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ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 80 

[EPA-HQ-OAR-2010-0133; FRL-XXXX-X] 

RIN 2060-AQ76 

Regulation of Fuels and Fuel Additives: 2012 Renewable Fuel Standards 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final rule. 

SUMMARY: Under the Clean Air Act Section 211(o), the Environmental Protection Agency is 

required to set the renewable fuel standards each November for the following year. In general 

the standards are designed to ensure that the applicable volumes of renewable fuel specified in 

the statute are used. However, the statue specifies that EPA is to project the volume of cellulosic 

biofuel production for the upcoming year and must base the cellulosic biofuel standard on that 

projected volume if it is less than the applicable volume set forth in the Act. EPA is today 

finalizing a projected cellulosic biofuel volume for 2012 and annual percentage standards for 

cellulosic biofuel, biomass-based diesel, advanced biofuel, and renewable fuels that will apply to 

all gasoline and diesel produced or imported in year 2012. In addition, today's action finalizes an 

applicable volume of biomass-based diesel that will apply in 2013. This action also presents a 

number of changes to the RFS2 regulations that are designed to clarify existing provisions and to 

address several unique circumstances that have come to light since the RFS2 program became 

effective on July 1, 2010. Finally, today's rule also makes a minor amendment to the gasoline 

benzene regulations regarding inclusion of transferred blendstocks in a refinery's early benzene 

credit generation calculations.

DATES: This final rule is effective on [insert date of publication in the Federal Register]. 

ADDRESSES: EPA has established a docket for this action under Docket ID No. EPA-HQOAR-2010-0133. 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-
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214-4816; E-mail address: macallister.julia@epa.gov, or Assessment and Standards Division 

Hotline; telephone number (734) 214-4636; E-mail address OTAQPUBLICWEB@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 

A. Does this Action Apply to Me? 

Entities potentially affected by this proposed rule are those involved with the production, 

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

fuels such as ethanol and biodiesel. Potentially regulated categories include: 

Category NAICS1

Codes 

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 final action. This table lists the types of entities 

that EPA is now aware could potentially be regulated by this final action. Other types of entities 

not listed in the table could also be regulated. To determine whether your activities will be 

regulated by this final action, you should carefully examine the applicability criteria in 40 CFR 

part 80. If you have any questions regarding the applicability of this final action to a particular 

entity, consult the person listed in the preceding section. 

Outline of this preamble 

I. EXECUTIVE SUMMARY ................................................................................................................. 6

A. Standards for 2012 ....................................................................................................................................... 7

1. Assessment of 2012 Cellulosic Biofuel Volume ............................................................................................... 7

2. Advanced Biofuel and Total Renewable Fuel in 2012 ..................................................................................... 8

3. Percentage Standards for 2012 ....................................................................................................................... 9

B. 2013 Biomass-Based Diesel Volume ...........................................................................................................10

C. Regulatory Changes ...................................................................................................................................10
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D. 2012 Price for Cellulosic Biofuel Waiver Credits ......................................................................................10

E. Assessment of the Aggregate Compliance Approach ...................................................................................11

II. PROJECTION OF CELLULOSIC VOLUME PRODUCTION AND IMPORTS FOR 2012 .12

A. Statutory Requirements .............................................................................................................................13

B. Cellulosic Biofuel Volume Assessment ........................................................................................................14

1. Existing Cellulosic Biofuel Facilities ............................................................................................................... 14

2. Potential New Facilities in 2012 .................................................................................................................... 16

3. Imports of Cellulosic Biofuel ......................................................................................................................... 19

4. Projections from the Energy Information Administration ............................................................................. 20

5. Comments on the Proposed Rule ................................................................................................................. 24

6. Summary of Volume Projections................................................................................................................... 25

C. Advanced Biofuel and Total Renewable Fuel in 2012 ..................................................................................28

D. Biomass-Based Diesel in 2012 .....................................................................................................................32

III. FINAL PERCENTAGE STANDARDS FOR 2012 ...............................................................40

A. Background .................................................................................................................................................40

B. Calculation of Standards .............................................................................................................................41

1. How Are the Standards Calculated?.............................................................................................................. 41

2. Small Refineries and Small Refiners ............................................................................................................ 42

3. Final Percentage Standards ........................................................................................................................... 44

IV. BIOMASS-BASED DIESEL VOLUME FOR 2013 .........................................................46

A. STATUTORY REQUIREMENTS .................................................................................................46

B. Factors Considered in Assessing 2013 Biomass-Based Diesel Volumes ....................................................48

1. Demand for Biomass-Based Diesel............................................................................................................... 49

2. Availability of Feedstocks to Produce 1.28 Billion Gallons of Biodiesel ..................................................... 53

a. Grease and Rendered Fats ........................................................................................................................ 53

b. Corn Oil .................................................................................................................................................... 54

c. Soybean Oil .............................................................................................................................................. 55

d. Other Vegetable Oils ................................................................................................................................ 58

3. Production Capacity ...................................................................................................................................... 58

4. Consumption Capacity .................................................................................................................................. 59

5. Biomass-Based Diesel Distribution Infrastructure ........................................................................................ 61

C. Impacts of 1.28 billion gallons of Biomass-Based Diesel ...........................................................................65

1. Climate Change ............................................................................................................................................. 67

2. Energy Security ............................................................................................................................................. 68

3. Agricultural Commodities and Food Prices .................................................................................................. 68

4. Air Quality .................................................................................................................................................... 70

5. Transportation Fuel Cost ............................................................................................................................... 72
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6. Deliverability and Transport Costs of Materials, Goods, and Products Other Than Renewable Fuel .......... 74

7. Wetlands, Ecosystems, and Wildlife Habitats ............................................................................................... 75

8. Water Quality and Quantity .......................................................................................................................... 76

a. Impacts on Water Quality and Water Quantity Associated with Soybean Production ............................. 77

b. Impacts on Water Quality and Water Quantity Associated with Biodiesel Production ........................... 79

9. Job Creation and Rural Economic Development .......................................................................................... 80

D. Final 2013 Volume for Biomass-Based Diesel ...........................................................................................81

E. 2014 and Beyond ........................................................................................................................................82

V. CHANGES TO RFS2 REGULATIONS ........................................................................................82

A. Summary of Amendments .........................................................................................................................82

B. Technical Justification for Equivalence Value Application ......................................................................84

C. Changes to Definitions of Terms................................................................................................................85

1. Definition of Annual Cover Crop.................................................................................................................. 85

2. Definition of "Naphtha" ................................................................................................................................ 86

D. Technical Amendments Related to RIN Generation and Separation .......................................................86

1. RIN Separation Limit for Obligated Parties .................................................................................................. 86

2. RIN Retirement Provision for Error Correction ............................................................................................ 89

3. Production Outlook Reports Submission Deadline ....................................................................................... 92

4. Attest Procedures .......................................................................................................................................... 93

5. Treatment of Canola and Rapeseed ............................................................................................................... 94

E. Technical Amendments Related to Registration & Recordkeeping ..........................................................94

1. Construction Discontinuance & Completion Documentation ....................................................................... 94

2. Third-Party Engineering Reviews ................................................................................................................. 95

3. Foreign Ethanol Producers ............................................................................................................................ 97

F. Additional Amendments and Clarifications ..............................................................................................97

1. Third-Party Engineering Review Addendum ................................................................................................ 97

2. RIN Generation for Fuel Imported from a Registered Foreign Producer ...................................................... 98

3. Bond Posting ................................................................................................................................................. 98

5. Acceptance of Separated Yard Waste and Food Waste Separation Plans ..................................................... 99

6. Transferred Blendstocks in Early Benzene Credit Generation Calculations ............................................... 100

VI. ANNUAL ADMINISTRATIVE ANNOUNCEMENTS ............................................... 102

A. 2011 Price for Cellulosic Biofuel Waiver Credits ........................................................................................ 102

B. Assessment of the Domestic Aggregate Compliance Approach ................................................................. 103

VII. COMMENTS OUTSIDE THE SCOPE OF THIS RULEMAKING ........................ 105

VIII. PUBLIC PARTICIPATION ................................................................................................... 108
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IX. STATUTORY AND EXECUTIVE ORDER REVIEWS ....................................................... 109

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

and Regulatory Review ...................................................................................................................................... 109

B. Paperwork Reduction Act .......................................................................................................................... 109

C. Regulatory Flexibility Act .......................................................................................................................... 110

D. Unfunded Mandates Reform Act ............................................................................................................... 111

E. Executive Order 13132: Federalism ........................................................................................................... 111

F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments ......................... 112

G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks ........... 112

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

Distribution, or Use ............................................................................................................................................ 112

I. National Technology Transfer Advancement Act ....................................................................................... 112

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

Low-Income Populations .................................................................................................................................... 113

K. Congressional Review Act ......................................................................................................................... 113

X. STATUTORY AUTHORITY ...................................................................................................... 114
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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 

revised regulatory requirements on March 26, 20101

. The transition from the RFS1 requirements 

of EPAct to the RFS2 requirements of EISA generally occurred on July 1, 2010. 

 Under RFS2, EPA is required to determine and publish the applicable annual percentage 

standards for each compliance year by November 30 of the previous year. As part of this effort, 

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

year. If the projected volume of cellulosic biofuel production is less than the applicable volume 

specified in section 211(o)(2)(B)(i)(III) of the statute, EPA must lower the applicable volume 

used to set the annual cellulosic biofuel percentage standard to the projected volume of 

production. When we lower the applicable volume of cellulosic biofuel in this manner, we are 

also authorized to lower the applicable volumes of advanced biofuel and/or total renewable fuel 

by the same or a lesser amount. Since these evaluations are based on evolving information about 

emerging segments of the biofuels industry, and may result in the applicable volumes differing 

from those in the statute, we believe that it is appropriate to establish the applicable volumes 

through a notice-and-comment rulemaking process. Today's notice provides our final evaluation 

of the projected production of cellulosic biofuel for 2012, our evaluation of whether to lower the 

applicable volumes of advanced biofuel and total renewable fuel, and the final percentage 

standards for compliance year 2012. We are finalizing a cellulosic biofuel requirement of 10.45 

mill ethanol-equivalent gallons for 2012, and are not reducing the advanced biofuel or total 

renewable fuel requirements below the levels specified in the statute. The evaluations that led to 

these 2012 volume requirements were based on a consideration of comments received in 

response to our notice of proposed rulemaking published on July 1, 20112

, the estimate of 

projected biofuel volumes that the EIA is required to provide to EPA by October 31, and other 

information that became available. 

 The statute also requires EPA to determine and promulgate the applicable volume of 

biomass-based diesel that will be required in 2013 and beyond, as the statute does not specify the 

applicable volumes for years after 2012. This determination must be made at least 14 months 

prior to the year in which the volume will be required. The statute identifies a number of factors 

that EPA must take into consideration in establishing the applicable volume of biomass-based 

diesel for years after 2012. Today's notice includes our final assessment of these factors and the 

volume of biomass-based diesel that will apply for 2013. 

 Today's final rule does not include an assessment of the environmental impacts of the 

percentage standards we are setting for 2012. All of the impacts of the RFS2 program were 

addressed in the RFS2 final rule published on March 26, 2010, including impacts of the biofuel 

standards specified in the statute. Today's rulemaking simply sets the standards for 2012 whose 

impacts were already analyzed previously. However, as described more fully in Section IV.A, 

 

1

 75 FR 14670 

2

 76 FR 38844 
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we are required to analyze a specified set of environmental and economic impacts for the 

biomass-based diesel volume we are setting for 2013. 

 Today's notice also finalizes a number of changes to the RFS2 regulations. These 

changes are designed to reduce confusion among regulated parties and streamline 

implementation by clarifying certain terms and phrases and addressing unique circumstances that 

came to light after the RFS2 program went into effect on July 1, 2010. Additionally, this notice 

also makes a minor amendment to the gasoline benzene regulations regarding inclusion of 

transferred blendstocks in a refinery’s early benzene credit generation calculations. Further 

discussion of all of these changes can be found in Section V. 

 Finally, in today's rulemaking we are announcing the price for cellulosic biofuel waiver 

credits that will be available for compliance with the 2012 cellulosic biofuel requirement, and are 

also announcing the results of our annual assessment of the aggregate compliance approach for 

U.S. crops and crop residue. These announcements are provided in Section VI. 

 

A. Standards for 2012 

 1. Assessment of 2012 Cellulosic Biofuel Volume

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

2012, we researched all potential production sources by company and facility. This included 

sources that were still in the planning stages, those that were under construction, and those that 

are already producing some volume of cellulosic ethanol, cellulosic diesel, or some other type of 

cellulosic biofuel. Facilities primarily focused on research and development work with no 

intention of marketing any fuel produced were not considered for this assessment. From this 

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

producing some volume of qualifying cellulosic biofuel for use as transportation fuel in 2012. 

 In today's final rule we specify the projected available volume for 2012 that forms the 

basis for the percentage standard for cellulosic biofuel. To arrive at this final volume, we took 

into consideration additional factors such as the current and expected state of funding, the status 

of the technology, 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 RINs. We also considered projections of cellulosic biofuel provided by the 

Energy Information Administration (EIA). Further discussion of these factors can be found in 

Section II.B. 

 In our assessment we focused on domestic sources of cellulosic biofuel. While imports 

of cellulosic biofuels are possible and would be eligible to generate RINs, we believe this is 

unlikely due to local demand for cellulosic biofuels in the countries in which they are produced 

as well as the cost associated with transporting these fuels to the U.S. Of the domestic sources, 

we estimated that six facilities can make volumes of cellulosic biofuel available for 

transportation use in the U.S. in 2012. These facilities are listed in Table I.A.1-1 along with our 

estimate of the projected 2012 volume for each. 
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Table I.A.1-1 

Projected Available Cellulosic Biofuel Plant Volumes for 2012 

Company Location Fuel type 

Projected available 

volume (million 

ethanol-equivalent 

gallons) 

American Process Inc. Alpena, MI Ethanol 0.5 

Fiberight Blairstown, IA Ethanol 2.0 

INEOS Bio Vero Beach, FL Ethanol 3.0 

KiOR Columbus, MS Gasoline, Diesel 4.8 

KL Energy Corp. Upton, WY Ethanol 0.1 

ZeaChem Boardman, OR Ethanol 0.05 

Total 10.45 

Each of the facilities listed in the Table I.A.1-1 are at different points in their progress 

towards the production of commercial volumes of cellulosic biofuel. KL Energy Corp. is the 

only facility in the United States currently generating cellulosic biofuel RINs. American Process 

Inc., Fiberight, and ZeaChem all anticipate completing construction on their production facilities 

in late 2011 or early 2012 and plan to begin producing biofuel soon after their facilities are 

complete. INEOS Bio and KiOR are targeting April 2012 and mid 2012 for the start-up of their 

respective cellulosic biofuel production facilities. The variation in these 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 

from each these facilities. 

 2. Advanced Biofuel and Total Renewable Fuel in 2012

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

total renewable fuel if we determine that the projected volume of cellulosic biofuel production 

for 2012 falls short of the statutory volume of 500 million gallons. As shown in Table I.A.1-1, 

we have determined that this is the case. Therefore, we also must evaluate the need to lower the 

applicable volumes for advanced biofuel and total renewable fuel. 

 To address the need to lower the advanced biofuel standard, we first consider whether it 

appears likely that the biomass-based diesel volume of 1.0 billion gallons specified in the statute 

can be met in 2012. As discussed in Section II.E, we believe that the 1.0 billion gallon standard 

can indeed be met. Since biodiesel has an Equivalence Value of 1.5, 1.0 billion physical gallons 

of biodiesel would provide 1.5 billion ethanol-equivalent gallons that can be counted towards the 

advanced biofuel standard of 2.0 billion gallons. Of the remaining 0.5 bill gallons, 10.45 mill 

gallons will be met with cellulosic biofuel. Based on our analysis as described in Section II.C, 

we believe that there will be sufficient volumes of other advanced biofuels, such as imported 

sugarcane ethanol, additional biodiesel, or renewable diesel, such that the standard for advanced 

biofuel can remain at the statutory level of 2.0 billion gallons. 
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 3. Percentage Standards for 2012

 The renewable fuel standards are expressed as a volume percentage, and are used by each 

refiner, blender or importer to determine their renewable fuel volume obligations. The 

applicable percentages are set so that if each regulated party meets the percentages, and if EIA 

projections of gasoline and diesel use are accurate, then the amount of renewable fuel, cellulosic 

biofuel, biomass-based diesel, and advanced biofuel used will meet the volumes required on a 

nationwide basis. 

 To calculate the percentage standard for cellulosic biofuel for 2012, we have used the 

projected annual volume of 10.45 million ethanol-equivalent gallons (representing 8.65 million 

physical gallons). The applicable volumes for biomass-based diesel, advanced biofuel, and total 

renewable fuel for 2012 will be those specified in the statute. These volumes are shown in Table 

I.A.3-1. 

Table I.A.3-1 

Final Volumes for 2012 

Actual Volume Ethanol Equivalent 

Volumea

Cellulosic biofuel 8.65 mill gal 10.45 mill gal 

Biomass-based diesel 1.0 bill gal 1.5 bill gal 

Advanced biofuel 2.0 bill gal 2.0 bill gal 

Renewable fuel 15.2 bill gal 15.2 bill gal 

a

Biodiesel and cellulosic diesel have equivalence values of 1.5 and 1.7 ethanol 

equivalent gallons respectively. As a result, ethanol-equivalent volumes are larger 

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

 Four separate standards are required under the RFS2 program, corresponding to the four 

separate volume requirements shown in Table I.A.3-1. The specific formulas we use to calculate 

the renewable fuel percentage standards are contained in the regulations at §80.1405 and 

repeated in Section III.B.1. The percentage standards represent the ratio of renewable fuel 

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

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

provided by EIA3

. 

 In March 2011, DOE evaluated the impacts of the RFS program on small entities and 

concluded that some small refineries would suffer a disproportionate economic hardship if 

required to participate in the program4

. As a result, we are required to exempt these few 

refineries from being obligated parties for a minimum of two years, and must also exempt their 

gasoline and diesel volumes from the calculation of the annual percentage standards. The final 

standards for 2012 are shown in Table I.A.3-2 and include the adjustment for exempt small 

 

3

 [XXX insert reference to final EIA letter when we get it XXX ]. 

4

 "Small Refinery Exemption Study: An Investigation into Disproportionate Economic Hardship," U.S. Department 

of Energy, March 2011. 
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refineries (which constitute about 2.4% of the gasoline pool and 2.9% of the diesel pool). 

Detailed calculations can be found in Section III. 

 

Table I.A.3-2 

Final Percentage Standards for 2012 

Cellulosic biofuel 0.006% 

Biomass-based diesel 0.89% 

Advanced biofuel 1.19% 

Renewable fuel 9.03% 

B. 2013 Biomass-Based Diesel Volume 

 While section 211(o)(2)(B) of the Clean Air Act specifies the volumes of biomass-based 

diesel (BBD) through year 2012, it directs the EPA to establish the applicable volume of BBD 

for years after 2012 no later than 14 months before the first year for which the applicable volume 

will apply. In today's action we are finalizing an applicable volume of 1.28 bill gallons for 

biomass-based diesel (BBD) for 2013. This is the volume that was projected for 2013 in the 

RFS2 final rulemaking, and we are requiring it in 2013 based on consideration of the factors 

specified in the statute, including a consideration of biodiesel production, consumption, and 

infrastructure issues. As required under the statute, we also assessed the likely impact of BBD 

production and use in a variety of areas, including climate change, energy security, the 

agricultural sector, air quality, and others. Section IV provides additional discussion of our 

assessment of the 2013 volume of 1.28 bill gallons of BBD. 

C. Regulatory Changes 

 In today's action we are also finalizing a number of changes to the RFS2 regulations. 

These changes are intended to: 

• Clarify certain provisions because we have learned that there is some confusion among 

some regulated parties 

• Clarify the application of certain provisions to unique circumstances 

• Provide greater specificity in the definition of certain terms 

• Correct regulatory language that inadvertently misrepresented our intent 

Today's rule also makes a minor amendment to the gasoline benzene regulations regarding 

inclusion of transferred blendstocks in a refinery's early benzene credit generation calculations. 

A detailed discussion of these regulatory changes is provided in Section V. 

D. 2012 Price for Cellulosic Biofuel Waiver Credits 

 Since we are reducing the required volume of cellulosic biofuel for 2012 below the 

applicable volume specified in the statute, EPA is required to offer biofuel waiver credits to 
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Page 11 of 126 

obligated parties that can be purchased in lieu of acquiring cellulosic biofuel RINs. These 

waiver credits are not allowed to be traded or banked for future use, are only allowed to be used 

to meet the 2012 cellulosic biofuel standard, and cannot be applied to deficits carried over from 

2011. Moreover, unlike cellulosic biofuel RINs, waiver credits may not be used to meet either 

the advanced biofuel standard or the total renewable fuel standard. For the 2012 compliance 

period, we are making cellulosic biofuel waiver credits available to obligated parties for end-ofyear compliance should they need them at a price of $0.78 per credit. Further discussion is 

provided in Section VI.A. 

E. Assessment of the Aggregate Compliance Approach 

As part of the RFS2 regulations, EPA established an aggregate compliance approach for 

renewable fuel producers who use planted crops and crop residue from U.S. agricultural land. 

This compliance approach relieved such producers (and importers of such fuel) of the individual 

recordkeeping and reporting requirements otherwise required of producers and importers to 

verify that feedstocks used in the production of RIN-qualifying renewable fuel meet the 

definition of renewable biomass. EPA determined that 402 million acres of U.S. agricultural 

land was available in 2007 (the year of EISA enactment) for production of crops and crop 

residue that would meet the definition of renewable biomass, and determined that as long as this 

total number of acres is not exceeded, it is unlikely that new land has been devoted to crop 

production based on historical trends and economic considerations. We indicated that we would 

conduct an annual evaluation of total U.S. acreage that is cropland, pastureland, or conservation 

reserve program land, and that if the value exceed 402 million acres, producers using 

domestically-grown crops or crop residue to produce renewable fuel would be subject to 

individual recordkeeping and reporting to verify that their feedstocks meet the definition of 

renewable biomass. 

The RFS2 regulations provide that EPA will make a finding concerning whether the 2007 

baseline amount of U.S. agricultural land has been exceeded in a given year and will publish this 

finding in the Federal Register by November 30 of the same year. Based on data provided by the 

USDA, we have estimated that U.S. agricultural land reached 396 million acres in 2011, and thus 

did not exceed the 2007 baseline acreage. 

 We also stated in the preamble to the final RFS2 rule that if, at any point, EPA finds that 

the total agricultural land is greater than 397 million acres, EPA will conduct further 

investigations to evaluate validity of the domestic aggregate compliance approach. The total 

acreage estimate of 396 million acres does not exceed the trigger point for further investigation, 

therefore EPA does not plan to conduct further investigations into this matter. Additional 

discussion on this matter can be found in Section VI.B of this preamble. 
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II. Projection of Cellulosic Volume Production and Imports for 2012 

 In order to project production volume of cellulosic biofuel in 2012 for use in setting the 

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

produce qualifying volumes for consumption as transportation fuel, heating oil, or jet fuel in the 

U.S. in 2012. This section describes the projected available volume of cellulosic biofuel in 2012 

as well as some of the uncertainties associated with those volumes. Section III describes the 

derivation of the percentage standards that will apply to obligated parties in 2012. 

 The 2012 volume projections in today's final rule were based on several sources of 

information: 

• An estimate from EIA of the volumes of transportation fuel, biomass-based 

diesel, and cellulosic biofuel that they project will be sold or introduced into 

commerce in the U.S. in 2012. 

• Progress that the cellulosic biofuel industry is making in 2011 

• Our own assessment of the cellulosic biofuel industry's projected volumes for 

2012 

• Comments in response to the NPRM 

 In addition to the sources of information listed above EPA had also intended to consider 

the Production Outlook Reports that are required under §80.1449 for all registered renewable 

fuel producers and importers. These Production Outlook Reports were not as useful as EPA had 

hoped in helping to provide information on the intentions of cellulosic biofuel producers in 2012 

as very few had registered under the RFS program and they were thus not required to submit a 

report. EPA expects that in future years as more cellulosic biofuel producers register under the 

RFS program these reports will become of greater value in helping to determine the appropriate 

projected available volume of cellulosic biofuel. 

 In directing EPA to project cellulosic biofuel production for purposes of setting the 

annual cellulosic biofuel standard, Congress did not specify what degree of certainty should be 

reflected in the projections. However, in response to the NPRM, some commenters cited 

Executive Order 13563 which states that regulations must in general "promote predictability and 

reduce uncertainty." We agree that this must be a goal in the process of determining the 

appropriate cellulosic biofuel requirement for 2012. The greatest certainty is achieved when the 

level of the standard is firmly established before it becomes applicable, and all regulated parties 

can have confidence regarding the immutability of that standard. Doing this ensures that 

obligated parties know what their obligations will be so that they can begin efforts to meet those 

obligations, and biofuel producers know what baseline demand for their product will be so that 

they can secure financing and ramp up production with confidence. 

 In contrast to statements made by several obligated parties, meeting the dual goals of 

predictability and reduce uncertainty does not require EPA to specify an applicable volume for 

cellulosic biofuel that is as low as possible, or based only on demonstrated production. Due to 

the availability of cellulosic waiver credits, obligated parties always have the means to comply 
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with the cellulosic biofuel standard that we set5

, and at a cost that is predictable. There is, 

therefore, no uncertainty with regard to the level of their obligations or the means available to 

achieve it. 

 Moreover, Executive Order 13563 also states that regulations must in general promote 

"economic growth, innovation, competitiveness, and job creation." Consistent with this goal, we 

believe that the cellulosic biofuel standard should promote growth in the cellulosic biofuel 

industry according to the goals that Congress established in the RFS program. While the 

cellulosic biofuel standard that we set should be within the range of what can be attained based 

on projected domestic production and import potential, the standard that we set in large part 

determines the volumes that will be made available. This is consistent with comments submitted 

by the Biotechnology Industry Organization and the Renewable Fuels Association. Thus while 

any standard we set for cellulosic biofuel standard for 2012 will have some uncertainty in terms 

of actual attainment, our intention is to balance such uncertainty with the objective of promoting 

growth in the industry. Our final projected available volume of 8.65 million gallons of cellulosic 

biofuel (10.45 million ethanol-equivalent gallons) for 2012 reflects these considerations. 

A. Statutory Requirements 

 The volumes of renewable fuel to be used under the RFS2 program each year (absent an 

adjustment or waiver by EPA) are specified in CAA 211(o)(2). These volumes for 2012 are 

shown in Table II.A-1. 

Table II.A-1 

Required Volumes in the Clean Air Act for 2012 (bill gal) 

Actual Volume Ethanol Equivalent 

Volume 

Cellulosic biofuel 0.5a 0.5 

Biomass-based diesel 1.0 1.5 

Advanced biofuel 2.0a 2.0 

Renewable fuel 15.2a 15.2 a

 These values assume that the biofuels would be ethanol. If any portion of the biofuels used to 

meet these applicable volumes has a volumetric energy content greater than that for ethanol, these 

values will be lower.

By November 30 of each year, the EPA is required under CAA 211(o) to determine and publish 

in the Federal Register the renewable fuel percentage standards for the following year. These 

standards are to be based in part on transportation fuel volumes estimated by the Energy 

Information Administration (EIA) for the following year. The calculation of the percentage 

standards is based on the formulas in §80.1405(c) which express the required volumes of 

renewable fuel as a volume percentage of gasoline and diesel sold or introduced into commerce 

in the 48 contiguous states plus Hawaii. 

 

5

 So long as the required volume is below the volume specified in the statute, such that cellulosic biofuel waiver 

credits are available. 
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 The statute requires that if EPA determines that the projected volume of cellulosic biofuel 

production for the following year is less than the applicable volume shown in Table II.A-1, then 

EPA is to reduce the applicable volume of cellulosic biofuel to the projected volume available 

during that calendar year. In addition, if EPA reduces the required volume of cellulosic biofuel 

below the level specified in the statute, the Act also indicates that we may reduce the applicable 

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

B. Cellulosic Biofuel Volume Assessment 

 In order to project cellulosic biofuel production for 2012, EPA has tracked the progress 

of over 100 biofuel production facilities. From this list of facilities we used publically available 

information, as well as information provided by DOE and USDA, to make a preliminary 

determination of which facilities are the most likely candidates to produce cellulosic biofuel and 

make it commercially available in 2012. Each of these companies was investigated further in 

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

production volumes for the coming years. Information such as the funding status of these 

facilities, announced construction and production ramp up periods, and annual fuel production 

targets were taken into account. Our projection of the volume of cellulosic biofuel production in 

2012 is based on this information as well as our own assessment of the likelihood of these 

facilities successfully producing cellulosic biofuel in the volumes indicated. A brief description 

of each of the companies we believe can produce cellulosic biofuel and make it commercially 

available in 2012 can be found below. 

 1. Existing Cellulosic Biofuel Facilities

The rule that established the required 2011 cellulosic biofuel volume identified five 

production facilities that we projected would produce cellulosic biofuel and make the fuel 

commercially available in 2011. Each of these production facilities are now structurally 

complete, however they are in various stages of biofuel production. All of these facilities have 

either produced some volume of cellulosic biofuel in 2011, or are on schedule to do so later in 

the year. Only KL Energy and Range Fuels, however, have completed registration of cellulosic 

biofuel production facilities under the RFS2 program and as such they are currently the only 

facilities of the five listed here currently eligible to generate cellulosic biofuel RINs. For more 

background information on each of these facilities see the 2011 standards rule6

. 

 DuPont Danisco Cellulosic Ethanol (DDCE) successfully started up their small 

demonstration facility in Vonore, Tennessee in late 2010. This facility has a maximum 

production capacity of 250,000 gallons of ethanol per year and uses an enzymatic hydrolysis 

process to convert corn cobs into ethanol. In conversations with EPA in July 2011 DDCE 

indicated that this facility was currently producing ethanol at approximately half the nameplate 

capacity, corresponding to a volume of 125,000 gallons per year. The focus of this facility, 

however, remains gathering information to help successfully design and operate DDCE’s first 

commercial scale facility. All the cellulosic ethanol currently produced at this facility is used for 

 

6

 75 FR 76790, December 9, 2010. 
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testing purposes or given away. No RINs are currently generated for this ethanol and it is not 

available for purchase by obligated parties. DDCE has indicated that they have no plans to 

generate RINs or sell ethanol produced at their facility in Vonore in 2012. No volume of 

cellulosic ethanol has therefore been included in the projections of available cellulosic biofuel 

for 2012. 

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

separated municipal solid waste (MSW) into ethanol. Construction on the first stage of 

Fiberight’s Blairstown, Iowa facility was completed in the summer of 2010. The production 

capacity of the first stage of this project is 2 million gallons of ethanol per year. Fiberight had 

planned to begin production of cellulosic biofuel from this facility in late 2010 but poor 

economic conditions, due in part to low cellulosic RIN values in 2010, caused them to postpone 

fuel production. Fiberight had also planned to begin construction on an expansion of this facility 

in late 2010 that would increase the production potential to 6 million gallons of ethanol per year, 

but were unable to secure funding to carry out the construction as planned. They have since 

secured funding and began construction on the expansion of their Blairstown facility in April 

2011. Fiberight anticipates that they will begin fuel production in early 2012 and will ramp up 

production at this facility throughout 2012. EPA projects the production of 2 million gallons of 

cellulosic ethanol from this facility in 2012. 

 KiOR continues to produce a small volume of renewable crude from agricultural residue 

at their demonstration facility in Houston, Texas using a technology they call Biomass Catalytic 

Cracking (BCC). This technology uses heat and a proprietary catalyst to convert biomass to a 

renewable crude with a relatively low oxygen content. The renewable crude is then upgraded to 

produce renewable gasoline and diesel, as well as a small quantity of fuel oil. While KiOR plans 

to continue to operate their Houston facility in 2012 its main purpose will be to provide small 

quantities of fuel for testing purposes and to provide data for the optimization of KiOR’s first 

commercial facility. In conversations with EPA KiOR has indicated that it is unlikely that any 

significant volume of fuel from this facility will be sold commercially. EPA has therefore not 

included any volume from KiOR’s Houston facility in our projected available volumes for 2012. 

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

sugars using a thermal-mechanical pretreatment process followed by an enzymatic hydrolysis. It 

had initially planned to used woody biomass as their feedstock for cellulosic biofuel production; 

however its production process is versatile enough to allow for a wide variety of cellulosic 

feedstocks to be used. In August 2010 KL Energy announced a joint development agreement 

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

modify KL Energy’s facility in Upton, Wyoming to allow it to process bagasse and other waste 

products. If successful, Petrobras and KL Energy plan to work together to integrate the 

technology into currently existing ethanol production facilities in Brazil. The modifications to 

KL Energy’s facility were completed earlier this year. KL Energy is currently producing small 

volumes of cellulosic ethanol and plans to continue to do so throughout 2012. In August 2011 

KL Energy successfully registered its cellulosic biofuel production facility under the RFS 

program making it eligible to generate RINs for biofuel produced from this facility. KL Energy 

has indicated to EPA its intent to generate RINs for the fuel it produces and to sell it 
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commercially in the United States. EPA projects that 100,000 gallons of cellulosic ethanol will 

be available from this facility in 2012. 

 Range Fuels began production of methanol at their Soperton, Georgia facility in the third 

quarter of 2010. This facility uses a thermochemical technology to produce syngas (consisting 

of mostly hydrogen and carbon monoxide) from a woody biomass feedstock. The syngas is then 

converted into fuel with the aid of a chemical catalyst developed by Range. Range has 

developed the capability to produce both methanol and ethanol, depending on the catalyst used. 

In January 2011, after producing a small volume of ethanol from this facility and proving this 

capability, Range Fuels shut down the Soperton facility in order to work through technical 

difficulties they had been experiencing. No timeline has been given for the restart of this facility 

and fuel production from this facility in 2012 appears unlikely. No cellulosic fuel production 

from Range Fuels has been included in EPA’s 2012 projected available volume. 

 2. Potential New Facilities in 2012

In the proposed rule EPA discussed five new cellulosic biofuel production facilities that 

had plans to begin commercial production at some point in 2012. These facilities were at various 

stages in the construction process, and as such had various degrees of uncertainty associated with 

any projected 2012 commercial production. Three of these facilities, those being developed by 

INEOS Bio, KiOR, and ZeaChem, have made significant progress towards completion and are 

expected to produce and market cellulosic biofuel in 2012. Two of the companies mentioned in 

the proposed rule, Fulcrum Bioenergy and Terrabon, are no longer on a schedule to produce 

cellulosic biofuel in 2012. Finally, EPA has become aware of a sixth company, American 

Process Inc., which is developing a cellulosic biofuel project that is likely to produce and market 

some volume of cellulosic biofuel in 2012. The following section provides updated information 

on each of the companies discussed in the proposed rule, as well as a summary of the project 

being developed by American Process Inc. 

 Fulcrum Bioenergy is planning to build a facility capable of producing 10.5 million 

gallons of cellulosic ethanol and 16 megawatts of renewable electricity per year. It has 

developed a thermochemical technology to produce ethanol from separated MSW via syngas 

using a chemical catalyst. In November 2010 Fulcrum announced that it had received a term 

sheet for an $80 million loan guarantee from DOE and was entering into the final phase of the 

loan guarantee program. Prior to that Fulcrum had announced that it had signed long term 

feedstock supply contracts for this facility as well as engineering, procurement, and construction 

contracts. In January 2011 Fulcrum announced it had closed on a $75 million Series C financing 

that would provide the remaining necessary capital for the construction of its first commercial 

production facility pending the closing of its DOE loan guarantee. The loan guarantee, however, 

has yet to be finalized. As a result the start of the construction of this facility, originally planned 

for the second quarter of 2011, is now expected to begin in late 2011. EPA has not included any 

volume of cellulosic biofuel from Fulcrum Bioenergy’s facility in our 2012 projected available 

volume because of this delay. 
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 INEOS Bio has developed a process for producing cellulosic ethanol by first gasifying 

feedstock material into a syngas and then using naturally occurring bacteria to ferment the 

syngas into ethanol. In January 2011 USDA announced a $75 million loan guarantee for the 

construction of INEOS Bio’s first commercial facility to be built in Vero Beach, Florida. This 

facility will be capable of producing 8 million gallons of cellulosic biofuel as well as 6 

megawatts of renewable electricity from a variety of feedstocks including yard, agricultural, and 

wood waste, as well as separated MSW. On February 9, 2011 INEOS Bio broke ground on this 

facility. Since February 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 is complete. Three million gallons of 

cellulosic ethanol from this facility has been included in EPA’s projected available volume for 

2012. 

 After successful operation of their demonstration plant in Houston, Texas KiOR began 

construction on its first commercial scale facility in May 2011. This facility, located in 

Columbus, Mississippi, will convert biomass to a low oxygen biocrude using a process KiOR 

calls Biomass Catalytic Cracking (BCC). BCC uses a catalyst developed by KiOR in a process 

similar to Fluid Catalytic Cracking currently used in the petroleum industry. KiOR’s Columbus 

facility will also be capable of upgrading this biocrude into finished gasoline and diesel as well 

as a small quantity of fuel oil. KiOR plans to finish construction on this facility in the first half 

of 2012 and begin commercial production early in the third quarter of 2012. KiOR has also 

announced plans to construct several more commercial scale biofuel production facilities in 

Mississippi and across the southeastern United States. It is unlikely any of these additional 

facilities will begin production of biofuel in 2012. EPA has included 3 million gallons of 

cellulosic biofuel (4.8 million ethanol equivalent gallons) from KiOR’s Columbus facility in our 

projected available volume for 2012. 

Terrabon completed construction of a small demonstration scale facility for the 

conversion of MSW and other waste materials into gasoline in 2010 and are currently developing 

plans for their first commercial scale facility. Terrabon utilizes a unique production process that 

can be used to produce gasoline, diesel, or jet fuel. Feedstock is first fermented into carboxylic 

acids by a variety of micro organisms. These carboxylic acids are then neutralized to form 

carboxylate salts that are dewatered, dried, and thermally converted to ketones. Finally, the 

ketones are hydrogenated to form alcohols which can then be refined into gasoline, diesel, or jet 

fuel. Terrabon had hoped to begin producing cellulosic biofuel at their first commercial scale 

facility some time in 2012, however difficulties in securing the necessary funding have delayed 

the expected start up of their first commercial scale facility to 2013. EPA has not included any 

volume of cellulosic biofuel from Terrabon in our 2012 projected available volume. 

 ZeaChem has begun construction on a small demonstration scale facility in Boardman, 

Oregon capable of producing 250,000 gallons of cellulosic ethanol per year. Its production 

process uses a combination of biochemical and thermochemical technologies to produce ethanol 

and other renewable chemicals from cellulosic materials. The feedstock is first fractionated into 

two separate streams containing cellulosic sugars and lignin. The cellulosic sugars are fermented 

into ethyl acetate using a naturally occurring acetogen, which can then be hydrogenated into 

ethanol. The hydrogen necessary for this process is produced by gasifying the lignin stream 
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from the cellulosic biomass. ZeaChem’s process is flexible and is capable of producing a wide 

range of renewable chemical and fuel molecules in addition to ethanol. ZeaChem has made 

significant progress on its demonstration facility and currently plans to begin production of 

cellulosic ethanol from this facility in early 2012. It has indicated to EPA, however, that it is 

highly unlikely to achieve full production capacity at this facility in its first year of production 

and has suggested that the production of 50,000 gallons of cellulosic ethanol from this facility in 

2012 is a more realistic expectation. Despite this small volume, ZeaChem does intend to 

generate RINs for the fuel that they produce and to market it commercially. Based on this 

information EPA has included 0.05 million gallons of cellulosic ethanol in our projected 

available volume for 2012. 

 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 hemicelluloses portion of woody biomass using hot water and hydrolyzes it into 

cellulosic sugars. These cellulosic 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 larger scale facilities API anticipates burning the 

residual biomass in a boiler to produce renewable steam and electricity as well as cellulosic 

biofuel. Construction of the Alpena, Michigan facility began in March 2011 and API anticipates 

beginning the production of cellulosic ethanol at this site early in 2012. API was not discussed 

as a potential producer of cellulosic biofuels in 2012 in our proposed rule due to uncertainty 

about its ability to generate RINs with the intended feedstock and production process. EPA 

anticipates these issues will be resolved. Cellulosic biofuel produced at API’s facility will 

therefore likely be eligible for cellulosic RINs. For our 2012 projected available volume of 

cellulosic biofuels we have included 500,000 gallons of cellulosic ethanol from this facility. 

This volume represents the low end of API’s production target for that year due to the 

uncertainties associated with the start up of a new industrial facility utilizing a technology 

unproven at industrial scale. 

 Another potential source of cellulosic biofuel in 2012 is the application of a technology 

being developed by EdeniQ. EdeniQ is developing a suite of enzymes capable of breaking down 

cellulose into simple sugars that can then be fermented into ethanol. Rather than build its own 

production facilities EdeniQ plans to license its enzymes to existing corn ethanol facilities. Such 

licensing would be accompanied by the Cellunator, an advanced milling device EdeniQ has 

developed to reduce the particle size of corn kernels to enable greater conversion of starch to 

ethanol as well as the conversion of cellulose to simple sugars. EdeniQ claims that its 

technology would allow corn ethanol facilities to increase ethanol production by 1-2% by 

converting the cellulosic portion of the corn kernel into ethanol. EdeniQ is also working to 

increase the effectiveness of its enzymes in order to enable ethanol production increases of 3-4% 

from the cellulose in the corn kernel in the future. EdeniQ plans to begin commercial trials of its 

technology in the second half of 2011. This technology has the potential to be implemented 

rapidly and produce significant amounts of cellulosic ethanol in 2012 as it requires relatively 

small capital additions to already existing corn ethanol facilities. While this technology is 

promising, there is currently no pathway in the RFS2 regulations for the generation of cellulosic 

biofuel RINs using the cellulosic portion of the corn kernel as a feedstock. Moreover, EdeniQ 
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has not announced any agreements with corn ethanol producers to install this technology to 

enable the production of cellulosic ethanol. For these reasons, EPA has not included any 

cellulosic ethanol production from EdeniQ’s technology in our 2012 projections. 

In addition to the facilities mentioned above, EPA is also aware of three companies 

planning to begin the production of cellulosic biofuels in early 2013. Coskata, Enerkem, and 

Poet are planning on completing construction on their first commercial scale cellulosic biofuel 

facilities in late 2012 or early 2013 and producing commercial volumes of biofuels in 2013. 

While all of these facilities continue to make progress towards commercial production of 

cellulosic biofuel in 2013 it is highly unlikely that any of these facilities will be capable of 

producing cellulosic biofuels by the end of 2012. EPA has therefore not included any volume of 

cellulosic biofuel from these facilities in our projected available volume for 2012. These 

facilities, along with several other commercial cellulosic biofuel facilities planning to begin 

production in 2013, notably the first commercial scale facilities from Abengoa and Mascoma, 

indicate that the potential exists for the rapid expansion of production volumes in future years. 

 3. Imports of Cellulosic Biofuel

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

biofuel available in the United States, producers and/or importers of cellulosic biofuel produced 

in other countries may also generate RINs and participate in the RFS2 program. While the RFS2 

program does provide a financial incentive for companies to import cellulosic biofuels into the 

United States, the combination of local demand, financial incentives from other governments, 

and transportation costs for the cellulosic biofuel has resulted in no cellulosic biofuel being 

imported to the United States thus far. EPA believes this situation is likely to continue in the 

near future. Additionally, the majority of internationally based cellulosic biofuel facilities that 

currently exist or plan to complete construction by the end of 2012 are small research and 

development or pilot facilities not designed for the commercial production of fuel. 

Two notable exceptions, both located in Canada, are Enerkem and Iogen. Enerkem has a 

currently existing commercial production facility in Westbury, Quebec and is expecting to 

complete construction on a second facility in Edmonton, Alberta in late 2011. Iogen has a small 

demonstration facility in Ottawa and is currently exploring the possibility of building its first 

commercial facility near Prince Albert, Saskatchewan. The large expected production volumes 

and relatively small distance this fuel would have to be transported to reach the United States 

make these facilities the most likely candidates to import cellulosic biofuel into the United 

States. In conversations with EPA, however, both companies indicated that they had no current 

intentions of importing fuel from their Canadian production facilities into the United States. On 

September 1, 2010 the government of Canada finalized regulations requiring all gasoline sold in 

Canada to have a renewable content of 5% and all diesel fuel and heating oil to have a renewable 

content of 2%. These regulations will further increase local demand for any cellulosic biofuel 

produced from these two facilities and decrease the likelihood of any of this fuel being exported 

to the United States. For these reasons we have not included any cellulosic biofuel production 

from foreign facilities in our projections of cellulosic biofuel availability in 2012. 
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 4. Projections from the Energy Information Administration

Section 211(o)(3)(A) of the Clean Air Act requires EIA to "...provide to the Administrator of the 

Environmental Protection Agency an estimate, with respect to the following calendar year, of the 

volumes of transportation fuel, biomass-based diesel, and cellulosic biofuel projected to be sold 

or introduced into commerce in the United States." EIA provided these estimates to us on 

DATE.7 With regard to cellulosic biofuel, the EIA estimated that the available volume in 2012 

would be 6.9 million gallons based on its assessment of the utilization of production capacity. A 

summary of the commercial scale plants they considered and associated production volumes is 

shown below in Table II.B.4.In addition to the facilities listed in this table EIA also projects that 

three pilot-scale facilities, those owned by American Process (Alpena, MI), KL Process Design 

(Upton, WY) and ZeaChem (Boardman, OR) will produce an additional 0.2 million gallons of 

cellulosic biofuel and make it available for sale in the US in 2012.

 

7

 Letter from Richard Newell, EIA Administrator to Lisa Jackson, EPA Administrator October XX, 2011. 
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Table II.B.4 

Commercial-scale cellulosic biofuel plants expected to generate cellulosic biofuel RINs in 2012 

Year 

Online Company Location Product 

Nameplate 

Capacity 

gallons) 

(million Utilization 

Projected 

(%) 

Projected 

Production 

gallons) 

(million 

2011/12 Fiberight, LLC Blairstown, IA Ethanol 6.4 25% 1.6 

2012 KiOR Columbus, MS Liquids 12.2 25% 3.1 2012 INP Bioenergy Vero Beach, FL Ethanol 8.0 25% 2.0 

Total 26.6 25% 6.7 
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EIA’s projections of cellulosic biofuel production in 2012 are very similar to EPA’s 

projections discussed above and summarized in Section II.B.6 below. The lists of companies 

that EIA and EPA expect to generate cellulosic biofuel RINS in 2012 are the same. There are, 

however, several small differences in the volumes of cellulosic biofuel expected to be produced 

at some of the production facilities listed. EPA has slightly higher projections of cellulosic 

biofuel production for Fiberight (2 million gallons vs. 1.59 million gallons), INEOS Bio (3 

million gallons vs. 2 million gallons), and American Process Inc. (0.5 million gallons vs. less 

than 0.2 million gallons). These slight variations are a result of different methodologies used by 

EIA and EPA to project biofuel production in future years. Both Fiberight and INEOS Bio are 

commercial scale facilities that plan to begin production in 2012. As a result, EIA has used a 

standard utilization factor of 25% (used for the first year of production for all commercial scale 

facilities) along with the nameplate capacity of these facilities to project their production 

volumes for 2012. While this is a reasonable approach, EPA believes it is more appropriate to 

consider the timing of the anticipated start up of these facilities within 2012. Facilities planning 

to begin production early in the year should not have the same expected utilization factor as 

those planning to begin production near the end of the year. Both Fiberight and INEOS Bio plan 

to complete construction and begin the production of fuel in early 2012, and therefore EPA has 

projected production volumes from these facilities that correspond to utilization factors of 

slightly higher than 25%. 

EIA’s projected production volume for American Process Inc. assumes a utilization 

factor of 10%, consistent with the factor that EIA uses for all demonstration scale facilities. 

While this may be reasonable in many cases as the purpose of most pilot plants is not to produce 

fuel for commercial scale, American Process Inc. has communicated to EPA that it plans to 

produce volumes approaching its facility’s nameplate capacity in their first year. While EPA 

believes this is unlikely due to the challenges of starting up a facility utilizing a technology that 

has not been proven at commercial scale, we believe a volume corresponding to a utilization rate 

higher than 10%, but at the low end of American Process Inc’s target production range is 

appropriate. While the production volumes of the other companies listed in EIA and EPA’s 

projected available volume tables are not identical the differences are very small and their impact 

on the overall volume projection is negligible. 

While the cellulosic biofuel volume projections for 2012 provided by EIA are not 

identical to those being finalized in this rule EPA believes that they are similar enough to support 

the volumes we are finalizing. Where differences exist they are primarily due to EPA’s 

consideration of facility specific situations rather than use of uniform utilization factors. As 

discussed above, EPA believes this is appropriate, and that wherever possible these facility 

specific factors should be taken into account. CAA 211(o)(7)(D) vests the authority for making 

the projection with EPA, since it provides that the projection is “determined by the Administrator 

based on the estimate provided [by EIA].” If Congress intended that EPA simply adopt EIA’s 

projection without an independent evaluation, it would not have specified that the projection is 

“determined by the [EPA] Administrator”. Although the statute provides that our determination 

must be “based on the estimate provided” by EIA, we believe that our consideration of EIA’s 

estimate in deriving our own projection as described above satisfies this statutory requirement. 
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5. Comments on the Proposed Rule

 EPA received comments on our proposed rule recommending various methodologies or 

suggested volumes for the final rule. Several parties supported our projected volumes and 

emphasized the importance of maintaining a consistent policy supporting growth in the cellulosic 

biofuel industry. Other comments we received recommended that the volume we set for 

cellulosic biofuel be based only on the demonstrated production rates of facilities that have been 

in production for at least three months. EPA believes this approach is inconsistent with the 

requirement that the mandated volume of cellulosic biofuel be based on the projected, not 

demonstrated, volume for any given year. Using the approach recommended by the commenters 

would effectively project no market growth from the end of 2011 through 2012, and would lead 

to no 2012 market demand for additional cellulosic biofuel capacity that comes on line during 

the course of 2012, hindering industry growth. As a result, the incentives for the cellulosic 

biofuels industry to grow, which are one of the primary purposes of the RFS program and which 

are consistent with Executive Order 13563, would be compromised. 

Several other commenters claimed that cellulosic biofuel technology was not yet capable 

of producing the volumes of fuel indicated in our proposal and that the proposed range of 

cellulosic biofuels was too high. Chevron suggested that EPA finalize the lower end of the 

proposed range (3.55 million ethanol-equivalent gallons). After reassessing the state of the 

cellulosic biofuel industry and tracking the progress being made towards the production of 

cellulosic biofuels at commercial scale facilities, EPA believes the industry is capable of 

exceeding the lower end of the range of projected volume from our proposed rule. In order to 

provide the appropriate economic conditions for the cellulosic biofuel industry to grow in 

accordance with the objectives of the statute, it is important that these fuels, once produced, have 

a viable market. EPA believes that setting the 2012 standard for cellulosic biofuels at the low 

end of the proposed range, or some lower volume, could potentially result in a depressed market 

for cellulosic biofuel and would discourage cellulosic biofuel producers from producing 

quantities of fuel in 2012 that are actually attainable. 

 Alternatively, we also received comments requesting that EPA finalize the high end of 

the proposed volume (15.7 ethanol-equivalent gallons). While this approach would provide a 

strong incentive for potential cellulosic biofuel producers to maximize their production of fuel, 

EPA does not believe it would be consistent with the requirement that the volume mandate be 

based on the projected production volume. As discussed above, several companies have 

experienced delays in their construction plans since the proposed rule has been published, and 

others have lowered their production targets or indicated that they no longer intend to generate 

RINs for the cellulosic biofuel they produce. While it is possible that one or more of the 

companies for whom we have included volumes in our 2012 projection may produce a greater 

volume of fuel than we currently anticipate, EPA does not believe it would be appropriate to rely 

on such speculation in setting the applicable volume of cellulosic biofuel for 2012. We believe 

that the 2012 cellulosic biofuel applicable volume of 8.65 million gallons (10.45 million ethanolequivalent gallons) finalized in this rule is a reasonable projection of the volume of cellulosic 

biofuel that will be produced and made available for RFS compliance in 2012. While this 

volume is slightly higher than the volume projected by EIA we believe this is appropriate based 

on the consideration of company specific factors such as when in the year the companies 
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anticipate the start of fuel production and production targets shared with EPA. The difference in 

the methodologies used for EIA and EPA’s projections is discussed in further detail in Section 

II.B.4. 

 The Consumers Energy Alliance, in addition to suggesting that the range of cellulosic 

biofuel production in our proposed rule was too high, also requested that EPA perform a costbenefit analysis to determine the implications of our proposed standards. The Clean Air Act 

clearly states that in the event that the projected volume of cellulosic biofuel production for the 

following year is less than the applicable volume shown in Table II.A-1, EPA is to reduce the 

applicable volume of cellulosic biofuel to the projected volume available during that calendar 

year. Since the mandated volume for any given year is to be based solely on the projected 

volume available for that year, a cost-benefit analysis is not necessary. 

 Two cellulosic biofuel companies, American Process Inc. and ZeaChem, commented on 

the volume of cellulosic biofuels they expect to produce in 2012 and requested that EPA’s 

projections of available volumes of cellulosic biofuel be adjusted accordingly. After 

consideration of these comments and additional information provided by these two companies 

EPA agrees that the adjustments they suggested are appropriate. As a result a volume of 500,000 

gallons of cellulosic ethanol from American Process Inc., a volume representing the lower end of 

their production target for 2012, has been included in our projected available volume. The 

volume of fuel projected from ZeaChem’s facility has been changed to 50,000 gallons of 

cellulosic ethanol in 2012 to more accurately reflect their current expectations for their facility. 

 Finally, EPA received several comments from obligated parties requesting that in any 

year in which actual annual production of cellulosic biofuel falls below the applicable volume 

used to set the annual standard, that EPA use its waiver authority to waive a volume of cellulosic 

biofuel equal to the shortfall in February of the following year, prior to the February 28 deadline 

for submission of compliance demonstration reports by obligated parties. This approach, these 

commenters argued, would ensure that their obligations match the number of cellulosic biofuel 

RINs that are available in the market. These comments deal with EPA’s general waiver 

authority under CAA 211(o)(7)(A), and thus are not directly related to the annual standard 

setting process or the waiver authority that is specific to cellulosic biofuel under 211(o)(7)(D). 

At this time EPA has received no petitions for a waiver of the 2011 cellulosic biofuel volume 

under 211(o)(7)(A) due to inadequate domestic supply, and thus we are not considering at this 

time whether and how any portion of the 2011 cellulosic biofuel applicable volume should be 

waived. 

6. Summary of Volume Projections

 The information EPA has gathered on the potential cellulosic biofuel producers in 2012, 

described above, allows us to project facility-specific volumes of cellulosic biofuel production 

for 2012. This information is summarized in Table II.B.6-1 below. 
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Table II.B.6-1 

Cellulosic Biofuel 2012 Projected Available Volume 

Company Name Location Feedstock Fuel Capacity 

(MGY) 

Earliest 

Production 

2012 Projected 

Available Volume 

(MG) 

Ethanol 

Equivalent 

Gallons (MG) 

INEOS BioFiberight Blairstown, IA MSW Ethanol 6 Early 2012 2.0 2.0 American Process Inc. Alpena, MI Waste Wood Ethanol 0.9 Early 2012 0.5 0.5 

a Vero Beach, FL Ag Residue, MSW Ethanol 8 May 2012 3.0 3.0 

ZeaChem Boardman, OR Planted Trees Ethanol 0.25 Early 2012 0.05 0.05 KL Energy Upton, WY Wood Waste Ethanol 1.5 Online 0.1 0.1 KiOR Columbus, MS Pulp Wood Gasoline, Diesel 10 Mid 2012 3.0 4.8 

Total 8.65 10.45 

This facility is listed as INP Bioenergy in EIA’s projections a
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Page 27 of 126 

 While the production volumes in Table II.B.6-1 have some uncertainty, we believe that a 

total volume of 8.65 million gallons (10.45 million ethanol-equivalent gallons) is reasonably 

attainable. By basing the 2012 cellulosic biofuel standard on the reasonably attainable volumes 

rather than proven production volumes, we aim to avoid a scenario in which cellulosic biofuel 

production exceeds the mandated volume; no mechanism exists for this standard to be raised 

should cellulosic biofuel production exceed the 2011 standard. Such a scenario would result in 

weak demand for cellulosic biofuels and RINs. Moreover, the standard that we set determines in 

large part the volumes of cellulosic biofuel that will be produced. The intent of Congress in 

establishing the RFS program through EISA was to provide a reliable market for renewable fuels 

and in doing so to spur growth in the cellulosic biofuels industry. EPA believes the projected 

available volume finalized in this rule best reflects these intentions. 

 Based on our assessment of the potential production capabilities of individual companies 

as described above, EPA is finalizing the cellulosic biofuel standard for 2012 at 10.45 million 

ethanol-equivalent gallons of cellulosic biofuel. This number represents the volume of RINgenerating cellulosic biofuel that we believe can be made available for use as transportation fuel, 

heating oil, or jet fuel in 2012. It incorporates reductions from the annual production capacity of 

each facility based on when fuel production can begin and assumptions regarding a ramp-up 

period to full production. We believe that a production volume of 10.45 million ethanolequivalent gallons is reasonably attainable despite the uncertainties. Moreover, by setting the 

standard for cellulosic biofuel based on the volumes that are reasonably attainable, we are 

providing incentives for producers to overcome uncertainties and greater opportunities for 

funding based on an established demand. 

 There are also a variety of factors that could lead to production volumes greater than 

those listed in Table II.B.6-1 and make up for potential shortfalls elsewhere. For instance: 

• For each of the facilities listed, we are projecting that their production will be some 

volume less than the capacity of their facility. It is possible, however, that these 

companies could produce a greater volume of fuel than they are currently anticipating or 

has been projected by EPA. 

• It is possible that companies that are currently targeting 2013 for commercial production 

may produce cellulosic biofuel ahead of schedule and generate RINs in 2012. None of 

this volume was included in our projection for 2012. 

• A high demand for cellulosic biofuels may be sufficient to cause companies to import 

fuel into the United States, even if they currently have no plans to do so. As described in 

Section II.B.3 above, there are several foreign producers that are either producing 

cellulosic biofuel now, or could potentially produce some cellulosic biofuel volume in 

2012. 

 Finally, we note that if the actual volume of cellulosic biofuel RINs that are available in 

2012 falls short of the 10.45 million gallon RINs used to derive the 2012 cellulosic biofuel 

standard, obligated parties have other recourses: 
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Page 28 of 126 

• Purchase cellulosic biofuel waiver credits from the EPA (see further discussion in Section 

VI.A) 

• Carry over a deficit from 2012 into 2013 according to §80.1427(b) under certain 

conditions 

C. Advanced Biofuel and Total Renewable Fuel in 2012 

 Under CAA 211(o)(7)(D)(i), EPA has the discretion to reduce the applicable volumes of 

advanced biofuel and total renewable fuel in the event that the projected volume of cellulosic 

biofuel production is determined to be below the applicable volume specified in the statute. As 

described in Section II.B above, we are indeed projecting the volume of cellulosic biofuel 

production for 2012 at significantly below the statutory applicable volume of 500 million 

gallons. Because cellulosic biofuel is used to satisfy the cellulosic biofuel standard, the 

advanced biofuel standard, and the total renewable fuel standard, any reductions in the applicable 

volume of cellulosic biofuel will also affect the means through which obligated parties comply 

with the advanced biofuel standard and the total renewable fuel standard. Therefore, we have 

considered whether and to what degree to lower the advanced biofuel and total renewable fuel 

applicable volumes for 2012. 

 If the required volume of cellulosic biofuel for a given year is less than the volume 

specified in the statute, it is important to evaluate whether there would be sufficient volume of 

advanced biofuels to satisfy the applicable volume of advanced biofuel volume set forth in the 

statute. Even with a reduced volume of cellulosic biofuel, other advanced biofuels, such as 

biomass-based diesel, sugarcane ethanol, or other biofuels, may be available in sufficient 

volumes to make up for the shortfall in cellulosic biofuel. 

 Several commenters stated their belief that the applicable volume of advanced biofuel 

should always be lowered concurrently, and to the same degree, that the applicable volume of 

cellulosic biofuel is lowered from the levels set forth in the statute. Since we are finalizing a 

cellulosic biofuel applicable volume today that is approximately 490 million gallons below the 

500 mill gal applicable volume specified in the statute, this approach would lead to a reduction in 

the advanced biofuel standard of 490 million gallons as well, from 2,000 mill gallons to 1,510 

mill gallons. However, as described in the NPRM, we believe that it would not be consistent 

with the energy security and greenhouse gas reduction goals of the statute to reduce the 

applicable volume of advanced biofuel set forth in the statute if there are sufficient volumes of 

advanced biofuels available, even if those volumes do not include the amount of cellulosic 

biofuel that Congress may have desired. Our authority to lower the advanced biofuel and/or total 

renewable fuel applicable volumes is discretionary, and in general we believe that actions to 

lower these volumes should only be taken if insufficient volumes of qualifying biofuel can be 

made available, based on such circumstances as insufficient production capacity, insufficient 

feedstocks, competing markets, constrained infrastructure, or the like. As discussed below, we 

project that sufficient volumes of advanced biofuel can be made available in 2012 such that the 

2.0 bill gallon advanced biofuel requirement need not be reduced. 
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Page 29 of 126 

 If we were to maintain the advanced biofuel, biomass-based diesel, and total renewable 

fuel volume requirements at the levels specified in the statute, while also lowering the cellulosic 

biofuel standard to 10.45 million ethanol-equivalent gallons, then 1,510 million gallons of the 

2.0 billion gallon advanced biofuel mandate would be satisfied automatically through the 

satisfaction of the cellulosic and biomass based diesel standards. An additional 490 million 

ethanol-equivalent gallons of additional advanced biofuels would be needed. See Table II.C-1. 

Table II.C-1 

Projected Fuel Mix in 2012 Assuming No Change in Advanced Biofuel or Total Renewable Fuel 

Volume Requirements (mill gallons) 

 Ethanol-Equivalent 

Volume 

Physical Volume 

Total renewable fuel 

Conventional renewable fuela

15,200 

13,200 

14,535 - 14,698 

13,200 

Total advanced biofuel 2,000 1,335 - 1,498 

Cellulosic biofuel 

Biomass-based diesel 

Other advanced biofuelb

10.45 

1,500 

490 

8.65 

1,000 

326 - 490c

a

 Predominantly corn-starch ethanol

b

 Rounded to nearest million gallons for simplicity 

c Physical volume is a range because other advanced biofuel may be ethanol, biodiesel, or some 

combination of the two 

 The most likely sources of additional advanced biofuel would be imported sugarcane 

ethanol and additional biomass-based diesel, though there may also be some volumes of other 

types of advanced biofuel available as discussed below. To determine if there are likely to be 

sufficient volumes of these biofuels to meet the need for 490 million gallons of other advanced 

biofuel, we first examined historical data on ethanol imports and projections from EIA and 

USDA for 2012. Brazilian imports have made up a sizeable portion of total ethanol imported 

into the U.S. in the past, and these volumes were predominantly produced from sugarcane. 

Ethanol imports averaged about 380 million gallons per year over the last five years, and reached 

an all-time high of 730 million gallons in 20068

. However, ethanol imports were significantly 

lower in 2010 than in previous years, and continue to be low in the first half of 2011. This 

decline in imports may be related to the cessation of the duty drawback that became effective on 

October 1, 2008, to changes in world sugar prices, and increases in demand within Brazil.9 

Several commenters cited these lower import volumes in the last two years as evidence that 

importation of sugarcane ethanol will be low in 2012 as well. 

 However, we believe that the broader view of historical data on sugarcane ethanol 

imports supports our view that Brazil has significant export potential under the appropriate 

economic circumstances. Monthly ethanol imports in June and July of 2011 were significantly 

higher than during any of the previous 16 months, at 71 and 305 thousand barrels, respectively.10 

Moreover, Brazil continues to be second worldwide in the production of ethanol, producing a 

 

8

 "Monthly U.S. Imports of Fuel Ethanol," EIA, released 3/30/2011 

9

 Lundell, Drake, “Brazilian Ethanol Export Surge to End; U.S. Customs Loophole Closed Oct. 1,” Ethanol and 

Biodiesel News, Issue 45, November 4, 2008. 

10 Monthly U.S. Imports of Fuel Ethanol, Energy Information Administration, Release Date 9/29/2011 
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Page 30 of 126 

total of 6.9 bill gallons in 2009.11 By establishing an increased U.S. demand for 490 million 

gallons of other advanced biofuel in 2012, we would be re-establishing an export market for 

Brazilian sugarcane ethanol that could compete with the use of sugarcane to produce sugar, and 

thus Brazilian producers will have an incentive to export higher volumes of sugarcane ethanol to 

the U.S. California's Low Carbon Fuel Standard also went into effect in 2010, and may result in 

some refiners importing additional volumes of sugarcane ethanol from Brazil into California in 

2012. These same volumes would count towards the federal RFS2 program as well. 

 Projections from other sources also suggest that a large portion of the 490 million gallons 

of advanced biofuel needed could be supplied by imported sugarcane ethanol. For instance, in 

its Annual Energy Outlook 2011, EIA projects ethanol imports of approximately 300 million 

gallons for 201212. More significantly, the university-based Food and Agricultural Policy 

Research Institute (FAPRI) released its 2011 U.S. and World Agricultural Outlook report in 

which it projects 2012 ethanol imports of 728 million gallons.13 This is a substantial increase 

compared to FAPRI's previous projection of 317 mill gallons as cited in our NPRM. According 

to the FAPRI report, this increase in imports into the U.S. would be concurrent with reductions 

in imports into other countries rather than an increase in exports of sugarcane ethanol from 

Brazil. 

 We also examined the potential for excess biodiesel to help meet the need for 490 million 

gallons of advanced biofuel. The applicable volume of biomass based diesel established in the 

statute for 2012 is 1.0 billion gallons (which corresponds to 1.5 billion ethanol-equivalent 

gallons). As discussed more fully in Section II.D below, we believe that the biodiesel industry 

has the potential for producing volumes above 1.0 billion gallons if demand for such volume 

exists. 

There are also other potential sources of advanced biofuels. Based on RIN generation 

reports collected via the EPA-Moderated Transaction System (EMTS), 32 million ethanolequivalent gallons of advanced biofuel with a D code of 5 were produced in the first half of 

201114. Extrapolated to the end of the year, it would be reasonable to expect a total of over 60 

million ethanol-equivalent gallons of such advanced biofuel to be produced in 2011. Production 

Outlook Reports also provided some insight into producers' expectations for 2012. For 2012, 

producers of advanced biofuel projected that they would produce about 80 million ethanolequivalent gallons, composed of some combination of ethanol, renewable diesel, and heating oil. 

 Another potential source of advanced biofuels is electricity generated from renewable 

biomass that is used as a transportation fuel. EIA data indicates that in 2009, the most recent 

year for which data is available, 35.6 million megawatt-hours of electricity was generated from 

wood and wood derived fuels, and an additional 18.4 million megawatt-hours was generated 

 

11 Portal Brasil, Energy Matrix for Ethanol, http://www.brasil.gov.br/sobre/economy/energymatrix/ethanol/br_model1?set_language=en 

12 Table 11 of AEO2011, Report Number DOE/EIA-0383(2011). 

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

13 Table "Ethanol Trade", Commodity Outlook/Biofuels, FAPRI-ISU 2011 World Agricultural Outlook. 

http://www.fapri.iastate.edu/outlook/2011/ 

14 RFS2 EMTS Informational Data, updated on August 18, 2011. 

http://www.epa.gov/otaq/fuels/renewablefuels/compliancehelp/rfsdata.htm 
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Page 31 of 126 

from other biomass in the United States15. This is significantly more than the 6.8 million 

megawatt-hours of electricity used in the transportation sector in 200916, equivalent to about 300 

mill ethanol-equivalent gallons. While not all the feedstocks used to generate the electricity 

included in these totals would meet the RFS2’s renewable biomass definition, this remains a very 

large potential source of advanced biofuel RINs. 

 Currently, there are no valid pathways in Table 1 to §80.1426 for the generation of RINs 

representing electricity used as transportation fuel. However, several companies have 

approached EPA with requests for such a pathway, and investigations are underway. It is 

possible that one or more new pathways for electricity may be available for use in 2012. 

 In addition to verifying that the feedstocks used to generate renewable electricity meet 

the renewable biomass definition, producers would also be required to document that the 

electricity they produce is used as a transportation fuel in order to be eligible to generate RINs. 

Until recently there were very few vehicles capable of using electricity as a transportation fuel, 

limited mainly to electric trains and trolley cars. Expected increases in the number of vehicles 

with this capability, such as electric vehicles and plug in hybrids, has the potential to 

dramatically increase the degree to which electricity is able to be used as a transportation fuel. 

Verifying that the renewable electricity produced is used as a transportation fuel would still 

remain a challenge, however the potential for capitalizing on the RIN value, without the 

necessity of making major changes in the areas of fuel production, distribution, or end use, may 

be a large enough incentive to overcome this challenge. While the uncertainties associated with 

the generation of advanced biofuel RINs representing renewable electricity used as 

transportation fuel prevent EPA from making a quantitative projection for 2012, such RINs may 

nevertheless play a role in meeting the advanced biofuel standard. 

In light of the potential volumes of imported sugarcane ethanol, excess biodiesel, and 

other sources of advanced biofuel, we continue to believe that there will likely be sufficient 

volumes of advanced biofuels to meet the need for 490 million ethanol-equivalent gallons. As a 

result, the applicable volume of advanced biofuel set forth in the statute need not be lowered. A 

number of commenters on the NPRM agreed with this assessment. However, several 

commenters raised a concern about the ethanol blendwall, saying that the volume of ethanol that 

can be legally and practically consumed in 2012 is a limiting factor in how much advanced 

biofuel can be consumed. We disagree. Based on gasoline energy demand projections from 

EIA17, a total of about 14.3 bill gallons of ethanol could be consumed in 2012 if all gasoline 

contained 10% ethanol. Under the requirements of the RFS program, however, the total volume 

of ethanol that would need to be consumed to meet the RFS standards would be no more than 

13.7 bill gallons in 201218. This assumes an extreme case in which all renewable fuel that is not 

advanced biofuel is assumed to be ethanol, and all advanced biofuel other than biomass-based 

diesel is also assumed to be ethanol. 

 

15 Table ES1 of Electric Power Industry 2009: Year in Review. Available online: 

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

16 Table 46 of AEO2011, Report Number DOE/EIA-0383(2011). 

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

17 Total energy demand for light-duty vehicles, motorcycles, and nonroad per AEO 2011 Tables 10, 45, and 46. 

18 From Table II.C-1, sum of ethanol-equivalent gallons of conventional renewable fuel, cellulosic biofuel, and other 

advanced biofuel. 
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It is possible that more ethanol may be produced/imported in 2012 than is necessary to 

meet the RFS requirements, and such circumstances could accelerate the arrival of the blendwall. 

However, this would only occur if market forces favored the consumption of higher volumes of 

ethanol, and we canniot make reliable predictions of such market forces. Since the applicable 

standards are set before a given compliance year begins, obligated parties should be coordinating 

with producers, distributors, and blenders of the various forms of ethanol (e.g. cellulosic ethanol, 

corn-ethanol, sugarcane ethanol) to ensure that all RFS standards are met by the end of the 

compliance period. 

Based on our assessment of the availability of volumes of advanced biofuel beyond those 

required to meet the cellulosic biofuel and biomass-based diesel standards, we do not believe that 

the advanced biofuel standard need be lowered below the 2.0 billion gallon level specified in the 

Act. Thus, we are not reducing the applicable volume of advanced biofuel for 2012. 

A number of parties that commented on the NPRM requested that the applicable volume 

for total renewable fuel in 2012 be reduced. However, all such commenters tied the reduction in 

total renewable fuel to a reduction in the advanced biofuel standard. Since we are not lowering 

the advanced biofuel standard for 2012, and there are expected to be sufficient volumes of cornethanol to meet the need for 13.2 bill gallons of conventional renewable fuel (see Table II.C-1), 

we do not believe that there is a need to lower the total renewable fuel standard. 

D. Biomass-Based Diesel in 2012 

 Unlike for cellulosic biofuel, the statute does not require EPA to project available 

volumes of biomass-based diesel for years up through 2012 and to base the standard on the 

projected available volume. Instead, the standard for 2012 is to be based on the statutory 

applicable volume of 1.0 bill gallons. However, the statute does include waiver provisions that 

allow for lowering the applicable volume of biomass-based diesel under certain circumstances. 

Moreover, as described more fully in Section II.C above, we must determine whether the 

required volumes of advanced biofuel and/or total renewable fuel should be reduced if we reduce 

the required volume of cellulosic biofuel. Since biomass-based diesel is also an advanced 

biofuel, the amount of biomass-based diesel that is consumed in 2012 directly affects our 

consideration of adjustments to the volumetric requirements for advanced biofuel and total 

renewable fuel. We therefore investigated whether the applicable volume of 1.0 bill gallons for 

biomass-based diesel is achievable in 2012, and whether additional volumes are also feasible. 

 We examined recent production rates, production capacity of the industry, and 

projections for future production from a variety of sources. Although there are several different 

fuel types that can qualify as biomass-based diesel, biodiesel is by far the predominant type. 

Thus, our assessment focused primarily on biodiesel, though we also investigated potential 

volumes of renewable diesel. 

 According to information from the EPA-Moderated Transaction System (EMTS) and 

RIN generation reports submitted to EPA from producers, we estimate that the volume of 

biomass-based diesel produced in 2010 was about 380 mill gallons. A number of commenters 
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Page 33 of 126 

pointed to this low volume as an indication that the volume requirements of 800 mill gallons in 

2011 and 1.0 bill gallons in 2012 are not achievable. However, many of the activities of the 

biodiesel industry in 2010 were due to unique circumstances that may not apply in 2012. It is 

likely that a contributing factor to the lower production volumes in 2010 was the expiration of 

the biodiesel tax credit at the end of 2009 and its absence throughout 2010, and the fact that the 

RFS program effectively created a demand for about 345 mill gallons in 2010.19 A more 

comprehensive view of historical biodiesel production levels strongly indicates that the U.S. 

biodiesel industry has produced higher volumes when demand for it existed, and that as a result 

the industry has the capability to produce greater volumes than it did in 2010 under the 

appropriate circumstances. This point is illustrated in Figure II.D-1 below. 

 

19 See question 6.7 in EPA's "Questions and Answers on Changes to the Renewable Fuel Standard Program 

(RFS2)", http://www.epa.gov/otaq/fuels/renewablefuels/compliancehelp/rfs2-aq.htm#6 
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Page 34 of 126 

Figure II.D-1 

Historical Domestic Production of Biodiesel 

0

100

200

300

400

500

600

700

800

2006 2007 2008 2009 2010

Mill gallons

Source: EIA Annual Energy Outlook 2011 Early Release
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Page 35 of 126 

 The biodiesel industry's production potential supports the view that it can more than 

satisfy the applicable volume of biomass based diesel specified in the statute for 2012. As of 

August, 2011, the aggregate production capacity of biodiesel plants in the U.S. was estimated at 

2.4 billion gallons per year across 148 facilities.20 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.21 Thus, restarting idled plants 

will not be a hindrance to meeting the applicable volumes for biomass-based diesel in 2011 or 

2012. 

 Additionally, information from the U.S. Census Bureau indicates that monthly production 

volumes of biodiesel have increased steadily in the first half of 2011, reaching about 78 mill 

gallons by July22. See Figure II.D-2. 

Figure II.D-2 

2011 Domestic Production of Biodiesel 

 

20 Figures taken from National Biodiesel Board's Member Plant List as of August 22, 2011. Some plants did not 

report production capacity. http://biodiesel.org/buyingbiodiesel/plants/showall.aspx 

21 Based on construction times for new plants listed in Biodiesel Magazine from July 2006 through May 2009. 

22 U.S. Census Bureau, Fats and Oils, Production, Consumption, and Stocks, Survey M311K. 

http://www.census.gov/manufacturing/cir/historical_data/m311k/index.html. Assumes 7.68 lb/gal conversion. 
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Over the seven months shown in this figure, biodiesel production increased by an average of 

about 16% each month. This trend demonstrates that the industry is responding to the higher 

demand created by the 800 mill gal biomass-based diesel volume requirement under the RFS 

program in 2011. Biodiesel production will only need to increase at a more modest rate of about 

3% each month after July in order for the total 2011 production volume to reach 800 mill 

gallons. Moreover, further increases in monthly production volumes would not be necessary 

after December 2011 for the industry to reach a total production volume of 1.0 bill gallons in 

2012. We believe, therefore, that the 1.0 bill gallon requirement for biomass-based diesel in 

2012 can be met. Moreover, given the increases in monthly production volumes that occurred in 

the first half of 2011 and the significant amount of underutilized production capacity that exists 

within the biodiesel industry, there is also reason to believe that monthly production volumes 

will increases after July 2011 at more than needed to meet the statutory volume requirements, 

providing additional volumes that can be used to meet the advanced biofuel standard. 

 Projections from other sources provide additional support to our conclusions that 1.0 bill 

gal biomass-based diesel can be produced in 2012. For instance, the U.S. Department of 

Agriculture projects that over 400 mill gallons of biodiesel will be produced from soybean oil in 

2012, and adds that "Although some other first-use vegetable oils are also used to produce 

biodiesel, most of the remaining biodiesel production needed to reach the 1-billion-gallon 

mandate of the 2007 Energy Act uses animal fats or recycled vegetable oil as the feedstock."23 

This projection is further supported by the Agricultural Marketing Resource Center at Iowa State 

University, which projects that soy-oil biodiesel production may reach as high as 470 mill 

gallons and that non-soy biodiesel may reach as high as 460 mill gallons.24 Both of these sources 

project more growth in non-soy oil feedstock volumes than soy oil. Finally, EIA projects that the 

total volume of biodiesel in 2012 would be about 830 mill gallons.25 While all of these 

projections suggest that volumes of biodiesel may fall short of 1.0 bill gallons, they do not take 

into account the increase in monthly production volumes as noted above, nor sources of 

renewable diesel that will also be available. For instance, Dynamic Fuels has constructed one 

plant in Geismar, Louisiana that started production of renewable diesel in November, 2010.26 In 

the final RFS2 rule, we projected that annual renewable diesel production could reach 150 mill 

gallons based on feedstock availability. Since renewable diesel can also be produced at existing 

refineries with little or no modification to processing equipment, we believe that 150 mill gallons 

of renewable diesel could be produced in 2012 considering the potential for refinery-based 

production as well as the Dynamic Fuels facilities. Thus, we currently believe that the total 

production volume of biomass-based diesel can readily reach 1.0 bill gal in 2012. 

 We also reviewed information submitted by registered producers of biomass-based diesel 

under the requirements of §80.1449 for Production Outlook Reports. Of the 65 facilities that 

submitted a report, the total projected 2012 volume of biomass-based diesel was 937 mill 

 

23 USDA Agricultural Projections to 2020, Long-Term Projections Report OCE-2011-1, February 2011. See Table 

24. Assumes 7.68 lb/gal. 

24 Soybean Oil and Biodiesel Usage Projections and Balance Sheet, updated 2/18/2011. A version made available 

on 8/1/2011 shows similar volumes of soybean oil for biodiesel use, but does not provide information about non-soy 

oil sources of biodiesel. http://www.extension.iastate.edu/agdm/crops/outlook/soybeanbalancesheet.pdf. Values 

cited are for the "High" case. 

25 Short-Term Energy Outlook, August 2011. Table 8. 

26 Project status updates are available via the Syntroleum website, http://dynamicfuelsllc.com/wp-news/ 
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Page 37 of 126 

gallons. We believe that this projection is indicative of the industry's expectation that the 

applicable volume requirement for 2012 will be 1.0 bill gallons and its intention to meet that 

requirement. Moreover, the projection provided in these reports likely underestimates the actual 

expectations and capabilities of the industry, since the number of facilities that submitted a report 

is far less than the total number of facilities capable of producing biodiesel and renewable diesel. 

 In additional to production capacity and projections of 2012 production volume, we also 

investigated feedstocks used to produce biomass-based diesel. We believe that there will be 

sufficient sources of qualifying renewable biomass to more than meet the needs of the biodiesel 

industry in 2012. The largest sources of feedstock for biodiesel in 2012 are expected to be soy 

oil, canola oil, rendered fats, and corn oil extracted during production of fuel ethanol. In 

response to the NPRM, the National Biodiesel Board (NBB) cited historically high soybean 

production rates for 2011 as evidence that there will be ample volumes of soybean oil available 

for biodiesel production. Likewise, the Renewable Energy Group (REG) provided information 

on significant increases in the availability of inedible corn oil from ethanol producers that it 

believes will occur in the next 1-2 years. 

 While commenters did not provide any information suggesting that the applicable volume 

of 1.0 bill gallons cannot be reached, some raised concerns about impacts on other industries and 

feedstock price. For instance, the American Trucking Association (ATA) stated that feedstocks 

will need to be diverted from other uses in order to meet the 1.0 bill gallon requirement, and the 

American Cleaning Institute (ACI) provided information about how such a diversion could affect 

the oleochemical industry. We address concerns about price in more detail below in our 

discussion of ATA's request for a waiver of the 2012 applicable volume of 1.0 bill gallons. 

 While we agree that the total volume of animal fats is largely inelastic and is unlikely to 

grow significantly due to the presence of the increasing market for biomass-based diesel, we also 

agree with the statement from ACI that "there is nothing in EISA or the proposed rule that limits 

the amount of animal fats that can be used to meet the mandate." Under the statutory definition 

of renewable biomass, valid feedstocks include animal waste material and animal byproducts. 

We believe that animal fats fall into these categories, and as a result we do not have the authority 

to exclude or limit volumes of animal fats that are used for production of biomass-based diesel. 

Such wastes could potentially be considered “biogenic waste oils/fats/greases” or “non-cellulosic 

portions of separated food waste” under the RIN-generating pathways listed in Table 1 to 

§80.1426, and thus eligible for the production of RIN-generating biofuel. 

 In response to the NPRM, we received comments both in support of and opposed to our 

proposal to maintain the statute's applicable volume of 1.0 bill gallons for biomass-based diesel 

in 2012. In general, producers of biodiesel and crop-based feedstocks were supportive, citing the 

sufficiency of available feedstocks and production capacity. Several supporters indicated that 

historically low biodiesel production volumes are not an appropriate reference point on which to 

base the capabilities of the industry for the future, since the higher biomass-based diesel 

mandates established by Congress for 2011 and 2012 are expected to drive production volumes 

more than any other factor. 
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 Parties opposed to maintaining the statutory applicable volume of 1.0 bill gallons for 

2012 were primarily obligated parties, as well as representatives of diesel trucking companies 

and the oleochemical industry. To a large degree, these commenters pointed to historical 

biodiesel production levels in support of their belief that 1.0 bill gallons in 2012 is not 

achievable. As described above, we do not agree with this conclusion. 

 One party opposed to maintaining the 1.0 bill gal requirement for 2012 also raised 

concerns about infrastructure. Comments about potential biomass-based diesel distribution 

infrastructure constraints associated with meeting both the 2012 and 2013 standards are 

addressed in Section IV.B.5 of today’s preamble. As discussed in that section, we continue to 

believe that there will be sufficient biomass-based diesel distribution infrastructure in place to 

support the use of the required volumes. 

 Of the parties that requested a reduction in the applicable volume of 1.0 bill gallons for 

2012, the American Trucking Association (ATA) and Chevron explicitly appealed to the waiver 

mechanism provided at 211(o)(7)(E). The full text of this statutory provision is shown below: 

(E) BIOMASS-BASED DIESEL.— 

(i) MARKET EVALUATION.—The Administrator, in consultation with the 

Secretary of Energy and the Secretary of Agriculture, shall periodically evaluate 

the impact of the biomass-based diesel requirements established under this 

paragraph on the price of diesel fuel. 

(ii) WAIVER.—If the Administrator determines that there is a significant 

renewable feedstock disruption or other market circumstances that would make 

the price of biomass-based diesel fuel increase significantly, the Administrator, in 

consultation with the Secretary of Energy and the Secretary of Agriculture, shall 

issue an order to reduce, for up to a 60-day period, the quantity of biomass-based 

diesel required under subparagraph (A) by an appropriate quantity that does not 

exceed 15 percent of the applicable annual requirement for biomass-based diesel. 

For any calendar year in which the Administrator makes a reduction under this 

subparagraph, the Administrator may also reduce the applicable volume of 

renewable fuel and advanced biofuels requirement established under paragraph 

(2)(B) by the same or a lesser volume. 

(iii) EXTENSIONS.—If the Administrator determines that the feedstock 

disruption or circumstances described in clause (ii) is continuing beyond the 60- 

day period prescribed in clause (ii) or this clause, the Administrator, in 

consultation with the Secretary of Energy and the Secretary of Agriculture, may 

issue an order to reduce, for up to an additional 60-day period, the quantity of 

biomass-based diesel required under subparagraph (A) by an appropriate quantity 

that does not exceed an additional 15 percent of the applicable annual requirement 

for biomass-based diesel. 
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 The waiver authority provided in paragraph (ii) is based on an EPA determination that 

there “is” a feedstock disruption or other market circumstance that would make the price of 

biomass-based diesel rise significantly. The authority to extend a temporary waiver in paragraph 

(iii) is based on an EPA determination that such disruption or circumstance “is continuing." 

Thus, we believe that any waiver of the 2012 biomass-based diesel requirements under this 

statutory provision must be based on an evaluation of feedstock conditions or other 

circumstances that exist currently and “would make” the price of biomass based diesel rise 

significantly in 2012. If Congress had intended that we project future market circumstances that 

might lead to significant prices increases, it could have used "will be" in place of "is" in 

paragraph (ii). Thus, we believe that any waiver of the biomass-based diesel requirements for 

2012 must be based on an evaluation of the market that occurs on or after January 1, 2012. 

 We do not believe that the information provided by Chevron and ATA warrants a waiver 

of the 2012 biomass-based diesel volume at this time. While ATA provided some information 

on the relative price of biodiesel and conventional diesel, it did not demonstrate how this price 

difference represented a price increase as required under the statute. Also, they did not cite any 

particular renewable feedstock disruption or other market circumstance to demonstrate how the 

difference in price between conventional diesel fuel and biomass-based diesel meets the statutory 

criterion for a significant increase in the price of biomass-based diesel. 

 Both Chevron and ATA cite an expected expiration of the biodiesel tax credit at the end 

of 2011 as a reason that prices will increase significantly. EPA has not determined whether the 

expiration of a tax credit should be considered a “market circumstance” within the meaning of 

CAA 211(o)(7)(E)(ii), and is making no determination regarding that matter at this time. 

Whether or not such a development would be a “market circumstance,” it is clear that it is not an 

existing circumstance, and conjecture that the tax credit may not be continued in the future does 

not provide an appropriate basis for a waiver under 211(o)(7)(E)(ii). Apart from possible 

consideration under the statutory waiver provisions, however, we note that the applicable 

volumes set by Congress must be met regardless of the status of federal or state tax credits, 

subsidies, incentives, and the like. 

 One commenter requested a cost-benefit analysis in the context of determining the 

appropriate volume for biomass-based diesel in 2012. Under the statute, we are to set the 

percentage standard for biomass-based diesel for 2012 based on the applicable volume of 1.0 bill 

gallons specifically set forth in the statute in CAA 211(o)(2)(B)(IV). While the statute does 

provide limited mechanisms for waiving all or a portion of any annual biomass-based diesel 

standard in 2012 under CAA 211(o)(7), the statute does not require a cost-benefit analysis either 

in setting a standard based on the statutory applicable volume or in considering whether or not to 

issue a waiver. For instance, under 211(o)(7)(A), waivers can be granted based on an EPA 

finding of severe harm to the economy or environment of a state, region, or the United States, or 

inadequate domestic supply. Under 211(o)(7)(E) waivers can be granted based on significant 

increases in the price of biomass-based diesel. Neither of these statutory provisions provides for 

a comparison of the costs associated with meeting the biomass-based diesel standard to the 

benefits of meeting that standard. Therefore, we do not believe that cost-benefit analyses are 

necessary or appropriate in the context of considering the 2012 biomass-based diesel volume of 

1.0 bill gallons. 
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Based on our review of the production potential of the biodiesel industry, projections 

from several sources, and our assessment of available feedstocks, we believe that the 1.0 billion 

gallons needed to satisfy the applicable volume of biomass-based diesel specified in the statute 

can be produced in 2012, and that more than 1.0 bill gallons of production is possible. 

Moreover, we do not believe that waiving a portion of the 2012 biomass-based diesel volume of 

1.0 bill gallons under the provisions of 211(o)(7)(E) is appropriate at this time. 

III. Final Percentage Standards for 2012 

A. Background 

 The renewable fuel standards are expressed as a volume percentage, and are used by each 

refiner, blender or importer to determine their renewable volume obligations (RVO). Since there are 

four separate standards under the RFS2 program, there are likewise four separate RVOs applicable 

to each obligated party. Each standard applies to the sum of all gasoline and diesel produced or 

imported. The applicable percentage standards are set so that if each regulated party meets the 

percentages, then the amount of renewable fuel, cellulosic biofuel, biomass-based diesel, and 

advanced biofuel used will meet the volumes required on a nationwide basis. 

 As discussed in Section II.B.6, we are finalizing a required volume of cellulosic biofuel 

for 2012 of 8.65 million gallons (10.45 million ethanol equivalent gallons). The advanced 

biofuel and total renewable fuel volumes will not be reduced below the applicable volumes 

specified in the statute. The final 2012 volumes used to determine the four percentage standards 

are shown in Table III.A-1. 

Table III.A-1 

Final Volumes for 2012 

Actual Volume Ethanol Equivalent 

Volume 

Cellulosic biofuel 8.65 mill gal 10.45 mill gal 

Biomass-based diesel 1.0 bill gal 1.5 bill gal 

Advanced biofuel 2.0 bill gal 2.0 bill gal 

Renewable fuel 15.2 bill gal 15.2 bill gal 

 

 The formulas used in deriving the annual renewable fuel standards are based in part on 

estimates of the volumes of gasoline and diesel fuel, for both highway and nonroad uses, that 

will be used in the year in which the standards will apply. Producers of other transportation 

fuels, such as natural gas, propane, and electricity from fossil fuels, are not subject to the 

standards, and volumes of such fuels are not used in calculating the annual standards. Since the 

standards apply to producers and importers of gasoline and diesel, these are the transportation 

fuels used to set the standards, and then again to determine the annual volume obligations of an 

individual gasoline or diesel producer or importer. 
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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): 

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. 
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Di = Amount of diesel projected to be used in the 48 contiguous states and Hawaii, in 

year i, in gallons. 

RGi = Amount of renewable fuel blended into gasoline that is projected to be consumed 

in the 48 contiguous states and Hawaii, in year i, in gallons. 

RDi = Amount of renewable fuel blended into diesel that is projected to be consumed in 

the 48 contiguous states and Hawaii, in year i, in gallons. 

GSi = Amount of gasoline projected to be used in Alaska or a U.S. territory in year i if 

the state or territory opts-in, in gallons. 

RGSi = Amount of renewable fuel blended into gasoline that is projected to be consumed 

in Alaska or a U.S. territory in year i if the state or territory opts-in, in gallons. 

DSi = Amount of diesel projected to be used in Alaska or a U.S. territory in year i if the 

state or territory opts-in, in gallons. 

RDSi = Amount of renewable fuel blended into diesel that is projected to be consumed in 

Alaska or a U.S. territory in year i if the state or territory opts-in, in gallons. 

GEi = The amount of gasoline projected to be produced by exempt small refineries and 

small refiners in year i, in gallons, in any year they are exempt per §§80.1441 and 

80.1442, respectively. 

DEi = The amount of diesel projected to be produced by exempt small refineries and 

small refiners in year i, in gallons, in any year they are exempt per §§80.1441 and 

80.1442, respectively. 

 The four separate renewable fuel standards for 2012 are based in part on the 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. EIA estimates 136 billion gallons of gasoline and 5227 billion gallons 

of transportation diesel will be sold or introduced into commerce in 2012. These gasoline and 

diesel volumes are adjusted to account for renewable fuel volumes – ethanol (estimated by EIA) 

and biodiesel (based on EIA’s Short-Term Energy Outlook (STEO). For 2012, these values are 

13 billion gallons and 0.8 billion gallons, respectively. 

2. Small Refineries and Small Refiners

In CAA section 211(o)(9), enacted as part of the Energy Policy Act of 2005, Congress 

provided a temporary exemption to small refineries (those refineries with a crude throughput of 

no more than 75,000 barrels of crude per day) through December 31, 2010. In RFS1, we 

 

27 Excluding diesel used by ocean-going vessels. 
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exercised our discretion under section 211(o)(3)(B) and extended this temporary exemption to 

the few remaining small refiners that met the Small Business Administration’s (SBA) definition 

of a small business (1,500 employees or less company-wide) but did not meet the statutory small 

refinery definition as noted above. Because EISA did not alter the small refinery exemption in 

any way, the RFS2 program regulations exempted gasoline and diesel produced by small 

refineries and small refiners in 2010 from the renewable fuels standard (unless the exemption 

was waived), see 40 CFR §80.1141. 

Under the RFS program, Congress provided two ways that small refineries can receive a 

temporary extension of the exemption beyond 2010. One is based on the results of a study 

conducted by the Department of Energy (DOE) to determine if small refineries would face a 

disproportionate economic hardship under the RFS program. The other is based on EPA 

determination of disproportionate economic hardship on a case-by-case basis in response to 

refiner petitions. 

In January 2009, DOE issued a study which did not find that small refineries would face 

a disproportionate economic hardship under the RFS program.28 The conclusions were based in 

part on the expected robust availability of RINs and EPA’s ability to grant relief on a case-bycase basis. As a result, beginning in 2011 small refiners and small refineries were required to 

participate in the RFS program as obligated parties, and there was no small refiner/refinery 

volume adjustment to the 2011 standard as there was for the 2010 standard. 

Following the release of DOE's 2009 small refinery study, Congress directed DOE to 

complete a reassessment and issue a revised report. DOE recently re-evaluated the impacts of 

the RFS program on small entities and concluded that 14 small refineries would suffer a 

disproportionate hardship if required to participate in the program29. As a result, these refineries 

will be exempt from being obligated parties for a minimum of two additional years, 2011 and 

2012.30 The 2012 standards reflect the exemption of these refineries. In addition, and separate 

from the DOE determination, EPA may extend the exemption for individual small refineries on a 

case-by-case basis if they demonstrate disproportionate economic hardship. 

In the NPRM, we stated that “requests for exemptions that are approved after the release 

of the final 2012 RFS standards will not affect the 2012 standards.” This position is unchanged 

from that set in the final rule establishing the 2011 standards31. At that time, we stated, “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.” However, a 

few commenters took issue with this approach. Specifically, these commenters maintain that 

 

28DOE report “EPACT 2005 Section 1501 Small Refineries Exemption Study”, (January, 2009). 

29 "Small Refinery Exemption Study: An Investigation into Disproportionate Economic Hardship," U.S. Department 

of Energy, March 2011. 

30 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. 

31 See 75 FR 76805, December 9, 2010. 
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EPA did not provide notice and comment opportunities regarding the extensions of the small 

refinery exemptions for the current compliance period (2011), and that EPA cannot grant such 

extensions (mid-year) without modifying the standards because such authority is not provided in 

the statute. In addition, these commenters extend the application of their comments to any 

extensions of exemptions that may occur after issuance of the final 2012 standards. 

Commenters suggested requiring petitions to be submitted in time to be considered in the annual 

standard-setting process. One commenter also suggested that the volumes waived in 2011 as a 

result of the small refiner waivers be “made up” in setting the 2012 standards. EPA understands 

the desire of the commenters to have the annual required volumes of renewable fuels realized. 

However, while the statute requires EPA to publish the standards for the following year by 

November 30 of the preceding year, there is no provision for changing the percentage standards 

once they are set outside of the waiver provisions of CAA 211(o)(7). In addition, we are not 

required to ensure that the biofuel volumes in the statute are precisely met. We are required to 

use the specified volumes to set the percentage standards, but there are no provisions for 

ensuring that the percentage standards actually result in the specified volumes actually being 

consumed. This outcome is evidenced by the fact that we use projections of gasoline and diesel 

volume for the next year which might turn out to be too high or too low. Insofar as those 

projections are wrong, the percentage standards will not produce a demand for biofuels that 

exactly corresponds to the volumes in the statute. Thus Congress allowed for some imprecision 

to exist in the actual volumes of renewable fuel that are consumed as a result of the percentage 

standards that we set each November, and did not provide a means for correcting the percentage 

standards after November to ensure that the applicable volumes of renewable fuel are exactly 

met in a given compliance year. 

3. Final Percentage Standards

As finalized in the March 26, 2010 RFS2 rule, the standards are expressed in terms of 

energy-equivalent gallons of renewable fuel, with the cellulosic biofuel, advanced biofuel, and 

total renewable fuel standards based on ethanol equivalence and the 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 1.0 

billion physical gallons of biomass-based diesel will be created in 2012, 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 gallons toward the biomass-based diesel 

standard, but worth 1.5 gallons toward the other standards.32

 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. 

 

32 75 FR 14716, March 26, 2010. 
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 Note that the terms for projected volumes of gasoline and diesel use include gasoline and 

diesel that has been blended with renewable fuel. Because the gasoline and diesel volumes 

estimated by EIA include renewable fuel use, we must subtract the total renewable fuel volume 

from the total gasoline and diesel volume to get total non-renewable gasoline and diesel 

volumes. The values of the variables described above are shown in Table III.B.3-1.33 Terms not 

included in this table have a value of zero. 

Table III.B.3-1 

Values for Terms in Calculation of the Standards (bill gal) 

Term Value 

RFVCB,2012 0.01045 

RFVBBD,2012 1.0 

RFVAB,2012 2.0 

RFVRF,2012 15.20 

G2012 139.98 

D2012 44.47 

GE2012 3.27 

DE2012 1.48 

RG2012 14.17 

RD2012 0.83 

Using the volumes shown in Table III.B.3-1, we have calculated the percentage standards 

for 2012 as shown in Table III.B.3-2. 

Table III.B.3-2 

Final Percentage Standards for 2012 

Cellulosic biofuel 0.006% 

Biomass-based diesel 0.89% 

Advanced biofuel 1.19% 

Renewable fuel 9.03% 

 

33 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 (2009) EIA State 

Energy Data, Transportation Sector Energy Consumption Estimates. The gasoline and transportation distillate fuel 

oil fractions are approximately 0.2% and 0.8%, respectively. Ethanol use in Alaska is estimated at 8.4% of its 

gasoline consumption (based on the same State data), and biodiesel use is assumed to be zero. 
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IV. Biomass-Based Diesel Volume for 2013 

 In today's action we are finalizing an applicable volume for biomass-based diesel for 

2013 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. To do this, we have reviewed RFS 

program implementation to date and analyzed a number of factors specified in the statute as part 

of this effort. This included an investigation into the demand for biomass-based diesel in 2013 

under the applicable advanced biofuel volume specified in the statute, analyses we conducted in 

the RFS2 final rulemaking, biodiesel production, consumption, and infrastructure issues, and 

comments received in response to the NPRM. In these investigations, biodiesel was the primary 

focus since it is expected to be the predominant type of biomass-based diesel through at least the 

next few years. However, renewable diesel may also play a role in meeting the biomass-based 

diesel standard. When appropriate, we have discussed renewable diesel separately from 

biodiesel. 

 Note that, in setting the 2013 applicable volume of biomass-based diesel, we are not at 

this time setting the percentage standards that would apply to obligated parties in 2013. Instead, 

the percentage standards will be determined after projections of gasoline and diesel volume are 

provided by the Energy Information Administration (EIA) in the fall of 2012, and will be 

announced by November 30, 2012. Moreover, in today's action we are not addressing potential 

exemptions for small refineries and/or small refiners in 2013, since such exemptions are only 

relevant in the context of specifying the percentage standards and their applicability. Finally, we 

are not specifying any applicable volumes of biomass-based diesel for 2014 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 statute34. 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 an analysis of the 

following: 

• The impact of the production and use of renewable fuels on the environment, including 

on air quality, climate change, conversion of wetlands, ecosystems, wildlife habitat, 

water quality, and water supply; 

 

34 For example, EPA may waive a given standard in whole or in part following the provisions at 211(o)(7). 
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• The impact of renewable fuels on the energy security of the United States; 

• The expected annual rate of future commercial production of renewable fuels, including 

advanced biofuels in each category (cellulosic biofuel and biomass-based diesel); 

• The impact of renewable fuels on the infrastructure of the United States, including 

deliverability of materials, goods, and products other than renewable fuel, and the 

sufficiency of infrastructure to deliver and use renewable fuel; 

• The impact of the use of renewable fuels on the cost to consumers of transportation fuel 

and on the cost to transport goods; and 

• The impact of the use of renewable fuels on other factors, including job creation, the 

price and supply of agricultural commodities, rural economic development, and food 

prices. 

While EPA is given the authority to determine the appropriate volume of renewable fuel for 

those years that are not specified in the statute based on a review of program implementation and 

analysis of the factors listed above, the statute also specifies that the applicable volume of 

biomass-based diesel cannot be less than the applicable volume for calendar year 2012, which is 

1.0 bill gallons. 

 It is useful to note that the statutory provisions described above are silent in two 

important areas. 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. Despite this ambiguity in the statute, 

commenters differed in their perspectives on the intent of Congress in allowing EPA to 

determine the appropriate applicable volume for biomass-based diesel for years after 2012. 

Some expressed their belief that Congress intended for the statutory minimum volume of 1.0 bill 

gallons to be used to set the applicable volume for all years after 2012, with higher volumes 

being required only if EPA could demonstrate that those higher volumes were already being 

produced. Others expressed the belief that Congress intended the required volumes of biomassbased diesel to increase every year, with EPA's role being that of determining an achievable size 

of that increase. However, since the statute is silent with regard to Congressional intent, 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. This 

is the approach we proposed in the NPRM and are using in today's final rule. 

 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 that 

specified for 2012 would not have any impact on the advanced biofuel or total renewable fuel 

volume requirements. While increasing the biomass-based diesel volume requirement above the 
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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. For the biomass-based 

diesel volume that would apply beginning on January 1, 2013, then, we must finalize the 

applicable volume by November 1, 2011. 

B. Factors Considered in Assessing 2013 Biomass-Based Diesel Volumes

 As described in Section IV.A, we are required to review the implementation of the RFS 

program for years prior to 2013, and to use information from this review in determining the 

applicable volume of biomass-based diesel for 2013. In the NPRM we indicated our belief that 

this review is of limited value due to the short history of the RFS program. Not only did the 

RFS1 program have no volume requirement specific to biomass-based diesel, but even in 2010 

under the RFS2 program several unique factors hindered biodiesel production volumes from 

increasing substantially above historical levels. These factors included the availability of 

carryover RINs from 2008 and 2009 and the expiration of the biodiesel tax credit (which was 

reinstituted at the end of 2010). 

 Since release of the NPRM, however, some information has become available on the 

implementation of the RFS program in 2011. While the available data covers only the first half 

of 2011, it does provide some indication as to how the biomass-based diesel standard for 2011 is 

affecting the market for biodiesel. As described more fully in Section II.D, reported biodiesel 

production has increased significantly between January and July of 2011, and is on track to meet 

the applicable volume of 800 mill gallons for 2011. Based on these results, we believe that the 

RFS program is working as intended, and that there is reason to believe that higher applicable 

volumes in future years would likewise drive increases in production volumes. A review of the 

operation of the RFS program during the remainder of 2011 and 2012 will provide more 

complete information for purposes of helping us to evaluate how the industry, as well as 

feedstock supplies and infrastructure, can respond to potential requirements in 2014 and beyond. 

 In the NPRM we indicated that, based on the limited information available on the current 

and historical operation of the RFS program, it would be prudent for 2013 to consider only 

moderate increases in biomass-based diesel above the statutory minimum of 1.0 bill gallons. We 

cited the annual increments in biomass-based diesel volumes specified in the statute for years 

2009 through 2012, and conveyed our belief that our proposed applicable volume of 1.28 bill 

gallons for 2013 was not a dramatic change from the trend in increments in the statute. In 

addition, since this biomass-based diesel volume had already been partially evaluated in the 

RFS2 rule, we decided to evaluate the appropriateness of setting an applicable volume of 1.28 

bill gallons for 2013 by considering whether 1.28 bill gal of biomass-based diesel was reasonable 

given likely market demand, availability of feedstocks, production capacity, limitations related to 
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Page 49 of 126 

storage and consumption, infrastructure, and the impacts of biomass-based diesel in a variety of 

areas as required under the statute. 

 In responding to the NPRM, some commenters took issue with our characterization of the 

proposed volume of 1.28 bill gallons as a "moderate" increase consistent with the annual 

increments in biomass-based diesel volumes specified in the statute for years 2009 through 2012. 

These commenters also suggested that any comparison to volume requirements in the statute is 

not appropriate. However, as described in the NPRM, we did not base our proposed volume of 

1.28 bill gallons on this comparison, but only used it to make a judgment regarding whether the 

0.28 bill gal increment above the statutory minimum of 1.0 bill gallons could reasonably be 

considered moderate. We continue to believe that this is the case, and that a comparison to the 

statutory volumes is appropriate for this limited purpose. Other commenters agreed with the 

comparison and agreed that the 0.28 bill gallons increment can appropriately be characterized as 

moderate. 

 In some cases commenters who were opposed to the proposed volume requirement of 

1.28 bill gallons cited concerns that the 2012 applicable volume of 1.0 bill gallons is not 

achievable. As described more fully in Section II.D, our evaluation, based in part on biodiesel 

production in the first half of 2011, has led us to conclude that the 1.0 bill gallon applicable 

volume for 2012 is indeed achievable. Therefore, we believe that concerns about the industry's 

ability to meet the applicable volume in 2012 are not a reasonable basis for concerns about 

achieving 1.28 bill gallons in 2013. Other commenters agreed with our assessment of 2012 and 

agreed that an increase of 0.28 bill gallons over the statutory minimum is moderate given the 

capabilities of the industry. 

 Several commenters suggested that 1.28 bill gallons is an infeasible target for 2013, and 

requested that we set the biomass-based diesel standard at the statutory minimum of 1.0 bill 

gallons. Commenters taking this view generally did not offer any data or information to support 

their belief that 1.28 bill gal is not achievable in 2013 beyond references to historical biodiesel 

productions rates. As described in Section II.D, we believe that the use of biodiesel production 

data from 2010 and earlier is of limited value, and production capacity as well as more recent 

data on actual production volumes does in fact demonstrate that the industry is capable of 

significant increases in production when demand for it exists. As described more fully in 

Sections IV.B 1 through 5 below, we continue to believe that 1.28 bill gallons is achievable 

based on production capacity, availability of feedstocks, recent trends in production volumes, 

and efforts to update infrastructure for storage, transport, and blending. Our consideration of 

other impacts, such as fuel costs, can be found in Section IV.C. 

1. Demand for Biomass-Based Diesel

 In the NPRM we described why we believed that the applicable volume of advanced 

biofuel would likely create a demand for biomass-based diesel in excess of 1.0 bill gallons. We 

continue to believe that this is the case. A summary in this regard follows. 
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Page 50 of 126 

 The demand for biomass-based diesel in 2013 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. There are currently only a small number of biofuels that are likely to be 

available for meeting the advanced biofuel standard. In addition to biomass-based diesel, these 

would include cellulosic biofuel, coprocessed renewable diesel, imported sugarcane ethanol, and 

other advanced biofuels. As described in Section II.B, cellulosic biofuels will be a very small 

fraction of the 2.0 bill gallon advanced biofuel requirement in 2012, and we expect the same to 

be true in 2013 with respect to the 2.75 bill gal advanced biofuel requirement. We are not aware 

of any facilities intending on producing renewable diesel through co-processing with petroleum 

in 2012, though several have expressed interest. Regarding other advanced biofuels, as 

described in Section II.C, volumes are expected to reach around 60 mill gallons in 2011 and 80 

mill gallons in 2012. As a result, we expect volumes of cellulosic biofuel, coprocessed 

renewable diesel, and other advanced biofuels to be small in comparison to volumes of imported 

sugarcane ethanol. Thus, to the degree that there are limits in the volumes of sugarcane ethanol 

that can be imported into the U.S., additional biomass-based diesel would be needed to ensure 

the advanced biofuel standard of 2.75 bill gallons can be met. 

 Between years 2000 and 2009, the volume of sugarcane ethanol imported into the U.S. 

from Brazil ranged from 46-730 million gallons per year, or on average, approximately 200 

million gallons per year. However, imports of ethanol have been much lower since 2010 for a 

variety of reasons, including: 

• Extremely wet weather in 2009/10 and dry conditions in 2010/11 which cut into 

Brazilian supplies of sugarcane and reduced sugar content 

• The international price of sweetener was so attractive in 2010 that mills may have 

given greater priority to sugar 

• Expanding sales of flex fuel vehicles in Brazil, which has continued to increase 

Brazilian domestic ethanol demand 

• Demand for Brazilian ethanol in other countries 

 

 Nevertheless, recent market projections suggest that the volume of sugarcane ethanol that 

can be imported into the U.S. from Brazil in 2013 will be on the order of historical import 

volumes prior to 2010, with the potential to reach the historical maximum. For instance, one 

source that evaluates trends and issues for U.S. energy markets is the U.S. Energy Information 

Administration's (EIA) Annual Energy Outlook (AEO).35 This report projects U.S. net ethanol 

imports in 2013 to be 306 million gallons. Another source for U.S. and world commodity 

projections is the Food and Agricultural Policy Research Institute's (FAPRI) U.S. and World 

Agricultural Outlook. The most current version of the outlook, the FAPRI 2011 Agricultural 

Outlook, projects for the year 2013 that the U.S. will have net ethanol imports of 768 million 

 

35 U.S. Energy Information Administration (EIA). “AEO2011,” April 2011. 

http://www.eia.doe.gov/forecasts/aeo/index.cfm 
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gallons.36 The only next ethanol exporters tracked in the FAPRI report are Brazil and China, 

with Brazil export volumes totally nearly 20 times those from China. Therefore, all ethanol 

imports into the U.S. can reasonably be considered to be from Brazil. 

 

 As we stated in the NPRM, then, we believe that the total volume of advanced biofuel 

other than biomass-based diesel will likely be less than about 1 billion gallons in 201337. In 

order to meet an advanced biofuel volume requirement of 2.75 billion gallons, then, it is likely 

that more than 1.0 bill gallons of biomass-based diesel (representing more than 1.5 billion 

ethanol-equivalent gallons) will be needed. The volume of biomass-based diesel that may be 

needed in excess of 1.0 bill gallons could potentially be on the order of hundreds of millions of 

gallons. 

 Among the parties that submitted comments in response to the NPRM, none contested 

our assessment of the volumes of sugarcane ethanol that might be expected to be imported into 

the U.S. from Brazil in 2013. Nevertheless, parties that were opposed to setting the biomassbased diesel applicable volume at 1.28 bill gallons in 2013 raised doubts about the projected 

demand for biomass-based diesel in 2013. In some cases commenters ignored the driving nature 

of the advanced biofuel standard or implicitly assumed that EPA would waive some portion of it. 

The American Trucking Association (ATA) explicitly requested that we lower the 2013 

advanced biofuel standard in order to ensure that demand for biomass-based diesel would not 

exceed 1.0 bill gallons in 2013. As described in the NPRM, we have assumed for the purposes 

of this rulemaking that the applicable volume of 2.75 bill gallons of advanced biofuel specified 

in the statute for 2013 will be used in setting the 2013 advanced biofuel standard. We will 

investigate the need to lower some portion of the advanced biofuel volume for 2013 when we set 

the annual 2013 percentage standards in November, 2012. In addition, we have authority to 

waive all or a portion of the standards after they are initially set. 

 The American Petroleum Institute cited projections from AEO 2011 in support of their 

argument that biodiesel volumes will not reach 1.28 bill gallons in 2013. For instance, Table 11 

of AEO 2011 projects a total biodiesel consumption of 1.04 bill gal in 2013. However, we do 

not believe that the projections provided in AEO 2011 can be used in this way, since EIA 

assumes that the required volume of advanced biofuel in any given year will be reduced 

concurrently with reductions in the required volume of cellulosic biofuel38. As a result, the total 

projected volume of biodiesel and imported ethanol in the 2013 EIA projections falls far short of 

what would be necessary to meet the applicable volume 2.75 bill gallons of advanced biofuel set 

forth in the statute. 

 Some parties that were opposed to setting the biomass-based diesel applicable volume at 

1.28 bill gallons in 2013 did recognize the driving nature of the advanced biofuel standard, but 

questioned the need to set the biomass-based diesel standard above the statutory minimum of 1.0 

bill gallons. They argued that the market should be allowed to determine the relative volumes of 

 

36 Table "Ethanol Trade", Commodity Outlook/Biofuels, FAPRI-ISU 2011 World Agricultural Outlook. 

http://www.fapri.iastate.edu/outlook/2011/ 

37 Including some small contributions from cellulosic biofuel, coprocessed renewable diesel, and other advanced 

biofuels. 

38 Communication with W. Brown, Energy Information Administration 
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biomass-based diesel, imported sugarcane ethanol, and other advanced biofuels needed to meet 

the advanced biofuel standard of 2.75 bill gallons. This approach, they argued, could potentially 

minimize the overall cost of compliance with the advanced biofuel standard in 2013. However, 

as described in the NPRM, the statute does not provide any overarching goals for EPA to achieve 

in setting the applicable volumes for biofuels in years after those specifically set forth in the 

statute. Thus, the statute does not indicate that EPA should maximize GHG benefits or energy 

security benefits, maximize or minimize supply of renewable fuel, or minimize cost. Instead, the 

statute provides a list of factors we must consider. While one of those factors is cost, other 

factors must also be considered. For instance, setting the biomass-based diesel standard at 1.28 

bill gallons instead of at the statutory minimum of 1.0 bill gallons will provide more certainty 

that the applicable volume of advanced biofuel set forth in the statute will not need to be 

reduced. This, in turn, means that there will be more certainty of reduced GHG emissions 

through the use of more advanced biofuels, and increased certainty of energy security benefits in 

terms of reduced reliance on fossil fuels. 

 As described above, we believe that there are limits in the volumes of sugarcane ethanol 

that can be imported in 2013, that advanced biofuels other than sugarcane ethanol and biomassbased diesel will not be produced in significant quantities, and that as a result it is likely that 

more than 1.0 bill gallons of biomass-based diesel will be needed in order to meet an advanced 

biofuel volume requirement of 2.75 billion gallons. However, if we do not set the biomass-based 

diesel standard above 1.0 bill gallons, biodiesel producers will be less certain of the mandated 

demand for their product given the opportunities that are also created by the advanced biofuel 

standard for imported sugarcane ethanol. Due to this uncertainty, the biodiesel industry is less 

likely to make preparations to increase production above 1.0 bill gallons. In the event that 

imported sugarcane ethanol volumes fall short of what is needed to meet the advanced biofuel 

standard in 2013, as we project, the biodiesel industry would not be in an ideal position to make 

up the difference. A waiver of the advanced biofuel standard would then become more likely 

due to insufficient supply. If we did waive a portion of the advanced biofuel standard for 2013, 

obligated parties that had acquired sufficient RINs to comply with the RFS mandates would be 

left holding more RINs than they need. 

 In setting the biomass-based diesel volume requirement at 1.28 bill gallons rather than at 

the statutory minimum of 1.0 bill gallons, then, we are creating greater certainty for both 

producers of biomass-based diesel and obligated parties, and increasing certainty that the 

intended GHG emissions reductions and energy security benefits associated with the use of 

advanced biofuels will be realized. It is possible that there may be some additional cost for 

compliance with the advanced biofuel requirement of 2.75 bill gallons under a biomass-based 

diesel requirement of 1.28 bill gallons, as compared to setting the biomass-based diesel 

requirement at the statutory minimum of 1.0 bill gallons and allowing the market to determine 

the relative volumes of each type of advanced biofuel that will be produced in 2013 to meet the 

advanced biofuel standard of 2.75 bill gallons. However, we have balanced the potential for 

somewhat increased costs against the additional certainty of GHG reductions and enhanced 

energy security provided by the advanced biofuel volume requirement of 2.75 bill gallons. 

Therefore, after consideration of all the factors required under the statute, we believe that setting 

the biomass-based diesel standard at 1.28 bill gallons in 2013 is a reasonable exercise of the 

authority provided EPA by Congress. 
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 2. Availability of Feedstocks to Produce 1.28 Billion Gallons of Biodiesel

 In the NPRM, we provided our assessment of the types and amounts of feedstocks that 

could be used to produce 1.28 bill gallons of biomass-based diesel in 2013. This assessment 

included references both to the work that had been done in the RFS2 final rule as well as a recent 

report released by IHS Global Insight39. The feedstock estimates from these two sources are 

shown in Table IV.B.2-1. 

Table IV.B.2-1 

Feedstocks That May Contribute to 2013 Volume of 1.28 bill gal (mill gal) 

Source RFS2 Final Rule IHS Global Insight 

Grease and rendered fats 380 272 

Corn oil 300 185 

Soybean oil 600 624 

Canola oil 0 68 

Palm oil 0 7 

Other 0 185 

Total 1,280 1,340 

As some commenters pointed out, these two sources used fundamentally different approaches. 

In the case of the RFS2 final rule, projections of feedstock volumes were determined first, and 

then summed to conclude that 1.28 bill gal is a reasonable volume of biomass-based diesel that 

could be achieved in 2013. In contrast, the IHS Global Insight report began with the aim of 

reaching 1.3 bill gallons in 2013, and then conducted modeling to determine the likely mix of 

feedstocks that would support that volume. Nevertheless, we believe that these sources suggest 

two similar ways that the market could meet the demand for feedstocks under a required volume 

of 1.28 bill gallons of biomass-based diesel. 

 One commenter stated that we relied too heavily on these sources without additional 

analysis. We did in fact conduct a more up-to-date analysis of these feedstocks and, as described 

below, the updated analysis confirms our belief that the projections in Table IV.B.2-1 are 

reasonable projections for the mix of feedstocks that could be used to reach 1.28 bill gallons of 

biomass-based diesel. Other commenters agreed with our assessment of available feedstocks and 

our conclusions that there would be sufficient volumes to meet a biomass-based diesel volume 

requirement of 1.28 bill gallons. A summary of our updated assessment of feedstocks is 

included below. 

 

a. Grease and Rendered Fats 

 

39 Table 2, "Biodiesel Production Prospects for the Next Decade," IHS Global Insight, March 11, 2011 
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 According to the U.S. Census Bureau, the total volume of yellow grease and other 

greases (most likely trap grease) produced in 2010 was about 340 mill gallons40. In the first half 

of 2011, production of greases was about 10% higher than for the same period in 2010, 

suggesting that total 2011 production could reach 370 mill gallons or more, similar to the 

production rates in 2008 and 2009. 

 With regard to inedible tallow, the volume produced in 2010 was about 440 mill gallons, 

and indications from the first half of 2011 are that a similar volume will be generated in 2011 as 

well. 

 Taken together, the total volume of grease and rendered fats that is produced annually is 

over 800 mill gallons. This is significantly more than was estimated in the RFS final rule and the 

report from IHS Global Insight for use in the production of biomass-based diesel in 2013. 

Moreover, we have not included in our estimate other potential sources, such as edible tallow, 

lard, and poultry fats. While these other potential feedstocks currently having existing markets, 

it may become economical for them to be used in the production of biomass-based diesel. 

 In their comments on the NPRM, the America Cleaning Institute raised concerns about 

the diversion of animal fats from the oleochemical industry for the production of biofuels. We 

noted in Section II.D that we do not have the authority to prevent feedstocks that meet the 

statutory definition of renewable biomass to be used in the production of renewable fuel. While 

the choice of which feedstocks will be used to produce biomass-based diesel will be determined 

by the market, based on our assessment, it is possible that the 1.28 bill gall requirement could be 

met without the use of animal fats given the available volume of greases, corn oil, and vegetable 

oils as described more fully below. 

b. Corn Oil 

 The RFS2 final rule projected that by 2013, 34% of all dry mill ethanol facilities would 

extract corn oil from the by-products of ethanol production using advanced extraction 

technologies. This estimated extraction rate led us to conclude that the volume of corn oil could 

reach 300 mill gallons in 2013. While currently available technologies have not been able to 

reach the oil extraction rates that we assumed in the RFS2 final rule, these lower extraction rates 

have been offset by a higher number of ethanol plants utilizing some form of extraction 

technology. For instance, according to a recent article in Ethanol Producer Magazine, up to 55 

percent of plants may be extracting corn oil by the end of 2012.41 Similarly, in an article in 

Biodiesel Magazine Dave Elsenbast, vice president of supply chain management for REG stated 

that as of July 2011 about 35% of U.S. corn ethanol plants had implemented corn oil extraction 

and that he expected that number to double within the next couple of years42. In the NPRM we 

 

40 Current Industrial Reports, U.S. Census Bureau, M311K - Fats and Oils: Production, Consumption, and Stocks, 

Table 2b. Assumes 7.5 lb/gal. http://www.census.gov/manufacturing/cir/historical_data/m311k/index.html 

41 Joseph Riley, "Customized Coproducts Needed as Industry Matures," June 6, 2011. Ethanol Producer Magazine. 

42 Dave Elsenbast quoted in Ron Kotrba, “Biodiesel from corn oil: a growing force,” July 6, 2011. Biodiesel 

Magazine. 
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stated our expectation that the percentage of dry mill ethanol facilities using some form of corn 

oil extraction technology will increase to 60% by 2013. Given the information from Ethanol 

Producer Magazine and Biodiesel Magazine, this estimate appears reasonable. 

 If 60% of all dry mill corn ethanol facilities were extracting corn oil at rates capable with 

current technology, the amount of corn oil available for biodiesel production would be 

approximately 270 million gallons. However, we expect that by 2013 technology improvements 

will increase corn oil production levels to the 300 million gallons projected in the RFS2 rule. 

Additional corn oil could come from ethanol production facilities using corn fractionation or wet 

milling technology. This corn oil was not considered as a biodiesel feedstock in the RFS2 rule, 

but market conditions may result in its availability to the biodiesel industry. The higher adoption 

rate of corn oil extraction in comparison to our projections from the RFS final rule, and the 

promise of ever increasing oil extraction yields, indicate that the 300 million gallons of corn oil 

extraction projected in the RFS2 rule in 2013 remains a reasonable projection. Comments from 

the Renewable Energy Group support this view. 

c. Soybean Oil 

 While a number of parties commented on the use of soybean oil for the production of 

biomass-based diesel, none provided data or information suggesting that there would be 

insufficient supplies to meet the need for 1.28 bill gallons of biomass-based diesel as well as 

other traditional markets for soybeans. Instead, comments on the use of soybean oil were 

focused on costs. We have addressed these comments separately in Section IV.C.5. The rest of 

this section summarizes our assessment of soybean oil availability, updated since the NPRM. 

 We examined recent and historical soybean oil production and consumption volumes to 

verify that the volumes shown in Table IV.B.2-1 are achievable in 2013. As shown in Figure 

IV.B.2.c-1, soy oil production has increased steadily over the last 30 years. While the trend 

suggests that domestic soy oil production could reach nearly 2.9 bill gal by 2013, production has 

fallen short of this trend in the last few years at around 2.5 bill gallons. 
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Figure IV.B.2.c-1 

Historical Domestic Production of Soybean Oil 

1,000

1,200

1,400

1,600

1,800

2,000

2,200

2,400

2,600

2,800

3,000

1980 1985 1990 1995 2000 2005 2010 2015

Million gallons of soybean oil

Source: Oil Crops Yearbook 2011, U.S. Department of Agriculture, 

Economic Research Service, Appendix Table 5. Assumes 7.68 lb/gal. 
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Page 57 of 126 

To determine what portion of domestically produced soy oil could be available for use in the 

production of biomass-based diesel in 2013, we also examined recent historical trends for 

domestic consumption and exports. Domestic consumption of soy oil for purposes other than 

biofuel has also increased steadily over the last 30 years, but was notably lower in the period 

2007 - 2010 compared to previous years, averaging about 1.9 bill gallons. See Figure IV.B.2.c2. 

Figure IV.B.2.c-2 

Historical Non-Biofuel Domestic Consumption of Soybean Oil 

1,000

1,200

1,400

1,600

1,800

2,000

2,200

2,400

2,600

2,800

3,000

1980 1985 1990 1995 2000 2005 2010 2015

Million gallons of soybean oil

Source: Oil Crops Yearbook 2011, U.S. Department of Agriculture, 

Economic Research Service, Appendix Table 5. Assumes 7.68 lb/gal.
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If production of soybean oil in 2013 was 2.5 bill gal and domestic consumption was 1.9 bill gal, 

consistent with trends in the last several years, then the volume of soy oil that could be available 

for the production of biomass-based diesel in 2013 would be about 600 million gallons. This is 

consistent with the volumes estimated to be available in both the RFS2 final rule and the IHS 

Global Insight report. 

d. Other Vegetable Oils 

 Although the modeling we conducted for the RFS2 final rule assumed that the only form 

of vegetable oil used to make biomass-based diesel would be from soybeans, in fact other seed 

oils may contribute meaningful volumes to the pool. For instance, on September 28, 2010 we 

approved a RIN-generating pathway for biodiesel made from canola oil43. The volume of 

biodiesel made from canola oil was 96 mill gallons in 200844. In addition, we are evaluating 

other pathways for the production of biodiesel from oilseeds, such as camelina, which could 

potentially be approved for RIN generation by 2013. Algal oil could also provide additional 

feedstocks if promising technologies for production are commercialized. 

 Nevertheless, even if none of these other sources of vegetable oil were available, we 

believe that the total volume of grease, fats, corn oil, and soybean oil would be sufficient to 

produce 1.28 bill gallons of biomass-based diesel in 2013. 

3. Production Capacity

 Total production capacity of the biodiesel industry has exceeded 1.28 bill gallons for a 

number of years. As of August 2011, total production capacity was more than 2.8 bill gallons for 

179 plants45. According to the National Biodiesel Board, 113 of these plants have registered 

with the EPA under the RFS2 program as of August 27, 2011, up from 90 in February 2011, and 

these plants have a combined production capacity of over 2.0 bill gallons. Plants that are 

currently not registered under RFS2 are either producing extremely low volumes that fall under 

the regulatory threshold for RIN generation, are producing products other than biodiesel such as 

soaps or cosmetics, or have shut down until such time as the demand for biodiesel rises. 

 While commenters generally did not disagree that sufficient production capacity exists to 

reach 1.28 bill gallons in 2013, some questioned how quickly idled plants can be brought back 

online. We note that most of the production capacity exists at plants that are already producing 

some volume, and that many operating biodiesel plants are currently producing at less than their 

 

43 75 FR 59622 

44 EPA memorandum, "Summary of Modeling Input Assumptions for Canola Oil Biodiesel for the Notice of 

Supplemental Determination for Renewable Fuels Produced Under the Final RFS2 Program," Document # EPAHQ-OAR-2010-0133-0049 

45 USA Plants, biodieselmagazine.com, as of August 18, 2011. 
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full capacity. As a result, these facilities typically do 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 many new plants can be built and started within 

a year or so46, we also believe that pre-existing but idled plants can be restarted in considerably 

less time. Given that there will be more than a year between the time that the 1.28 bill gall 

requirement is finalized and the beginning of the 2013 compliance year, there is no reason to 

believe that idled plants cannot be restarted in time to contribute meaningfully to total volumes 

in 2013. 

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 legally be used at any blend level in nonroad 

diesel and heating oil. However, other factors typically limit the concentration of biodiesel in 

conventional diesel fuel. To the extent that the consumption of biodiesel occurs only at lower 

blend levels, the geographic areas where biodiesel must be marketed would correspondingly be 

higher, impacting both how much biodiesel can be consumed in the U.S. as a whole as well as 

how the infrastructure may need to change to accommodate 1.28 bill gallons in 2013. 

 Most engine manufacturers have explicit statements in their engine warranties regarding 

acceptable biodiesel blend levels. Although a few permit B100 to be used in their engines 

without any adverse impact on their warranties, most limit biodiesel blends to B20 or less, and of 

those, about half allow no more than B547. For specific applications where a party knows which 

engines will be using biodiesel blends, higher concentrations of biodiesel may be possible. 

However, for general distribution such as at retail facilities, these warranty conditions create a 

disincentive to blend or sell biodiesel at higher concentrations, and would tend to drive most 

blends towards low concentrations of biodiesel such as B5. Those parties that commented on 

this issue agreed with this assessment. 

 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 

 

46 Based on construction times for new plants listed in Biodiesel Magazine from July 2006 through May 2009. 

47 "Automaker's' and Engine Manufacturers' Positions of Support for Biodiesel Blends," Biodiesel.org 
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heating rail cars and tank trucks. However, some of these biodiesel cloud point mitigation 

efforts may be reduced through the use of low biodiesel blend levels such as B2 or B5, since 

cloud point is strongly correlated with biodiesel concentration in the final blend. Insofar as 

biodiesel is blended into conventional diesel before being transported to its final destination for 

sale, low biodiesel blend levels may reduce the need for heated equipment at the final 

destination. 

 Based on highway and nonroad diesel consumption projections for 2013 from the EIA, a 

biodiesel volume of 1.28 bill gallons would represent about 2.8% of all diesel fuel48. If all 

biodiesel were to be blended as B5, just over half of the diesel fuel consumed nationwide in 2013 

would contain biodiesel. However, today some biodiesel is blended at concentrations higher 

than B5, and we expect that some blending at these higher concentrations would continue in the 

future. One commenter disagreed that blends higher than B5 will be marketed in any but niche 

markets. We agree with this comment. However, since there has been a cost difference between 

biodiesel and conventional diesel in the recent past, and yet blends above B5 have in fact been 

sold, 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. 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%.49 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 1.28 bill 

gallons, we have declined to quantify the volume of biodiesel that is likely to be sold in blends 

higher than B5 in 2013 for use in highway and nonroad engines. 

 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. As a result, 

significant volumes of biodiesel can be consumed as heating oil and count for compliance 

purposes under the RFS program. 

 We believe that distributing and consuming 1.28 bill gallons of biodiesel in 2013 is 

achievable. A number of states already have mandates for the use of biodiesel in 201350, and 

efforts are underway by the production and distribution industries to meet these mandates. These 

include Minnesota, Oregon, Washington, Pennsylvania, New Mexico, and Louisiana. 

Collectively, these states currently account for approximately 13 percent of the nationwide 

consumption of diesel. Other states have implemented other forms of incentives as shown in 

Table IV.B.4-1. 

 

48 Assumes total diesel volume consumed in 2013 is 46.65 bill gal, per Annual Energy Outlook (AEO) 2011, Table 

10. 

49 National Biodiesel Board, Retailing Fueling Sites, as of February 17, 2011. 

http://biodiesel.org/buyingbiodiesel/retailfuelingsites/default.shtm 

50 As one commenter pointed out, some of these mandates have not yet taken effect as in-state production volumes 

have not yet reached specified thresholds. Nevertheless, the state mandates represent incentives within those states 

to increase production. 
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Table IV.B.4-1 

States with Rebates, Refunds, Reduced Tax Rates, or 

Credits for Biodiesel Production or Blending51

Illinois 

Indiana 

Kansas 

Kentucky 

Maine 

Maryland 

Michigan 

Montana 

North Dakota 

Oklahoma 

Rhode Island 

South Carolina 

South Dakota 

Texas 

Virginia 

Washington 

* Conditions and exemptions for all 

incentive programs vary by state

Collectively, the states listed in Table IV.B.4-1 currently account for approximately 37% of the 

nationwide consumption of biodiesel. A variety of states also have requirements for the use of 

biodiesel in state fleets, provisions that allow biodiesel to be used as an alternative to meeting 

alternative fuel vehicle mandates, and credits/rebates for the installation of biodiesel dispensing 

and blending equipment. Altogether, therefore, more than half of the states in the U.S. have 

mandates and/or incentives that will induce them to address biodiesel infrastructure issues. 

 One commenter pointed out that state-specific economic incentives for the production of 

biodiesel do not necessarily eliminate cost differences between biodiesel and conventional diesel. 

We agree with this comment. Nevertheless, efforts to incentivize biodiesel production and use in 

individual states will directionally help the nation to meet a 1.28 bill gal biomass-based diesel 

requirement in 2013. 

5. Biomass-Based Diesel Distribution Infrastructure

 

The National Petroleum Refiners Association (NPRA) stated that an analysis of the 

feasibility of meeting increased biodiesel use requirements should be based on a maximum 

biodiesel blend ratio of 5%.52 This is consistent with our analysis of the additional biodiesel 

distribution infrastructure that will be needed. NPRA commented that the required increase in 

 

51 U.S. Department of Energy, Alternative Fuels and Advanced Vehicles Data Center 

52 NPRA acknowledged that higher biodiesel blend ratios are sometimes used but that this would not substantially 

increase the capacity of the market to absorb additional biodiesel volume. 
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the use of biodiesel will necessitate numerous installations of biodiesel storage tanks (possibly 

heated) as well as the installation of biodiesel receiving and blending capacity at the diesel fuel 

distribution terminals throughout the U.S. markets. This is also consistent with our analysis. In 

the proposal, we noted that some terminals may be able to avoid or delay the installation of 

additional biodiesel storage facilities by storing 50/50 biodiesel/diesel fuel blends that are then 

further blended with diesel fuel to produce a finished fuel. However, we assumed that all 

biodiesel blending facilities would install segregated (heated and insulated) biodiesel storage 

facilities in our infrastructure analysis. We further noted that some terminals may delay the 

installation of biodiesel in-line blending equipment by splash blending biodiesel.53 However, we 

stated that we expect that this approach would be temporary due to the heightened concerns over 

achieving a correct blend ratio and a fully mixed biodiesel blend that accompanies splash 

blending. We assumed that terminals would install in-line biodiesel blending equipment in our 

infrastructure analysis. 

The proposed rule concluded that there will be sufficient fuel distribution infrastructure 

available to support the use of 1 bill gal of biomass-based diesel in 2012 and 1.28 bill gal in 

2013. NPRA stated that the rapid expansion in B5 blending capability in the marketplace 

necessary to support the use of the envisioned volumes of biodiesel is unrealistic and 

unachievable. NPRA did not further support this statement. The National Biodiesel Board 

(NBB) stated that there will be sufficient biodiesel distribution infrastructure available to 

facilitate the use of the envisioned volumes of biodiesel.54 NBB further stated that in most 

markets, terminals can treat 5% biodiesel blends as a fungible commodity like diesel fuel and 

that they believe that many terminals may be storing B5 blends. To the extent terminals store a 

finished B5 blend, it would obviate the need for much of the segregated biodiesel storage and 

blending capability that is assumed in our infrastructure analysis. The Iowa Biodiesel Board 

stated that claims that industry cannot accommodate the distribution of the target gallons are 

baseless and cited various examples of recent biodiesel blending initiatives at Iowa terminals. 

We acknowledge that the required expansion of the biodiesel handling capacity at 

terminals will represent a significant challenge to industry. However, we continue to believe that 

industry can respond effectively to this challenge to support the use of the envisioned 2012 and 

2013 biodiesel volumes. Industry activities are currently progressing to ramp up biodiesel 

consumption from the approximately 380 mill gallons estimated to be used in the U.S. in 2010 to 

the volumes that will be needed in 2011 to meet the biomass-based diesel volume requirement. 

For example, Kinder Morgan and the Renewable Energy Group opened a substantial biodiesel 

distribution facility to serve the Chicago area in December of 2010.55 Magellan also recently 

announced that it plans to complete its biodiesel blending facility in Sioux Falls Minnesota in 

2011.56 In June of this year, Sunoco Logistics and Sprague Energy opened a new terminal 

 

53 In-line blending refers to the process of blending biodiesel into petroleum-based diesel fuel in the delivery line 

that feeds into the tank truck from the terminal storage tanks. Splash blending refers to the process of first loading 

petroleum-based diesel fuel into a tank truck followed by biodiesel so that the final blend meets the desired blend 

ratio. 

54 NBB did not provide an analysis regarding the addition of new biodiesel distribution facilities. 

55 Biodiesel Magazine, November 17, 2010. http://www.biodieselmagazine.com/articles/4568/chicago-areaterminal-soon-to-offer-biodiesel 

56 Report to the Legislature, Annual Report on Biodiesel, Minnesota Department of Agriculture, January 15, 2011. 

http://www.mda.state.mn.us/en/news/government/~/media/Files/news/govrelations/legrpt-biodiesel2011.ashx 
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facility to supply of biodiesel blended transportation fuel and heating fuel to New Jersey57 These 

new terminal facilities employ segregated biodiesel storage and blending capability. Just as 

there has been considerable biodiesel production capacity idled due to lack of demand which will 

be brought back on line as biodiesel volumes ramp up, we believe that there may also be 

substantial idled biodiesel distribution assets that could be brought back into service. It seems 

reasonable to assume that at least some of the distribution assets used previously to deliver 

biodiesel manufactured at now idled production plants would still be available. 

Our evaluation of the changes to the fuel distribution infrastructure that will be needed to 

support the use of 920 million gallons/yr of biodiesel in 2012 and 1,200 million gallons/yr in 

2013 is based on the analysis conducted for the RFS2 final rule.58 See Table IV.B.5-1. 

Table IV.B.5-1 

Additional Infrastructure Needed to Distribute Biodiesel in 2012 and 2013 

 Additional 

Distribution 

Assets Needed in 

2012 Relative to 

2011 

Additional 

Distribution 

Assets Needed in 

2013 (with 1.28 

bill gal) Relative 

to 2012 

Total 

Distribution 

Assets Needed to 

Support the 2012 

Biodiesel 

Volume 

Total 

Distribution 

Assets Needed to 

Support 1.28 bill 

gal Biodiesel 

Volume 

Petroleum 

Product 

Terminals with 

Biodiesel 

Blending 

Capability* 

74 130 428 558 

Rail Cars 131 230 754 984 

Tank Trucks 14 25 83 108 

Barges 4 7 23 29 

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

The American Trucking Association (ATA) stated that EPA should have provided a 

discussion of the costs of the infrastructure changes contained in the above table. These costs 

were accounted for in the discussion of the overall impacts on transportation fuel costs contained 

in Section IV.C.5. It was estimated that the unsubsidized fuel cost would be 0.2 cents per 

gallon. Accounting for the subsidy, we estimated a cost savings to consumers of diesel fuel of 

1.7 cents per gallon compared to petroleum-based diesel fuel. The reader was referred to the 

RFS2 final rule Regulatory Impact Analysis for details on the projected costs of the additional 

distribution infrastructure projected to be needed. 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. The cost to install new segregated biodiesel storage, blending, receipt, 

 

57 http://www.tankterminals.com/news_detail.php?id=1284 

58 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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and other miscellaneous biodiesel handling equipment was estimated at $1.6 million per 

terminal. The estimated total cost of the additional biodiesel distribution assets needed in 2012 

relative to 2011 is $140.3 million. The estimated total cost of the additional biodiesel 

distribution assets needed in 2013 relative to 2012 is $246.5 million. 

ATA commented that EPA underestimated the number of tank trucks needed to distribute 

the additional amount of biodiesel in 2013 relative to volume used in 2012. ATA stated that the 

assumed 6 trips per tank truck per day that EPA used in estimating the number of tank trucks that 

would be needed was unrealistically high. ATA stated that one large ATA member that 

transports biofuels reports that the average length of haul (one way) is 141 miles. Based on this, 

ATA stated that 2 loads per day would be a more accurate estimate considering loading and 

unloading times. 

ATA assumed a single shift tank truck delivery operation. Our estimated number of tank 

trucks was based on a two shift operation. We continue to believe that a two shift truck delivery 

model of operation is appropriate to maximize the utilization of distribution system resources. 

Given time for loading and unloading and lunch breaks for 2 shifts, our assumed 6 deliveries per 

day equates to an average one way truck shipping distance of 40 miles. We project that number 

of additional biodiesel plants will be brought into production to meet the 2013 biodiesel volume. 

Biodiesel production plants tend to be geographically dispersed. Hence, the opening of 

additional plants will tend to reduce the average shipping distance from the biodiesel production 

plant to the terminal compared to today. We also project that the production volume will 

increase at a number of existing biodiesel plants. This will facilitate the shipment by rail of 

biodiesel volumes that previously were shipped by truck long distances. Thus, we believe that 

biodiesel trucking distances will be substantially reduced in the future. 

Nevertheless, we acknowledge that uncertainty exists regarding what biodiesel shipping 

distances will be in the future. Therefore, we believe that it is useful to evaluate the potential 

impacts of longer shipping distances on the number of additional tank trucks that will be needed 

to transport biodiesel. If we were to assume a 141 mile average truck shipping distance per ATA 

and a two-shift operation, this would translate to 4 loads per day per tank truck. At 4 loads per 

day, 38 additional number of tank trucks would be needed in 2013 relative to 2012 (as opposed 

to the 25 that we projected). If we were to assume only 2 deliveries per day as ATA did, an 

additional 75 trucks would be needed for the 2013 case. Even under this extreme case, the 

addition of 75 tank trucks would represent less than 0.3% of the total U.S. fleet of petroleum 

products tank trucks (estimated at 27,000).59 Consequently, that 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 and drivers needed. 

In the proposal, we estimated that a total of 5 tank trucks will be needed to transport 80 

mill gallons/yr of renewable diesel that we projected would be used annually in 2012 and 2013 to 

the locations where it is blended with petroleum-based diesel fuel. This is based on each tank 

 

59 Department of Transportation, Hazardous Materials, Safety Requirements for External Product Piping on Cargo 

Tanks Transporting Flammable Liquids, Notice of Proposed Rulemaking, 76 FR 4847, January 27, 2011. 

http://www.gpo.gov/fdsys/pkg/FR-2011-01-27/pdf/2011-1695.pdf 
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truck carrying 7,800 gallons of renewable diesel fuel making 6 deliveries per day. We estimate 

that the production facility that will account for the renewable diesel produced through 2013 will 

ship its product 20 miles or less by tank truck to facilities that produce blends with petroleumbased diesel fuel. Shipment of the projected renewable diesel volume such short distances could 

likely be achieved by making 6 deliveries during without the need for a second shift. We 

anticipate that the renewable diesel fuel will be blended directly into storage tanks containing 

petroleum-based diesel fuel. Consequently, we continue to believe that the distribution of 

renewable diesel fuel could be accomplished without undue difficulty. 

C. Impacts of 1.28 billion gallons of Biomass-Based Diesel 

 In order to evaluate the impacts of a biomass-based diesel volume of 1.28 bill gal in the 

areas required under the statute (see Section IV.A), we first considered what the appropriate 

reference would be. Since the statute requires that the biomass-based diesel volume we set for 

2013 be no lower than 1.0 bill gal, we believe that this is a reasonable reference point. 

Therefore, in the discussion that follows, we have focused on either a volume of 1.28 bill gal 

biomass-based diesel, or an increment of 0.28 bill gal biomass-based diesel, depending on the 

specific sources of information and analyses available. 

 As described in Section IV.B.1 above, even if we set the applicable volume for biomassbased diesel at 1.0 bill gal, the demand for biomass-based diesel in 2013 is likely to be on the 

order of 1.28 bill gal or more due to the limited projected availability of other advanced biofuels 

(including cellulosic biofuel, imported sugarcane ethanol, and others). Since the actual demand 

for biomass-based diesel would likely be 1.28 bill gal or higher regardless of whether we set the 

biomass-based diesel requirement at 1.0 or 1.28 bill gal, the net impact of setting the biomassbased diesel volume requirement at 1.28 bill gallons in 2013 could be seen as zero. 

 We recognize that this conclusion is based on an applicable advanced biofuel volume of 

2.75 bill gallons. While we will be considering the possibility of lowering the 2013 advanced 

biofuel applicable volume below 2.75 bill gal in next year's rulemaking, we have not presumed 

any such reduction in today's final rule. Such reductions in advanced biofuel must occur in the 

context of determining the applicable volume of cellulosic biofuel for 2013, and using 

information available at that time regarding advanced biofuel volumes that are projected to be 

available in 2013. 

 Nevertheless, the statute requires that we analyze specified environmental and other 

impacts in deriving an applicable biomass-based diesel volume for 2013 and other years. These 

analyses can be conducted for 1.28 bill gal biomass-based diesel or an increment of 0.28 bill gal. 

Most of the areas we are required to analyze were covered in the RFS2 final rule in some form, 

and we believe that we can use this information in satisfying our statutory obligations to analyze 

specified factors in determining the applicable volume of biomass-based diesel for 2013. 

 Some of the analyses presented in the RFS2 final rule were for the specific case of 1.28 

bill gallons in 2013. These analyses included an investigation of the expected annual rate of 

commercial production of biomass-based diesel in 2013, impacts on agricultural commodity 
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supply and price, and the cost to consumers of transportation fuel. Some of these were discussed 

in Section IV.B above. Most of the analyses in the RFS2 final rule, however, were conducted to 

represent full implementation of the RFS2 program in 2022. In these analyses, the biomassbased diesel volume was estimated to be 1.82 bill gallons, and was compared to a reference case 

in which biodiesel volume was 380 mill gallons. These cases are shown in Table IV.C-1. 

Table IV.C-1 

Primary Reference and Control Cases from RFS2 Final Rulemaking (billion gallons) 

Advanced Biofuel 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 1.28 bill gallons we chose to evaluate for today's final rule for 2013. 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 2013 (0.28 billion gallons). Many of the 

impacts analyzed for the RFS2 final rule reflected the whole biofuel mandate, not the relatively 

smaller portion just due to biodiesel. 

 In response to the NPRM, the American Petroleum Institute (API) commented that 

comparing the analyses conducted in the RFS2 final rule for the fully implemented RFS2 

program in 2022 to a biodiesel increment of 0.28 bill gal occurring in 2013 was misleading. 

They cited the fact that the 2022 analysis between the control and reference cases accounts for 

agricultural and market conditions that develop over multiple years, while the proposed biomassbased diesel requirement of 1.28 bill gallons in 2013 would require those changes to occur over a 

single year. They also cited the fact that the annualized growth rate in the RFS final rule (1.44 

bill gal increase over ten years, or about 0.14 bill gal per year) is about twice as high as the 

single-year growth from 2012 to 2013 that would occur under a requirement for 1.28 bill gallons 

(0.28 bill gallons in one year). 

 As described in Section IV.B, we believe that the industry can increase production to at 

least 1.28 bill gallons by 2013, that sufficient feedstocks will be available, and that the 

infrastructure will be able to accommodate these higher volumes. Therefore, we do not believe 

that API's concern about the different annual production growth rates in the RFS2 final rule 

compared to our proposal for 2013 is warranted. 
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 With regard to concerns about agricultural and market conditions, we agree that the 

positive impacts of yield growth and foreign crop production increases that may be reflected in 

our 2022 analysis, and which develop over multiple years, may not be representative of a singleyear increase in biomass-based diesel of 0.28 bill gallons in 2013. However, we do not believe 

that this difference makes the application of the 2022 analysis to our proposal for 2013 

misleading. Our intent in using the analyses from the RFS2 final rule was only to determine if 

an increase in biomass-based diesel of 0.28 bill gallons is reasonable given the potential impacts. 

Given that the RFS2 final rule analyzed the impacts of an increase in biomass-based diesel that 

was about five times larger than the volume increment we proposed for 2013, we continue to 

believe that the impacts of 1.28 bill gallons 2013, compared to the statutory minimum of 1.0 bill 

gallons, will likely be similar to or smaller than those we estimated for 2022. 

1. Climate Change

 Since biodiesel has a GHG benefit exceeding 50% compared to the petroleum-based 

diesel it is replacing, an increase in biomass-based diesel of 0.28 Bill gal from 2012 to 2013 

would lead to a displacement of conventional diesel fuel, with corresponding GHG emissions 

reductions. This increased use of biomass-based diesel will contribute to lower climate change 

impacts in comparison to the petroleum-based diesel it is replacing. 

 However, due to the nested nature of the RFS2 standards, biomass-based diesel is also 

used to meet the advanced biofuel standard. Moreover, both biomass-based diesel and advanced 

biofuel must meet a GHG reduction threshold of 50%. If the 2013 advanced biofuel standard 

were to remain at the 2.75 bill gal specified in the statute, an increase in the biomass-based diesel 

volume requirement from 1.0 to 1.28 bill gal would not change the total volume of advanced 

biofuel, and thus the total volume of biofuels that must meet a 50% reduction in GHGs would 

remain unchanged. Under such circumstances, a standard of 1.28 bill gal of biomass-based 

diesel would have essentially no impact on climate change in the context of the full mix of 

biofuels used to meet the RFS2 requirements. However, increasing the biomass-based diesel 

standard provides additional certainty that the total advanced biofuel standard would be met and 

provides more justification for keeping the advanced biofuel standard at the 2.75 bill gal 

specified in the statute. Not lowering the advanced standard means greater certainty that the 

GHG benefits of the advanced standard will be achieved. 

One commenter suggested this would not be the case and that increased biodiesel use 

would reduce GHG emissions compared to sugarcane ethanol, an alternative advanced biofuel 

that would be used to meet the mandate. This is based on the specific GHG reductions that we 

estimated in our lifecycle analysis for different biofuels. However, there is a range of GHG 

impacts associated with different biofuels that could go towards meeting the advanced mandate 

and the biomass-based diesel standard, and there is no indication that setting the biomass-based 

diesel standard at 1.28 would impact the overall climate change emissions in the context of the 

full mix of biofuels used to meet the RFS2 requirements. 

One commenter also suggested that by requiring 0.28 bill gallons of biomass-based diesel 

above the statutory minimum of 1.0 bill gallons, effectively shifting the biodiesel used for the 
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“other” advanced biofuel category to biomass‐based diesel, EPA would actually promote 

increased volumes of renewable fuels (rather than ethanol‐equivalent gallons based on the 1.5 

equivalence value), allowing for the greater displacement of fossil fuels. However, this is not the 

case. Although the requirement for a physical volume of biomass-based diesel will be 1.28 bill 

gallons, the contribution of this volume to compliance with the advanced biofuel requirement is 

based on energy-equivalence with respect to ethanol, not physical volumes. Thus there would be 

no additional quantities of other advanced fuels produced. 

 

2. Energy Security

 An analysis of the energy security impacts of the increased use of renewable fuels was 

conducted in support of the RFS2 rulemaking. Based on that analysis, increasing usage of 

renewable fuels including biomass-based diesel helps to reduce U.S. petroleum imports. A 

reduction of U.S. petroleum imports reduces both financial and strategic risks associated with a 

potential disruption in supply or a spike in cost of a particular energy source. This reduction in 

risks is a measure of improved U.S. energy security. 

 One commenter questioned whether a potential increase of 300-500 million gallons of 

ethanol imported from Brazil as a result of this rule would improve the energy security position 

of the U.S. by displacing diesel fuel (i.e., hydrocarbons). Another commenter suggested that the 

location of the source of ethanol is required to conduct an energy security impact analysis. The 

analysis of the energy security impacts of the RFS2 rule showed that increased use of ethanol, 

regardless of where it was produced, provides energy security benefits to the U.S. by reducing 

the macroeconomic and adjustment costs associated with potential future disruptions in U.S. 

petroleum imports. In other words, diversifying transportation fuel supply sources to the U.S. 

improves the energy security position of the U.S. 

 Another commenter also suggested that an increase in biodiesel for the mandate is 

statistically insignificant. EPA understands this to mean that the increase in biodiesel production 

due to this rule would not add significantly to the energy security of the U.S. However, EPA 

believes that any reduction in U.S. petroleum imports could result in a reduction of risk 

associated with those petroleum imports. 

 

3. Agricultural Commodities and Food Prices

For the RFS2 rule, we examined the impacts of increased renewable fuels production on 

commodity prices, food prices and trade in agricultural products. This analysis considered the 

impacts of all the biofuel feedstock sources anticipated to meet the 2022 biofuel volume 

requirements, not just biodiesel. For the RFS2, EPA used two primary models for its agricultural 

economic impacts analysis, the Food and Agriculture Sector Optimization Model (FASOM), and 

the Food and Agricultural Policy Research Institute-Center for Agriculture and Rural 

Development (FAPRI-CARD) models. The FASOM model is a long-term economic model of 

the U.S. forest and agriculture sectors that maximizes the net present value of the sum of 

producer and consumer surplus across the two sectors over time subject to market, technology, 
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and other constraints. The FAPRI-CARD models are a system of econometric models covering 

many agricultural commodities in the U.S. and internationally. They are based on historical data 

analysis, current academic research, and a reliance on accepted economic, agronomic, and 

biological relationships in agricultural production and markets.60

 

 To meet the RFS2 renewable fuel volumes, a number of price effects on the agricultural 

commodities were estimated for 2022. For instance, FASOM estimates that an increase in 

renewable fuel volumes to meet the RFS2 would result in an increase in the U.S. soybean prices 

of $1.02 per bushel (10.3 percent) above the Reference Case price in 2022. FASOM also 

projected the price of soybean oil would increase by $183 per ton (37.9 percent) over the 2022 

Reference Case price (all prices are in 2007$). Most of the additional soybeans needed for 

increased biodiesel production are diverted from U.S. exports to the rest of the world. In 

FASOM, soybean exports decrease by 135 million bushels (-13.6 percent) in 2022 relative to the 

AEO2007 Reference Case. This change represents a decrease of $453 million (-4.6 percent) in 

the total value of U.S. soybean exports in 2022. However, these price effects are not attributed 

to the demand for biodiesel feedstocks alone, rather the compounding affect of all changes in 

feedstock demand estimated to result from the total biofuel mandate in 2022. Since the impact 

on soybeans due to biodiesel demand was only a portion of this total feedstock impact and since 

the impact in 2013 will be less than considered in 2022 (since the 2013 biodiesel volumes 

anticipated are less than those for 2022), the impact on soybean prices and exports from an 

increase to 1.28 bill gall in 2013 could also be less. 

 A recent report by IHS Global Insight61 also discusses potential agricultural and 

economic impacts from increasing vegetable oil demand for biodiesel production. According to 

this study, existing soybean yield technologies are expected to be applied increasingly across the 

U.S., resulting in roughly a 10% higher growth rate in soybean yields than USDA’s projections 

from 2010-2016 which were used by EPA in its RFS2 analyses. Similarly, Global Insight 

predicts these higher yield technologies would be implemented in other large soybean-producing 

countries, such as Brazil and Argentina. If higher yields than modeled for RFS2 indeed are 

realized, then it is likely the price increases for soybean oil will be less than estimated for RFS2. 

Likewise, other price impacts, such as those on food prices, would still move in the same 

direction (i.e., an increase in price resulting from an increase in demand) but could be smaller 

than in the RFS2 analysis. 

 One commenter suggested that the biodiesel mandate for 2013 will result in an increase 

of soybean oil prices. However, as shown in Section IV.B.2.c, EPA estimates that soybean 

production will outpace non-biofuel demand in 2013. Therefore, EPA does not project that the 

price of soybean oil should increase as a result of this rule. 

 For the analyses performed for the RFS2 final rule, EPA estimated a $10 per person per 

year increase in food costs due to the total annual impact of the RFS2 program by 2022 

compared to a Reference case that assumed no RFS2 renewable fuel requirements. Again, the 

biodiesel impacts would represent only a small portion of these overall impacts and would like 

be even smaller in 2013 due to the smaller volume of feedstock required. One commenter 

 

60 (add reference to FAPRI description document used in RFS2 FRM) 

61 "Biodiesel Production Prospects for the Next Decade," IHS Global Insight, March 11, 2011. 
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suggested that EPA should conduct a more thorough analysis of food price impacts of this rule. 

However, since the volume of feedstock required in 2013 is considerably less than what is 

required by the RFS2 program in the year 2022, we can reasonably expect that the impact on 

food prices should be comparably small relative to that estimated in the RFS2 final rule. Thus, 

we did not conduct an analysis of food price impacts for the 2013 biomass-based diesel volume 

requirement of 1.28 bill gallons given that the impacts would likely be substantially less than the 

impacts on food prices of the whole RFS2 program in 2022.

4. Air Quality 

As described in the NPRM, we are relying on the analyses of renewable fuel impacts 

conducted in support of the RFS2 rule62 to qualitatively discuss the expected air quality impacts 

of a biomass-based diesel volume of 1.28 bill gallons. The RFS2 analyses reflect EPA’s most 

current assumptions regarding biodiesel emission impacts.63 

In the RFS2 rule, we analyzed both changes in pollutant emissions (measured in tons) 

and changes in ambient air quality associated with the changes in pollutant emissions. The 

changes in pollutant emissions were calculated by comparing the 2022 RFS2 renewable fuel 

volumes to volumes if the RFS2 mandate was not in place (the reference scenario).64 The 

analysis reflected full implementation of the RFS2 program in 2022 and accounted for impacts 

from multiple types of renewable fuels, of which biodiesel was only one type. Specifically, the 

RFS2 emissions inventory analysis assumed 1.82 bill gal of biodiesel in the RFS2 scenario 

compared to 0.38 bill gal of biodiesel in the reference scenario, reflecting a 1.44 bill gal increase 

in biodiesel with the rule in place. 

Biodiesel emission impacts from the RFS2 rule emissions inventory analysis are 

presented in Table IV.C.4-1. A complete discussion of the emissions inventory analysis 

conducted for the RFS2 rule can be found in Chapter 3 of the RFS2 Regulatory Impact Analysis 

(RIA).65 These biomass-based diesel emission impacts, which reflect a 1.44 bill gal increase in 

biodiesel, are all less than 1% of the total U.S. emissions inventory for each pollutant. We 

expect the impacts of the 1.28 bill gal of biomass-based diesel, as compared to the 1.0 bill gal 

statutory minimum volume, to be smaller. 

 

62 75 FR14670, March 26, 2010 63 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 

64 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. 

65 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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Table IV.C.4-1 

Biodiesel Emission Impacts of the RFS2 Renewable Fuel Volumes (1.82 bill gal) Relative to the 

Reference Case (0.38 bill gal) 

Biodiesel Impacts of RFS2 Rule Emissions Inventory 

Analysis (Δ 1.44 bill gal Biodiesel) Percent RFS2 Total 

U.S. Inventory 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% a

U.S. EPA 2010, Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis. 

EPA-420-R-10-006. February 2010. Docket EPA-HQ-OAR-2009-0472-11332. Table 3.2-

11. Note: units in Table 3.2-11 were mislabeled as tons/mmBTU. Actual units are tons. 

b

U.S. EPA 2010, Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis. 

EPA-420-R-10-006. February 2010. Docket EPA-HQ-OAR-2009-0472-11332. Table 3.2-9. 

The air quality analysis for the RFS2 rule used photochemical modeling to characterize 

primary pollutants that are emitted directly into the atmosphere and secondary pollutants that are 

formed as a result of complex chemical reactions within the atmosphere. Included in the air 

quality modeling scenarios for the RFS2 rule were large volumes of ethanol as well as other 

renewable fuels, and the nature of these complex chemical interactions makes it difficult to 

determine the air quality impacts of biodiesel alone. Specifically, the RFS2 air quality analysis 

reflects a roughly 21 bill gal increase in ethanol, far outweighing the volume increase in 

biodiesel (0.43 bill gal). A complete discussion of the RFS2 air quality analysis and its 

limitations can be found in Chapter 3 of the RFS2 Regulatory Impact Analysis (RIA).66 

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.67,68 The air 

 

66 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. 

67 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. 
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Page 72 of 126 

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. The difference between the RFS2 modeling scenarios is the basis for this analysis 

thus the 0.43 bill gal increase in biodiesel is what we use to qualitatively discuss the potential 

impacts of a 0.28 bill gal increase in biodiesel from this rule. 

Given the small emissions impact of a 0.43 bill gal increase in biodiesel on the total U.S. 

emissions inventory (the basis for our air quality modeling scenarios), we would expect the 

portion of air quality impacts attributable to a move from 1.0 to 1.28 bill gal (a 0.28 bill gal 

biodiesel increase) to be small enough that on a nationwide basis the air quality impact would 

likely not be noticeable. 

We note that Clean Air Act section 211(v) requires EPA to analyze and mitigate, to the 

greatest extent achievable, adverse air quality impacts of the renewable fuels required by the 

RFS2 rule. We intend to address any potential adverse impacts from increased renewable fuel 

use through that study and will promulgate appropriate mitigation measures separate from 

today's final rule.

5. Transportation Fuel Cost

In the NPRM, we cited cost estimates that we had developed in the RFS2 final rule. For 

instance, we estimated the year-by-year per-gallon costs for diesel fuel due to the RFS2 biofuel 

requirements. For 2013, we based our diesel fuel cost estimate on the production and use of 

biodiesel, renewable diesel fuel and some cellulosic diesel fuel. The unsubsidized cost increase 

is 0.2 cents per gallon, but accounting for the subsidy, we estimated a cost savings to consumers 

for diesel fuel of 1.7 cents per gallon. This assumes a crude oil price of 81 dollars per barrel, 

which is within the range of crude oil prices over the last several years which have ranged from 

$35 per barrel to $147 per barrel. 

 Another way to estimate the possible effects of today's rule on transportation fuel costs is 

to compare the price of total diesel fuel (representing a nationwide average blend of petroleumbased diesel and biodiesel) under a 1.0 bill gallon mandate with the price of total diesel fuel 

under a 1.28 bill gallon mandate. Effectively, this is the price increment associated with adding 

280 million gallons of biodiesel to the nationwide diesel pool. 

 The most recently released Annual Energy Outlook from EIA, AEO 2011, projects that 

1.07 billion gallons of biodiesel69 and 46.85 billion gallons of total diesel70 will be produced in 

2013. Furthermore, AEO estimates that the price of total, highway and nonroad diesel will be 

$2.97 per gallon (2009$) in 2013. Although the AEO does not include price projections for 

biodiesel, the 2011 FAPRI Outlook estimates the price of biodiesel to be $3.72 per gallon 

 68 The RFS2 air quality analysis reflects EPA’s most recent air quality analysis applicable to changes in renewable 

fuel types and volumes. 

69 AEO 2011: Liquid Fuels Supply and Disposition Table. 

70 AEO 2011: Energy Consumption by Sector and Source Table. 
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Page 73 of 126 

(2009$) in 2013.71 This price would reflect all costs components, including production, 

collection, and delivery of the feedstock to the biodiesel production facility, production of the 

biodiesel, and infrastructure changes needed to store, blend, and transport biodiesel to retail 

stations. Using this biodiesel price allows us to determine that the 2013 price of petroleum-based 

diesel would be $2.95 per gallon. Table IV.C.5-1 illustrates the calculation. 

Table IV.C.5-1 

Estimate of Biodiesel Price and Volume under AEO 2011 

 Volume (bill gallons) Price ($/gal) 

Biodiesel 1.07 3.72 

Petroleum-based diesel 45.78 2.95 

Total 46.85 2.97 

If an additional 280 million gallons of biodiesel enters the market in 2013 at $3.72 per gallon, 

displacing the same amount of petroleum-based diesel, the price for total, highway and nonroad 

diesel increases by less than $0.01 per gallon. For the nation as a whole, this represents a total 

cost of $215 million in 2013 (2009$). 

 Similarly, IHS Global Insight’s analysis also includes diesel and biodiesel prices of $3.48 

and $3.70 per gallon, respectively in 2009$. Using these prices, the impact on transportation fuel 

cost of an increase of 280 million gallons of biodiesel that displaces the same volume of 

petroleum-based diesel is negligible - the overall price of total diesel remains $3.48 per gallon 

when rounded to the nearest $0.01, though the total cost to the consumer would be $63 million in 

2013. 

 Several parties commented that the analysis of the cost impacts of 1.28 bill gallons of 

biomass-based diesel must take into account the biodiesel tax subsidy, currently scheduled to 

expire at the end of 2011. Fuel taxes and tax subsidies function to change the manner in which 

society pays for transportation fuel through redistribution of costs, but they do not change the 

total cost to society. For this reason we generally do not quantify the impact of taxes or tax 

subsidies on price, but instead focus on the costs to produce and distribute transportation fuel. 

Moreover, the impact of the biodiesel tax subsidy on the market price of biodiesel is a complex 

relationship that can be difficult to assess. For instance, Figure IV.C.5-1 shows the price of 

biodiesel over the period January 2008 through July 2011. While the biodiesel tax credit was not 

effective during 2010, the price of biodiesel was not substantially higher than it was in 2009. 

Moreover, after the tax credit was reinstated for 2011, including retroactive credits for biodiesel 

produced in 2010, the price of biodiesel in 2011 did not decrease substantially in 2011 compared 

to 2010. These results illustrate the difficulty in correlating biodiesel price with tax policies, and 

as a result we have not made an effort to project biodiesel prices in the future under different tax 

policy scenarios. 

 

71 FAPRI-ISU 2011 World Agricultural Outlook. http://www.fapri.org/outlook/2011/
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Figure IV.C.5-1 

Nationwide Average Biodiesel Prices 

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Source: DOE Alternative Fuels & Advanced Vehicles Data Center, Alternative Fuel Price Report. 

http://www.afdc.energy.gov/afdc/price_report.html

 In their comments on the 2012 Renewable Fuel Standards, the American Trucking 

Association (ATA) suggested that production of biomass-based biodiesel from yellow grease and 

other rendered fats may not be economically practical due to the diffuse nature of the feedstock 

supply chain. Specifically, ATA argues that the cost of collection of often small quantities of 

this feedstock dispersed over a wide geographic area and their transport to biofuel producers may 

be cost-prohibitive. 

 The transportation costs associated with the collection of yellow grease and other 

rendered fats are likely greater than the cost of collection for biomass-based biodiesel feedstocks 

such as soybean oil. However, the actual delivered cost of feedstocks for use in producing 

biodiesel consists of two components: the cost of production and the cost of transportation. For 

soybean oil, the cost of production (i.e. planting, fertilizing, harvesting, expelling, etc.) is 

relatively large compared to the cost of transportation to centralized biofuel producers. 

However, the cost of production for yellow grease and other rendered fats is zero, as they are 

considered wastes or byproducts. When combining both cost components (i.e. production and 

transportation) for each respective feedstock from USDA’s National Weekly Agricultural Energy 

Round-Up (www.ams.usda.gov/LSMarketNews), the total delivered costs for yellow grease and 

other rendered fats (approximately 44¢ per pound) is less that the total delivered costs for 

soybean oil (approximately 57¢ per pound). As such, we believe that the ATA concerns 

regarding the feedstock supply chain are not warranted. 

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

Renewable Fuel
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Page 75 of 126 

EPA evaluated in the RFS2 final rule the impacts on the U.S. transportation network from 

the distribution of the total additional volume of biofuels that would be used to meet the RFS2 

standards. Oakridge National Laboratory (ORNL) conducted an analysis of biofuel 

transportation activity from production plants to petroleum terminals by rail, barge, and tank 

truck to identify potential distribution constraints to help support the assessment in the RFS2 

final rule.72 The ORNL analysis concluded that the increase in biofuel shipments due to the 

RFS2 standards would have a minimal impact on U.S. transportation infrastructure. The 

majority of biofuel transportation is projected to be accomplished by rail. Nevertheless, it was 

estimated that the biofuels transport would constitute only 0.4% of the total freight tonnage for 

all commodities transported by the rail system through 2022.73 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. There were no comments on the 

proposed rule to contradict this assessment. 

7. Wetlands, Ecosystems, and Wildlife Habitats

 As directed by CAA section 211(o)(2)(B)(ii), in setting the 2013 biodiesel volume 

requirements, EPA is to consider the impacts of biodiesel production and use on wetlands, 

ecosystems and wildlife habitat. No specific public comments on these impacts were received so 

the following updates the largely qualitative analyses provided in the proposal. 

 The most complete and up-to-date assessment of these impacts is contained in the draft 

analysis prepared by EPA in response to the requirements set out in CAA section 204. This 

report has been released in draft form in order to allow interested parties to provide comments on 

the analyses and policy implications. Based on comments received including a peer review, 

updates are being made to the report, and then the final report will be published in 2011 on the 

EPA Biofuels web site. 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 (as was the 

case in the publically released draft) will provide extensive detail.74

 

72 “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. 

73 See sections 1.6.4 and 1.6.5 of the RFS2 RIA. 

74U.S. EPA (Environmental Protection Agency). 2011. 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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 The draft assessment focuses on the use of oil from soy beans as the feedstock for 

biodiesel production. Other oil seed feedstock sources represent a very small portion of biofuel 

production in 2013 so would be expected to have much less of an impact than soy oil. Corn oil 

extracted during the ethanol production process is increasing, adds a small increment of supply 

for biofuel production by 2013 that will offset demands for soy and other oil seed crops, thus 

reducing potential agricultural impact of biodiesel production. Corn 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). 

Soy production tends to use less fertilizer than corn production (the most likely alternative crop) 

and can reduce the amount of fertilizer required for corn when planted in rotation with corn. 

However, compared to other crops, erosion can be higher from fields planted in row crops such 

as corn and soy beans. While the impacts of nutrient loading and erosion tend to be site specific, 

good farming practices including the optimum fertilizer use and the set aside of sensitive lands 

via the CRP program can significantly help control these adverse affects. Wetlands can also be 

adversely affected through diversion of surface and ground water for agricultural irrigation. Soy 

bean production less frequently relies on irrigation than corn and some other crops. More 

discussion on water usage is included below in the section on water use and water quality 

impacts. 

 Ecosystems and wildlife habitat can be adversely affected if CRP lands are converted to 

crop production, if row crops such as soy beans replace grassy crops and in general if new lands 

with diverse vegetation are converted to crop production. As noted in the RFS2 rule, we do not 

expect the RFS program production to result in an increase in total acres of agricultural land 

under production in the US compared to a reference case without the impact of the RFS2 

volumes. The relatively small increase of 0.28 bill gall should not appreciably affect the amount 

of land devoted to oil seed production. Further, since soy beans are traditionally planted in 

rotation with other crops such as corn, this small increase in soy oil demand for biodiesel 

production is unlikely to replace grassy crops or result in the indirect increase in land under crop 

production. Additionally, the USDA commitment to support the CRP program should minimize 

the likelihood of any significant change in the amount of CRP land. Therefore, while some very 

local changes may result due to individual farmer’s planting decisions, since no new crop land 

are expected in the U.S. due to this increase in biodiesel production and sensitive lands will be 

protected via programs such as CRP, no measureable impact in aggregate ecosystems or wildlife 

habitat is expected. 

8. Water Quality and Quantity

 
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Page 77 of 126 

The water quality and quantity impacts of biodiesel are primarily related to the type of 

feedstock and the production practices used to both produce the feedstock and to convert the 

feedstock into biodiesel. Soybeans are the principal feedstock used for biodiesel production and 

are predicted to account for 600 million gallons of the 1.28 billion gallons evaluated for 2013. 

Non-food grade corn oil extracted during ethanol production, animal fats and recycled fats 

account for most of the remaining biodiesel feedstock. Since these fats and greases are the 

byproduct of another use and are not produced specifically for biodiesel manufacture, their 

production and primary use is not related to the level of biodiesel so their indirect impacts are not 

considered here. While non-food grade corn oil is extracted for its use as a feedstock for 

biodiesel production, it is a by-product of corn ethanol production. The corn used for biofuel 

production is primarily grown for the purpose of producing ethanol, not as a source of extracted 

non-food grade oil so the water impacts of corn production are primarily a concern for ethanol 

produced from the corn starch, not the by-product of extracted corn oil. Thus, this analysis will 

focus on soybeans as a primary source of vegetable oil used in biodiesel production. No specific 

public comments on these impacts were received so the following updates the largely qualitative 

analyses provided in the proposal. 

From a water quality perspective, the primary pollutants of concern from soybean 

production are fertilizers (nitrogen and phosphorus) and sediment. There are three major 

pathways for these potential pollutants to reach water from agricultural lands: runoff from the 

land’s surface, subsurface tile drains, or leaching to ground water. Climate, hydrological, and 

management factors influence the potential for these contaminants to reach water from 

agricultural lands. 

a. Impacts on Water Quality and Water Quantity Associated with Soybean 

Production

 After corn, soybeans are the second largest agricultural crop in terms of acreage in the 

U.S. 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. 75Legumes have associations in their roots with bacteria that can acquire 

atmospheric nitrogen and convert it into bioavailable forms, reducing the need for external 

addition of nitrogen fertilizer. However, losses of nitrogen and phosphorus from soybeans can 

 

75 U.S. EPA (United States Environmental Protection Agency). Renewable fuel standard program (RFS2) regulatory 

impact analysis. EPA-420-R-10-006. Available at: http://www.epa.gov/otaq/renewablefuels/420r10006.pdf. 
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occur at quantities that can degrade water quality. 76 In 2006, USDA’s NASS estimated that 

nitrogen and phosphorus fertilizers were applied to 18 percent and 23 percent of soybean 

acreage, respectively, with an average of 16 pounds of nitrogen and 46 pounds of phosphate 

applied per acre fertilized (NASS, 2007).77 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.78 

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.79 

The effectiveness of conservation practices, however, depends upon their adoption. The 

USDA‘s Conservation Effects Assessment Project (CEAP) quantified the effects of conservation 

practices used on cultivated cropland in the Upper Mississippi River Basin. It found that, while 

erosion control practices are commonly used, there is considerably less adoption of proper 

nutrient management to mitigate nitrogen loss to water bodies.80 However, as noted above, the 

relatively low amount of fertilizer used for soy bean production tends to lessen the potential for 

nitrogen loss to water bodies. 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. This is also the case for assuring that the amount 

of corn stover or other crop residue removed to provide feedstock for cellulosic biofuel 

production is sustainable and does not result in critical loss of soil cover and subsequent soil 

erosion. In the case of corn stover, the trend to more dense crop and hence greater stover per 

acre will help in providing a sustainable source of feedstock. Indeed, when EPA assessed corn 

stover as a potential feedstock, we took into account the need to leave an appreciable amount of 

 

76 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. 

77 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. 

78 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. 

79 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. 

80 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 . 
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stover for land cover and soil enrichment. Good farming practices can allow for corn stover and 

other crop residue removal without necessarily increasing soil erosion or nutrient runoff. 

 

 Water for soybean cultivation predominately comes from rainfall, although about 11 

percent of soybean acres in the U.S. are irrigated.81 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.82

 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). 83The 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 the cultivation and harvesting of corn, corn stover, 

or soybeans on CRP lands is considered a renewable source of energy as defined in RFS2. 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. Historically, land 

entering and exiting the CRP program has been more vulnerable to erosion than other cultivated 

land, but also less productive. 84 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. 

b. Impacts on Water Quality and Water Quantity Associated with Biodiesel 

Production

Biological oxygen demand (BOD), total suspended solids, and glycerin pose the major 

water quality concerns in wastewater discharged from biodiesel facilities. Actual impacts depend 

on a range of factors, including the type of feedstock processed, biorefinery technology, effluent 

controls, and water re-use/recycling practices, as well as the facility location and source and 

receiving water. 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 

 

81U.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

82 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 83 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.

84 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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glycerin. Glycerin disposal may be regulated under several EPA programs, depending on the 

practice. However, there have been incidences of glycerin dumping, including an incident in 

Missouri that resulted in a large fish kill.85 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.86 To mitigate wastewater issues, some production systems reclaim glycerin from the 

wastewater. Closed-loop systems in which water and solvents can be recycled and reused can 

reduce the quantity of water that must be pretreated before discharge. 

 Biodiesel can also impact water bodies as a result of spills. However, biodiesel degrades 

approximately four times faster than petroleum diesel including in aquatic environments.87 

Results of aquatic toxicity testing of biodiesel indicate that it is less toxic than regular diesel.88 

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.89 

9. 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. Income expansion in rural areas from renewable fuel 

production will contribute to rural economic development. As mentioned above, industry 

activities are currently progressing to ramp up biodiesel production from the approximately 380 

mill gallons estimated to be used in the U.S. in 2010 to the 800 mill gallons that is estimated to 

be used in 2011 to meet the RFS2 biomass-based diesel volume requirement. In addition, it is 

anticipated that biodiesel production capacity idled due to lack of demand will be brought back 

on line as biodiesel volumes ramp up. Expansions to the fuel distribution infrastructure (i.e., 

more fuel terminals, rail cars, tank trucks, barges etc.) will be needed to support the use of 1 bill 

gal/yr of biodiesel in 2012 and 1.28 bill gal/yr in 2013 based on the analysis conducted for the 

 

85 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.. 86 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.. 87 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 . 88 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. 

89 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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RFS2 final rule.90 We expect 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 EPA anticipated when it analyzed the RFS2 rule. 

 One commenter stated that expanding biodiesel production in the U.S. would result in 

significant employment gains in the biodiesel industry. Another commenter raised the issue of 

the impacts of the potential increased use of animal fats to produce biodiesel under a 1.28 bill 

gallon requirement on employment within the oleochemical industry. According to the 

commenter, with renewable fuel production consuming an increasingly significant amount of the 

total supply of animal fats produced in the U.S., this may limit the availability of animal fats for 

oleochemical production. According to the commenter, the price of animal fats recently exceeded 

the price of Malaysian palm oil. If the oleochemical industry switched to palm oil as a feedstock to 

make its products and located near palm oil supply, there could be a possible loss of U.S. 

employment in this industry. 

 As the commenter pointed out, we cannot prevent any feedstocks from being used to produce 

RIN-generating renewable fuel if they meet the regulatory definition of renewable biomass and are 

otherwise valid. Nevertheless, we noted in Section IV.B.2 that there would be sufficient sources of 

feedstock to produce 1.28 bill gallons of biomass-based diesel without using any animal fats. 

Moreover, as described in Section IV.B.1, we believe it is likely that the advanced biofuel standard 

of 2.75 bill gallons would drive demand for biomass-based diesel above 1.0 bill gallons, potentially 

to as high as 1.28 bill gal. Under such circumstances, the requirement for 1.28 bill gallons would 

have little or no effect on the production of biomass-based diesel, and thus on the consumption of 

animal fats, than if the requirement was set at 1.0 bill gallons. Given these same circumstances, we 

would not expect significant impacts on the domestic oleochemical industry of the biomass-based 

diesel standard of 1.28 bill gallons. 

D. Final 2013 Volume for Biomass-Based Diesel 

We are finalizing an applicable volume of 1.28 bill gal biomass-based diesel for 2013, 

consistent with our proposal. We received comments both in support of and opposed to an 

increase above the statutory minimum of 1.0 bill gallons. We have determined that 1.28 bill 

gallons is achievable in 2013, and after analyzing the factors required under the statute, we have 

determined that setting the applicable volume of biomass-based diesel at 1.28 bill gallons is a 

reasonable exercise of our authority under 211(o)(2)(B)(ii). 

As noted in Section IV.B, because we have made no decision with regard to whether to 

reduce any portion of the 2013 advanced biofuel applicable volume in this rulemaking, we have 

used the 2.75 bill gallon applicable volume for the analyses in today’s final rule. Given an 

advanced biofuel applicable volume of 2.75 bill gallons for 2013, the 1.28 bill gal biomass-based 

diesel volume requirement is not expected to force any additional biomass-based diesel volumes 

into the market in 2013 than would have occurred under a requirement for 1.0 bill gallons. As a 

result, the increase in biomass-based diesel from the statutory minimum of 1.0 bill gal to 1.28 

 

90Renewable Fuels Standard Program (RFS2), Regulatory Impact Analysis (RIA), EPA-420-R-10-006, February 

2010. Available at: http://www.epa.gov/otaq/renewablefuels/420r10006.pdf. 
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bill gal could be seen as not having any impact beyond what is anticipated to result from meeting 

the current 2.75 bill gal advanced biofuel applicable volume. 

E. 2014 and Beyond 

 EPA is directed under CAA 211(o)(2) to determine the required biomass-based diesel 

volumes no less than 14 months ahead of the first year that they would be applicable. We did not 

propose biomass-based diesel standards for 2014 and beyond in the NPRM since we believe we 

will be in a better position in the future to evaluate all of the factors related to establishing an 

applicable volume for 2014 and later years. 

 In response to the NPRM, two parties commented that EPA should set the required 

volumes of biomass-based diesel through at least the year 2017. We agree that specifying the 

required volumes of biomass-based diesel for more than one compliance year would provide 

greater certainty for both biofuel producers and obligated parties, stability for future investments 

and contracts, and could potentially reduce the need to waive a portion of the advanced biofuel 

requirement in future years, thus furthering the goals of the statute to require increasing volumes 

of advanced biofuel through 2022. However, we will have more information on the operation of 

the RFS program and on the industry's response to higher mandates after 2011. Therefore, we 

will take these comments into consideration in future rulemakings. 

V. Changes to RFS2 Regulations 

 As the RFS2 program got underway in the second half of 2010, we discovered that a 

number of regulatory provisions were causing confusion among regulated parties. In some cases 

the confusion was due to a lack of specificity in terms, while in others it was due to unique 

circumstances that were not sufficiently addressed in the RFS2 regulations. A few amendments 

are being finalized in order to correct these problems and to amend regulatory language that 

inadvertently misrepresented our intent as reflected in the preamble to the final RFS2 

regulations. In addition, as we have worked with regulated parties to ensure that the RFS 

program is operating as intended, we identified areas in the regulations that could benefit from 

streamlining. We also identified one provision in the gasoline benzene regulations that 

misrepresented our intent as stated in the preamble. As a result, we are finalizing a number of 

amendments to the RFS regulations, and one amendment to the gasoline benzene regulations, in 

40 CFR Part 80. 

A. Summary of Amendments 

 Below is a table listing the provisions that we are amending in today’s action. We have 

provided additional explanation for several of these amendments in Sections V.B through V.F 

below. 
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Table V.A-1 

Summary of Technical Amendments 

Section Description 

80.1275(d)(3) 

Removed to allow for the inclusion of transferred blendstocks in the 

calculation of benzene early credits. 

80.1401 

Amended definition of "annual cover crop" to clarify that the crop 

has no existing market to which it can be sold except for its use as 

feedstock for the production of renewable fuel. 

80.1401 

Amended definition of “naphtha” to clarify that it applies to 

hydrocarbons only, must be commonly or commercially known as 

naphtha, and is used for producing gasoline. 

80.1405(a), (b), and (d) 

Amended to state the standards for 2012 and the date of the annual 

standards calculation. 

80.1405(c) 

Amended terms “GEi” and “DEi” to reference the amount of gasoline 

and/or diesel produced by small refineries and small refiners that are 

exempt pursuant to §§80.1441 and 80.1442. 

80.1415(c)(2) 

Amended to state the specific requirements needed for technical 

justifications for applications for Equivalence Values. 

80.1426, Table 1 

Amended to add ID letters to pathways to facilitate references to 

specific pathways and to change the reference to “canola” to 

“canola/rapeseed”. 

80.1426(f)(1) 

Corrected typographical error in cross reference to paragraph (f)(6) 

of §80.1426. 

80.1426(f)(5)(ii) 

Amended requirements so that the separated yard waste plans and 

separated food waste plans need not be approved by EPA, but instead 

only need to be accepted by EPA under the registration provisions. 

80.1429(b)(2) 

Amended to clarify that "fossil-based” diesel fuel is different from 

renewable diesel fuel. 

80.1429(b)(9) 

Amended to include RIN separation limitations on parties whose 

non-export RVOs are solely related to imports of gasoline and diesel 

or the use of blendstocks to produce gasoline or diesel. 

80.1449(a) 

Amended Production Outlook Report due date; added allowance for 

unregistered renewable fuel producers and importers to submit 

Production Outlook Reports. 

80.1450(d)(1)-(d)(3) 

Amended to add more specificity on when updates, addenda, or 

resubmittals are required for engineering reviews and to include 

references to foreign ethanol producers. 

80.1451(a)(1)(xi) 

Amended to clarify that this section references RFS1 RINs retired for 

compliance. 

80.1452(b)(2) Corrected typographical error. 

80.1452(b)(4) 

Amended to clarify that a RIN-generating importer must submit to 

EMTS the EPA facility registration number of the facility at which 

the renewable fuel producer or foreign ethanol producer produced the 

batch. 

§80.1452(b)(5) 

Amended to clarify that for imports of renewable fuel, the RINgenerator must submit to EMTS the EPA facility registration number 
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of the importer that imported the batch. 

§80.1454(e)(3) 

Amended to require submission of additional evidence as part of 

registration to verify eligibility for exemptions in §80.1403(c) or (d). 

80.1460(b)(6) 

Adds the existing prohibition against generating a RIN for fuel for 

which RINs have previously been generated. 

80.1464(a)(2)(iii), 

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

(b)(2)(iv), (c)(1)(iii), and 

(c)(1)(iv) 

Added to clarify that auditors must verify that product transfer 

documents for RIN transactions contain the required information for 

obligated parties/exporters and for renewable fuel 

producers/importers. 

80.1464(a)(2)(i), 

(a)(3)(ii), (b)(2)(i), 

(b)(3)(ii) 

Amended to clarify that auditors must validate RIN separations for 

obligated parties/exporters and for renewable fuel 

producers/importers; amended to correct typographical error. 

80.1465(h)(2); 

80.1466(h)(2); and 

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

(g)(2) 

Amended to remove the option of using an alternative commitment 

in lieu of paying a bond and to clarify the amount of bond a foreign 

entity must post. 

B. Technical Justification for Equivalence Value Application 

A producer or importer of renewable fuels is required to submit an equivalence value 

(EV) application in accordance with §80.1415(c) for any renewable fuel that does not have an 

EV listed in §80.1415(b). In addition, a producer or importer could apply for an alternative EV 

if the producer or importer has reason to believe that a different EV than that listed in 

§80.1415(b) is warranted. Section 80.1415(c) provides the calculation equation for the EV of the 

renewable fuel and the requirements for the technical justification to be submitted in the EV 

application. 

We have received many inquiries from producers and importers of renewable fuels 

requesting clarification of the specific requirements for the technical justification listed in 

§80.1415(c). In addition, based on the many EV applications we have evaluated, we have found 

that we needed to request additional information from producers and importers to better 

understand the composition of the renewable fuel they produced, such as intermediate steps and 

energy inputs in production process, sources of renewable and non-renewable feedstock, and so 

forth, to better evaluate and assign the correct EV to the producer or importer’s renewable fuel. 

Therefore, we are finalizing in this rulemaking amendments to §80.1415(c)(2) to clarify 

the current requirements and to include additional requirements for the technical justification to 

be submitted in the EV application. The final amendments to §80.1415(c)(2) include: 

- A calculation for the requested equivalence value according to the equation in 

§80.1415(c)(1), including supporting documentation for the energy content (EC) of the 

renewable fuel such as a certificate of analysis from a laboratory that verifies the lower 

heating value in Btu per gallon of the renewable fuel produced. 

- For each feedstock, component or additive used to make the renewable fuel, provide a 

description, the percent input and identify whether or not it is renewable biomass or is 

derived from renewable biomass. 
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- For each feedstock that could independently qualify as a renewable fuel, state whether or 

not RINs have been previously generated for the feedstock. 

- A description of renewable fuel and the production process, including a block diagram 

that shows quantities of all inputs and outputs required at each step of the production 

process for the production of one batch of renewable fuel. 

We received no adverse comments on our proposed changes to §80.1415(c)(2), and so 

are finalizing the changes as proposed. 

 C. Changes to Definitions of Terms 

 1. Definition of Annual Cover Crop

As explained in the preamble of the RFS2 final rulemaking, EPA extended modeling for 

cellulosic biofuel made from corn stover and biodiesel/renewable diesel made from waste 

oils/fats/greases to certain fuels made from annual cover crops, based on the expectation that 

cultivation of annual cover crops, as defined in §80.1401, will have little impact on the 

agricultural commodity markets and therefore little or no land use impact associated with them. 

Therefore, certain fuels (as specified in Table 1 to §80.1426) derived from annual cover crop 

feedstocks qualify for D-codes under the advanced biofuel, biomass-based diesel, and cellulosic 

renewable fuel categories. 

Section 80.1401 of the final RFS2 rule defines “annual cover crop.” We proposed to 

amend the definition of annual cover crop in order to more clearly define those feedstocks that 

meet the intent of including cover crops in several pathways in Table 1 to §80.1426. 

As explained in the proposal, in order to extend our modeling to cover crops, we used the 

rationale that annual cover crops would have no land use impact since they are planted on land 

otherwise used for crop production. Greenhouse gas emissions would only be associated with 

growing, harvesting and transporting the cover crop, and then processing into biofuel. (See 75 

FR 14794 col. 3.) Thus, we assumed that no additional land would be required to plant annual 

cover crops, that cover crops would not displace primary crop production, and that the use of the 

cover crop as a feedstock for renewable fuels would not have secondary impacts on other 

agricultural commodity markets. This implies that annual cover crops would not be planted and 

harvested for the purpose of being sold to existing markets. If a cover crop already had an 

existing market, then the increased use of cover crops as feedstocks for renewable fuel 

production could potentially impact the existing markets. Therefore, we proposed to amend the 

current definition for “annual cover crop” to clarify that for purposes of the RFS program the 

term only includes crops that have no existing market to which they can be sold except for the 

use of the feedstock for renewable fuel. This will ensure that no unintended land use or 

significant indirect effects result from the use of annual cover crops as feedstocks for renewable 

fuel production. 

Several parties commented against this change, stating that it is too restrictive and thus 

would prevent some crops they considered cover crops from qualifying as eligible feedstock 
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under the RFS2 program. While this change clarifies that crops having existing market impacts 

would not qualify as cover crops, such exclusion is consistent with the basis for including the 

cover crop provision. EPA determined that crops with no market value could be planted on land 

without any expected impact on other crops and thus no expected indirect land use impact. This 

amendment clarifies that only crops with no market impact can qualify as cover crops and is 

consistent with the underlying analysis. However, even if a crop does not qualify under this 

revised cover crop definition, that does not prevent it from being included as an eligible 

feedstock under the RFS2 program. As stated in the proposal, EPA recognizes that there may be 

additional fuel pathways requiring lifecycle greenhouse gas (GHG) assessments and the 

assignment of appropriate RIN D-Codes, including those using feedstocks that do not meet the 

proposed amended definition of annual cover crop. For further guidance on the process for 

requesting EPA evaluation of new fuel pathways, please refer to the following sites: 

http://www.epa.gov/otaq/fuels/renewablefuels/compliancehelp/rfs2-lca-pathways.htm

http://www.epa.gov/otaq/fuels/renewablefuels/compliancehelp/lca-petition-instructions.htm#1

2. Definition of "Naphtha"

 In the RFS2 final rule, we included several RIN-generating pathways in Table 1 to 

§80.1426 for naphtha made from renewable biomass. We also provided a definition of naphtha 

in §80.1401. However, the definition we finalized was overly broad and did not adequately 

represent our intent to limit naphtha to gasoline blendstocks. As a result, some biofuel producers 

have expressed interest in interpreting the term "naphtha" to include materials that, while falling 

within the boiling range of gasoline, are not used as a blendstock to produce gasoline. 

 To remedy this situation, we proposed to revise the definition of naphtha to also specify 

that it applies only to blendstocks which are composed of only hydrocarbons, are commonly or 

commercially known as naphtha, and are used to produce gasoline. We received no adverse 

comments on this proposal, and so are finalizing it as proposed. 

D. Technical Amendments Related to RIN Generation and Separation 

1. RIN Separation Limit for Obligated Parties

 We proposed to amend section §80.1429(b)(9) to limit the amount of RINs a company 

who is an obligated party solely by virtue of importation of obligated fuel can separate to meet 

their Renewable Volume Obligation (RVO). This proposal was designed to prevent abuse of the 

obligated party RIN separation provision by a company that imports a relatively small amount of 

an obligated volume, but then separates a large amount of RINs. It was also designed to help 

prevent hoarding of RINs by parties that do not need them for compliance purposes, and to 

generally increase the liquidity of RINs. EPA structured the original RFS1 separation 

regulations around facilitating compliance by obligated parties who must acquire RINs to meet 
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their RVOs. This change is consistent with the original design and also ensures that importers 

can separate enough RINs to meet their obligations. Overall, commenters were against this 

amendment with many companies indicating that they are currently taking advantage of the 

ability to separate all RINs in their possession if they are an obligated party solely related to their 

gasoline and/or diesel imports, and that they wish to continue to do so. 

One commenter opposed this change, stating that the RIN life limitation would prevent 

hoarding. EPA does not agree with this; the life of a RIN prevents use for compliance after a 

designated amount of time, see §80.1447(a)(6), this does not provide an adequate mechanism to 

prevent hoarding of RINs. 

Several commenters stated that the carryover provisions prevent RIN hoarding. EPA 

does not agree; the carryover provisions, §80.1428(a)(5), refer only to the ratio of assigned RINs 

to volumes of renewable fuel owned at the end of a quarter. There is no limit on the amount of 

separated RINs that a party may own at the end of a quarter. 

Several commenters stated that market liquidity would decrease if obligated importers 

could not separate all RINs that they own. They also stated that RINs will be held by fewer 

obligated parties. We believe that market liquidity would not be decreased; RIN separation 

would still occur according to §80.1429 and obligated parties would still have access to the 

separated RINs needed for compliance. In fact, to the extent that the provision prevents RIN 

hoarding, as intended, it should increase RIN liquidity.EPA has determined that this will not 

change or limit who can participate in the RFS program or become an obligated party; it will 

only limit the number of RINs that certain importers can separate. In addition, these obligated 

importers and any other RIN owning party can separate RINs without being subject to the 

limitation in §80.1429(b)(9) for any of the reasons outlined in §80.1429(b)(2)-(b)(5) and (b)(8). 

One commenter was concerned about how an obligated importer would know how many 

RINs they could separate for “receipt of fuel by an obligated party” noting that they will not 

know their exact RVO until the end of the compliance year. EPA believes that obligated 

importers should separate RINs on the basis of “receipt of fuel by an obligated party” only to the 

extent necessary to meet their existing obligation. 

One commenter felt that the proposed amendment would limit the actual capacity of an 

importer to introduce a volume of renewable fuel into the marketplace. EPA does not agree with 

this statement and believes that limiting RIN separation using the reason “receipt of fuel by an 

obligated party” would not reduce the amount of renewable fuel that is in demand and may be 

sold. 

One commenter requested confirmation of the following statement: “this change would, 

in no way, limit the right of a company to separate RINs from renewable fuel if that entity is 

acting as a blender and blending renewable fuel into transportation, heating fuel or jet fuel.” 

EPA confirms the previous statement with one clarification. Amended §80.1429 applies “except 

as provided in paragraphs (b)(2) through (b)(5) and (b)(8).” Since the obligation for blenders to 

separate Ins for renewable fuel that they blend to produce a transportation fuel, heating oil or jet 

fuel appears in (b)(2), the limitations in (b)(9) are not applicable to RIN separations pursuant to 
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that provision. We clarify, however, that (b)(2) applies to blending “to produce” a transportation 

fuel, heating oil or jet fuel. For example, blending biodiesel at a rate of 5% into motor vehicle 

diesel fuel would produce a transportation fuel. 

One commenter indicated that this method of separation helped companies that did not 

want to be involved with the RFS program; allowing obligated importers to transfer renewable 

fuel without RINs and not violating the quarterly check outlined in §80.1428(a)(5). EPA notes 

that all parties have the ability to separate up to 2.5 RINs per gallon pursuant to §80.1429. This 

amendment, which will limit obligated importers’ ability to separate RINs, would not change this 

feature. This provision could facilitate the transfer of fuel with separated RINs to parties not 

wishing to receive RINs. Also, small blenders have the ability to delegate all RIN related 

responsibilities to the party directly upstream as long as they are blending less than 125,000 

gallons of renewable fuel per year (§80.1440). In addition to separating up to their RVO, 

obligated importers and any other RIN owning party can separate for any of the reasons outlined 

in §80.1429(b)(2)-(b)(5) and (b)(8) without being subject to the limitation in (b)(9). 

One commenter argued that the ability to separate as an obligated importer allowed them 

more flexibility with RIN transfer dates. EPA believes that this implies that the party uses its 

ability to separate to avoid the requirement in §80.1428(a)(3) “an assigned RIN cannot be 

transferred to another person without simultaneously transferring a volume of renewable fuel to 

that same person.” The commenter indicated that a reason for becoming an obligated importer is 

to be able to separate all RINs and avoid the previously referenced regulatory requirement. This 

also allows them to remain in compliance with the EMTS transaction reporting time frames laid 

out on §80.1452(c). EPA believes that transfer date and the ability to transfer separated RINs 

without renewable fuel are not relevant to this amendment. The commenter’s use of the 

provision is counter to how the program was set up to ensure the distribution of RINs and could 

be used not only to slow the transfer of RINs downstream to the blender or final user of the 

renewable fuel, but also allow hoarding. The commenter also stated that there is no requirement 

to report physical fuel inventory and number of assigned RINs (§80.1428(a)(5)). EPA has 

determined that this statement is not accurate pursuant to §80.1451. Currently, 

§80.1451(c)(2)(xiv), requires the volume of renewable fuel owned at the end of the quarter. This 

volume must meet the requirements of §80.1428(a)(5). 

EPA believes that while commenters were mainly against the amendment, specific 

arguments presented supported EPAs reason for the amendment. For the reasons stated above, 

we are finalizing the regulatory changes as proposed. 
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 2. RIN Retirement Provision for Error Correction

 

 As we stated in the proposal, in some instances, renewable fuel producers or importers 

may improperly generate RINs in EMTS as a result of calculation errors, meter malfunctions or 

clerical errors. Pursuant to §80.1431(a), improperly generated RINs are invalid, and cannot be 

used to achieve compliance with any Renewable Volume Obligations (RVOs). 

 EPA sought comment on the possibility of amending §80.1431 to provide the regulated 

community with limited flexibility to allow certain RINs that were improperly generated to 

nevertheless be transferred and used for compliance, provided the RIN-generator retires 

equivalent RINs (the same quantity and fuel category (D-code) of RINs with the same RIN year) 

in order to make the market whole. 

We sought comment on whether EPA should amend the regulations to include the 

flexibility for EPA to allow improperly generated RINs to be used for compliance, whether the 

conditions set forth in the proposal were appropriate, and whether there are additional or 

alternative conditions that should be imposed if the flexibility were to be granted. We proposed 

that the following general limitations should apply to any flexibility to allow improperly 

generated RINs to be transferred and used for compliance: 1) the RINs must have been 

improperly generated as a result of an inadvertent error, 2) the improperly generated RINs must 

have the correct D code, 3) the RIN generator must correct the information submitted to EMTS 

and retire an equivalent number and type of any excess RINs that were generated as a result of 

the error within a fixed time period of 60 days, 4) the flexibility to allow improperly generated 

RINs to be used for compliance would only apply if the number of excess RINs generated for a 

particular batch exceeds the number of RINs that should have been generated by no more than 

two percent, and 5) the flexibility to allow improperly generated RINs to be used for compliance 

should be limited to a certain number of times per year per RIN generator. 
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We received several comments in support of providing EPA with some sort of flexibility 

to allow improperly generated RINs to be used for compliance, and a few comments that did not 

support EPA providing any flexibility of this type. Supporters of the flexibility believe that this 

flexibility is necessary for good faith RIN generators who have made inadvertent mistakes. They 

argue that the flexibility will avoid time spent by both EPA and regulated parties tracking 

invalidly generated RINs to their current owner when equivalent RINs could be retired to make 

the system whole. Commenters believe EPA’s time is better spent investigating more egregious 

violations. Many supporters of the flexibility, however, believe that, given the proposed 

limitations, the proposed flexibility would be too narrow. Commenters believe that EPA should 

take into consideration the totality of the circumstances, including the number of RINs/percent of 

the batch that are invalid, the frequency of improper generation on the part of the producer and 

indications of good faith mistake when determining whether to allow the flexibility for 

improperly generated RINs to be used for compliance, rather than imposing strict limitations on 

the use of the flexibility. 

EPA believes that providing this type of flexibility will reduce disruptions to the RIN 

market while continuing to apply appropriate pressure on parties that generate, transfer and use 

RINs to comply with the regulations. However, EPA disagrees with the commenters that 

advocated that the flexibility should be unlimited. EPA believes that by limiting the use of this 

flexibility, RIN generators are provided an incentive to implement and utilize measures and 

controls to ensure the validly of information sent to EMTS in a more timely manner. Therefore, 

in today’s rule in 80.1431(c) and (d), EPA is finalizing an approach that provides flexibility to 

RIN generators to retire equivalent RINs in situations where they have over-generated RINs on a 

batch due a broken meter, an inadvertent temperature correction error, or an inadvertent 

administrative error. This flexibility may only be used under certain conditions, though, in order 

to mitigate harm to the RIN market, as specified in the regulations and discussed in detail below. 

Some commenters supported the proposed 60-day time allowance for a RIN generator to 

correct RIN generation information submitted to EMTS. The commenters believe 60 days is 

sufficient to identify and correct inadvertent mistakes, and the time limit provides an incentive 

for the regulated community to regularly verify that RINs have been correctly generated. On the 

other hand, another commenter thought that the correction period should be longer than 60 days. 

One commenter suggested 18 months for RIN generators to notify EPA of improperly generated 

RINs at which point EPA would determine whether to allow those invalid RINs to be used for 

compliance. The commenter believed this would allow invalid RINs to be discovered during the 

attest audit conducted each year concerning the renewable fuel producer’s compliance records. 

Additionally, commenters generally disagreed with EPA’s proposal to limit the flexibility 

to situations where the number of excess RINs generated for a particular batch exceeds the 

number of RINs that should have been generated by no more than 2%. Commenters argued that 

a simple typing error in any digit can easily result in an over-generation that far exceeds 2%. 

One commenter suggested that the number of RINs eligible for the flexibility be limited to no 

more than 2% of a specific RVO category (e.g. Cellulosic Biofuel, Advanced Biofuel, etc.) for 

any given year. Another suggested that there is no reason to limit the flexibility this way, and 

that EPA should maintain discretion to determine when invalid RINs can be used for 

compliance, regardless of what percentage of the RIN batch is invalid. The commenter states 
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that there is no reasonable equitable basis for limiting the availability of the flexibility to 

situations involving an error of no more than 2%, since there can be significant variability in the 

size of renewable fuel batches; for example, 2% of a large batch could consist of more RINs than 

an entire batch for a smaller facility. 

In today’s final rule, EPA did not limit the ability to use the flexibility to a certain 

number of RINs or percentage of a batch as proposed because we agree with commenters’ 

suggestion that a simple typing or meter error may result in a large number of excess RINs just 

as easily as it could result in an error that constitutes only a small number of RINs. EPA’s 

decision to eliminate the two percent limitation may result in more regulated parties taking 

advantage of the flexibility created by this rule. Nevertheless, EPA is limiting the use of the 

flexibility to situations in which RIN generators who improperly over-generated RINs on a batch 

fit certain criteria, including taking remedial action to retire equivalent RINs within 30 days of 

the original invalid RIN generation submission in EMTS, as specified in 80.1431(c)(7). EPA 

believes that it is appropriate to require RIN generators to correct the information submitted to 

EMTS within 30 days to encourage the regulated community to take prompt corrective action, 

which will aid in maintaining market integrity. EPA believes that limiting the amount of time 

that RIN generators are afforded to avail themselves of this flexibility is necessary to provide an 

incentive to RIN generators to conduct timely internal inspections of their RIN generation 

activities in order to ensure that RINs are properly generated and the accuracy of RIN 

information in EMTS. 

We also sought comment on the possibility of establishing a limit on the number of times 

this flexibility could be requested within a compliance period by a given RIN generator. We 

stated that we believe such a limitation could encourage RIN generators to take appropriate 

measures to avoid generating invalid RINs, and limit the possibility that RIN generators would 

intentionally generate invalid RINs to take advantage of short term RIN price spikes. Some 

commenters argued that there should not be a limit on the number of times a RIN generator can 

request EPA allow them to use the flexibility, but that if a particular company regularly generates 

RINs improperly, that company should be penalized on a case-by-case basis, taking into account 

whether the error was truly a mistake made in good faith. 

EPA disagrees with commenters’ belief that RIN generators should have unlimited access 

to these flexibilities. EPA believes that the flexibility should be limited to a set number (namely, 

five) of improperly generated batches per year and is finalizing regulations to that effect in 

80.1431(c)(6). By limiting the number of times a RIN generator may utilize the flexibility to 

retire equivalent RINs, the regulations will encourage RIN generators to implement robust 

measures and controls to prevent errors from occurring, knowing that the flexibility is only 

available to them for five batches each compliance year. Additionally, limiting the number of 

batches to which this flexibility can be applied restricts the ability of RIN generators that might 

otherwise intentionally generate invalid RINs to take advantage of short term RIN price spikes. 

Finally, EPA is finalizing a provision informing the regulated community that EPA 

intends to publicly post information concerning RIN generators utilizing this flexibility in 

80.1431(c)(7)(B). By posting this information, EPA is assisting obligated and other regulated 
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parties in their due diligence to ensure compliance with all RFS2 regulations. EPA believes that 

posting information concerning the use of this flexibility will incentivize proper RIN generation 

in the future. 

Further, EPA may remove improperly generated RINs from EMTS if the RIN generator 

has failed to properly meet the remedial action requirements stated in the regulations, as 

specified in 80.1431(d). EPA believes this will prevent invalid RINs that do not meet the 

requirements in 80.1431(c) from propagating through the market and being used for compliance 

purposes, thus preventing additional violations. While EPA is aware that the proposal did not 

include the ability to remove improperly generated RINs, EPA believes this ability is a logical 

outgrowth from the comments that EPA should spend more time investigating egregious 

violations. This provision will allow EPA to quickly remove from the market those RINs 

reported by the RIN generator to be invalid due to reasons in 80.1431(c)(2), thus affording EPA 

more time to spend investigating egregious violations. 

 Finally, a number of commenters noted that good faith purchasers and the ultimate users 

of the RINs, the obligated parties, should not be subject to a violation for unwittingly buying 

and/or retiring invalid RINs for compliance. EPA disagrees, and believes that the “buyer 

beware” aspect of the RIN trading program is one of the cornerstones of the program. It provides 

an important incentive for the regulated community to comply with the regulations and mandates 

due diligence on the part of all RIN buyers. It encourages self-policing on the part of RIN 

generators, owners and users in order to keep the program functioning smoothly. EPA is not 

making any changes to the liability sections of RFS2 as a result of these comments and although 

today’s rule will allow obligated parties to use some invalid RINs for compliance, the obligated 

parties and any intermediary party are still liable for buying and/or transferring invalid RINs. 

3. Production Outlook Reports Submission Deadline

 In the final RFS2 regulations, in §80.1449(a), EPA set the annual deadline for submitting 

Production Outlook Reports as March 31 of each year. However, EPA has determined that, in 

order for the information contained in the Production Outlook Reports to be most useful when 

setting the RFS2 volume requirements and associated percentage standards for the following 

calendar year, the reports should contain the most accurate projections possible. Since the 

accuracy of projections tends to increase the closer those projections are made to the following 

calendar year, we proposed that the March 31 deadline should be moved to June 1. This revised 

deadline would still allow the information contained in the Production Outlook Reports to be 

used in the development of the final rulemaking setting the standards for the following year. 

 We received one comment on the proposed Production Outlook Reports deadline of June 

1 that suggested August 31, or as late as possible that still ensures the information is useful in the 

development of the final RFS standards for the following year. EPA believes, however, that if 

the deadline is set later in the year, there would be insufficient opportunity for EPA to quality 

check the incoming data prior to incorporating it into the analysis for developing the RFS2 

volume requirements and associate percentage standards for the following calendar year. EPA 
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strives to make the most accurate projections possible, so without time to check the data quality, 

there could be inaccuracies in the volume requirements that lead to market disruption. 

Another commenter suggested that having the Production Outlook Reports deadline 

immediately after the May 31 attest engagement deadline would place a significant burden on 

regulated parties at that time, and suggests a deadline of June 30 for the Production Outlook 

Reports. EPA believes that it is not a significant burden for regulated parties to submit the 

Production Outlook Report at the same time as the attest engagement report, especially 

considering the attest audit and report are typically conducted by independent third-party 

auditors, rather than the regulated parties themselves. 

 For the reasons stated above, EPA believes that the proposed June 1 deadline for 

Production Outlook Reports is reasonable and should not be moved to later in the year. 

Therefore, EPA is finalizing the June 1 deadline for Production Outlook Reports. 

 

4. Attest Procedures 

 In the final RFS2 regulations, EPA required in §80.1464(c)(1)(i) and (c)(2)(ii) that RIN 

owners conduct attest procedures for RIN transaction and RIN activity reports that involve RIN 

separations. This requirement was intended to be included in the attest procedures for obligated 

parties and exporters as well as for renewable fuel producers and RIN-generating importers, in 

order to confirm that RINs are being properly separated by all parties participating in the RIN 

market. Thus, we proposed amendments to §80.1464(a)(2)(i) and (a)(3)(ii) for obligated parties 

and exporters as well as to §80.1464(b)(2)(i) and (3)(ii) for renewable fuel producers and RINgenerating importers to include attest procedures concerning verification of RIN separation. 

 

Additionally, in the final RFS2 regulations, EPA required in §80.1464 that auditors of 

RIN generation reports verify that product transfer documents (PTDs) include the required 

information. EPA believes it would be beneficial for auditors to verify the required information 

is present on PTDs for RIN transactions for all parties, including obligated parties, renewable 

fuel producers and importers and RIN owners. Thus, we proposed amendments to 

§80.1464(a)(2), (b)(2) and (c)(1) to require auditors to verify that the PTDs for a representative 

sample of RINs sold and purchased contains the information required in §80.1453. 

We received one comment that stated that the attestation procedures should be 

comparable for all reporting activities of all regulated parties. EPA believes, however, that the 

proposed regulatory changes to the attest engagement procedures apply consistently to all 

regulated parties in that all parties are responsible for ensuring that RINs that they separate, 

purchase or use for compliance have been properly separated and that they have associated PTDs 

with all of the required information. Another commenter states that obligated parties should not 

be required to audit RIN separation activities in addition to RIN purchases. Again, EPA feels 

this additional check on RIN separation activities will ensure that the RINs are properly 

separated and that renewable fuel is actually being blended for use as transportation fuel, heating 

oil or jet fuel. Therefore, EPA is finalizing the amendments to the attest engagement procedures 

as proposed. 
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5. Treatment of Canola and Rapeseed

 On September 28, 2010, EPA published a “Supplemental Determination for Renewable 

Fuels Produced Under the Final RFS2 Program from Canola Oil” (FR Vol. 75, No. 187, pg 

59622-59634). In the NPRM we proposed to clarify two aspects of the supplemental 

determination. First we proposed to amend the regulatory language in Table 1 to §80.1426 to 

clarify that the currently-approved pathway for canola also applies more generally to rapeseed. 

While “canola” was specifically described as the feedstock evaluated in the supplemental 

determination, we had not intended the supplemental determination to cover just those varieties 

or sources of rapeseed that are identified as canola, but to all rapeseed. As described in the 

NPRM, we currently interpret the reference to “canola” in Table 1 to §80.1426 to include any 

rapeseed. To eliminate ambiguity caused by the current language, however, we proposed to 

replace the term “canola” in that table with the term “canola/rapeseed”. Canola is a type of 

rapeseed. While the term “canola” is often used in the American continent and in Australia, the 

term “rapeseed” is often used in Europe and other countries to describe the same crop. We 

received no adverse comments on our proposal, and thus are finalizing it as proposed. This 

change will enhance the clarity of the regulations regarding the feedstocks that qualify under the 

approved canola biodiesel pathway. 

Second, we wish to clarify that although the GHG emissions of producing fuels from 

canola feedstock grown in the U.S. and Canada was specifically modeled as the most likely 

source of canola (or rapeseed) oil used for biodiesel produced for sale and use in the U.S., we 

also intended that the approved pathway cover canola/rapeseed oil from other countries, and we 

interpret our regulations in that manner. We expect the vast majority of biodiesel used in the 

U.S. and produced from canola/rapeseed oil will come from U.S. and Canadian crops. Incidental 

amounts from crops produced in other nations will not impact our average GHG emissions for 

two reasons. First, our analyses considered world-wide impacts and thus considered 

canola/rapeseed crop production in other countries. Second, other countries most likely to be 

exporting canola/rapeseed or biodiesel product from canola/rapeseed are likely to be major 

producers which typically use similar cultivars and farming techniques. Therefore, GHG 

emissions from producing biodiesel with canola/rapeseed grown in other countries should be 

very similar to the GHG emissions we modeled for Canadian and U.S. canola, though they could 

be slightly (and insignificantly) higher or lower. At any rate, even if there were unexpected 

larger differences, EPA believes the small amounts of feedstock or fuel potentially coming from 

other countries will not impact our threshold analysis. Therefore, EPA interprets the approved 

canola pathway as covering canola/rapeseed regardless of country origin. 

E. Technical Amendments Related to Registration & Recordkeeping 

1. Construction Discontinuance & Completion Documentation 

The registration requirements in §80.1450(b)(1)(vi) state that for facilities claiming the 

exemption described in §80.1403(c) or (d), evidence must be submitted demonstrating the date 
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that construction commenced. However, the registration requirements do not explicitly require 

the submission of evidence demonstrating that they meet the other requirements described in 

§80.1403(c)(1) and (2) or (d)(1), (2) and (3). 

 

In order to verify that facilities which claim to qualify for an exemption under 

§80.1403(c) or (d) in fact meet all of the qualification requirements for such an exemption, we 

proposed to amend §80.1450(b)(1)(vi) to include requirements that the owner or operator of 

facilities claiming exemption under §80.1403(c) submit evidence demonstrating that construction 

was not discontinued for a period of 18 months after construction began, and that construction 

was completed by December 19, 2010. Similarly, we proposed that for facilities claiming the 

exemption under §80.1403(d), evidence be submitted demonstrating that construction was not 

discontinued for a period of 18 months after construction began and that construction was 

completed within 36 months of the commenced construction date . 

We received comments that EPA should not adopt these proposed amendments because 

the requirements would be overly burdensome and unnecessary due to the fact that the majority 

of all facilities that have claimed the exemption under §80.1403 have already been registered and 

therefore these amended requirements would have no effect on these facility’s registration. 

Secondly, the commenter stated that the proposed requirement to submit evidence that 

construction was not discontinued for a period of 18 months is unreasonable because it is unclear 

how a facility could prove a lack of construction activity. Thirdly, the commenter stated that the 

proposed amendment to submit evidence that construction was timely completed was 

unnecessary because a facility’s operation activity such as production of fuel was enough to 

serve as evidence that construction was completed. The commenter suggested that EPA only 

request evidence to demonstrate that these requirements are met from facilities that EPA believes 

did not rightly claim the exemption under §80.1403. 

In order to fully assess the concerns raised by the commenters, EPA has decided to 

investigate this issue in more detail and analyze some additional options. Therefore, at this time, 

EPA is not taking final action with respect to this proposed amendment. 

2. Third-Party Engineering Reviews

 The regulations stipulate that producers of renewable fuels and foreign ethanol producers 

are required to update their registration information, and submit an updated independent thirdparty engineering review, every 3 years after their initial registration in accordance with 

§80.1450(d)(3). We have received many inquiries regarding the start date that EPA uses to 

determine the 3 year period after which the producer must submit an updated independent third 

party engineering review (such as the registration acceptance date, the third-party professional 

engineer’s signature date on the engineering review report, or the due date for engineering 

reviews. 

 Given the lack of clarity in the current regulations, we proposed amendments to specify 

the time frame for submission of updated independent third-party engineering reviews which 
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included a simplified method that would group producers according to the calendar year they 

were or will be registered, and set a fixed time frame for registration updates for each group. We 

proposed to amend §80.1450(d)(3) to stipulate that for all producers of renewable fuel and 

foreign ethanol producers for which registration was accepted by EPA in calendar year 2010, 

that the updated registration information and independent third-party engineering review would 

be submitted to EPA within the three months prior to January 1, 2014, and within three months 

prior to January 1 of every third calendar year thereafter. For all producers of renewable fuel and 

foreign ethanol producers registered in any calendar year after 2010, the updated registration 

information and independent third-party engineering review would be submitted to EPA within 

three months prior to January 1 of every third calendar year after the first year the producer’s 

registration was accepted by EPA. For example, a producer registered in 2011 would be 

required to submit an updated independent third-party engineering review by January 1, 2015, 

and by January 1 every three calendar years thereafter. 

 We received comments that supported the adoption of the proposed amendments for a 

simplified method of grouping producers according to the calendar year that they were or will be 

registered to determine the due date for submission of the updated registration information and 

independent third-party engineering review. The commenter suggested that we provide a clear 

method to determine the due date for individual facilities to further help with the compliance of 

this requirement. We agree with the commenter that providing more clarity and guidance would 

help facilities comply with this requirement. Therefore, in the near future and well before the 

due date for any updated engineering reviews, we plan to compile and publish a guidance 

document that will provide the date in which each facility’s registration was accepted, the 

calendar year in which each facility will be grouped, and the corresponding triennial due dates 

for the updated engineering review for each calendar year group. This guidance document will 

be published on the RFS public website. Parties must also comply with all other applicable 

requirements in 40 CFR Part 80, Subpart M. This guidance does not, in any way, alter the 

requirements of the renewable fuel program regulations, and does not establish or change legal 

rights or obligations.

In addition, we are removing from the final rule the proposed 3 months allowance period 

prior to triennial due date. The reason we included a 3 months allowance was to ensure that the 

updated engineering reviews were not submitted so early as to not provide appropriately updated 

information as of the three-year submission deadline. We believed at the time of the proposal 

that the inclusion of the 3 month window would ensure that facilities conduct their engineering 

review closer to the end of the 3 year period, which we assumed would provide the most up-todate information. However, now we believe that the inclusion of this 3 month period is 

unnecessary since the owners or operators of a facility can determine for themselves when it is 

appropriate to coordinate and conduct the engineering review for their facility and that the 

regulatory requirement for “up-dated” engineering reviews provide sufficient clarity that the 

information submitted to EPA must reflect the up-to-date information 

 Therefore, we are finalizing in this rulemaking the proposed simplified method to group 

facilities based on the calendar year in which their facility’s registration was accepted by EPA 

with the due date for the updated registration and independent third party engineering review to 

be submitted to EPA by January 31st of every 3 calendar years, starting from the acceptance date 
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of the facility’s initial registration. We are allowing the engineering reviews to be submitted at 

the end of January due to possible scheduling concerns during the holiday season. 

3. Foreign Ethanol Producers

We proposed that the amendments to the registration requirements in §80.1450 also apply 

to foreign ethanol producers. As defined in §80.1401, foreign ethanol producers are foreign 

producers that produce ethanol for use in transportation fuel, heating oil or jet fuel but who do 

not add denaturant to their product. Therefore, foreign ethanol producers do not technically 

produce ‘‘renewable fuel’’ as defined in our regulations. As discussed in the preamble to the 

Direct Final Rule published on May 1, 2010 (see 75 FR 26032), the result of the amendments 

made in the Direct Final Rule is to require foreign ethanol facilities that produce ethanol that 

ultimately becomes part of a renewable fuel for which RINs are generated to provide EPA the 

same registration information as foreign renewable fuel facilities that export their product to the 

United States. In both cases the required registration information is important for enforcement 

purposes, including verifying the use of renewable biomass as feedstock and the assignment of 

appropriate D codes. Therefore, we believe amendments to the registration requirements that we 

make in this final rule should also be applicable to foreign ethanol producers for the same 

reasons. We did not receive comments on this proposed change, so we are finalizing the 

amendment as proposed. 

F. Additional Amendments and Clarifications 

 

1. Third-Party Engineering Review Addendum

We have received many inquires as to whether an addendum to the existing independent 

third-party engineering review is sufficient to meet the requirement that all producers of 

renewable fuel and foreign ethanol producers submit an updated independent third-party 

engineering review if they make changes to their facility that will qualify the renewable fuel that 

is produced for a renewable fuel category or D code that is not already reflected in the producer’s 

registration information. In some circumstances the majority of the information verified in the 

existing independent third-party engineering review would remain the same, and duplicating the 

entire effort does not appear necessary. We believe the concept of allowing the submission of an 

addendum in lieu of a updated independent third-party engineering review is reasonable and 

therefore we are finalizing to amend the requirements in §80.1450(d)(1) to state that a producer 

of renewable fuel or foreign ethanol producer may submit an addendum to the existing 

independent third-party engineering review on file with EPA provided the addendum meets all 

the requirements in §80.1450(b)(2) and verifies for EPA the most up-to-date information at the 

producer’s existing facility. The updated independent third-party engineering review or 

addendum shall be submitted at least 60 days prior to producing the new type of renewable fuel 

and must meet all the same requirements stipulated in §80.1450(b)(2) for the independent thirdparty engineering review, including a new site visit conducted by the third-party to verify any 

changes to the facility that allows it to produce a different renewable fuel that is not currently 

reflected in their registration on file with EPA. 
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 2. RIN Generation for Fuel Imported from a Registered Foreign Producer

 In RFS2, EPA finalized provisions allowing importers to generate RINs for renewable 

fuel imported from a foreign producer only under certain circumstances. The importer may only 

generate RINs for fuel imported from a foreign renewable fuel producer or foreign ethanol 

producer if that producer is registered with EPA and has received EPA company and facility 

identification numbers pursuant to §80.1450. Pursuant to §80.1426(c)(4), the importer is 

prohibited from generating RINs for fuel imported from a foreign producer that is not registered 

with EPA. In the proposed rulemaking, EPA proposed to clarify that when an importer is 

generating RINs for fuel imported from a registered foreign renewable fuel producer or foreign 

ethanol producer, the importer must submit to EPA via EMTS the importer’s company 

identification number, the facility identification number of the import facility where the batch 

was imported, and the facility identification number for the foreign renewable fuel or ethanol 

producer that produced the batch of fuel for which the importer is generating RINs. EPA did not 

receive comments on these clarifications, and is therefore finalizing them as proposed in 

§§80.1452(b)(4) and (5). 

 3. Bond Posting

 We proposed to amend paragraphs (e)(1), (e)(2) and (g)(2) of §80.1467 to make them 

consistent with §80.1467(g)(1). These proposed amendments were intended to clarify that the 

amount of the posted bond must cover the number of gallon RINs that are sold and/or 

transferred, and also those RINs held and/or obtained by the foreign entity, including those held 

and/or obtained to comply with a foreign importer's RVO requirements. We also proposed to 

amend §§80.1465-80.1467 by striking §§80.1465(h)(2)(iii), 80.1466(h)(2)(iii) and 

80.1467(e)(2)(iii), which allowed entities to make alternative commitments in lieu of posting 

bonds. EPA believes that this method is vague, unnecessary, and unenforceable. 

 

 One commenter at the hearing is against the removal of the regulation allowing foreign 

producers to make alternative commitments as it may discourage foreign renewable fuel 

producers from entering the U.S. market. EPA disagrees as no foreign producer has used an 

alternative commitment to date, and most foreign renewable fuel producers do not post bonds 

and instead rely on the renewable fuel importers to generate RINs for renewable fuel that is 

imported. For those reasons and the reasons described above, we are finalizing the proposed 

changes to the bond posting regulations as proposed. 

 4. Prohibition Against Repeat Generation of RINs

 We are finalizing our proposal to add a new paragraph (b)(6) to the prohibited acts of 

§80.1460 to specify in this section of the regulations that RINs may not be generated for any fuel 

for which RINs have previously been generated. Pursuant to §80.1401, a RIN is a unique 

number generated to represent a volume of renewable fuel. If more than one RIN is generated 
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for a particular volume, the RIN will no longer be unique, and is therefore improperly generated 

and cannot be used to demonstrate compliance with the renewable volume obligations. While 

generating RINs for a particular volume of fuel for which RINs have already been generated is 

already prohibited, we are amending the regulations to include this prohibition in § 80.1460 for 

clarity. 

 5. Acceptance of Separated Yard Waste and Food Waste Separation Plans

We proposed to amend §80.1426(f)(5)(ii)(A) to remove the requirement that the 

separated yard waste plan and separated food waste plan must be approved by EPA, and instead 

only require that these two plans be submitted and accepted by EPA under the registration 

procedures specified in §80.1450(b)(1)(vii). The details and information required to be submitted 

in the separated yard waste plan and separated food waste plan are not overly burdensome or 

complex, and therefore we believe it does not warrant a specific EPA approval, but that EPA 

acceptance of these plans through the registration procedures is sufficient. 

We received comments that supported the adoption of this amendment for separated food 

waste plan and separated yard waste plan. We also received comments suggesting that we also 

adopt this amendment for the separated MSW plan. The commenter stated that although the 

separated MSW plan requires somewhat more information than the separated yard and food 

waste plans, the same logic applies in that the separated MSW plan will also be subject to EPA 

review as part of the producer’s registration process and therefore requiring a separate duplicate 

approval for the separated MSW plan is not necessary. 

First, we would like to clarify that there is not a duplicate approval process for the 

separated MSW plan that serves as a separate additional requirement for the producer’s 

registration. Similar to the proposed acceptance process for the producer’s separated yard and 

food waste plan, the approval process for the producer’s separated MSW plan will equally serve 

as verification of compliance as part of the producer’s registration. Secondly, we disagree with 

the commenter that the separated MSW plan only requires somewhat more information than the 

separated yard and food waste plans, and that the same logic applies in terms of the review 

process. For the separated MSW plan, producers are required to provide ongoing verification 

that there is separation of recyclable paper, cardboard, plastics, rubber, textiles, metals, and glass 

wastes to the extent reasonably practicable, including: the extent and nature of the recycling that 

occurred prior to receipt of the waste material, identification of available recycling technology 

and practices that are appropriate for removing recycling materials from the waste stream, and 

identification of the technology or practices selected for implementation, including an 

explanation for such selection, and reasons why other technologies or practices were not 

implemented. In addition, producers are also required to provide contracts relevant to materials 

recycled from municipal waste streams and certification that recycling is conducted in a manner 

consistent with goals and requirements of applicable State and local laws relating to recycling 

and waste management as part of their registration process. For the separated yard and food 

waste plan, the producers are only required to provide ongoing verification that the separated 

yard waste or food waste was kept separate since generation from other waste materials, and for 

food waste, contain only incidental amounts of other components. We believe the information 
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submitted in the separated MSW plan will be considerably more complex than information 

submitted in the separated yard and food waste plans, and therefore, will require EPA conduct a 

much more comprehensive review and also consider many additional factors to ensure that the 

producer has met the all the requirements stipulated. Based on the factors discussed, we believe 

that it is not reasonable to apply the same proposed acceptance process for separated yard and 

food waste plan to the separated MSW plan. 

Therefore, we are finalizing in this rulemaking only for separated yard waste plan and 

separated food waste plan to amend the requirement that the plans must be approved by EPA, 

and instead only require that the plans will be accepted by EPA under the registration procedures 

specified in §80.1450(b)(1)(vii). 

 6. Transferred Blendstocks in Early Benzene Credit Generation Calculations

Today’s rule also finalizes one minor correction to the gasoline benzene regulations 

which would clarify how refiners should account for transferred blendstocks in their early 

benzene credit generation calculations. Under current rules, refineries which generated early 

benzene credits are required to reduce gasoline benzene during an early credit generation period 

by at least 10% compared to the refinery’s benzene baseline, and are also required to make 

specific operational changes and/or improvements in benzene control technology to reduce 

gasoline benzene levels.91 Refineries which reduce their gasoline benzene by at least 10%, in 

part by transferring reformate to another refinery, could also generate early benzene credits, 

provided the transferee refinery treated the reformate in specific benzene-reduction processing 

units.92 See 72 FR 8486-87 (Feb. 26, 2007). However, the gasoline benzene regulations also 

contain an additional provision that requires all blendstock streams transferred to, from or 

between refineries to be excluded from a refinery’s early credit generation calculations (except 

for reformate as described previously). This led to an inconsistent comparison of a refinery’s 

benzene during an early credit generation period with a refinery’s benzene baseline (which 

included blendstocks transferred to the refinery), which was not EPA’s intent. 

As described in the preamble of the gasoline benzene final rule, EPA intended that 

refineries not be allowed to generate early benzene credits exclusively through blendstock 

trading, without making any other qualifying reductions (see 72 FR 8487), but that refineries 

could generate early benzene credits in part through qualifying reductions and “in part” through 

other means such as blendstock transfers (see 72 FR 8496-97). However, the current regulations 

do not allow this approach, and this inconsistency has caused confusion among refiners about 

how to calculate the amount of early credits generated. Refiners have generally followed the 

approach set out in the preamble (as EPA in fact intended), and included all blendstocks 

transferred to a refinery in the refinery’s early credit generation calculations. Refiners typically 

 

91 Early credit generation periods were July 1, 2007 through December 31, 2007, and calendar years 2008, 2009 and 

2010. 

92 Refineries produce gasoline by combining several different blendstocks produced by various refinery processing 

units. Reformate is a blendstock which contains approximately 80% of all benzene found in gasoline, per the 

MSAT2 regulatory impact analysis. 
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keep records on transferred blendstocks for 1-2 years, and thus do not have sufficient data to 

exclude transferred blendstocks from their early credit generation calculations. 

EPA recently became aware of this inconsistency and is amending the regulations to 

make them consistent with EPA’s intent as described in the preamble. This rule amends the 

gasoline benzene regulations at 40 CFR 80.1275(d)(3) by deleting that provision. This will 

allow a refinery to include blendstocks transferred to the refinery in the refinery’s early benzene 

credit generation calculations (all other conditions, including treatment which removes benzene 

in transferred reformate streams still applying, of course). Consistent with EPA’s original intent, 

today’s rule also allows a refinery to include transferred blendstocks in past early credit 

generation calculations, provided the refinery met all of the other requirements for generating 

early benzene credits. EPA is finalizing this change to include transferred blendstocks in past 

early credit generation calculation not only because this was EPA’s intent at the time of the 

benzene gasoline rulemaking, but because some refiners have reasonably relied upon that stated 

intent in devising their compliance strategies. 

 All of the comments received on this change to the regulations were in support of this 

change. Commenters generally noted that the change was needed in order to align the language 

in the regulations with the intent stated in the preamble.
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VI. Annual Administrative Announcements 

 In the RFS2 final rule, we stated our intent to make two announcements each year: 

• Set the price for cellulosic biofuel waiver credits that will be made available to 

obligated parties in the event that we reduce the volume of cellulosic biofuel 

below the applicable volume specified in the Clean Air Act (CAA), and 

• Announce the results of our annual assessment of the aggregate compliance 

approach for U.S. planted crops and crop residue. 

The biofuel waiver credit price being announced today was calculated in accordance with the 

specifications in §80.1456(d). Since the manner in which EPA calculates the waiver credit price 

is precisely set forth in EPA regulations (which were issued through a notice-and-comment 

process), and since some of the variables necessary to compute the price have only recently 

become available, EPA did not propose a waiver credit price for comment. Similarly, because 

EPA’s assessment of the aggregate compliance approach announced today was conducted using 

data sources, methodology, and criteria that were identified and explained in the preamble to the 

RFS2 final rule, it was not necessary to present a preliminary annual assessment for comment in 

the NPRM. 

A. 2011 Price for Cellulosic Biofuel Waiver Credits 

Section 211(o)(7)(D) of the CAA requires that whenever EPA sets the applicable volume 

of cellulosic biofuel at a level lower than that specified in the Act, EPA is to provide a number of 

cellulosic credits for sale that is no more than the EPA-determined applicable volume. Congress 

also specified the formula for calculating the price for such waiver credits: adjusted for inflation, 

the credits must be offered at the price of the higher of 25 cents per gallon or the amount by 

which $3.00 per gallon exceeds the average wholesale price of a gallon of gasoline in the United 

States.93 The inflation adjustment is for years after 2008. EPA regulations provide that the 

inflation adjustment is calculated by comparing the most recent Consumer Price Index for Al 

Urban Consumers (CPI-U) for the “All Items” expenditure category as provided by the Bureau 

of Labor Statistics that is available at the time EPA sets the cellulosic biofuel standard to the 

comparable value that was reported soonest after December 31, 2008.94 

In contrast to its directions to EPA for setting the price of a cellulosic biofuel waiver 

credit, Congress afforded the Agency considerable flexibility in designing regulations specifying 

 

93 More information on wholesale gasoline prices can be found on the Department of Energy's (DOE), Energy 

Information Administration's (EIA) Web site at: 

http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=EMA_EPM0_PBR_NUS_DPG&f=M

94 See U.S. Department of Labor, Bureau of Labor Statistics (BLS), Consumer Price Index Web site at: 

http://www.bls.gov/cpi/ 
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the permissible uses of the credits. The CAA states that EPA regulations “shall include such 

provisions, including limiting the credits’ uses and useful life, as the Administrator deems 

appropriate to assist market liquidity and transparency, to provide appropriate certainty for 

regulated entities and renewable fuel producers, and to limit any potential misuse of cellulosic 

biofuel credits to reduce the use of other renewable fuels, and for such other purposes as the 

Administrator determines will help achieve the goals of this subsection.” The final RFS2 

provides a detailed discussion of how we designed the provisions for cellulosic biofuel waiver 

credits in keeping with the statutory language. In short, 2012 cellulosic biofuel waiver credits 

(or ”waiver credits”) are only available for the 2012 compliance year. Waiver credits will only 

be made available to obligated parties, and they are nontransferable and nonrefundable. Further, 

obligated parties may only purchase waiver credits up to the level of their cellulosic biofuel RVO 

less the number of cellulosic biofuel RINs that they own. A company owning cellulosic biofuel 

RINs and cellulosic waiver credits may use both types of credits if desired to meet their RVOs, 

but unlike RINs obligated parties are not permitted to carry waiver credits over to the next 

calendar year. Obligated parties may not use waiver credits to meet a prior year deficit 

obligation. Finally, unlike cellulosic biofuel RINs which may also be used to meet an obligated 

party's advanced and total renewable fuel obligations, waiver credits may only be used to meet a 

cellulosic biofuel RVO. An obligated party will still need to additionally and separately acquire 

RINs to meet their advanced biofuel and total renewable fuel obligations. 

For the 2012 compliance period, since the applicable volume of cellulosic biofuel used to 

set the annual cellulosic biofuel standard is lower than the volume for 2012 specified in the 

CAA, we are making cellulosic waiver credits available to obligated parties for end-of-year 

compliance should they need them at a price of $0.78 per credit. To calculate this price, EPA 

first determined the average wholesale (refinery gate) price of gasoline using the most recent 12 

months of data available from the EIA website on September 30, 2011. Based on this data, we 

calculated an average price of gasoline for the period July 2010 to June 2011 of $2.44. In 

accordance with the Act, we then calculated the difference of the inflation-adjusted value of 

$3.00, or $3.22, and $2.44, which yielded $0.78. Next, we compared the value of $0.78 to the 

inflation-adjusted value of $0.25, or $0.27. The Act requires EPA to use the greater of these two 

values as the price for cellulosic biofuel waiver credits. 

The derivation of this value is more fully explained in a memorandum submitted to the 

docket for this rulemaking,95 and a more complete description of the statutory requirements and 

their application can be found in the RFS2 final rule.96 The price for the 2013 compliance 

period, if necessary, will be set when we announce the 2013 cellulosic biofuel standard. 

B. Assessment of the Domestic Aggregate Compliance Approach 

The RFS2 regulations contain a provision for renewable fuel producers who use planted 

crops and crop residue from U.S. agricultural land that relieves them of the individual 

recordkeeping and reporting requirements concerning the specific land from which their 

 

95 See memo to docket number EPA-HQ-OAR-2011-XXX from Scott Christian, on the subject of “Calculating the 

price for cellulosic biofuel waiver credits,” dated October XX, 2011. 

96 75 FR 14726 - 14728 
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feedstocks were harvested. To enable this approach, EPA established a baseline number of acres 

for U.S. agricultural land in 2007 (the year of EISA enactment) and determined that as long as 

this baseline number of acres was not exceeded, it was unlikely that new land outside of the 2007 

baseline would be devoted to crop production based on historical trends and economic 

considerations. We therefore provided that renewable fuel producers using planted crops or crop 

residue from the U.S. as feedstock in renewable fuel production need not comply with the 

individual recordkeeping and reporting requirements related to documenting that their feedstocks 

are renewable biomass, unless EPA determines through annual evaluations that the 2007 baseline 

acreage of agricultural land has been exceeded. 

In the final RFS2 regulations, EPA committed to make an annual finding concerning 

whether the 2007 baseline amount of U.S. agricultural land has been exceeded in a given year 

and publish this finding in the Federal Register by November 30 of the same year. If the 

baseline is found to have been exceeded, then producers using U.S. planted crops and crop 

residue as feedstocks for renewable fuel production would be required to comply with individual 

recordkeeping and reporting requirements to verify that their feedstocks are renewable biomass. 

Based on data provided by the USDA Farm Service Agency (FSA) and Natural 

Resources Conservation Service (NRCS), we have estimated that U.S. agricultural land reached 

approximately 396 million acres in 2011, and thus did not exceed the 2007 baseline acreage. 

This acreage estimate is based on the same methodology used to set the 2007 baseline acreage 

for U.S. agricultural land in the RFS2 final rulemaking. Specifically, we started with FSA crop 

history data for 2011, from which we derived a total estimated acreage of 396million acres. We 

then subtracted the amount of land estimated to be participating in the GRP and WRP by the end 

of Fiscal Year 2011, XX million acres, to yield an estimate of approximately XX million acres of 

U.S. agricultural land in 2011. The USDA data used to make this calculation can be found in the 

docket to this rule. 
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VII. Comments Outside the Scope of This Rulemaking 

 In their comments responding to the NPRM, a number of parties used the opportunity to 

raise concerns that were not directly related to the issues and provisions we were addressing in 

the NPRM, such as the proposed standards for 2012, the applicable volume of biomass-based 

diesel for 2013, and the various proposed changes to the regulations designed to clarify intent 

and streamline implementation. Neither did these comments address setting the price for 

cellulosic biofuel credits or EPA’s annual evaluation of the U.S. aggregate compliance approach 

for renewable biomass. In some cases, commenters requested EPA action in some other area, 

such as the following: 

• Request for EPA to implement a more robust biofuel quality assurance program 

• Request for EPA to prohibit increases in biomass-based diesel above 1.0 billion 

gallons in 2013 

• Request for EPA to mandate that 50% of all vehicles be E100 capable by 2017 

• Request for EPA to encourage legislation that allows corn ethanol to be 

categorized as advanced biofuel 

• Request for EPA to pursue changes to the statute that would make valid 

renewable fuels feedstock-neutral 

In other cases, commenters raised issues related to other areas not addressed in our NPRM, such 

as the following: 

• Other state and federal fuel regulations 

• Retail dispensing requirements and misfueling of E15 in non-flexible fueled 

vehicles 

• Need for continuing federal incentives for biofuels, such as tax subsidies 

• Relative energy security implications of imported petroleum versus imported 

biofuels 

• Delayed RINs 

• Definition of heating oil 

While we are taking these comments under consideration as we continue to implement the RFS2 

program, these comments are outside the scope of today’s action. In some cases, they are also 

outside our authority. Thus, we are not providing substantive responses to them at this time. 
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 One commenter provided a copy of a copyrighted report, "Energy Life-Cycle Assessment 

Of Soybean Biodiesel Revisited". Similarly, both Monsanto and RFA provided comments on the 

lifecycle GHG impacts of corn ethanol, indicating that it should be a higher GHG reduction than 

what was calculated by EPA as part of the RFS2 final rule and that we should reevaluate corn 

ethanol lifecycle emissions based on new studies that are available. We will consider the 

information and analyses provided as part of any future updates to our lifecycle evaluations of 

these biofuels. 

 Another commenter urged EPA to quickly certify additional feedstocks for cellulosic 

biofuels under the RFS. We are moving forward responding to a series of petitions requesting 

EPA approval of other pathways, including both feedstock-specific pathways (e.g., palm oil and 

sorghum) and company- or process-specific pathways. A discussion of the process involved and 

a list of the current pathways we are currently evaluating can be found at: 

http://www.epa.gov/otaq/fuels/renewablefuels/compliancehelp/rfs2-lca-pathways.htm 

We appreciate that multiple stakeholders are highly interested in the timeline on which 

EPA is conducting these analyses. We note that the analysis required for the RFS fuel pathway 

determinations as required under CAA 211(o) are comprehensive in nature, and EPA is 

committed to ensuring they are conducted in an appropriately rigorous fashion. 

Some commenters noted that regulated parties are having difficulty complying with the 

requirement that the RIN transfer date in EMTS and on product transfer documents (PTDs) be 

the actual title transfer date. Some of these commenters requested EPA enforcement discretion 

to allow biofuel producers and first purchasers to update their electronic systems in order to be in 

compliance with the title transfer date regulatory requirement. Two commenters specified that 

this enforcement discretion should be issued for six months in order to provide these companies 

with sufficient time to update their systems. EPA believes that the proposed enforcement 

discretion would likely introduce confusion for anyone who attempts to review and match 

transactions with records.

In contrast, several commenters requested that EPA reconsider its position that the RIN 

transfer date reported to EMTS and identified on PTDs must be the actual title transfer date. One 

commenter requested that EPA allow invoice dates to be used in lieu of title transfer dates as title 

transfer does not usually coincide with customer payments and ultimately place a burden on the 

selling company’s cash flow. While we understand that some parties would prefer to use a date 

other than the true title transfer date for purposes of EMTS reporting and PTDs, we believe this 

would violate the clear language and intent of the regulations.

 One commenter requested that EPA provide adjustment mechanisms to allow corrections 

in EMTS after noting that EMTS is a “forward looking” system, meaning that EMTS 

transactions cannot be modified once submitted. EPA is looking at several ways and has updated 

the RFS2 remedial action webpage since the comment period closed. EPA will continually 

update its guidance for regulated parties to correct violations that true mistakes on the following 

webpage: 
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http://www.epa.gov/otaq/fuels/renewablefuels/compliancehelp/rfs2remedialactions.htm

Additionally, in this final rule, EPA is finalizing a regulation amendment giving EPA discretion 

to allow invalidly generated RINs to be used for compliance purposes on a case-by-case basis 

(Please see Section V of the preamble). 

 Several commenters requested that EPA edit Q&As 7.8 and 10.6 as they conflict with the 

regulations. EPA will review and make edits to the RFS2 Q&As in order to ensure agreement 

with the regulations as appropriate at a later date. 
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VIII. Public Participation 

 Many interested parties participated in the rulemaking process that culminates with this 

final rule. This process provided opportunity for submitting written public comments following 

the proposal that we published on July 1, 2011 (76 FR 38844), and we considered these 

comments in developing the final rule. Comments and responses for issues raised in the public 

comments are included throughout this preamble. 
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IX. 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. Accordingly, EPA 

submitted this action to the Office of Management and Budget (OMB) for review under 

Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in 

response to OMB recommendations have been documented in the docket for this action. 

 The economic impacts of the RFS2 program on regulated parties, including the impacts 

of the required volumes of renewable fuel, were already addressed in the RFS2 final rule 

promulgated on March 26, 2010 (75 FR 14670). This action finalizes the percentage standards 

applicable in 2012 based on the volumes that were analyzed in the RFS2 final rule. This action 

is also finalizing technical amendments to the RFS2 regulations that have been determined to 

have no adverse economic impact on regulated parties since they generally clarify existing 

requirements. 

B. Paperwork Reduction Act 

 This action does not impose any new information collection burden. While there are 

three regulatory amendments in today's rule that affect the recordkeeping and reporting burdens 

for regulated parties, we believe that the information collections already approved for the RFS2 

program's general recordkeeping and reporting requirements, or the information collection 

already under review, would also cover the these technical amendments. 

 The regulatory changes are listed in Table IX.B-1. 

Table IX.B-1 

Technical Amendments Affecting Recordkeeping and Reporting 

Section Description 

80.1449(a) 

Amended Production Outlook Report due date; added 

allowance for unregistered renewable fuel producers and 

importers to submit Production Outlook Reports. 

80.1450(b)(1)(vi) 

Amended to require submission of additional evidence as part 

of registration to verify eligibility for exemptions in 

§80.1403(c) or (d). 

80.1450(d)(1)-(d)(3) 

Amended to add more specificity on when updates, addenda, 

or resubmittals are required for engineering reviews and to 

include references to foreign ethanol producers. 

With regard to Production Outlook Reports, the change in due date is not expected to have any 

impact on the reporting burden. In addition, EPA recently prepared an Information Collection 
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Request (ICR) document to permit the submission of voluntary Production Outlook Reports by 

domestic and foreign renewable fuels producers. The parties affected by the ICR are not 

regulated parties under the RFS2 program. The ICR has been submitted for approval to OMB 

under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and may be identified by EPA ICR 

number 2409.01. Documents related to the ICR have been placed in docket number EPA-HQOAR-2005-0161, which is accessible at http://www.regulations.gov. 

On October 14, 2010, EPA published a notice in the Federal Register announcing our 

intent to submit the proposed ICR for voluntary Production Outlook Reports to OMB for 

approval. (See 75 FR 63173). The 60-day comment period closed on December 14, 2010. No 

comments were received. On February 8, 2011, EPA published a Federal Register notice 

announcing submission of the ICR to OMB. Additional comments were solicited via an 

additional comment period through March 10, 2011.97 

 The Office of Management and Budget (OMB) has previously approved the information 

collection requirements contained in the existing regulations at 40 CFR Part 80, Subpart M under 

the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. This would include the 

following approved information collections (with OMB control numbers and expiration dates 

listed in parenthesis): “Renewable Fuels Standard Program: Petition and Registration” (OMB 

Control Number 2060-0367, expires March 31, 2013); “Renewable Fuels Standard (RFS2)” 

(OMB Control Number 2060-0640, expires July 31, 2013); “Regulations of Fuels and Fuel 

Additives: 2011 Renewable Fuels Standard – Petition for International Aggregate Compliance 

Approach” OMB Control Number 2060-0655, expires February 28, 2014). Detailed and 

searchable information about these and other approved collections may be viewed on the Office 

of Management and Budget (OMB) Paperwork Reduction Act website, which is accessible at 

http://www.reginfo.gov/public/do/PRAMain. With regard to the technical amendments in 

§80.1450, we believe that these information collections already approved for the RFS2 program's 

general recordkeeping and reporting requirements would also cover the amendments in today's 

final rule. 

C. Regulatory Flexibility Act 

 The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice and comment rulemaking 

requirements under the Administrative Procedure Act or any other statute unless the agency 

certifies that the rule will not have a significant economic impact on a substantial number of 

small entities. Small entities include small businesses, small organizations, and small 

governmental jurisdictions. 

 For purposes of assessing the impacts of today's rule on small entities, small entity is 

 

97 See “Agency Information Collection Activities; Submission to OMB for Review and Approval; Comment 

Request; Production Outlook Reports for Un-Registered Renewable Fuel Producers (New Collection),” 76 FR 6781 

(February 8, 2011). The document identification number for this notice is EPA-HQ-OAR-2005-0161-3221. The 

document identification number for the supporting statement is EPA-HQ-OAR-2005-0161-3222. 
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defined as: (1) a small business as defined by the Small Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a 

city, county, town, school district or special district with a population of less than 50,000; and (3) 

a small organization that is any not-for-profit enterprise which is independently owned and 

operated and is not dominant in its field. 

 After considering the economic impacts of today’s final rule on small entities, we certify 

that this action will not have a significant economic impact on a substantial number of small 

entities. 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). This rule simply finalizes the annual 

standard for cellulosic biofuels for 2012 and biomass-based diesel for 2013, regulatory 

provisions for new RIN-generating pathways, and clarifying changes and minor technical 

amendments to the regulations. Therefore, this action will not impose any additional 

requirements on small entities. 

 D. Unfunded Mandates Reform Act 

 This rule does not contain a Federal mandate that may result in expenditures of $100 

million or more for State, local, and tribal governments, in the aggregate, or the private sector in 

any one year. This rule simply finalizes the annual standard for cellulosic biofuels for 2012 and 

biomass-based diesel for 2013, regulatory provisions for new RIN-generating pathways, and 

clarifying changes and minor technical amendments to the regulations. Thus, this action is not 

subject to the requirements of sections 202 or 205 of UMRA. 

This action is also not subject to the requirements of section 203 of UMRA because it 

contains no regulatory requirements that might significantly or uniquely affect small 

governments. 

 E. Executive Order 13132: Federalism 

 This action does not have federalism implications. It will not have substantial direct 

effects on the States, on the relationship between the national government and the States, or on 

the distribution of power and responsibilities among the various levels of government, as 

specified in Executive Order 13132. This action only applies to gasoline, diesel, and renewable 

fuel producers, importers, distributors and marketers and makes relatively minor corrections and 

modifications to the RFS2 regulations. Although section 6 of Executive Order 13132 does not 

apply to this action, EPA did consult with State and local officials in developing this action. A 

summary of the concerns raised, and EPA’s response to those concerns, is provided in this 

preamble. 

 In the spirit of Executive Order 13132, and consistent with EPA policy to promote 

communications between EPA and State and local governments, EPA specifically solicited 

comment on the proposed action from State and local officials. 
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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 rule will be implemented at the Federal level and impose 

compliance costs only on transportation fuel refiners, blenders, marketers, distributors, 

importers, exporters, and renewable fuel producers and importers. Tribal governments would be 

affected only to the extent they purchase and use regulated fuels. Thus, Executive Order 13175 

does not apply to this action. 

 

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

Risks and Safety Risks 

 EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying only to those 

regulatory actions that concern health or safety risks, such that the analysis required under 

section 5-501 of the EO has the potential to influence the regulation. This action is not subject to 

EO 13045 because it does not establish an environmental standard intended to mitigate health or 

safety risks and because it implements specific standards established by Congress in statutes. 

H. Executive Order 13211: Actions Concerning Regulations That Significantly 

Affect Energy Supply, Distribution, or Use 

 This rule is not a “significant energy action” as defined in Executive Order 13211, 

“Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” 

(66 FR 28355 (May 22, 2001)) because it is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. This action simply finalizes the annual standards for 

cellulosic biofuels for 2012 and biomass-based diesel for 2013, provisions for new RINgenerating pathways, and clarifying changes and minor technical amendments to the regulations. 

I. National Technology Transfer Advancement Act 

 Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(‘‘NTTAA’’), Public Law 104–113, 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary 

consensus standards in its regulatory activities unless to do so would be inconsistent with 

applicable law or otherwise impractical. Voluntary consensus standards are technical standards 

(e.g., materials specifications, test methods, sampling procedures, and business practices) that are 

developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations when the Agency decides not to use available and 

applicable voluntary consensus standards. 

 This action does not involve technical standards. Therefore, EPA did not consider the 

use of any voluntary consensus standards. 
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J. Executive Order 12898: Federal Actions to Address Environmental Justice 

in Minority Populations and Low-Income Populations 

 Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive 

policy on environmental justice. Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental justice part of their mission by 

identifying and addressing, as appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and activities on minority populations and lowincome populations in the United States. 

 EPA has determined that this final rule will not have disproportionately high and 

adverse human health or environmental effects on minority or low-income populations because it 

does not affect the level of protection provided to human health or the environment. This action 

does not relax the control measures on sources regulated by the RFS2 regulations and therefore 

will not cause emissions increases from these sources.

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business 

Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take 

effect, the agency promulgating the rule must submit a rule report, which includes a copy of the 

rule, to each House of the Congress and to the Comptroller General of the United States. EPA 

will submit a report containing this rule and other required information to the U.S. Senate, the 

U.S. House of Representatives, and the Comptroller General of the United States prior to 

publication of the rule in the Federal Register. A major rule cannot take effect until 60 days after 

it is published in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 

804(2). Therefore, this rule will be effective on the date of publication. 
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X. Statutory Authority 

Statutory authority for the rule finalized today can be found in section 211 of the Clean 

Air Act, 42 U.S.C. 7545. Additional support for the procedural and compliance related aspects 

of today's rule, including the recordkeeping requirements, 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 

Environmental protection, Administrative practice and procedure, Air pollution control, 

Confidential Business Information, Diesel fuel, Fuel additives, Gasoline, Imports, Labeling, 

Motor vehicle pollution, Penalties, Petroleum, Reporting and recordkeeping requirements. 

Dated: 

Lisa P. Jackson, 

Administrator. 
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For the reasons set forth in the preamble, 40 CFR part 80 is amended as follows: 

PART 80—REGULATION OF FUELS AND FUEL ADDITIVES 

1. The authority citation for part 80 continues to read as follows: 

Authority: 42 U.S.C. 7414, 7542, 7545, and 7601(a). 

§80.1275—[Amended]

2. In §80.1275, remove paragraph (d)(3). 

Subpart M—[Amended] 

3. Section 80.1401 is amended by revising the definitions of “Annual cover crop” and 

“Naphtha” to read as follows: 

§ 80.1401 Definitions. 

* * * * * 

Annual cover crop means an annual crop, planted as a rotation between primary planted crops, or 

between trees and vines in orchards and vineyards, typically to protect soil from erosion and to 

improve the soil between periods of regular crops. An annual cover crop has no existing market 

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

* * * * * 

Naphtha means a blendstock falling within the boiling range of gasoline which is composed of 

only hydrocarbons, is commonly or commercially known as naphtha, and is used to produce 

gasoline. 

* * * * * 

4. Section 80.1405 is amended by revising paragraphs (a) through (c) to read as follows: 

 

§ 80.1405 What are the Renewable Fuel Standards? 

(a) (1) Renewable Fuel Standards for 2011.

(i) The value of the cellulosic biofuel standard for 2011 shall be 0.003 percent. 

(ii) The value of the biomass-based diesel standard for 2011 shall be 0.69 percent. 

(iii) The value of the advanced biofuel standard for 2011 shall be 0.78 percent. 

(iv) The value of the renewable fuel standard for 2011 shall be 8.01 percent. 

(2) Renewable Fuel Standards for 2012.

(i) The value of the cellulosic biofuel standard for 2012 shall be 0.006 percent. 

(ii) The value of the biomass-based diesel standard for 2012 shall be 0.89 percent. 

(iii) The value of the advanced biofuel standard for 2012 shall be 1.19 percent. 

(iv) The value of the renewable fuel standard for 2012 shall be 9.03 percent. 

(b) EPA will calculate the value of the annual standards and publish these values in the 

Federal Register by November 30 of the year preceding the compliance period. 

(c) EPA will calculate the annual renewable fuel percentage standards using the following 

equations: 
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Where: 

StdCB,i = The cellulosic biofuel standard for year i, in percent. 

StdBBD,i= The biomass-based diesel standard for year i, in percent. 

StdAB,i= The advanced biofuel standard for year i, in percent. 

StdRF,i= The renewable fuel standard for year i, in percent. 

RFVCB,i= Annual volume of cellulosic biofuel required by 42 U.S.C. 7545(o)(2)(B) for year 

i, or volume as adjusted pursuant to 42 U.S.C. 7545(o)(7)(D), in gallons. 

RFVBBD,i= Annual volume of biomass-based diesel required by 42 U.S.C. 7545 (o)(2)(B) for 

year i, in gallons. 

RFVAB,i= Annual volume of advanced biofuel required by 42 U.S.C. 7545(o)(2)(B) for year 

i, in gallons. 

RFVRF,i= Annual volume of renewable fuel required by 42 U.S.C. 7545(o)(2)(B) for year i, 

in gallons. 

Gi= Amount of gasoline projected to be used in the 48 contiguous states and Hawaii, in year i, 

in gallons. 

Di= Amount of diesel projected to be used in the 48 contiguous states and Hawaii, in year i, in 

gallons. 

RGi= Amount of renewable fuel blended into gasoline that is projected to be consumed in the 

48 contiguous states and Hawaii, in year i, in gallons. 

RDi= Amount of renewable fuel blended into diesel that is projected to be consumed in the 48 

contiguous states and Hawaii, in year i, in gallons. 

GSi= Amount of gasoline projected to be used in Alaska or a U.S. territory, in year i, if the 

state or territory has opted-in or 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 has opted-in or opts-in, in gallons. 

RDSi= Amount of renewable fuel blended into diesel that is projected to be consumed in Alaska 

or a U.S. territory, in year i, if the state or territory opts-in, in gallons. 

GEi= The amount of gasoline projected to be produced by exempt small refineries and small 

refiners, in year i, in gallons in any year they are exempt per §§80.1441 and 80.1442. 

 DEi= The amount of diesel fuel projected to be produced by exempt small refineries and small 

refiners in year i, in gallons, in any year they are exempt per §§80.1441 and 80.1442. 

* * * * * 
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5. Section 80.1415 is amended by revising paragraph (c)(2) to read as follows: 

§ 80.1415 How are equivalence values assigned to renewable fuel? 

* * * * * 

(c) * * * 

(2) The application for an equivalence value shall include a technical justification that 

includes all the following: 

(i) A calculation for the requested equivalence value according to the equation in paragraph 

(c)(1) of this section, including supporting documentation for the value of EC used in the 

calculation such as a certificate of analysis from a laboratory that verifies the lower heating value 

in Btu per gallon of the renewable fuel produced. 

(ii) For each feedstock, component, or additive that is used to make the renewable fuel, 

provide a description, the percent input, and identify whether or not it is renewable biomass or is 

derived from renewable biomass. 

(iii) For each feedstock that also qualifies as a renewable fuel, state whether or not RINs have 

been previously generated for such feedstock. 

(iv) A description of the renewable fuel and the production process, including a block 

diagram that shows all inputs and outputs at each step of the production process with a sample 

quantity of all inputs and outputs for one batch of renewable fuel produced. 

* * * * * 

6. Section 80.1426 is amended as follows: 

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

 b. By revising Table 1 to §80.1426. 

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

§ 80.1426 How are RINs generated and assigned to batches of renewable fuel by 

renewable fuel producers or importers? 

* * * * * 

(f) * * * 

(1) Applicable pathways. D codes shall be used in RINs generated by producers or importers 

of renewable fuel according to the pathways listed in Table 1 to this section, paragraph (f)(6) of 

this section, or as approved by the Administrator. In choosing an appropriate D code, producers 

and importers may disregard any incidental, de minimis feedstock contaminants that are 

impractical to remove and are related to customary feedstock production and transport. Tables 1 

and 2 to this section do not apply to, and impose no requirements with respect to, volumes of fuel 

for which RINs are generated pursuant to paragraph (f)(6) of this section. 

Table 1 to §80.1426—Applicable D Codes for Each Fuel Pathway for Use in Generating 

RINs 

 Fuel type Feedstock Production process requirements DCode 
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A Ethanol Corn starch All of the following: 

Dry mill process, using natural gas, 

biomass, or biogas for process energy 

and at least two advanced technologies 

from Table 2 to this section 

6 

B Ethanol Corn starch All of the following: 

Dry mill process, using natural gas, 

biomass, or biogas for process energy 

and at least one of the advanced 

technologies from Table 2 to this 

section plus drying no more than 65% 

of the distillers grains with solubles it 

markets annually 

6 

C Ethanol Corn starch All of the following: 

Dry mill process, using natural gas, 

biomass, or biogas for process energy 

and drying no more than 50% of the 

distillers grains with solubles it 

markets annually 

6 

D Ethanol Corn starch Wet mill process using biomass or 

biogas for process energy 

6 

E Ethanol Starches from crop residue and annual 

covercrops 

Fermentation using natural gas, 

biomass, or biogas for process energy 

6 

F Biodiesel, 

and 

renewable 

diesel 

Soy bean oil; 

Oil from annual covercrops; 

Algal oil; 

Biogenic waste oils/fats/greases; 

Non-food grade corn oil 

One of the following: 

Trans-Esterification 

Hydrotreating 

Excluding processes that co-process 

renewable biomass and petroleum 

4 

G Biodiesel Canola/Rapeseed oil Trans-Esterification using natural gas 

or biomass for process energy 

4 

H Biodiesel, 

and 

renewable 

diesel 

Soy bean oil; 

Oil from annual covercrops; 

Algal oil; 

Biogenic waste oils/fats/greases; 

Non-food grade corn oil 

One of the following: 

Trans-Esterification 

Hydrotreating 

Includes only processes that coprocess renewable biomass and 

petroleum 

5 

I Ethanol Sugarcane Fermentation 5 

J Ethanol Cellulosic Biomass from crop residue, 

slash, pre-commercial thinnings and tree 

residue, annual covercrops, switchgrass, 

and miscanthus; cellulosic components of 

separated yard waste; cellulosic 

components of separated food waste; and 

cellulosic components of separated MSW 

Any 3 

K Cellulosic 

Diesel, Jet 

Fuel and 

Heating Oil 

Cellulosic Biomass from crop residue, 

slash, pre-commercial thinnings and tree 

residue, annual covercrops, switchgrass, 

and miscanthus; cellulosic components of 

separated yard waste; cellulosic 

components of separated food waste; and 

cellulosic components of separated MSW 

Any 7 

L Butanol Corn starch Fermentation; dry mill using natural 

gas, biomass, or biogas for process 

energy 

6 

M Cellulosic Cellulosic Biomass from crop residue, Fischer-Tropsch process 3 
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Naphtha slash, pre-commercial thinnings and tree 

residue, annual covercrops, switchgrass, 

and miscanthus; cellulosic components of 

separated yard waste; cellulosic 

components of separated food waste; and 

cellulosic components of separated MSW 

N Ethanol, 

renewable 

diesel, jet 

fuel, heating 

oil, and 

naphtha 

The non-cellulosic portions of separated 

food waste 

Any 5 

O Biogas Landfills, sewage waste treatment plants, 

manure digesters 

Any 5 

* * * * * 

(5) * * * 

(ii) (A) A feedstock qualifies under paragraph (f)(5)(i)(A) or (f)(5)(i)(B) of this section 

only if it is collected according to a plan submitted to and accepted by U.S. EPA under the 

registration procedures specified in §80.1450(b)(1)(vii). 

(B) A feedstock qualifies under paragraph (f)(5)(i)(C) of this section only if it is collected 

according to a plan submitted to and approved by U.S. EPA. 

* * * * * 

7. Section 80.1429 is amended by revising paragraphs (b)(2) and (b)(9) introductory text to 

read as follows: 

§ 80.1429 Requirements for separating RINs from volumes of renewable fuel. 

* * * * * 

(b) * * * 

(2) Except as provided in paragraph (b)(6) of this section, any party that owns a volume of 

renewable fuel must separate any RINs that have been assigned to that volume once the volume 

is blended with gasoline or fossil-based diesel to produce a transportation fuel, heating oil, or jet 

fuel. A party may separate up to 2.5 RINs per gallon of blended renewable fuel. 

* * * * * 

(9) Except as provided in paragraphs (b)(2) through (b)(5) and (b)(8) of this section, parties 

whose non-export renewable volume obligations are solely related to either the importation of 

products listed in §80.1407(c) or §80.1407(e) or to the addition of blendstocks into a volume of 

finished gasoline, finished diesel fuel, RBOB, or CBOB, can only separate RINs from volumes 

of renewable fuel if the number of gallon-RINs separated in a calendar year is less than or equal 

to a limit set as follows: 

* * * * * 

8. Section 80.1449 is amended by revising paragraph (a) introductory text to read as 

follows: 

§ 80.1431 Treatment of invalid RINs. 
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* * * * * 

(c) Notwithstanding paragraph (b) of this section, improperly generated RINs may be used for 

compliance [providing that all of the following conditions and requirements are satisfied] [if the 

renewable fuel producer or importer who improperly generated the RINs demonstrates through 

the reporting and recordkeeping requirements set forth below, that]: 

(1) The number of RINs generated for a batch exceeds the number of RINs that should have 

been properly generated; 

(2) The RINs were improperly generated as a result of a broken meter, an inadvertent 

temperature correction error, or an inadvertent administrative error; 

(3) The renewable fuel producer or importer had in place at the time the RINs were improperly 

generated a quality assurance / quality control plan designed to ensure that process measuring 

equipment such as meters and temperature probes are properly maintained and to prevent 

inadvertent administrative errors. 

(4) The renewable fuel producer or importer has taken any appropriate additional steps to prevent 

similar violations from occurring in the future; 

(5) The improperly generated RINs have been transferred to another party, 

(6) The renewable fuel producer or importer has not improperly generated RINs for the reasons 

described in paragraph (c)(2) on more than five batches during any calendar year; and 

(7) The following remedial actions have been implemented within 30 days of the EMTS 

submission date of the improper RIN generation: 

(A) The renewable fuel producer or importer retires an equal number of valid RINs with the 

same D Code and RIN year as the properly generated RINs, using an EMTS retire code of 110; 

(B) The renewable fuel producer or importer reports the following information to EPA via 

EMTS, which EPA may make publicly available: 

 (i) Company name 

(ii) Company ID 

(iii) Facility name 

(iv) Facility ID 

(v) The date the renewable fuel was produced 

(vi) The date the RINs were originally generated 

(vii) The number of RINs generated 

(vii) The number of RINs improperly generated 

(ix) RIN year 

(x) D codes of generated RINs 

(xi) Batch numbers 

(xii) EMTS Transaction ID of the original generation 

(xiii) An explanation of how the violation occurred, and why the improperly generated RINs 

meet the criteria in paragraph (c)(2) of this section 

(xiv) Steps taken to prevent similar violations from occurring in the future 

(xv) Information under (c)(3), (c)(4), (c)(5) of this section (xvi) Any additional information the 

Administrator may require. 

(8) The renewable fuel producer or importer maintains all records relating to the improper RIN 

generation and the associated remedial actions taken, including but not limited to: 
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 (A) All information regarding the generation of invalid RINs, including information that is 

sufficient to demonstrate that the improperly generated RINs meet the criteria in paragraph (c)(2) 

of this section; 

(B) Documents demonstrating that the renewable fuel producer or importer has implemented the 

quality control / quality assurance plan required in paragraph (c)(3) of this section, and has taken 

all appropriate additional steps to prevent similar violations from occurring in the future; 

(C) All correspondence with EPA; 

(D) All EMTS transactions (Generation, Buy, Sell and Retire); and 

(E) All Product Transfer Documents (PTDs). 

(d) If EPA determines that a renewable fuel producer improperly generated RINs, but did not 

meet the requirements set forth in paragraph (c), then the requirements of paragraph (b) apply 

from the moment that the invalid RINs were generated in EMTS. Once the RIN generator has 

identified improperly generated RINs to EPA, then EPA may remove these improperly generated 

RINs from EMTS. 

§ 80.1449 What are the Production Outlook Report requirements? 

(a) By June 1 of each year (September 1 for the report due in 2010), a registered renewable 

fuel producer or importer must submit and an unregistered renewable fuel producer may submit 

all of the following information for each of its facilities, as applicable, to EPA: 

* * * * * 

9. Section 80.1450 is amended by revising paragraphs (d)(1)-(d)(3) to read as follows: 

 

§ 80.1450 What are the registration requirements under the RFS program? 

* * * * * 

 (d) * * * 

(1) Any producer of renewable fuel, and any foreign ethanol producer who makes changes to 

his facility that will allow him to produce renewable fuel, as defined in §80.1401 that is not 

reflected in the producer's registration information on file with EPA must update his registration 

information and submit a copy of an updated independent third-party engineering review on file 

with EPA at least 60 days prior to producing the new type of renewable fuel. The producer may 

also submit an addendum to the independent third-party engineering review on file with EPA 

provided the addendum meets all the requirements in paragraph (b)(2) of this section and verifies 

for EPA the most up-to-date information at the producer’s existing facility. 

(2) Any producer of renewable fuel and any foreign ethanol producer who makes any other 

changes to a facility that will affect the producer's registration information but will not affect the 

renewable fuel category for which the producer is registered per paragraph (b) of this section 

must update his registration information 7 days prior to the change. 

(3) All producers of renewable fuel and foreign ethanol producers must update registration 

information and submit an updated independent third-party engineering review according to the 

schedule in paragraph (d)(3)(i) or (d)(3)(ii) of this section, and including the information 

specified in paragraph (d)(3)(iii) of this section: 
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(i) For all producers of renewable fuel and foreign ethanol producers registered in calendar 

year 2010, the updated registration information and independent third-party engineering review 

shall be submitted to EPA by January 31, 2013, and by January 31 of every third calendar year 

thereafter; or 

(ii) For all producers of renewable fuel and foreign ethanol producers registered in any 

calendar year after 2010, the updated registration information and independent third-party 

engineering review shall be submitted to EPA by January 31 of every third calendar year after 

the first year of registration. 

(iii) In addition to conducting the engineering review and written report and verification 

required by paragraph (b)(2) of this section, the updated independent third-party engineering 

review shall include a detailed review of the renewable fuel producer's calculations used to 

determine VRIN of a representative sample of batches of each type of renewable fuel produced 

since the last registration. The representative sample shall be selected in accordance with the 

sample size guidelines set forth at §80.127. 

* * * * * 

10. Section 80.1451 is amended by revising paragraph (a)(1)(xi) to read as follows: 

§ 80.1451 What are the reporting requirements under the RFS program? 

(a) * * * 

(1) * * * 

(xi) A list of all RINs generated prior to July 1, 2010 that were retired for compliance in the 

reporting period. 

* * * * * 

11. Section 80.1452 is amended revising paragraphs (b)(2), (b)(4), and (b)(5) to read as 

follows: 

§ 80.1452 What are the requirements related to the EPA Moderated Transaction 

System (EMTS)? 

* * * * * 

(b) * * * 

(2) The EPA company registration number of the renewable fuel producer or foreign ethanol 

producer, as applicable. 

* * * * * 

(4) The EPA facility registration number of the facility at which the renewable fuel producer 

or foreign ethanol producer produced the batch, as applicable. 

(5) The EPA facility registration number of the importer that imported the batch, if 

applicable. 

* * * * * 
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13. Section 80.1460 is amended by adding a new paragraph (b)(6) to read as follows: 

§ 80.1460 What acts are prohibited under the RFS program? 

* * * * * 

(b) * * * 

(6) Generate a RIN for fuel for which RINs have previously been generated. 

* * * * * 

14. Section 80.1464 is amended as follows: 

 a. By revising paragraphs (a)(2) introductory text and (a)(2)(i). 

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

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

 d. By revising paragraphs (b)(2) introductory text and (b)(2)(i). 

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

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

 g. By revising paragraph (c)(1) introductory text. 

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

§ 80.1464 What are the attest engagement requirements under the RFS program? 

* * * * * 

(a) * * * 

(2) RIN Transaction Reports and Product Transfer Documents.

(i) Obtain and read copies of a representative sample, selected in accordance with the 

guidelines in §80.127, of each RIN transaction type (RINs purchased, RINs sold, RINs retired, 

RINs separated, RINs reinstated) included in the RIN transaction reports required under 

§80.1451(a)(2) for the compliance year. 

* * * * * 

(iii) Verify that the product transfer documents for the representative samples under 

paragraph (a)(2)(i) of this section of RINs sold and the RINs purchased contain the applicable 

information required under §80.1453 and report as a finding any product transfer document that 

does not contain the required information. 

(iv) Verify the accuracy of the information contained in the product transfer documents 

reviewed pursuant to paragraph (a)(2)(iii) of this section and report as a finding any exceptions. 

(3) * * * 

(ii) Obtain the database, spreadsheet, or other documentation used to generate the 

information in the RIN activity reports; compare the RIN transaction samples reviewed under 

paragraph (a)(2) of this section with the corresponding entries in the database or spreadsheet and 

report as a finding any discrepancies; compute the total number of current-year and prior-year 

RINs owned at the start and end of each quarter, purchased, separated, sold, retired and 

reinstated, and for parties that reported RIN activity for RINs assigned to a volume of renewable 

fuel, the volume and type of renewable fuel (as defined in §80.1401) owned at the end of each 

quarter; as represented in these documents; and state whether this information agrees with the 

party's reports to EPA. 

(b) * * * 
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(2) RIN Transaction Reports and Product Transfer Documents.

(i) Obtain and read copies of a representative sample, selected in accordance with the 

guidelines in §80.127, of each transaction type (RINs purchased, RINs sold, RINs retired, RINs 

separated, RINs reinstated) included in the RIN transaction reports required under 

§80.1451(b)(2) for the compliance year. 

* * * * * 

(iii) Verify that the product transfer documents for the representative samples under 

paragraph (b)(2)(i) of this section of RINs sold and the RINs purchased contain the applicable 

information required under §80.1453 and report as a finding any product transfer document that 

does not contain the required information. 

(iv) Verify the accuracy of the information contained in the product transfer documents 

reviewed pursuant to paragraph (b)(2)(iii) of this section and report as a finding any exceptions. 

(3) * * * 

(ii) Obtain the database, spreadsheet, or other documentation used to generate the 

information in the RIN activity reports; compare the RIN transaction samples reviewed under 

paragraph (b)(2) of this section with the corresponding entries in the database or spreadsheet and 

report as a finding any discrepancies; report the total number of each RIN generated during each 

quarter and compute and report the total number of current-year and prior-year RINs owned at 

the start and end of each quarter, purchased, separated, sold, retired and reinstated, and for 

parties that reported RIN activity for RINs assigned to a volume of renewable fuel, the volume of 

renewable fuel owned at the end of each quarter, as represented in these documents; and state 

whether this information agrees with the party's reports to EPA. 

* * * * * 

(c) * * * 

(1) RIN Transaction Reports and Product Transfer Documents.

* * * * * 

(iii) Verify that the product transfer documents for the representative samples under 

paragraph (c)(1)(i) of this section of RINs sold and RINs purchased contain the applicable 

information required under §80.1453 and report as a finding any product transfer document that 

does not contain the required information. 

(iv) Verify the accuracy of the information contained in the product transfer documents 

reviewed pursuant to paragraph (c)(1)(iii) of this section and report as a finding any exceptions. 

* * * * * 

15. Section 80.1465 is amended by revising paragraph (h)(2) to read as follows: 

§ 80.1465 What are the additional requirements under this subpart for foreign small 

refiners, foreign small refineries, and importers of RFS–FRFUEL? 

* * * * * 

(h) * * * 

(2) Bonds shall be posted by any of the following methods: 

(i) Paying the amount of the bond to the Treasurer of the United States. 

(ii) Obtaining a bond in the proper amount from a third party surety agent that is payable to 

satisfy United States administrative or judicial judgments against the foreign refiner, provided 

EPA agrees in advance as to the third party and the nature of the surety agreement. 
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* * * * * 

16. Section 80.1466 is amended by revising paragraph (h)(2) to read as follows: 

§ 80.1466 What are the additional requirements under this subpart for RINgenerating foreign producers and importers of renewable fuels for which RINs have been 

generated by the foreign producer?

* * * * * 

(h) * * * 

(2) Bonds shall be posted by any of the following methods: 

(i) Paying the amount of the bond to the Treasurer of the United States. 

(ii) Obtaining a bond in the proper amount from a third party surety agent that is payable to 

satisfy United States administrative or judicial judgments against the foreign producer, provided 

EPA agrees in advance as to the third party and the nature of the surety agreement. 

* * * * * 

17. Section 80.1467 is amended by revising paragraphs (e)(1), (e)(2), and (g)(2) to read as 

follows: 

 

§ 80.1467 What are the additional requirements under this subpart for a foreign RIN 

owner? 

* * * * * 

(e) * * * 

(1) The foreign entity shall post a bond of the amount calculated using the following 

equation: 

 Bond = G * $ 0.01 

Where: 

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

G = The total of the number of gallon-RINs the foreign entity expects to obtain, sell, transfer 

or hold during the first calendar year that the foreign entity is a RIN owner, plus the number of 

gallon-RINs the foreign entity expects to obtain, sell, transfer or hold during the next four 

calendar years. After the first calendar year, the bond amount shall be based on the actual 

number of gallon-RINs obtained, sold, or transferred so far during the current calendar year plus 

the number of gallon-RINs obtained, sold, or transferred during the four calendar years 

immediately preceding the current calendar year. For any year for which there were fewer than 

four preceding years in which the foreign entity obtained, sold, or transferred RINs, the bond 

shall be based on the total of the number of gallon-RINs sold or transferred so far during the 

current calendar year plus the number of gallon-RINs obtained, sold, or transferred during any 

immediately preceding calendar years in which the foreign entity owned RINs, plus the number 

of gallon-RINs the foreign entity expects to obtain, sell or transfer during subsequent calendar 

years, the total number of years not to exceed four calendar years in addition to the current 

calendar year. 

(2) Bonds shall be posted by any of the following methods: 

(i) Paying the amount of the bond to the Treasurer of the United States. 
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(ii) Obtaining a bond in the proper amount from a third party surety agent that is payable to 

satisfy United States administrative or judicial judgments against the foreign RIN owner, 

provided EPA agrees in advance as to the third party and the nature of the surety agreement. 

* * * * * 

(g) * * * 

(2) Any RIN that is obtained, sold, transferred, or held that is in excess of the number for 

which the bond requirements of this section have been satisfied is an invalid RIN under 

§80.1431. 

* * * * *