DRAFT 5/18/10

1 ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

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

RIN 2060-AO81

Regulation of Fuels and Fuel Addi tives: 2011 Renewable Fuel Standards

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice of Proposed Rulemaking.

SUMMARY: Under the Clean Air Act Section 21 1(o), as amended by the Energy Independence and Security Act of 2007 (EISA) , the Environmental Protection Agency is required to set the renewable fuel standards each November for the following year based on gasoline and diesel projections from EIA. Additionally, EPA is required to set the cellulosic biofuel standard each year based on the volume projected to be available during the following year, using EIA projections and assessments of production capability from industry. This regulatory ac tion proposes these annual standards for cellulosic biofuel, biomass-base d diesel, advanced biofuel, a nd renewable fuels that apply to all gasoline and diesel produced or importe d in year 2011. This action also presents two proposed changes to the RFS2 regulations . The first would create a temporary and limited means for certain renewable fuel producer s to generate delayed RINs after they have produced and sold renewable fuel. Th is proposed provision would apply only to those producers who use canola oil, grai n sorghum, pulpwood, or palm oil to produce renewable fuel. The second proposed regula tory provision would establish criteria for foreign countries to adopt an aggregate ap proach to compliance with the renewable biomass provision akin to that applicable to the U.S.

DATES: Comments must be received on or before [ insert date 30 days after publication in the federal register ].

Hearing: We do not expect to hold a public hearing. However, if we receive such a request we will publish informa tion related to the timing and location of the hearing and the timing of a new deadline for public comments.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2010-0133, by one of the following methods:

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

• Email: asdinfo@epa.gov

.

• Mail: Air and Radiation Docket and Information Center, Environmental Protection Agency, Mailcode: 2822T, 1200 Pe nnsylvania Ave., NW., Washington, DC

20460.DRAFT 5/18/10

2 • Hand Delivery: EPA Docket Center , EPA West Building, Room 3334, 1301 Constitution Ave., NW., Washington, DC 20460. Such deliveries are only accepted during the Docket’s normal hours of operation, and special arrangements should be made

for deliveries of boxed information.

Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-2010-0133. EPA's policy is that all comments r eceived will be included in the public docket without change and may be made available online at www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through www.regulations.gov or e- mail. The www.regulations.gov website is an “anonymous access” system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e-mail comment directly to EPA without going through www.regulations.gov your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to t echnical difficulties and cannot c ontact you for clarification, EPA may not be able to consider your comme nt. Electronic files s hould avoid the use of special characters, any form of encryption, a nd be free of any defects or viruses. For

additional information about EPA’s public docket visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm. For additional instructions on submitting comments, go to Section I.B of the SUPPLEMENTARY INFORMATION section of

this document.

Docket: All documents in the docket are liste d in the www.regulations.gov index. Although listed in the index, some informati on 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 availa ble only in hard copy. Publicly available

docket materials are available either electr onically in www.regulations.gov or in hard copy at the Air and Radiation Docket a nd Information Center , EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW, Washi ngton, 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 Readin g 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, Assessmen t and Standards Division, Environmental Protection Agency, 2000 Traverwood Drive, Ann Arbor MI 48105; Telephone number : 734-214-4131; Fax number: 734-214- 4816; E-mail address: macallister.julia@epa.gov,

or Assessment and Standards Division Ho tline; telephone numbe r (734) 214-4636; Email address asdinfo@epa.gov.

SUPPLEMENTARY INFORMATION:

I. General InformationDRAFT 5/18/10

3 A. Does this Action Apply to Me?

Entities potentially affected by this propos ed rule are those involved with the production, distribution, and sale of transportation fuels, including gasoline and diesel

fuel or renewable fuels such as ethanol a nd biodiesel. Potentiall y regulated categories

include:

Category NAICS 1

Codes SIC 2

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 stati ons and terminals Petroleum and petroleu m products merchant

wholesalers

Other fuel dealers

1 North American Industry Cl assification System (NAICS)

2 Standard Industrial Classi fication (SIC) system code.

This table is not intended to be exhaustiv e, but rather provides a guide for readers regarding entities likely to be regulated by this proposed action. This table lists the types of entities that EPA is now aware could potentia lly be regulated by this proposed action. Other types of entities not listed in the table could also be regulated. To determine whether your activities would be regulated by this proposed action, you should carefully examine the applicability criteria in 40 CFR part 80. If you have any questions regarding the applicability of this proposed action to a pa rticular entity, consult the person listed in the preceding section.

B. What Should I Consider as I Prepare My Comments for EPA?

1. Submitting CBI

Do not submit this information to EPA through www.regulations.gov or e-mail. Clearly mark the part or all of the inform ation that you claim to be CBI. For CBI information in a disk or CD ROM that you ma il to EPA, mark the outside of the disk or CD ROM as CBI and then identify electronicall y within the disk or CD ROM the specific

information that is claimed as CBI. In add ition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain

the information claimed as CBI must be s ubmitted for inclusion in the public docket.

Information so marked will not be disclose d except in accordance with procedures set forth in 40 CFR part 2.

2. Tips for Preparing Your CommentsDRAFT 5/18/10

4 When submitting comments, remember to: • Identify the rulemaking by docket number and other identifying information (subject heading, Federal Register date and page number). • Follow directions - The agency may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or

section number. • Explain why you agree or disagree, suggest alternatives, and substitute language for your requested changes. • Describe any assumptions a nd provide any technical info rmation and/or data that you used. • If you estimate potential costs or burdens, explain how you arrived at your

estimate in sufficient detail to allow for it to be reproduced. • Provide specific examples to illustrate your concerns, and suggest alternatives. • Explain your views as clearly as possi ble, avoiding the use of profanity or personal threats. • Make sure to submit your comments by the comment period deadline identified.

Outline of this preamble

I. Executive Summary ................................................................................................... 6

A. Statutory Requirements for Cellulosic Biofuel .............................................................. 7

B. Assessment of 2011 Cellulosic Biofuel Volume .............................................................. 8

C. Advanced Biofuel and Total Renewable Fuel .............................................................. 10

D. Proposed Percentage Standards.................................................................................... 10

II. Volume Production and Import Potential for 2011............................................ 13

A. Cellulosic Biofuel ............................................................................................................ 1 3

1. Domestic Cellulosic Ethanol ......................................................................................................14

2. Domestic Cellulosic Diesel ........................................................................................................16

3. Other Domestic Cellulosic Biofuels ...........................................................................................17

4. Imports of Cellulosic Biofuel .....................................................................................................17

5. Summary of Volume Projections ...............................................................................................18

B. Potential Limi tations ...................................................................................................... 21

C. Advanced Biofuel and Total Renewable Fuel .............................................................. 21

D. Biomass-Based Diesel ..................................................................................................... 24

III. Proposed Percentage Standards for 2011 .......................................................... 27

A. Background ..................................................................................................................... 27

B. Calculation of Standards................................................................................................ 27

1. How Are the Standards Calculated? ...........................................................................................27

2. Small Refineries and Small Refiners ..........................................................................................31

IV. Cellulosic Biofuel Technology Assessment......................................................... 32

A. What Pathways are Valid for the Production of Cellulosic Biofuel?......................... 32DRAFT 5/18/10

5 B. Cellulosic Fe edstocks...................................................................................................... 34

C. Emerging Technologies .................................................................................................. 34

1. Biochemical

............................................................................................................................... 36

a. Feedstock Handling............................................................................................................. ..37

b. Biomass Pretreatment........................................................................................................... .38

c. Hydrolysis ..................................................................................................................... ........38

i. Acid Hydrolysis .................................................................................................................39

ii. Enzymatic Hydrolysis .......................................................................................................39

d. Fuel Production ................................................................................................................ .....40

e. Fuel Sepa ration................................................................................................................ ......41

f. Process Variations ............................................................................................................. ....42

g. Current Status of Biochemical Conversion Technology .......................................................42

h. Major Hurdles to Commercialization ....................................................................................43

2. Thermochemical .........................................................................................................................43

a. Ethanol based on a Thermochemical Platform......................................................................47

b. Diesel and Naphtha Production based on a Thermochemical Platform.................................48

3. Hybrid Thermochemical/Biochemical Processes .......................................................................49

4. Pyrolysis and Depolymerization ................................................................................................51

a. Pyrolysis Diesel Fuel and Gasoline.......................................................................................51

b. Catalytic Depolymerization...................................................................................................53

5. Catalytic Reforming of Sugars to Gasoline ................................................................................54

V. Proposed Changes to RFS2 Regulations ................................................................ 56

A. Delayed RIN Generation for New Pathways................................................................ 56

B. Criteria and Process for Adoption of Aggregate Approach to Renewable Biomass for Foreign Countries.......................................................................................................... .... 58

1. Criterion and Considerations ......................................................................................................59

2. Data Sources ..............................................................................................................................6 0

3. Petition Submission ....................................................................................................................61

4. Petition Process ..........................................................................................................................62

VI. Public Participation ............................................................................................. 64

A. How Do I Submit Comments?....................................................................................... 64

B. How Should I Submit CBI to the Agency?................................................................... 64

VII. Statutory and Executi ve Order Reviews.............................................................. 66

A. Executive Order 12866: Regulatory Planning and Review......................................... 66

B. Paperwork Reduction Act.............................................................................................. 66

C. Regulatory Flexibility Act.............................................................................................. 66

D. Unfunded Mandates Reform Act .................................................................................. 67

E. Executive Order 131 32: Federalism.............................................................................. 67

F. Executive Order 13175: Consultation a nd Coordination with Indian Tribal

Governments.................................................................................................................... ........ 68

G. Executive Order 13045: Protection of Ch ildren from Environmental Health Risks and Safety Risks............................................................................................................... ........ 68

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use...................................................................................... 68DRAFT 5/18/10

6 I. National Technology Transfer Advancement Act ....................................................... 68

J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations ........................................................... 69

VIII. Statutory Authority........................................................................................... 70

I. Executive Summary

The Renewable Fuel Standard (RFS) program began in 2007 following the requirements in Clean Air Act (CAA) secti on 211(o) which were implemented through the Energy Policy Act of 2005 (EPAct). The statutory requirements for the RFS program were subsequently modified through the En ergy Independence and Security Act of 2007 (EISA), resulting in the release of revi sed regulatory requirements on March 26, 2010 1

. In general, the transition from the RFS1 requi rements of EPAct to the RFS2 requirements of EISA will occur on July 1, 2010.

EPA is required to determine and pub lish the applicable annual percentage standards for each compliance year by November 30 of the previous year. The determination of the applicab le standards under RFS2 require s the EPA to conduct an indepth evaluation of the volume of qualifying ce llulosic biofuel that can be supplied in the following year. If the projected volume of cellulosic biofuel production is less than the required volume specified in th e statute, EPA must lower th e required volume used to set the annual cellulosic biofuel percentage stan dard to the projected volume of production.

We must also determine whether the advanc ed biofuel and/or total renewable fuel volumes should be reduced by the same or a lesser amount. Since these evaluations will be based on evolving information about emergi ng segments of the biofuels industry, and may result in the required volumes differing fro m those in the statute, we believe that a notice-and-comment rulemaking process is a ppropriate. Today's notice provides our evaluation of the projected production of cellulosic biofuel for 2011, and proposed percentage standards for compliance year 2011. We will complete our evaluation based on comments received in response to this proposal, the Production Outlook Reports due to the Agency on September 1, 2010, the estimate of projected biofuel volumes that the EIA is required to provide to EPA by Oct ober 31, and other information that becomes available, and will finalize the st andards for 2011 by November 30, 2010.

Today's proposed rule does not include an assessment of the environmental impacts of the standards we are proposing fo r 2011. All of the impacts of the RFS2 program were addressed in the RFS2 fina l rule published on March 26, 2010, including impacts of the biofuel standards specified in the statute. Today's rulemaking simply proposes the standards for 2011 whose impacts were already analyzed previously.

Today's notice also presents two proposed changes to the RFS2 regulations. The first would create a temporary and limited mean s for certain renewable fuel producers to

1 75 FR 14670DRAFT 5/18/10

7 generate RINs after they have produced a nd sold renewable fuel. This proposed provision for "Delayed RINs" would apply onl y to those producers who use canola oil, grain sorghum, pulpwood, or palm oil to produce renewable fuel, and only if EPA determines that fuel pathways utilizing th ese feedstocks provide appropriate greenhouse gas reductions as compared to baseline fuels to enable EPA to list the pathways in Table 1 to §80.1426. We are proposing that the provision for Delayed RINs would apply only

to these four feedstocks because we would have included them in the final RFS2 rule if the lifecycle analyses had been completed in time. The greenhouse gas (GHG) lifecycle impacts of these four feedstocks are current ly being analyzed as a supplement to the RFS2 final rule and are expected to be completed in 2010. The second proposed regulatory provision would establish criteria for EPA to use in determining whether to authorize renewable fuel producers using fore ign-grown feedstocks to use an aggregate approach to compliance with the renewable bi omass verification provisions, akin to that applicable to producers using crops and crop re sidue grown in the United States. Further discussion of both of these proposed pr ovisions can be found in Section V.

Finally, we note that in the RFS2 final ru le we also stated our intent to make two announcements each year:

• Set the price for cellulosic biofuel waiver credits that will be made available to obligated parties in the event that we reduce the volume of cellulosic biofuel below the volume required by EISA.

• Announce the results of our assessment of the aggregate compliance approach for verifying renewable biom ass requirements for U.S. crops and crop residue, and our conclusion regarding whether the aggregate compliance provision will continue to apply.

For both of these determinations EPA will use specific sources of data and a methodology laid out in the RFS2 final rule. We intend to present the results of both of

these determinations in the final rule following today's proposal.

A. Statutory Requirements for Cellulosic Biofuel

The volumes of renewable fuel that must be used under the RFS2 program each year (absent an adjustment or waiver by EPA) are specified in CAA 211(o)(2). These

volumes for 2011 are shown in Table I.A-1.

Table I.A-1 Required Volumes in the Clean Air Act for 2011 (bill gal)

Actual Volume Ethanol Equivalent

Volume

Cellulosic biofuel 0.25 0.25

Biomass-based diesel 0.80 1.20

Advanced biofuel 1.35 1.35DRAFT 5/18/10

8 Renewable fuel 13.95 13.95

By November 30 of each year, the EPA is required under CAA 211(o) to determine and publish in the Federal Register the renewabl e fuel standards for the following year. These standards are to be based in part on transportation fuel volumes estimated by the Energy Information Administration (EIA) for the following year. The calculation of the percentage standards is based on the form ulas in §80.1405(c) which express the required

volumes of renewable fuel as a volume percentage of gasoline and diesel sold or introduced into commerce in the 48 contiguous states plus Hawaii.

The statute requires the EPA to determine whether the projected volume of cellulosic biofuel production for the following year is less than the minimum applicable

volume shown in Table I.A-1. If this is the case, then the standard for cellulosic biofuel must be based upon the volume projected to be available rather than the applicable volume in the statute. In addition, if EP A reduces the required volume of cellulosic biofuel below the level specified in the statute, the Act also indicates that we may reduce the applicable volume of advanced biofuels and total renewable fuel by the same or a

lesser volume.

As described in the final rule for the RFS2 program, we intend to examine EIA’s projected volumes and other available data including the Production Outlook Reports required under §80.1449 in making the determin ation of the appropriate volumes to require for 2011. Since the first set of Production Outlook Reports are not due until September 1, 2010, they were not available fo r today's proposal but will be considered for development of the final rule to be released by November 30, 2010.

B. Assessment of 2011 Cellulosic Biofuel Volume

To estimate the volume of cellulosic biofuel that could be made available in the U.S. in 2011, we researched all potential pr oduction sources by company and facility.

This included sources that were still in th e planning stages, those that were under construction, and those that are already pr oducing some volume of cellulosic ethanol, cellulosic diesel, or some other type of cellu losic biofuel. We considered all pilot and demonstration plants as well as commercial plants. From this universe of potential

cellulosic biofuel sources we identified the subset that had a possibility of producing some volume of qualifying cellulosic biofuel for use as transportation fuel in 2011. We then conducted a rigorous pro cess of contacting all of thes e producers to determine which ones were actually in a position to produce and make available an y commercial volumes

of cellulosic biofuel in 2011. Based on info rmation gathered in this process, we estimated the maximum potentially available 2011 volumes. For the final rule, we will specify the projected available volume for 2011 that will be the basis for the percentage standard for cellulosic biofuel. To determine the projected available volume, we will

consider factors such as the current and ex pected state of funding, the status of the technology and contracts for feedstocks , and progress toward s construction andDRAFT 5/18/10

9 production goals. A complete list of all the factors we expect to consider in this process is provided in Section II.A.5.

In our assessment we evaluated both dom estic and foreign sources of cellulosic biofuel. Of the domestic sources, we estimated that seven facilities have the potential to

make volumes of cellulosic bi ofuel available for transportation use in the U.S. in 2011. We also determined that one facility in Canada has the potential to export some cellulosic biofuel to the U.S. These facilities are listed in Table I.B-1 along with our estimate of the maximum potentially available volume.

Table I.B-1 Maximum Potentially Ava ilable Cellulosic Biofuel Plant Volumes for 2011

Company Location Fuel type Maximum potentially

available volume(million ethanolequivalent gallons)

AE Advanced Fuels Keyes Keyes, CA Ethanol 0.5

Agresti Biofuels Pike County, KY Ethanol 1 Bell Bio-Energy Atlanta, GA Diesel

feedstock 11.9

Cello Energy Bay Minette, AL Diesel 8.5
DuPont Dansico Vonore, TN Ethanol 0.15 Fiberight Blairstown, IA Ethanol 2.8 Iogen Corporation O ttawa, Ont Ethanol 0.25 KL Energy Corp / WBE Upton, WY Ethanol 0.4

Total 25.5

The volumes in Table I.B-1 for each facility represent the volume that would be produced in 2011 based upon the owner's expect ed month of startup and an assumed period of production rampup fo r testing and process valida tion. However, none of the facilities we evaluated are currently producing ce llulosic biofuel at the rates they project for 2011. Moreover, there are other uncertainties associated with each facility's projected volume that could result in less production volume in 2011 than the maximum potentially

available values shown in Table I.B-1. Thes e uncertainties include outstanding issues in areas such as technology, funding, and cons truction. Historical successes in meeting various past milestones also play a role in assessing the likelihood of meeting future milestones. A detailed discussion of these uncertainties is presented in Section II.A. Finally, the volumes that should be consider ed for setting the 2011 standard are those that result from valid cellulosic biofuel pathways in Table 1 to §80.1426. As described more fully in Section IV.A, some of the facilities in Table I.B-1 may use feedstocks that have not yet been subjected to lifecycle analyses to determine if the pathway meets the applicable GHG thresholds.DRAFT 5/18/10

10 Based on our preliminary assessment for this NPRM, we believe that we could justify a 2011 cellulosic biofuel volume re quirement of at least 6.5 million ethanolequivalent gallons, and poten tially as high as 25.5 million gallons. For the final rule we

will use additional information that becomes available after publication of this proposal and a more precise assessment of the uncertainties associated with each facility to determine the projected available volume on which to base the cellulosic biofuel percentage standard for 2011.

C. Advanced Biofuel and Total Renewable Fuel

As described in Section I.A above, the st atute indicates that we may reduce the applicable volume of advanced biofuel and tota l renewable fuel if we determine that the projected volume of cellulosi c biofuel production for 2011 falls short of the statutory volume of 250 million gallons. As shown in Table I.B-1, we are proposing a determination that this is the case. Therefore, we also needed to evaluate the need to lower the required volumes for advanced biofuel and total renewable fuel.

We first considered whether it appear s likely that the required biomass-based diesel volume of 0.8 billion gallons can be met with existing biodiesel production capacity in 2011. As discussed in Section II.D, we believe that the 0.8 billion gallon

standard can indeed be met. Since biodies el has an Equivalence Value of 1.5, 0.8 billion physical gallons of biodiesel would provide 1.20 billion etha nol-equivalent gallons that

can be counted towards the advanced biofue l standard of 1.35 billion gallons. Of the remaining 0.15 bill gallons, up to 0.026 bill ga llons would be met with the proposed

volume of cellulosic biofuel. Based on our an alysis as described in Section II.C, there may be sufficient volumes of other advan ced biofuels, such as imported sugarcane ethanol, additional biodiesel, or renewable diesel, such that the standard for advanced

biofuel could remain at the statutory level of 1.35 billion gallons. However, uncertainty in the potential volumes of these other adva nced biofuels coupled with the range of potential production volumes of cellulosic biofue l could provide a rationale for lowering

the advanced biofuel standard. If we do not simultaneously lower the required volume for total renewable fuel, the result would be that additional volumes of conventional renewable fuel, such as corn-starch ethanol , would be produced, effectively replacing some advanced biofuels. In today's NPRM we are proposing that neither the required

2011 volumes for advanced biofuel nor tota l renewable fuel be lowered below the statutory volumes. However, we request comment on whether the advanced biofuel

and/or total renewable fuel volume requirements should be lowered if, as we propose, EPA lowers the required cellulosic biofuel volume from that specified in the Act.

D. Proposed Percentage Standards

The renewable fuel standards are expressed as a volume percentage, and are used by each refiner, blender or importer to dete rmine their renewable fu el volume obligations. The applicable percentages are set so that if each regulated party meets the percentages,DRAFT 5/18/10

11 and if EIA projections of gasoline and dies el use are accurate, then the amount of renewable fuel, cellulosic biofuel, biomass-based diesel, and advanced biofuel used will meet the volumes required on a nationwide basis. To calculate the percentage standard for cellulosic biofuel for 2011, we have us ed a potential volume range of 6.5 - 25.5 million ethanol-equivalent gallons (represen ting 5 - 17.1 million physical gallons). For the final rule, EPA intends to pick a single value from within this range to represent the projected available volume on which the 2011 pe rcentage standard for cellulosic biofuel will be based. We are also proposing that the applicable volumes for biomass-based diesel, advanced biofuel, and total renewable fuel for 2011 will be those specified in the

statute. These volumes ar e shown in Table I.D-1.

Table I.D-1 Proposed Volumes for 2011

Actual Volume Ethanol Equivalent

Volume Cellulosic biofuel 5 - 17.1 mill gal 6.5 - 25.5 mill gal Biomass-based diesel 0.80 bill gal 1.20 bill gal Advanced biofuel 1.35 bill gal 1.35 bill gal Renewable fuel 13.95 bill gal 13.95 bill gal

Four separate standards are required under the RFS2 program, corresponding to the four separate volume requi rements shown in Table I.D-1. The specific formulas we use to calculate the renewable fuel percentage standards are contained in the regulations at §80.1405 and repeated in Section III.B.1. Th e percentage standards represent the ratio of renewable fuel volume to non-renewable ga soline and diesel volum e. The projected volumes of gasoline and renewable fuels used to calculate the standards are provided by EIA's Short-Term Energy Outlook (STEO) 2 . The projected volume of transportation

diesel used to calculate the standards is provided by EIA's 2010 Annual Energy Outlook (early release version). 3 Because small refiners and sma ll refineries are also regulated parties beginning in 2011 4 , there is no small refiner/refi nery volume adjustment to the

2011 standard as there was for the 2010 standar d. Thus, the increase in the percentage standards relative to 2010 appears smaller than would otherwise be the case, since more obligated parties will be par ticipating in the program. The proposed standards for 2011

are shown in Table I.D-2. Detailed ca lculations can be found in Section III.

Table I.D-2

2 The March 2010 issue of STEO was used for today's proposal. We intend to use the October 2010

version for the final rule.

3 EIA has recommended the use of the Annual Energy Outlook (AEO) rather than the Short Term Energy Outlook as a better representation of the estimated tr ansportation sector diesel fuel use. We will use the

most recent version of AEO in the final values of the standards.

4 The Department of Energy concluded that there is no reason to believe that any small refinery would be disproportionately harmed by inclusion in the proposed RFS2 program for 2011 and beyond. See DOE report “EPACT 2005 Section 1501 Small Refineries Exemption Study”, (January, 2009). We will revisit extensions to the exemption for small refiners and refineries if DOE revises their study and provides a different conclusion, or an individual small refinery is able to demonstrate that it will suffer a disproportionate economic hardship under the RFS program.DRAFT 5/18/10

12 Proposed Percentage Standards for 2011

Cellulosic biofuel 0.004-0.015%

Biomass-based diesel 0.68%

Advanced biofuel 0.77%

Renewable fuel 7.95%DRAFT 5/18/10

13 II. Volume Production and Import Potential for 2011

In order to project production volumes of cellulosic biofuel in 2011 for use in setting the percentage standards, we collect ed information on individual facilities that have the potential to produce qualifying volum es for consumption as transportation fuel, heating oil, or jet fuel in the U.S. in 2011. This section describe s the potential volumes

that we believe could be produced or imported in 2011 as well as the uncertainties

associated with those volumes . The volumes listed in this section do not represent the projected available volume of cellulosic biofuel that will be used to finalize the cellulosic biofuel percentage standard for 2011. Rather , for today's NPRM we have assessed the maximum potentially available volume for 2011, which is intended to represent an upper bound of the volume of fuel that may be pr oduced and made available. The production of cellulosic biofuel remains highly uncer tain, and EPA expects that the volume of cellulosic biofuel used to set the 2011 percenta ge standard will be a lesser volume than this maximum potentially available volume. Section III describes the conversion of our maximum potentially available volumes for cellulosic biofuel into a range of percentage

standards.

While the 2011 volume projections in t oday's proposal were based on our own

assessment of the cellulosic biofuel indus try, by the time we announce the final 2011 volumes and percentage standard s we will have additional info rmation. First, in addition to comments in response to today's proposal , we will have update d and more detailed information about how the industry is prog ressing in 2010. Second, by September 1 all registered producers and importers of re newable fuel must submit Production Outlook Reports describing their exp ectations for new or expanded biofuel supply for the next five years, according to §80.1449. Finally, by October, 2010 the Energy Information Administration (EIA) is required by statute to provide EPA with an estimate of the volumes of transportation fuel , biomass-based diesel, and ce llulosic biofuel projected to

be sold or introduced into commerce in the U.S. in 2011.

A. Cellulosic Biofuel

The task of projecting the volume of cellu losic biofuels that will be produced in 2011 is a difficult one. Currently there are no facilities consistently producing cellulosic

biofuels for commercial sale. Announcements of new projects, changes in project plans, project delays, and cancellations occur with great regularity. Biofuel producers face not only the challenge of the scale up of innovativ e, first-of-a-kind technology, but also the challenge of securing funding in a difficult economy.

In order to project cellulosic biof uel production in 2011, EPA has tracked the progress of over 100 biofuel pr oduction facilities. From this list of facilities we used publically available information, as well as information provided by DOE and USDA, to

determine which facilitie s were the most likely candidate s to produce cellulosic biofuel and make it commercially available in 2011. Each of these companies was contacted by

EPA in order to determine the current status of their facilities and discuss theirDRAFT 5/18/10

14 commercialization plans for the coming years. Our estimate of the maximum potentially available cellulosic biofuel pr oduction in 2011 is based on the information we received in conversations with these companies as well as our own assessment of the likelihood of these facilities successfully producing cellulosic biofuel in the volumes indicated.

A brief description of each of the co mpanies we believe may produce cellulosic

biofuel and make it commercial ly available can be found below. These companies have been grouped according to the type of biofuel they produce. For the purpose of setting

the cellulosic biofuel standard for 2011 this is a convenient grouping, as the number of RINs generated per gallon of fuel produced is dependent on the type of fuel. A more in depth discussion of the technologies used to produce cellulosic biofuels can be found in

Section IV.

In today's NPRM EPA is proposing a range, rather than a single value, for the required 2011 cellulosic biofuel volume. At a minimum, we believe that a volume of 6.5 million gallons could be justifie d based on currently available information. This is the cellulosic biofuel volume that was required in 2010, and absent a waiver for some portion of this volume, producers will be aiming to meet it. Therefore, it is reasonable to project that this same volume could, at minimum, also be produced in 2011.

For a maximum potentially available ce llulosic biofuel volume for 2011, we are proposing 25.5 million ethanol equivalent gall ons, representing the highest volume of fuel that can reasonably be expected to be produced and made available based on current

information. The rest of this section describes the analyses th at were used as the basis for this maximum value. We will continue to gather more information to help inform our

decision on the final cellulosic biofuel sta ndard for 2011, and we will specify a single volume in the final rule that will be the basis for the cellulosic biofuel percentage

standard for 2011.

1. Domestic Cellulosic Ethanol

Based on our assessment of the cellulosic biofuel industry we believe that there are five companies in the United States with the potential to produce cellulosic ethanol and make it commercially ava ilable in 2011. These companies are AE Biofuels, Agresti Biofuels, DuPont Danisco Cellulosic Ethanol, Fiberight, and KL Energy Corporation. This section will provide a brief description of each of these companies and our assessment of their potential fuel production in 2011. This section also provides a brief update on companies from whom we do not expect any commercial sales of transportation fuel in 2011 in the U.S. but were included in prior assessments.

AE Biofuels is a company that plans to convert corn cobs and corn stover to ethanol using an enzymatic hydrolysis. They plan to use an integrated process that

converts both starch and cellulose to et hanol. In August 2008 they opened a demonstration plant in Butte, Montana to test their technology and gather information for their first commercial scale plant. AE Biofue ls has reached a lease agreement with CilionDRAFT 5/18/10

15 to operate Cilion’s 55 MGY corn ethanol plant in Keyes, CA under the name AE Advanced Fuels Keyes. This facility has been idled since April 2009 and will require repairs before being operational. AE Biofuels plans to start up production with a starch feedstock in late-2010 and then begin to transition some production to cellulosic feedstock in mid-2011. AE Biofuels plans to eventually use up to 25% cellulosic feedstock for ethanol production in this facility. EPA projects that up to 0.5 million gallons of ethanol may be produced by this facility in 2011.

Agresti Biofuels plans to produce etha nol from separated municipal solid waste (separated MSW) at a facility in Pike Count y, Kentucky. Their process uses a gravity pressure vessel licensed from Ge neSyst to crack the lignin in their feedstock and then a

combination of weak bases and acids to convert the cellulose and hemicellulose into simple sugars for later fermentation into et hanol. Agresti plans to begin construction on their first production facility in Pike Count y sometime in the summer of 2010 and hope to be producing ethanol by the end of 2011. The full production capacity of this facility will be 20 million gallons of ethanol per year. Due to the fact that construction on this facility has not yet begun and production is not exp ected until late in 2011 EPA expects no more than 1 million gallons of cellulosic ethanol to be produced by Agresti Biofuels in 2011.

DuPont Danisco Cellulosic Ethanol (DDC E) began start up operations at a small demonstration facility in Vonor e, Tennessee in early 2010. This facility has a maximum production capacity of 250,000 gallons of etha nol per year and uses an enzymatic hydrolysis process to convert corn cobs into ethanol. The main purpose of this facility is not to produce ethanol to be sold commercially, but rather to provide information for the future construction and optimization of larger, commercial scale cellulosic ethanol production facilities. DDCE have indicated that they do not intend to produce more than 150,000 gallons of ethanol in 2011 from the Vonore facility.

Fiberight is another company planning to convert MSW to ethanol. Fiberight purchased a small corn ethanol plant in Bl airstown, IA and has converted it to produce cellulosic ethanol. They use an enzymatic hy drolysis process, with enzymes provided by Novozymes, to convert the cellulosic waste mate rials to simple sugars and eventually to ethanol. Fiberight has a unique enzyme recycle and recovery process that allows them to affordably use high concentrations of enzyme s to increase the speed and conversion rate of the cellulose to simple sugars. Fiberi ght plan to begin ethanol production in the summer of 2010 and ramp up to full production capacity of 5.7 million gallons of ethanol per year by late 2011. Based on company estimates, EPA projects Fiberight could produce as much as 2.8 million gallons of cellulosic ethanol in 2011.

The fifth company that EPA is aware of with the potential to produce cellulosic ethanol in 2011 is KL Energy Corporation. KL Energy has a small facility in Upton, Wyoming that uses an enzymatic hydrolys is process to convert wood chips and wood waste to ethanol. This facility has a maximum annual producti on volume of 1.5 million gallons and has been operational since the fall of 2007. Since KL Energy completed construction on this facility they have been slowly ramping up production and gathering information to optimize this and future et hanol production facilities. KL has informedDRAFT 5/18/10

16 EPA that they intend to produce 400,000 gallons of cellulosic ethanol from their Upton, WY facility in 2011.

In addition to the five companies mentioned above, EPA is also tracking the progress of more than 70 ethanol production facilities in various stages ranging from construction to planning stages. Several of these companies, including Abengoa, BlueFire Ethanol, Coskata, Fulcrum, POET, and Vercipia all intend to begin the production and commercial sale of cellulosic ethanol in 2012. These facilities range in maximum production capacity from 10 to 100 million gallons of ethanol. EPA anticipates a significant increase in the pr oduction and sale of ce llulosic ethanol in 2012, and strong continued growth in the following ye ars. In addition, if any of these or other companies accelerates their production plans to make cellulosic biofuel available for commercial sale in 2011, we will take those volumes into account in our final rule.

2. Domestic Cellulosic Diesel

EPA is also aware of two companies in the United States with the potential of producing cellulosic diesel fuel in 2011. The fi rst of these companies is Cello Energy. Cello Energy plans to use a catalytic depol ymerization process to produce diesel fuel from wood chips and hay. Cello currently has a structurally complete facility in Bay Minette, Alabama with an a nnual production capacity of 20 million gallons of diesel per year. While having a structurally complete facility puts Cello ahead of many other potential biofuel producers they ha ve yet to be able to produce biofuel at anywhere near the production capacity. They are currently a ssessing feedstock preparation and handling issues that must be resolved before they are able to again attempt start up and production at this facility. If these issues are successf ully addressed EPA belie ves that Cello has the potential to produce up to 5 million gallons ( 8.5 million ethanol equivalent gallons) of

cellulosic diesel fuel in 2011.

Another potential producer of cellulosic biofuel in 2011 is Bell Bio-Energy. Bell Bio-Energy uses proprietary organisms to convert waste materials to liquid fuels and compost in a single step. The company currently has an agreement in place for the sale of the compost they produce and are searching for a location for their first plant and a partner to supply the waste materials they inte nd to use as feedstock. The liquid fuel they produce is not a finished transportation fuel, but could be upgraded to jet or diesel fuel. Bell Bio-Energy is currently working with a refining company to analyze the fuel they produce and determine the extent of upgrading necessary for the fuel to qualify as transportation fuel. They plan to begin construction on their first facility, which will have an annual fuel production capacity of 14.4 million gallons per year, as soon as a suitable site and partner are found. The simplicity and low capital costs of Bell Bio-Energy’s single step production process allow them to construct plants very rapidly, in as little as six weeks. This would make it possible for Bell Bio-Energy to produce cellulosic biofuel in 2011 despite the fact that they have not yet begun construction on their first commercial scale facility. It is unclear when fuel will be produced at this facility, and whether it would qualify under the RFS2 program. If Bell Bio-Energy is successful inDRAFT 5/18/10

17 producing and upgrading their fuel EPA es timates they could produce as much as 7 million gallons (11.9 million ethanol equivalent gallons) of jet or diesel fuel in 2011.

EPA is also tracking the progress of 17 other facilities that plan to produce

cellulosic diesel. Flambeau Rivers Biof uels, New Page, and Terrabon are planning on opening commercial scale cellulosic diesel facilities in 2012. Both Bell Bio-Energy and Cello have plans to build additional facilities if their initial projects are successful. As with cellulosic ethanol, cellulosic diesel pr oduction has the potential for rapid growth in 2012 and the following years.

3. Other Domestic Cellulosic Biofuels

We are currently unaware of any compan ies in the United States planning on producing cellulosic biofuel other than etha nol and diesel and making it commercially available. EPA is currently tracking the efforts of 10 companies that plan to produce fuels such as gasoline, jet fuel, dimethyl ether (DME), and others. Many of these companies have reported that they are still developing their technologies and waiting for funding, and that they are not expecting to make any cellulosic fuel commercially

available until 2012 at the earliest. There ar e several companies, such as Gevo and Virent, with small demons tration facilities w ho intend to produce other fuels from cellulosic feedstocks, but are currently optimiz ing their technology with sugar or starch feedstocks. EPA anticipates that in the future this may be a significant source of cellulosic biofuel, however we are only exp ecting cellulosic ethanol and diesel to be produced in 2011.

4. Imports of Cellulosic Biofuel

In addition to the companies located in the United States, EPA is also aware of two Canadian companies with the potential for cellulosic biofuel production in 2011. If this fuel was imported into the United States, these companies would be eligible to participate in the RFS2 program. Counting on cellulosic biofuel pr oduced internationally in setting the 2011 standard brings with it the additional uncertainty associated with the fact that the fuel may be used locally rather than imported into the United States.

Iogen uses a steam explosion pre-tr eatment process followed by enzymatic hydrolysis to produce cellulosic ethanol from whea t, oat, and barley straw. They have a demonstration facility with an annual production capacity of 500,000 gallons of ethanol located in Ontario, Canada. This facilit y has been operational and producing small

volumes of ethanol since 2004. So far all of the ethanol produced by this facility has been used locally and in racing and other promotional events. Iogen, however, is exploring the possibility of participating in the RFS2 program. If they do decide to import ethanol to the United States, EPA proj ects that they may provide as much as 250,000 gallons of cellulosic ethanol in 2011 based on production volumes from previous

years.DRAFT 5/18/10

18 Another Canadian company with the pot ential to produce cellulosic ethanol in 2011 is Enerkem. Enerkem plans to use a th ermo-chemical process to gasify separated MSW and other waste products and then use a catalyst to convert the synthesis (syn) gas into ethanol. Enerkem is currently finish ing construction on a 1.3 million gallon per year facility in Westbury, Quebec and plans to begin producing ethanol in the summer of 2010. They are also planning a 10 million gall on per year facility in Edmonton, Alberta, however production from this facility is not expected until 2012. Enerkem has informed EPA that they plan to market ethanol they produce locally, and have no intentions to import cellulosic ethanol into the United Stat es. We are therefore not projecting any

available cellulosic fuel from Enerkem in 2011.

While Canada may be the most likely s ource of imported cellulosic biofuels due to its close proximity, it is possible that ce llulosic biofuels produced in other countries may be imported into the United States as well. Another potential source of cellulosic biofuel imports is Brazil, due to its estab lished ethanol industry and history of importing

ethanol into the United States. EPA is aware of several companies exploring the possibility of cellulosic biofuel production in Brazil; however none of these companies are likely to make cellulosic biofuels commerc ially available in the United States in 2011. With the exception of Iogen, as mentioned above, EPA has not projected imports of

cellulosic biofuels from outside the United States in 2011.

5. Summary of Volume Projections

The information EPA has gathered on the potential cellulosic biofuel producers in 2011, summarized in Section II.A above, allows us to project a maximum potentially

available biofuel volume for each facilit y in 2011. After the appropriate ethanol equivalence value has been applied to the volumes of those facilities producing diesel fuel, the overall maximum potentially availabl e volume of cellulosic biofuels for 2011 can be calculated by summing the maximum potential of each facility. EPA is not proposing to set the 2011 cellulosic biofuel standard at this maximum potentially available volume, rather this is intended to serve as an upper bound. This information is

summarized in Table II.A.5-1 below.DRAFT 5/18/1019Table II.A.5-1Cellulosic Biofuel Maximum 2011 Potentially Available VolumeCompany NameLocationFeedstockFuelCapacity(MGY)EarliestProductionMaximum 2011PotentiallyAvailableVolume (MG)EthanolEquivalentGallons(MG)AE Advanced FuelsKeyesKeyes, CA Corn, thenstoverEthanol 20 June 2011 0.5 0.5Agresti Biofuels Pike County,KYMSW Ethanol 20 Oct. 2011 1 1Bell Bio-Energy Atlanta, GA MSW or othercellulosicbiomassDieselFeedstock14.4 June 2011 7 11.9Cello Energy Bay Minette,ALWood, hay Diesel 20 Online 5 8.5DuPont DaniscoaVonore, TN Corn cobs,thenswitchgrassEthanol 0.25 Online 0.15 0.15FiberightaBlairstown,IAMSW Ethanol 6 April 2010 2.8 2.8Iogen Ottawa,OntarioWheat, oat &barley strawEthanol 0.5 Online 0.25 0.25KL EnergyaUpton, WY Wood Ethanol 1.5 Online 0.4 0.4Total 17.1 25.5aMaximum Production/Import Potential represents company estimateDRAFT 5/18/10

20 It is important to note that this ma ximum potentially available volume of 17.1 million gallons of cellulosic biofuel, or 25.5 milli on ethanol equivalent gallons, is not the

volume on which the final 2011 cellulosic biofue l standard will be based. This number represents the maximum amount of fuel EPA be lieves could reasonably be expected to be produced or imported and made available for use as transportation fuel, heating oil, or jet fuel in 2011. It incorporates some redu ctions from the annual production capacity of each facility based on when the facilities an ticipate fuel production will begin and assumptions regarding a ramp up period to fu ll production. However, the history of the cellulosic biofuel industry has indicated that delays in achieving full production capacity in new facilities are not uncommon. Also, ther e are many other factors that increase the uncertainty of fuel production facilities being able to achieve their maximum potential production. These factors may include:

• Difficulty/delays in securing necessary funding

• Delays in permitting and/or construction

• Difficulty in scale up, especially for 1 st of their kind technologies

• Volumes from pilot and demonstration plants may not be sold commercially

• Not all feedstocks may qualify to produce cellulosic RINs; some still awaiting evaluation of lifecycle impacts

• Likelihood that fuels produced internati onally will be exported to the United States rather than consumed locally

Each of the facilities listed in Table II.A.5-1 may experience some of the difficulties listed above, and as a result may prod uce a volume of fuel less than that listed as their maximum 2011 potentially available volumel. Despite this uncertainty, EPA

believes that the volume of ce llulosic biofuel produced in 2011 will, at minimum, be able

to meet or exceed the 2010 standard of 6.5 million ethanol equivalent gallons. However, we will have more detailed and accurate information for the final rule, including the first round of Production Outlook Repor ts, due on September 1, 2010 5 which will provide information from each producer or importer on the type or types of fuel they plan to make available, the volume of fuel, and the number of RINs they plan to generate for the next five calendar years 6 . Therefore, in today's NPRM we are proposing a range of values, from a minimum of 6.5 million ethanol equivale nt gallons to a maximum of 25.5 million ethanol equivalent gallons for the 2011 cellulo sic biofuel standard. As time progresses

and we are able to track whether or not the cellulosic biofuels producers are able to meet the construction and ramp up schedules they have presented, we will have a better idea of the appropriate volume of fuel that we can reasonably expect to be produced and made commercially available. Additionally, each year by October 31 EIA is required to provide an estimate of the volume of cellulosic biofuel they expect to be sold or introduced into commerce in the United States in the following year. EPA will consider this information as well when finalizing a single volume for use in setting the 2011

cellulosic biofuel standard.

5 In future years, Production Outlook Reports will be due on March 1. As a result, they may be considered during development of the NPRM in year 2011 and beyond.

6 For more information on the annual production outlook reports see § 80.1449 of the RFS2 regulations.DRAFT 5/18/10

21 Although we are currently projecting that the maximum potentially available

volume of cellulosic biofuel in 2011 will be 25.5 million gallons, we expect that volumes of cellulosic biofuel will increase rapidly in the years following 2011. As stated before, we are aware of more than 100 companies that are actively investigating or making plans to produce cellulosic biofuel in the near future . Many of these companies intend to begin

construction in 2011 or 2012. We will be mon itoring these companies carefully as we project the potential volumes of cellulo sic biofuel for years 2012 and beyond.

B. Potential Limitations

In addition to production capacity, a variet y of other factors have the potential to limit the amount of cellulosic biofuel that can be produced and used in the U.S. For instance, there may be limitations in the availability of qualifying cellulosic feedstocks at reasonable prices. Most of the cellulosic biofuel producers that we project will produce

commercial volumes in 2011 have indicated th at they will use some type of cellulosic waste, such as separated municipal solid wa ste, wastes from the forestry industry, and agricultural residues. Based on the analyses of cellulosic feedstock availability in the RFS2 final rule, we believe that there will be significantly more than enough sources of these feedstocks for 2011. For producers that intend to use dedicated energy crops, we do not believe that the availability of ex isting cropland will limit production in 2011. We plan to continue to evaluate the availability of valid feedstocks in future years as the required volumes of cellu losic biofuel increase.

Another factor that has the potential to limit the amount of renewable fuel that can be produced and used in the U.S. is distribu tion and storage capacity. In the longer term, most biofuels are expected to be produced in the heartland of the country and then be shipped towards the coasts, flowing roughly in the opposite directi on of petroleum-based fuels. The physical and chemical nature of many of these biofuels may limit the extent to which they can be shipped and/or stored fu ngibly with petroleum-based fuels. As a result, new and expanded rail, barge and tank truck transport will need to be put in place. Dedicated biofuels pipelines are also being investigated. However, for 2011 the volumes of cellulosic biofuel are small enough that long-distance transport will be unnecessary; with the exception of foreign-produced biofue ls, much of the cellulosic biofuel volumes can be consumed in regions close to their production facilities. We also expect existing distribution and storage capacity to be suffi cient to accommodate the small increase in

cellulosic biofuel volumes in 2011.

C. Advanced Biofuel and Total Renewable Fuel

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

volume of the advanced biofue l and total renewable fuel requirements in the event that the projected volume of cellulosic biofuel is de termined to be below the volume specified

in the statute. As described in Section II.A above, even the largest potential volumes of cellulosic biofuel supply for 2011 are signif icantly below the statutory volume of 250DRAFT 5/18/10

22 million gallons. Therefore, we must consider whether and to what degree to lower the

advanced biofuel and total re newable fuel standards for 2011.

As described in the RFS2 final rule, we believe it may be appropriate to allow

excess advanced biofuels to ma ke up some or all of the shor tfall in cellulosic biofuel.

This could include excess biom ass-based diesel, sugarcane ethanol, or other biofuels categorized as advanced biofuel. We belie ve that Congress wanted to encourage the development of advanced renewable fuels and allow in appropriate circumstances for the

use of additional volumes of those fuels in the event that the projected volume of cellulosic biofuel falls below the statutory mandate.

If we were to maintain the advanced biofuel and total renewable fuel volume requirements at the levels specified in th e statute, we estimate that 125 - 144 million ethanol-equivalent gallons of additional advanced biofuels would be needed, depending

on the standard we set for cellulo sic biofuel. See Table II.C-1.

Table II.C-1 Projected Impact of Cellulosic Volume on Use of Other Biofuels in 2011 (mill gallons) Ethanol-Equivalent

Volume Physical Volume

Total renewable fuel

Conventional renewable fuel a 13,950 12,600 13,500 - 13,549 12,600
Total advanced biofuel 1,350 900 - 949

Cellulosic biofuel

Biomass-based diesel

Other advanced biofuel b 6.5 - 25.5

1200

125 - 144 5 - 17.1

800

83 c - 144 d

a Predominantly corn-starch ethanol

b Rounded to nearest million gallons for simplicity

c Lowest volume of other advanced biofuel assumes cellulosic biofuel standard is based on 25.5 mill gallons and only excess biodiesel (with an equivalence value (EV) of 1.5) is

used to fill the need for other advanced biofuel

d Highest volume of other advanced biofuel assumes cellulosic biofuel standard is based on 6.5 mill gallons and only imported sugarcane ethanol (with an EV of 1.0) is used to

fill the need for other advanced biofuel

To determine if there are likely to be sufficient volumes of imported sugarcane

ethanol and/or excess biodiesel to meet the need for 125 - 144 million gallons of other advanced biofuel, we examined historical data on ethanol imports and EIA projections for 2011. For instance, as shown in Table II.C -2 below, recent annual import volumes of ethanol were higher than what would be needed in 2011.DRAFT 5/18/10

23 Table II.C-2 Historical Imports of Ethanol (mill gallons) 7

2007

2008

2009 439

530

194

However, EIA's projections for 2011 suggest th at there may be insufficient volumes of imported sugarcane ethanol and excess biodies el production to make up for our proposed reduction in the required volume of cellulo sic biofuel. See Table II.C-3.

Table II.C-3 EIA Projected Imported Ethanol and Bi odiesel Availability in 2011 (mill gallons) 8

Imported ethanol 32 Total domestic biodiesel production

Biodiesel needed to meet bi omass-based diesel standard

Excess biodiesel 860

800

60

Further discussion of the potential availabilit y of biomass-based diesel in 2011 can be

found in the next Section II.D below.

Based on these projections, there would be a total of 60 million gallons of excess biodiesel production (90 million gallons etha nol-equivalent), plus another 32 million gallons of imported sugarcane ethanol. Th e total would therefore be 122 million gallons ethanol-equivalent. Since we are projecting that the need for other advanced biofuel would be in the range of 125 - 144 million ga llons depending on the cellulosic biofuel standard that we set, 122 million gallons may not be sufficient. However, the projections

in Table II.C-3 do not account for other potential sources of advanced biofuels. For instance, California's Low Carbon Fuel Standa rd may compel some refiners to import additional volumes of sugarcane ethanol fro m Brazil into California, and these same

volumes could count towards the federal RFS2 program as well. There may also be other types of advanced biofuel not included in th e EIA projections that could help meet our projected shortfall. These other advanced bi ofuels include, for instance, renewable fuels made from separated yard and food waste. Fi nally, the values in Table II.C-3 do not account for the potentially higher value for im ported sugarcane ethanol and biodiesel and

the additional market demand for these renewabl e fuels that would be created if we chose

not to lower the advanced biof uel standard for 2011. Given th ese factors, we believe that there are likely to be sufficient volumes of other advanced biofuels such that the

advanced biofuel standard need not be lo wered below 1.35 billion gallons. Thus, we are proposing to leave the required volume of advanced biofuel for 2011 at 1.35 billion gallons. Nevertheless, we request comment on whether we should lower the advanced

biofuel standard. If we do lower the adva nced biofuel standard, we request comment on the degree to which we should take into account other potential sources of advanced

biofuel as discussed above.

7 "Monthly U.S. Imports of Fuel Ethanol," EIA, released 4/8/2010

8 EIA STEO, March 2010, Table 8DRAFT 5/18/10

24 If we lower the cellulosic biofuel standar d, we would also need to determine if the

total renewable standard s hould be lowered. Lowering both the advanced biofuel

standard and the total renewable fuel standa rd by the same amount would mean that the expected amount of conventional renewable fuel use, such as corn-ethanol, would remained unchanged at 12,600 million gallons etha nol equivalent, the same as shown in

Table II.C-1.

If instead we were to lower the advanced biofuel standard but retain the total renewable fuel standard at 13,950 million gall ons, then we would expect the use of

conventional renewable fuels such as corn etha nol to increase. For instance, if we were

to lower the advanced biofuel standard by 144 million gallons to 1206 million gallons, we would expect the amount of corn-etha nol used would increase by 144 million gallons in order to satisfy the total renewable fu el standard of 13,950 million gallons. According to EIA, projected volumes of corn-ethanol are indeed expected to be higher than 12,600 million gallons in 2011, producing an excess of 490 million gallons. See Table II.C-4.

Table II.C-4 Projected Excess Corn Ethanol in 2011 (mill gallons) Total domestic corn ethanol production 9

Corn-ethanol needed to meet total renewable fuel standard

Excess corn ethanol 13,090 12,600

490

However, the market potential for ethanol in the U.S. is also a function of the ethanol blender's tax credit, set to expi re at the end of 2010. If this tax credit is not renewed, the

excess ethanol volume shown in Table II.C-4 may be smaller. Thus, while we are proposing that the required volume of total rene wable fuel for 2011 be set at the statutory level of 13.95 billion gallons, we request comme nt on whether the total renewable fuel

standard should be lowered.

D. Biomass-Based Diesel

While the statutory requirement that we project volumes of cellulosic biofuel for next year does not explicitly apply to bioma ss-based diesel as well, there are two other statutory requirements that compel us to i nvestigate current and potential future volumes of biomass-based diesel. First, the Clean Air Act provides limited waiver authority specific to biomass-based dies el under 211(o)(7)(E) if a significant renewable feedstock disruption or other market circumstance woul d make the price of biomass-based diesel fuel increase significantly. Second, as desc ribed more fully in Se ction II.C above, we must determine whether the required volumes of advanced biofuel a nd/or total renewable

fuel should be reduced at the same time that we reduce the required volume of cellulosic

biofuel. The amount of biomass-based dies el that we project can be available will directly affect our consideration of adju stments to the volumetric requirements for

advanced biofuel and total renewable fuel.

9 EIA STEO, March 2010, Table 8DRAFT 5/18/10

25 To project biodiesel production volum es for 2011, we examined both production capacity of the industry as well as actual re cent production rates. As of April 2010, the aggregate production capacity of biodiesel pl ants in the U.S. was estimated at 2.2 billion gallons per year across approximately 137 facilities. 10 Biodiesel production for calendar year 2009, according to the most recently available information, was 540 million gallons, with an estimated 351 mill gallons (or 65%) being used domestically. Domestic production rates in the second ha lf of 2009 increased above pr oduction rates in the first half as economic conditions improved, to an annualized rate of around 646 mill gal per year. Meanwhile, exports appeared to stab ilize at an annualized rate of about 242 mill gal per year, after recovering from changes in European import regulations early in the year. These trends for 2009 are shown in Figure II.D-1.

Figure II.D-1 U.S. Biodiesel Production and Export Trends for 2009. 11

0 10 20 30 40 50 60 70

1 2 3 4 5 6 7 8 9 10 11 12

Month, 2009MMgal Production Exports

In the early part of 2010, industry re ports of monthly biodiesel production indicated that production rate s have dropped below the 2009 average. The most likely cause is the expiration of the biodiesel tax credit. However, EIA's Short-Term Energy Outlook projects that, for the year as a whol e, average monthly bi odiesel production rates in 2010 will actually exceed those in 2009. Th e projected increase in monthly biodiesel production rates later in 2010 is consistent with the fact th at obligated parties are not required to demonstrate compliance with the 2010 biomass-based diesel volume requirement of 1.15 billion gallons until Februa ry 28, 2011. For development of our final rule setting the standards for 2011, we will ha ve more complete data with which to

10 Figures taken from National Biodiesel Board list of operating plants as of April 5, 2010.

11 Data taken from Energy Information Administration Monthly Energy Review, Table 10.4, March 2010.DRAFT 5/18/10

26 evaluate the progress of the biodiesel i ndustry in meeting the 2010 volume mandate and thus its preparedness for 2011.

In order to meet a 2011 biomass-based diesel volume requirement of 0.8 billion gallons to be consumed in the United States , the biodiesel industry will need to produce approximately 725 million gal of fuel. Th is value accounts for the production of 75 million gallons of renewable diesel at one renewable diesel facility in Geismar, Louisiana, set to begin operations later this year. 12 Assuming imports and exports continue at a rate equivalent to that in the second half of 2009, biodiesel production in the U.S. would need to total approximately 900 million gal in 2011. While this production rate would be about 10% higher than the produ ction rate projected by EIA for the second half of 2010, it would be significantly lower than the current 2.2 billion gallon biodiesel production capacity of the industry. Based on information from the biodiesel industry,

we believe that idled facilitie s can be brought back into production in time to meet the 2011 requirements for biomass-base d diesel. Moreover, as shown in Table II.C-3, EIA is projecting that biodiesel availability will in fact exceed the minimum volume needed to

meet the biomass-based diesel standard in 2011.

Finally, we believe that there will be sufficient sources of qualifying renewable

biomass to meet the needs of the biodiesel industry in 2011. The largest sources of

feedstock for biodiesel in 2011 ar e expected to be soy oil, rendered fats, and potentially some corn oil extracted during production of fuel ethanol, as this technology continues to proliferate. Moreover, comments we received from a large rendering company after the May 2009 RFS2 proposed rule suggest that th ere will be adequate fats and greases feedstocks to supply biofuels producti on as well as other historical uses. 13

12 Project status updates are available via the Syntroleum website, http://dynamicfuelsllc.com/wp-news/

13 See Federal Register v.74 n.99 p.24903. Comments are available in docket EPA-HQ-OAR-2005-0161.DRAFT 5/18/10

27 III. Proposed Percentage Standards for 2011

A. Background

The renewable fuel standards are expressed as a volume percentage, and are used by each refiner, blender or importer to determine their renewable volume obligations (RVO). Since there are four separate standards under the RFS2 program, there are likewise four separate RVOs applicable to each obligated part y. Each standard applies to the sum of all gasoline and diesel produced or imported. The applicable percentage standards are set so that if each regulated party meets the percen tages, then the amount of renewable fuel, cellulosic biofuel, biomass-based diesel, and advanced biofuel used will meet the volumes required on a nationwide basis.

As discussed in Section II.A.5, we ar e proposing a required volume of cellulosic biofuel for 2011 in the range of 5 - 17.1 million gallons (6.5 - 25.5 million ethanol equivalent gallons). The single volume we select for the final rule will be used as the basis for setting the percentage standard fo r cellulosic biofuel for 2011. We are also proposing that the advanced biofuel and to tal renewable fuel volumes would not be reduced below the statutory requirement s. The proposed 2011 volumes used to determine the four percentage standa rds are shown in Table III.A-1.

Table III.A-1 Proposed Volumes for 2011

Actual Volume Ethanol Equivalent

Volume Cellulosic biofuel 5 - 17.1 mill gal 6.5 - 25.5 mill gal Biomass-based diesel 0.80 bill gal 1.20 bill gal Advanced biofuel 1.35 bill gal 1.35 bill gal Renewable fuel 13.95 bill gal 13.95 bill gal

The formulas used in deriving the annu al renewable fuel standards are based in part on an estimate of combined gasoline and diesel volumes, for both highway and nonroad uses, for the year in which the st andards will apply. Producers of other transportation fuels, such as natural gas, propa ne, and electricity from fossil fuels, are not subject to the standards. Si nce the standards apply to produ cers and importers of gasoline and diesel, these are the transportation fuels used to set the standards, and then again to determine the annual volume obligations of an individual producer or importer.

B. Calculation of Standards

1. How Are the Standards Calculated?

The following formulas are used to ca lculate the four percentage standards applicable to producers and importers of gasoline and diesel (see §80.1405):DRAFT 5/18/10

28 i i i i i i i i i i DE RDS DS RD D GE RGS GS RG G

− − +

− +

− − +

− × = ) ( ) ( ) ( ) ( RFV % 100 Std i CB,

i CB,

i i i i i i i i i i DE RDS DS RD D GE RGS GS RG G

− − +

− +

− − +

− × × = ) ( ) ( ) ( ) ( 5

. 1 RFV % 100 Std i BBD,
i BBD,

i i i i i i i i i i DE RDS DS RD D GE RGS GS RG G

− − +

− +

− − +

− × = ) ( ) ( ) ( ) ( RFV % 100 Std i AB,

i AB,

i i i i i i i i i i DE RDS DS RD D GE RGS GS RG G

− − +

− +

− − +

− × = ) ( ) ( ) ( ) ( RFV % 100 Std i RF,
i RF,

Where

Std CB,i = The cellulosic biofuel standard for year i, in percent.

Std BBD,i = The biomass-based diesel standard (eth anol-equivalent basis) for year i, in

percent.

Std AB,i = The advanced biofuel standard for year i, in percent.

Std RF,i = The renewable fuel standard for year i, in percent.

RFV CB,i = Annual volume of cellulosic biofue l required by section 211(o) of the Clean Air Act for year i, in gallons.

RFV BBD,i = Annual volume of biomass-based dies el required by section 211(o) of the Clean Air Act for year i, in gallons.

RFV AB,i = Annual volume of advanced biofue l required by section 211(o) of the Clean Air Act for year i, in gallons.

RFV RF,i = Annual volume of renewable fuel re quired by section 211(o) of the Clean Air Act for year i, in gallons.

G i = Amount of gasoline projected to be used in the 48 contiguous states and Hawaii, in year i, in gallons.

D i = Amount of diesel projected to be used in the 48 contiguous states and Hawaii, in year i, in gallons.

RG i = Amount of renewable fuel blended into gasoline that is projected to be consumed in the 48 contiguous states and Hawaii, in year i, in gallons.DRAFT 5/18/10

29 RD i = Amount of renewable fuel blended into diesel that is projected to be consumed in the 48 contiguous states and Hawaii, in year i, in gallons.

GS i = Amount of gasoline projected to be used in Alaska or a U.S. territory in year i if the state or territory opts-in, in gallons.

RGS i = Amount of renewable fuel blended in to gasoline that is projected to be consumed in Alaska or a U.S. territory in year i if the state or territory opts-in, in gallons.

DS i = Amount of diesel projected to be used in Alaska or a U.S. territory in year i if the state or territory opts-in, in gallons.

RDS i = Amount of renewable fuel blended in to diesel that is projected to be consumed in Alaska or a U.S. territory in year i if the state or territory opts-in, in gallons.

GE i = The amount of gasoline projected to be produced by exempt small refineries and small refiners in year i, in gallons, in any year they are exempt per §§80.1441 and 80.1442, respectively. For 2011, this value is

zero. See further discussion in Section III.B.2 below.

DE i = The amount of diesel projected to be produced by exempt small refineries and small refiners in year i, in gallons, in any year they are exempt per §§80.1441 and 80.1442, respectively. For 2011, this value is zero. See

further discussion in Section III.B.2 below.

The four separate renewable fuel st andards for 2011 are based on the 49-state gasoline and diesel consumption volumes proj ected by EIA. The Act requires EPA to base the standards on an EIA estimate of the amount of gasoline and diesel that will be sold or introduced into commerce for that year . The projected volume of gasoline used to calculate the final percentage standards will continue to be provided by the October issue of EIA's Short-Term Energy Outlook (STEO). For the purposes of this proposal, we

have used the March 2010 issue of STEO. Th e projected volume of transportation diesel used to calculate the final percentage stan dards will be provided by the most recent Annual Energy Outlook (AEO). For the purposes of this proposal, we have used the Early Release version of AEO2010. Gasoline an d diesel volumes are adjusted to account

for renewable fuel contained in the EIA projections. Beginning in 2011, gasoline and diesel volumes produced by sma ll refineries and small refine rs are not exempt, and thus there is no adjustment to the gasoline and di esel volumes in today's proposal to account for such an exemption, as there has been in pa st years. However, as discussed more fully in Section III.B.2 below, depending upon th e results of a Congressionally-mandated DOE study, it is possible that the exemption for ga soline and diesel volumes produced by small refineries and small refiners may be extended. In addition, EPA may extend the exemption for individual small refineries on a case-by-case basis if they demonstrate disproportionate ec onomic hardship.DRAFT 5/18/10

30 As finalized in the March 26, 2010 RFS2 rule, the standards are expressed in terms of energy-equivalent gallons of rene wable fuel, with the cellulosic biofuel, advanced biofuel, and total renewable fuel standards based on et hanol equivalence and

the biomass-based diesel sta ndard based on biodiesel equiva lence. However, all RIN generation is based on ethanol-e quivalence. More specifically, the RFS2 regulations provide that production or import of a gallon of biodiesel will lead to the generation of

1.5 RINs. In order to ensure that demand for 0.8 billion physical gallons of biomassbased diesel will be created in 2011, the calcula tion of the biomass-ba sed diesel standard provides that the required volume be multiplied by 1.5. The net result is a biomass-based diesel gallon being worth 1.0 gallons toward th e biomass-based diesel standard, but worth 1.5 gallons toward the other standards.

The levels of the percentage standards would be reduced if Alaska or a U.S. territory chooses to participate in the RFS2 program, as gasoline and diesel produced in or imported into that state or territory woul d then be subject to the standard. Neither Alaska nor any U.S. territory has chosen to participate in the RFS2 program at this time,

and thus the value of the related terms in the calculation of the standards is zero.

Note that the terms for projected volum es of gasoline and diesel use include gasoline and diesel that has been blended w ith renewable fuel. Because the gasoline and

diesel volumes described above include renewable fuel use, we must subtract the total renewable fuel volume from the total ga soline and diesel volume to get total nonrenewable gasoline and diesel volumes. The va lues of the variables described above are

shown in Table III.B.1-1. Terms not include d in this table have a value of zero.

Table III.B.1-1 Values for Terms in Calculation of the Standards (bill gal)

Term Value

RFV CB,2011 0.0065 - 0.0255

RFV BBD,2011 0.80

RFV AB,2011 1.35

RFV RF,2011 13.95

G 2011 139.66

D 2011 50.01

RG 2011 13.38

RD 2011 0.74

Using the volumes shown in Table III.B .1-1, we have calculated the proposed percentage standards for 2011 as shown in Table III.B.1-2.DRAFT 5/18/10

31 Table III.B.1-2 Proposed Percentage Standards for 2011

Cellulosic biofuel 0.004-0.015%

Biomass-based diesel 0.68%

Advanced biofuel 0.77%

Renewable fuel 7.95%

2. Small Refineries and Small Refiners

In CAA section 211(o)(9), enacted as part of EPAct, Congress provided a temporary exemption to small refineries (those re fineries with a crude throughput of no more than 75,000 barrels of crude per day) through December 31, 2010. In RFS1, we exercised our discretion under section 211( o)(3)(B) and extended this temporary exemption to the few remaining small refiners that met the Small Business Administration’s (SBA) definition of a small business (1,500 employees or less company-wide) but did not meet the statutory small refinery definition as noted above. Because EISA did not alter the small refinery exemption in any way, the RFS2 program regulations exempt gasoline and diesel produced by small refineries and small refiners in 2010 from the renewable fuels standard (unle ss the exemption was waived), see 40 CFR §80.1141.

Under the RFS program, Congress has provi ded two ways that small refineries can receive a temporary extension of the exemption beyond 2010. One is based on the results of a study conducted by the Department of Energy (DOE) to determine if small refineries would face a disproportionate ec onomic hardship under the RFS program. The

other is based on EPA determin ation of disproportionate ec onomic hardship on a case-bycase basis in response to refiner petitions.

In January 2009, DOE issued a Small Refineries Exemption Study which did not

find that small refineries w ould face a disproportionate ec onomic hardship under the RFS program. The conclusions were based in part on the expected robust availability of RINs and EPA’s ability to grant relief on a case-by-case basis. Subsequently, Congress directed DOE to complete a reassessment a nd issue a revised report by June 30, 2010. DOE had not revised its study at the time of the RFS2 final rulemaking nor at the time of this writing. Additionally, we have not received any requests for relief on a case-by-case basis from any small refinery. If DOE prepares a revised study, and the results of that study show a disproportionate economic hard ship for any small refineries under the RFS program, we will take appropr iate action to extend the exemption. However, until and unless a DOE study supporting an extensi on to the temporary exemption for small refineries beyond 2010 is used, or any petitions to EPA from individual small refineries claiming disproportionate economic hardship are approved, we are not proposing to change the required inclusion of small refineri es and small refiners in the RFS2 program beginning with the 2011 compliance period.DRAFT 5/18/10

32 IV. Cellulosic Biofuel Technology Assessment

In projecting the volumes of cellulosi c biofuel for 2011, we conducted a technical assessment of the production technologies th at are under consideration by the broad universe of companies we investigated. Many of these companies are still in the research phase, resolving outstanding issues with specifi c technologies, and/or in the design phase to implement those technologies for the production of commercia l-scale volumes of cellulosic biofuel. A subset of the compan ies we investigated have moved beyond the research and design phase and are actively preparing for production. This smaller group of companies formed the basis for our proj ection of potential 2011 volumes of cellulosic

biofuel.

This section discusses the full range of cellulosic biofue l technologies being considered among producers, with referenc e to those individual companies that are focusing on each technology and those we project will be most likely to use those technologies to produce cellulosic biofuel in 2011.

A. What Pathways are Valid for the Production of Cellulosic Biofuel?

In determining the appropriate volume of cellulosic biofuel on which to base the percentage standard for 2011, we must ensure that the production facilities we use as the basis for this volume are using fuel pathwa ys that are valid for the production of cellulosic biofuel. In general this means that each facility's pathway (combination of feedstock, production process, and fuel ty pe) must be included in Table 1 to §80.1426 and be assigned a D code of either 3 or 7. As of this writing, there are three valid pathways available as shown in Table IV.A-1 below.

Table IV.A-1 Cellulosic Biofuel Pathways for Use in Generating RINs

Fuel Type Feedstock Production Process Requirements D-Code

Ethanol Cellulosic Biomass from agricultural residues, slash, forest thinnings and forest product residues, annual covercrops; switchgrass, and miscanthus; cellulosic components of separated yard wastes; cellulosic components of separated food Any 3 (cellulosic

biofuel)DRAFT 5/18/10

33 wastes; and cellulosic components of separated MSW

Cellulosic Diesel, Jet Fuel and Heating Oil Cellulosic Biomass from agricultural residues, slash, forest thinnings and forest product residues, annual covercrops, switchgrass, and miscanthus; cellulosic components of separated yard wastes; cellulosic components of separated food wastes; and cellulosic components of separated MSW Any 7 (cellulosic

diesel)

Cellulosic Naphtha Cellulosic Biomass from agricultural residues, slash, forest thinnings and forest product residues, annual covercrops, switchgrass, and miscanthus; cellulosic components of separated yard wastes; cellulosic components of separated food wastes; and cellulosic components of separated MSW Fischer-Tropsch

process 3 (cellulosic

biofuel)

Of the eight facilities that we currently believe could contribute to the volume of commercially available cellulosic biofue l in 2011, six would produce ethanol from cellulosic biomass and two would produce diesel from cellulosic biomass. None of the facilities we have evaluated would produce ce llulosic naphtha through a Fischer-Tropsch

process.

Two of the facilities shown in Table II.A.5-1, Cello Energy and KL Energy, intend to use wood as the primary feedstock. The only types of wood that are currentlyDRAFT 5/18/10

34 allowed as a valid feedstock are those derived from various types of waste. If either of these two companies choose to use trees from a tree plantation instead of qualifying waste wood, its pathway would not fall into the any of the pathways currently listed in Table 1 to §80.1426. However, as described more fully in Section V.A, we are currently evaluating the lifecycle GHG impacts of bi ofuel made from pulpwood, including wood from tree plantations. If such a pathway is determined to meet the 60% GHG threshold required for cellulosic biofuel, we expect that it will be added to Table 1 to §80.1426 in time to apply to fuel produced in 2011. Fo r the purposes of this proposal, we have

chosen to retain the volumes from these two companies in our projections of 2011 cellulosic biofuel volume, but we will revisit this issue for the final rule.

B. Cellulosic Feedstocks

Cellulosic biofuel technologies are diff erent from other biofuel technologies because they convert the cellulose and othe r very difficult to convert compounds into biofuels. Unlike grain feedstocks where the major carbohydrate is starch (very simply combined sugars), lignocellulosic biomass is composed mainly of cellulose (40-60 %) and hemicellulose (20-40 %). 14 Cellulose and hemicellulo se are made up of sugars linked together in long chains called polysaccharides. Once hydrolyzed, they can be

fermented into ethanol. Most all the remainde r of cellulosic feedstocks consists of lignin, a complex polymer which serves as a stiffe ning and hydrophobic (water-repelling) agent in cell walls. Currently, lignin cannot be ferm ented into ethanol, but could be burned as a by-product to generate electricity. Ther mochemical, pyrolysis and depolymerization processing, however, can convert some or ev en most of the lignin, in addition to the cellulosic and hemicellulose, into biofuels.

C. Emerging Technologies

When evaluating the array of biofuel technologies which could produce one or more fuels from cellulose that could qualify under RFS2, we found that it is helpful to organize them into fuel technology categories. Organizing them into categories eases the task of understanding the technologies, and al so simplifies our understanding of the costs and lifecycle impacts of these technologie s because similar technologies likely have similar cost and lifecycle impacts. The simple st organization is by the fuel produced. However, we frequently found that additiona l subdivisions were also helpful. Table IV.C-1 provides a list of technologies, the cellu losic fuels produced and a list of many of the companies which we learned are pursuing the technology (or something very similar to the technology listed in the category).

14 DOE. “Biomass Program: ABC’s of Biofuels”. Accessed at: http://www1.eere.energy.gov/biomass/abcs_biofuels.html#contentDRAFT 5/18/10

35 Table IV.C-1 List of Technology Categories, the Fuels Produced Through Each Type of Technology, and the Companies Pursuing Them

Technology Category Technology Fuels

Produced Companies

Enzymatic Hydrolysis Ethanol Abengoa, AE Fuels, DuPont/Danisco, Florida Crystals, Gevo, Poet, ICM, Iogen, BPI, Energy, Fiberight, KL Energy. Acid Hydrolysis Ethanol Agresti, Arkenol, Blue Fire, Pencor, Pangen, Raven

Biofuels Dilute Acid, Steam Explosion of

Cellulose Ethanol Verenium, BP, Central Minnesota Ethanol Coop. Consolidated Bioprocessing (one step hydrolysis and fermentation)

of Cellulose Ethanol Mascoma, Qteros

Conversion of Cellulose via carboxylic acid Ethanol, Gasoline, Jet Fuel, Diesel

Fuel Terrabon, Swift Fuels Biochemical

One step Conversion of Cellulose

to distillate Diesel, Jet

Fuel or Naphtha Bell Bioenergy, LS9

Thermochemical/Fischer Tropsch Diesel Fuel and Naphtha Choren, Flambeau River Biofuels, Baard, Clearfuels, Gulf Coast Energy, Rentech,

TRI. Thermochemical/Fischer Tropsch DME Chemrec, New Page. Thermochemical

Thermochemical/Catalytic conversion of syngas to alcohols Ethanol Range Fuels, Pearson Technologies, Fulcrum Bioenergy, Enerkem, and Gulf Coast Energy.

Thermochemical w/ Biochemical catalyst Ethanol Coskata, INEOS Bio Hybrid

Acid Hydrolysis of cellulose to intermediate; hydrogenation using Thermochemical syngas

from non-cellulose fraction Ethanol,

Other

alcohols Zeachem

Catalytic Depolymerization of

Cellulose Diesel, Jet

Fuel or Naphtha Cello Energy Depolymerization

Pyrolysis of Cellulose Diesel, Jet Fuel, or

Gasoline Envergent (UOP/Ensyn), Dynamotive, Petrobras, Univ. of Mass, KIOR. Other Catalytic Reforming of Sugars

from Cellulose Gasoline VirentDRAFT 5/18/10

36 Of the technologies listed above, many of them are considered to be “second generation” biofuels or new bi ofuel technologies capable of meeting either the advanced

biofuel or cellulosic biofuel RFS standard. The following sections describe specific companies and the new biofuel technologies wh ich the companies have developed or are developing. This summary is not meant to be an unabridged list of new biofuel technologies, but rather a description of some of the more prominent of the new biofuel technologies that serve to provide a sense of the technology categories listed above. The process technology summaries are based on information provided by the respective companies. EPA has not been able to confir m all of the information, statements, process conditions, and the process flow steps n ecessary for any of these processes and companies.

1. Biochemical

Biochemical conversion refers to a broad grouping of processes that use biological organisms to convert cellulosic feedstocks into biofuels. While no two processes are identical, many of these proce sses follow a similar basic pathway to convert cellulosic materials to biofuel. The general process of most biochemical cellulosic biofuel processes consists of five main steps: feedstock handling, pretreatment, hydrolysis, fermentation/fuel conversion, and distillation/separa tion. The feedstock handling step reduces the particle size of the incoming feedstock and removes any contaminants that may negatively impact the rest of the process. In the pretreatment step the structure of the lignin and hemicellulose is disrupted, usually using some combination of heat, pressure, acid, or base, to allow for a more effective hydrolysis of the cellulosic material to simple sugars. In the hydrolysis stage the cellulose and any remaining

hemicellulose is converted into simple sugars, usually using an enzyme or strong acid. In the fermentation or fuel conversion step, the simple sugars are conv erted to the desired fuel by a biological organism. In the final st ep the fuel that is produced is separated from the water and other byproducts by distillation or some other means. A basic diagram of the biochemical conversion process can be found in Figure IV.C.1-1 below.DRAFT 5/18/10

37 Figure IV.C.1-1 15

While this diagram shows the production of ethanol from cellulosic biomass, it is possible to use the same process to produce other fuels or specialty chemicals using different biological organisms.

The following sections will discuss each of these steps in greater detail, discuss some of the variations to this general proc ess, and discuss some of the advantages and disadvantages of the biochemical process of producing biofuel from cellulosic materials as compared to other fuel production processes.

Seven of the eight companies that EPA believes may produce cellulosic biofuel in 2011 plan to use a biochemical process to produ ce biofuels. Five of these companies, AE Biofuels, Dupont Danisco Cellulosic Ethanol, Fi beright, Iogen, and KL energy, all plan to use an enzymatic hydrolysis, while Agres ti Biofuels and Bell Bio-Energy are pursuing gravity pressure vessel and single step pr ocess technologies respectively. The main

reason for the dominance of biochemical te chnologies in 2011 is the relatively low capital costs of these projects compared to other cellulosic biofuel facilities. Biochemical projects also benefit less fro m economies of scale, making smaller and less capital intensive commercial facilities more feasible. The following sections, as well as a

technical memorandum that ha s been added to the docket 16 , provide more information on the biochemical processes being pursued by majority of the companies we expect to produce cellulosic biofuels and make them commercially available in 2011, as well as many other companies planning to begin production in later years.

a. Feedstock Handling

The first step of the biochemical conversi on process is to insure that the biomass stream can be utilized by the rest of the conversion process. This most often takes the form of size reduction, either by grinding or chipping as appropriate for the type of biomass. While this is a relatively simple process it is essential to allow the following

15 Image From: http://www.afdc.energy.gov/afdc/ethanol/production_cellulosic.html

16 Wyborny, Lester. “In-Depth Assessment of Advanced Biofuels Technologies.” Memo to the docket, May 2010.DRAFT 5/18/10

38 steps of the process to function as designed. It is also a potentially energy intensive process. It may be possible for biofuel produ cers to purchase cellulosic material that is already of the appropriate size, however we belie ve that in the near term this is unlikely and most biofuel producer s will have to invest in equipm ent to reduce the size of the material they receive as needed for their pr ocess. In coming years, as the market for cellulosic materials expands, purchasing fe edstock that has already been ground or chipped may be possible and cost effective, as these processes increase the density of this material and may reduce transportation costs.

In addition to size reduction, steps must also be taken to remove any material from the feedstock that might be detriment al to the fuel production process.

Contaminants in the feedstock would at best travel through the fuel production process unchanged, resulting in reduced fuel producti on capacity. Depending on the type of contaminant they may also be converted to undesired byproducts that must be separated from the fuel. They could also be toxic to th e biological organisms being used to convert the sugars to fuel, necessitating a shut down and restart of the plant. Any of these scenarios would result in a significant cost to the fuel producer. Feedstocks such as agricultural residues, wood chips, or herbaceous or woody energy crops are likely to

contain far fewer contaminants than more he terogeneous feedstocks such as municipal solid waste (MSW).

b. Biomass Pretreatment

The purpose of the biomass pretreatment st age is to disrupt the structure of the cellulosic biomass to allow for the hydrolysis of the cellulose and hemicellulose into simple sugars. The ideal pretreatment stag e would allow for a high conversion of the cellulose and hemicellulose to simple sugars, minimize the degradation of these sugars to undesired forms that reduce fuel yields and inhibit fermentation, not require especially large or expensive reaction vessels, and be a relatively robust and s imple process. No single biomass pretreatment method has yet been discovered that meets all of these goals, but rather a variety of options are being used by various cellulosic fuel producers, each with their own strengths and weaknesses. Dilute acid pretreatment and alkaline pretreatment are two methods currently bein g used that attack the hemicellulose and lignin portions of the cellulosic biomass resp ectively. Other methods, such as steam explosion and ammonia fiber expansion, seek to use high temperature and pressure, followed by rapid decompression to disrupt th e structure of the cellulosic biomass and allow for a more efficient hydrolysis of the cellulose and hemicellulose to simple sugars.

Each of these methods is discussed in more detail in a technical memo that has been

added to the docket 17 . The cost and characteristics of the cellulosic feedstock being processed is likely to have a significant impact on the pretreatment process that is used.

c. Hydrolysis

17 Wyborny, Lester. “In-Depth Assessment of Advanced Biofuels Technologies.” Memo to the docket, May 2010.DRAFT 5/18/10

39 In the hydrolysis step the cellulose and any remaining hemicellulose are converted to simple sugars. There are two ma in methods of hydrolysis, acid hydrolysis and enzymatic hydrolysis. Acid hydrolysis is the oldest technology for the conversion of cellulosic feedstock to ethanol and can only be used following an acid pretreatment process. An alternative method is to us e a combination of enzymes to perform the hydrolysis after the biomass has been pret reated. This process is potentially more effective at hydrolyzing pretreated biomass but in the past has not been economically feasible due to the prohibitively high cost of the enzymes. The falling cost of these enzymes in recent years has made the produc tion of cellulosic biofuels using enzymatic hydrolysis possible. The lignin is largely unaffected by the hydrolysis and fuel production steps but is carried through these pr ocesses until it is separa ted out in the fuel separation step and burned for proce ss energy or sold as a co-product.

i. Acid Hydrolysis

Acid hydrolysis is a technique that has been used for over 100 years to convert cellulosic feedstocks into fuels. In the acid hydrolysis process the lignin and cellulose portions of the feedstock that remain af ter the hemicellulose has been dissolved, hydrolyzed, and separated during the dilute ac id pretreatment process is treated with a

second acid stream. This second acid treatment uses a less concentrated acid than the pretreatment stage but at a hi gher temperature, as high as 215° C. This treatment hydrolyzes the cellulose into glucose and ot her 6 carbon sugars that are then fed to biological organisms to produce the desired fuel. It is necessary to hydrolyze the hemicellulose and cellulose in two separate st eps to prevent the conversion of the pentose sugars that result from the hydrolysis of th e hemicellulose from being further converted

into furfural and other chemicals. This would not only reduce the total production of sugars from the cellulosic feedstock, but al so inhibit the production of fuel from the sugars in later stages of the process.

The acidic solution containing the sugars produced as a result of the hydrolysis

reaction must also be treated so that this st ream can be fed to th e biological organisms that will convert these sugars into fuel. In order to operate an acid hydrolysis process cost effectively the acid must be recovere d, not simply neutralized. Methods currently being used to recover this acid include membrane separati on and continuous ion exchange. The advantages of using an acid hydrolysis are that this process is well understood and capable of producing high sugar yi elds from a wide variety of feedstocks. Capital costs are high however, as materials compatible with the acidic streams must be extensively utilized. The high temperatures necessary for acid hydrolysis also result in considerable energy costs, and profitability is highly dependent on the ability to effectively recover and reuse the acid.

ii. Enzymatic Hydrolysis

The enzymatic hydrolysis process uses enzymes, rather than acids, to hydrolyze the cellulose and any remaining hemicellulose from the pretreatment process. This process is much more versatile than the acid hydrolysis and can be used in combinationDRAFT 5/18/10

40 with any of the pretreatment processes descri bed above, provided that the structure of the lignocellulosic feedstock has been disrupted enough to allow the enzymes to easily access

the hemicellulose and cellulose. After the feedstock has gone through pretreatment a cocktail of cellulose enzymes is added. Thes e enzymes can be produced by the cellulosic biofuel producer or purchased from enzyme producers such as Novozymes, Genencor, and others. The exact mixture of enzymes used in the enzymatic hydrolysis stage can vary greatly depending on which of the pret reatment stages is used as well as the composition of the feedstock.

The main advantages of the enzymatic hydrolysis process are a result of the mild operating conditions. Because no acid is used special materials are not required for the reaction vessels. Enzymatic hydrolysis is carried out at relatively low temperatures, usually around 50° C, and atmospheric pr essure and therefore has low energy requirements. These conditions also result in less undesired reactions that would reduce the production of sugars and potentially inhi bit fuel production. Enzymatic hydrolysis works best with a uniform feedstock, such as agricultural residues or energy crops, where the concentration and combination of enzymes can be optimized for maximum sugar production. If the composition of the feedstock va ries daily, as can be the case with fuel producers utilizing MSW or other waste streams, or even seasonally, it would make it more difficult to ensure that the correct enzyme cocktail is being used to carry out the hydrolysis as efficiently as possible. The ma in hurdle to using an enzymatic hydrolysis has been and continues to be the costs of the enzymes. Recent advances by companies that produce enzymes for the hydrolysis of cellulosic materials have resulted in a drastic cost reduction of these enzymes. If, as ma ny researchers and cellu losic biofuel producers expect, the cost of these enzymes continues to fall it is likely that enzymatic hydrolysis will be a lower cost option than acid hydrolysis, especially for cellulosic biofuel producers utilizing uniform feedstocks.

d. Fuel Production

After the cellulosic biomass has been hydrolyzed to simple sugars this sugar solution is converted to fuel by biological organisms. In some biochemical fuel production processes the sugars produced fro m the fermentation of the hemicellulose, which are mainly five carbon sugars, are converted to fuel in a separate reactor and with a different set of organisms than the sugars produced from the cellulose hydrolysis, which are mainly six carbon sugars. Others processe s, however, produce fuel from the five and six carbon sugars in the same reaction vessel.

A wide range of biological organisms can be used to convert the simple sugars into fuel. These include yeasts, bacteria, a nd other microbes, some of which are naturally occurring and others that have been genetical ly modified. The ideal biological organism converts both five and six carbon sugars to fuel w ith a high efficiency, is able to tolerate a range of conditions, and is adaptable to pr ocess sugar streams of varying compositions that may result from variations in feedstoc k. Many cellulosic biofuel producers have their own proprietary organism or organism s optimized to produce the desired fuel from their unique combination of feedstock, pretrea tment and hydrolysis processes, and fuelDRAFT 5/18/10

41 conversion conditions. Other cellulosic fuel producers license these organisms from biotechnology companies who specialize in their discovery and production.

The many different biological organism s being considered for cellulosic biofuel production are capable of producing many diffe rent types of fuels. Many cellulosic biofuel producers are working with organisms th at produce ethanol. In many ways this is the most simple fuel to produce from lignoce llulosic biomass as the production of ethanol from simple sugars is a well understood proce ss. Others intend to produce butanol or other alcohols that have higher energy content. Butanol may be able to be blended into gasoline in greater proportion to ethanol and therefore has a potentially greater market as well as value due to its higher energy conten t. Yields for butanol, however, are currently significantly lower per ton of feedstock than ethanol. Some of the fuel producers who plan to produce alcohols are considering purch asing and modifying already existing grain ethanol plants. This would potentially have significant capital cost savings as many of the units used in a grain ethanol process are very similar to those required by the biochemical fuel production process and c ould be used with minimal modification.

Other cellulosic biofuel producers in tend to produce hydrocarbon fuels very similar to gasoline, diesel, and jet fuel. These fuels command a higher price than alcohols, have a greater energy density, and are potentially drop in fuels that could be used in any conventional vehicles without st rict blending limits. They could also be transported by existing pipelines and utilize the same infrastructure as the petroleum industry. Some of the processes being re searched by fuel producers produce a single compound, such as iso-octane, that would need to be blended into petroleum gasoline in order to be used while others produce a ra nge of hydrocarbons very similar to those found in gasoline or diesel fuel refined from petroleum and could potentially be used in conventional vehicles without blending. Wh ile the prospect of producing hydrocarbon fuels from cellulosic feedstock is promising, th e current yields of fuel produced by these organisms are significantly lower than t hose that are producing ethanol and other alcohols. Improvement in the yields of these organisms will have to be realized in order for cellulosic hydrocarbon fuels produced vi a a biochemical process to compete with cellulosic ethanol, and ultimately petroleum based fuels.

e. Fuel Separation

In the fuel separation stage the fuel pr oduced is separated from the water, lignin, any un-reacted hemicellulose and cellulose, and any other compounds remaining after the fuel production stage. The complexity of this stage is highly dependent on the type of fuel produced. For processes producing hydrocar bon fuels this stage can be as simple as a settling tank, where the hydrocarbons are allo wed to float to the top and removed. Recovering the ethanol is a much more difficult task. To recover the ethanol a distillation process, nearly identical to that used in th e grain ethanol industry, is used. The ethanol solution is first separated from the solids before being sent to a distillation column called

a beer column. The overheads of the beer co lumn are fed to a second distillation column, called a rectifier for further separation. The r ectifier produces a stream with an ethanol of approximately 96%. A molecular sieve unit is then used to dehydrate this stream toDRAFT 5/18/10

42 produce fuel grade ethanol with purity greater than 99.5%. Gasoline is added to the fuel ethanol as a denaturant before the fuel is stored. The distillation of ethanol is a very energy intensive process and new technologie s, such as membrane separation, are being developed that could potentially reduce the ener gy intensity, and thus the cost, of the ethanol dehydration process. After the fuel has been recovered the remaining lignin and

solids are dried and either burned on site to provide process heat and electricity or sold as a byproduct of the fuel production process. The wa ste water is either recycled or sent to a water treatment facility.

f. Process Variations

While the process describe d above outlines the general biochemical process used by many cellulosic biofuel producers, ther e are several prominent variations being pursued by prospective biofuel producers. Th ese variations usually seek to simplify the biochemical fuel production process by combin ing several steps into a single step or using other means to reduce the capital or ope rating costs of the process. SimultaneousSaccharification and Fermentation (SSF), Simultaneous Saccharification and CoFermentation (SSCF), Consolidated Bio-Proc essing (CBP), and Single Step Fuel Production are all production methods being developed by various biofuel production companies to combine two or more of the st eps outlined above. These process variations

are discussed in more detail in a techni cal memo that can be found in the docket 18 . These modifications are usually enabled by a proprieta ry technology or biological organism that makes these changes possible.

g. Current Status of Bioc hemical Conversion Technology

The biochemical cellulosic fuel production industry is currently transitioning from an industry consisting mostly of small scal e research and optimiza tion focused facilities to one capable of producing fuel at a commercial scale. Companies such as Iogen, DuPont Danisco Cellulosic Ethanol, and KL Ener gy are just beginning to market the fuel they are producing at their first small scal e commercial fuel produ ction facilities. By 2011 we expect several other cellulosic fu el production facilities using biochemical processes to come online, including the first commercial scale facilities of AE Advanced Fuels, Agresti Biofuels, Bell Bio-Energy, and Fi beright. Many other facilities, including some large scale facilities capab le of producing tens of millions of gallons of fuel are planned to come online starting in 2012 and in the following years.

There are many factors that are likely to continue to drive the expansion of the cellulosic biofuel industry. The high price of petroleum fuels and the mandates put into place by the RFS2 program have created a large demand for cellulosic biofuels. The biochemical production process also has se veral advantages over other methods of producing fuel from cellulosic feedstocks in cluding relatively low capital costs, highly selective fuel production, flexibility in the type of fuel produced, and the promise of future production cost reductions.

18 Reference docket numberDRAFT 5/18/10

43 While the poor worldwide economy and ti ght credit markets has had a negative impact on the biofuel industry as a whole the cellulosic biofuel producers utilizing biochemical processes have not been as hard h it as many others in the industry. This is partially due to the relative ly low capital costs of biochemical production plants as a result of the relative simplicit y and mild operating conditions of these plants. Several companies have been able to purchase dist ressed grain ethanol plants and are in the process of modifying them to produce cellu losic ethanol, further reducing the capital

costs of their initial facilities. Once bioc hemical fuel production facilities have been constructed another advantage they have over ot her fuel production processes is that their high selectivity in the fuels they produce. Unlike chemical catalysts, which often produce a range of products and byproducts, biol ogical organisms often produce a single type of fuel, which leads to very high fuel production rates per unit sugar. Finally, there is a large potential to further decrease the pr oduction costs of cellulosic biofuels using the biochemical processes. Unlik e other production methods such as gasification which are relatively mature technologies, biochemical production of fuels is a young technology. One of the major costs of the biochemical fuel production processes currently are the enzymes. Great strides have been made rece ntly in reducing the cost of these enzymes, and as the price of enzymes continues to fall so will the operating costs of biochemical fuel production processes.

h. Major Hurdles to Commercialization

Despite the many promising qualities of the biochemical fuel production process several significant hurdles re main. Improvements must be made to the pretreatment processes of the cellulosic materials to maximize the conversion of cellulose and hemicellulose to simple sugars and to minimize the production of other undesired compounds, especially those that may inhibit the fuel production process. The ability of the biological fuel producti on organisms to process a wide range of both five and six carbon sugars must also continue to be impr oved. Both these improvements will increase the fuel yield per ton of cellulosic feedstock, reducing the operating costs of the process. The cost of enzymes must continue to decrea se to allow the fuel produced by biochemical processes to be cost competitive with petroleum and other cellulosic biofuels.

Another significant hurdle that must be overcome is the profitable utilization of the lignin portion of the cellulosic feedstock. Unlike some of the other cellulosic biofuel production processes, the biochemical proce ss does not convert the lignin to fuel. Cellulosic feedstock can contain up to 40% lig nin, depending on the type of feedstock used, so the effective utilization of this ligni n is an important piece of the profitability of the biochemical process. One option for the use of the lignin is to burn it to provide process heat and electricity, as well as excess electricity to the grid. While this would provide good value for the lignin, it would require fairly expensive boilers and turbines that increases the capital cost of the facility. If the lignin cannot be used as part of the fuel production process it may be able to be marketed as a solid fuel with high energy density and low carbon intensity.

2. ThermochemicalDRAFT 5/18/10

44 Thermochemical conversion involves bi omass being broken down into syngas using heat and upgraded to fuels using a combin ation of heat and pressure in the presence of catalysts. 19 For generating the syngas, thermochemical processes partially oxidize biomass in the presence of a gasifying agent, usually air, oxygen, and/or steam. It is important to note that these processing steps ar e also applicable to other feedstocks (e.g., coal or natural gas); the only difference is that a renewable feedstock is used (i.e., biomass) to produce cellulosic biofuel. Th e cellulosic biofuel produced can be mixed alcohols, but optimizing the process to produce ethanol, or it could be diesel fuel and naphtha. A thermochemical unit can also comp lement a biochemical processing plant to enhance the economics of an integrated biorefinery by converting lignin-rich, nonfermentable material left over from high-s tarch or cellulosic feedstocks conversion. 20
Compared to corn ethanol or biochemical ce llulosic ethanol plants, the use of biomass gasification may allow for greater flexibility to utilize different biomass feedstocks at aspecific plant. Mixed biomass feedstocks may be used, based on availability of longterm suppliers, seasonal availability, harvest cycle, and costs.

The general steps of the gasification th ermochemical process include: feedstock handling, gasification, gas cleanup and conditi oning, fuel synthesis, and separation. Refer to Figure IV.C.2-1 for a schematic of the thermochemical cellulosic ethanol production process through gasification. For greater detail on the th ermochemical mixedalcohols route refer to NR EL technical documentation. 21

19 US. DOE. Technologies: Processing and Conversion. Accessed at: http://www1.eere.energy.gov/biomass/processing_conversion.html on October 28 , 2008

20 EERE, DOE, Thermochemical Conversion , & Biochemical Conversion

, Biomass Program

Thermochemical R&D . http://www1.eere.energy.gov/biomass/thermochemical_conversion.html http://www1.eere.energy.gov/biomass/biochemical_conversion.html

21 Aden, Andy, Mixed Alcohols from Woody Biomass – 2010, 2015, 2022, National Renewable Energy Laboratory (NREL), September, 23 2009.DRAFT 5/18/10

45 Figure IV.C.2-1

Cellulosic Ethanol Thermochemical Gasification Process

Figure IV.C.2-2 is a block diagram of a biomass to liquids (BTL) process which produces diesel fuel and naphtha th rough a thermochemical process.DRAFT 5/18/10

46 Figure IV.C.2-2 Biomass to Liquids (BTL) Ther mochemical Gasification Process

The first step in a thermochemical plant is feedstock size reduction. The particle size requirement for a thermochemi cal process is around 10-mm to 100-mm in

diameter. 22 Once the feed is ground to the proper size, flue gases from the char combustor and tar reformer catalyst regenerator dry the feed from the as received

moisture level of around 30% to 50% moisture to the level required by the gasifier.

The dried, ground feedstock is fed to a ga sification reactor for producing syngas. There are two general classes of gasifiers, pa rtial oxidation (POx) and indirect gasifiers. Partial oxidation gasifiers (directly-heated gasifiers) use the exothermic reaction between oxygen and organics to provide the heat n ecessary to devolatilize biomass and to convert residual carbon-rich chars. Indirect gasifiers use steam to accomplish gasification through heat transfer from a hot solid or through a heat transfer surface. Either the byproduct char and/or a portion of the product gas can be combusted with air (external to the gasifier itself) to provide the energy required for gasification. The raw syngas produced from either type of gasifier has a low to medium energy content which consists mainly of CO, H 2 , CO 2 , H 2 O, N 2 , and hydrocarbons

Once the biomass is gasified and converted to syngas, the syngas must be cleaned and conditioned, as minor compone nts of tars, sulfur, nitroge n oxides, alkali metals, and

22 Lin Wei, Graduate Research Assistant, Lester O. Pordesimo, Assistant Professor Willam D. Batchelor, Professor, Department of Agricultural and Biological Engineering, Mississippi State University, MS 39762, USA, Ethanol Production from Wood: Comparison of Hydrolysis Fermentation and Gasification Biosynthesis, Paper Number: 076036, Written for presentation at the 2007 ASABE Annual International Meeting. Minneapolis Convention Center, Minneapolis, MN, 17 - 20 June

2007DRAFT 5/18/10

47 particulates have the potential to negativel y affect the syngas conversion steps. Therefore, unwanted impurities are remove d in a gas cleanup step and the gas composition is further modified during gas condi tioning. Because this step is a necessary part of the thermochemical process, ther mochemical plants are good candidates for processing municipal solid waste (MSW) wh ich may contain a significant amount of toxic material. Gas conditioning steps include sulfur polishing to remove trace levels of

H 2 S and water-gas shift to adjust the final H 2 /CO ratio for optimized fuel synthesis.

After cleanup and conditioning, the “clean” syngas is comprised of essentially CO

and H 2 . The syngas is then converted into a liqui d fuel by a catalytic process. The fuel producer has the choice of producing diesel fuel or alcohols from syngas by optimizing the type of catalyst used and the H 2 /CO ratio. Diesel fuel ha s historically been the primary focus of such processes by using a Fischer Tropsch reactor, as it produces a high quality distillate product. However, with a $1.01 per gallon cellulosic biofuel tax deduction which favors the less energy dense ethanol, it may be economically advantageous for fuel producers to convert syng as to ethanol instead of to diesel fuel.

A carefully integrated conventional steam cycle produces process heat andelectricity (excess electricity is exported). Pre-heaters, steam generators, and superheaters generate steam that drives turbines on compressors and electrical generators. The

heat balance around a thermochemical unit or thermochemical combined unit must be carefully designed and tuned in or der to avoid unnecessary heat losses. 23 These facilities greatly increase the thermal efficiency of these plants, but they add to the very high capital costs of these technologies.

a. Ethanol based on a Ther mochemical Platform

Conceptual designs and techno-economic m odels have been developed for ethanol production via mixed alcohol synthesis using cat alytic processes. The proposed mixed alcohol process produces a mixture of ethanol along with higher normal alcohols (e.g., npropanol, n-butanol, and n-penta nol). The by-product higher normal alcohols have value as commodity chemicals and fuel additives.

The liquid rundown from the low-pressure se parator is dehydrated in vapor-phase molecular sieves, producing the dehydrated mix ed alcohol feed into a methanol/ethanol overhead stream and a mixed, higher molecu lar weight alcohol bottom stream. The overhead stream is further separated into a methanol stream and an ethanol stream.

Two companies which are pursuing ethanol based on a thermochemical route are Range Fuels and Enerkem. Range has operate d a pilot plant for over 7 years using over

20 different nonfood feedstocks . Range broke ground building its first commercial plant late in late 2008 and is expected to be oper ational in 2010. This plant will be located in

23 S. Phillips, A. Aden, J. Jechura, and D. Dayton, National Renewable Energy Laboratory, Golden, Colorado 80401-3393, T. Eggeman, Neoterics International, Inc., Thermochemical Ethanol via Indirect Gasification and Mixed Alcohol Synthesis of Lignocellulosic Biomass, Technical Report, NREL/TP-510- 41168, April 2007DRAFT 5/18/10

48 Soperton, Georgia and is partia lly funded from proceeds of a DOE grant. The plant will use wood, grasses, and corn stover as feedstoc ks. In its initial phase, the Range plant is expected to produce 4 million gallons per ye ar of methanol. After the company is confident in its operations, Range will begin efforts to expand the plant and add additional reaction capacity to conve rt the methanol to ethanol.

Enerkem is pursuing cellulosic ethanol pr oduction via the thermochemical route. The Canadian-based company was recently announced as a recipient of a $50 million grant from DOE to build a 10 MGY woody biom ass-to-ethanol plant in Pontotoc, MS. The U.S. plant is not scheduled to come online until 2012, but Enerkem is currently building a 1.3 MGY demonstration plant in Westbury, Quebec. According to the company, plant construction in Westbury st arted in October 2007 and the facility is currently scheduled to come online around the middle of 2010. While it’s unclear at this time whether the cellulosic ethanol produced will be exported to the United States, Enerkem has expressed interest in selling its fuel commercially. If Enerkem does export some of its cellulosic biofuel to the U.S., it could help to enable refiners meet the 2011

cellulosic biofuel standard.

b. Diesel and Naphtha Production ba sed on a Thermochemical Platform

The cleaned and water-shifted syngas is sent to the Fischer Tropsch (FT) reactor where the carbon monoxide and hydrogen are reacted over a FT catalyst. Current FT catalysts include iron-based catalysts, and cobalt-based catalysts. The FT reactor creates a syncrude, which is a variety of hydrocarbons that boil over a wide distillation range (a mix of heavy and light hydrocarbons) which ar e separated into various components based on their vapor pressure, mainly liquid petroleum gas (LPG), naphtha, disti llate and wax fractions. The heavier compounds are hydrocra cked to maximize the production of diesel fuel. Conversely, the naphtha material is very low in octane thus, it would either have to be upgraded, or blended down with high octane blendsto cks (i.e., ethanol), or be upgraded to a higher octane blendstock to have much value for use in gasoline.

Choren is an European company which is pursuing a thermochemical technology for producing diesel fuel and naphtha. The prin cipal aspect of Choren’s process is their patented three stage gasification reactor. The three-stage gasification reactor includes low temperature gasification, high temperat ure gasification and e ndothermic entrained bed gasification. Choren designed its gasifica tion reactor with three stages to more fully convert the feedstock to syngas. Choren w ill be building a commercial Plant in Freiberg/ Saxony Germany that is expected to be operational in 2011 or 2012. Initially, the plant will use biomass from nearby forests, the wood-processing industry and straw from farmland. Although any fuel produced in 2011 by its Freiberg/Saxony plant and marketed commercially would most likely be us ed in Europe, it is possible that some of that fuel could be exported to the US. Chor en is also planning to build a commercial thermochemical/BTL plant in the U.S. after their Freiberg/Saxony plant is operational in Germany.DRAFT 5/18/10

49 Baard Energy is a U.S. company which plans on utilizing a thermochemical technology for producing diesel fuel and naphtha. Baard, however, plans on primarily combusting coal and cofiring biomass with the coal. Cofiring the biomass with the coal will make their first plant more like the coal-to-liquids plants which are operating today, which may help to convince investors that this technology is already tested. Baard’s coal and biomass-to-liquids plant is not exp ected to be operational until at least 2012.

Probably the largest commercialization hurdle for the companies pursing the thermochemical route is the very high capita l costs associated with these technologies. Because of the economic hardships associated with recent global recession, banks are less willing to make loans to fund new technologies which are likely to be considered riskier investments. The capital costs are very high because there are two significant reactors required for each plant – the gasification re actor and the syngas to fuel reactor. Additionally, the syngas must be cleaned to protect the catalysts used in the downstream syngas to fuel reactor which requires additiona l capital costs. Because the syngas would be cleaned anyways, this technology is a ve ry good candidate for processing MSW which may contain toxic compounds. When considerin g the cost savings for not having to pay the tipping fees at municipal dumping gr ounds, MSW feedstocks may avoid almost all the purchase costs for MSW feedstocks which would significantly help offset the high capital costs.

3. Hybrid Thermochemical/Biochemical Processes

Hybrid technologies include process el ements involving both the gasification stage of a typical thermochemical process, as well as the fermentation stage of a typical biochemical process and therefor e cannot be placed easily into either category. For more specific information regarding either biochemical processes or thermochemical, please see Sections IV.C.1 and IV.C.2 respectively. Currently, there are several strategies for the production of ethanol through hybr id processes; these strategies are differentiated by the

order in which the thermochemical and bioche mical steps take place within the process, as well as how the intermediate pr oducts from each step are used.

While we do not expect significant comme rcial production from hy brid processes in 2011, there are several companies pursing this approach for the future. Examples of the first process strategy, described in the pa ragraph below, include both INEOS Bio and Coskata. INEOS Bio (along with partner New Planet Energy) has recently been selected for a $50MM DOE grant for the construction of an 8 MGPY plant in River County, Florida; predicted to finish construction in late 2011. Coskata is currently running a 40,000 gallon per year pilot plant that became operational in 2009 in Madison, Pennsylvania. Coskata is targeting to design and build a 50 MGPY commercial plant that it expects to be operational in 2012. A comp any currently pursing the second process strategy, described in the following third paragraph, is Zeachem Inc. Zeachem is currently constructing a 250 KGPY demonstr ation plant in Boardman, Oregon. They have received a $25MM DOE grant and exp ect to have a full commercial production facility operational in 2013.DRAFT 5/18/10

50 One strategy involves the gasification of all feedstock material to syngas before being processed into ethanol using a bioc hemical fermenter. Further information regarding gasification can also be found in Section IV.C.2. After gasification, the syngas

stream is cooled and bubbled into a ferm enter containing modified microorganisms, usually bacteria or yeast. This fermenter replaces the typical catalysts found after gasification in a traditional thermochemical process. Further information regarding

fermentation can be found in Section IV.C .1. Unlike traditional fermentation (which break down C5 and C6 sugars), these microorganisms are engineered to convert the carbon monoxide and hydrogen contained in the syngas stream directly into ethanol. After fermentation, the effluent water/ethanol stream from the fermenter is separated similarly to a biochemical process; usually using a combination of distillation and molecular sieves. The separated water can then be recycled back into the fermentation stage of the process. Typical yields of et hanol are predicted in the 100 - 120 gallon per

ton range.

Since gasification converts all carbonace ous feedstock material to a uniform syngas before fermentation, there is a higher flexibility of feedstock choices than if these materials were to be fermented directly; including agricultural residues, switchgrass, farm-grown trees, sorted MSW, or any comb ination of such. In addition, processing incoming feedstock with gasification does not require the addition of enzymes or acid hydrolysis necessary in a biochemical proc ess to aid in the breakdown of cellulosic materials. Fermenting syngas also captu res all available carbon contained in the feedstock, including lignin that would not be processed in a typical biochemical fermentation. However, more energy is lost as waste heat as well as secondary carbon dioxide production in the gasification proce ss than would be lost for biochemical feedstock preparation. Using a fermenter in a hy brid process replaces the catalyst needed in a typical thermochemical process. Thes e microorganisms allow for a higher variation of the incoming syngas stream properties, a void the necessity of a water-shift reaction preceding traditional catalytic conversion, and ar e able to operate at lower temperatures and pressures than those required for a catal ytic conversion to ethanol. Microorganisms, unlike a catalyst, are also self-sustaining a nd do not require periodic replacement. They are; however, susceptible to bacterial a nd viral infections which requires periodic cleaning of the fermentation reactors.

Another hybrid production strategy involves gasification of the typically unfermentable feedstock fraction (lignin) conc urrently with a typical fermentation step

for the cellulose and hemicellulose fraction. Th ese steps are subsequently combined in a hydrogenation reaction of the produced syngas with the product of the fermented stream. Feedstock first undergoes acid hydrolysis to break down contained cellulose and hemicellulose. Before fermentation, the unfer mentable portion of feedstock (lignin, ash and other residue) is fractioned and sent to a gasifier. Concurrently, the remaining fraction of hydrolyzed feedstock is fermen ted using an acetogen microorganism. These acetogens occur naturally, and therefore do not have to be modified for this process. These acetogen convert both C6 and C5 porti ons of the hydrolized feedstock to acetic acid. This reaction creates no carbon dioxide, unlike traditional fermentation using yeast,DRAFT 5/18/10

51 preserving the maximum amount of carbon for the finished fuel. Th e acetic acid stream then undergoes esterification to create ethyl acetate. Meanwhile, the syngas stream from the gasification of lignin and other residue is separated into its carbon monoxide and hydrogen components. The carbon monoxide stre am can be further combusted to provide process heat or energy. The hydrogen stream is combined with the ethyl acetate in a hydrolysis reaction to form ethanol. Acetic acid and ethyl acetate also form the precursors to many other chemical compounds and therefor e may also be sold in addition to ethanol. Typical yields for this technology are pr edicted in the 130 – 150 gallon per ton range.

4. Pyrolysis and Depolymerization

Pyrolysis and depolymerization is a group of technologies which are capable of creating biofuels from cellulose by either thermally or catalytically breaking them down into molecules which fall within the boiling range of transportation fuels. Pyrolysis technologies are usually thought of being primarily a thermal technology, however, newer pyrolysis technologies are being devel oped which are attemptin g to integrate some catalysts into the technology. These are all unique processes, typically with single companies developing the technologies, so they are discussed separately.

a. Pyrolysis Diesel Fuel and Gasoline

Pyrolysis oils, or bio-oils, are produced by decomposing cellulosic biomass at lower temperatures than the gasification pro cess, thus producing a liquid bio oil instead of a synthesis gas. 24 The reaction can occur either with or without the use of catalysts, but it occurs without any additional oxygen being present. The resulting oil which is produced must have particulates and ash re moved in filtration to create a homogenous “dirty” crude oil type of product. This di rty crude oil must be further upgraded to hydrocarbon fuels via hydrotreating and hydr ocracking processing, which reduces its total oxygen content and cracks the heaviest of the hydrocarbon compounds. One of the finished fuels produced by the pyrolysis pro cess is diesel fuel, however, a significant amount of gasoline would likely be produced as well. There are two main reaction pathways currently being explored: a two step pyrolysis pathway, and a one step pyrolysis pathway.

The simplest technology used for the two- step pyrolysis approach is called fast pyrolysis. The fast pyrolysis technology uses sand in a fluidized bed to transform biofuels into a product named bio-oil. This is purely a thermal process, where the sand’s (or other solid) role is to transport heat to th e biomass. Fast pyrolysis technology has two problems to be solved. First, fast pyroly sis oil is unstable, acidic, viscous and may separate itself into two phases so it must be immediately upgraded or it will begin to degrade and repolymerize. The second issue is that pyrolysis bio-oil must be upgraded before it can be used as a transportation fuel.

24 DOE EERE Biomass Program. “Thermochemical Conversion Processes: Pyrolysis” http://www1.eere.energy.gov/biomass/thermochemical_processes.html , November 6, 2008.DRAFT 5/18/10

52 Another approach to Fast Pyrolysis bein g pursued by several companies would be to substitute a catalyst in place of sand and the catalyst would be able to stabilize the resulting bio-oil in addition to helping depolymerize the biomass to liquids. Although the resulting bio-oil is stable, it still has to be upgraded into a transportation fuel, since it would still have a high level of oxygenated compounds.

The National Renewable Energy Laboratory (NREL) is working on a “hot filtration” technology that appa rently is able to stabilize bio-oil created using the fast pyrolysis process for a very long period of time (years). This would allow the bio-oil to be stored and transported to an upgradin g facility without significant degradation.

It is possible to use a sophisticated catal yst (instead of sand) in a single step pyrolysis reaction to create pyrolysis oils th at exhibit much improve d bio-oil properties. The catalysts would not only be able to help depolymerize cellulosic feedstocks, but they produce a bio-oil which could possibly be used directly as transportation fuel. Thus, a second upgrading step may not be necessary. The difficulty encountered by this technology is that catalysts which have been used in the one step process are relatively expensive and they degrade quickly due to the metals which are present in the biomass. Development work on the two-step and on e-step pyrolysis processes is ongoing.

Dynamotive Energy Systems Corporation is a Canadian company which has developed a pyrolysis technology that uses medium temperatures and oxygen free reactions to convert dry wast e biomass and energy crops into different products. The liquid product produced by the Dynamotive process is called BioOil. The BioOil contains up to 25% water, though the wate r is intimately mixed and does not easily separate into another phase with time. Since the BioOil contains significant amounts of water, it is not directly useable as fuel in conventional vehicles and would have to be converted via another catalytic conversion proc essing step. The additional catalytic step envisioned by Dynamotive to upgrade the Bi oOil into a transportation fuel would combust the material into a synthesis gas whic h would then be converted into diesel fuel or bio-methanol via a catalytic reaction (the BTL process). The diesel fuel produced is expected to be compatible with existing petr oleum diesel fuels. The poor quality BioOil, though, could be used in the No. 2 industrial heating oil market at industrial facilities. However, because of its high acidity level, users would need to change equipment metallurgy to stainless steel for pi pes, pumps, tanks, nozzles etc.

Dynamotive has two small demonstration plants. One demonstration plant is located in Guelph, Ontario, Canada and its ca pacity is 66,000 dry tons of biomass a year with an energy output equivalent to 130,000 barrels of oil. The other of its demonstration plants is located in West Lorne Ontario, Canada. Dynamotive continues to work on a technology for converting its BioOil to tran sportation fuels, although they have not announced plans for building such a facility due to funding limits. While Dynamotive is expected to continue to sell its fuel into the chemicals market, it could find a fuel oil user in the U.S. to use its fuel under the RFS2 program that refiners could use to comply with

the 2011 cellulosic biofuel standard.DRAFT 5/18/10

53 Envergent is a company formed through a joint venture between Honeywell’s UOP and the Ensyn Corporation. Although Ensyn has been using fast pyrolysis for more than a decade to produce specialty chemicals, UOP is relying on its decades of experience developing refini ng technologies to convert the pyrolysis oils into transportation fuels. Envergent is also working with Federal laboratories to further their technology. Based on their current t echnology and depending on the feedstock processed, about 70 % of the feedstock is c onverted into liquid products. The gasoline range products produced are high in octane, while the diesel fuel products are low in cetane. Envergen estimates that if it was able to procure cellulosic feedstocks at 70 per ton, that their technology would be competitiv e with #2 fuel oil produced from crude oil priced at about $40 per barrel. Envergent is licensing this technology as well as working with a U.S. oil company to test out this technology in a commercial setting here in the

U.S.

Petrobras is a Brazilian oil company also working to develop a pyrolysis technology. Because of Petrobas’ work in this area (and other areas on biofuels), a Memorandum of Understanding was signed by United States‘ Secr etary of State and

Brazil’s External Relations Minister on March 9, 2007 to advance the cooperation on

biofuels. A second Memorandum of Unders tanding was signed by PETROBRAS and NREL on September 2008 aiming at collaborating to maximize the benefit of their respective institutional interest s in second generation biofuels . Petrobras is negotiating a Cooperation Agreement with NREL to devel op a two step pyrolysis route to produce biofuels from agricultural wastes such as suga r cane bagasse, wood chips or corn stover. Petrobras is optimistic that a catalytic pyro lysis technology can be developed that will produce a stable bio-oil (pyrolysis oil). Pe trobras is hopeful that a one-step pyrolysis technology can be developed to convert bioma ss directly to transportation fuels, although

in the end Petrobras believes that the tw o step process may be more economically

attractive.

b. Catalytic Depolymerization

Two companies that are pursuing catalytic depolymerization are Green Power Inc. and Cello Energy.

The Green Power process catalytically depolymerizes cellulosic feedstocks at moderate temperatures into liquid hydrocarbon fuels. The proposed feedstock is municipal solid waste (MSW) or other waste material such as animal waste, plastics, agriculture residue, woody biomass and sewage waste. The feedstock is first ground to a size finer than 5 mm. The feedstock is placed along with a catalyst, some lime, which serves as a neutralizing agent, and some fuel which provides a liquid medium, into a reactor and heated to around 350 degrees Celsiu s. As described, this technology may fit the description for catalyzed pyrolysis reacti ons described above, but because we are not

certain of the reaction kinetic s, we have categorized this as a separate catalytic depolymerization technology. In the reactor, the feedstock is catalytically converted to liquid fuels which primarily fall within the gasoline and diesel fuel boiling ranges, although these fuels may need further upgrad ing. The liquid fuels are separated fromDRAFT 5/18/10

54 some solids which are present and are distilled into typical fuel streams including naphtha, diesel fuel, kerosene and fuel oil. According to the literature writing about this technology, the process reportedly produces 120 gallons per ton of feedstock inputted into the process. A light hydrocarbon gas, wh ich is mostly methane, is also produced, but this gas is expected to be burned in a turbine to generate electricity and the waste heat is used for heating the process. Apparently, some carbon dioxide is also formed and is released from the process.

Greenpower completed construction on a demonstration plant located in Fife, Washington about March of 2008. Greenpower is working on obtaining additional funding and to obtain an air permit throug h the State of Washington Environmental

Office. While we don’t believe that Gree npower will have its pl ant operational in 2011 due to financial and other issues the company faces, those issues could be resolved to allow this company to produce fuel that could help refiners comply with the cellulosic

biofuel volume standard for 2011.

The Cello-Energy process is also a cat alytic depolymerization technology. At moderate pressure and temperature, the Cello-Energy process catalytically removes the oxygen and minerals from the hydrocarbons th at comprise finely ground cellulose. This results in a mixture of short chain (3, 6 and 9 carbon) hydrocarbon compounds. These short chain hydrocarbon compounds are polymeriz ed to form compounds that boil in the diesel boiling range, though the process can also be adjusted to produce gasoline or jet fuel. The resulting diesel fuel meets the ASTM standards, is in the range of 50 cetane to 55 cetane and typically contains 3 ppm of sulfur.

The Cello process is reported to be on th e order of 82 % efficient at converting the feedstock energy content into the energy c ontent of the product, which is very high compared to most of today's biochemical a nd thermochemical processes which are on the order of 50 % efficient, or less. Because of the simplicity of the process, the capital costs are very low. A 50 million gallon per year plant is claimed to only incur a total cost of $45 million. Because of its high efficiency in converting feedstocks into liquid fuel, the production and operating costs are estimated to be very low.

In December 2008, Cello completed c onstruction on a 20 million gallon per year commercial demonstration plant. However, at the present they are still working to resolve process issues that have arisen upon scaleup from their pilot plant. We expect that Cello will be able to produce so me volume of cellulosic biofuel in 2011.

5. Catalytic Reforming of Sugars to Gasoline

Virent Biorefining is pursuing a process called “Bioforming” which functions similarly as the gasoline reforming process used in the refining industry. Hence, this is a very different technology to any of those ot her cellulosic biofuel technologies discussed above. While refinery-based catalytic refo rming technologies raise natural gasoline’s octane value and produces aromatic compounds, Bioformin g reforms biomass-derivedDRAFT 5/18/10

55 sugars into hydrocarbons for blending into ga soline and diesel fuel. The process operates at moderate temperatures a nd pressures. In March of 2010, Virent announced that they had begun operating a larger pilot plant capable of about 30 gallons per day.

Commercialization of the Virent process will happe n sometime after 2011.

For this technology to become a cellulosi c biofuel technology, it will be necessary to link this reforming technology with a technology which breaks cellulose down into starch or sugars. In parallel with its Bioreforming work, Virent is working on a technology to break down cellulose into sugars upstream of its technology which reforms sugars to gasoline.DRAFT 5/18/10

56 V. Proposed Changes to RFS2 Regulations

Following publication of the final RFS2 program regulations 25 , EPA identified two program areas that could benefit from the addition of new regulatory provisions. The first would provide for the generation of RINs for fuel produced between July 1, 2010 and December 31, 2010 representing certain fuel pathways that are not currently in Table 1 to §80.1426, but which could possibly be added late r this year if they are determined to meet the applicable GHG thresholds. Unde r this proposal RINs could be generated only if the pathways are indeed approved, and only for quantities reflecting fuel produced between the effective date of the RFS2 regulations and the effective date of a new pathway added to Table 1 to §80.1426. The second program addition would establish procedures for petitions requesting EPA authorization of an aggregate compliance approach to renewable biomass verification for feedstocks grown in foreign countries, akin to that applicable to crops and crop re sidue grown within the U.S. We are proposing to make amendments to the RFS regulations in Subpart M to implement both of these provisions.

A. Delayed RIN Generation for New Pathways

As described in the RFS2 final rule, we did not have sufficient time to complete the necessary lifecycle GHG impact assessment for certain fuel pathways. We indicated that we would model and evaluate several additional pathways after the final rule (see Section V.C of the RFS2 final rule, 75 FR 14796). EPA anticipates modeling and publishing the lifecycle GHG analyses for the following four pathways later this year:

• Grain sorghum ethanol • Pulpwood biofuel

• Palm oil biodiesel

• Canola oil biodiesel

Depending on how these lifecycle GHG results compare with the required GHG thresholds for cellulosic biofuel, bioma ss-based diesel, advanced biofuel, and conventional renewable fuel, we may add one or more of these pathways to Table 1 to §80.1426. Once a new pathway is approved, producers using that pathway could generate RINs with the specified D code.

We consider the four new fuel pathways currently being analyzed to be an

extension of the RFS2 final rule. Had we be en able to complete these analyses for the

RFS2 final rule and verified that the GHG thre sholds had been met, D codes to represent these pathways would have been included in Table 1 to §80.1426 promulgated on March 26, 2010, and renewable fuel producers could have begun using those pathways to generate RINs beginning on July 1, 2010. Indeed, we are aware of a number of producers who intend to produce biofuel using one of the four pathways listed above

25 75 FR 14670, March 26, 2010DRAFT 5/18/10

57 despite the fact that a determination rega rding their lifecycle GHG impact has not yet

been made.

Based on the fact that we may have incl uded the four pathways listed above in the RFS2 final rule if the lifecycle modeling had been completed in time, we believe that it would be appropriate to allow renewable fuel producers using any of these four pathways that are ultimately approved for inclusion in Table 1 to §80.1426 to generate RINs for all fuel they produce and sell on and after July 1, 2010. However, while EPA is expeditiously working to complete its GHG asse ssments for these four fuel pathways in 2010, the determination of whether any of the four pathways will meet the 20%, 50%, or 60% GHG thresholds may not occur until after July 1, 2010. Therefore, RINs representing fuel produced between July 1, 2010 and any EPA approval of a new fuel pathway could only be generated after the re newable fuel in question had been produced and sold, after the time when EPA announces th e results of the lifecycle analyses and specifies the applicable D code in Table 1 to §80.1426. Thus we are proposing a new regulatory provision for the generation of “D elayed RINs” that would allow RINs with newly specified D codes to be generated fo r eligible fuel produced between July 1, 2010 and the date any new D code is approved for one of the four fuel pathways listed above. This Delayed RINs provision would only be a pplicable for any of the four pathways

described above that are deter mined to meet the applicable GHG thresholds. We are also proposing that this provision would apply only for renewable fuel produced in 2010, since the lifecycle GHG assessments for the four pathways listed above is expected to be completed in 2010. Our proposed regulatory provision for Delayed RIN generation would be inserted into §80.1426 as new paragraph (g). As for any RIN generation, producers using this new regulatory provision would need to be registered under RFS2 before they could generate Delayed RINs , and would need to comply with the recordkeeping and reporting re quirements of the regulations.

We do not believe that this proposed provision for Delayed RINs should be extended to any other pathways. The four pa thways listed above are the only pathways currently under evaluation that would have been included in the RFS2 final rule if we had completed the modeling in time. Moreover, we have provided a petition process in §80.1416 for other fuel pathways for which lifec ycle GHG assessments have not yet been

made.

In developing this proposed provision for Delayed RIN Generation, we have accounted for renewable fuel producers who ar e eligible for an exemption from the 20% GHG reduction requirement for their fuel under §80.1403 (“grandfathered” producers) and those that are not. Grandfathered produc ers can generate RINs for their renewable fuel starting on July 1, 2010, but must designate the D code as 6 for such fuel, identifying it as conventional renewable fuel. They must also transfer those RINs with renewable fuel they sell. If one of the four fuel pa thways described above is approved between July 1, 2010 and December 31, 2010 for use of a D code other than 6, and the producer wishes to apply this new D code to fuel they have already produced and transferred, the RINs they already generated and transferred with renewable fuel they produced must be accounted for. We are proposing a proce ss whereby these grandfathered producersDRAFT 5/18/10

58 would be required to acquire and retire RINs from the open market with a D code of 6 prior to the generation of Delayed RINs. The nu mber of RINs retired in this fashion must be no greater than the number they generate d between July 1, 2010 and the effective date of the new applicable pathway. Produc ers who are not grandfathered under §80.1403 cannot generate RINs starting on July 1, 2010, and so would not be required to acquire and retire any RINs prior to the generation of Delayed RINs.

The generation of Delayed RINs would also differ for grandfathered producers and non-grandfathered producers. Grandfat hered producers would base the number of Delayed RINs they generate on the number of RI Ns with a D code of 6 that they retired as described above. In contrast, non-grandf athered producers would base the number of Delayed RINs they generate on the volume of renewable fuel they produced and sold between July 1, 2010 and the effective date of the new pathway. Since all Delayed RINs will be generated after the renewable fuel in question had been produced and sold, they would be assigned a K code of 2 and thus c ould be sold by the producer separately from

renewable fuel.

Finally, we believe that there should be a deadline for the generation of Delayed RINs to ensure that they are entering the market as close as possible to the date of production of the renewable fuel that they re present. We are proposing that all Delayed RINs must be generated within 30 days of th e effective date of a new pathway added to Table 1 to §80.1426 between July 1, 2010 and December 31, 2010. We believe that 30 days would provide sufficient time for producer s who are grandfathered to first acquire and retire RINs from the open market, and woul d be sufficient to allow any producer to generate Delayed RINs according to the pro cedures in the regulations. However, we request comment on a longer period within which Delayed RINs must be generated.

We request comment on our propos ed provision for Delayed RINs.

B. Criteria and Process for Adop tion of Aggregate Approach to Renewable Biomass for Foreign Countries

In the preamble to the final RFS2 regulations, EPA indicated that, while we did not have sufficient data at the time to make a finding that the aggregate compliance approach adopted for domestically-grown cr ops and crop residues would be appropriate for foreign-grown feedstocks, we would consider applying the aggregate compliance approach for renewable biomass on a country by country basis if ad equate land use data

becomes available.

Since promulgation of the final RFS2 re gulations, we have received several inquiries regarding the process, criteria, and data needed for EPA to approve the aggregate compliance approach for planted cr ops and crop residue grown in areas outside the U.S. Thus, in today’s rule, EPA is proposing a process by which entities may petition EPA for approval of the aggregate compliance approach for specified renewable fuel feedstocks either in a foreign country as a w hole or in a specified ge ographical area. TheDRAFT 5/18/10

59 proposed regulations include a general criteri on and a number of considerations that EPA will use in evaluating petitions. They also include a list of submissions that are required, absent an explanation by petitioner of why they should not be required for EPA to approve a petition. The proposed rule also in cludes a description of the proposed process by which EPA would make decisions concerning any petitions received.

1. Criterion and Considerations

In developing these proposed regula tions, EPA relied substantially on the approach we used to determine that an aggregate compliance approach was appropriate for planted crops and crop residue from U.S. agricultural land. The fundamental finding that would be required of EPA in approving a petition for application of the aggregate approach would be that an aggregate compliance approach will provide reasonable assurance that specified renewable fuel feedstocks from a given geographical area meet

the definition of renewable biomass and will continue to meet the definition of renewable biomass, based on the submission of credible, reliable and verifiable data. Based on our experience in making the comparable finding for U.S.-grown crops and crop residues, we are also proposing a number of more specifi c factors that would be considered in determining whether this finding should be ma de, as described below. EPA is proposing

to consider:

• Whether there has been a reasonable identification of the aggregate amount of agricultural land in th e specified geographical area on December 19, 2007 that was available fo r the production of the specified feedstock(s) and that satisfy the defi nition of renewable biomass, taking

into account the definitions of terms such as “cropland,” “pastureland,” “planted crop,” and “crop residue” includ ed in the final RFS2 regulations.

• Whether information from years preceding and following 2007 shows that the identified aggregate amount of land in the specific geographical area, called the 2007 baseline area of land, is not likely to be exceeded in the

future.

• Whether economic considerations, lega l constraints, historical land use and agricultural practices and other f actors show that it is likely that producers of the feedstock(s) will continue to use agricultural land within the baseline area of land identified into the future, as opposed to clearing and cultivating land not eligib le under the 2007 baseline.

• Whether there is a reliable method to evaluate on a continuing basis

whether the 2007 baseline area of land is being or has been exceeded.

• Whether an entity has been identif ied to conduct data gathering and analysis needed for an annual EPA evaluation of the aggregate compliance approach if EPA grants the petition.

EPA is requesting comments on the propos ed general criterion and specific considerations for approving the aggregat e compliance approach for non-domestically grown feedstocks. The existing approved aggregate approach for US domestic feedstocks applies to all crops and crop residue that could be used in renewable fuelDRAFT 5/18/10

60 production. EPA has received inquiries on the extent to whic h approval could be obtained for a single, or limited number, of f eedstocks. The proposed regulations leave open the possibility of feedstock-specific petitions, but EPA particularly solicits comment

on the extent to which different or additi onal data submittals or inquiries would be appropriate for such petitions.

2. Data Sources

To make the aggregate compliance determination for U.S. agricultural lands, EPA obtained USDA data from three independently gathered national la nd use data sources (the Farm Service Agency (FSA) Crop Hist ory Data, the USDA Census of Agriculture (2007), and the satellite-based USDA Crop Da ta Layer (CDL)). Please see Section II.C.4.c.iii.of the preamble to the final RFS2 rule (75 Fed. Reg. 14701 (March 26, 2010)) for a more detailed description of the data sources used. Using these data sources, EPA was able assess the area of land (acreage) av ailable in the United States under EISA for production of crops and crop residue s that meet the definition of renewable biomass. In the case of a petition to apply the aggregate compliance approach to feedstocks from a specific geographical area in a foreign count ry, when considering the information and data submitted by the petitioner, EPA will evaluate such information on a case-by-case basis, but suggests that petitioners obtain data from sources that are at least as credible, reliable, and verifiable as the USDA data used to make the determination for U.S. agricultural land.

When evaluating whether the data relied on are credible, reliable, and verifiable,

EPA will take into account whether the data is submitted by, genera ted by, or approved by the national government of the fore ign country in question, as well as how comprehensive and accurate the data sour ce is. It is important for the national government of the area seeking consideration be involved in this process, and we seek

comment on whether or not involvement of the national government should be required as part of the petitioning and/or data submittal processes. Additionally, EPA will take into consideration whether the data is publically available, whether the data collection and analysis methodologies and information on the primary data source are available to EPA, and whether the data has been generate d, analyzed, and/or approved or endorsed by an independent third party. EPA would also take into account the quality of the data that

is available on an annual basis for EPA’s a nnual assessments of any approved aggregate compliance approach, as well as whether the petitioner has identified an entity who will provide to EPA an analysis of the data updates each year following EPA’s approval of the aggregate compliance approach for that area. Furthermore, EPA will consider agricultural land use trends from several years preceding 2007, as well as the years following 2007 to the time the petition is submitte d in order to evaluate whether or not it is likely that a 2007 baseline would be exceed ed in the future. EPA will consider whether there are laws in place in the ar ea for which the petition was submitted that might prohibit or incentivize the clearing of new agricultural lands and the efficacy of these laws. EPA will also assess whether any market factors are expected to drive an increase in the demand for agricultural land.DRAFT 5/18/10

61 3. Petition Submission

EPA is proposing that all submittals, including the petition, supporting documentation, and annual data and analyses , be submitted in English. We are also proposing that petitioners submit specified info rmation as part of their formal petition submission package, or explain why such information is not necessary for EPA to approve their petition. Petitioners would n eed to submit an assessment of the total amount of land that is cropland or pasturela nd that was cleared or cultivated prior to December 19, 2007 and that was actively mana ged or fallow and nonforested on that date. For example, in assessing the amount of total existing agricultural land in the U.S. on the enactment date of EISA, EPA used FSA Crop History data to show that there were 402 million acres of agricultural land existing in the U.S. in 2007. Additionally, if the petitioner is seeking approval of the aggregate compliance approach for a particular feedstock, they would also need to sub mit an assessment of the total amount of agricultural land dedicated to that feedstoc k in 2007 within the specified area. Petitioners would also be required to provide EPA with maps or electronic data identifying the boundaries of the land in questi on and a description of the feedstock(s) for which the petitioner is submitting the petition.

As part of the petition, the petitioner would be required to submit to EPA land use data that demonstrates that the land in ques tion is agricultural land that was cleared or cultivated prior to December 19, 2007 and th at was actively managed or fallow and nonforested on that date, which may include sa tellite imagery data, aerial photography, census data, agricultural surveys, and/or agricultural economic modeling data. As mentioned above, the FSA crop history data used for the U.S. aggregate compliance approach determination consis ts of annual records of farm-level land use data that includes all cropland and pastur eland in the U.S. EPA also considered USDA Census of Agriculture data, which consists of a full censu s of the U.S. agricultural sector once every five years, as well as the USDA Nation Agricultural Statistics Service (NASS) Crop Data Layer (CDL), which is based on satellite data.

In establishing the total amount of existing agricultural land for the U.S. aggregate compliance approach determination, EPA relied on the RFS2 definitions of the relevant terms, including planted crops, cr op residue, and agricultural land, which is defined as consisting of cr opland, pastureland and CRP land. EPA will take into consideration whether the data submitted by the petitioner relies on comparable definitions. For purposes of RFS2, planted cr ops are defined as all annual or perennial agricultural crops from existing agricultural land that may be used as feedstocks for renewable fuel, such as grains, oilseeds, su garcane, switchgrass, prairie grass, duckweed, and other species (but not including algae speci es or planted trees), providing they were intentionally applied by humans to the gr ound, a growth medium, a pond or tank, either by direct application as seed or plant, or through intentional natural seeding or vegetative propagation by mature plants introduced or left undisturbed for that purpose. Crop

residue is defined as the biom ass left over from the harvestin g or processing of planted crops from existing agricultural land and any bi omass removed from existing agricultural land that facilitates crop management (including biomass removed from such lands inDRAFT 5/18/10

62 relation to invasive species control or fire management), whether or not the biomass includes any portion of a crop or crop plant. Cropland is defined as land used for production of crops for harvest and includes cu ltivated cropland, such as for row crops or close-grown crops, and non-cultivated cropland, su ch as for horticultura l or aquatic crops. Pastureland is land managed for the production of indigenous or introduced forage plants for livestock grazing or hay production, and to prevent succession to other plant types. It is important to note that EPA considers pa stureland to be distinctly different from rangeland, which may be used for livestock grazing, but is not managed to prevent succession to other plant types. Finally, CRP land is land enrolled in the US Conservation Reserve Program (administered by USDA’s Farm Service Agency), which encourages farmers to convert highly er odible cropland or other environmentally sensitive acreage to vegetative cover, such as tame or native grasses, wildlife plantings, trees, filterstrips, or riparian buffers. EPA recognizes that the CRP is only applicable to U.S. agricultural land. EPA solicits comment s on whether the final rules should allow EPA to consider land that is equivalent or similar to US CRP land as existing agricultural land for purposes of RFS2-compliant feedstock cultivation in a foreign county, and

whether EPA should be able to make such a determination in the context of a petition for application of the aggregate approach to a foreign country.

The petitioner would also be required to provide EPA with historical land use data for the land in question, covering the years from prior to 2007 to the current year. For the U.S. aggregate compliance approach determination, EPA analyzed the FSA Crop History data from the years 2005 through 2007 and the USDA Census of Agriculture from 1997 through 2007, finding that there was an overall de cade trend of contra ction of agricultural land utilization in the U.S. The petitioner would need to provide a description of any applicable laws, agricultural practices, economic considerations, or ot her relevant factors that had or may have an effect on the use of the land in question. For the U.S. aggregate compliance approach determination, EPA also took in account the EISA renewable fuel obligations, the unsuitability and high cost of developing previously undeveloped land for agricultural purposes, as well as projected incr eases in crop yields on existing agricultural

land.

Finally, the petitioner would be required to provide EPA with a plan describing how the entity who will, on a continuing year ly basis, conduct any data gathering and analysis necessary to assist EPA in its annual assessment of any approved aggregate approach. In the plan, the petitioner would describe the data, the data source, and the

schedule on which the data woul d be updated and made available to EPA and the public. Additionally, the plan would include the en tity’s strategy and schedule for conducting an annual analysis of the data and providing it to EPA.

4. Petition Process

We believe that it will be important to incorporate a public comment component into EPA’s deliberations on a petition made to incorporate an aggregate compliance approach for a new area. EPA plans to pub lish a Federal Register notice informing the public of incoming petitions, with information on how to view the petitions and anyDRAFT 5/18/10

63 supporting information. EPA proposes to th en accept public comment on the petition for a specified period of time. Once the public comment period closes, EPA will make an assessment, taking into account the inform ation submitted in the petition as well as the comments received, and will then publish a deci sion in the Federal Register to either approve or deny the petitioner’s request. If the petition has been approved, the Federal Register notice will specify an effective date at which time producers using the specified feedstocks from the specified areas identified in EPA’s approval will be subject to the aggregate compliance approach requireme nts in 40 CFR 80.1454(g) in lieu of the renewable biomass recordkeeping and reportin g requirements. In the event that the annual data submitted by the pe titioner is insufficient to de monstrate that the baseline

amount of land has not been exceeded or if the annual data is not submitted in a timely manner, EPA will make a finding that the baseline acreage has been exceeded and producers using crops or crop residue from the specified area will be subject to the individual recordkeeping and re porting requirements described in the regulations. EPA is seeking comments on this proposed process.DRAFT 5/18/10

64 VI. Public Participation

We request comment on all aspects of th is proposal. This section describes how you can participate in this process.

A. How Do I Submit Comments?

We are opening a formal comment period by publishing this document. We will accept comments during the period indicated under DATES in the first part of this proposal. If you have an interest in th e proposed standards and changes to the RFS regulations described in this document, we encourage you to comment on any aspect of this rulemaking. We also request comment on specific topics identified throughout this proposal.

Your comments will be most useful if you include appropriate and detailed supporting rationale, data, and analysis. Co mmenters are especially encouraged to provide specific suggestions for any changes th at they believe need to be made. You should send all comments, except those contai ning proprietary information, to our Air Docket (see ADDRESSES in the first part of this proposal) before the end of the comment period.

You may submit comments electronically, by mail, or through hand delivery/courier. To ensure proper receipt by EPA, identify the appropriate docket identification number in the subject line on the first page of your comment. Please ensure that your comments are submitted within the specified comment period. Comments received after the close of the comment period will be marked “late.” EPA is not required to consider these late comments. If you wish to submit Confidential Business Information (CBI) or information that is othe rwise protected by statute, please follow the

instructions in Section VI.B.

B. How Should I Submit CBI to the Agency?

Do not submit information that you consider to be CBI electronically through the electronic public docket, www.regulations.gov, or by e-mail. Send or deliver information identified as CBI only to the following addr ess: U.S. Environmental Protection Agency, Assessment and Standards Division, 2000 Tr averwood Drive, Ann Arbor, MI, 48105, Attention Docket ID EPA-HQ-OAR-2010-0133. You may claim information that you submit to EPA as CBI by marking any part or all of that information as CBI (if you submit CBI on disk or CD ROM, mark the outside of the disk or CD ROM as CBI and then identify electronically within the disk or CD ROM the specific information that is CBI). Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2.DRAFT 5/18/10

65 In addition to one complete version of the comments that include any information claimed as CBI, a copy of the comments that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. If you submit the copy that does not contain CBI on disk or CD ROM, ma rk the outside of the disk or CD ROM clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket without prior notice. If you have any questions about CBI or the procedures for claiming CBI, please consult the person identified in the FOR

FURTHER INFORMATION CONTACT section.DRAFT 5/18/10

66 VII. Statutory and Ex ecutive Order Reviews

A. Executive Order 12866: Regula tory Planning and Review

Under Executive Order (EO) 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 EO 12866 and any changes made in response to OMB recommendations

have been documented in the docket for this action.

The economic impacts of the RFS2 progr am on regulated parties, including the impacts of the required volumes of renewable fuel, were already addressed in the RFS2 final rule promulgated on March 26, 2010 ( 75 FR 14670). This action proposes the percentage standards applicable in 2011 based on the volumes that were analyzed in the RFS2 final rule. This action also proposes tw o new regulatory provisions that have been determined to have no adverse economic impact on regulated parties since they would increase flexibility to produce qualifying renewable fuel under the RFS2 program.

B. Paperwork Reduction Act

This action does not impose any new info rmation collection burdens, as we have

determined that this rule does not im pose any additional reporting requirements on regulated parties beyond those already required under RFS2. Therefore, there will not be any additional reporting burdens on entities impacted by this rulemaking. This action makes adjustments to the renewable fuel vol ume requirements specified in RFS2, as well as creating a temporary and limited means for certain renewable fuel producers to generate RINs after they have produced and so ld fuel. The action also establishes criteria for foreign countries to adopt an aggregate approach to compliance with the renewable biomass provision akin to that applicable to the U.S

.

The Office of Management and Budget (OMB) has previously approved the information collection require ments contained in the existing RFS2 regulations 75 FR 14670, March 26, 2010 under the provisions of the Paperwork Reduction Act , 44 U.S.C.

3501 et seq . and has assigned OMB contro l number 2060-0637. These preapproved items include registration (general and Centra l Data Exchange), independent third party engineering reviews, petitions for new re newable fuels and pathways, and additional items of reporting for foreign RIN owners. Th ese preapproved items take effect before July 1, 2010. Additional information collec tion requirements related to RFS2 are currently under review at OMB. The OMB c ontrol numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility ActDRAFT 5/18/10

67 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 Proce dure 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, c ounty, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-forprofit enterprise which is i ndependently owned and operated and is not dominant in its

field.

After considering the economic impacts of today’s proposed rule on small entities, we certify that this proposed action will not have a significan t economic impact on a

substantial number of small en tities. This rule sets the annual standard for cellulosic biofuels, proposes a regulatory provision for the generation of Delayed RINs, and establishes criteria for foreign countries to adopt an aggregate approach of compliance with the renewable biomass provision similar to that used in the U.S. However, the impacts of the RFS2 program on small entities were already addressed in the RFS2 final rule promulgated on March 26, 2010 (75 FR 14670) . Therefore, this proposed rule will not impose any additional requirements on small entities. We continue to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such impacts.

D. Unfunded Mandates Reform Act

This action contains no Federal mandates under the provisions of Title II of the Unfunded Mandates Reform Act of 1995 (U MRA), 2 U.S.C. 1531-1538 for State, local, or tribal governments or the private sector

. The action imposes no enforceable duty on any State, local or tribal governments or the private sector. Therefore, this action is not subject to the requirements of sections 202 or 205 of the UMRA.

This action is also not subject to th e 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 relations hip between the national government and the States, or on the distribution of power and responsibilities among the various levels ofDRAFT 5/18/10

68 government, as specified in Executive Order 13132

. This proposed rule does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the nationa l government and the States, or on the distribution of power and responsibilities among the various le vels of government, as specified in Executive Order 13132. Thus, Executive Order 13132 does not apply to this rule.

In the spirit of Executive Order 13132, and consistent with EPA policy to promote

communications between EPA and State and lo cal governments, EPA specifically solicits comment on this proposed rule from State and local officials.

F. Executive Order 13175: Consultation and Coordination with Indian

Tribal Governments

This action does not have tribal impli cations, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000)

. This proposed rule does not have tribal implications, as this rule will be implemented at the Federal level and impose compliance costs only on transportation fuel refiners, ble nders, marketers, distributors, importers, and exporters. Tribal governments would be aff ected 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 sa fety 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 esta blish an environmenta l standard intended to mitigate health or safety risks and because it implements specific standards established by Congress in statutes.

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

This rule is not a “significant energy action” as defined in Executive Order 13211, “Actions Concerning Regulations That Signif icantly 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, dist ribution, or use of energy.

I. National Technology Transfer Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), Public Law No. 104-113, 12(d) ( 15 U.S.C. 272 note) directs EPA to useDRAFT 5/18/10

69 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 speci fications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congre ss, through OMB, explanations when the Agency decides not to use available and a pplicable voluntary consensus standards.

This proposed rulemaking does not involve technical standards. Therefore, EPA is not considering the use of any voluntary consensus standards

.

J. Executive Order 12898: Federal Ac tions to Addre ss Environmental Justice in Minority Population s 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, disp roportionately high

and adverse human health or environmental effects of th eir programs, policies, and activities on minority populations and low-income populations in the United States.

EPA has determined that this proposed rule will not have disproportionately high and adverse human health or envir onmental effects on minority or low-income populations because it does not affect the leve l of protection provided to human health or

the environment. This action does not relax th e control measures on sources regulated by the RFS2 regulations and therefore will not cause emissions increases from these sources.DRAFT 5/18/10

70 VIII. Statutory Authority

Statutory authority for this action come s from section 211 of the Clean Air Act, 42 U.S.C. 7545. Additional support for the proc edural and compliance related aspects of today's proposal, including the proposed recordkeeping requirements, come from Sections 114, 208, and 301(a) of the Clean Air Act, 42 U.S.C. Sections 7414, 7542, and 7601(a).

List of Subjects in 40 CFR Part 80

Environmental protection, Air pollution control, Diesel Fuel, Fuel additives, Gasoline, Imports, Labeling, Motor vehicle polluti on, Penalties, Reporting and recordkeeping requirements.

Dated:

Lisa P. Jackson,

Administrator.DRAFT 5/18/10

71 For the reasons set forth in the preamble, 40 CFR part 80 is proposed to be amended as

follows:

PART 80—REGULATION OF FUELS AND FUEL ADDITIVES

1. The authority citation for part 80 continues to read as follows:

Authority: 42 U.S.C. 7414, 7542, 7545, and 7601(a).

2. Section 80.1426 is amended by revising paragraph (e)(1) and adding paragraph (g) to read as follows:

§ 80.1426 How are RINs generated and assigned to batches of renewable fuel by renewable fuel producers or importers?

* * * * *

(e) * * * (1) Except as provided in paragraph (g)(8 ) of this section for delayed RINs, the producer or importer of renewable fu el must assign all RINs generated

to volumes of renewable fuel.

* * * * *

(g) Delayed RIN generation . Parties who produce or import renewable fuel may generate delayed RINs to represent rene wable fuel volumes that have already been transferred to another party if thos e renewable fuel volumes can be described by a pathway that has been added to Table 1 to §80.1426 on or after July 1, 2010 and before January 1, 2011.

(1) When a new pathway is added to Table 1 to §80.1426, EPA will specify the effective date of that new pathway. This date will generally be the effective date of the rule in which the pathway is added.

(2) Delayed RINs must be generated with in 30 days of the date specified in paragraph (g)(1) of this section.

(3) Delayed RINs may only be genera ted to represent renewable fuel produced or imported between July 1, 2010 and the date specified in paragraph (g)(1) of this section.

(4) If a party originally generated and transferred RINs with renewable fuel volumes, and those RINs can be descri bed by a pathway added to Table 1 to §80.1426 on or after July 1, 2010 and before January 1, 2011, that party must retire a number of gallon-RINs prior to generating delayed RINs.DRAFT 5/18/10

72 (i) The number of gallon-RINs retir ed must not exceed the number of gallon-RINs originally generated to represent the renewable fuel volumes produced or imported betw een July 1, 2010 and the date specified in paragraph (g)(1) of this section.

(ii) Retired RINs must have a D code of 6.

(iii) Retired RINs must have a K code of 2.

(iv) Retired RINs must ha ve been generated in 2010.

(5) For parties that retire RINs pursuant to paragraph (g)(4) of this section, the number of delayed gallon-RINs generate d shall be equal to the number of gallon-RINs retired.

(6) For parties that did not retire RINs pursuant to paragraph (g)(4) of this section, the number of delayed gallon-RI Ns generated shall be determined pursuant to paragraph (f) of this section.

(i) The standardized volume of fuel (V

s ) used to determine the RIN volume (V RIN ) under paragraph (f) of th is section shall be the

standardized volume of renewa ble fuel produced or imported between July 1, 2010 and the date specified in paragraph (g)(1) of

this section.

(ii) The renewable fuel for which de layed RINs are generated must be described by a pathway that ha s been added to Table 1 to §80.1426 on or after July 1, 2010 and before January 1, 2011.

(7) All delayed RINs generated by a renewable fuel producer must be generated on the same date.

(8) Delayed RINs shall have a K code of 2.

(9) The D code that shall be used in delayed RINs generated shall be the D code specified in Table 1 to §80.1426 which corresponds to the pathway that describes the producer's operations.

3. Section 80.1454 is proposed to be amended by revising paragraph (g) introductory

text to read as follows:

§ 80.1454 What are the recordkeeping requirements under the RFS Program?

* * * * *DRAFT 5/18/10

73 (g) Aggregate compliance with renewable biomass requirement. Any producer or RIN-generating importer of renewable fuel made from planted crops or crop residue from existing U.S. agricultural land as defined in § 80.1401, or any producer or RIN-generating importer of renewable fuel made from feedstock covered by a petition approved pursuant to §80.1457, is subject to the aggregate compliance approach and is not required to maintain feedstock records unless EPA publishes a finding that the 2007 ba seline amount of agricultural land has been exceeded or that the criterion in §80.1457(a) is no longer satisfied.

* * * * *

4. Section 80.1457 is proposed to be added to read as follows:

§ 80.1457 Petition Process for Internat ional Aggregate Compliance Approach

(a) EPA may approve a petition for application of the aggregate compliance approach to non-U.S. planted crops and crop resi dues from existing foreign agricultural land if it determines that an aggregate compliance approach will provide reasonable assurance that specified renewable fuel feedstocks from a given geographical area meet the definition of renewable biomass and will continue to

meet the definition of rene wable biomass, based on the submission of credible, reliable, and verifiable data.

(1) As part of its evaluation, EPA will consider: (i) Whether there has been a reasonable identification of the aggregate amount of agricultural land in the specified geographi cal area as of December 19, 2007 that was available for the production of the specified feedstock(s) and that sa tisfy the definition of renewable biomass; (ii) Whether information from years preceding and following 2007 shows that the 2007 amount of agricultural land identified in paragraph (a)(1)(i) of this section is not likely to be exceeded in the future; (iii) Whether economic cons iderations, legal constraints, historical land use and agricultural practices, and/or other factors show that it is likely that producers of the feed stock(s) will continue to use agricultural land within area of land identified in paragraph (a)(1)(i) of this section in the fu ture as opposed to clearing and cultivating land that was not in cluded in that area of land. (iv) Whether there is a reliable me thod to evaluate on a continuing basis whether the 2007 area of land identified in paragraph (a)(1)(i) of this section is being exceeded; and (v) Whether an entity has been id entified to conduct data gathering and analysis needed for the evaluation specified in paragraphDRAFT 5/18/10

74 (a)(1)(iv) of this section, for sub mission to EPA on an annual basis if EPA grants the petition. (2) [Reserved]

(b) Any petition submitted under paragraph (a) of this section must be in the English language, and must include all of the following, or an explanation of why it is not needed for EPA to approve the petition:

(1) Maps or electronic data identifyi ng the boundaries of the land for which the petitioner seeks approval of an aggregate compliance approach.

(2) (i) For petitions regarding crops or crop residue, the total amount of land that is cropland or pastureland within the geographic boundaries specified in paragraph (b )(1) of this section that was cleared or cultivated prior to December 19, 2007 and that was actively managed or fallow and nonf orested on that date, and the total amount of land that is cropl and or pastureland within the geographic boundaries specified in paragraph (b)(1) of this section

that was not cleared or cultivat ed prior to December 19, 2007 and actively managed or fallow a nd nonforested on that date.

(ii) If the petitioner is seeking approval of the aggregate compliance approach for a particular plante d crop or crop residue, the total amount of land within the geographic boundaries specified in paragraph (b)(1) of this section that was used for the production of

that feedstock in 2007 and that wa s actively managed or fallow and nonforested on that date, and the total amount of land within the geographic boundaries specified in paragraph (b)(1) of this section that was used for the production of that feedstock in 2007 that was not cleared or cultivated prior to December 19, 2007 and actively managed or fallow and nonf orested on that date..

(3) A description of the feedstock(s) for which the petitioner is submitting the petition.

(4) Land use data that demonstrates th at the land in question in paragraph (b)(1)of this section is cropland or pastureland that was cleared or cultivated prior to December 19, 2007 and that was actively managed or

fallow and nonforested on that date , which may include any of the following:

(i) Satellite imagery data. (ii) Aerial photography. (iii) Census data. (iv) Agricultural surveys. (v) Agricultural economic modeling data.DRAFT 5/18/10

75 (5) Historical land use data for th e land within the geographic boundaries specified in paragraph (b)(1) of this section to the current year, which may include any of the following:

(i) Satellite imagery data. (ii) Aerial photography. (iii) Census data. (iv) Agricultural surveys. (v) Agricultural economic modeling data.

(6) A description of any applicable laws, agricultural practices, economic considerations, or other re levant factors that had or may have an effect on the use of the land within the geographic boundaries specified in paragraph (b)(1) of this section.

(7) A plan describing how the petitioner will identify an entity who will, on a continuing basis, conduct data gather ing, analysis, and submittal to assist EPA in making an annual determina tion of whether the criterion specified in paragraph (a) of this section remains satisfied.

(8) Any additional information the Administrator may require.

(c) If EPA approves a petition it will issue a Federal Register notice announcing its decision and specifying an effective date for the application of the aggregate compliance approach to the specified feedstock(s) from the specific geographical area. Thereafter, the specified feedstocks from the specified area will be covered by the aggregate compliance approach set forth in §80.1454(g), or as otherwise specified pursuant to paragraph (d) of this section.

(d) If EPA grants a petition to establish an aggregate compliance approach for a specified feedstock(s) from a specific geographical area, it may include any conditions that EPA considers appropria te in light of the conditions and

circumstances involved.

(e) (1) EPA may withdraw its approval of the aggregate approach for the area and feedstocks in question if: (i) EPA determines that the data submitted pursuant to the plan described in paragraph (b)(7) of this section does not demonstrate that the amount of cropland and pa stureland within the geographic boundaries covered by the approved petition does not exceed the 2007 baseline amount of land; (ii) EPA determines based on other information that the criterion specified in paragraph (a) of this section is no longer satisfied; orDRAFT 5/18/10

76 (iii) EPA determines that the data needed for its annual evaluation has not been collected and submitted in a timely and appropriate

manner. (2) If EPA withdraws its approval, then producers using feedstocks from that area will be subject to the individual recordkeeping and reporting requirements of §80.1454(b) through (d) in accordance with the schedule specified in §80.1454(g).