EO12866_RFS standards 2060-AQ76 FRM FRN_20120523

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2010-0133; FRL-9678-7]

RIN 2060-AR55

Regulation of Fuels and Fuel Additives: 2013 Biomass-Based Diesel Renewable Fuel 

Volume

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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

required to determine the applicable volume of biomass-based diesel to be used in setting annual 

percentage standards under the renewable fuel standard program for years after 2012. We 

proposed an applicable volume requirement for 2013 of 1.28 billion gallons on July 1, 2011. In 

order to sufficiently evaluate the many comments on the proposal from stakeholders as well as to 

gather additional information to enhance our analysis, we did not finalize this volume 

requirement in the January 9, 2012, rulemaking setting the 2012 percentage standards. In this 

action we are finalizing an applicable volume of 1.28 billion gallons of biomass-based diesel for 

calendar year 2013.

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-

214-4816; E-mail address: macallister.julia@epa.gov, or the public information line for the 

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

OTAQ@epa.gov.

SUPPLEMENTARY INFORMATION: 
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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................................................................................................................ 5

A. Purpose of This Action ....................................................................................................... 5

B. Summary of Today's Action ............................................................................................... 5

C. Impacts of This Action........................................................................................................ 6

II. Statutory Requirements........................................................................................................... 7

III. Factors Affecting Supply and Consumption......................................................................... 10

A. Demand for Biomass-Based Diesel .................................................................................. 11

B. Availability of Feedstocks to Produce 1.28 Billion Gallons of Biodiesel ........................ 14

1. Grease and Rendered Fats............................................................................................. 14

2. Corn Oil ........................................................................................................................ 16

3. Soybean Oil................................................................................................................... 16

4. Effects on Food Prices.................................................................................................. 18
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5. Other Bio-oils................................................................................................................ 19

C. Production Capacity.......................................................................................................... 19

D. Consumption Capacity...................................................................................................... 20

E. Biomass-Based Diesel Distribution Infrastructure ........................................................... 23

IV. Impacts of 1.28 Billion Gallons of Biomass-Based Diesel

A. Consideration of Statutory Factors ................................................................................... 30

1. Climate Change............................................................................................................. 30

2. Energy Security............................................................................................................. 33

3. Agricultural Commodities and Food Prices.................................................................. 36

4. Air Quality .................................................................................................................... 38

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

Renewable Fuel..................................................................................................................... 40

6. Wetlands, Ecosystems, and Wildlife Habitats.............................................................. 41

7. Water Quality and Quantity.......................................................................................... 42

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

43

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

45

8. Job Creation and Rural Economic Development.......................................................... 46

B. Consideration of Quantifiable Costs and Benefits............................................................ 49

1. Monetized Quantifiable Costs....................................................................................... 50

a. Impact on the Cost of Soybean Oil........................................................................... 50

b. Cost of Displacing Petroleum-Based Diesel with Soybean-Based Biodiesel........... 51

c. Transfers Occurring as a Result of This Mandate .................................................... 53

d. Transportation Fuel Costs......................................................................................... 53

2. Monetized Quantifiable Benefits.................................................................................. 55

a. Energy Security......................................................................................................... 55

b. Air Quality ................................................................................................................ 55

c. Greenhouse Gas Impacts........................................................................................... 59

3. Quantifiable Benefits and Costs Compared.................................................................. 59

a. Combined Quantifiable Costs and Benefits for Biodiesel Produced in 2022........... 59

b. Combined Quantifiable Costs and Benefits for Biodiesel Produced in 2013........... 60

V. Final 2013 Volume for Biomass-Based Diesel..................................................................... 60

VI. Public Participation........................................................................................................... 62

VII. Statutory and Executive Order Reviews........................................................................... 63

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

Improving Regulation and Regulatory Review ........................................................................ 63

B. Paperwork Reduction Act................................................................................................. 63

C. Regulatory Flexibility Act ................................................................................................ 64

D. Unfunded Mandates Reform Act...................................................................................... 64

E. Executive Order 13132: Federalism ................................................................................. 65

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

65

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

Safety Risks .............................................................................................................................. 65
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H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use......................................................................................... 65

I. National Technology Transfer Advancement Act ............................................................ 66

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

Populations and Low-Income Populations ............................................................................... 66

K. Congressional Review Act................................................................................................ 66

VIII. Statutory Authority ........................................................................................................... 68
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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.

A. Purpose of This Action

While CAA section 211(o)(2)(B) specifies the volumes of biomass-based diesel to be 

used in the RFS program through year 2012, it directs the EPA to establish the applicable 

volume of biomass-based diesel for years after 2012 no later than 14 months before the first year 

for which the applicable volume will apply. On July 1, 2011, we proposed that the applicable 

volume of biomass-based diesel for 2013 would be 1.28 bill gal.2 

In a final rulemaking published on January 9, 2012, we specified the 2012 standards for 

cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel. Although 

we had intended to also finalize the applicable volume of biomass-based diesel for 2013 in that 

rulemaking, we did not do so. In that final rule we explained that we were continuing to evaluate 

the many comments on the NPRM from stakeholders as well as fulfilling other analytical 

requirements. We indicated that we intended to gather additional information to enhance our 

analysis including consideration of costs and benefits. In today's notice we are finalizing the 

applicable volume of biomass-based diesel for 2013. We believe that the volume we are 

finalizing today is not only feasible and consistent with the overall analytic approach to the RFS2 

program but also consistent with the overall intent of the act to expand the use of renewable fuels 

through the year 2022.

B. Summary of Today's Action

In today's action we are finalizing an applicable volume of 1.28 bill gallons for biomassbased diesel for 2013. This is the volume that was projected for 2013 in the March 26, 2010, 

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

specified in the statute.

Today's final rule does not specify the percentage standard for biomass-based diesel in 

2013, but only the applicable volume. The percentage standards for cellulosic biofuel, biomassbased diesel, advanced biofuel, and total renewable fuel that will be applicable in 2013 are being 

proposed in a separate Notice of Proposed Rulemaking, and we expect to issue a final rule 

establishing those standards by November 30, 2012.

 

1

75 FR 14670

2

76 FR 38844
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C. Impacts of This Action

The RFS program established by Congress is a long-term program aimed at replacing 

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

March 26, 2010 RFS2 final rule, EPA assessed the costs and benefits of this program as a whole 

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

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

we have estimated costs and benefits in 2013 where such estimates can reasonably be made and 

have provided trends and other information on likely impacts where quantification for just 2013 

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

We estimate that soybean prices could increase up to 3 cents per pound in 2013 if the 280 

million gallon increment over the 2012 biodiesel standard is met solely with soybean oil. Again 

assuming the 280 billion gallon increase in required biomass-based diesel is met through 

increased demand for soy oil, we estimate the cost of producing this increment in biomass-based 

diesel would range from $253 to $381 million in 2013. Illustrative of the changing impacts over 

the duration of the RFS program, the cost of this amount of soy-based biodiesel in 2022 would 

be $116 million. Adding the estimate of 2013 costs to the total 2013 fuel pool would suggest a 

diesel fuel cost increase of approximately 2 cents per gallon. Of course, if less expensive 

feedstock is used, then the cost impacts would be less.

Quantified estimates of benefits include $0.15 per gallon of biodiesel in energy security 

benefit, $15 million in air quality benefit and up to $134 million in GHG benefits. Other benefits 

include both direct and indirect employment benefits in rural areas due to increased biodiesel 

production. Impacts on water quality, water use, wetlands, ecosystems and wildlife habitats are 

expected to be likely directionally negative but modest due to both the small impact on crop 

acres planted necessary to supply sufficient soy oil feedstock and due to the relatively small 

impact on these measures of soybean production compared to other potential crops.
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II. 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 statute3. 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;

• 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. 

As evidenced by the annual schedule of applicable volumes leading to 36 bill gallons by 

2022, the statute is forward-looking in its emphasis on achieving environmental and energy 

goals. In assessing potential increases in the applicable volume requirement for biomass-based 

diesel, then, we believe that many of the factors that we must consider under the statute are best 

analyzed for the longer term, while others are more appropriately analyzed for the near term. 

 

3

For example, EPA may waive a given standard in whole or in part following the provisions at 211(o)(7).
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Those factors that we believe should be analyzed when the program has had time to evolve and 

mature include impacts on costs and benefits. Those factors that we believe should be analyzed 

in the near term include production capacity, availability of feedstocks, and impacts on 

infrastructure. Thus for this NPRM, we have not simply looked at the impacts of the program in 

any one year with near term implementation, but have also looked at the evolving pattern of 

impacts through time. 

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. Due to 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 the belief that Congress intended the required volumes of biomass-based 

diesel to increase every year, with EPA's role being that of determining an achievable size of that 

increase. Others 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. Given that all biomass-based diesel counts towards the advanced biofuel 

requirement, and that the statute requires annual increases in advanced biofuel through 2022, we 

believe that it is appropriate that biomass-based diesel play an increasing role in supplying 

advanced biofuels to the market between 2012 and 2022. However, the determination of 

whether to increase the volume requirement for biomass-based diesel in any given year is subject 

to a consideration of a number of factors in the statute as described above.

We also note that the statute does not provide authority to raise the applicable volumes of 

advanced biofuel or total renewable fuel above those specified in the statute for years up to and 

including 2022. Thus, any increase in the biomass-based diesel volume requirement above 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 

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).

We received one comment in response to the NPRM requesting that we prohibit increases 

in biomass-based diesel above 1.0 billion gallons in years after 2012. We disagree. As 

described in this preamble, we believe it is appropriate to require 1.28 bill gal of biomass-based 

diesel in 2013, and that we should consider further increases in the future by evaluating the 

factors specified in the statute. 

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 
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months before the first year for which such applicable volume will apply. For the biomass-based 

diesel volume requirement applicable in 2013, the deadline for promulgation was November 1, 

2011. As described in the January 9, 2012, final rule that set the applicable percentage standards 

for 2012, we delayed issuing this final rule to allow additional time to evaluate the many 

comments on the NPRM from stakeholders as well to fulfill other analytical requirements. To 

this end, we did in fact gather additional information to enhance our analysis of the factors 

required in the statute, and we considered costs and benefits. Our assessment is provided in 

Sections III and IV. We do not believe that the delay in issuing this final rule will materially 

affect the regulated community, however, since we are setting the final volume requirement 

several months prior to the date when it will be applicable. This is still earlier than the final 

applicable 2013 standards that will be set for cellulosic biofuel, advanced biofuel, and total 

renewable fuel in November of this year.
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III. Factors Affecting Supply and Consumption

As described in Section II, 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. For instance, RFS1 RINs from both 2008 and 

2009 could be carried over to 2010 and used to meet a combined 2009/2010 volume requirement 

for biomass-based diesel. 

Since release of the NPRM, however, some information has become available on the 

implementation of the RFS program in 2011. The available data provide some indication as to 

how the biomass-based diesel standard for 2011 is affecting the market for biodiesel. Based on 

information provided through the EPA-Moderated Transaction System (EMTS), reported 

biodiesel production increased significantly to about 1.07 bill gal in 2011. This is a significant 

increase over the 2010 production volume of about 400 mill gal and exceeds the applicable 

volume requirement of 800 mill gal for 2011. 2011 biomass-based diesel RINs were available to 

meet the higher advanced biofuel volume requirement. Based on these results, we believe that 

the RFS program is driving production of biomass-based diesel, and that higher applicable 

volume requirements in future years would likewise drive increases in production volumes. 

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, storage, distribution, 

and blending capacity, the capability of the existing diesel fleet to consume this volume of 

biodiesel, 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 comments also suggested that any comparison to volume requirements in the statute is not 

appropriate. However, we did not base our proposed volume of 1.28 bill gallons on this 

comparison but referred to past statutory increments to put our proposal in context. Regardless 

of the size of these past statutory increments, however, we find the final 280 mill gal increment 

to be moderate and achievable, as described below, especially in light of the substantial increases 

in production volume that occurred in 2011 which were approximately twice the amount of the 
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280 mill gal increase we are adopting for 2013. 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 opposed the proposed volume requirement of 1.28 bill 

gallons, citing concerns that the 2012 applicable volume of 1.0 bill gallons is not achievable. As 

noted above, our evaluation indicates that biodiesel production exceeded 1.0 billion gallons in 

2011, confirming our projection that the 1.0 bill gallon applicable volume for 2012 is achievable. 

Therefore, 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 for 2013 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 

production rates. As described in the NPRM, 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 the 

sections below, we continue to believe that 1.28 bill gallons is achievable based on production 

capacity, availability of feedstock, recent trends in production volumes, and efforts to update 

infrastructure for storage, transport, and blending. Our consideration of other impacts, such as 

fuel costs and environmental impacts, can be found in Section IV.

A. Demand for Biomass-Based Diesel 

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. In addition to biomass-based diesel, biofuels that are likely to be available 

for meeting the advanced biofuel standard would include cellulosic biofuel, imported sugarcane 

ethanol, and other domestically produced advanced biofuels. As described in the January 9, 

2012 rulemaking establishing the 2012 standards4, 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. Regarding other 

domestically produced advanced biofuels, volumes reached about 60 mill gal in 2011, and we 

have projected in a separate Notice of Proposed Rulemaking for the applicable 2013 standards 

that they could reach 150 mill gal or more in 2013. As a result, most of the 2.75 bill gal 

advanced biofuel requirement will be met with biodiesel and imported sugarcane ethanol.

 

Recent market projections suggest that the volume of sugarcane ethanol that can be 

imported into the U.S. from Brazil in 2013 could be on the order of historical import volumes 

 

4

77 FR 1320
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prior to 2010, with the potential to reach the historical maximum or more5. However, there is 

considerable variability in the projections for 2013. 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).6 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 FAPRI 2011 Agricultural Outlook projects for the year 2013 that the 

U.S. will have net ethanol imports of 768 million gallons.7 As a result, while there is good 

reason to believe that there will be volumes of imported sugarcane ethanol in 2013 sufficient to 

meet the advanced biofuel standard, uncertainty in those volumes could create a demand for 

volumes of biodiesel in excess of 1.0 bill gallons. 

If we do not set the biomass-based diesel standard above 1.0 bill gallons, biodiesel 

producers will be less certain of the 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 volume requirement of 2.75 bill gal in 2013, the biodiesel 

industry would not be in an ideal position to make up the difference. 

Thus in setting the biomass-based diesel volume requirement at 1.28 bill gallons rather 

than at the statutory minimum of 1.0 bill gallons, 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, the potential for somewhat increased 

costs is appropriately balanced 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, described in more 

detail below, we believe that the biomass-based diesel standard of 1.28 bill gallons in 2013 is 

appropriate and in keeping with the goals of the statute.

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 

 

5 Historical maximum imports of ethanol were 730 mill gal in 2006. Total Brazillian exports of ethanol exceeded 

900 mill gal annual for 2006 - 2009.

6 U.S. Energy Information Administration (EIA). “AEO2011,” April 2011. 

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

7 Table "Ethanol Trade", Commodity Outlook/Biofuels, FAPRI-ISU 2011 World Agricultural Outlook. 

http://www.fapri.iastate.edu/outlook/2011/
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demand for biomass-based diesel in 2013. In some cases commenters ignored the fact that much 

of the advanced biofuel standard can be met with biodiesel or implicitly assumed that EPA 

would waive some portion of the advanced biofuel requirement. 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 a separate Notice of Proposed Rulemaking8, we are proposing to not reduce the 

2013 advanced biofuel requirement of 2.75 bill gal.

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 biofuel9. 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 of 2.75 bill gal 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 that the advanced biofuel requirement of 2.75 bill gal 

could place pressure on the industry to produce volumes of biodiesel in excess of 1.0 bill gal 

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 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 as described in Section II. 

Additionally, 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. In addition, increasing the biomass-based diesel volume requirement to 1.28 bill gal in 

2013 serves the long term goal of the statute to increase volumes of renewable fuels over time 

such that in the longer term they are more likely to be available to offset the need for crude oil.

 

8 This NPRM will propose the applicable 2013 percentage standards for cellulosic biofuel, biomass-based diesel, 

advanced biofuel, and total renewable fuel.

9 Communication with W. Brown, Energy Information Administration
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B. Availability of Feedstocks to Produce 1.28 Billion Gallons of Biodiesel

In the NPRM, we provided our assessment of the types and amounts of feedstock 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 Insight10. The feedstock estimates from these two sources are 

shown in Table IV.B-1.

Table III.B-1

Feedstock Sources (in mill gallons) That May Contribute to 2013 Volume of 1.28 bill 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 comments 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 feedstock sources that would support that volume. Nevertheless, we 

believe that these sources suggest two similar ways that the market could meet the demand for 

feedstock under a required volume of 1.28 bill gallons of biomass-based diesel. The actual mix 

of feedstock sources used to produce 1.28 bill gallons of biomass-based diesel could also differ 

substantially from the values shown in Table III.B-1 as the market adjusts to the new mandate. 

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 feedstock sources and, as 

described below, the updated analysis confirms our belief that the projections in Table III.B-1 are 

reasonable projections for the mix of feedstock sources that could be used to reach 1.28 bill 

gallons of biomass-based diesel. Other comments agreed with our assessment of available 

feedstock 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 

feedstock sources is included below. 

1. Grease and Rendered Fats

 

10 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 gallons11. 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 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 do 

not have the authority to prevent feedstocks that meet the statutory definition of renewable 

biomass from being used in the production of renewable fuel. The choice of which feedstocks 

will be used to produce biomass-based diesel will be determined by the market. We also note 

that in responding to comments to the rule establishing the RFS2 program, we acknowledged 

that animal fat can be used in other markets such as the soap industry, but that the diversion of 

some portion of this feedstock to the biofuels industry was both not prohibited and would not 

significantly impact the GHG assessment of biofuel made from this feedstock12. However, based 

on our assessment, it is possible that the 1.28 bill gall requirement could be met without the use 

of animal fats. As noted above, the total volume of grease and rendered fats is estimated at 800 

mill gallons, far above the volumes listed in Table III.B-1. It is therefore possible that the 

industry may produce biodiesel predominately from waste grease instead of animal fats. 

Moreover, the volumes of other feedstock sources, such as corn oil and vegetable oils as 

described more fully below, may exceed the volumes needed to produce 1.28 bill gal biodiesel, 

further reducing the need to rely on animal fats for biodiesel production. Finally, EPA has 

received inquiries from industry regarding the use of additional sources of waste oils often from 

the food processing industry as biodiesel feedstock, indicating the sources of feedstock are likely 

to continue expanding, improving the availability of alternatives to animal fat as a biofuel 

feedstock.

Since the market will determine how much animal fats are used in the production of 

biofuels, we cannot project how their availability for the production of oleochemicals might be 

affected. We agree with the American Cleaning Institute that increases in the use of animal fats 

 

11 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 The 

U.S. Census Bureau terminated collection of data for this report as of July 2011 so updated data is not available.

12 "Renewable Fuel Standard Program (RFS2) Summary and Analysis of Comments," February 2010, EPA-420-R003, pages 6-15 and 7-304.
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to produce biofuel could increase the price of those animal fats and/or reduce their availability 

for the production of oleochemicals. Such circumstances could in turn compel the oleochemical 

industry to use a greater fraction of alternative feedstock sources such as cottonseed oil. Given 

that we are projecting that a mandate for 1.28 bill gal biomass-based diesel would increase jobs 

in the biodiesel industry, we believe it is likely that on balance for all industries using animal fats 

as feedstocks, the total number of jobs will not decrease but will at least remain approximately 

constant or could even increase.

2. Corn Oil

The RFS2 final rule projected that by 2013, 34% of all dry mill ethanol facilities in the 

U.S. would extract inedible 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 2012.13 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 years14. In the 

NPRM we 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 in the U.S. were extracting inedible 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. 

3. 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 

 

13 Joseph Riley, "Customized Coproducts Needed as Industry Matures," June 6, 2011. Ethanol Producer Magazine.

14 Dave Elsenbast quoted in Ron Kotrba, “Biodiesel from corn oil: a growing force,” July 6, 2011. Biodiesel 

Magazine.
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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 III.B.3. The rest of 

this section summarizes our assessment of soybean oil availability, updated since the NPRM.

Since the RFS2, other oilseeds (e.g., canola oil) have emerged as potential sources of 

biodiesel feedstock. However, the U.S. market for soybean oil biodiesel is significantly more 

mature than for biodiesel made from other oilseeds. Because of this, we anticipate that soybeans 

will remain the primary source of U.S. biodiesel from oilseeds in 2013. It is possible that 

biodiesel production from other oilseeds such as canola could achieve a significant level of 

production by 2013. If other oilseeds with approved pathways are able to contribute to the 

biodiesel volumes, achieving the biomass based diesel mandate would be facilitated. For the 

purposes of this analysis, EPA is making the conservative assumption that there will be no 

biodiesel production from other oilseeds in 2013.

We examined historical and projected soybean oil supplies and use to verify that the 

volumes shown in Table III.B-1 are achievable in 2013. Our analysis concludes that there will 

be sufficient supplies of soybean oil to meet the needs of both biodiesel production and other 

domestic uses in 2013. Producing 600 million gallons of soybean-based biodiesel will require 

4,530 million pounds of soybean oil. 

Table III.B.3-1 below lists U.S. Department of Agriculture (USDA) historical data and 

current projections for U.S. supply and use of soybean oil from the 2006/2007 crop year to the 

2013/2014 year. Since 2006/2007, domestic use of soybean oil for non-biodiesel purposes has 

ranged from 14,134 million pounds to 15,813 million pounds. USDA projects non-biodiesel use 

will stay above 14,000 million lbs through the 2013/2014 year.

Table III.B.3-1

Historical Supplies and Use of Soybean Oil in the U.S. (in million lbs)

Year Starts 

October 1

Total 

Supplies

Domestic Use 

for NonBiodiesel 

Purposes

Supplies 

Available for 

Biofuel 

Feedstock 

Use or Export

Historical 

Exports

Historical 

Biofuel 

Feedstock 

Use

2006/07 23,536 15,813 7,723 1,877 2,762

2007/08 23,730 15,089 8,641 2,911 3,245

2008/09 21,319 14,196 7,123 2,193 2,069

2009/10 22,578 14,134 8,444 3,359 1,680

2010/11 22,452 14,244 8,208 3,233 2,550

2011/12a21,215 14,100 7,115 * *

2012/13a21,075 14,200 6,875 * *

2013/14a21,290 14,400 6,890 * *

a Projected volumes.

Sources: USDA, Agricultural Marketing Service, Oil Crops Outlook, February 10th, 2012. USDA, Economic 

Research Service, Agricultural Long-Term Projections, February 2012.
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USDA projects that 6,875 million pounds of soybean oil will be available for biofuel 

feedstock use or export in the 2012/2013 crop year and that 6,890 million pounds will be 

available in the 2013/2014 year (see Table III.B.3-1). This is considerably more than the 4,530 

million pounds needed to meet the soybean-based biodiesel portion of the 1.28 billion gallon 

mandate. For this reason, EPA does not anticipate any shortage in availability of soybean oil 

feedstock for biodiesel production.

4. Effects on Food Prices

In order to determine the likelihood of a substantial increase in food prices, EPA 

projected the effects of a 1.28 billion gallon mandate using the CARD stochastic modeling 

framework discussed in Section IV.B.1. of this final rule. Assuming that the 280 million gallon 

increment is met entirely with soybean oil biodiesel in 2013, EPA projects that the price of 

soybean oil will be $0.45 per pound under this proposed mandate, compared to $0.42 under a 1.0 

bill gal volume requirement. This represents a price increase of 3 cents per pound (about 7 

percent). The increase in demand for soybean oil is also expected to have a small impact on the 

price of soybeans. EPA projects that the price of soybeans will be $10.39 per bushel under this 

mandate, compared to $10.21 per bushel under a 1.0 bill gal volume requirement. This 

represents a price increase of 18 cents per bushel (about 1.8 percent). Both of these projections 

are within the recent historical range of prices (see Table III.B.4-1).

Table III.B.4-1

Historical and Projected Prices of Soybeans and Soybean Oil 

(2010 dollars per lb)

Soybean Oil Soybeans

2006-2011 Low Annual Average Price $0.33 per lb $9.70 per bushel

2006-2011 High Annual Average Price $0.54 per lb $12.36 per bushel

2013 Projected Price $0.45 per lb $10.39 per bushel

2022 Projected Price $0.42 per lb $9.36 per bushel

Sources: USDA, Agricultural Marketing Service, Oil Crops Outlook, February 10th, 2012. USDA, Economic 

Research Service, Agricultural Long-Term Projections, February 2012.

The timeframe of this rulemaking did not permit large-scale modeling of the impacts of 

this proposed mandate on the agricultural sector. We therefore cannot predict the exact impact 

that these increases in soybean and soybean oil prices will have on food prices in general. 

However, given that projected prices for soybeans and soybean oil fall within the range of recent 

historical prices, EPA does not expect that the 1.28 bill gal mandate to cause any significant 

variations in food prices. As noted above, these results assume that 680 mill gal of this mandate 

is soybean-based. To the extent that this increment is met with other feedstocks, the overall 

effect of this mandate on the price of soybeans and soybean oil would be smaller. Further, 

USDA currently predicts a long-run decline in soybean and soybean oil prices over the next 

decade. Soybean prices are predicted to decline from the historical peak of $12.36 per bushel in 

2011 to $9.36 per bushel by the beginning of 2022 (in 2010 dollars). The price of soybean oil is 

predicted to decline from a 2010 peak of $0.54 per pound to $0.42 per pound by the beginning of 

2022. EPA projections fit within this general decline in prices, further bolstering the assessment 

that this mandate will not significantly affect food prices. Finally, as part of our analysis for the 
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RFS2 final rule, EPA estimated that the total impact of the program on food prices from all 

sources would be about $10 per person.15 Given that this proposed increase of 110 mill gal 

represents less than 1 percent of the 36 bill gal of biofuels analyzed for that rule, this analysis 

also indicates that the effects on food prices stemming from this proposed mandate will be 

minimal.

5. Other Bio-oils

Although the modeling we conducted for the RFS2 final rule assumed that the only form 

of bio-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 oil16. The volume of 

biodiesel made from canola oil was 96 mill gallons in 200817. In addition, we are evaluating 

other pathways for the production of biodiesel from oilseeds which could potentially be 

approved for RIN generation by 2013. On January 5, 2012 we proposed to include oil from 

camelina as an approved feedstock for producing biodiesel (77 FR 462). Algal oil could also 

provide additional feedstocks if promising technologies for production are commercialized. 

Nevertheless, even if none of these other sources of bio-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.

C. Production Capacity

Total production capacity of the biodiesel industry has exceeded 1.28 bill gallons for a 

number of years. As of February 2012, total production capacity was more than 2.5 bill gallons 

for 191 companies18. According to the EPA registration database, 216 facilities have registered 

with the EPA under the RFS2 program as of March 15, 2012. 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 comments 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 

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 

 

15 Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis, Chapter 5: Economic Impacts and 

Benefits, Section 5.1 Agricultural Impacts, 2010.

16 75 FR 59622

17 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

18 Plant list from National Biodiesel Board, 2/7/2012.
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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 so19, we also believe that pre-existing but idled plants can be restarted in considerably 

less than a year. Given the time between release of this action and when the 1.28 bill gal 

requirement will become effective, there is no reason to believe that idled plants cannot be 

restarted in time to contribute meaningfully to total volumes in 2013.

D. 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 area where biodiesel must be marketed would correspondingly be 

greater, 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. As 

described below, we believe that there are no impediments to consuming an additional 280 mill 

gal of biodiesel.

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 B520. 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 during the winter 

months through blending with lighter grades (i.e., #1 diesel fuel), the cloud point of biodiesel 

generally requires more dramatic interventions such as heated storage tanks, lines, and blending 

equipment, as well as heating rail cars and tank trucks. However, some of these biodiesel cloud 

 

19 Based on construction times for new plants listed in Biodiesel Magazine from July 2006 through May 2009.

20 "Automaker's' and Engine Manufacturers' Positions of Support for Biodiesel Blends," Biodiesel.org
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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 2.9% of all diesel fuel

21. If all 

biodiesel were to be blended as B5, almost 60% 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%.22 If the volumes of 

biodiesel currently sold as B10 and higher were to continue to be sold in 2013, such blends 

would account for about one quarter of the 1.28 bill gal mandate, and 45% of the diesel fuel 

consumed nationwide in 2013 would contain biodiesel.

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 are 

achievable. As shown in Table III.D-1, a number of states already have mandates for the use of 

biodiesel in 201323, and efforts are underway by the production and distribution industries to 

meet these mandates. 

 

21 Assumes total diesel volume consumed in the transportation sector in 2013 is 44.86 bill gal, per Annual Energy 

Outlook (AEO) 2012 Early Release, Table A2.

22 National Biodiesel Board, Retailing Fueling Sites, as of February 17, 2011. 

http://biodiesel.org/buyingbiodiesel/retailfuelingsites/default.shtm

23 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 III.D-1

States with Biodiesel Mandates

Minnesota Diesel fuel for use in internal combustion engines must contain at least 5% 

biodiesel. Beginning May 1, 2012, during the months of April through October, 

diesel fuel must contain at least 10% biodiesel (B10). 

Oregon Diesel fuel sold in the state must be blended with at least 5% biodiesel. 

Washington At least 2% of all diesel fuel sold in Washington must be biodiesel or renewable 

diesel. This requirement will increase to 5% after it is determined that in-state 

feedstock sources and oil-seed crushing capacity can meet a 3% requirement. 

Pennsylvania All diesel fuel sold in Pennsylvania must contain at least 2% biodiesel one year 

after in-state production of biodiesel reaches 40 million gallons. The mandated 

biodiesel blend level will increase to 5% biodiesel one year after in-state 

production of biodiesel reaches 100 million gallons.

New Mexico After July 1, 2012, all diesel fuel sold to consumers for use in on-road motor 

vehicles must contain at least 5% biodiesel. This requirement may be suspended 

for up to six months under certain conditions.

Louisiana Within six months following the point at which cumulative monthly production of 

biodiesel produced in the state equals or exceeds 10 million gallons, at least 2% of 

the total diesel volume must be biodiesel.

Source: U.S. Department of Energy, Alternative Fuels and Advanced Vehicles Data Center

Collectively, these states currently account for approximately 13 percent of the nationwide 

consumption of diesel. Other states that have implemented other forms of incentives are listed in 

Table III.D-2.

Table III.D-2

States with Rebates, Refunds, Reduced Tax Rates, or

Credits for Biodiesel Production or Blending

Illinois

Indiana

Kansas

Kentucky

Maine

Maryland

Michigan

Montana

North Dakota

Oklahoma

Rhode Island

South Carolina

South Dakota

Texas

Virginia

Washington

Source: U.S. Department of Energy, Alternative 

Fuels and Advanced Vehicles Data Center

* Conditions and exemptions for all incentive 

programs vary by state
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Collectively, the states listed in Table III.D-2 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.

Based on our review of the ability of diesel engines to use diesel blended with biodiesel, 

and the various state requirements and incentives to use biodiesel, we believe that consumption 

of 1.28 bill gal of biodiesel will not be problematic.

E. 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%.24 This is consistent with our analysis of the additional biodiesel 

distribution infrastructure that will be needed. NPRA commented that the required increase in 

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.25 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.

We proposed finding that there will be sufficient fuel distribution infrastructure available 

to support the use of 1.28 bill gal of biomass-based diesel in 2013. NPRA stated that the rapid 

 

24 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. NPRA recently changed its name to the 

American Fuel & Petrochemical Manufacturers (AFPM).

25 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. 
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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.26 

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 2013 

biodiesel volume. Industry activities are currently progressing to meet the biomass-based diesel 

volume requirement for 2012. We anticipate such efforts will continue to be successful in 

supporting the required biodiesel volume for 2013.

Our evaluation of the changes to the fuel distribution infrastructure that will be needed to 

support the use of 1,280 million gallons/yr in 2013 is based on the analysis conducted for the 

RFS2 final rule.27 See Table III.E-1.

Table III.E-1

Additional Infrastructure Needed to Distribute Biodiesel in 2013

Additional 

Distribution Assets 

Needed in 2013 

Relative to 2012

Total Distribution 

Assets Needed to 

Support 1.28 bill gal 

Biodiesel Volume

Petroleum Product 

Terminals with Biodiesel 

Blending Capabilitya

130 558

Rail Cars 230 984

Tank Trucks 25 108

Barges 7 29

a 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 price contained 

in Section IV.B.1.d. 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 

 

26 NBB did not provide an analysis regarding the addition of new biodiesel distribution facilities. 

27 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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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, 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 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 a 

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).28 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 

 

28 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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the locations where it is blended with petroleum-based diesel fuel. This is based on each tank 

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 one shift 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. 

IV. 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 II), 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 an appropriate 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.

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. 

The statute envisions annual increases in applicable volumes of renewable fuels leading 

to 36 bill gallons by 2022. In considering potential increases in the applicable volume 

requirement for biomass-based diesel, we believe that certain factors that we must consider under 

the statute are most appropriately analyzed in the longer term, after the full build-up of 

renewable fuel production and use envisioned by the statute are in place. Others factors are more 

appropriately analyzed for the near term, including production capacity, availability of 

feedstocks, and impacts on infrastructure. These are factors that could limit the successful 

implementation of any increment in required applicable volume. We believe that other factors 

are appropriately considered over a longer term, since full build-up of the RFS program is 

expected to generate benefits over many years, and short-term considerations should not impede 

attainment of long term goals and benefits. We believe that greenhouse gas emissions are one 

factor for which taking a long-term view is appropriate. Finally, certain factors, such as energy 

security, may be evaluated for both near- and long-term benefits. Thus for this final rule, we 

have not simply looked at the impacts of the program in any one year with near term 

implementation, but have also looked at the evolving pattern of impacts through time where it is 

appropriate to do so.
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Some of the analyses presented in the RFS2 final rule were for the specific case of 1.28 

bill gallons in 2013. These analyses included an investigation of the expected annual rate of 

commercial production of biomass-based diesel in 2013, impacts on agricultural commodity 

supply and price, and the cost to consumers of transportation fuel. Some of these were discussed 

in Section III 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, which was compared to a reference 

case biodiesel volume of 380 mill gallons. These cases are shown in Table IV-1.
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Table IV-1

Primary 2022 Reference and Control Cases from RFS2 Final Rulemaking (billion gallons)

Advanced Biofuel Non-Advanced 

Biofuel Total 

Renewable 

Fuel

Cellulosic Biofuel Biomass-Based Diesel Other Advanced Biofuel

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.
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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 are required 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). The RFS2 final 

rule analysis considers impacts from the entirety of the renewable fuel mandates, as opposed to 

impacts resulting solely from the biodiesel portion of the mandates. 

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 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) is about twice as 

high as 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).

As described in Section III, we believe that the industry can increase production to at 

least 1.28 bill gallons by 2013, that sufficient feedstock 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.

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, the RFS is a 

forward-looking program that focuses on long-term changes in the fuels sector. For this reason, 

it is not appropriate to emphasize specific interim year impacts in cases where these impacts are 

transient and continually changing. However, in some cases we have been able to analyze a 

2013 impact and compare it to the 2022 impact analyzed for the RFS2 final rule. In other cases 

we have used trends used to derive our 2022 assessments to indicate likely impacts in 2013. 

Since the NPRM, EPA has conducted a specific analysis of the effects of the 2013 mandate on 

the biofuels market. This analysis is detailed in Section IV.B of this rulemaking. This analysis 

was conducted in response to comment about quantifying some of the costs and benefits of this 

rule. However, it also addresses API’s concerns by providing a year-specific analysis. 

We recognize that uncertainties remain regarding how markets for soybeans and other 

crops will react to a mandate of 1.28 bill gallons for biomass-based diesel. For instance, the 

volume of soybean oil required to meet the mandate will likely be higher in 2013 than it has been 

in 2011. As a result, there may be upward pressure on soybean oil prices, which we consider in 
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Section III.B of this rulemaking. Nevertheless, we expect that RIN prices will adjust in the 

market to provide the economic incentive for the mandate to be met. As described in the 

rulemaking that established the RFS1 program, the RIN system was designed with this end in 

mind.

A. Consideration of Statutory Factors

1. Climate Change

Since biodiesel has a GHG benefit compared to the petroleum-based diesel it is replacing, 

an increase in biomass-based diesel of 0.28 bill gal from 2012 to 2013 will 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. 

One commenter suggested that increased biodiesel use would also reduce GHG emissions 

compared to sugarcane ethanol, an alternative advanced biofuel that would be used to meet the 

mandate. This statement is based on the specific GHG reductions associated with a gallon of 

biodiesel produced in 2022 that we estimated in our lifecycle analysis for different biofuels. 

However, for this rulemaking we are only considering the GHG impacts of the biomass-based 

diesel standard. Therefore, it is outside the scope of this rule to analyze the potential GHG 

emission impacts of displacing sugarcane ethanol with biodiesel. 

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 

“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 will be 

no additional quantities of other advanced fuels produced. 

EPA estimates the social benefits of regulatory actions that have a small or “marginal” 

impact on cumulative global CO2 emissions using the social cost of carbon dioxide (SC-CO2). 

The SC-CO2 is an estimate of the net present value of the flow of monetized damages from a one 

metric ton increase in CO2 emissions in a given year. Alternatively, this represents the benefit to 

society of reducing CO2 emissions by one ton.29 The SC-CO2 includes, but is not limited to, 

climate damages due to changes in net agricultural productivity, human health, property damages 

from flood risk, and ecosystem services. 

The SC-CO2 estimates currently used by the Agency were developed through an 

interagency process that included EPA and other executive branch entities and concluded in 

February 2010. The Technical Support Document: Social Cost of Carbon for Regulatory Impact 

 

29 In the absence of direct model estimates of the social cost of non-CO2 GHGs, the social cost of CO2 can be used to 

estimate those benefits on a CO2-e basis, as discussed further below.
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Analysis Under Executive Order 12866 for the final joint EPA/Department of Transportation 

Rulemaking to establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate 

Average Fuel Economy Standards provides a complete discussion of the methods used to 

develop the SC-CO2 estimates (Interagency Working Group on Social Cost of Carbon, 2010) 

(hereafter, “2010 TSD”). 

To monetize global social benefits of reduced CO2 emissions, the interagency group 

selected four SC-CO2 estimates for use in regulatory analysis. In 2013, these are: $6, $24, $39, 

and $73 per metric ton of CO2 emissions in 2013 (in 2010 dollars). The first three values are 

based on the average SC-CO2 from three integrated assessment models, at discount rates of 5, 3, 

and 2.5 percent, respectively. SC-CO2s at several discount rates are included because the 

literature shows that the SC-CO2 is quite sensitive to assumptions about the discount rate, and 

because no consensus exists on the appropriate rate to use in an intergenerational context. The 

fourth value is the 95th percentile of the SC-CO2 from all three models at a 3 percent discount 

rate. It is included to represent higher-than-expected impacts from temperature change further 

out in the tails of the SC-CO2 distribution. The “central value” is the average SCC across models at 

the 3 percent discount rate. For purposes of capturing the uncertainties involved in regulatory impact 

analysis, we emphasize the importance and value of considering the full range.

The 2010 interagency SCC technical support report discusses a number of important 

limitations for which additional research is needed. In particular, the document highlights the 

incomplete way in which the integrated assessment models capture catastrophic and non-catastrophic 

impacts, their incomplete treatment of adaptation and technological change, uncertainty in the 

extrapolation of damages to high temperatures, and assumptions regarding risk aversion. The limited 

amount of research linking climate impacts to economic damages makes this modeling exercise even 

more difficult. The interagency group recommended that the SCC estimates used for regulatory 

analysis by the Federal government be revisited and continue to evolve with improvements in modeling.

The SC-CO2 increases over time because future emissions are expected to produce larger 

incremental damages as physical and economic systems become more stressed in response to 

greater climatic change. For example, by 2022 the four estimates increase to $8, $29, $45, and 

$88 per metric ton of CO2 emissions (in 2010 dollars). Note that the interagency group 

estimated the growth rate of the SCC directly using the three integrated assessment models rather 

than assuming a constant annual growth rate. This helps to ensure that the estimates are 

internally consistent with other modeling assumptions. The Table below presents the four 

estimates for the years 2013 through 2022.

Table IV.A.1-1

Benefit per Metric Ton CO2 Reduced, 2013-2022 ($2010)a

Year

Discount Rate (Statistic)

5% (Avg) 3% (Avg) 2.5% (Avg) 3% (95th %ile)

2013 $6 $24 $39 $73

2014 $6 $24 $39 $74

2015 $6 $25 $40 $76

2016 $6 $25 $41 $78

2017 $6 $26 $42 $79
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2018 $7 $26 $42 $81

2019 $7 $27 $43 $83

2020 $7 $28 $44 $84

2021 $7 $28 $45 $86

2022 $8 $29 $45 $88

a The SC-CO2 values vary depending on the year of CO2 emission and are defined in real terms. The change from 

year to year is not obvious in this table because estimates are rounded to the nearest dollar.

Today’s rulemaking also analyzes reductions in non-CO2 GHGs. The 2010 interagency 

work group, however, did not directly estimate the social cost of non-CO2 GHGs. In the absence 

of direct model estimates from the interagency analysis, EPA has used a “global warming 

potential (GWP) approach” to estimate the dollar value of this rule’s non-CO2 GHG benefits. 30 

This approach is consistent with the methodology used in the final RFS2 rulemaking, which was 

finalized prior to the 2010 interagency work group process. Specifically, EPA converted 

methane and nitrous oxide to CO2 equivalents using the GWP of these gases, then multiplied 

these CO2-equivalent emission reductions by the interagency social cost of carbon dioxide 

estimates. Furthermore, EPA has used the 100-year GWP estimates from the IPCC Second 

Assessment Report (SAR) to estimate the methane and nitrous oxide benefits for this rule. The 

use of the SAR GWP values allows comparability of data collected in this final rule to the 

national GHG inventory that EPA compiles annually to meet U.S. commitments to the United 

Nations Framework Convention on Climate Change (UNFCCC).

As discussed in a recent working paper (Marten and Newbold, 2011)31, the GWPweighted benefit estimates for methane and nitrous oxide are likely to be lower than those that 

would be derived using a directly modeled social cost of the non-CO2 GHGs for a variety of 

reasons.

32

 In sum, the authors find that an integrated assessment model produces higher 

estimates of the social cost of methane and nitrous oxide than the GWP approach because the 

model captures the effect of temperature changes on economic output over time, whereas GWP 

is based only on physical impacts. 

EPA established in the RFS2 final rule that a gallon of soybean-based biodiesel results in 

an annualized GHG emission reduction of 57 percent compared to the 2005 petroleum baseline 

(approximately 0.0065 tons of CO2 equivalent per gallon). This GHG reduction is calculated by 

estimating the annualized emissions streams over 30 years, starting in 2022 (the year when the 

RFS2 program will be fully implemented). For this reason, it may not be appropriate to include 

any benefits from GHG reductions in our 2013 calculations. This is not because EPA believes 

that the GHG benefits in 2013 will be zero, but rather because it may not be consistent to cite 

 

30 For a longer discussion of the GWP approach, see the Regulatory Impact Analysis associated with the New 

Source Performance Standards and Amendments to the National Emissions Standards for Hazardous Air Pollutants 

for the Oil and Natural Gas Industry, issued on April 17, 2012. See 

http://www.epa.gov/airquality/oilandgas/actions.html. 

31 Marten, A. and S. Newbold. 2011. “Estimating the Social Cost of Non-CO2 GHG Emissions: Methane and

Nitrous Oxide.” NCEE Working Paper Series # 11-01. 

http://yosemite.epa.gov/ee/epa/eed.nsf/WPNumber/2011-01?opendocument

32 As discussed in Marten and Newbold, the discount rate influences whether directly modeled social cost estimates 

are higher than those estimated with the GWP approach. Methane is a short-lived gas and therefore direct modeling 

results in higher social costs at higher discount rates than the GWP approach. 
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them for an interim year of the program using lifecycle biofuel assessments based on a 2022 

analyses. 

To monetize the global SC-CO2 value, we use the same stream of emissions for both 

2013 and 2022 that were estimated for the RFS2 final rulemaking. We then apply the 

appropriate SC-CO2 dollar values to each year (i.e., we apply the 2015 SC-CO2 value to a stream 

in 2015, the 2028 value to a stream in 2028). These benefits are then totaled, discounted to net 

present value using the applicable discount rate, and divided by 30 to place the estimate back on 

a per gallon basis. The resulting estimates are provided in the table below for 2013 and 2022.33 

Table IV.A.1-2

Monetized per Gallon CO2-e Annualized Benefits of Biomass-Based Diesel Produced in 2013 

and 2022 ($2010)

YEAR ANNUALIZED

EMISSIONS

REDUCTION 

(TONS OF CO2-

eq/ GALLON)

BENEFITS

5% (Avg) 3% (Avg) 2.5% (Avg) 3% (95th 

%ile)

2013 0.0065 $0.02 $0.12 $0.21 $0.37

2022 0.0065 $0.03 $0.14 $0.23 $0.43

Estimates represent the CO2-eq estimate of carbon dioxide, methane, and nitrous oxide reductions multiplied by the 

SCC estimates (“GWP approach”). CO2-eq for methane calculated using the GWP of 21 (SAR). These co-benefit 

estimates are not the same as would be derived using a social cost of methane directly computed from integrated 

assessment models. See Marten and Newbold (2011) for discussion of the limitations of the GWP approach.

 

2. Energy Security

This final standard will assure an increased use of biomass-based diesel in the U.S. and 

help to reduce U.S. petroleum imports. Reducing U.S. petroleum imports lowers both the 

financial and strategic risks caused by potential sudden disruptions in the supply of imported 

petroleum to the U.S. The economic value of reductions in these risks provides a measure of 

improved U.S. energy security. This section summarizes EPA’s estimates of U.S. oil import 

reductions and energy security benefits from this rule. 

In 2010, U.S. petroleum import expenditures represented 14 percent of total U.S. imports 

of all goods and services.34 These expenditures rose to 18 percent by April of 2011.35 In 2010, 

the United States imported 49 percent of the petroleum it consumed36, and the transportation 

sector accounted for 71 percent of total U.S. petroleum consumption. This compares to 

approximately 37 percent of total U.S. petroleum supplied by imports and 55 percent of U.S. 

 

33 Tables IV.A.1-1 and IV.A.1-2 provide summary details about the global SC-CO2 values and emissions streams 

used in our calculations. Additional details are included in a Memorandum to the Docket, Docket ID XXX, Dated 

May XX, 2012.

34 http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WTTIMUS2&f=W 35 http://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_ep00_im0_mbblpd_a.htm

36 http://www.eia.gov/dnav/pet/pet_pri_rac2_dcu_nus_m.htm
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petroleum consumption in the transportation sector in 1975. Requiring higher volumes of 

renewable fuels to be used in the U.S. is expected to lower U.S. oil imports. 

This rule will require an additional 280 million gallons of biodiesel to be produced, 

which equals about 255 million gallons of diesel equivalent.37 Based on analysis of historical 

and projected future variation in U.S. petroleum consumption and imports, we estimate that 

approximately 50 percent of the reduction in fuel consumption resulting from adopting 

renewable fuels is likely to be reflected in reduced U.S. imports of refined fuel, while the 

remaining 50 percent is expected to be reflected in reduced domestic fuel refining. Of this latter 

figure, 90 percent is anticipated to reduce U.S. imports of crude petroleum for use as a refinery 

feedstock, while the remaining 10 percent is expected to reduce U.S. domestic production of 

crude petroleum. Thus, on balance, each gallon of fuel saved as a consequence of the renewable 

fuel standards is anticipated to reduce total U.S. imports of petroleum by 0.95 gallons.38 

Therefore, this rule reduces imports of petroleum by about 242 million gallons. Table IV.A.2-1 

below compares EPA’s estimates of the reduction in imports of U.S. crude oil and petroleumbased products from this program to projected total U.S. imports for the years 2013 and 2022. 

Table IV.A.2-1

Projected Import Reductions from this Rule and Total U.S. Petroleum-Based Imports in 

2013 and 2022 (Millions of Barrels)

Year

U.S. Petroleum-Based 

Import Reductions 

from the Rule

(million barrels/yr)

U.S. Total PetroleumBased Imports without 

the Rule

(million barrels/yr)

2013 5.8 3,391

2022 5.8 2,964

In order to understand the energy security implications of reducing U.S. petroleum 

imports, EPA worked with Oak Ridge National Laboratory (ORNL), which has developed 

approaches for evaluating the economic costs and energy security implications of oil use. The 

energy security estimates provided below are based upon a methodology developed in a peerreviewed study entitled, ”The Energy Security Benefits of Reduced Oil Use, 2006-2015,” 

completed in March 2008. This study is included as part of the docket for this rule.39,40

When conducting its analysis, ORNL considered the full economic cost of importing petroleum 

into the United States. 

The economic cost of importing petroleum into the U.S. is defined to include two 

components in addition to the purchase price of petroleum itself. These are: (1) the higher costs 

 

37 RFS2 Final Rulemaking

38This figure is calculated as 0.50 + 0.50*0.9 = 0.50 + 0.45 = 0.95.

39 Leiby, Paul N., "Estimating the Energy Security Benefits of Reduced U.S. Oil Imports" Oak Ridge National 

Laboratory, ORNL/TM-2007/028, Final Report, 2008. (Docket EPA-HQ-OAR-2010-0162)

40 The ORNL study “The Energy Security Benefits of Reduced Oil Use, 2006-2015," completed in March 2008, is an 

update version of the approach used for estimating the energy security benefits of U.S. oil import reductions 

developed in an ORNL 1997 Report by Leiby, Paul N., Donald W. Jones, T. Randall Curlee, and Russell Lee, 

entitled “Oil Imports: An Assessment of Benefits and Costs." (Docket EPA-HQ-OAR-2010-0162)
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for oil imports resulting from the effect of increasing U.S. import demand on the world oil price 

and on the market power of the Organization of Petroleum Exporting Countries (i.e., the 

“demand” or “monopsony” costs); and (2) the risk of reductions in U.S. economic output and 

disruption of the U.S. economy caused by sudden disruptions in the supply of imported 

petroleum to the U.S. (i.e., “macroeconomic disruption/adjustment costs”). 

An often-identified component of the full economic costs of U.S. oil imports is the cost to 

U.S. taxpayers of existing U.S. energy security policies. The two primary components of this 

cost are likely to be (1) the expenses associated with maintaining a U.S. military presence – in 

part to help secure a stable oil supply – in potentially unstable regions of the world; and (2) costs 

for maintaining the U.S. Strategic Petroleum Reserve (SPR). The SPR is the largest stockpile of 

government-owned emergency crude oil in the world. 

The EPA recognizes that potential national and energy security risks exist due to the 

possibility of tension over oil supplies. Much of the world’s oil and gas supplies are located in 

countries facing social, economic, and demographic challenges, thus making them even more 

vulnerable to potential local instability. Thus, to the degree to which this final rule reduces 

reliance upon imported energy supplies that can be deployed by either consumers or the nation’s 

defense forces, the United States could expect benefits related to national security and increased 

energy supply. Although the Agency recognizes the clear benefit to the United States from 

reducing dependence on foreign oil, the Agency has been unable to calculate the monetary 

benefit that the United States will receive from the improvements in national security expected to 

result from this program. 

Also, while the costs of building and maintaining the SPR are clearly related to U.S. oil 

use and imports, these costs have not varied historically in response to U.S. oil import levels. 

Thus, the costs of maintaining the SPR are excluded from this analysis. In addition, given the 

redistributive nature of this monopsony effect from a global perspective, it is excluded in the 

energy security benefits calculations for this rule. In contrast, the other portion of the energy 

security premium, the U.S. macroeconomic disruption and adjustment cost that arises from U.S. 

petroleum imports, does not have offsetting impacts outside of the U.S. and, thus, is included in 

the energy security benefits estimated for this rule. To summarize, EPA has included only the 

macroeconomic disruption portion of the energy security benefits to estimate the monetary value 

of the total energy security benefits of this program. 

 The energy security premiums for the year 2013 and 2022 are presented in Table 

IV.A.2-2 as well as a breakdown of the components of the energy security premiums for those 

years. These energy security premiums are recorded on a dollar per barrel of oil imported 

reduced from this rule. On a gallon of biodiesel fuel basis, these translate into a $0.15/gallon 

benefit in 2013 and a $0.16/gallon benefit in 2022 for the macroeconomic disruption and 

adjustment costs component of the energy security premium (in 2010$).

Table IV.A.2-2

Energy Security Premiums in 2013 and 2022 (2010$/Barrel)
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Monopsony Macroeconomic 

Disruption/Adjustment Costs

Total Mid-Point

2013 $11.40

($3.83 - $19.40)

$7.13

($3.41 - $10.35)

$18.53

($10.03 - $26.74)

2022 $9.82

($3.27-$16.77)

$7.84

($3.80-$11.30)

$17.66

($9.88-$24.99)

Note: Values in parentheses represent a 90% confidence interval around the central value.

Using EPA’s fuel consumption analysis in conjunction with ORNL’s energy security 

premium estimates, the agency has developed estimates of the total energy security benefits for 

the year 2013 and 2022 in Table IV.A.2-3. 

Table IV.A.2-3

Energy Security Benefits in 2013 and 2022 (2010$) 

U.S. Oil 

Imports 

Reduced

(million 

barrels/yr)

Benefits

($ Millions)

2013 5.8 $41.2

2022 5.8 $45.5

One commenter suggested that an increase in biodiesel for the mandate is statistically 

insignificant. EPA interprets this comment to mean that the increase in biodiesel production due 

to this rule is not a sufficiently large volume that it will add significantly to the energy security 

position of the U.S. EPA’s analysis of energy security is conducted on a per gallon basis, and 

per gallon estimates are extrapolated upwards to estimate the total energy security benefits 

estimate in Table IV.A.2-3. Thus, we assume that each extra gallon of biodiesel has an equal 

energy security benefit regardless of the overall size of the renewable fuels volume requirement. 

Thus, total energy security benefits are increasing with this rule.

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, 

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 
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analysis, current academic research, and a reliance on accepted economic, agronomic, and 

biological relationships in agricultural production and markets.41

To meet the RFS2 renewable fuel volumes, a number of price effects on the agricultural 

commodities were estimated for 2022. For instance, FASOM estimated that an increase in 

renewable fuel volumes to meet the RFS2 will 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 will 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 feedstock 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 are less 

than those considered for 2022), the impact on soybean prices and exports from an increase to 

1.28 bill gall in 2013 should also be less. See Sections III.B.3 and IV.B.1.a of this rulemaking 

for further information on the impact on soybean availability and prices.

A recent report by IHS Global Insight42 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 will 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 that the price increases for soybean oil will be less than estimated for 

RFS2. Likewise, other price impacts, such as those on food prices, will still move in the same 

direction (i.e., an increase in price resulting from an increase in demand) but could be smaller 

than in the RFS2 analysis.

For the analyses performed for the RFS2 final rule, EPA estimated a $10 per person per 

year increase in food costs due to the total annual impact of the RFS2 program by 2022 

compared to a Reference case that assumed no RFS2 renewable fuel requirements. Again, the 

biodiesel impacts will represent only a small portion of these overall impacts and will likely be 

even smaller in 2013 due to the smaller volume of feedstock required. One commenter 

suggested that EPA should conduct a more thorough analysis of food price impacts of this rule. 

EPA has conducted an analysis projecting the amount of soybean oil that will be required to meet 

this mandate and the effect this will have on the prices of soybeans and soybean oil. The results 

of this analysis are discussed in detail in Sections III.B.3 and IV.B.1.a of this rule.

 

41

 CARD Staff, Technical Report: An Analysis of EPA Renewable Fuel Scenarios with the FAPRI-CARD 

International Models, December, 2009. Docket #: EPA-HQ-OAR-2005-0161-3177

42 "Biodiesel Production Prospects for the Next Decade," IHS Global Insight, March 11, 2011.
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4. Air Quality 

As described in the NPRM, we are relying on the analyses of renewable fuel impacts 

conducted in support of the RFS2 rule43 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.44

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 were not in place (the reference scenario).45 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.A.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).46 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.47 We 

expect the impacts of the 1.28 bill gal of biomass-based diesel volume relative to the 1.0 bill gal 

statutory minimum volume (which reflect a 0.28 bill gal increase) to be smaller. 

 

43 75 FR14670, March 26, 2010

44 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

45 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.

46 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.

47 While the national-level emissions and air quality impacts may be small, there may still be local and regional 

impacts that are larger in percentage terms. Our analysis is unable to capture this local and regional variability.
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Table IV.A.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 Upstream c

a

(tons)

Downstreamb

(tons)

Total 

(tons)

VOC -1,049 -2,422 -3,471 -0.03%

CO 913 -4,104 -3,191 -0.01%

NOx -290 1,346 1,056 0.01%

PM10 4,268 -569 3,699 0.10%

PM2.5 632 -315 317 0.01%

SO2 1,580 0 1,580 0.02%

NH3 4,171 0 4,171 0.10%

Benzene 10 -30 -20 -0.01%

Ethanol 0 0 0 0.00%

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

Acetaldehyde 2 -66 -65 -0.14%

Formaldehyde 1 -182 -181 -0.21%

Naphthalene -1 0 -1 -0.01%

Acrolein 63 -9 54 0.84%

aU.S. EPA 2010, Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis. 

EPA-420-R-10-006. February 2010. Docket EPA-HQ-OAR-2009-0472-11332. Table 3.2-

11. Note: units in Table 3.2-11 were mislabeled as tons/mmBTU. Actual units are tons. 

bU.S. EPA 2010, Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis. 

EPA-420-R-10-006. February 2010. Docket EPA-HQ-OAR-2009-0472-11332. Table 3.2-9.

cWhile the national-level emissions and air quality impacts may be small, there may still be 

local and regional impacts that are larger in percentage terms. Our analysis is unable to 

capture this local and regional variability.

The air quality analysis for the RFS2 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).48 

 

48 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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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.49,50 The air 

quality analysis assumed 0.81 bill gal of biodiesel in the RFS2 scenario compared to 0.38 bill gal 

of biodiesel in the reference scenario, reflecting a 0.43 bill gal increase in biodiesel use with the 

rule in place. We use the 0.43 bill gal increase in biodiesel assumed in the RFS2 air quality 

analysis to qualitatively discuss the potential impacts of a 0.28 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 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 will 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 investigate 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. Deliverability and Transport Costs of Materials, Goods, and Products Other Than 

Renewable Fuel

EPA evaluated in the RFS2 final rule the impacts on the U.S. transportation network from 

the distribution of the total additional volume of biofuels that will be used to meet the RFS2 

standards. Oak Ridge National Laboratory (ORNL) conducted an analysis of biofuel 

transportation activity from production plants to petroleum terminals by rail, barge, and tank 

truck to identify potential distribution constraints to help support the assessment in the RFS2 

final rule.51 The ORNL analysis concluded that the increase in biofuel shipments due to the 

RFS2 standards will 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 will constitute only 0.4% of the total freight tonnage for all 

commodities transported by the rail system through 2022.52 Given the small increase in freight 

 

49 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.

50 The RFS2 air quality analysis reflects EPA’s most recent air quality analysis applicable to changes in renewable 

fuel types and volumes.

51 “Analysis of Fuel Ethanol Transportation Activity and Potential Distribution Constraints”, Oak Ridge 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.

52 See sections 1.6.4 and 1.6.5 of the RFS2 RIA.
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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. 

6. 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 

analysis prepared by EPA in response to the requirements set out in CAA section 204. This 

report to Congress considers a range of impacts but the focus of the discussion here is on 

wetlands, ecosystems and wildlife habitats as directed by the CAA amendments. This report 

does not attempt to quantify the impacts of biofuel production and use as these impacts are 

dependent on local or regional conditions. Nevertheless the analyses contained in the report 

provide qualitative assessments and reasonable expectations of trends which can be used to 

consider the environmental impacts of increases in biodiesel production and use. These trends 

are only summarized here while the final report provides extensive detail.53

The assessment focuses on the use of oil from soybeans as the feedstock for biodiesel 

production. Other oil seed feedstock sources represent a very small portion of biofuel production 

in 2013 so will be expected to have much less of an impact than soy oil. Corn oil extracted 

during the ethanol production process is increasing, adding 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 supply of 

extracted corn oil is not considered here. Finally, waste fats, oils and greases are 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 Conservation Reserve Program (CRP) can significantly help control these adverse affects. 

Wetlands can also be adversely affected through diversion of surface and ground water for 

 

53U.S. EPA (Environmental Protection Agency). February 2012. “Biofuels and the Environment: First Triennial 

Report to Congress.” Office of Research and Development, Washington, DC. EPA/600/R-10/183F
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agricultural irrigation. Soybean production less frequently relies on irrigation than corn and 

some other crops. More discussion on water usage is included below in the section on water use 

and water quality impacts.

 Ecosystems and wildlife habitat can be adversely affected if CRP lands are converted to 

crop production, if row crops such as soybeans replace grassy crops and in general if new lands 

with diverse vegetation are converted to crop production. As explained in the RFS2 final rule, 

we do not expect the RFS program production to result in an increase in total acres of 

agricultural land under production in the 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. 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 the biomass-based diesel standard and sensitive lands will be protected via programs such as 

CRP, no measureable impact in aggregate ecosystems or wildlife habitat due to cropland 

expansion is expected.

Increased water withdrawals for soy biodiesel production can lead to more frequent lowflow conditions that reduce the availability for aquatic habitat. Additionally, waste water from 

biodiesel production can adversely affect surface water quality if not properly treated.

7. Water Quality and Quantity

The water quality and quantity impacts of biodiesel are primarily related to the type of 

feedstock and the production practices used both to produce the feedstock and to convert the 

feedstock into biodiesel. Soybeans are the principal feedstock used for biodiesel production 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 discussion updates the 

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. Additional pollutants such as 

from pesticides have the potential to impact water quality to a lesser degree. There are three 

major pathways for these potential pollutants to reach water from agricultural lands: runoff from 
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Page 43 of 68

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.54 Legumes have associations in their roots with 

bacteria that can acquire atmospheric nitrogen and convert it into bio-available forms, reducing 

the need for external addition of nitrogen fertilizer. However, losses of nitrogen and phosphorus 

from soybeans can occur at quantities that can degrade water quality.55 In 2006, USDA’s NASS 

estimated that nitrogen was applied to 18 percent of the 2006 soybean planted acres in the 

Program States at an average rate of 16 pounds per acre per year. Phosphate was applied to 23 

percent of the planted acres, at an average rate of 46 pounds per acre (NASS, 2007).56 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.57

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.58

 

54 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.

55 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.

56 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.

57 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.

58 Dinnes, DL; Karlen, DL; Jaynes, DB; Kaspar, TC; Hatfield, JL; Colvin, TS; Cambardella, CA. 220 2002. 

Nitrogen management strategies to reduce nitrate leaching in tile-drained 221 midwestern soils. Agronomy Journal 

94(1): 153-171.
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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.59 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. 

Water for soybean cultivation predominately comes from rainfall, although about 11 

percent of soybean acres in the U.S. are irrigated.60 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.61 Water used for irrigation is at least 

temporarily not available for other uses and if pumped from deep aquifers, may not return to 

those aquifers for centuries

There is some concern that the demand for corn and soybeans as biofuel feedstocks may 

lead to high prices of these commodities, inducing farmers with land currently enrolled in 

USDA’s CRP to return to intensive agricultural production (e.g., Secchi et al., 2009). 62 The 

CRP provides farmers with financial incentives to set aside a certain portion of their cropland in 

order to conserve or improve wildlife habitat, reduce erosion, protect water quality, and support 

other environmental goals. Biomass produced from CRP lands is considered “renewable 

biomass” as defined under the RFS regulations and is therefore eligible for use in the production 

of renewable fuel under the RFS program. The Food, Conservation, and Energy Act of 2008 

(known as the Farm Bill) capped CRP acreage at 32 million acres, reducing enrollment by 7.2 

million acres from the 2002 Farm Bill with the potential for making more acreage available for 

the production of row crops. As noted earlier, the USDA’s position is to support maintaining 32 

million acres of CRP protected lands so in aggregate we do not expect significant changes in the 

amount of land in CRP. However, individual farmers have the opportunity to move specific land 

in and out of CRP such that the specific lands in the program do not necessarily remain fixed. 

Historically, land entering and exiting the CRP program has been more vulnerable to erosion 

 

59 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 .

60U.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

61 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 

62 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.
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than other cultivated land, but also less productive.63 So while the conversion of a specific piece 

of land from CRP to intensive feedstock production is possible, such a land use conversion is 

less likely than land already in crop production 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, bio-refinery technology, effluent 

controls, and water re-use/recycling practices, as well as the facility location and source and 

receiving water. Discharge water quality requirements of local and regional governments can 

help assure best control practices and reduce water quality concerns.

Despite the existing commercial market for glycerin and the likely expanded uses for 

glycerin as mentioned in the RFS2 final rule, the rapid development of the biodiesel industry has 

caused a glut of glycerin production, resulting in many facilities disposing of glycerin. Glycerin 

disposal may be regulated under several EPA programs, depending on the practice. However, 

there have been instances of glycerin dumping, including an incident in Missouri that resulted in 

a large fish kill.64 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.65 BOD 

can lead to methane emissions during the water treatment process. To mitigate wastewater 

issues, some production systems reclaim glycerin from the wastewater. Closed-loop systems in 

which water and solvents can be recycled and reused can reduce the quantity of water that must

be pretreated before discharge. Others employ anaerobic digesters to mitigate the release of 

methane to the atmosphere.

Biodiesel can also impact water bodies as a result of spills. However, biodiesel degrades 

approximately four times faster than petroleum diesel including in aquatic environments.66 

Results of aquatic toxicity testing of biodiesel indicate that it is less toxic than regular diesel.67 

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.

 

63 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.

64 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..

65 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..

66 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 . 

67 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. 
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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.68

8. Job Creation and Rural Economic Development

The Energy Independence and Security Act (EISA) requires analyses of, among other 

factors, the impact of renewable fuel use on “...job creation [and] rural economic 

development...” to help inform each annual determination of applicable volumes. In the RFS2 

final rule, we anticipated employment to increase and income to expand in rural areas and 

farming communities as a result of the increased use of renewable fuel. Income expansion in 

rural areas from renewable fuel production will contribute to rural economic development. As 

mentioned above, industry activities are currently progressing, ramping up biodiesel production 

from the approximately 0.38 bill gallons estimated to have been used in the U.S. in 2010 to over 

1.0 bill gallons that was produced in 2011. This increase in biodiesel production was in large 

part due to bringing on line existing capacity idled due to lack of demand, a trend that we expect 

will continue into the near future. 

Employment impacts of federal rules are of particular concern in the current economic 

climate of sizeable unemployment. The recently issued Executive Order 13563, “Improving 

Regulation and Regulatory Review” (January 18, 2011), states, “Our regulatory system must 

protect public health, welfare, safety, and our environment while promoting economic growth, 

innovation, competitiveness, and job creation” (emphasis added). Executive Order 13563 also 

states that “[i]n applying these principles, each agency is directed to use the best available 

techniques to quantify anticipated present and future benefits and costs as accurately as possible” 

and that “...each agency may consider (and discuss qualitatively) values that are difficult or

impossible to quantify...” Consistent with the Executive Order, and consistent with recent efforts 

to characterize the employment effects of economically significant rules, the Agency has 

provided this analysis to inform the discussion of labor demand and employment impacts in rural 

areas and farming communities. Estimates of this particular rule’s effects on labor markets 

beyond the biodiesel production sector are “difficult or impossible to quantify” to an acceptable 

degree of accuracy using currently available methodologies, Therefore, the Agency has not 

quantified the rule’s effects on labor in other sectors, including conventional diesel production 

and sales, nor has the agency attempted to estimate the effects induced by changes in workers’ 

incomes or changes in food and fuel prices.

When the economy is at full employment, an environmental regulation is unlikely to have 

much impact on net overall U.S. employment; instead, labor would primarily be shifted from one 

sector to another. These shifts in employment impose an opportunity cost on society, 

approximated by the wages of the employees, as regulation diverts workers from other activities 

in the economy. In this situation, any effects on net employment are likely to be transitory as 

 

68 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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workers change jobs (e.g., some workers may need to be retrained or require time to search for 

new jobs, while shortages in some sectors or regions could bid up wages to attract workers). 

On the other hand, if a regulation comes into effect during a period of high 

unemployment, a change in labor demand due to regulation may affect net overall U.S. 

employment because the labor market is not in equilibrium. Schmalansee and Stavins point out 

that net positive employment effects are possible in the near term when the economy is at less 

than full employment due to the potential hiring of idle labor resources by the regulated sector to 

meet new requirements (e.g., to install new equipment) and new economic activity in sectors 

related to the regulated sector.69 In the longer run, the net effect on employment is more difficult 

to predict and will depend on the way in which the related industries respond to the regulatory 

requirements. For this reason, Schmalensee and Stavins urge caution in reporting and 

interpreting partial employment effects since it can “paint an inaccurate picture of net 

employment impacts if not placed in the broader economic context.”

This rule is expected to primarily affect employment in the United States through the 

biodiesel plants and distributors, and through several related sectors, specifically, industries that 

supply inputs in the production of biodiesel. To provide a partial picture of the employment 

consequences of this rule, EPA investigated the expected consequences for rural areas and 

farming communities. Assuming the current average of 30 to 40 people to operate a biodiesel 

plant of 30 million gallons (a typical capacity for a standalone transesterification plant), an 

expansion of 280 million gallons is the equivalent of adding about 4 plants representing the 

addition of around 350 direct jobs for biodiesel production70. Providing soy oil feedstock 

would require an estimated 120 additional truck trips per day or an addition of 120delivery 

drivers per day assuming one trip per delivery truck per day to account for driving and loading / 

unloading time.71 Expansions to the fuel distribution infrastructure (i.e., more fuel terminals, rail 

cars, tank trucks, barges etc.) would also be needed to support the use of an additional 280 

million gallon increase in the 2013 volume requirement for biomass-based diesel. Necessary 

support to a functioning biodiesel plant such as the delivery of methanol to allow processing of 

vegetable oil into biodiesel as well as additional handling at biodiesel distribution centers will 

also add directly to the employment impacts. 

Most large biodiesel plants in the U.S. are located in rural communities near feedstock 

(soybean oil or corn oil) sources. Urban biodiesel plants tend to be smaller with more diffuse 

feedstock suppliers. In 2011, approximately 71 percent of biodiesel producers were located in 

rural areas, defined as towns of less than 50,000. A 30 million gallon per year (MGY) biodiesel 

plant will spend nearly $140 million on goods and services with feedstocks accounting for more 

than 80 percent of expenditures.72 The size of the economic impact on the local economy of 

spending by an individual biodiesel plant will depend on location (e.g., state) and how much 

feedstock is sourced locally. 

 

69 Schmalensee, Richard, and Robert N. Stavins. “A Guide to Economic and Policy Analysis of EPA’s Transport 

Rule.” White paper commissioned by Excelon Corporation, March 2011 (Docket EPA-HQ-OAR-2010-0799).

70 Presentation from National Biodiesel Board, “Biodiesel Forecasts, Infrastructure, and Economic Impacts”, 

February 14, 2012.

71 Ibid.

72 Ibid.
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In addition to the employment effects from increased biodiesel production, this rule 

would also result in reductions in conventional diesel fuel use, which could affect employment in 

the diesel fuel supply chain. The loss of expenditures to diesel fuel suppliers throughout the 

diesel fuel supply chain, from the petroleum refiners to diesel fuel distributors, is likely to result 

in some loss in employment in these sectors. The potential impacts on the diesel industry and 

other sectors of the economy are not quantified in this analysis because available data and 

methodologies are insufficient to support reasonably accurate estimates of the incremental 

employment effects of this rule. 

To summarize, we anticipate that bringing idle biodiesel plants back online and 

expanding biodiesel distribution infrastructure in the U.S. will increase employment in the 

renewable fuels and related industries and promote rural economic development. These 

increases in employment are similar to what we anticipated when we analyzed the volume 

requirements in RFS2 final rule. These employment impacts may be offset to some degree by 

decreases in other sectors and/or locations (e.g., from the reduced production and transport of 

conventional diesel fuel); however sufficiently reliable data and a satisfactory methodology 

supporting quantitative evaluation of the employment impacts beyond the biodiesel sectors are 

not currently available.

One 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, while Table III.B-1 lists grease and fats as one 

likely source of feedstocks for the production of biomass-based diesel, we noted in Section III.B 

that there could be sufficient sources of other feedstocks to produce 1.28 bill gallons of biomassbased diesel without using any animal fats. The comment implies that feedstock used in the 

oleochemical industry depends significantly on relative costs which can vary over time in part 

due to changes in demand. The cost of animal fat is dependent on the general demand for this 

material which is only in part impacted by its potential use as a biofuel feedstock. The general 

supply of animal fat is not expected to be impacted significantly by its alternative use as a 

biofuel feedstock or the range of other uses of this material. Thus the choice of feedstock(s) used 

by the oleochemical industry already depends on market prices of multiple feedstock sources. 

Since feedstock such as rendered fats or, as suggested by the commenter, palm oil are readily 

marketed and transportable, we do not expect the industry to relocate production every time 

feedstock market conditions change. Therefore we do not believe production facility location 

will be significantly impacted by the potential use of rendered fats as a biofuel feedstock if some 
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portion of the 280 million gallon increase in the biomass-based diesel standard is produced from 

rendered fats. 

B. Consideration of Quantifiable Costs and Benefits

The RFS program established by Congress is primarily a long-term program aimed at 

replacing substantial volumes of fossil-based transportation fuels with low GHG renewable fuels 

over time. In the final rulemaking for the RFS2, EPA assessed the costs and benefits of this 

program as a whole when the program was fully mature, which we continue to believe is the 

appropriate approach to examining the costs and benefits of a long term program like the RFS2. 

However, the annual standard-setting process is part of the program. The annual standard-setting 

process encourages consideration of the program on a piecemeal (i.e., year to year) basis instead 

of a holistic one, though doing so creates an incomplete understanding of the program’s impacts. 

EPA received comments requesting that we consider costs and benefits for the 1.28 

billion gallon biomass-based diesel mandate in 2013. This mandate is an interim step within the 

larger RFS program, so any examination of short-term impacts separate from that larger effort 

must be kept in context. Further, many of the impacts of this rule are difficult to fully quantify, 

which makes any comprehensive consideration of costs and benefits difficult to undertake in the 

limited timeframe of the RFS annual rule. In spite of these limitations, EPA has analyzed some 

of the costs and has estimated the monetary value of some of the benefits of the 2013 biomassbased diesel mandate to provide more information on this rulemaking.

In this section, we provide estimates of some costs and benefits for the year 2022, when 

the RFS2 legislative requirements will be fully implemented and the program is more mature. 

We also provide estimates of the costs and benefits of the 1.28 bill gal volume requirement for 

the year 2013, the year in which we are setting the biomass-based diesel volume mandate at 1.28 

bill gal. The statute is forward-looking in that it created a program whose energy and 

environmental benefits are intended to grow over time; to evaluate the program on the basis of 

only one early year’s impacts, as part of near-term implementation, would be to paint an 

unbalanced and incomplete picture. For example, as we examine the costs of the program 

through time, we see that these costs fall steadily. This is due to two key factors: the cost of 

petroleum, the basic raw material of diesel fuel, rises through time. Meanwhile, the principal 

cost of soybean-based biodiesel, the soybean oil feedstock, tends to fall though time. For 

example, the AEO 2012 Early Release (AEO12 ER) projects that oil prices rise from roughly 

$103 per barrel in 2013 to $129 per barrel in 2022, a 25 percent increase.73 The AEO 2011 High 

Oil Price case (AEO11 HOP), projects that oil prices will increase to about $179 per barrel, a 73 

percent increase.74 According to EPA’s projections performed for this rule and USDA long-term 

projections, soy oil prices will decrease from $0.45/lb in 2013 to $0.42/lb in 2022, a 6 percent 

decrease.75 As a result, the relative cost difference between diesel and biodiesel fuel tends to 

 

73 U.S. Department of Energy, Energy Information Administration. 2012. Annual Energy Outlook 2012 (Early 

Release). Available at: http://www.eia.gov/forecasts/aeo/er/.

74 U.S. Department of Energy, Energy Information Administration. 2011. Annual Energy Outlook 2011. Available 

at: http://www.eia.gov/forecasts/aeo/data.cfm#enprisec.

75 U.S. Department of Agriculture, Economic Research Service, Agricultural Long-Term Projections, February 

2012.
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narrow through time as the program reaches maturity. Thus, we do not just look at the impacts 

of the program in any one year, but also look at the impacts at a point of greater program 

maturity.

1. Monetized Quantifiable Costs

Our analysis of costs focuses on the sector most likely to be impacted by an increase in 

biomass-based diesel volumes – the agricultural commodity market. To assess some of the 

impacts of the 1.28 billion gallon biodiesel mandate, EPA used a stochastic economic model 

developed by the Center for Agricultural and Rural Development (CARD) at Iowa State 

University to conduct this analysis. The CARD stochastic model approximates U.S. and 

Brazilian biofuel production, consumption, and trade. Using a relatively small set of input 

assumptions about petroleum prices, commodity yields, and ethanol production, the CARD 

model examines what the U.S. and Brazilian biofuels markets may look like under different 

combinations of parameters (e.g., low petroleum prices, low soybean yields, and high Brazilian 

ethanol production).

The model shows the probability of different outcomes by running 500 different potential 

scenarios. This modeling approach provides a range of estimates which helps to bound 

uncertainty about possible impacts on the biofuels sector. Analysis of this range can indicate 

which outcomes are more likely than others and also provide a sense of the possible high and 

low estimates that should be considered for a given variable. The CARD model projects ranges

for commodity yields and prices, fuel volumes and prices, and several other variables. For the 

biomass-based diesel standard, EPA analyzed the cost of mandating an additional 280 million 

gallons for biodiesel in 2013, going from 1.0 billion gallons of biomass-based biodiesel to 1.28 

billion gallons. For purposes of this analysis, EPA assumed that the additional 280 million 

gallons of biodiesel we are mandating for 2013 will be entirely soybean-based and would not 

otherwise be produced. As we outline in Section III.B of this rulemaking, most of the additional 

280 million gallons is likely to be soybean-based, but other sources are possible. Because 

soybean oil feedstock is more expensive than corn oil or waste feedstock, the cost impact of the 

extended volume requirement would decrease if biodiesel production from these other sources 

expands. We therefore consider the cost projections presented below to be potentially high 

estimates.

a. Impact on the Cost of Soybean Oil

One commenter suggested that the biodiesel mandate for 2013 will result in an increase 

of soybean oil prices. In response to this comment and other related comments, EPA modeled 

the change in soybean oil prices in 2013 using the CARD stochastic model. Assuming that the 

280 million gallon increment is met entirely with soybean oil biodiesel in 2013, EPA estimates 

that the price of soybean oil will be $0.45 per pound (in 2010$) under this mandate, compared to 

approximately $0.42 under a 1.0 billion gallon mandate (see Section III.B of this rule for further 

discussion of feedstock availability and prices). The mandate is estimated to increase feedstock 

costs of soybean-based biodiesel by about $0.22 per gallon of biodiesel. The effect of this 

increase on the cost of the additional 280 million gallons is incorporated into the estimates in 

section IV.B.1.b.
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Given that the CARD stochastic model is not designed to estimate long-run impacts, we 

do not attempt to estimate the impacts of the 2013 biomass-based biodiesel volume requirement 

on the price of soybean oil in 2022. In Section III.B.3 of this rule, we estimate that this proposed 

mandate will raise soybean oil prices by approximately 7 percent in 2013. The international 

market for vegetable oils is large and diverse, with considerable capacity to absorb short-term 

demand increases. It is therefore unlikely that an increase in U.S. demand for soybean oil of this 

size in 2013 would significantly affect prices nine years in the future. Therefore, in lieu of 

projecting soybean oil prices in 2022, we are utilizing USDA’s 2012 Long-Term Agricultural 

Projections of soybean oil prices. USDA estimates that the price of soybean oil will be $0.42 per 

pound (in 2010$) for the 2021/2022 crop year (the last year for which USDA provides estimates

in their long-term projections as of this writing).76

b. Cost of Displacing Petroleum-Based Diesel with Soybean-Based Biodiesel

Producing an additional 280 million gallons of biodiesel will displace approximately 255 

million gallons of petroleum-based diesel. Since biodiesel costs more to produce in the U.S. than 

diesel, this displacement has associated costs. In this analysis, we compare the cost of biodiesel 

and petrodiesel at the wholesale stage, since that is when the two are blended together. 

Therefore, this analysis does not consider taxes, retail margins, and any other costs and transfers 

that occur at or after the point of blending.

On this basis, EPA estimated the cost of producing and transporting a gallon of biodiesel 

to the blender. For soybean-based biodiesel, soybean oil feedstock costs generally represent the 

majority of the overall cost, usually somewhere between 70 and 90 percent. The soybean oil 

price estimates discussed in Section IV.B.1.a of this rule therefore had a strong impact on EPA’s 

cost estimates, though estimates of distribution and other production costs were also important. 

Estimating the cost to produce biodiesel and transport it to the blender presents considerable 

uncertainties, even in the near term. Unforeseen fluctuations in the prices of oil, for example, 

could have a very significant effect. Therefore, instead of presenting a point estimate, EPA has 

chosen to present a range of estimates for 2013 and 2022 that reflects uncertainty associated with 

the oil and feedstock prices at the 1.28 bill gal level that we are finalizing.

After estimating the cost of biodiesel at the wholesale stage, EPA compared that to what 

it would cost to consume an equivalent amount of petroleum-based diesel instead. The 

Department of Energy’s Energy Information Administration (EIA) publishes two regular reports 

that make estimates of wholesale diesel prices in 2013. In 2013, costs are on the low-end of the 

range if we use the wholesale diesel estimate from DOE’s most recent Short-Term Energy 

Outlook (STEO).77 The high-end estimate utilizes DOE’s AEO12 ER wholesale diesel 

estimate.78 Both estimates are relevant for an analysis of fuel prices in 2013. On this basis, we 

 

76 U.S. Department of Agriculture. 2012. USDA Long-Term Agricultural Projections. Available at: 

http://usda.mannlib.cornell.edu/MannUsda/viewStaticPage.do?url=http://usda.mannlib.cornell.edu/usda/ers/94005/./

2012/index.html.

77 U.S. Department of Energy, Energy Information Administration. 2012. Short Term Energy Outlook, March 

2012. Available at: http://www.eia.gov/forecasts/steo/index.cfm.

78 U.S. Department of Energy, Energy Information Administration. 2012. Annual Energy Outlook 2012 (Early 

Release). Available at: http://www.eia.gov/forecasts/aeo/er/.
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estimate the increase in the cost of fuel for 280 million gallons of biodiesel will be between 

$0.91 and $1.36 per gallon in 2013. This translates into total cost estimates of $253 million to 

$381 million from increased fuel cost in 2013. 

Table IV.B.1.b-1

Estimated Increase in Wholesale Cost of Biodiesel in Comparison to Petrodiesel in 2013 and 

2022 (in 2010 dollars)

Estimate for 2013 Estimate for 2022

Difference in biodiesel 

production cost (per gallon) $0.91 - $1.36 -$0.70 - $0.41

Cost of 280 million gallons $253 - $381 million -$195 - $116 million

We also present a range of estimates for the year 2022. The upper bound of our cost 

estimates utilizes the AEO 2012 ER. The low end of this range utilizes the AEO 2011 High Oil 

Price (HOP) case’s wholesale diesel estimate. The STEO does not currently provide projections 

for the year 2022 and the AEO 2012 Early Release does not include the high oil price case (at the 

time of this writing the full AEO 2012 has not been released). In lieu of these, the AEO 2011 

HOP is the best available estimate of a higher diesel cost in 2022. Based this range of data and 

on USDA’s long-term projection of soybean oil prices, we estimate the incremental increase in 

fuel costs associated with this proposed volume requirement will be between -$0.70 and $0.41 

per gallon in 2022. This translates to a cost of -$195 million to $116 million from increased fuel 

costs in 2022. The low end of this estimate is negative because with higher oil costs, biodiesel is 

less expensive than petroleum-based diesel.

Consistent with our previous work in this area, EPA’s quantifiable cost methodology is a 

“bottom-up” engineering cost analysis that estimates the cost to produce a gallon of soybeanbased biodiesel and then compares that cost to the production cost of an energy-equivalent gallon 

of petroleum-based diesel. In certain situations, it may also be useful to use a “top down” 

analyses to estimate the potential cost of a program to society. In the case of the biomass-based 

diesel standard, one suggestion was to look at the RIN price as a proxy for the societal cost of the 

program. 

However, we have numerous concerns with using RIN prices to estimate the costs to 

society of the biomass-based diesel RFS2 requirement. First of all, RIN prices are more 

representative of marginal costs. If producers have different costs of production, as they do in 

the biodiesel market, using the marginal cost of compliance as a proxy for cost of production will 

significantly overestimate the cost to society. Second, the commodity traded, biomass-based 

diesel, has one overall price, but has two components (the RIN component and the liquid volume 

component). The relative magnitude of these two components can vary depending on their 

individual markets, making it difficult to have confidence in the RIN value as a representation of 

the full cost of the biomass-based diesel fuel. Third, it is difficult to have confidence in the use 

of historical RIN price trends as an indicator of future program cost given observed instability 

and uncertainties in U.S. tax policy, import tariff policies, and the level of RFS standard itself. 

Finally, other factors, such as the existence of multiple RIN vintages in any given year and the 
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aforementioned uncertainties, can create significant incentives for potential speculation in the 

RIN markets, further undermining confidence in the effectiveness of RIN prices as a proxy for 

true social costs of the biodiesel program. In their 2011 report on RINs, USDA observed that 

this speculation results in RIN prices that are somewhat higher than the cost of biodiesel, though 

the exact amount of this increment is extremely difficult to quantify.79

c. Transfers Occurring as a Result of This Mandate

Some general equilibrium effects that will result from this rule are not captured in a 

partial equilibrium framework such as the CARD stochastic model. Since the increase in the 

biomass-based diesel volume requirement is fairly modest, these impacts will likely be modest 

and represent various transfers in different markets. For example, the price of soybean oil, both 

for biodiesel production and in food products, will increase as a result of the demand for an 

additional 280 mill gal biodiesel. In addition, as soybean prices increase moderately, soybean 

growers will likely spend more of their revenues on key inputs such as labor and fertilizers. 

Increasing payments to labor and fertilizer producers will results in further spending with 

impacts primarily in rural areas of the U.S. that supply the soybeans. 

On the petroleum side of the market, a modest decline in diesel fuel demand will result in 

lower payments to diesel fuel suppliers and to refineries that produce diesel fuel. In turn, diesel 

fuel suppliers and refineries will spend less on key inputs such as refinery equipment used to 

produce diesel fuel. Given the small volumes of diesel fuel involved, it is not likely that there 

will be discernible impacts on the overall market price for diesel fuel, which is set by a 

combination of world, national, regional and local markets and conditions. 

d. Transportation Fuel Costs

In the NPRM, we cited cost estimates that we had developed in the RFS2 final rule. In 

response to comment, we have revised our methodology for examining the effect of this mandate 

on the cost of transportation fuel. The estimates described in Section IV.B.1 above represent the 

quantifiable costs to society as a whole stemming from our increase in the biomass-based diesel 

volume requirement from 1.0 bill gal to 1.28 bill gal. These estimates do not include certain 

transfers, such as those between buyers and sellers of diesel fuel (see Section IV.B.1.c). For this 

reason, the increase in the cost of transportation fuel from a societal perspective is different from 

the increase from the perspective of individual buyers and sellers of fuel. However, these costs 

do impact the retail price of diesel.

To estimate the increase in the cost of transportation fuel associated with today's mandate 

for 1.28 bill gal in 2013 and 2022, we took our projections for the quantifiable program costs 

reported in Section IV.B.1.b and compared that to projected fuel consumption. The AEO 

projects that the U.S. will consume 44.9 bill gal of blended diesel in 2013 and 50.3 bill gal in 

2022.80 Averaged over this diesel pool, the quantifiable costs of the 1.28 bill gal mandate 

 

79 McPhail, L, P Westcott, and H Lutman, The Renewable Identification Number System and U.S. Biofuel Mandates, 

United States Department of Agriculture, November 2011.

80 U.S. Department of Energy, Energy Information Administration. 2012. Annual Energy Outlook 2012 (Early 

Release). Available at: http://www.eia.gov/forecasts/aeo/er/.
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translate into a per gallon cost of between $0.006 and $0.008 in 2013 and between -$0.004 and 

$0.002 in 2022. 

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, which expired 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 retail price of biodiesel is a complex relationship that 

can be difficult to assess. For instance, Figure IV.B.1.d-2 shows the retail 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 thus 

represents an additional reason that we have not made an effort to project biodiesel prices in the 

future under different tax policy scenarios.

Figure IV.B.1.d-2

Nationwide Average Biodiesel Prices at Retail

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 argued 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.

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00 January 2008 April 2008 July 2008 October 2008 January 2009 April 2009 July 2009 October 2009 January 2010 April 2010 July 2010 October 2010 January 2011 April 2011 July 2011 B100 price per gallon

Biodiesel tax credit not available
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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 feedstock 

such as soybean oil. However, the actual delivered cost of feedstock 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 (e.g., planting, fertilizing, harvesting, expelling) 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-Up81, the 

total delivered costs for yellow grease and other rendered fats is consistently less that the total 

delivered costs for soybean oil. For instance, for the week of March 30, 2012, crude soybean oil 

was selling for about 53 ¢/lb, while yellow grease was selling for about 41 ¢/lb. As such, we 

believe that the ATA concerns regarding the feedstock supply chain are not warranted.

2. Monetized Quantifiable Benefits

Many of the benefits and impacts that Congress asked EPA to examine when evaluating 

whether to increase the volume requirement for biomass-based biodiesel are difficult to fully 

quantify. In this section, we present a selection of quantifiable benefits from increased biodiesel 

production, including increased energy security and reduced greenhouse gas emissions. As 

observed above, it is most appropriate to consider these benefits within the context of full 

program implementation (i.e., the year 2022). However, we also present benefits for 280 million 

gallons of additional biodiesel produced in the year 2013 for comparison purposes. 

a. Energy Security

Quantified energy security benefits are taken from the estimates reported in Section 

IV.A.2 of this final rule. As noted there, EPA considers only the macroeconomic disruption and 

adjustment effect in its estimates of energy security benefits. We estimate that the energy 

security benefits of the additional 280 mill gal increment of biodiesel are $0.15 per gallon in 

2013 and $0.16 per gallon in 2022. This translates to a total program benefit of about $41 

million in 2013 and $45 million in 2022.

b. Air Quality

We discuss air quality impacts qualitatively in Section IV.A.4 of this final rule and expect 

an additional 280 mill gal of biodiesel (in years 2013 and 2022) will have a relatively small 

impact on ambient air quality. That said, we do expect the production and combustion of 

biodiesel to have a slightly different emissions impact relative to petroleum-based diesel. As 

presented in Table IV.A.4-1, we estimated that in 2022, the increased production of biodiesel 

related to the RFS2 mandate would impact both downstream and upstream emissions, with 

increases in some pollutants and decreases in others.

 

81 USDA Livestock & Grain Market News for October 14, 2011. 

http://www.ams.usda.gov/mnreports/lswagenergy.pdf
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Ideally, the monetized impacts of changes in air quality related to the final rule would be 

estimated based on changes in ambient pollution concentrations and population exposure, as 

determined by complete air quality and exposure modeling. However, conducting such detailed 

modeling was not possible within the timeframe for this analysis.

 

Instead, our analysis of PM2.5-related health impacts associated with 280 additional 

gallons of biodiesel (in both 2013 and 2022) uses a “dollar-per-ton” method to estimate selected 

PM2.5-related health impacts. These PM2.5-related dollar-per-ton estimates provide the total 

monetized human health impacts (the sum of premature mortality and premature morbidity) of 

reducing one ton of directly emitted PM2.5, or one ton of a pollutant that contributes to 

secondarily-formed PM2.5 (such as NOx, SOx, and VOCs) from a specified source.82 The dollarper-ton technique has been used in previous analyses, including the 2012-2016 Light-Duty 

Greenhouse Gas Rule,83 the Ozone National Ambient Air Quality Standards (NAAQS) RIA,84

the Portland Cement National Emissions Standards for Hazardous Air Pollutants (NESHAP) 

RIA,85 and the final NO2 NAAQS.86

 

The analysis of the final 2013 fuel mandate did not estimate the direct emissions impacts 

to which we could apply the “dollar-per-ton” estimates. Instead, we converted “dollars-per-ton” 

to “dollars-per-gallon” by transferring the biodiesel tons –to-emissions relationship observed in 

the RFS2 analysis to the current analysis (dividing emissions in Table IV.A.4-1 by 1.44 bill 

gallons of biodiesel) and multiplying that by each pollutant-specific dollar-per-ton estimate.

The dollar-per-ton estimates used to monetize the emissions impacts from each gallon of 

biodiesel are provided in Table IV.B.2.b-1.

Table IV.B.2.b-1

Benefits-per-ton Values (2010$) Derived Using the American Cancer Society Cohort Study for 

PM-related Premature Mortality (Pope et al., 2002)a

Year All Sourcesc Upstream (Non-EGU) Mobile Sources

 

82 Due to analytical limitations, the estimated dollar-per-ton values do not include comparable impacts related to 

reductions in other ambient concentrations of criteria pollutants (such as ozone, NO2 or SO2) or toxic air pollutants, 

nor do they monetize all of the potential health and welfare effects associated with PM2.5 or the other criteria 

pollutants.

83 U.S. Environmental Protection Agency (U.S. EPA), 2010. Regulatory Impact Analysis, Final Rulemaking to 

Establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy 

Standards. Office of Transportation and Air Quality. April. Available at 

http://www.epa.gov/otaq/climate/regulations/420r10009.pdf. EPA-420-R-10-009

84 U.S. Environmental Protection Agency (U.S. EPA). 2008. Regulatory Impact Analysis, 2008 National Ambient 

Air Quality Standards for Ground-level Ozone, Chapter 6. Office of Air Quality Planning and Standards, Research 

Triangle Park, NC. March. Available at <http://www.epa.gov/ttn/ecas/regdata/RIAs/6-ozoneriachapter6.pdf>. 

EPA-HQ-OAR-2009-0472-0238

85 U.S. Environmental Protection Agency (U.S. EPA). 2010. Regulatory Impact Analysis: National Emission 

Standards for Hazardous Air Pollutants from the Portland Cement Manufacturing Industry. Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. August. Available on the Internet at < 

http://www.epa.gov/ttn/ecas/regdata/RIAs/portlandcementfinalria.pdf >. EPA-HQ-OAR-2009-0472-0241

86 U.S. Environmental Protection Agency (U.S. EPA). 2010. Final NO2 NAAQS Regulatory Impact Analysis 

(RIA). Office of Air Quality Planning and Standards, Research Triangle Park, NC. April. Available on the Internet 

at http://www.epa.gov/ttn/ecas/regdata/RIAs/FinalNO2RIAfulldocument.pdf. Accessed March 15, 2010. EPA-HQOAR-2009-0472-0237
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Sourcesd

SO2 VOC NOX Direct 

PM2.5

NOX Direct 

PM2.5

Estimated Using a 3 Percent Discount Rateb

2015 $30,000 $1,200 $4,900 $230,000 $5,100 $280,000

2020 $33,000 $1,400 $5,400 $250,000 $5,600 $310,000

Estimated Using a 7 Percent Discount Rateb

2015 $27,000 $1,100 $4,500 $210,000 $4,600 $250,000

2020 $30,000 $1,200 $4,900 $230,000 $5,100 $280,000

a The benefit-per-ton estimates presented in this table are based on an estimate of premature mortality derived from 

the ACS study (Pope et al., 2002). If the benefit-per-ton estimates were based on the Six-Cities study (Laden et al., 

2006), the values would be approximately 245% (nearly two-and-a-half times larger). 

b The benefit-per-ton estimates presented in this table assume either a 3 percent or 7 percent discount rate in the 

valuation of premature mortality to account for a twenty-year segmented cessation lag. 

c Note that the benefit-per-ton value for SO2 is based on the value for Stationary (Non-EGU) sources; no SO2 value 

was estimated for mobile sources. The benefit-per-ton value for VOCs was estimated across all sources.

d Non-EGU denotes stationary sources of emissions other than electric generating units (EGUs).

For certain PM2.5-related pollutants (such as direct PM2.5 and NOx), EPA estimates 

different per-ton values for reducing mobile source emissions than for reductions in emissions of 

the same pollutant from stationary sources such as fuel refineries and storage facilities. These 

reflect differences in the typical geographic distributions of emissions of each pollutant by 

different sources, their contributions to ambient levels of PM2.5, and resulting changes in 

population exposure. We apply these separate values to estimates of changes in emissions from 

vehicle use and from fuel production and distribution to determine the net change in total 

economic impacts from emissions of those pollutants. Monetized PM2.5-related health impacts 

associated with the final rule can be found in Table VI.B.2.b-2 and per gallon impacts can be 

found in Table VI.B.2.b-3.

Table VI.B.2.b-2

Total Ambient PM2.5-related Monetized Health Impacts (millions 2010$; based on Pope et al., 

2002)a

2013 Monetized Impacts (7% 

Discount Rate – 3% Discount Rate)

2022 Monetized Impacts (7% 

Discount Rate – 3% Discount Rate)

Downstream $15 - $16 $16 - $18

Upstream -$34 - -$37 -$37 - -$40

Net Impacts -$19 - -$21 -$20 - -$22

a Note: Negative values indicate disbenefits associated with decrements in ambient air quality.
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Table VI.B.2.b-3

Per Gallon Ambient PM2.5-related Monetized Health Impacts (2010$ per gallon; based on Pope 

et al., 2002)a

2013 Monetized Impacts (7% 

Discount Rate – 3% Discount Rate)

2022 Monetized Impacts (7% 

Discount Rate – 3% Discount Rate)

Downstream $0.05-$0.06 $0.06b

Upstream -$0.12- -$0.13 -$0.13- -$0.14

Net Impacts -$0.07b-$0.07- -$0.08

a Note: Negative values indicate disbenefits associated with decrements in ambient air quality.

bVariation in this category is less than one cent.

The method used in this analysis to estimate the monetized PM2.5-related impacts of an 

increase in biodiesel production is subject to a number of assumptions and uncertainties. 

The method does not reflect local variability in population density, meteorology, 

exposure, baseline health incidence rates, or other local factors that might lead to an 

overestimate or underestimate of the actual benefits of controlling fine particulates in 

specific locations. This is particularly a problem for the monetization of upstream 

emissions since those have a very specific geographic profile different to that associated 

with mobile source emissions.

Transferring the biodiesel tons-to-emissions relationship derived from the RFS2 mandate 

in 2022 to the current analysis (in both 2013 and 2022) assumes that the incremental 

production of biodiesel associated with the 2013 mandate (of 280 million gallons) will 

yield the same relative emissions impacts, which we cannot say with certainty.

This analysis assumes that all fine particles, regardless of their chemical composition, are 

equally potent in causing premature mortality. PM2.5 produced via transported precursors 

emitted from stationary sources may differ significantly from direct PM2.5 released from 

engines and other industrial sources. At the present time, however, no clear scientific 

grounds exist for supporting differential effects estimates by particle type.

This analysis assumes that the health impact function for fine particles is linear within the 

range of ambient concentrations under consideration. Thus, the estimates include health 

benefits from reducing fine particles in areas with varied initial concentrations of PM2.5,

including both regions that are in attainment with fine particle standard and those that do 

not meet the standard, down to the lowest modeled concentrations. This is an appropriate 

assumption because the scientific literature provides no evidence of a threshold below 

which health effects associated with exposure to fine particles – including premature 

death -- would not occur.

There are several health benefits categories that we are unable to quantify due to 

limitations associated with using dollars-per-ton estimates, several of which could be 

substantial. Because NOX and VOC emissions are also precursors to ozone, changes in 

NOX and VOC would also impact ozone formation and the health effects associated with 

ozone exposure. Dollars-per-ton estimates for ozone do not exist due to issues associated 

with the complexity of the atmospheric air chemistry and nonlinearities associated with 
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ozone formation. The PM-related benefits-per-ton estimates also do not include any 

human welfare or ecological benefits. 

c. Greenhouse Gas Impacts

EPA established in the RFS2 final rule that a gallon of soybean-based biodiesel results in 

an annualized GHG emission reduction of approximately 57 percent compared to the 2005 

petroleum baseline . This GHG reduction calculation is based on the annualized emissions 

stream over a 30 year period, starting in 2022 (the year when the RFS2 program will be fully 

implemented). As described in Section IV.A.1 of this final rulemaking. , it may not be 

appropriate to include these GHG benefit reductions in our 2013 calculations. Again, this is not 

because EPA believes that the GHG benefits in 2013 will be zero, but rather because it may not 

be consistent to cite them for an interim year of the program using lifecycle biofuel assessments 

based on a 2022 analyses. As a sensitivity, however, if we were to apply the 2022 GHG 

emissions reductions to the 1.28 bill gal biomass-based diesel mandate, the GHG benefits of an 

additional 280 million gallons of biodiesel produced in 2013 would be up to $104 million, 

depending on the assumed discount rate. Also on this basis, we estimate that benefits of an 

additional 280 million gallons of biodiesel produced in 2022 will be between $9 and $120 

million.

3. Quantifiable Benefits and Costs Compared

As we have observed above, the cost and benefit categories discussed in this section are 

not comprehensive. EPA has included estimates for those impacts that we are able to quantify at 

the present time, but this is not meant to suggest that EPA considers these to be the total costs 

and benefits of the 2013 biomass-based diesel mandate. However, for illustrative purposes, we 

are providing a range of quantifiable combined cost and benefit estimates for the impact of a 

1.28 billion gallon mandate in 2013 and in 2022, based on those impacts that we were able to 

monetize.

a. Combined Quantifiable Costs and Benefits for Biodiesel Produced in 2022

EPA’s estimates of quantifiable costs and benefits vary significantly in 2022 due to 

uncertainty about the value of the SCC, air quality impacts, and the price of oil. Table IV.B.3.a1 presents the range of estimates for the combined quantifiable costs and benefits of an 

additional 280 million gallons of biodiesel produced in 2013 and 2022, using the SCC discount 

rates to delineate the ranges. Each range also incorporates variations in the discount rate for air 

quality disbenefits and both estimates of the price of oil and diesel in 2022. The total range 

varies from -$84 million to $301 million.

Table IV.B.3.a-1

Estimates of Combined Costs and Benefits of the 1.28 Billion Gallon Biodiesel Mandate in 2022

(in 2010 dollars)

Social Cost of Carbon Assumption Combined Costs and Benefits

5% Discount Rate -$84 to $189 million

3% Discount Rate -$53 to $220 million

2.5% Discount Rate -$28 to $246 million
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3% Discount Rate (95th Percentile) $28 to $301 million

b. Combined Quantifiable Costs and Benefits for Biodiesel Produced in 2013

EPA’s estimates of quantifiable costs and benefits vary significantly in 2013 as well, 

though this is due to uncertainty about the price of diesel as well as uncertainty about the value 

of the SC-CO2. Table IV.B.3.b-1 presents the range of estimates for the combined quantifiable 

costs and benefits of an additional 280 million gallons of biodiesel produced in 2013, which 

varies from -$393 million to -$159 million.

Table IV.B.3.b-1

Estimates of Combined Costs and Benefits of the 1.28 Billion Gallon Biodiesel Mandate in 2013

(in 2010 dollars)

Social Cost of Carbon Assumption Combined Estimate

No GHG Benefit Included -$393 to -$263 million

5% Discount Rate -$386 to -$256 million

3% Discount Rate -$359 to -$229 million

2.5% Discount Rate -$335 to -$206 million

3% Discount Rate (95th Percentile) -$289 to -$159 million

The transition from negative combined quantified costs and benefits estimates in 2013 to 

generally even or positive estimates in 2022 illustrate the importance of considering the RFS 

program at full implementation. As observed above, oil prices have generally tended to increase 

in real terms over time, causing the price of diesel to rise, while soybean oil prices decrease in 

real terms due to improving yields, which reduces the cost of biodiesel production. Thus, while 

quantified costs from the wider use of biomass-based biodiesel can be greater than quantified 

benefits in the near term, through time benefits tend to increase and outweigh costs.

Further, as noted at the beginning of this section, this analysis is not intended to serve as 

a comprehensive quantification of the costs and benefits of this mandate. Rather, it illustrates 

those costs and benefits that are quantifiable in response to comments received on the proposed 

rule. To develop a comprehensive estimate of costs and benefits, one would need to qualitatively 

balance these estimates against the impacts discussed earlier in this section. 

V. Final 2013 Volume for Biomass-Based Diesel 

Through the RFS program, Congress established a schedule of renewable fuel volumes 

that gradually increases over time. While the schedule in the statute for biomass-based diesel 

ends in 2012, the schedule of increasing volumes for advanced biofuels continues through 2022. 

For the years between 2012 and 2022, the statute indicates that biomass-based diesel volumes 

can increase above the 2012 applicable volume of 1.0 bill gal, but they cannot ever be lower than 

1.0 bill gal. Subject to a consideration of a number of factors as described in Section II, we 

believe that it is appropriate to consider biomass-based diesel as playing an increasing role in 

supplying advanced biofuels to the market between 2012 and 2022.
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61

As described in Section IV.A.9, increases in the required volume of biomass-based diesel 

above 1.0 bill gal will help to support rural economic growth and job creation, will increase 

energy security, and reduce emissions of GHGs. While we have projected that quantifiable 

benefits of an increase of 280 mill gal are unlikely to exceed the costs in 2013, the quantifiable 

benefits will most likely exceed costs by 2022. Thus by establishing an applicable volume for 

biomass-based diesel in 2013 that exceeds the minimum of 1.0 bill gal, we are helping to 

establish the industry as a substantial contributor to the required volumes of advanced biofuel 

anticipated after full implementation of the RFS program. To this end, and subject to the factors 

described in Section II, we envision additional increases in the required volume of biomassbased diesel throughout the period between 2012 and 2022, though not necessarily every year.

Therefore, based on our review of the factors required in the statute, 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 is a reasonable exercise of our authority under CAA 211(o)(2)(B)(ii) to bring about the longterm benefits of the RFS program.

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. However, one of 

the factors that we are required to consider when determining the appropriate biomass-based 

diesel volume for years after 2012 is a review of the implementation of the program during prior 

years. By determining the applicable volume requirement for biomass-based diesel only one 

year in advance, we are able to use the most up-to-date information on the implementation of the 

program in making our determination. This is particularly important in the early years of the 

program.
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VI. 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. Public comments and EPA responses are discussed 

throughout this preamble, and all comments received are available in EPA docket number EPAHQ-OAR-2010-0133.
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VII. Statutory and Executive Order Reviews

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

13563: Improving Regulation and Regulatory Review

Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is a 

"significant regulatory action” because it raises novel legal or policy issues. 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 applicable volume of 

biomass-based diesel for 2013. We have been able to quantify some of the economic impacts of 

this rule in 2013.

We estimate that soybean prices could increase up to 3 cents per pound in 2013 if the 

2013 biodiesel standard is met solely as a result of increased demand for soy bean oil. Potential 

use of other less expansive feedstocks would reduce this impact on soy beans. Again assuming 

the 280 billion gallon increase in required biomass-based diesel is met through increased demand 

for soy oil, we estimate the cost of producing this biomass-based diesel would range from $253 

to $381 million in 2013. Illustrative of the changing analysis over time, the cost of this amount 

of soy-based biodiesel in 2022 would be -$195 million to $116 million. Adding these estimates 

of 2013 costs to the fuel pool would result in a diesel fuel cost increase of between -$0.004 and 

$0.002 per gallon.

Quantified estimates of benefits and disbenefits include energy security benefits of $0.15 

per gallon in 2013 and $0.16 per gallon in 2022, air quality disbenefits of $0.07 per gallon in 

2013 and $0.07 to $0.08 per gallon in 2022, and GHG benefits of up to $134 million in 2013 and 

between $15 million and $160 million in 2022. Other benefits include both direct and indirect 

employment benefits in rural areas due to increased biodiesel production. Impacts on water 

quality, water use, wetlands, ecosystems and wildlife habitats are expected to be modest due to 

both the small impact on crops planted and due to the relatively small impact of soy bean 

production.

B. Paperwork Reduction Act

This action does not impose any new information collection burden since it only specifies 

the required volume of biomass-based diesel under the RFS program for 2013. However, 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 
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Control Number 2060-0637, 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). The OMB control 

numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. 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. 

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice and comment rulemaking 

requirements under the Administrative Procedure Act or any other statute unless the agency 

certifies that the rule will not have a significant economic impact on a substantial number of 

small entities. Small entities include small businesses, small organizations, and small 

governmental jurisdictions.

For purposes of assessing the impacts of today's rule on small entities, small entity is 

defined as: (1) a small business as defined by the Small Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a 

city, county, town, school district or special district with a population of less than 50,000; and (3) 

a small organization that is any not-for-profit enterprise which is independently owned and 

operated and is not dominant in its field.

After considering the economic impacts of today’s final rule on small entities, I 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 that are directly regulated under the 

RFS2 program were already addressed in the RFS2 final rule promulgated on March 26, 2010 

(75 FR 14670). This rule simply establishes the applicable volume for biomass-based diesel for 

2013 at a level that is consistent with the analyses in the RFS2 final rule. Therefore, this action 

will not impose any additional requirements on small entities beyond those which have already 

been evaluated. 

We received a comment suggesting that impacts on truckers of the applicable volume of 

biomass-based diesel for 2013 established in this rule should be evaluated as part of our standard 

small business impact analysis. In response, we note that such analyses are only required under 

the Regulatory Flexibility Act for parties directly regulated by a rule and that, in general, 

truckers are not directly regulated by today's action nor under the regulatory requirements 

established in the RFS2 final rule.

D. Unfunded Mandates Reform Act
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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 establishes the applicable volume for biomass-based diesel for 

2013 at a level that is consistent with the analyses in the RFS2 final rule. 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. A summary of the concerns raised, and EPA’s response 

to those concerns, is provided in this preamble. 

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
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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.

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 
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will submit a report containing this rule and other required information to the U.S. Senate, the 

U.S. House of Representatives, and the Comptroller General of the United States prior to 

publication of the rule in the Federal Register. A major rule cannot take effect until 60 days 

after it is published in the Federal Register. This action is not a “major rule” as defined by 5 

U.S.C. 804(2). This rule will be effective on the date of publication.
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VIII. 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.