.

(i) The value of the cellulosic biofuel standard for 2013 shall be 0.020 percent.

(ii) The value of the biomass-based diesel standard for 2013 shall be 1.18 percent.

(iii) The value of the advanced biofuel standard for 2013 shall be 1.69 percent.

(iv) The value of the renewable fuel standard for 2013 shall be 10.15 percent.