[Federal Register Volume 74, Number 99 (Tuesday, May 26, 2009)]
[Proposed Rules]
[Pages 24904-25143]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E9-10978]



[[Page 24903]]

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Part II





Environmental Protection Agency





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40 CFR Part 80



Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel 
Standard Program; Proposed Rule

Federal Register / Vol. 74, No. 99 / Tuesday, May 26, 2009 / Proposed 
Rules

[[Page 24904]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2005-0161; FRL-8903-1]
RIN 2060-A081


Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel 
Standard Program

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice of proposed rulemaking.

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SUMMARY: Under the Clean Air Act, as amended by Sections 201, 202, and 
210 of the Energy Independence and Security Act of 2007, the 
Environmental Protection Agency is required to promulgate regulations 
implementing changes to the Renewable Fuel Standard program. The 
revised statutory requirements specify the volumes of cellulosic 
biofuel, biomass-based diesel, advanced biofuel, and total renewable 
fuel that must be used in transportation fuel each year, with the 
volumes increasing over time. The revised statutory requirements also 
include new definitions and criteria for both renewable fuels and the 
feedstocks used to produce them, including new greenhouse gas emission 
thresholds for renewable fuels. For the first time in a regulatory 
program, an assessment of greenhouse gas emission performance is being 
utilized to establish those fuels that qualify for the four different 
renewable fuel standards. As mandated by the revised statutory 
requirements, the greenhouse gas emission assessments must evaluate the 
full lifecycle emission impacts of fuel production including both 
direct and indirect emissions, including significant emissions from 
land use changes. The proposed program is expected to reduce U.S. 
dependence on foreign sources of petroleum by increasing domestic 
sources of energy. Based on our lifecycle analysis, we believe that the 
expanded use of renewable fuels would provide significant reductions in 
greenhouse gas emissions such as carbon dioxide that affect climate 
change. We recognize the significance of using lifecycle greenhouse gas 
emission assessments that include indirect impacts such as emission 
impacts of indirect land use changes. Therefore, in this preamble we 
have been transparent in breaking out the various sources of greenhouse 
gas emissions included in the analysis and are seeking comments on our 
methodology as well as various options for determining the lifecycle 
greenhouse gas emissions (GHG) for each fuel. In addition to seeking 
comments on the information in this document and its supporting 
materials, the Agency is conducting peer reviews of critical aspects of 
the lifecycle methodology. The increased use of renewable fuels would 
also impact criteria pollutant emissions, with some pollutants such as 
volatile organic compounds (VOC) and nitrogen oxides (NOX) 
expected to increase and other pollutants such as carbon monoxide (CO) 
and benzene expected to decrease. The production of feedstocks used to 
produce renewable fuels is also expected to impact water quality.
    This action proposes regulations designed to ensure that refiners, 
blenders, and importers of gasoline and diesel would use enough 
renewable fuel each year so that the four volume requirements of the 
Energy Independence and Security Act would be met with renewable fuels 
that also meet the required lifecycle greenhouse gas emissions 
performance standards. Our proposed rule describes the standards that 
would apply to these parties and the renewable fuels that would qualify 
for compliance. The proposed regulations make a number of changes to 
the current Renewable Fuel Standard program while retaining many 
elements of the compliance and trading system already in place.

DATES: Comments must be received on or before July 27, 2009, 60 days 
after publication in the Federal Register. Under the Paperwork 
Reduction Act, comments on the information collection provisions are 
best assured of having full effect if the Office of Management and 
Budget (OMB) receives a copy of your comments on or before June 25, 
2009, 30 days after date of publication in the Federal Register.
    Hearing: We will hold a public hearing on June 9, 2009 at the 
Dupont Hotel in Washington, DC. The hearing will start at 10 a.m. local 
time and continue until everyone has had a chance to speak. If you want 
to testify at the hearing, notify the contact person listed under FOR 
FURTHER INFORMATION CONTACT by June 1, 2009.
    Workshop: We will hold a workshop on June 10-11, 2009 at the Dupont 
Hotel in Washington, DC to present details of our lifecycle GHG 
analysis. During this workshop, we intend to go through the lifecycle 
GHG analysis included in this proposal. The intent of this workshop is 
to help ensure a full understanding of our lifecycle analysis, the 
major issues identified and the options discussed. We expect that this 
workshop will help ensure that we receive submission of the most 
thoughtful and useful comments to this proposal and that the best 
methodology and assumptions are used for calculating GHG emissions 
impacts of fuels for the final rule. While this workshop will be held 
during the comment period, it is not intended to replace either the 
formal public hearing or the need to submit comments to the docket.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2005-0161, by one of the following methods:
     www.regulations.gov: Follow the on-line instructions for 
submitting comments.
     E-mail: asdinfo@epa.gov.
     Mail: Air and Radiation Docket and Information Center, 
Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania 
Ave., NW., Washington, DC 20460. In addition, please mail a copy of 
your comments on the information collection provisions to the Office of 
Information and Regulatory Affairs, Office of Management and Budget 
(OMB), Attn: Desk Officer for EPA, 725 17th St., NW., Washington, DC 
20503.
     Hand Delivery: EPA Docket Center, EPA West Building, Room 
3334, 1301 Constitution Ave., NW., Washington, DC 20004. 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-
2005-0161. EPA's policy is that all comments received will be included 
in the public docket without change and may be made available online at 
www.regulations.gov, including any personal information provided, 
unless the comment includes information claimed to be Confidential 
Business Information (CBI) or other information whose disclosure is 
restricted by statute. Do not submit information that you consider to 
be CBI or otherwise protected through www.regulations.gov or e-mail. 
The www.regulations.gov Web site is an ``anonymous access'' system, 
which means EPA will not know your identity or contact information 
unless you provide it in the body of your comment. If you send an e-
mail comment directly to EPA without going through 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

[[Page 24905]]

comment and with any disk or CD-ROM you submit. If EPA cannot read your 
comment due to technical difficulties and cannot contact you for 
clarification, EPA may not be able to consider your comment. Electronic 
files should avoid the use of special characters, any form of 
encryption, and be free of any defects or viruses. For additional 
information about EPA's public docket visit the EPA Docket Center 
homepage at http://www.epa.gov/epahome/dockets.htm. For additional 
instructions on submitting comments, go to Section XI, Public 
Participation, of the SUPPLEMENTARY INFORMATION section of this 
document.
    Docket: All documents in the docket are listed in the 
www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy. 
Publicly available docket materials are available either electronically 
in www.regulations.gov or in hard copy at the Air and Radiation Docket 
and Information Center, EPA/DC, EPA West, Room 3334, 1301 Constitution 
Ave., NW., Washington, DC. The Public Reading Room is open from 8:30 
a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The 
telephone number for the Public Reading Room is (202) 566-1744, and the 
telephone number for the Air Docket is (202) 566-1742.
    Hearing: The public hearing will be held on June 9, 2009 at the 
Dupont Hotel, 1500 New Hampshire Avenue, NW., Washington, DC 20036. See 
Section XI, Public Participation, for more information about the public 
hearing.

FOR FURTHER INFORMATION CONTACT: Julia MacAllister, Office of 
Transportation and Air Quality, Assessment and Standards Division, 
Environmental Protection Agency, 2000 Traverwood Drive, Ann Arbor, MI 
48105; Telephone number: 734-214-4131; Fax number: 734-214-4816; E-mail 
address: macallister.julia@epa.gov, or Assessment and Standards 
Division Hotline; telephone number (734) 214-4636; E-mail address 
asdinfo@epa.gov.

SUPPLEMENTARY INFORMATION:

General Information

A. Does This Proposal Apply to Me?

    Entities potentially affected by this proposal are those involved 
with the production, distribution, and sale of transportation fuels, 
including gasoline and diesel fuel or renewable fuels such as ethanol 
and biodiesel. Regulated categories include:

 
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                                               NAICS \1\   SIC \2\
                   Category                      codes      codes                         Examples of potentially regulated entities
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Industry.....................................     324110       2911  Petroleum Refineries.
Industry.....................................     325193       2869  Ethyl alcohol manufacturing.
Industry.....................................     325199       2869  Other basic organic chemical manufacturing.
Industry.....................................     424690       5169  Chemical and allied products merchant wholesalers.
Industry.....................................     424710       5171  Petroleum bulk stations and terminals.
Industry.....................................     424720       5172  Petroleum and petroleum products merchant wholesalers.
Industry.....................................     454319       5989  Other fuel dealers.
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\1\ North American Industry Classification System (NAICS).
\2\ Standard Industrial Classification (SIC) system code.

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by this 
proposed action. This table lists the types of entities that EPA is now 
aware could potentially be regulated by this proposed action. Other 
types of entities not listed in the table could also be regulated. To 
determine whether your activities would be regulated by this proposed 
action, you should carefully examine the applicability criteria in 40 
CFR part 80. If you have any questions regarding the applicability of 
this proposed action to a particular entity, consult the person listed 
in the preceding FOR FURTHER INFORMATION CONTACT 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 information that you 
claim to be confidential business information (CBI). For CBI 
information in a disk or CD-ROM that you mail to EPA, mark the outside 
of the disk or CD-ROM as CBI and then identify electronically within 
the disk or CD-ROM the specific information that is claimed as CBI. In 
addition to one complete version of the comment that includes 
information claimed as CBI, a copy of the comment that does not contain 
the information claimed as CBI must be submitted for inclusion in the 
public docket. Information so marked will not be disclosed except in 
accordance with procedures set forth in 40 CFR part 2.
2. Tips for Preparing Your Comments
    When submitting comments, remember to:
     Explain your views as clearly as possible.
     Describe any assumptions that you used.
     Provide any technical information and/or data you used 
that support your views.
     If you estimate potential burden or costs, explain how you 
arrived at your estimate.
     Provide specific examples to illustrate your concerns.
     Offer alternatives.
     Make sure to submit your comments by the comment period 
deadline identified.
     To ensure proper receipt by EPA, identify the appropriate 
docket identification number in the subject line on the first page of 
your response. It would also be helpful if you provided the name, date, 
and Federal Register citation related to your comments.
    We are primarily seeking comment on the proposed 40 CFR Part 80 
Subpart M regulatory language that is not directly included in 40 CFR 
Part 80 Subpart K. For the proposed subpart M regulatory language that 
is unchanged from subpart K, we are only soliciting comment as it 
relates to its use for the RFS2 rule.

Outline of This Preamble

I. Introduction
    A. Renewable Fuels and the Transportation Sector

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    B. Renewable Fuels and Greenhouse Gas Emissions
    C. Building on the RFS1 Program
II. Overview of the Proposed Program
    A. Summary of New Provisions of the RFS Program
    1. Required Volumes of Renewable Fuel
    2. Changes in How Renewable Fuel Is Defined
    3. Analysis of Lifecycle Greenhouse Gas Emissions and Thresholds 
for Renewable Fuels
    4. Coverage Expanded to Transportation Fuel, Including Diesel 
and Nonroad Fuels
    5. Effective Date for New Requirements
    6. Treatment of Required Volumes Preceding the RFS2 Effective 
Date
    7. Waivers and Credits for Cellulosic Biofuel
    8. Proposed Standards for 2010
    B. Impacts of Increasing Volume Requirements in the RFS2 Program
    1. Greenhouse Gases and Fossil Fuel Consumption
    2. Economic Impacts and Energy Security
    3. Emissions, Air Quality, and Health Impacts
    4. Water
    5. Agricultural Commodity Prices
III. What Are the Major Elements of the Program Required Under EISA?
    A. Changes to Renewable Identification Numbers (RINs)
    B. New Eligibility Requirements for Renewable Fuels
    1. Changes in Renewable Fuel Definitions
    a. Renewable Fuel and Renewable Biomass
    b. Advanced Biofuel
    c. Cellulosic Biofuel
    d. Biomass-Based Diesel
    e. Additional Renewable Fuel
    2. Lifecycle GHG Thresholds
    3. Renewable Fuel Exempt From 20 Percent GHG Threshold
    a. Definition of Commence Construction
    b. Definition and Boundaries of a Facility
    c. Options Proposed in Today's Rulemaking
    i. Basic Approach: Grandfathering Limited to Baseline Volumes
    (1) Increases in volume of renewable fuel produced at 
grandfathered facilities due to expansion
    (2) Replacements of equipment
    (3) Registration, Recordkeeping and Reporting
    (4) Sub-option of treatment of future modifications
    ii. Alternative Options for Which We Seek Comment
    (1) Facilities that meet the definition of ``reconstruction'' 
are considered new
    (2) Expiration date of 15 years for exempted facilities
    (3) Expiration date of 15 years for grandfathered facilities and 
limitation on volume
    (4) ``Significant production units'' are defined as facilities
    (5) Indefinite grandfathering and no limitations placed on 
volume
    4. Renewable Biomass with Land Restrictions
    a. Definitions of Terms
    i. Planted Crops and Crop Residue
    ii. Planted Trees and Tree Residue
    iii. Slash and Pre-Commercial Thinnings
    iv. Biomass Obtained From Certain Areas at Risk From Wildfire
    b. Issues Related to Implementation and Enforceability
    i. Ensuring That RINs Are Generated Only for Fuels Made From 
Renewable Biomass
    ii. Ensuring That RINs Are Generated for All Qualifying 
Renewable Fuel
    c. Review of Existing Programs
    i. USDA Programs
    ii. Third-Party Programs
    d. Approaches for Domestic Renewable Fuel
    e. Approaches for Foreign Renewable Fuel
    C. Expanded Registration Process for Producers and Importers
    1. Domestic Renewable Fuel Producers
    2. Foreign Renewable Fuel Producers
    3. Renewable Fuel Importers
    4. Process and Timing
    D. Generation of RINs
    1. Equivalence Values
    2. Fuel Pathways and Assignment of D Codes
    a. Domestic Producers
    b. Foreign Producers
    c. Importers
    3. Facilities With Multiple Applicable Pathways
    4. Facilities That Co-Process Renewable Biomass and Fossil Fuels
    5 Treatment of Fuels Without an Applicable D Code
    6. Carbon Capture and Storage (CCS)
    E. Applicable Standards
    1. Calculation of Standards
    a. How Would the Standards Be Calculated?
    b. Proposed Standards for 2010
    c. Projected Standards for Other Years
    d. Alternative Effective Date
    2. Treatment of Biomass-Based Diesel in 2009 and 2010
    a. Proposed Shift in Biomass-Based Diesel Requirement from 2009 
to 2010
    i. First Option for Treatment of 2009 Biodiesel and Renewable 
Diesel RINs
    ii. Second Option for Treatment of 2009 Biodiesel and Renewable 
Diesel RINs
    b. Proposed Treatment of Deficit Carryovers and Valid RIN Life 
for Adjusted 2010 Biomass-Based Diesel Requirement
    c. Alternative Approach to Treatment of Biomass-Based Diesel in 
2009 and 2010
    F. Fuels That Are Subject to the Standards
    1. Gasoline
    2. Diesel
    3. Other Transportation Fuels
    G. Renewable Volume Obligations (RVOs)
    1. Determination of RVOs Corresponding to the Four Standards
    2. RINs Eligible to Meet Each RVO
    3. Treatment of RFS1 RINs under RFS2
    a. Use of 2009 RINs in 2010
    b. Deficit Carryovers from the RFS1 Program to RFS2
    4. Alternative Approach to Designation of Obligated Parties
    H. Separation of RINs
    1. Nonroad
    2. Heating Oil and Jet Fuel
    3. Exporters
    4. Alternative Approaches to RIN Transfers
    5. Neat Renewable Fuel and Renewable Fuel Blends Designated as 
Transportation Fuel, Home Heating Oil, or Jet Fuel
    I. Treatment of Cellulosic Biofuel
    1. Cellulosic Biofuel Standard
    2. EPA Cellulosic Allowances for Cellulosic Biofuel
    3. Potential Adverse Impacts of Allowances
    J. Changes to Recordkeeping and Reporting Requirements
    1. Recordkeeping
    2. Reporting
    3. Additional Requirements for Producers of Renewable Natural 
Gas, Electricity, and Propane
    K. Production Outlook Reports
    L. What Acts Are Prohibited and Who Is Liable for Violations?
IV. What Other Program Changes Have We Considered?
    A. Attest Engagements
    B. Small Refinery and Small Refiner Flexibilities
    1. Small Refinery Temporary Exemption
    2. Small Refiner Flexibilities
    a. Extension of Existing RFS1 Temporary Exemption
    b. Program Review
    c. Extensions of the Temporary Exemption Based on 
Disproportionate Economic Hardship
    d. Phase-in
    e. RIN-Related Flexibilities
    C. Other Flexibilities
    1. Upward Delegation of RIN-Separating Responsibilities
    2. Small Producer Exemption
    D. 20% Rollover Cap
    E. Concept for EPA Moderated Transaction System
    2. How EMTS Would Work
    3. Implementation of EMTS
    F. Retail Dispenser Labelling for Gasoline with Greater than 10 
Percent Ethanol
V. Assessment of Renewable Fuel Production Capacity and Use
    A. Summary of Projected Volumes
    1. Reference Case
    2. Control Case for Analyses
    a. Cellulosic Biofuel
    b. Biomass-Based Diesel
    c. Other Advanced Biofuel
    d. Other Renewable Fuel
    B. Renewable Fuel Production
    1. Corn/Starch Ethanol
    a. Historic/Current Production
    b. Forecasted Production Under RFS2
    2. Cellulosic Ethanol
    a. Current Production/Plans
    b. Federal/State Production Incentives
    c. Feedstock Availability
    i Urban Waste
    ii. Agricultural and Forestry Residues
    iii Dedicated Energy Crops
    iv. Summary of Cellulosic Feedstocks for 2022
    v. Cellulosic Plant Siting
    3. Imported Ethanol
    a. Historic World Ethanol Production and Consumption
    b. Historic/Current Domestic Imports
    c. Projected Domestic Imports
    4. Biodiesel & Renewable Diesel
    a. Historic and Projected Production
    i. Biodiesel

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    ii. Renewable Diesel
    b. Feedstock Availability
    C. Renewable Fuel Distribution
    1. Overview of Ethanol Distribution
    2. Overview of Biodiesel Distribution
    3. Overview of Renewable Diesel Distribution
    4. Changes in Freight Tonnage Movements
    5. Necessary Rail System Accommodations
    6. Necessary Marine System Accommodations
    7. Necessary Accommodations to the Road Transportation System
    8. Necessary Terminal Accommodations
    9. Need for Additional E85 Retail Facilities
    D. Ethanol Consumption
    1. Historic/Current Ethanol Consumption
    2. Increased Ethanol Use under RFS2
    a. Projected Gasoline Energy Demand
    b. Projected Growth in Flexible Fuel Vehicles
    c. Projected Growth in E85 Access
    d. Required Increase in E85 Refueling Rates
    e. Market Pricing of E85 Versus Gasoline
    3. Other Mechanisms for Getting Beyond the E10 Blend Wall
    a. Mandate for FFV Production
    b. Waiver of Mid-Level Ethanol Blends (E15/E20)
    c. Partial Waiver for Mid-Level Blends
    d. Non-Ethanol Cellulosic Biofuel Production
    e. Measurement Tolerance for E10
    f. Redefining ``Substantially Similar'' to Allow Mid-Level 
Ethanol Blends
VI. Impacts of the Program on Greenhouse Gas Emissions
    A. Introduction
    1. Definition of Lifecycle GHG Emissions
    2. History and Evolution of GHG Lifecycle Analysis
    B. Methodology
    1. Scenario Description
    2. Scope of the Analysis
    a. Legal Interpretation of Lifecycle Greenhouse Gas Emissions
    b. System Boundaries
    3. Modeling Framework
    4. Treatment of Uncertainty
    5. Components of the Lifecycle GHG Emissions Analysis
    a. Feedstock Production
    i. Domestic Agricultural Sector Impacts
    ii. International Agricultural Sector GHG Impacts
    b. Land Use Change
    i. Amount of Land Converted
    ii. Where Land Is Converted
    iii. What Type of Land Is Converted
    iv. What Are the GHG Emissions Associated with Different Types 
of Land Conversion
    v. Assessing GHG Emissions Impacts Over Time and Potential 
Application of a GHG Discount Rate
    c. Feedstock Transport
    d. Processing
    e. Fuel Transport
    f. Tailpipe Combustion
    6. Petroleum Baseline
    7. Energy Sector Indirect Impacts
    C. Fuel Specific GHG Emissions Estimates
    1. Greenhouse Gas Emissions Reductions Relative to the 2005 
Petroleum Baseline
    a. Corn Ethanol
    b. Imported Ethanol
    c. Cellulosic Ethanol
    d. Biodiesel
    2. Treatment of GHG Emissions Over Time
    D. Thresholds
    E. Assignment of Pathways to Renewable Fuel Categories
    1. Statutory Requirements
    2. Assignments for Pathways Subjected to Lifecycle Analyses
    3. Assignments for Additional Pathways
    a. Ethanol From Starch
    b. Renewable Fuels from Cellulosic Biomass
    c. Biodiesel
    d. Renewable Diesel Through Hydrotreating
    4. Summary
    F. Total GHG Emission Reductions
    G. Effects of GHG Emission Reductions and Changes in Global 
Temperature and Sea Level
    1. Introduction
    2. Estimated Projected Reductions in Global Mean Surface 
Temperatures
VII. How Would the Proposal Impact Criteria and Toxic Pollutant 
Emissions and Their Associated Effects?
    A. Overview of Impacts
    B. Fuel Production & Distribution Impacts of the Proposed 
Program
    C. Vehicle and Equipment Emission Impacts of Fuel Program
    D. Air Quality Impacts
    1. Current Levels of PM2.5, Ozone and Air Toxics
    2. Impacts of Proposed Standards on Future Ambient 
Concentrations of PM2.5, Ozone and Air Toxics
    E. Health Effects of Criteria and Air Toxic Pollutants
    1. Particulate Matter
    a. Background
    b. Health Effects of PM
    2. Ozone
    a. Background
    b. Health Effects of Ozone
    3. Carbon Monoxide
    4. Air Toxics
    a. Acetaldehyde
    b. Acrolein
    c. Benzene
    d. 1,3-Butadiene;
    e. Ethanol
    f. Formaldehyde
    g. Naphthalene
    h. Peroxyacetyl nitrate (PAN)
    i. Other Air Toxics
    F. Environmental Effects of Criteria and Air Toxic Pollutants
    1. Visibility
    2. Atmospheric Deposition
    3. Plant and Ecosystem Effects of Ozone
    4. Welfare Effects of Air Toxics
VIII. Impacts on Cost of Renewable Fuels, Gasoline, and Diesel
    A. Renewable Fuel Production Costs
    1. Ethanol Production Costs
    a. Corn Ethanol
    b. Cellulosic Ethanol
    i. Feedstock Costs
    ii. Production Costs
    c. Imported Sugarcane Ethanol
    2. Biodiesel and Renewable Diesel Production Costs
    a. Biodiesel
    b. Renewable Diesel
    3. BTL Diesel Production Costs
    B. Distribution Costs
    1. Ethanol Distribution Costs
    a. Capital Costs to Upgrade the Distribution System for 
Increased Ethanol Volume
    b. Ethanol Freight Costs
    2. Biodiesel and Renewable Diesel Distribution Costs
    a. Capital Costs to Upgrade the Distribution System for 
Increased FAME Biodiesel Volume
    b. Biodiesel Freight Costs
    c. Renewable Diesel Distribution System Capital and Freight 
Costs
    C. Reduced Refining Industry Costs
    D. Total Estimated Cost Impacts
    1. Refinery Modeling Methodology
    2. Overall Impact on Fuel Cost
    a. Costs Without Federal Tax Subsidies
    b. Gasoline and Diesel Costs Reflecting the Tax Subsidies
IX. Economic Impacts and Benefits of the Proposal
    A. Agricultural Impacts
    1. Commodity Price Changes
    2. Impacts on U.S. Farm Income
    3. Commodity Use Changes
    4. U.S. Land Use Changes
    5. Impact on U.S. Food Prices
    6. International Impacts
    B. Energy Security Impacts
    1. Implications of Reduced Petroleum Use on U.S. Imports
    2. Energy Security Implications
    a. Effect of Oil Use on Long-Run Oil Price, U.S. Import Costs, 
and Economic Output
    b. Short-Run Disruption Premium from Expected Costs of Sudden 
Supply Disruptions
    c. Costs of Existing U.S. Energy Security Policies
    d. Anticipated Future Effort
    e. Total Energy Security Benefits
    C. Benefits of Reducing GHG Emissions
    1. Introduction
    2. Marginal GHG Benefits Estimates
    3. Discussion of Marginal GHG Benefits Estimates
    4. Total Monetized GHG Benefits Estimates
    D. Co-pollutant Health and Environmental Impacts
    1. Human Health and Environmental Impacts
    2. Monetized Impacts
    3. Other Unquantified Health and Environmental Impacts
    E. Economy-Wide Impacts
X. Impacts on Water
    A. Background
    1. Ecological Impacts
    2. Gulf of Mexico
    B. Upper Mississippi River Basin Analysis
    1. SWAT Model
    2. Baseline Model Scenario
    3. Alternative Scenarios
    C. Additional Water Issues
    1. Chesapeake Bay Watershed
    2. Ethanol Production
    a. Distillers Grain with Solubles
    b. Ethanol Leaks and Spills
    3. Biodiesel Plants
    4. Water Quantity
    5. Drinking Water
    D. Request for Comment on Options for Reducing Water Quality 
Impacts
XI. Public Participation

[[Page 24908]]

    A. How Do I Submit Comments?
    B. How Should I Submit CBI to the Agency?
    C. Will There Be a Public Hearing?
    D. Comment Period
    E. What Should I Consider as I Prepare My Comments for EPA?
XII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    1. Overview
    2. Background
    3. Summary of Potentially Affected Small Entities
    4. Potential Reporting, Record Keeping, and Compliance
    5. Related Federal Rules
    6. Summary of SBREFA Panel Process and Panel Outreach
    a. Significant Panel Findings
    b. Panel Process
    c. Panel Recommendations
    i. Delay in Standards
    ii. Phase-in
    iii. RIN-Related Flexibilities
    iv. Program Review
    v. Extensions of the Temporary Exemption Based on a Study of 
Small Refinery Impacts
    vi. Extensions of the Temporary Exemption Based on 
Disproportionate Economic Hardship
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
XIII. Statutory Authority

I. Introduction

    The current Renewable Fuel Standard program (RFS1) was originally 
adopted by EPA to implement the provisions of the Energy Policy Act of 
2005 (EPAct), which added section 211(o) to the Clean Air Act (CAA). 
With the passage of the Energy Independence and Security Act of 2007 
(EISA), Congress recently made several important revisions to these 
renewable fuel requirements. This Notice proposes to revise the RFS 
program regulations to implement these EISA provisions. The proposed 
changes would apply starting January 1, 2010. For the remainder of 
2009, the current RFS1 regulations would apply. However, in 
anticipation of the biomass-based diesel standard proposed for 2010, 
obligated parties may find it in their best interest to plan 
accordingly in 2009.

A. Renewable Fuels and the Transportation Sector

    For the past several years, U.S. renewable fuel use has been 
rapidly increasing for a number of reasons. In the early 1990's, 
certain oxygenated gasoline fuel programs required by the CAA 
amendments of 1990 established new market opportunities for renewable 
fuels, primarily ethanol. At the same time, growing concern over U.S. 
dependence on foreign sources of crude placed increasing focus on 
renewable fuels as a replacement for petroleum-based fuels. More 
recently, several state bans on the use of methyl tertiary butyl ether 
(MTBE) in gasoline resulted in a large, sudden increase in demand for 
ethanol. Perhaps the largest impact on renewable fuel demand, however, 
has been the dramatic increase in the cost of crude oil. In the last 
few years, both crude oil prices and crude oil price forecasts have 
increased dramatically, which have resulted in a large economic 
incentive for the increased development and use of renewable fuels.
    In 2005, Congress introduced a new approach to supporting renewable 
fuels. EPAct established a major new federal renewable fuel volume 
mandate. EPAct required a ramp up to 7.5 billion gallons of renewable 
fuel as motor vehicle fuel by 2012 and set annual volume targets for 
each year leading up to 2012. For 2013 and beyond, EPA was directed to 
establish the annual required renewable fuel volumes, but at a 
percentage level no less than that required for 2012. While the market 
forces described above ultimately caused renewable fuel use to far 
exceed the EPAct mandates, this program provided certainty that at 
least a minimum amount of renewable fuel would be used in the U.S. 
transportation market, which in turn provided assurance for investment 
in production capacity.
    The subsequent passage of EISA made significant changes to both the 
structure and the magnitude of the renewable fuel program. The 
renewable fuel program established by EISA, hereafter referred to as 
RFS2, mandates the use of 36 billion gallons of renewable fuel by 2022. 
This is nearly a five-fold increase over the highest volume specified 
by EPAct and constitutes a 10-year extension of the scheduled 
production ramp-up period provided for in that legislation. It is clear 
that the volumes required by EISA will push the market to new levels--
far beyond what current market conditions would achieve alone. In 
addition, EISA specifies four separate categories of renewable fuels, 
each with a separate volume mandate. The categories are renewable fuel, 
advanced biofuel, biomass-based diesel, and cellulosic biofuel. There 
is a notable increase in the mandate for cellulosic biofuels in 
particular. EISA increased the cellulosic biofuel mandate from 250 
million in EPAct to 1.0 billion gallons by 2013, with additional yearly 
increases to 16 billion gallons by 2022. These requirements will 
provide a strong foundation for investment in cellulosic production and 
position cellulosic fuel to become a major portion of the renewable 
fuel pool over the next decade.
    The implications of the volume expansion of the program are not 
trivial. Development of infrastructure capable of delivering, storing 
and blending these volumes in new markets and expanding existing market 
capabilities will be needed. For example, the market's absorption of 
increased volumes of ethanol may ultimately require new ``outlets'' 
beyond E10 blends (i.e., gasoline containing 10% ethanol by volume), 
such as an expansion of the number of flexible-fuel E85 vehicles and 
the number of retail outlets selling E85.

B. Renewable Fuels and Greenhouse Gas Emissions

    Another significant aspect of the RFS2 program is the focus on the 
greenhouse gas impact of renewable fuels, from a lifecycle perspective. 
The lifecycle GHG emissions means the aggregate quantity of GHGs 
related to the full fuel cycle, including all stages of fuel and 
feedstock production and distribution, from feedstock generation and 
extraction through distribution and delivery and use of the finished 
fuel. EISA established specific greenhouse gas emission thresholds for 
each of four types of renewable fuels, requiring a percentage 
improvement compared to a baseline of the gasoline and diesel used in 
2005. EPA must conduct a lifecycle analysis to determine whether or not 
renewable fuels produced under varying conditions will meet the 
greenhouse gas (GHG) thresholds for the different fuel types for which 
EISA establishes mandates. While these thresholds do not constitute a 
control on greenhouse gases for transportation fuels (such as a low 
carbon fuel standard),\1\ they do require that the volume mandates be 
met through the use of renewable fuels that meet certain lifecycle GHG 
reduction thresholds when compared to

[[Page 24909]]

the baseline lifecycle emissions of petroleum fuel they replace. 
Compliance with the thresholds requires a comprehensive evaluation of 
renewable fuels, as well as of gasoline and diesel, on the basis of 
their lifecycle emissions. As mandated by EISA, the greenhouse gas 
emission assessments must evaluate the full lifecycle emission impacts 
of fuel production including both direct and indirect emissions, 
including significant emissions from land use changes. We recognize the 
significance of using lifecycle greenhouse gas emission assessments 
that include indirect impacts such as emission impacts of indirect land 
use changes. Therefore, in this preamble, we have been transparent in 
breaking out the various sources of greenhouse gas emissions included 
in the analysis. As described in detail in Section VI, EPA has analyzed 
the lifecycle GHG impacts of the range of biofuels currently expected 
to contribute significantly to meeting the volume mandates of EISA 
through 2022. In these analyses we have used the best science 
available. Our analysis relies on peer reviewed models and the best 
estimate of important trends in agricultural practices and fuel 
production technologies as these may impact our prediction of 
individual biofuel GHG performance through 2022. We have identified and 
highlighted assumptions and model inputs that particularly influence 
our assessment and seek comment on these assumptions, the models we 
have used and our overall methodology so as to assure the most robust 
assessment of lifecycle GHG performance for the final rule.
---------------------------------------------------------------------------

    \1\ See Section IV.D of EPA's advanced notice of proposed 
rulemaking, Regulating Greenhouse Gas Emissions under the Clean Air 
Act, for a discussion of EPA's possible authority under section 
211(c) of the CAA to establish GHG standards for renewable and 
alternative fuels. 73 FR 44354, July 30, 2008.
---------------------------------------------------------------------------

    Because lifecycle analysis is a new part of the RFS program, in 
addition to the formal comment period on the proposed rule, EPA is 
making multiple efforts to solicit public and expert feedback on our 
proposed approach. EPA plans to hold a public workshop focused 
specifically on lifecycle analysis during the comment period to assure 
full understanding of the analyses conducted, the issues addressed and 
the options that are discussed. We expect that this workshop will help 
ensure that we receive submission of the most thoughtful and useful 
comments to this proposal and that the best methodology and assumptions 
are used for calculating GHG emissions impacts of fuels for the final 
rule. Additionally, between this proposal and the final rule, we will 
conduct peer-reviews of key components of our analysis. As explained in 
more detail in the Section VI, EPA is specifically seeking peer review 
of: Our use of satellite data to project future the type of land use 
changes; the land conversion GHG emissions factors estimates we have 
used for different types of land use; our estimates of GHG emissions 
from foreign crop production; methods to account for the variable 
timing of GHG emissions; and how the several models we have relied upon 
are used together to provide overall lifecycle GHG estimates.
    In addition to the GHG thresholds, EISA included several provisions 
for the RFS2 program designed to address the long-term environmental 
sustainability of expanded biofuels production. The new law limits the 
crops and crop residues used to produce renewable fuel to those grown 
on land cleared or cultivated at any time prior to enactment of EISA, 
that is either actively managed or fallow, and non-forested. EISA also 
generally requires that forest-related slash and tree thinnings used 
for renewable fuel production pursuant to the Act be harvested from 
non-federal forest lands.
    To address potential air quality concerns, EPA is required by 
section 209 of EISA to determine whether the RFS2 volumes will 
adversely impact air quality as a result of changes in vehicle and 
engine emissions and then to issue fuel regulations that mitigate--to 
the extent achievable--these impacts. The Agency is also required by 
section 204 of EISA to conduct a broad study of environmental and 
resource conservation impacts of EISA, including impacts on water 
quality and availability, soil conservation, and biodiversity. Congress 
set specific deadlines for both of these provisions, which are separate 
from this rulemaking and will be carried out as part of a future 
effort. However, this NPRM does include EPA's initial assessment of the 
air and water quality impacts of the EISA volumes.
    While the above described changes are significant, it is important 
to note that Congress left other structural elements of the RFS program 
basically intact. The various modifications are discussed throughout 
this preamble.

C. Building on the RFS1 Program

    In designing this proposed RFS2 program, the Agency is utilizing 
and building on the same programmatic structure created to implement 
the current renewable fuel program (hereafter referred to as RFS1). For 
example, we propose to continue to use the Renewable Identification 
Number (RIN) system currently in place to track compliance with the 
RFS1 program, with modifications to implement the EISA provisions. This 
approach is in keeping with the Agency's overall intent for RFS1--to 
design a flexible and enforceable system that could continue to operate 
effectively regardless of the level of renewable fuel use or market 
conditions in the transportation fuel sector.
    A key component of the Agency's work to build a successful RFS1 
program was early and sustained engagement with our stakeholders. In 
developing this proposed rulemaking, we have again worked closely with 
a wide variety of stakeholders. Because EISA created new obligated 
parties and established new, complex provisions such as the lifecycle 
GHG thresholds and previous cropland requirements, EPA has extended its 
stakeholder engagement to include dozens of meetings with stakeholders 
from a broad spectrum of perspectives. For example, the Agency has had 
multiple meetings and discussions with renewable fuel producers, 
technology companies, petroleum refiners and importers, agricultural 
associations, lifecycle experts, environmental groups, vehicle 
manufacturers, states, gasoline and petroleum marketers, pipeline 
owners and fuel terminal operators.

II. Overview of the Proposed Program

    This section provides an overview of the RFS2 program requirements 
that EPA proposes to implement as a result of EISA. The RFS2 program 
would replace the RFS1 program promulgated on May 1, 2007 (72 FR 
23900).\2\ We are also proposing a number of changes to make the 
program more flexible based on what we learned from the operation of 
the RFS1 program since it began on September 1, 2007. Details of the 
proposed requirements can be found in Sections III and IV. We request 
comment on our proposed regulatory requirements and the alternatives 
that we have considered.
---------------------------------------------------------------------------

    \2\ To meet the requirements of EPAct, EPA had previously 
adopted a limited program that applied only to calendar year 2006. 
The RFS1 program refers to the general program adopted in the May 
2007 rulemaking.
---------------------------------------------------------------------------

    This section also provides a summary of EPA's impacts assessment of 
the use of higher renewable fuel volumes. Impacts that we assessed 
include: emissions of pollutants such as greenhouse gases (GHG), oxides 
of nitrogen (NOX), hydrocarbons, particulate matter (PM), 
and toxics; reductions in petroleum use and related impacts on national 
energy security; impacts on the agriculture sector; impacts on costs of 
transportation fuels; economic costs and benefits; and impacts on 
water. Details of these

[[Page 24910]]

analyses can be found in Sections V through X and in the Draft 
Regulatory Impact Analysis (DRIA).

A. Summary of New Provisions of the RFS Program

    Today's notice proposes new regulatory requirements for the RFS 
program that would be implemented through a new Subpart M to 40 CFR 
Part 80. EPA is generally proposing to maintain many elements of the 
RFS1 program such as regulations governing the generation, transfer, 
and use of Renewable Identification Numbers (RINs). At the same time, 
we seek comment on a number of RFS1 provisions that may require 
adjustment under an expanded RFS2 program, including whether or not to 
require that all qualifying renewable fuels have RINs generated for it 
(discussed in Section III.B.4.b.ii), and whether a rollover cap on RINs 
other than 20 percent might be appropriate (discussed in Section IV.D). 
Furthermore, EPA is proposing several new provisions and seeking 
comment on alternatives on aspects of the program for which EISA grants 
EPA discretion and flexibility, such as the grandfathering of existing 
renewable fuel production facilities (discussed in Section III.B.3), 
the potential inclusion of electricity for credit (discussed in Section 
III.B.1.a), and how renewable fuels are categorized based on the 
results of lifecycle analyses (discussed in Section VI.B). We believe 
these and other aspects of the program are important because they will 
affect available volumes of qualifying renewable fuel, regulated 
parties' ability to comply with the program and, ultimately, the 
program's environmental and societal impacts. A full description of all 
the changes we are proposing to the RFS program to implement the 
requirements in EISA is provided in Section III, while Section IV 
includes extensive discussion of other changes to the RFS program under 
consideration.
1. Required Volumes of Renewable Fuel
    The primary purpose of the RFS program is to require a minimum 
volume of renewable fuel to be used each year in the transportation 
sector. Under RFS1, the required volume was 4.0 billion gallons in 
2006, ramping up to 7.5 billion gallons by 2012. Starting in 2013, 
EPAct required that the total volume of renewable fuel represent at 
minimum the same volume fraction of the gasoline fuel pool as it did in 
2012, and that the total volume of renewable fuel contains at least 250 
million gallons of fuel derived from cellulosic biomass.
    EISA makes three primary changes to the volume requirements of the 
RFS program. First, it substantially increases the required volumes and 
extends the timeframe over which the volumes ramp up through at least 
2022. Second, it divides the total renewable fuel requirement into four 
separate categories, each with its own volume requirement. Third, it 
requires that each of these mandated volumes of renewable fuels achieve 
certain minimum thresholds of GHG emission performance. The volume 
requirements in EISA are shown in Table II.A.1-1.

                           Table II.A.1-1--Renewable Fuel Volume Requirements for RFS2
                                                [Billion gallons]
----------------------------------------------------------------------------------------------------------------
                                                    Cellulosic    Biomass- based     Advanced          Total
                                                      biofuel         diesel          biofuel     renewable fuel
                                                    requirement     requirement     requirement     requirement
----------------------------------------------------------------------------------------------------------------
2009............................................             n/a             0.5             0.6            11.1
2010............................................             0.1            0.65            0.95           12.95
2011............................................            0.25            0.80            1.35           13.95
2012............................................             0.5             1.0             2.0            15.2
2013............................................             1.0             \a\            2.75           16.55
2014............................................            1.75             \a\            3.75           18.15
2015............................................             3.0             \a\             5.5            20.5
2016............................................            4.25             \a\            7.25           22.25
2017............................................             5.5             \a\             9.0            24.0
2018............................................             7.0             \a\            11.0            26.0
2019............................................             8.5             \a\            13.0            28.0
2020............................................            10.5             \a\            15.0            30.0
2021............................................            13.5             \a\            18.0            33.0
2022............................................            16.0             \a\            21.0            36.0
2023+...........................................             \b\             \b\             \b\             \b\
----------------------------------------------------------------------------------------------------------------
\a\ To be determined by EPA through a future rulemaking, but no less than 1.0 billion gallons.
\b\ To be determined by EPA through a future rulemaking.

As shown in the table, the volume requirements are not exclusive, and 
generally result in nested requirements. Any renewable fuel that meets 
the requirement for cellulosic biofuel or biomass-based diesel is also 
valid for meeting the advanced biofuel requirement. Likewise, any 
renewable fuel that meets the requirement for advanced biofuel is also 
valid for meeting the total renewable fuel requirement. See Section 
VI.E for further discussion of which specific types of fuel meet the 
requirements for one of the four categories shown in Table II.A.1-1.
    We are co-proposing and taking comment on two options for how to 
treat the volumes of different renewable fuels for purposes of 
complying with the volume mandates of RFS2: As either ethanol-
equivalent gallons, based on energy content, as finalized in the RFS1 
program, or as actual volume in gallons. Consideration of the actual 
volume option would recognize that EISA now guarantees a market for 
specific categories of renewable fuel and assigns a GHG requirement to 
each category in the form of minimum GHG thresholds that each must 
meet. The approach taken in RFS1 would continue to assign value, in 
terms of gallons, to all renewable fuels based on their energy value in 
comparison with ethanol. Further discussion of the rationale and 
implications of these two approaches can be found in Section III.D.1.
    The statutorily-prescribed phase-in period ends in 2012 for 
biomass-based diesel and in 2022 for cellulosic biofuel, advanced 
biofuel, and total renewable fuel. Beyond these years, EISA requires 
EPA to determine the applicable

[[Page 24911]]

volumes based on a review of the implementation of the program up to 
that time, and an analysis of a wide variety of factors such as the 
impact of the production of renewable fuels on the environment, energy 
security, infrastructure, costs, and other factors. For these future 
standards, EPA must promulgate rules establishing the applicable 
volumes no later than 14 months before the first year for which such 
applicable volumes would apply. For biomass-based diesel, this would 
mean that final rules would need to be issued by October 31, 2011 for 
application starting on January 1, 2013. In today's proposed 
rulemaking, we are not suggesting any specific volume requirements for 
biomass-based diesel for 2013 and beyond that would be appropriate 
under the statutory criteria that we must consider. Likewise, we are 
not suggesting any specific volume requirements for the other three 
renewable fuel categories for 2023 and beyond. However, the statute 
requires that the biomass-based diesel volume in 2013 and beyond must 
be no less than 1.0 billion gallons, and that advanced biofuels in 2023 
and beyond must represent at a minimum the same percentage of total 
renewable fuel as it does in 2022.
2. Changes in How Renewable Fuel Is Defined
    Under the existing Renewable Fuel Standard, (RFS1) renewable fuel 
is defined generally as ``any motor vehicle fuel that is used to 
replace or reduce the quantity of fossil fuel present in a fuel mixture 
used to fuel a motor vehicle''. The RFS1 definition includes motor 
vehicle fuels produced from biomass material such as grain, starch, 
fats, greases, oils and biogas.
    The definitions of renewable fuels under today's proposed rule 
(RFS2) are based on the new statutory definitions in EISA. Like the 
existing rules, the definitions in RFS2 include a general definition of 
renewable fuel, but unlike RFS1, we are including a separate definition 
of ``Renewable Biomass'' which identifies the feedstocks from which 
renewable fuels may be made.
    Another difference in the definitions of renewable fuel is that 
RFS2 contains three subcategories of renewable fuels: (1) Advanced 
Biofuel, (2) Cellulosic Biofuel and (3) Biomass-Based Diesel.
    ``Advanced Biofuel'' is a renewable fuel other than ethanol derived 
from corn starch and which must achieve a lifecycle GHG emission 
displacement of 50%, compared to the gasoline or diesel fuel it 
displaces.
    Cellulosic biofuel is any renewable fuel, not necessarily ethanol, 
derived from any cellulose, hemicellulose, or lignin each of which must 
originate from renewable biomass. It must achieve a lifecycle GHG 
emission displacement of 60%, compared to the gasoline or diesel fuel 
it displaces for it to qualify as cellulosic biofuel.
    The RFS1 definition provided that ethanol made at any facility--
regardless of whether cellulosic feedstock is used or not--may be 
defined as cellulosic if at such facility ``animal wastes or other 
waste materials are digested or otherwise used to displace 90% or more 
of the fossil fuel normally used in the production of ethanol.'' This 
provision was not included in EISA, and therefore does not appear in 
the definitions pertaining to cellulosic biofuel in today's proposed 
rule.
    The statutory definition of ``renewable biomass'' in EISA does not 
include a reference to municipal solid waste (MSW) as did the 
definition of ``cellulosic biomass ethanol'' in EPAct, but instead 
includes ``separated yard waste and food waste. EPA's proposed 
definition of renewable biomass in today's proposed rule includes the 
language present in EISA. As discussed in Section III.B.1.a, we invite 
comment on whether this definition should be interpreted as including 
or excluding MSW containing yard and/or food waste from the definition 
of renewable biomass. EPA intends to resolve this matter in the final 
rule, and EPA solicits comment on the approach that it should take.
    Under today's proposed rule ``Biomass-based diesel'' includes 
biodiesel (mono-alkyl esters), non-ester renewable diesel and any other 
diesel fuel made from renewable biomass, as long as they are not ``co-
processed'' with petroleum. EISA requires that such fuel achieve a 
lifecycle GHG emission displacement of 50%, compared to the gasoline or 
diesel fuel it displaces. As discussed in Section III.B.1.d, we are 
proposing that co-processing is considered to occur only if both 
petroleum and biomass feedstock are processed in the same unit 
simultaneously. Thus, if serial batch processing in which 100% 
vegetable oil is processed one day/week/month and 100% petroleum the 
next day/week/month occurs, the fuel derived from renewable biomass 
would be assigned RINs with a D code identifying it as biomass-based 
diesel. The resulting products could be blended together, but only the 
volume produced from renewable biomass would count as biomass-based 
diesel.
    For other renewable fuels, EISA makes a distinction between fuel 
from new and existing facilities. Only renewable fuel from new 
facilities is required to achieve a lifecycle GHG emission displacement 
of 20%. As discussed in Section III.B.3, this requirement applies only 
to renewable fuel that is produced from certain facilities which 
commenced construction after December 19, 2007.
    EISA defines ``additional renewable fuel'' as fuel produced from 
renewable biomass that is used to replace or reduce fossil fuels used 
in home heating oil or jet fuel. The Act provides that EPA may allow 
for the generation of RFS credits for such fuel. This represents a 
change from RFS1, where renewable fuel qualifying for credits was 
limited to fuel used in motor vehicles. We propose to modify the 
regulatory requirements to allow RINs assigned to renewable fuel 
blended into heating oil or jet fuel to be valid for compliance 
purposes. The fuel would still have to meet all the other criteria to 
qualify as a renewable fuel, including being made from renewable 
biomass. For example, RINs generated for advanced biofuel or biomass-
based diesel that could be used in automobiles would still be valid, 
and would not need to be retired, if the fuel producer instead sells 
the fuels for use in heating oil or jet fuel.
    ``Renewable biomass'' is defined in EISA to include a number of 
feedstock types, such as planted crops and crop residue, planted trees 
and tree residue, animal waste, algae, and yard and food waste. 
However, the EISA definition limits many of these feedstocks according 
to the management practices for the land from which they are derived. 
For example, planted crops and crop residue must be harvested from 
agricultural land cleared or cultivated at any time prior to December 
19, 2007, that is actively managed or fallow, and non-forested. 
Therefore, planted crops and crop residue derived from land that does 
not meet this definition cannot be used to produce renewable fuel for 
credit under RFS2.
    Under today's proposed rule, we describe several options for 
ensuring that feedstocks used to produce renewable fuel for which 
credits are generated under RFS2 meet the definition of renewable 
biomass. Our proposed approach places overall responsibility for 
verifying a feedstock's source on the party who generates a RIN for the 
renewable fuel produced from the feedstock. We also present options for 
how a party could or should verify his or her feedstock, and we seek 
comment on these options. A full discussion of the definition and 
implementation options for ``renewable biomass'' is presented in 
Section III.B.4.

[[Page 24912]]

3. Analysis of Lifecycle Greenhouse Gas Emissions and Thresholds for 
Renewable Fuels
    As shown in Table II.A.3-1, EISA requires that a renewable fuel 
must meet minimum thresholds for their reduction in lifecycle 
greenhouse gas emissions: A 20% reduction in lifecycle GHG emissions 
for any renewable fuel produced at new facilities; a 50% reduction in 
order to be classified as biomass-based diesel or advanced biofuel; and 
a 60% reduction in order to be classified as cellulosic biofuel. The 
lifecycle GHG emissions means the aggregate quantity of GHG emissions 
related to the full fuel cycle, including all stages of fuel and 
feedstock production and distribution, from feedstock generation or 
extraction through distribution and delivery and use of the finished 
fuel. As mandated by EISA, it includes direct emissions and significant 
indirect emissions such as significant emissions from land use changes. 
EPA believes that compliance with the EISA mandate--determining the 
aggregate GHG emissions related to the full fuel lifecycle, including 
both direct emissions and significant indirect emissions such as land 
use changes--make it necessary to assess those direct and indirect 
impacts that occur not just within the United States but also those 
that occur in other countries. This applies to determining the 
lifecycle emissions for petroleum-based fuels to determine the 
baseline, as well as the lifecycle emissions for biofuels. For 
biofuels, this includes evaluating significant emissions from indirect 
land use changes that occur in other countries as a result of the 
increased domestic production or importation of biofuels into the U.S. 
As detailed in Section VI, we have included the GHG emission impacts of 
international land use changes including the indirect land use changes 
that result from domestic production of biofuel feedstocks. We 
recognize the significance of including international land use emission 
impacts and, in our analysis presentation in Section VI, have been 
transparent in breaking out the various sources of GHG emissions so 
that the reader can readily see the impact of including international 
land use impacts.

       Table II.A.3-1--Lifecycle GHG Thresholds Specified in EISA
                    [Percent reduction from baseline]
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Renewable fuel \a\.............................................       20
Advanced biofuel...............................................       50
Biomass-based diesel...........................................       50
Cellulosic biofuel.............................................       60
------------------------------------------------------------------------
\a\ The 20% criterion generally applies to renewable fuel from new
  facilities that commenced construction after December 19, 2007.

    The lifecycle GHG emissions of the renewable fuel are compared to 
the lifecycle GHG emissions for gasoline or diesel (whichever is being 
replaced by the renewable fuel) sold or distributed as transportation 
fuel in 2005. EISA provides some limited flexibility for EPA to adjust 
these GHG percentage thresholds downward by up to 10 percent under 
certain circumstances. As discussed in Section VI.D, we are proposing 
that the GHG threshold for advanced biofuels be adjusted to 44% or 
potentially as low as 40% depending on the results from the analyses 
that will be conducted for the final rule. This adjustment would allow 
ethanol produced from sugarcane to count as advanced biofuel and would 
help ensure that the volume mandate for advanced biofuel could be met.
    The regulatory purpose of the lifecycle greenhouse gas emissions 
analysis is to determine whether renewable fuels meet the GHG 
thresholds for the different categories of renewable fuel. As described 
in detail in Section VI, EPA has analyzed the lifecycle GHG impacts of 
the range of biofuels currently expected to contribute significantly to 
meeting the volume mandates of EISA through 2022. In these analyses we 
have used the best science available. Our analysis relies on peer 
reviewed models and the best estimate of important trends in 
agricultural practices and fuel production technologies as these may 
impact our prediction of individual biofuel GHG performance through 
2022. We have identified and highlighted assumptions and model inputs 
that particularly influence our assessment and seek comment on these 
assumptions, the models we have used and our overall methodology so as 
to assure the most robust assessment of lifecycle GHG performance for 
the final rule.
    In addition to the many technical issues addressed in this 
proposal, Section VI discusses the emissions decreases and increases 
associated with the different parts of the lifecycle emissions of 
various biofuels and the timeframes in which these emissions changes 
occur. The need to determine a single lifecycle value that best 
represents this combination of emissions increases and decreases 
occurring over time led EPA to consider various alternative ways to 
analyze the timeframe of emissions changes related to biofuel 
production and use as well as options for adjusting or discounting 
these emissions to determine their net present value. Section VI 
highlights two options. One option assumes a 30 year time period for 
assessing future GHG emissions impacts of the anticipated increase in 
biofuel production to meet the mandates of EISA, both emissions 
increases and decreases, and values all these emission impacts the same 
regardless of when they occur during that time period (i.e., no 
discounting). The second option assesses emissions impacts over a 100 
year time period but then discounts future emissions 2% annually to 
arrive at an estimate of a net present value of those emissions. 
Several other variations of time period and discount rate are also 
discussed. The analytical time horizon and the choice whether to 
discount GHG emissions and, if so, at what appropriate rate can have a 
significant impact on the final assessment of the lifecycle GHG 
emissions impacts of individual biofuels as well as the overall GHG 
impacts of these EISA provisions and this rule.
    We believe that our lifecycle analysis is based on the best 
available science and recognize that in some aspects it represents a 
cutting edge approach to addressing lifecycle GHG emissions. Because of 
the varying degrees of uncertainty in the different aspects of our 
analysis, we conducted a number of sensitivity analyses which focus on 
key parameters and demonstrate how our assessments might change under 
alternative assumptions. By focusing attention on these key parameters, 
the comments we receive as well as additional investigation and 
analysis by EPA will allow narrowing of uncertainty concerns for the 
final rule. In addition to this sensitivity analysis approach, we will 
also explore options for more formal uncertainty analyses for the final 
rule to the extent possible.
    Because lifecycle analysis is a new part of the RFS program, in 
addition to the formal comment period on the proposed rule, EPA is 
making multiple efforts to solicit public and expert feedback on our 
proposed approach. EPA plans to hold a public workshop focused 
specifically on lifecycle analysis during the comment period to assure 
full understanding of the analyses conducted, the issues addressed and 
the options that are discussed. We expect that this workshop will help 
ensure that we receive submission of the most

[[Page 24913]]

thoughtful and useful comments to this proposal and that the best 
methodology and assumptions are used for calculating GHG emissions 
impacts of fuels for the final rule. Additionally, between this 
proposal and the final rule, we will conduct peer reviews of key 
components of our analysis. As explained in more detail in Section VI, 
EPA is specifically seeking peer review of: Our use of satellite data 
to project future types of land use changes; the land conversion GHG 
emissions factors estimates we have used for different types of land 
use; our estimates of GHG emissions from foreign crop production; 
methods to account for the variable timing of GHG emissions; and how 
the several models we have relied upon are used together to provide 
overall lifecycle GHG estimates.
    Some renewable fuel is not required to meet the 20% GHG threshold. 
Section 211(o)(2)(A) provides that only renewable fuel produced from 
new facilities which commenced construction after December 19, 2007 
must meet the 20% threshold. Facilities that commenced construction on 
or before December 19, 2007 are exempt or ``grandfathered'' from the 
20% threshold requirement. In addition, section 210(a) of EISA provides 
a further exemption from the 20% threshold requirement for ethanol 
plants that commenced construction in 2008 or 2009 and are fired with 
natural gas, biomass, or any combination thereof. The renewable fuel 
from such facilities is deemed to be in compliance with the 20% 
threshold, and would thus also be ``grandfathered.''
    We are proposing and taking comment on one approach to the 
grandfathering provisions in today's rule, and seeking comment on five 
additional options. The proposed approach would provide an indefinite 
time period for grandfathering status but with restrictions to the 
baseline volume of renewable fuel that is grandfathered. The 
alternative options are (1) Expiration of exemption for grandfathered 
status when facilities undergo sufficient changes to be considered 
``reconstructed''; (2) Expiration of exemption 15 years after EISA 
enactment, industry-wide; (3) Expiration of exemption 15 years after 
EISA enactment with limitation of exemption to baseline volume; (4) 
``Significant'' production components are treated as facilities and 
grandfathered or deemed compliant status ends when they are replaced; 
and (5) Indefinite exemption and no limitations placed on baseline 
volumes. Our proposal and the alternative options are discussed in 
further detail in Section III.B.3.c.
    While renewable fuels would be required to meet the GHG thresholds 
shown in Table II.A.3-1 in order to be valid for compliance purposes 
under the RFS2 program, we are not proposing that an individual 
facility-specific lifecycle GHG emissions value would have to be 
determined in order to show that the biofuel produced or imported at an 
individual facility complies with the threshold. Instead, EPA has 
determined lifecycle GHG values for specific combinations of fuel type, 
feedstock, and production process, using average values for various 
lifecycle model inputs. As a result of these assessments, we propose to 
assign each combination of fuel type, feedstock, and production process 
to one of the four renewable fuel categories specified in EISA or, 
alternatively, make a determination that the biofuel combination has 
been disqualified from generating RINs (except as may be allowed for 
grandfathered renewable fuel) due to a failure to meet the minimum 20% 
GHG threshold. Section VI.E discusses our proposed assignments. We are 
also proposing a mechanism to allow biofuels whose lifecycle GHG 
emissions have not been assessed to participate in the RFS program 
under certain limited conditions. These conditions are described in 
Section III.D.5.
4. Coverage Expanded to Transportation Fuel, Including Diesel and 
Nonroad Fuels
    EPAct only mandated the blending of renewable fuels into gasoline, 
though it gave credit for renewable fuels blended into diesel fuel. 
EISA expanded the program to generally cover transportation fuel, which 
is defined as fuel for use in motor vehicles, motor vehicle engines, 
nonroad vehicles, or nonroad engines. This includes diesel fuel 
intended for use in highway vehicles and engines, and nonroad, 
locomotive, and marine engines and vessels, as well as gaseous or other 
fuels used in these vehicles, engines, or vessels. EISA also specifies 
that ``transportation fuels'' do not include fuels for use in ocean-
going vessels.
    EPA is required to ensure that transportation fuel contains at 
least the specified volumes of renewable fuel. Under EISA, renewable 
fuel now includes fuel that is used to displace fossil fuel present in 
transportation fuel, and as in RFS1, EPA is required to determine the 
refiners, blenders, and importers of transportation fuel that are 
subject to the renewable volume obligation. As discussed in Section 
III.F, while we are seeking comment on alternatives, EPA is proposing 
consistent with RFS1 that these provisions could best be met by 
requiring that the renewable volume obligation apply to refiners, 
blenders, and importers of motor vehicle or nonroad gasoline or diesel 
(with limited flexibilities for small refineries and small refiners), 
and that their percentage obligation would apply to the amount of 
gasoline or diesel they produce for such use. We propose to use the 
current definition of motor vehicle, nonroad, locomotive, and marine 
diesel fuel (MVNRLM)--as defined at Sec.  80.2(qqq)--to determine the 
obligated volumes of non-gasoline transportation fuel for this rule.
    We request comment on these aspects of our proposed program.
5. Effective Date for New Requirements
    Under CAA section 211(o) as modified by EISA, EPA is required to 
revise the RFS1 regulations within one year of enactment, or December 
19, 2008. Promulgation by this date would have been consistent with the 
revised volume requirements shown in Table II.A.1-1 that begin in 2009 
for certain categories of renewable fuel. However, due to the addition 
of complex lifecycle assessments to the determination of eligibility of 
renewable fuels, the extensive analysis of impacts that we are 
conducting for the higher renewable fuel volumes, the various complex 
changes to the regulatory program that require close collaboration with 
stakeholders, and various statutory limitations such as the Small 
Business Regulatory Enforcement Flexibility Act (SBREFA) and a 60 day 
Congressional review period for all significant actions, we were not 
able to promulgate final RFS2 program requirements by December 19, 
2008. As a result, we are proposing that the RFS2 regulatory program go 
into effect on January 1, 2010.
    In order to successfully implement the RFS2 program, parties that 
generate RINs, own and/or transfer them, or use them for compliance 
purposes will need to re-register under the RFS2 provisions and modify 
their information technology (IT) systems to accommodate the changes we 
are proposing today. As described more fully in Section III, these 
changes would include redefining the D code within the RIN, adding a 
process for verifying that feedstocks meet the renewable biomass 
definition, and calculating compliance with four standards instead of 
one. Regulated parties will need to establish new contractual 
relationships to cover the different types of renewable fuel required 
under RFS2. Parties that

[[Page 24914]]

produce MVNRLM diesel but not gasoline will be newly obligated parties 
and may be establishing IT systems for the RFS program for the first 
time. For RFS1, regulated parties had four months between promulgation 
of the final rulemaking on May 1, 2007 and the start of the program on 
September 1, 2007. However, this was for a new program that had not 
existed before. For the RFS2 program, most regulated parties will 
already be familiar with the general requirements for RIN generation, 
transfer, and use, and the attendant recordkeeping and reporting 
requirements. We believe that with proper attention to the 
implementation requirements by regulated parties, the RFS2 program can 
be implemented on January 1, 2010 following release of the final rule.
    Although we are proposing that the RFS2 regulatory program begin on 
January 1, 2010, we seek comment on whether a start date later than 
January 1, 2010 would be necessary. Alternative effective dates for the 
RFS2 program include January 1, 2011 and a date after January 1, 2010 
but before January 1, 2011. We are requesting comment on all issues 
related to such an alternative effective date, including the need for 
such a delayed start, treatment of diesel producers and importers, 
whether the standards for advanced biofuel, cellulosic biofuel and 
biomass-based diesel should apply to the entire 2010 production or just 
the production that would occur after the RFS2 effective date, and the 
extent to which RFS1 RINs should be valid to show compliance with RFS2 
standards. Further discussion of alternative effective dates for RFS2 
can be found in Section III.E.1.d.
6. Treatment of Required Volumes Preceding the RFS2 Effective Date
    We are proposing that the RFS2 regulatory program begin on January 
1, 2010. Under CAA section 211(o), the requirements for refiners, 
blenders, and importers (called ``obligated parties'') as well as the 
requirements for producers of renewable fuel and others, stem from the 
regulatory provisions adopted by EPA. In effect while EPAct and EISA 
both call for EPA to issue regulations that achieve certain results, 
the various regulated parties are not subject to these requirements 
until EPA issues the regulations establishing their obligations. The 
changes brought about by EISA, such as the 4 separate standards, the 
lifecycle GHG thresholds, changes to obligated parties, and the revised 
definition of renewable biomass do not become effective until today's 
proposal is finalized. Rather, the current RFS1 regulations continue to 
apply until EPA amends them to implement EISA, and any delay in 
issuance of the RFS2 regulations means that parties would continue to 
be subject to the RFS1 regulations until the RFS2 regulations were in 
effect. Therefore, regulated parties would continue to be subject to 
the existing regulations at 40 CFR Part 80 Subpart K through December 
31, 2009, or later if the effective date of the RFS2 program were later 
than January 1, 2010.
    Under the RFS1 regulations the annual percentage standards that are 
applicable to obligated parties are determined by a formula set forth 
in the regulations. The formula uses gasoline volume projections from 
the Energy Information Administration (EIA) and the required volume of 
renewable fuel provided in Clean Air Act section 211(o)(2)(B). Since 
EISA modified the required volumes in this section of the Clean Air 
Act, EPA believes that the new statutory volumes can be used under the 
RFS1 regulations in generating the standards for 2009. Therefore, in 
November 2008 we used the new total renewable fuel volume of 11.1 
billion gallons as the basis for the 2009 standard, and not the 6.1 
billion gallons that was required by EPAct.\3\
---------------------------------------------------------------------------

    \3\ 73 FR 70643, November 21, 2008.
---------------------------------------------------------------------------

    While this approach will ensure that the total renewable fuel 
volume of 11.1 billion gallons required by EISA for 2009 will be used, 
the RFS1 regulatory structure does not provide a mechanism for 
implementing the 0.5 billion gallon requirement for biomass-based 
diesel nor the 0.6 billion gallon requirement for advanced biofuel. As 
described in more detail in Section III.E.2, we are proposing to 
address this issue by increasing the 2010 biomass-based diesel 
requirement by 0.5 billion gallons and allowing 2009 biodiesel and 
renewable diesel RINs to be used to meet this combined 2009/2010 
requirement. Doing so would also allow most of the 2009 advanced 
biofuel requirement to be met. We believe this would provide a similar 
incentive for biomass-based diesel use in 2009 as would have occurred 
had we been able to implement this standard for 2009. We propose that 
this requirement would apply to all obligated parties under RFS2, 
including producers and importers of diesel fuel.
    As noted above, EPA is proposing a start date for the RFS2 program 
of January 1, 2010, and is also seeking comment on alternative start 
dates of sometime during 2010 or January 1, 2011. If the start date is 
other than January 1, 2010, EPA would need to determine what renewable 
fuel volumes to require in the interim between January 1, 2010 and the 
start of the RFS2 program. While we could apply the same approach, 
described above, that we have used for 2009, doing so could mean that 
2009 biodiesel RINs would be valid for compliance purposes in 2011, 
which would run counter to the statutory valid life of two years. 
Nevertheless, we request comment on whether this potential approach or 
another approach is warranted based on the differing volumes and types 
of renewable fuel specified for use in EISA for 2010.
7. Waivers and Credits for Cellulosic Biofuel
    Section 202(e) of EISA provides that for any calendar year in which 
the projected volume of cellulosic biofuel production is less than the 
minimum applicable volume required by the statute, EPA will waive a 
portion of the cellulosic biofuel standard by using the projected 
volume as the basis for setting the applicable standard. In this event, 
EISA also allows but does not require EPA to reduce the required volume 
of advanced biofuel and total renewable fuel. The process of projecting 
the volume of cellulosic biofuel that may be produced in the next year, 
and the associated process of determining whether and to what degree 
the advanced biofuel and total renewable fuel requirements should be 
lowered, will involve considerations that extend beyond the simple 
calculation based on gasoline demand that was used to set the annual 
standards under RFS1. As a result, we believe that this process should 
be subject to a notice-and-comment rulemaking process. Moreover, since 
we must make these determinations every year for application to the 
following year, we expect to conduct these rulemakings every year.
    In determining whether the advanced biofuel and/or total renewable 
fuel volume requirements should also be adjusted downward in the event 
that projected volumes of cellulosic biofuel fall short of the 
statutorily required volumes, we believe it would be appropriate to 
allow excess advanced biofuels to make up some or all of the shortfall 
in cellulosic biofuel. For instance, if we determined that sufficient 
biomass-based diesel was available, we could decide that the required 
volume of advanced biofuel need not be lowered, or that it should be 
lowered to a smaller degree than the required cellulosic biofuel 
volume. We would then lower the total renewable fuel volume to the same 
degree that we

[[Page 24915]]

would lower the advanced biofuel volume. We do not believe it would be 
appropriate to lower the advanced biofuel standard but not the total 
renewable standard, as this would allow conventional biofuels to 
effectively be used to meet the standards Congress specifically set for 
cellulosic and advanced biofuels.
    If EPA reduces the required volume of cellulosic biofuel, EPA must 
offer a number of credits no greater than the reduced cellulosic 
biofuel standard. EISA dictates the cost of these credits and ties them 
to inflation. The Act also dictates that we must promulgate regulations 
on the use of these credits and offers guidance on how these credits 
may be offered and used. We propose that their uses will be very 
limited. The credits would not be allowed to be traded or banked for 
future use, but would be allowed to meet the cellulosic biofuel 
standard, advanced biofuel standard and total renewable fuel standard. 
Further discussion of the implementation of these provisions can be 
found in Section III.I.
8. Proposed Standards for 2010
    Once the RFS2 program is implemented, we expect to conduct a 
notice-and-comment rulemaking process each year in order to determine 
the appropriate standards applicable in the following year. We 
therefore intend to issue an NPRM in the spring and a final rule by 
November 30 of each year as required by statute.
    However, for the 2010 compliance year, today's action provides a 
means for seeking comment on the applicable standards. Therefore, 
rather than issuing a separate NPRM for the 2010 standard, we are 
proposing the 2010 standards in today's notice. We will consider 
comments received during the comment period associated with today's 
NPRM, and we expect to issue a Federal Register notice by November 30, 
2009 setting the applicable standards for 2010.
    We propose that the RFS2 program be effective on January 1, 2010. 
Therefore, all EISA volume mandates for 2010 would be implemented in 
that year, unless EPA exercised its authority to waive one or more of 
the standards. Based on information from the industry, we believe that 
there are sufficient plans underway to build plants capable of 
producing 0.1 billion gallons of cellulosic biofuel in 2010, the 
minimum volume of cellulosic biofuel required by EISA for 2010. 
However, we recognize that cellulosic biofuel is at the very earliest 
stages of commercialization and current economic concerns could have 
significant impacts on these near term plans. Therefore, while based on 
industry plans available to EPA, we are not proposing that any portion 
of the cellulosic biofuel requirement for 2010 be waived, we are 
seeking additional and updated information that would be available 
prior to November 30, 2009 which could result in a change in this 
conclusion. Similarly, we are not aware of the need to waive any other 
volume mandates for 2010. Therefore, we are proposing that the volumes 
shown in Table II.A.1-1 for all four renewable fuel categories be used 
as the basis for the applicable standards for 2010. The proposed 
standards are shown in Table II.A.8-1, each representing the fraction 
of a refiner's or importer's gasoline and diesel volume which must be 
renewable fuel.

               Table II.A.8-1--Proposed Standards for 2010
                                [Percent]
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Cellulosic biofuel.............................................     0.06
Biomass-based diesel...........................................     0.71
Advanced biofuel...............................................     0.59
Renewable fuel.................................................     8.01
------------------------------------------------------------------------

    Note that the proposed 2010 standards shown in Table II.A.8-1 were 
based on currently available projections of 2010 gasoline and diesel 
volumes. The final standards will be calculated on the basis of 
gasoline and diesel volume projections from the Energy Information 
Administration's (EIA) Short-Term Energy Outlook and published by 
November 30, 2009. Additional discussion of our proposed 2010 standards 
can be found in Section III.E.1.b.
    Note also that the proposed standards assume an effective date of 
January 1, 2010 for RFS2. We are taking comment on alternative 
effective dates for RFS2, including January 1, 2011 and a date after 
January 1, 2010 but before January 1, 2011. Such alternative effective 
dates would raise issues with regard to the calculation and application 
of the standards for total renewable fuel and the other standards 
required under EISA, as well as the generation and application of RINs 
under RFS1 and RFS2. As described more fully in Section III.E.1.d, we 
request comment on the issues associated with alternative effective 
dates for RFS2.

B. Impacts of Increasing Volume Requirements in the RFS2 Program

    The displacement of gasoline and diesel with renewable fuels has a 
wide range of environmental and economic impacts. As we describe below, 
we have assessed many of these impacts for the RFS2 proposal and we 
will have more complete assessments, including a cost-benefit 
comparison, for the final rule. These assessments provide important 
information to the wider public policy considerations of renewable 
fuels, climate change, and national energy security. They are also an 
important component of all significant rulemakings.
    However, because the volumes of renewable fuel were specified by 
statute, they would not be based on or revised by our analysis of 
impacts. In addition, because we have very limited discretion to pursue 
regulatory alternatives, the proposal does not include a systematic 
alternatives analysis. We have investigated regulatory alternatives in 
some areas to the degree that EISA provides discretion.
    As one point of reference to assess the impacts of the volume 
requirements for the RFS2 program, we used projections for renewable 
fuel use in 2022 that EIA issued through their 2007 Annual Energy 
Outlook (AEO), and for transportation fuel consumption through their 
2008 AEO. This reference case, referred to as the ``AEO Reference 
Case,'' represents a projection of the demand for renewable fuels prior 
to enactment of EISA while still reflecting the new Corporate Average 
Fuel Economy (CAFE) requirements in EISA, and the 2008 AEO projections 
for the future price of crude oil ($53 to $92 per barrel). Further 
discussion of the Reference Case can be found in Section V.A.1. Other 
points of reference include the renewable fuel volumes mandated by 
EPAct for the RFS1 program, renewable fuel use prior to implementation 
of the RFS1 program, and the full impacts of renewable fuel use 
compared to a petroleum-only economy.
    Given the short time provided by Congress to conduct a rulemaking, 
many of our analyses were done in parallel for this proposal. As a 
result, some analyses were conducted without the benefit of waiting for 
the conclusion of another analysis that could prove influential. Thus, 
for example, impacts on food prices assume that soy-based biodiesel and 
sugarcane ethanol will qualify as advanced fuels under the proposed 
RFS2 program, even though the analyses conducted for this proposal 
might preclude such eligibility. We have highlighted such 
inconsistencies in results and assumptions throughout the proposal. 
Additionally, since we have identified many issues and analytical 
options in our assessment of which biofuel pathways would comply with 
the GHG thresholds, the assessment we

[[Page 24916]]

conducted for this proposal may not reflect the final rule in all 
cases. We will be addressing these issues of analytical consistency 
between analyses more fully in the final rule.
    In a similar fashion, while we recognize uncertainty in our 
assessment of impacts of the proposed RFS2 program, we do not present a 
formal, comprehensive analysis of uncertainty. For this proposal, many 
of the analyses are without precedent, and as a result we have 
identified the more uncertain aspects of these analyses and have worked 
to assess their potential impact on the results through sensitivity 
analyses. We intend to continue these assessments for the final rule, 
and expect that comments on this proposal will allow us to reduce our 
uncertainty in a number of areas. In addition to this sensitivity 
analysis approach, we will also explore options for more formal 
uncertainty analyses for the final rule to the extent possible.
1. Greenhouse Gases and Fossil Fuel Consumption
    Our analyses of GHG impacts consider the full useful life 
assessment of the production of biofuels compared to the petroleum-
based fuels they would replace. The analysis compared the AEO reference 
case transportation fuel pool in 2022 without the EISA mandates with 
the same fuel pool in 2022, but assuming the greater volumes of biofuel 
as mandated by EISA replace an energy equivalent amount of petroleum-
based fuel. The incremental volumes of each biofuel type were then 
evaluated to determine their average impact on GHG emissions compared 
to the 2005 baseline petroleum fuel they would be displacing. These 
average GHG emission reduction results can then be compared to the 
threshold performance levels for each fuel type.
    As a result of the transition to greater renewable fuel use, some 
petroleum-based gasoline and diesel will be directly replaced by 
renewable fuels. Therefore, consumption of petroleum-based fuels will 
be lower than it would be if no renewable fuels were used in 
transportation vehicles. However, a true measure of the impact of 
greater use of renewable fuels on petroleum use, and indeed on the use 
of all fossil fuels, accounts not only for the direct use and 
combustion of the finished fuel in a vehicle or engine, but also 
includes the petroleum use associated with production and 
transportation of that fuel. For instance, fossil fuels are used in 
producing and transporting renewable feedstocks such as plants or 
animal byproducts, in converting the renewable feedstocks into 
renewable fuel, and in transporting and blending the renewable fuels 
for consumption as motor vehicle fuel. Likewise, fossil fuels are used 
in the production and transportation of petroleum and its finished 
products. In order to estimate the true impacts of increases in 
renewable fuel use on fossil fuel use, we must take these steps into 
account. Such analyses are termed lifecycle analyses.
    The definition of lifecycle greenhouse gas emissions in EISA 
requires the Agency to look broadly at lifecycle analyses and to 
develop a methodology that accounts for the significant secondary or 
indirect impacts of expanded biofuels use. These indirect effects 
include both the domestic and international impact of land use change 
from increased biofuel feedstock production and the secondary 
agricultural sector GHG impacts from increased biofuel feedstock 
production (e.g., changes in livestock emissions due to changes in 
agricultural commodity prices). Today no single model can capture all 
of the complex interactions required to conduct a complete lifecycle 
assessment as required by Congress. As a result, the methodology EPA 
has currently evaluated uses a number of models and tools to provide a 
comprehensive estimate of GHG emissions. We have used a combination of 
peer reviewed models including Argonne National Laboratory's GREET 
model, Texas A&M's Forestry and Agricultural Sector Optimization Model 
(FASOM) and Iowa State University's Food and Agricultural Policy 
Research Institute's (FAPRI) international agricultural models as well 
as the Winrock International database to estimate lifecycle GHG 
emissions estimates. These models are described in more detail in 
Section VI and have been used in combination to provide the lifecycle 
GHG estimates presented in this proposal. However, we recognize other 
models and sources of information can also be used and these are also 
discussed in Section VI.
    Based on the combined use of these models we have estimated the 
lifecycle GHG emissions for a number of pathways for producing the 
increased volumes of renewable fuels as mandated by EISA. Section VI of 
this proposal outlines the approach taken and describes the key 
assumptions and parameters used in this analysis. In addition, this 
section highlights the impacts of varying these key inputs on the 
overall results.
    We estimate the greater volumes of biofuel mandated by RFS2 will 
reduce lifecycle GHG emissions from transportation by approximately 6.8 
billion tons of CO2 equivalent emissions when accounting for 
all the emissions changes over 100 years and then discounting this 
emission stream by 2% per year. This is equivalent to an average 
annualized emission rate of 160 million metric tons of CO2-
eq. emissions per year over the entire 100 year modeling time frame if 
that average annualized emission rate is also discounted at 2% per 
year. Determining lifecycle GHG emissions values for renewable fuels 
using a 0% discount rate over 30 years would result in an estimated 
total reduction of 4.5 billion tons of CO2-eq. over the 30 
year period or an average annualized emission rate reduction of 150 
million metric tons of CO2-eq. GHG emissions per year. (See 
Section VI.F of this preamble for additional information on how these 
emission reductions were calculated).
    Our analysis of the petroleum consumption impacts took a similar 
lifecycle approach. For the year 2022, we estimate that the 36 billion 
gallons of renewable fuel mandated by these rules will increase 
renewable fuel usage by approximately 22 billion gallons which will 
displace about 15 billion gallons of petroleum-based gasoline and 
diesel fuel. This represents about 8% of annual oil consumed by the 
transportation sector in 2022.
2. Economic Impacts and Energy Security
    The substantially increased volumes of renewable fuel that would be 
required under RFS2 would produce a variety of different economic 
impacts. These would include changes in the cost of gasoline and 
diesel, a reduction in nationwide expenditures on petroleum imports and 
the associated increase in energy security, and increases in the prices 
of agricultural commodities such as corn and soybeans.
    The RFS program is projected to significantly impact the cost of 
gasoline and diesel, though the estimated costs vary based on the price 
of crude oil that is assumed. In our analysis we used both $92 and $53 
per barrel crude oil based on price projections made by EIA. At these 
two crude oil price points, we estimate that gasoline costs would 
increase by about 2.7 and 10.9 cents per gallon, respectively, by 2022. 
Likewise, diesel fuel costs could experience a small cost reduction of 
0.1 cents per gallon, or increase by about 1.2 cent per gallon, 
respectively. For the nation as a whole, these costs are equivalent to 
$4 and $18 billion in 2022, respectively (in 2006 dollars, and 
amortizing capital costs using a 7% before-tax rate of return). These 
costs represent the nationwide average impacts including the costs of 
producing and distributing

[[Page 24917]]

both renewable fuels and gasoline and diesel, as well as blending 
costs, but without consideration of either the tax subsidies and import 
tariff for ethanol or tax subsidies for biodiesel and renewable diesel 
fuel.
    EPA's estimates of economic impacts of fuels do not consider other 
societal benefits. For example, the displacement of petroleum-based 
fuel (largely imported) by renewable fuel (largely produced in the 
United States), should reduce our consumption of imported oil and fuel. 
We estimate that 91% of the lifecycle petroleum reductions resulting 
from the use of renewable fuel will be met through reductions in net 
petroleum imports. In Section IX of this preamble we estimate the value 
of the decrease in imported petroleum at about $12.4 billion in 2022 
due to increased volumes of renewable fuels mandated by RFS2 in 
comparison to the AEO reference case. Net U.S. expenditures on 
petroleum imports in 2022 are projected to be about $208 billion.
    Furthermore, the above estimate of reduced U.S. petroleum import 
expenditures only partly assesses the economic impacts of this 
proposal. One of the effects of increased use of renewable fuel is that 
it diversifies the energy sources used in making transportation fuel. 
To the extent that diverse sources of fuel energy reduce the U.S. 
dependence on any one source, the risks, both financial as well as 
strategic, of a potential disruption in supply of a particular energy 
source are reduced. EPA has worked with researchers at Oak Ridge 
National Laboratory (ORNL) to update a study they previously published 
that has been used or cited in several government actions impacting 
U.S. oil consumption. This updated study went through an independent, 
third-party peer review process and a final draft report of this 
updated study was developed. This peer-reviewed report is being made 
available in the docket at this time for further consideration. Using 
the updated ORNL estimate, the total energy security benefits 
associated with a reduction of U.S. imported oil is $12.38 per barrel 
of imported oil that is reduced. Based on these values, we estimate 
that the total annual energy security benefits would be $3.7 billion in 
2022 (in 2006 dollars).
    We recognize that our current energy security analysis does not 
take into account risk-shifting that might occur as the U.S. reduces 
its dependency on petroleum by increasing its use of biofuels. For 
example, our analysis did not take into account other energy security 
implications associated with biofuels, such as possible supply 
disruptions of corn-based ethanol. We will attempt to broaden our 
energy security analysis to incorporate estimates of overall motor fuel 
supply and demand flexibility and reliability for the final rule, along 
with impacts of possible agricultural sector market disruptions. A 
complete discussion of the Agency's plans for this analysis can be 
found in Section IX.B.2. of this preamble.
    While increased use of renewable fuel will reduce expenditures on 
imported oil, it will also increase expenditures on renewable fuels and 
in turn on the sources of those renewable fuels. The RFS program is 
likely to spur the increased use of renewable transportation fuels made 
principally from agricultural crops and it is expected that most of 
these crops will be produced in the U.S. As a result, it is important 
to analyze the consequences of the transition to greater renewable fuel 
use in the U.S. agricultural sector. To analyze the domestic 
agricultural sector impacts, EPA selected the Forest and Agricultural 
Sector Optimization Model (FASOM) developed by Professor Bruce McCarl 
of Texas A&M University and others over the past thirty years. FASOM is 
a dynamic, nonlinear programming model of the agriculture and forestry 
sectors of the U.S.
    In Section IX of this preamble, we estimate the change in the price 
of various agricultural products as a result of this rulemaking. By 
2022, we estimate the price of corn would increase by $0.15 per bushel 
(4.6%) above the Reference Case price of $3.19 per bushel. By 2022, 
U.S. soybean prices would increase by $0.29 per bushel (2.9%) above the 
Reference Case price of $9.97 per bushel. Due to higher commodity 
prices, FASOM estimates that U.S. food costs would increase by $10 per 
person per year by 2022, relative to the Reference Case. Total farm 
gate food costs would increase by $3.3 billion (0.2%) in 2022. As a 
result of increased renewable fuel requirements, FASOM predicts that 
net U.S. farm income would increase by $7.1 billion dollars in 2022 
(10.6%), relative to the Reference Case.
    Due to higher commodity prices, FASOM estimates that U.S. corn 
exports would drop from 2.7 billion bushels under the Reference Case to 
2.4 billion bushels (a 10% decrease) by 2022. In value terms, U.S. 
exports of corn would fall by $487 million in 2022. FASOM estimates 
that U.S. exports of soybeans would decrease from 1.03 billion bushels 
to 943 million bushels (an 8% decrease) in 2022. In value terms, U.S. 
exports of soybeans would decrease by $691 million in 2022.
    Assuming current subsidies remain in place, the Renewable Fuels 
Standard, by encouraging the use of biofuels, will result in an 
expansion of subsidy payments by the U.S. government. If this resulting 
loss of tax revenue were offset by an increase in taxes, this could 
have a distortionary impact on the economy. We intend to consider the 
impact of the expansion of biofuel subsidies associated with the RFS2 
in the context of the economy-wide modeling to be conducted for the 
final rule.
    We note that the economic analyses that support this proposal do 
not reflect all of the potentially quantifiable economic impacts. There 
are several key impacts that remain incomplete as a result of time and 
resource constraints, including the economic impact analysis (see 
Section IX) and the air quality and health impacts analysis (see 
Section II.B.3). As a result, this proposal does not combine economic 
impacts in an attempt to compare costs and benefits, in order to avoid 
presenting an incomplete and potentially misleading characterization. 
For the final rule, when the planned analyses are complete and current 
analyses updated, we will provide a consistent cost-benefit comparison.
3. Emissions, Air Quality, and Health Impacts
    Analysis of criteria and toxic emission impacts was performed 
relative to three different reference case ethanol volumes, ranging 
from 3.64 to 13.2 billion gallons per year. To assess the total impact 
of the RFS program, emissions were analyzed relative to the RFS1 rule 
base case of 3.64 billion gallons in 2004. To assess the impact of 
today's RFS2 proposal relative to the current mandated volumes, we 
analyzed impacts relative to RFS1 mandate of 7.5 billion gallons of 
renewable fuel use by 2012, which was estimated to include 6.7 billion 
gallons of ethanol.\4\ In order to assess the impact of today's 
proposal relative to the level of ethanol projected to be used in 2022 
without RFS2, the AEO2007 projection of 13.2 billion gallons of ethanol 
in 2022 was analyzed.
---------------------------------------------------------------------------

    \4\ RFS1 base and mandated ethanol levels were projected to 
remain essentially unchanged in 2022 due to the flat energy demands 
projected by EIA.
---------------------------------------------------------------------------

    We are also presenting a range of impacts meant to bracket the 
impacts of ethanol blends on light-duty vehicle emissions. Similar to 
the approach presented in the RFS1 rule, we present a ``less 
sensitive'' and ``more sensitive'' case to present a range of the 
possible

[[Page 24918]]

emission impacts of E10 on recent model year light duty gasoline 
vehicles. As detailed in Section VII.C, ``less sensitive'' does not 
apply any E10 effects to NOX or HC emissions for later model 
year vehicles, or E85 effects for any pollutant, while ``more 
sensitive'' does.
    Our projected emission impacts for the ``less sensitive'' and 
``more sensitive'' cases are shown in Table II.B.3-1 and II.B.3-2, 
showing the expected emission changes for the U.S. in 2022, and the 
percent contribution of this impact relative to the total U.S. 
inventory across all sectors. Overall we project the proposed program 
will result in significant increases in ethanol and acetaldehyde 
emissions--increasing the total U.S inventories of these pollutants by 
up to 30-40% in 2022 relative to the RFS1 mandate case. We project more 
modest but still significant increases in acrolein, NOX, 
formaldehyde and PM. We project today's action will result in decreased 
ammonia emissions (due to reductions in livestock agricultural 
activity), decreased CO emissions (driven primarily by the impacts of 
ethanol on exhaust emissions from vehicles and nonroad equipment), and 
decreased benzene emissions (due to displacement of gasoline with 
ethanol in the fuel pool). Discussion and a breakdown of these results 
by the fuel production/distribution and vehicle and equipment emissions 
are presented in Section VII.

                          Table II.B.3-1--RFS2 ``Less Sensitive'' Case Emission Impacts in 2022 Relative to Each Reference Case
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     RFS1 base                     RFS1 mandate                       AEO2007
                                                         -----------------------------------------------------------------------------------------------
                        Pollutant                          Annual short     % of total     Annual short     % of total     Annual short     % of total
                                                               tons       U.S. inventory       tons       U.S. inventory       tons       U.S. inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOX.....................................................         312,400             2.8         274,982             2.5         195,735             1.7
HC......................................................         112,401             1.0          72,362             0.6          -8,193           -0.07
PM10....................................................          50,305             1.4          37,147             1.0           9,276             0.3
PM2.5...................................................          14,321             0.4          11,452             0.3           5,376            0.16
CO......................................................      -2,344,646            -4.4      -1,669,872            -3.1        -240,943            -0.4
Benzene.................................................          -2,791            -1.7          -2,507            -1.5          -1,894            -1.1
Ethanol.................................................         210,680            36.5         169,929            29.4          83,761            14.5
1,3-Butadiene...........................................             344             2.9             255             2.1              65             0.5
Acetaldehyde............................................          12,516            33.7          10,369            27.9           5,822            15.7
Formaldehyde............................................           1,647             2.3           1,348             1.9             714             1.0
Naphthalene.............................................               5            0.03               3            0.02              -1           -0.01
Acrolein................................................             290             5.0             252             4.4             174             3.0
SO2.....................................................          28,770             0.3           4,461            0.05         -47,030            -0.5
NH3.....................................................         -27,161            -0.6         -27,161            -0.6         -27,161            -0.6
--------------------------------------------------------------------------------------------------------------------------------------------------------


                          Table II.B.3-2--RFS2 ``More Sensitive'' Case Emission Impacts in 2022 Relative to Each Reference Case
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     RFS1 base                     RFS1 mandate                       AEO2007
                                                         -----------------------------------------------------------------------------------------------
                        Pollutant                          Annual short     % of total     Annual short     % of total     Annual short     % of total
                                                               tons       U.S. inventory       tons       U.S. inventory       tons       U.S. inventory
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOX.....................................................         402,795             3.6         341,028             3.0         210,217             1.9
HC......................................................         100,313             0.9          63,530             0.6         -15,948           -0.14
PM10....................................................          46,193             1.3          33,035             0.9           5,164            0.15
PM2.5...................................................          10,535             0.3           7,666             0.2           1,589            0.05
CO......................................................      -3,779,572            -7.0      -3,104,798            -5.8      -1,675,869            -3.1
Benzene.................................................          -5,962            -3.5          -5,494            -3.3          -4,489            -2.7
Ethanol.................................................         228,563            39.6         187,926            32.5         105,264            18.2
1,3-Butadiene...........................................            -212            -1.8            -282            -2.4            -430            -3.6
Acetaldehyde............................................          16,375            44.0          14,278            38.4           9,839            26.5
Formaldehyde............................................           3,373             4.7           3,124             4.3           2,596             3.6
Naphthalene.............................................            -175            -1.2            -178            -1.3            -187            -1.3
Acrolein................................................             253             4.4             218             3.8             143             2.5
SO2.....................................................          28,770             0.3           4,461            0.05         -47,030            -0.5
NH3.....................................................         -27,161            -0.6         -27,161            -0.6         -27,161            -0.6
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We note that the aggregate nationwide emission inventory impacts 
presented here will likely lead to health impacts throughout the U.S. 
due to changes in future-year ambient air quality. However, emissions 
changes alone are not a good indication of local or regional air 
quality and health impacts, as there may be highly localized impacts 
such as increased emissions from ethanol plants and evaporative 
emissions from cars, and decreased emissions from gasoline refineries. 
In addition, the atmospheric chemistry related to ambient 
concentrations of PM2.5, ozone and air toxics is very 
complex, and making predictions based solely on emissions changes is 
extremely difficult. Full-scale photochemical modeling is necessary to 
provide the needed spatial and temporal detail to more completely and 
accurately estimate the changes in ambient levels of these pollutants. 
As discussed in Section VII.D, timing and resource constraints 
precluded EPA from conducting a full-scale photochemical air quality 
modeling analysis in time for the NPRM. For the final rule, however, a 
national-scale air quality modeling analysis will be performed to 
analyze the impacts of the proposed standards on PM2.5, 
ozone, and selected air toxics (i.e., benzene, formaldehyde, 
acetaldehyde, ethanol, acrolein and 1,3-butadiene). As described in 
Section VII.D.2, EPA intends to use a 2005-based Community Multi-scale 
Air Quality (CMAQ) modeling platform as the tool for the air

[[Page 24919]]

quality modeling. The CMAQ modeling system is a comprehensive three-
dimensional grid-based Eulerian air quality model designed to estimate 
the formation and fate of oxidant precursors, primary and secondary PM 
concentrations and deposition, and air toxics, over regional and urban 
spatial scales (e.g., over the contiguous U.S.).
    The lack of air quality modeling data also precluded EPA from 
conducting its standard analysis of human health impacts, where CMAQ 
output data are used as inputs to the Environmental Benefits Mapping 
and Analysis Program (BenMAP). Section IX.D of this preamble describes 
the human health impacts that will be quantified and monetized for the 
final rule, as well as the unquantified impacts that will be 
qualitatively described.
4. Water
    As the production of biofuels increases to meet the requirements of 
this proposed rule, there may be adverse impacts on both water quality 
and quantity. Increased production of biofuels may lead to increased 
application of fertilizer and pesticides and increased soil erosion, 
which could impact water quality. Since ethanol production uses large 
quantities of water, the supply of water could also be significantly 
impacted in some locations.
    EPA focused the water quality analysis for this proposal on the 
impacts of corn produced for ethanol for several reasons. Corn has the 
highest fertilizer and pesticide use per acre and accounts for the 
largest share of nitrogen fertilizer use among all crops. Furthermore, 
corn-based ethanol is expected to be a large component of the biofuels 
mix.
    Fertilizer nutrients that are not used by the crops are available 
to runoff to surface water or leach into groundwater. Nutrient 
enrichment due to human activities is one of the leading problems 
facing our nation's lakes, reservoirs, and estuaries, and also has 
negative impacts on aquatic life in streams; adverse health effects on 
humans and domestic animals; and impairs aesthetic and recreational 
use. Excess nutrients can lead to excessive growth of algae in rivers 
and streams, and aquatic plants in all waters. Nutrient pollution is 
widespread. The most widely known examples of significant nutrient 
impacts include the Gulf of Mexico and the Chesapeake Bay, however 
waterbodies in virtually every state and territory are impacted by 
nutrient-related degradation. A more detailed discussion of nutrient 
pollution can be found in Section X of this preamble and in Chapter 6 
of the DRIA.
    To provide a quantitative estimate of the impact of this proposal 
and production of corn ethanol generally on water quality, EPA 
conducted an analysis that modeled the changes in loadings of nitrogen, 
phosphorus, and sediment from agricultural production in the Upper 
Mississippi River Basin (UMRB). The UMRB is representative of the many 
potential issues associated with ethanol production, including its 
connection to major water quality concerns such as Gulf of Mexico 
hypoxia, large corn acreage, and numerous ethanol production plants. 
The UMRB contributes 39% of nitrogen loads and 26% of phosphorus loads 
to the Gulf of Mexico.
    EPA selected the SWAT (Soil and Water Assessment Tool) model to 
assess nutrient loads from changes in agricultural production in the 
UMRB. SWAT is a physical process model developed to quantify the impact 
of land management practices in large, complex watersheds. In 
conducting its analysis EPA quantified the impacts from a baseline that 
preceded the current high production of ethanol from corn to four 
future years--2010, 2015, 2020 and 2022.
    Table II.B.4-1 summarizes the model outputs at the outlet of the 
UMRB in the Mississippi River at Grafton, Illinois for each of the four 
scenario years. The local impact in smaller watersheds within the UMRB 
may be significantly different. The decreasing nitrogen load over time 
is likely attributed to the increased corn yield production, resulting 
in greater plant uptake of nitrogen. The relatively stable sediment 
loadings are likely due to the fact that corn was modeled assuming that 
corn stover is left on the fields following harvest.

   Table II.B.4-1--Changes From the 2005 Baseline to the Mississippi River at Grafton, Illinois From the Upper
                                             Mississippi River Basin
----------------------------------------------------------------------------------------------------------------
                                                    2005 Baseline           2010      2015      2020      2022
----------------------------------------------------------------------------------------------------------------
Average corn yield (bushels/acre).........  141.........................       150       158       168       171
Nitrogen..................................  1433.5 million lbs..........     +5.5%     +4.7%     +2.5%     +1.8%
Phosphorus................................  132.4 million lbs...........     +2.8%     +1.7%    +0.98%     +0.8%
Sediment..................................  6.4 million tons............     +0.5%     +0.3%     +0.2%     +0.1%
----------------------------------------------------------------------------------------------------------------

    After evaluating comments on this proposal, if time and resources 
permit, EPA may conduct additional water quality analyses using the 
SWAT model in the UMRB. Potential future analyses could include: (1) 
Determination of the most sensitive assumptions in the model, (2) water 
quality impacts from the changes in ethanol volumes between the 
reference case and this proposal, (3) removing corn stover for 
cellulosic ethanol, and (4) a case study of a smaller watershed to 
evaluate local water quality impacts that are impossible to ascertain 
at the scale of the UMRB.
    EPA also qualitatively examined other water issues, which are also 
discussed in detail in Section X of this Preamble, and Chapter 6 of the 
DRIA.
5. Agricultural Commodity Prices
    The recent increase in food prices, both domestically and 
internationally, has raised the issue of whether diverting grains and 
oilseeds for fuel production is having a large impact on commodity 
markets. While we share the concern that food prices have increased 
significantly over the same time period in which renewable fuel 
production has increased, many factors have contributed to recent 
increases in food prices. As described by the U.S. Department of 
Agriculture (USDA), the Department of Energy (DOE), the Council of 
Economic Advisors (CEA), and others, the recent increase in commodity 
prices has been influenced by factors as diverse as world economic 
growth, droughts in Australia, China and Eastern Europe, increasing oil 
prices, changes in investment strategies, and the declining value of 
the U.S. dollar. While the increase in renewable fuel production has 
contributed to the increase in commodity prices, the magnitude of the 
contribution of the RFS has most likely been minor, as market 
conditions have continued to push renewable fuel use beyond the 
mandated levels.
    As the mandated levels of renewable fuels continue to rise in the 
future, our

[[Page 24920]]

economic modeling suggests that the impact of the RFS2 program on food 
prices will continue to be modest, particularly with the expansion of 
cellulosic biofuels. Table II.B.5-1 summarizes the changes in prices 
for some commodities we have estimated for this proposal. Further 
discussion can be found in Section IX.A.

 Table II.B.5-1--Change in U.S. Commodity Prices for 2022 in Comparison
                          to the Reference Case
                                 [2006$]
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Corn...............................  $0.15/bushel.
Soybeans...........................  $0.29/bushel.
Sugarcane..........................  $13.34/ton.
Beef...............................  $0.93/hundred pounds.
------------------------------------------------------------------------

II. What Are the Major Elements of the Program Required Under EISA?

    While EISA made a number of changes to CAA section 211(o) that must 
be reflected in the RFS program regulations, it left many of the basic 
program elements intact, including the mechanism for translating 
national renewable fuel volume requirements into applicable standards 
for individual obligated parties, requirements for a credit trading 
program, geographic applicability, treatment of small refineries, and 
general waiver provisions. As a result, we propose that many of the 
regulatory requirements of the RFS1 program would remain largely or, in 
some cases, entirely unchanged. These provisions would include the 
distribution of RINs, separation of RINs, use of RINs to demonstrate 
compliance, provisions for exporters, recordkeeping and reporting, 
deficit carryovers, and the valid life of RINs.
    The primary elements of the RFS program that we propose changing to 
implement the requirements in EISA fall primarily into the following 
five areas:
    (1) Expansion of the applicable volumes of renewable fuel
    (2) Separation of the volume requirements into four separate 
categories of renewable fuel, with corresponding changes to the RIN and 
to the applicable standards
    (3) Changes to the definition of renewable fuels and criteria for 
determining which if any of the four renewable fuel categories a given 
renewable fuel is eligible to meet
    (4) Expansion of the fuels subject to the standards (and applicable 
to refiners, blenders, and importers of those fuels) to include diesel 
and certain nonroad fuels
    (5) Inclusion of specific types of waivers and EPA-generated 
credits for cellulosic biofuel.
    EISA does not change the basic requirement under CAA 211(o) that 
the RFS program include a credit trading program. In the May 1, 2007 
final rulemaking implementing the RFS1 program, we described how we 
reviewed a variety of approaches to program design in collaboration 
with various stakeholders. We finally settled on a RIN-based system for 
compliance and credit purposes as the one which met our goals of being 
straightforward, maximizing flexibility, ensuring that volumes are 
verifiable, and maintaining the existing system of fuel distribution 
and blending. RINs represent the basic framework for ensuring that the 
statutorily required volumes of renewable fuel are produced and used as 
transportation fuel in the U.S. The use of RINs is predicated on the 
fact that once renewable fuels are produced or imported, there is very 
high confidence that, setting aside exports, all but de minimus 
quantities will in fact be used as transportation fuel in the U.S. 
Focusing on production of renewable fuel as a surrogate for the later 
actual blending and use of such fuel has many benefits as far as 
streamlining the RFS program and minimizing the impact that the program 
has on the business operations of the regulated industries. Since the 
RIN-based system generally has been successful in meeting EPA's goals, 
we propose to maintain much of its structure under RFS2.
    This section describes the regulatory changes we propose to 
implement the new EISA provisions. Section IV describes other changes 
to the RFS program that we have considered or are proposing, including 
a concept for an EPA-moderated RIN trading system that would provide a 
context within which all RIN transfers could occur.

A. Changes to Renewable Identification Numbers (RINs)

    Under RFS2, we propose that each RIN would continue to represent 
one gallon of renewable fuel for compliance purposes consistent with 
our approach under RFS1, and the RIN would continue to have 38 digits. 
In general the codes within the RIN would have the same meaning under 
RFS2 as they do under RFS1, with the exception of the D code which 
would be expanded to cover the four categories of renewable fuel 
defined in EISA. The proposed change to the D code is described in 
Table III.A-1.

                                    Table III.A-1--Proposed Change to D Code
----------------------------------------------------------------------------------------------------------------
                D value                         Meaning under RFS1                  Meaning under RFS2
----------------------------------------------------------------------------------------------------------------
1......................................  Cellulosic biomass ethanol.....  Cellulosic biofuel.
2......................................  Any renewable fuel that is not   Biomass-based diesel.
                                          cellulosic biomass ethanol.
3......................................  Not applicable.................  Advanced biofuel.
4......................................  Not applicable.................  Renewable fuel.
----------------------------------------------------------------------------------------------------------------

The determination of which D code would be assigned to a given batch of 
renewable fuel is described in more detail in Section III.D.2 below.
    As described in Section II.A.5, we are proposing that the RFS2 
program go into effect on January 1, 2010. However, we are also taking 
comment on other potential start dates including January 1, 2011 and 
dates between January 1, 2010 and January 1, 2011. If we were to start 
the RFS2 program during 2010 but after January 1, some 2010 RINs would 
be generated under the RFS1 requirements and others would be generated 
under the RFS2 requirements, but all RINs generated in 2010 would need 
to be valid for meeting the appropriate 2010 annual standards. Since 
RFS1 RINs and RFS2 RINs would differ in the meaning of the D codes, we 
would need a mechanism for distinguishing between these two categories 
of RINs in order to appropriately apply them to the standards. One 
straightforward way of accomplishing this would be to use values for 
the D code under RFS2 that do not overlap the values for the D code 
under RFS1. Table III.A-2 describes the D code definitions under such 
an alternative approach.

[[Page 24921]]



                                  Table III.A-2--Alternative D Code Definitions
----------------------------------------------------------------------------------------------------------------
                D value                         Meaning under RFS1                  Meaning under RFS2
----------------------------------------------------------------------------------------------------------------
1......................................  Cellulosic biomass ethanol.....  Not applicable.
2......................................  Any renewable fuel that is not   Not applicable.
                                          cellulosic biomass ethanol.
3......................................  Not applicable.................  Cellulosic biofuel.
4......................................  Not applicable.................  Biomass-based diesel.
5......................................  Not applicable.................  Advanced biofuel.
6......................................  Not applicable.................  Renewable fuel.
----------------------------------------------------------------------------------------------------------------

    In this alternative approach, D code values of 1 and 2 would only 
be relevant for RINs generated under RFS1, and D code values of 3, 4, 
5, and 6 would only be relevant for RINs generated under RFS2. As a 
result, 2010 RINs generated under RFS1 would be subject to our proposed 
RFS1/RFS2 transition provisions wherein they would be assigned to one 
of the four annual standards that would apply in 2010 using their RR 
and/or D codes. See Section III.G.3 for further description of how we 
propose using RFS1 RINs to meet standards under RFS2.
    Under RFS2, each batch-RIN generated would continue to uniquely 
identify not only a specific batch of renewable fuel, but also every 
gallon-RIN assigned to that batch. Thus the RIN would continue to be 
defined as follows:

RIN: KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE

Where:

K = Code distinguishing assigned RINs from separated RINs
YYYY = Calendar year of production or import
CCCC = Company ID
FFFFF = Facility ID
BBBBB = Batch number
RR = Code identifying the Equivalence Value
D = Code identifying the renewable fuel category
SSSSSSSS = Start of RIN block
EEEEEEEE = End of RIN block

B. New Eligibility Requirements for Renewable Fuels

    Aside from the higher volume requirements, most of the substantive 
changes that EISA makes to the RFS program affect the eligibility of 
renewable fuels in meeting one of the four volume requirements. 
Eligibility would be determined based on the types of feedstocks that 
can be used, the land that can be used to grow feedstocks for renewable 
fuel production, the processes that can be used to convert those 
feedstocks into fuel, and the lifecycle greenhouse gas (GHG) emissions 
that can be emitted in comparison to the gasoline or diesel that the 
renewable fuel displaces. This section describes these eligibility 
criteria and how we propose to include them in the RFS2 program.
1. Changes in Renewable Fuel Definitions
    Under the existing Renewable Fuel Standard (RFS1), renewable fuel 
is defined generally as ``any motor vehicle fuel that is used to 
replace or reduce the quantity of fossil fuel present in a fuel mixture 
used to fuel a motor vehicle''. The RFS1 definition includes motor 
vehicle fuels produced from biomass material such as grain, starch, 
fats, greases, oils, and biogas. The definition specifically includes 
cellulosic biomass ethanol, waste derived ethanol, and biodiesel, all 
of which are defined separately. (See 72 FR 23915.)
    The definitions of renewable fuels under today's proposed rule 
(RFS2) are based on the new statutory definition in EISA. Like the 
existing rules, the definitions in RFS2 include a general definition of 
renewable fuel, but unlike RFS1, we are including a separate definition 
of ``Renewable Biomass'' which identifies the feedstocks from which 
renewable fuels may be made.
    Another difference in the definitions of renewable fuel is that 
RFS2 contains three subcategories of renewable fuels: (1) Advanced 
Biofuel, (2) Cellulosic Biofuel and (3) Biomass-Based Diesel. Each must 
meet threshold levels of reduction of greenhouse gas emissions as 
discussed in Section III.B.2. The specific definitions and how they 
differ from RFS1 follow below.
a. Renewable Fuel and Renewable Biomass
    ``Renewable Fuel'' is defined as fuel produced from renewable 
biomass and that is used to replace or reduce the quantity of fossil 
fuel present in a transportation fuel. The definition of ``Renewable 
Fuel'' now refers to ``transportation fuel'' rather than referring to 
motor vehicle fuel. ``Transportation fuel'' is also defined, and means 
fuel used in motor vehicles, motor vehicle engines, nonroad vehicles or 
nonroad engines (except for ocean going vessels).
    We propose to allow fuel producers and importers to include 
electricity, natural gas, and propane (i.e., compressed natural gas 
(CNG) and liquefied petroleum gas (LPG)) as a RIN-generating renewable 
fuel in today's program only if they can identify the specific 
quantities of their product which are actually used as a transportation 
fuel, and if the fuel is produced from renewable biomass. This may be 
possible for some portion of electricity, natural gas, and propane 
since many of the affected vehicles and equipment are in centrally-
fueled fleets supplied under contract by a particular producer or 
importer of natural gas or propane. A producer or importer of 
electricity, natural gas, or propane who could document the use of his 
product in a vehicle or engine would be allowed to generate RINs to 
represent that product, if it met the definition of renewable fuel. 
Given that the primary use of electricity, natural gas, and propane is 
not for fueling vehicles and engines, and the producer generally does 
not know how it will be used, we cannot require that producers or 
importers of these fuels generate RINs for all the volumes they produce 
as we do with other renewable fuels.
    Our proposal to allow electricity, natural gas, and propane to 
generate RINs under certain conditions is consistent with our treatment 
of neat renewable fuels under RFS1 and EISA's requirement that all 
transportation fuels be included in RFS2. With specific regard to 
renewable electricity, Section 206 of EISA requires the EPA to conduct 
a study of the feasibility of issuing credits under the RFS2 program 
for renewable electricity used by electric vehicles. Once completed, 
this study will provide additional information regarding the means by 
which renewable electricity is able to generate RINs under the RFS2 
program.
    As an alternative to allowing producers and importers of 
electricity, natural gas, and propane to generate RINs if they can 
demonstrate that their product is a renewable fuel and it is used as 
transportation fuel, we could allow or require parties who supply these 
fuels to centrally fueled fleets to generate the RINs even if they are 
not the producer of the fuel. This approach

[[Page 24922]]

would treat the supplier of the fuel to the fleet as the producer or 
importer who then generates RINs, as they are the party who in effect 
changes the fuel from a fuel that can be used in a variety of ways and 
ensures that it is in fact used as transportation fuel. This 
alternative approach might enable a larger volume of electricity, 
natural gas, and propane that is made from renewable biomass and which 
is actually used in vehicles or engines to be included in our proposed 
fuels program as RIN-generating, since in many cases a supplier could 
document the use of these fuels in vehicles or engines, while a 
producer could not. In addition, in this case the supplier is the party 
who causes the fuel to transition from general fuel supply to fuel 
designated for use in motor vehicles or nonroad applications--in that 
sense, the supplier is more like a producer or importer than the 
upstream producer or importer. However, if we were to allow the 
supplier of renewable electricity, natural gas, or propane to generate 
RINs in such cases, it may also be appropriate to require suppliers of 
fossil-based electricity, natural gas, or propane to determine a 
Renewable Volume Obligation (RVO) that includes these fuels used as 
transportation fuel. See Section III.F.3 for further discussion. We 
request comment on this alternative approach for generating RINs for 
renewable electricity, natural gas and propane.
    The term ``Renewable Biomass'' as defined in EISA, means:
    1. Planted crops and crop residue,
    2. Planted trees and tree residues,
    3. Animal waste material and byproducts,
    4. Slash and pre-commercial thinnings (from non-federal 
forestlands),
    5. Biomass cleared from the vicinity of buildings and other areas 
to reduce the risk of wildfire,
    6. Algae, and
    7. Separated yard waste or food waste.
    Section III.B.4 of this preamble outlines our proposed 
interpretations for most of the key terms contained in the EISA 
definition of ``renewable biomass'' and possible approaches for 
implementing the land restrictions on renewable biomass that are 
included in EISA. It is worth noting here, however, that the statutory 
definition of ``renewable biomass'' does not include a reference to 
municipal solid waste (MSW) as did the definition of ``cellulosic 
biomass ethanol'' in the Energy Policy Act of 2005 (EPAct), but instead 
includes ``separated yard waste and food waste. EPA's proposed 
definition of renewable biomass in today's regulation includes the 
language present in EISA, and we propose to clarify in the regulations 
that ``yard waste'' is leaves, sticks, pine needles, grass and hedge 
clippings, and similar waste from residential, commercial, or 
industrial areas. Nevertheless, EPA invites comment on whether the 
definition of ``renewable biomass'' should be interpreted as including 
or excluding MSW from the definition of renewable biomass.
    While the lack of a reference to MSW and the new listing of 
separated yard waste and food waste could be readily interpreted to 
exclude MSW as a qualifying feedstock under RFS2, EPA believes there 
are indications of ambiguity on this issue and solicits comment on 
whether EPA can and should interpret EISA as including MSW that 
contains yard and/or food waste within the definition of renewable 
biomass. On the one hand, the reference in the statutory definition to 
``separated yard waste and food waste,'' and the lack of reference to 
other components of MSW (such as waste paper and wood waste) suggests 
that only yard and food wastes physically separated from other waste 
materials satisfy the definition of renewable biomass as opposed to the 
yard and food waste present in MSW. This view would exclude unprocessed 
MSW from any role in the development of renewable fuel under EISA, and 
would also likely severely limit the amount of yard and food waste 
available as feedstock for EISA-qualifying fuel, since large quantities 
of these materials are disposed of as unprocessed MSW.
    On the other hand, there are some indications that Congress may not 
have specifically intended to exclude MSW from playing a role in the 
development of renewable fuels under EISA. For example, ethanol 
``derived from waste material'' and biogas ``including landfill gas'' 
are specifically identified as ``eligible for consideration'' in the 
definition of advanced biofuel. While landfill gas is generated 
primarily by the yard waste and food waste in a landfill, these wastes 
typically are not separated from each other in a landfill. In addition, 
Congress did not define the term ``separated'' and did not otherwise 
specify the degree of ``separation'' required of yard and food waste in 
the definition of renewable biomass. Thus, it might be reasonable to 
consider these items sufficiently ``separated'' from other materials, 
including non-waste materials, when food and yard waste is present in 
MSW. In addition, the processing of MSW to fuel will effectively 
separate out the materials in MSW that cannot be made into fuel, such 
as glass and metal, and non-biomass portions of MSW (for example, 
pastics) could be excluded from getting credit under the RFS program as 
described in Section III.D.4. EPA invites comment on whether there is 
enough separation of food and yard waste in MSW used in renewable fuel 
production for MSW containing yard and food waste to meet the 
definition of renewable biomass.
    Approximately 35% by weight of MSW is paper wastes, and another 6% 
by weight from wood wastes. Combined with food and yard wastes, more 
than 60% by weight of MSW is biomass that could be used to make ethanol 
and other renewable fuels.\5\ The volume of ethanol associated with MSW 
as a feedstock is described in more detail in Section 1.1 of the Draft 
Regulatory Impact Analysis (DRIA).
---------------------------------------------------------------------------

    \5\ Construction and demolition (C&D) wastes are not typically 
considered as elements of MSW. Because they are significant 
feedstocks for the production of ethanol, we include such wastes in 
our economic analysis (Section V). Therefore, for all practical 
purposes, the discussion here as it pertains to whether MSW should 
be included in the definition of ``renewable biomass'' also applies 
to C&D wastes.
---------------------------------------------------------------------------

    Our discussions with stakeholders indicate that a potential concern 
with interpreting the definition of renewable biomass to include MSW 
containing yard and/or food waste is that this approach may cause some 
decrease in the amount of paper that is separated from the MSW waste 
stream and recycled into paper products. We believe, however, that 
current waste handling practices and current and anticipated market 
conditions would continue to provide a strong incentive for paper 
separation and recycling. A narrow reading of the statute to exclude 
MSW-derived renewable fuel would directionally reduce the options 
available for meeting the goal of EISA to reduce our dependence on 
foreign sources of energy.
    By including MSW containing yard and/or food waste in the 
definition of renewable biomass, we could also allow renewable fuel to 
be produced in part from certain plastics in the MSW waste stream. We 
believe this could be appropriate given that plastics that would 
otherwise be destined for landfills can be used for fuel and energy 
production. We recognize that the definition of renewable biomass 
generally includes only materials of a non fossil-fuel origin, and ask 
that commenters consider this issue in their comments on whether: (1) 
MSW containing yard and food waste should qualify as renewable biomass, 
(2) if non-fossil portions of MSW should be included in the definition 
of renewable biomass, and (3) if non-fossil portions of

[[Page 24923]]

MSW should not be included, whether the approach discussed in Section 
III.D.4 can provide an appropriate means for excluding the non-fossil 
portions.
    Although we are proposing to exclude MSW from the definition of 
``renewable biomass'' for the proposed rule, our analysis of renewable 
fuel volume (discussed in Section V) assumes that MSW is included for 
purposes of quantifying the potential future volume of renewable fuel. 
EPA intends to resolve this matter in the final rule, and we solicit 
comment on the approach that we should take.
b. Advanced Biofuel
    ``Advanced Biofuel'' is a renewable fuel other than ethanol derived 
from corn starch and which must also achieve a lifecycle GHG emission 
displacement of 50%, compared to the gasoline or diesel fuel it 
displaces. As such, advanced biofuel would be assigned a D code of 3 as 
shown in Table III.A-1.
    ``Advanced biofuel'' also may be biomass-based diesel, biogas 
(including landfill gas and sewage waste treatment gas), butanol or 
other alcohols produced through conversion of organic matter from 
renewable biomass, and other fuels derived from cellulosic biomass, as 
long as it meets the proposed 40-44% GHG emission reduction threshold. 
``Advanced Biofuel'' is a renewable fuel other than ethanol derived 
from corn starch and for which lifecycle GHG emissions are at least 40-
44% less than the gasoline or diesel fuel it displaces. Advanced 
biofuel would be assigned a D code of 3 as shown in Table III.A-1.
    While ``Advanced Biofuel'' specifically excludes ethanol derived 
from corn starch, it includes other types of ethanol derived from 
renewable biomass, including ethanol made from cellulose, 
hemicellulose, lignin, sugar or any starch other than corn starch, as 
long as it meets the proposed 40-44% GHG emission reduction threshold. 
Thus, even if corn starch-derived ethanol were made so that it met the 
proposed 40-44% GHG reduction threshold, it would still be excluded 
from being defined as an advanced biofuel. Such ethanol, while not an 
advanced biofuel, would still qualify as a renewable fuel for purposes 
of meeting the standards.
    ``Advanced biofuel'' also may be biomass-based diesel, biogas 
(including landfill gas and sewage waste treatment gas), butanol or 
other alcohols produced through conversion of organic matter from 
renewable biomass, and other fuels derived from cellulosic biomass, as 
long as it is derived from renewable biomass and meets the proposed 40-
44% GHG emission reduction threshold.
c. Cellulosic Biofuel
    Cellulosic biofuel is renewable fuel, not necessarily ethanol, 
derived from any cellulose, hemicellulose, or lignin each of which must 
originate from renewable biomass. It must also achieve a lifecycle GHG 
emission reduction of at least 60%, compared to the gasoline or diesel 
fuel it displaces. Cellulosic biofuel is assigned a D code of 1 as 
shown in Table III.A-1. Cellulosic biofuel in general also qualifies as 
both ``advanced biofuel'' and ``renewable fuel''.
    The proposed definition of cellulosic biofuel for RFS2 is broader 
in some respects than the RFS1 definition of ``cellulosic biomass 
ethanol''. That definition included only ethanol, whereas the RFS2 
definition of cellulosic biofuels includes any biomass-to-liquid fuel 
in addition to ethanol. The definition of ``cellulosic biofuel'' in 
RFS2 differs from RFS1 in another significant way. The RFS1 definition 
provided that ethanol made at any facility--regardless of whether 
cellulosic feedstock is used or not--may be defined as cellulosic if at 
such facility ``animal wastes or other waste materials are digested or 
otherwise used to displace 90% or more of the fossil fuel normally used 
in the production of ethanol.'' This provision was not included in 
EISA, and therefore does not appear in the definitions pertaining to 
cellulosic biofuel in today's proposed rule.
d. Biomass-Based Diesel
    Under today's proposed rule ``Biomass-based diesel'' includes both 
biodiesel (mono-alkyl esters) and non-ester renewable diesel (including 
cellulosic diesel). The definition is the same very broad definition of 
``biodiesel'' that was in EPAct and in RFS1, with three exceptions. 
First, EISA requires that such fuel be made from renewable biomass. 
Second, its lifecycle GHG emissions must be at least 50% less than the 
gasoline or diesel fuel it displaces. Third, the statutory definition 
of ``Biomass-based diesel'' excludes renewable fuel derived from co-
processing biomass with a petroleum feedstock. In drafting the proposed 
definition, we considered two options for how co-processing could be 
treated. The first option would consider co-processing to occur only if 
both petroleum and biomass feedstock are processed in the same unit 
simultaneously. The second option would consider co-processing to occur 
if renewable biomass and petroleum feedstock are processed in the same 
unit at any time; i.e., either simultaneously or sequentially. Under 
the second option, if petroleum feedstock was processed in the unit, 
then no fuel produced from such unit, even from a biomass feedstock, 
would be deemed to be biomass-based diesel.
    We are proposing the first option to be used in the definition in 
today's rule. Under this approach, a batch of fuel qualifying for the D 
code of 2 that is produced in a processing unit in which only renewable 
biomass is the feedstock for such batch, would meet the definition of 
``Biomass-Based Diesel. Thus, serial batch processing in which 100% 
vegetable oil is processed one day/week/month and 100% petroleum the 
next day/week/month could occur without the activity being considered 
``co-processing.'' The resulting products could be blended together, 
but only the volume produced from vegetable oil would count as biomass-
based diesel. We believe this is the most straightforward approach and 
an appropriate one, given that it would allow RINs to be generated for 
volumes of fuel meeting the 50% GHG reduction threshold that is derived 
from renewable biomass, while not providing any credit for fuel derived 
from petroleum sources. In addition, this approach avoids the need for 
potentially complex provisions addressing how fuel should be treated 
when existing or even mothballed petroleum hydrotreating equipment is 
retrofitted and placed into new service for renewable fuel production 
or vice versa.
    Under today's proposal, any fuel that does not satisfy the 
definition of biomass-based diesel only because it is co-processed with 
petroleum would still meet the definition of ``Advanced Biofuel'' 
provided it meets the 50% GHG threshold and other criteria for the D 
code of 3. Similarly it would meet the definition of renewable fuel if 
it meets a GHG emission reduction threshold of 20%. In neither case, 
however, would it meet the definition of biomass-based diesel.
    This restriction is only really an issue for renewable diesel and 
biodiesel produced via the fatty acid methyl ester (FAME) process. For 
other forms of biodiesel, it is never made through any sort of co-
processing with petroleum.\6\

[[Page 24924]]

Producers of renewable diesel must therefore specify whether or not 
they use ``co-processing'' to produce the fuel in order to determine 
the correct D code for the RIN.
---------------------------------------------------------------------------

    \6\ The production of biodiesel (mono alkyl esters) does require 
the addition of methanol which is usually derived from natural gas, 
but which contributes a very small amount to the resulting product. 
We do not believe that this was intended by the statute's reference 
to ``co-processing'' which we believe was intended to address only 
renewable fats or oils co-processed with petroleum in a hydrotreater 
to produce renewable diesel.
---------------------------------------------------------------------------

e. Additional Renewable Fuel
    The statutory definition of ``additional renewable fuel'' specifies 
fuel produced from renewable biomass that is used to replace or reduce 
fossil fuels used in home heating oil or jet fuel. EISA indicates that 
EPA may allow for the generation of credits for such additional 
renewable fuel that will be valid for compliance purposes. Under the 
RFS program, RINs operate in the role of credits, and RINs are 
generated when renewable fuel is produced rather than when it is 
blended. In most cases, however, renewable fuel producers do not know 
at the time of fuel production (and RIN generation) how their fuel will 
ultimately be used.
    Under RFS1, only RINs assigned to renewable fuel that was blended 
into motor vehicle fuel are valid for compliance purposes. As a result, 
we created special provisions requiring that RINs be retired if they 
were assigned to renewable fuel that was ultimately blended into 
nonroad fuel. The new EISA provisions regarding additional renewable 
fuel make the RFS1 requirement for retiring RINs unnecessary if 
renewable fuel is blended into heating oil or jet fuel. As a result, we 
propose modifying the regulatory requirements to allow RINs assigned to 
renewable fuel blended into heating oil or jet fuel to continue to be 
valid for compliance purposes.
2. Lifecycle GHG Thresholds
    As part of the new definitions that EISA creates for cellulosic 
biofuel, biomass-based diesel, advanced biofuel, and renewable fuel, 
EISA also sets minimum performance measures or ``thresholds'' for 
lifecycle GHG emissions. These thresholds represent the percent 
reduction in lifecycle GHGs that is estimated to occur when a renewable 
fuel displaces gasoline or diesel fuel. Table III.B.2-1 lists the 
thresholds required by EISA.

           Table III.B.2-1--Required Lifecycle GHG Thresholds
       [Percent reduction from a 2005 gasoline or diesel baseline]
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Renewable fuel.................................................       20
Advanced biofuel...............................................       50
Biomass-based diesel...........................................       50
Cellulosic biofuel.............................................       60
------------------------------------------------------------------------

    There are also special provisions for each of these thresholds:
    Renewable fuel: The 20% threshold only applies to renewable fuel 
from new facilities that commenced construction after December 19, 
2007, with an additional exemption from the 20% threshold for ethanol 
plants that commenced construction in 2008 or 2009 and are fired with 
natural gas, biomass, or any combination thereof. Facilities not 
subject to the 20% threshold would be ``grandfathered.'' See Section 
III.B.3 below for a complete discussion of grandfathering. Also, EPA 
can adjust the 20% threshold to as low as 10%, but the adjustment must 
be the minimum possible, and the resulting threshold must be 
established at the maximum achievable level based on natural gas fired 
corn-based ethanol plants.
    Advanced biofuel and biomass-based diesel: The 50% threshold can be 
adjusted to as low as 40%, but the adjustment must be the minimum 
possible and result in the maximum achievable threshold taking cost 
into consideration. Also, such adjustments could be made only if it was 
determined that the 50% threshold was not commercially feasible for 
fuels made using a variety of feedstocks, technologies, and processes. 
As described more fully in Section VI.D, we are proposing that the GHG 
threshold for advanced biofuels be adjusted to 44% or potentially as 
low as 40% depending on the results from the analyses that will be 
conducted for the final rule.
    Cellulosic biofuel: Similarly to advanced biofuel and biomass-based 
diesel, the 60% threshold applicable to cellulosic biofuel can be 
adjusted to as low as 50%, but the adjustment must be the minimum 
possible and result in the maximum achievable threshold taking cost 
into consideration. Also, such adjustments could be made only if it was 
determined that the 60% threshold was not commercially feasible for 
fuels made using a variety of feedstocks, technologies, and processes.
    Our analyses of lifecycle GHG emissions, discussed in detail in 
Section VI, included all GHGs related to the full fuel cycle, including 
all stages of fuel and feedstock production and distribution, from 
feedstock generation and extraction through distribution, delivery, and 
use of the finished fuel. They included direct emissions and any 
significant indirect emissions such as significant emissions from land 
use changes. These lifecycle analyses were used to determine whether 
the thresholds shown in Table III.B.2-1 should be adjusted downwards 
and which specific combinations of feedstock, fuel type, and production 
process met those thresholds under the assumption of a 100-year 
timeframe and 2% discount rate for GHG emission impacts.
    We are not proposing to adjust any of these thresholds. However, we 
may adjust the GHG threshold for biomass-based diesel and/or advanced 
biofuel downward for the final rule based on additional lifecycle GHG 
analyses and further assessments of the market potential for volumes 
that can meet the requirements for these categories of renewable fuel. 
As explained in more detail in Section VI.D, ethanol produced from 
sugarcane sugar has been estimated to have a lifecycle GHG performance 
of 44% (under the assumption of a 100 year timeframe and 2% discount 
rate), short of the 50% threshold specified in EISA. Ethanol from 
sugarcane is one of the few currently commercial pathways that have the 
potential to meet the requirements for advanced biofuel in the near 
term (in addition to cellulosic biofuel and biomass-based diesel which 
are a subset of advanced biofuel, and any other new fuels that may 
arise), and the only such pathway that was subjected to lifecycle 
analysis to date. If ethanol from sugarcane does not qualify as 
advanced biofuel, it is likely that it would not be commercially 
feasible for the advanced biofuel volume requirements to be met in the 
near term. We request comment on whether it would be necessary to 
adjust the GHG threshold for advanced biofuel. For similar reasons, as 
discussed in more detail in Section VI.D, we are also seeking comment 
on the need to adjust the GHG threshold for biomass-based diesel.
3. Renewable Fuel Exempt From 20 Percent GHG Threshold
    EISA amends section 211(o) of the Clean Air Act to provide that 
renewable fuel produced from new facilities which commenced 
construction after December 19, 2007 must achieve at least a 20% 
reduction in lifecycle greenhouse gas emissions compared to baseline 
lifecycle greenhouse gas emissions.\7\ Facilities that commenced 
construction before December 19, 2007 are ``grandfathered'' and thereby 
exempt from the 20% GHG reduction requirement.
---------------------------------------------------------------------------

    \7\ Section 211(o)(2)(A)(i) of the Clean Air Act as amended by 
EISA. Note that this is not a prohibition--facilities that make 
ethanol can continue to do so. It is a minimum requirement for 
facilities to generate RINs under today's proposed rule; failure to 
meet such requirements means that the ethanol produced from such 
facilities cannot generate RINs.

---------------------------------------------------------------------------

[[Page 24925]]

    For facilities that produce ethanol and for which construction 
commenced after December 19, 2007, section 210 of EISA states that 
``for calendar years 2008 and 2009, any ethanol plant that is fired 
with natural gas, biomass, or any combination thereof is deemed to be 
in compliance with the 20% threshold.'' We refer to these facilities as 
``deemed compliant.'' This provision does not specify whether such 
facilities are deemed to be in compliance only for the period of 2008 
and 2009, or indefinitely. Nor does EISA specify a date by which such 
qualifying facilities must have started operation. Although the Act is 
unclear as to whether their special treatment is only for 2008/2009, or 
for a longer time period, we believe that it would be a harsh result 
for investors in these new facilities, and generally inconsistent with 
the energy independence goals of EISA, for these new facilities to only 
be guaranteed two years of participation in the RFS2 program. We 
propose that the statute be interpreted to mean that fuel from such 
qualifying facilities, regardless of date of startup of operations, 
would be exempt from the 20% GHG threshold requirement for the same 
time period as facilities that commence construction prior to December 
19, 2007, provided that such plants commence construction prior to 
December 31, 2009, complete such construction in a reasonable amount of 
time, and continue to burn only natural gas, biomass, or a combination 
thereof. Therefore, we believe that they should be treated like 
grandfathered facilities. We seek comment, however, on the alternative 
in which after 2009, such plants must meet the 20% threshold in order 
to generate RINs for renewable fuel produced.
    Based on our survey of ethanol plants in operation, as well as 
those not yet in operation but which commenced construction prior to 
December 19, 2007, it is likely that production capacity of ethanol 
from all such facilities will reach 15 billion gallons. (See Section 
1.5.1.4 of the DRIA.) This volume of ethanol will be excluded from 
having to meet the 20% GHG threshold by the grandfathering and deemed 
compliant provisions of EISA.\8\ For ease of reference, we will refer 
to both these provisions as the ``exemption provisions'' of EISA.
---------------------------------------------------------------------------

    \8\ The grandfathering and deemed compliant provisions in EISA 
sections 202 and 210 do not apply to the advanced biofuels, biomass-
based diesel or cellulosic biofuel standards for which the Act 
requires a 50 or 60% GHG reduction threshold to be met regardless of 
when the facilities producing such fuels are constructed.
---------------------------------------------------------------------------

    EISA does not define the term ``new facility'' and, as mentioned 
above, does not clarify whether ``deemed compliant'' facilities have 
that status for only 2008 and 2009, or for a longer time period. EPA 
seeks, in interpreting these terms, to avoid long-term backsliding with 
respect to environmental performance and to also provide a level 
playing field for future investments. Thus, we want to avoid incentives 
that would allow overall GHG performance to worsen via expansion at 
older plants with poorer GHG performance or by modifications such as 
switches to more polluting process heat sources, such as coal. At the 
same time, we also want to offer protection for historical business 
investments that were made prior to enactment of EISA, and we want 
future significant investments to meet the GHG reduction standards of 
the Act. Finally we want to avoid excessive case-by-case decision 
making where possible, and seek instead a rule that offers ease of 
implementation while providing certainty to EPA and the regulated 
industry.
    We are proposing one basic approach to the exemption provisions and 
seeking comment on five additional options. In fashioning the basic 
proposal and alternative options for exempted facilities, we considered 
aspects of exemption approaches elsewhere in the CAA and EPA 
regulations to evaluate whether they would foster the above-described 
objectives. We are only looking to these other provisions for guidance 
and are not bound to follow any already-established approach for a 
different statutory provision (especially as those other provisions may 
contain definitions that Congress did not incorporate here).
a. Definition of Commence Construction
    In defining ``commence'' and ``construction'', we wanted a clear 
designation that would be broad enough to avoid facility-specific 
issues, but narrow enough to prevent new facilities (i.e., post-
December 19, 2007) from being grandfathered. We believe that the 
definitions of ``commence'' and ``Begin actual construction'' in the 
Prevention of Significant Deterioration (PSD) regulations, which draws 
upon definitions in the Clean Air Act, served this purpose. (40 CFR 
52.21(b)(9) and (11)). Specifically, under the PSD regulations, 
``commence'' means that the owner or operator has all necessary 
preconstruction approvals or permits and either has begun a continuous 
program of actual on-site construction to be completed in a reasonable 
time, or entered into binding agreements which cannot be cancelled or 
modified without substantial loss.'' Such activities include, but are 
not limited to, ``installation of building supports and foundations, 
laying underground pipe work and construction of permanent storage 
structures.'' We have added language to the definition that is 
currently not in the PSD definition with respect to multi-phased 
projects. We are proposing that for multi-phased projects, commencement 
of construction of one phase does not constitute commencement of 
construction of any later phase, unless each phase is ``mutually 
dependent'' on the other on a physical and chemical basis, rather than 
economic.
    The PSD regulations provide additional conditions beyond what 
constitutes commencement. Specifically, the regulations require that 
the owner or operator ``did not discontinue construction for a period 
of 18 months or more and completed construction within a reasonable 
time.'' (40 CFR 52.21(i)(4)(ii)(c). While ``reasonable time'' may vary 
depending on the type of project, we believe that with respect to 
renewable fuel facilities, a reasonable time to complete construction 
is no greater than 3 years from initial commencement of construction. 
We seek comment on the use of these definitions.
b. Definition and Boundaries of a Facility
    We propose that the grandfathering and deemed compliant exemptions 
apply to ``facilities.'' Our proposed definition of this term is 
similar in some respects to the definition of ``building, structure, 
facility, or installation'' contained in the PSD regulations in 40 CFR 
52.21. We have modified the definition, however, to focus on the 
typical renewable fuel plant. We therefore propose to describe the 
exempt ``facilities'' as including all of the activities and equipment 
associated with the manufacture of renewable fuel which are located on 
one property and under the control of the same person or persons.
c. Options Proposed in Today's Rulemaking
    We are proposing one basic approach to the grandfathering 
provisions and seeking comment on five additional options. The basic 
approach would provide an indefinite extension of grandfathering and 
deemed compliant status but with a limitation of the exemption from the 
20% GHG threshold to a baseline volume of renewable fuel. The five 
additional options for which we seek comment are: (1) Expiration of 
exemption for grandfathered and ``deemed compliant'' status when 
facilities undergo sufficient changes to

[[Page 24926]]

be considered ``reconstructed''; (2) Expiration of exemption 15 years 
after EISA enactment, industry-wide; (3) Expiration of exemption 15 
years after EISA enactment with limitation of exemption to baseline 
volume; (4) ``Significant'' production components are treated as 
facilities and grandfathered or deemed compliant status ends when they 
are replaced; and (5) Indefinite exemption and no limitations placed on 
baseline volumes.
i. Basic Approach: Grandfathering Limited to Baseline Volumes
    We are proposing and seeking comments on an option which generally 
limits the volume of any renewable fuel for which a grandfathered and 
deemed compliant facility can generate RINs without complying with the 
20% GHG reduction threshold to the capacity volume specified in a state 
or Federal air permit or the greater of nameplate capacity or actual 
production. This approach is similar to how we have treated small 
refiner flexibilities under our other fuel rules. As a sub-option to 
this approach, we also seek comment on a provision whereby facilities 
would lose their status if they switch to a process fuel or feedstock 
which results in an increase of GHG emissions.
(1) Increases in Volume of Renewable Fuel Produced at Grandfathered 
Facilities due to Expansion
    For facilities that commenced construction prior to December 19, 
2007, we are proposing to define the baseline volume of renewable fuel 
exempt from the 20% GHG threshold requirement to be the maximum 
volumetric capacity of the facility as allowed in any applicable state 
air permit or Federal Title V operating permit. If the capacity of a 
facility is not stipulated in such air permits, then the grandfathered 
volume is the greater of the nameplate capacity of the facility or 
historical annual peak production prior to enactment of EISA. Volumes 
greater than this amount which may typically be due to expansions of 
the facility which occur after December 19, 2007, would be subject to 
the 20% GHG reduction requirement in order for the facility to generate 
RINs for the incremental expanded volume. The increased volume would be 
considered as if produced from a ``new facility'' which commenced 
construction after December 19, 2007. Changes that might occur to the 
mix of renewable fuels produced within the facility would remain 
grandfathered as long as the overall volume fell within the baseline 
volume.
    The baseline volume would be defined as above for deemed compliant 
facilities with the exception that if the maximum capacity is not 
stipulated in air permits, then the exempt volume would be the maximum 
annual peak production during the plant's first three years of 
operation. In addition, any production volume increase that is 
attributable to construction which commenced prior to December 31, 2009 
would be exempt from the 20% GHG threshold, provided that the facility 
continued to use natural gas, biomass or a combination thereof for 
process energy. Because deemed compliant facilities owe their status to 
the fact that they use natural gas, biomass or a combination thereof 
for process heat, we propose that their status would be lost, and they 
would be subject to the 20% GHG threshold requirement, at any time that 
they change to a process energy source other than natural gas and/or 
biomass. Finally, because EISA limits deemed compliant facilities to 
ethanol facilities, we propose that if there are any changes in the mix 
of renewable fuels produced by the facility that only the ethanol 
volume remain grandfathered. We solicit comment, however, on whether 
the statute could be read to allow deemed compliant facilities to be 
treated the same as grandfathered facilities by allowing a mix of 
renewable fuels.
    Volume limitations contained in air permits may be defined in terms 
of peak hourly production rates or a maximum annual capacity. If they 
are defined only as maximum hourly production rates, they would need to 
be converted to an annual rate. We believe that assuming 24-hour per 
day production over 365 days per year (8,760 production hours) may 
overstate nameplate capacity. In other regulations that pertain to 
refinery operations, we have assumed a conversion rate of 90% of the 
total hours in a year (7884 production hours). We seek comment on what 
would be an appropriate conversion rate for renewable fuel facilities.
    The facility registration process (see Section III.C) would be used 
to define the baseline volume for individual facilities. Owners and 
operators would submit information substantiating the nameplate 
capacity of the plant, as well as historical annual peak capacity if 
such is greater than nameplate capacity. Subsequent expansions at a 
grandfathered that result in an increase in volume would subject the 
increase in volume to the 20% GHG emission reduction threshold (but not 
the original baseline volume). Thus, any new expansions would need to 
be designed to achieve the 20% GHG reduction threshold if the facility 
wants to generate RINs for that volume. Such determinations would be 
made on the basis of EPA-defined corn ethanol fuel pathway categories 
that are deemed to represent such 20% reduction. As an alternative 
approach to the greater of nameplate capacity or historical annual peak 
capacity, we seek comment on an approach in which the baseline volume 
is the actual volume of renewable fuel produced during the 2006 
calendar year, where adequate data is available. Since there has been a 
particularly high demand for ethanol in recent years, the use of 2006 
data may be a fair representation of the real production capacity for 
most plants. For plants that have not operated for an adequate shake 
down period, the information in the state or Federal air permit could 
be used and if this is not available, the nameplate capacity could be 
used. As mentioned above, deemed compliant facilities would be exempt 
from the 20% GHG threshold for baseline volumes and any additional 
volumes regarding which construction commenced prior to December 31, 
2009.
    We recognize, however, that some debottlenecking type changes may 
cause increases in volume that are within a plant's inherent capacity. 
To account for this in past regulations (e.g., 40 CFR 80.552 and 554) 
we allowed for an increase of 5% above the baseline volume. Based on 
conversations with builders of ethanol plants, however, such plants 
have often been debottlenecked to exceed nameplate capacity by 20% and 
sometimes much higher. We seek comment on whether we should allow a 10% 
tolerance on the baseline volume for which RINs can be generated 
without complying with the 20% GHG reduction threshold. Once that 10% 
increase in volume is exceeded, the total increase above baseline 
volume would then be subject to the 20% GHG reduction requirement in 
order to generate RINs. We also seek comment on tolerance values in the 
5 to 20% range.
    Our guiding philosophy of protecting historical business 
investments that were made to comply with the provisions of RFS1 is 
realized by allowing production increases within a plant's inherent 
capacity. At the same time, the alternative of requiring compliance 
with the 20% GHG reduction requirement for increases in volume above 
10% over the baseline volume, would place new volumes from 
grandfathered facilities on a level playing field with product from new 
grass roots facilities. We believe that a level playing field for new 
investments

[[Page 24927]]

is fair and consistent with the provisions of EISA.
(2) Replacements of Equipment
    If production equipment such as boilers, conveyors, hoppers, 
storage tanks and other equipment are replaced, it would not be 
considered construction of a ``new facility'' under this option of 
today's proposal--the baseline volume of fuel would continue to be 
exempt from the 20% GHG threshold. We discuss in a sub-option in 
III.B.3.c.i(4) below in which if the replacement unit uses a higher 
polluting fuel in terms of GHG emissions such replacement would render 
the facility a new facility, and it would no longer be exempt from the 
20% GHG threshold. We also solicit comment on an approach that would 
require that if coal-fired units are replaced, that the replacement 
units must be fired with natural gas or biofuel for the product to be 
eligible for RINs that do not satisfy the 20% GHG threshold.
(3) Registration, Recordkeeping and Reporting
    Facility owner/operators would be required to provide evidence and 
certification of commencement of construction. Owner/operators must 
provide annual records of process fuels used on a BTU basis, feedstocks 
used and product volumes. For facilities that are located outside the 
United States (including outside the Commonwealth of Puerto Rico, the 
U.S. Virgin Islands, Guam, American Samoa, and the Commonwealth of the 
Northern Mariana Islands) owners would be required to provide 
certification as well. Since the definition of commencement of 
construction includes having all necessary air permits, we would 
require that facilities outside the United States to certify that such 
facilities have obtained all necessary permits for construction and 
operation required by the appropriate national and local environmental 
agencies.
(4) Sub-Option of Treatment of Future Modifications
    We seek comment on a sub-option to the basic approach whereby 
facilities would lose their grandfathered status if they switch to a 
process fuel or feedstock which results in an increase of GHG 
emissions. Some facilities may keep production volumes the same, but 
change some or all of their feedstocks and energy sources, thus causing 
a facility's product to fall further below the GHG performance for the 
fuel pathway it produced at the time of enactment. We are therefore 
seeking comment on an approach to limit the initial grandfathering only 
for the fuel pathways that applied during 2007, when establishing the 
volume baseline. Table III.B.3.c.i-1 below presents a ranking of fuels 
and feedstock by fuel pathway in order of life cycle GHG emissions (as 
discussed further in Section VI.E). (Table III.B.3.c.i-1 is based on 
the table of fuel pathways contained in proposed regulations 40 CFR 
80.1426.) Since the majority of facilities under consideration in this 
portion of the rulemaking consists of ethanol plants, the table below 
is limited to those types. Any changes to a facility that shift it to a 
feedstock or use of a process energy source that results in higher GHG 
emissions on the basis of the ranking categories in Table III.B.3.c.i-1 
below would terminate the facility's grandfathered status.
    For example, an ethanol dry mill plant using natural gas for 
process heat, as well as combined heat and power (CHP), is ranked as 
``2'' in the table below. If the plant (or any portion of the plant) 
switches to coal, it is ranked as ``4''. The higher number indicates an 
increase in GHG emissions. Therefore in this example, the plant is 
considered to have undertaken a modification that increases GHG 
emissions, would render the facility as ``new'' and its grandfathered 
status would end. Similarly, replacements of equipment that worsen GHG 
emissions would also terminate grandfathered status. (For replacements 
of equipment that do not change the fuel, nor result in an increase in 
volume of renewable fuel, the grandfathered status of the plant would 
remain, as discussed in Section III.B.3.c.i(2) above.)

    Table III.B.3.c.i-1--Groups of Renewable Fuel Facilities by Fuel
                      Feedstock and Process Energy
------------------------------------------------------------------------
                                      Production process
            Feedstock                    requirements          Ranking
------------------------------------------------------------------------
Starch from corn, wheat, barley,   --Process heat derived              1
 oats, rice, or sorghum.            from biomass.
Starch from corn, wheat, barley,   --Dry mill plant........            2
 oats, rice, or sorghum.
                                   --All process heat
                                    derived from natural
                                    gas.
                                   --Combined heat and
                                    power (CHP).
                                   --Fractionation of
                                    feedstocks.
                                   --Dried distillers
                                    grains.
Starch from corn, wheat, barley,   --Dry mill plant........            3
 oats, rice, or sorghum.
                                   --All process heat
                                    derived from natural
                                    gas.
                                   --Wet distillers grains.
Starch from corn, wheat, barley,   --Dry mill plant........            4
 oats, rice, or sorghum.
                                   --All or part of process
                                    heat derived from coal.
                                   --Combined heat and
                                    power (CHP).
                                   --Fractionation of
                                    feedstocks.
                                   --Membrane separation of
                                    ethanol.
                                   --Raw starch hydrolysis.
                                   --Dried distillers
                                    grains.
Starch from corn, wheat, barley,   --Dry mill plant........            5
 oats, rice, or sorghum.
                                   --All or part of process
                                    heat derived from coal.
                                   --Combined heat and
                                    power (CHP).
                                   --Fractionation of
                                    feedstocks.
                                   --Membrane separation of
                                    ethanol.
                                   --Wet distillers grains.
Sugarcane sugar..................  --Process heat derived              1
                                    from sugarcane bagasse.
Sugarcane sugar..................  --Process heat derived              2
                                    from natural gas.
Sugarcane sugar..................  --Process heat derived              3
                                    from coal.
------------------------------------------------------------------------


[[Page 24928]]

    We considered whether improvements at a facility (i.e., a fuel 
switch from coal to natural gas) that still result in GHG performance 
less than 20% should be credited to allow the facility to increase its 
baseline volume. We decided not to propose such an approach because it 
would take away an incentive for new plants that achieve greater than 
20% GHG reduction to be constructed. As such, this would go against our 
guiding principle of providing equal opportunities for future 
investments in new plants.
    We recognize that there may be combinations of changes made at a 
plant, some of which may worsen GHG emissions and others which may 
cause an improvement and that not all such combinations can be taken 
into account in a single table of fuel pathways. We seek comment on 
ways to address such combinations.
ii. Alternative Options for Which We Seek Comment
(1) Facilities That Meet the Definition of ``Reconstruction'' Are 
Considered New
    An alternative approach on which we are seeking comment would 
consider whether a facility is effectively a ``new'' facility with 
respect to the costs incurred in maintaining the plant over time. 
Starting in 2010, we would require facility owners to report annually 
(specifically by January 31) to EPA the expenses for replacements, 
additions, and repairs undertaken at facilities since start up of the 
facility through the year prior to reporting. The Agency would then 
determine whether the degree of such activities warrants considering 
the facility as effectively ``new''. That substantial rebuilding or 
modernization may render an existing facility a new facility for 
regulatory purposes finds analogies in other Clean Air Act regulatory 
programs. For example, under the New Source Performance Standards 
(NSPS) equipment that has been ``reconstructed'' as defined in 40 CFR 
60.15 is considered new. Specifically, ``reconstruction'' is defined in 
40 CFR 60.15 as ``the replacement of components of an existing facility 
to such an extent that the fixed capital cost of the new components 
exceeds 50% of the fixed capital cost that would be required to 
construct a comparable entirely new facility. In addition to the NSPS 
program, regulations such as the recently promulgated standards for 
locomotive and marine engines (73 FR 25160; May 6, 2008) use a more 
encompassing concept of reconstruction and consider a vessel to be new 
if it is modified such that the value of the modifications exceeds 50% 
of the value of the modified vessel. We are seeking comment on an 
approach wherein upon the Agency's determination that costs of 
replacements, repairs and upgrades conducted since the start-up of the 
facility meet the test of ``reconstruction'' (i.e., the costs equal or 
exceed 50% of what it would cost to rebuild), that the facility would 
be considered effectively new, and would be subject to the 20% GHG 
reduction requirements.
    The application of the definition of reconstruction in the NSPS 
program occurs on an equipment-wide rather than on a plant-wide basis. 
Under this option, we would apply the concept of a ``new'' facility on 
a plant-wide basis similar to the approach we have taken in the 
recently promulgated locomotive and marine standards. We believe that a 
plant-wide approach is appropriate under RFS2 because it is not the 
emissions from individual pieces of equipment that are being regulated. 
Rather, the 20% GHG reduction standard applies to the renewable fuel 
produced by the facility, and it is logical to consider all of the 
equipment and structures at the facility involved in producing the 
product in evaluating when a grandfathered facility has been 
reconstructed. For these reasons, we believe that it would be 
reasonable to apply the definition of ``new'' on a plant-wide basis. 
Also, since upgrades, replacements and repairs will occur on an ongoing 
basis we would consider rebuilding or reconstruction to occur over time 
as the accumulation of all individual upgrades, replacements and 
repairs.
    The NSPS definition also requires that it be ``technologically and 
economically feasible for the reconstructed facility to meet applicable 
standards that apply to new facilities.'' We do not think that EISA 
requires this additional consideration, and also do not believe that 
there is any compelling public policy justification for allowing a 
reconstructed facility to continue to make renewable fuel that does not 
meet the 20% GHG reduction standard based upon a claim that it is 
technologically or economically infeasible. EPA's experience in the New 
Source Review (NSR) program has demonstrated that it is extremely 
difficult to clearly define what the terms ``technologically and 
economically feasible'' mean. Aside from such definitional 
difficulties, however, and as discussed in Section III.B.3.c.ii(2) 
below, we believe that it is technologically feasible to meet the 20% 
GHG reduction and with proper planning would be economically so, as 
well. Therefore, this alternative option would not require such a 
showing.
    Our assessment of whether a facility has been reconstructed would 
be based on application of an appropriate cost model such as U.S. 
Department of Agriculture's cost estimation model for construction of 
new ethanol plants described by Kwiatkowski, J. et al. (2006) \9\. 
Costs associated with the costs of repair and replacement of all parts 
(including the labor associated with replacement and repair), would be 
included in such calculation, regardless of the parts' intended useful 
life. We seek comment on whether to also include costs associated with 
employee labor related to routine maintenance, and also whether the 
costs of repairs and replacements at the facility should be limited 
only to the property directly related to the production of 
biofuels.\10\
---------------------------------------------------------------------------

    \9\ Kwiatkowski, J.R., McAloon, A., Taylor, F. Johnson, D. 2006. 
``Modeling the process and costs of fuel ethanol production by the 
corn dry-grind process.'' Industrial Crops and Products 23 (2006) 
288-296.
    \10\ We note that under NSPS the costs considered in determining 
whether the definition of reconstruction has been met are restricted 
to the capital costs of equipment and materials. The RFS2 program is 
authorized from EISA which does not rely on the definitions of 
``modification'' and ``routine maintenance and repair'' that are in 
NSPS and other new source programs (e.g., New Source Review, 
National Emission Standards for Hazardous Pollutants). Since our 
application of the term ``reconstruction'' assumes that over time, 
renewable fuel facilities may become substantially rebuilt it is 
therefore appropriate to consider not only equipment replacements 
but some of the labor costs associated with such replacements.
---------------------------------------------------------------------------

    Under this alternative option, the volume of renewable fuel that 
qualifies for an exemption from the 20% GHG threshold would remain 
fixed at the baseline volume as in the basic option described in 
III.B.3(c)(i). However, we also seek comment on whether the volume of 
renewable fuel at a grandfathered facility should be allowed to 
increase above baseline volumes under this option. Specifically, 
increases in volume could be exempt until such time as the entire plant 
is deemed to have been reconstructed. In making such assessment and 
applying the 50% test, the basis for the cost of a ``comparable 
entirely new facility'' would be a facility with the original baseline 
volume. For example, if an existing plant has a 100 million gallon per 
year capacity and expands its volume to 120 million gallons per year, 
reconstruction would occur if the costs incurred over time equal or 
exceed 50% of the cost of a comparable 100 million gallon per year 
facility.
    Under this alternative option, owner/operators or other responsible 
parties would be required to provide records of costs incurred for 
additions, replacements, and repairs that have

[[Page 24929]]

occurred since start-up. Such records would be provided on an annual 
basis to EPA by May 31, and would include cumulative cost information 
up to the prior year.
    We recognize that implementation of a facility-wide definition of 
``reconstruction'' would be complex. Records of costs since start-up 
may not be available for older facilities. Also, this alternative 
option requires EPA enforcement staff to have sufficient financial 
knowledge and experience to be able to evaluate the veracity of claims 
regarding various types of expenditures. Calculating the costs of 
repairs and replacements also poses challenges. Specifically, as 
discussed above, we seek comment on whether the costs of routine 
maintenance and repair should be included in such assessments. Were 
such costs to be included, the determination of whether a replacement 
or a repair is routine may not always be straightforward. In addition 
to the recordkeeping and implementation issues, however, there is an 
important policy consideration that is also significant. As in the case 
of the NSR program, where many industry representatives have argued 
that the program has a chilling effect on projects that could provide 
environmental benefits, the reconstruction approach in this alternative 
option could also provide a disincentive to implementation of safety 
and environmental projects. Thus, this option could have the unintended 
consequence of causing facilities to refrain from investing in projects 
that will increase safety and efficiency and reduce emissions in order 
to avoid triggering the 50% cost threshold. We seek comment on this 
issue.
(2) Expiration Date of 15 Years for Exempted Facilities
    The above discussion highlights potential complexities in 
implementing the option of considering reconstruction of exempted 
facilities on a case-by-case basis. These include potential disputes 
over how to calculate costs, as well as verifying records of 
expenditures. In addition, that option has as a potential unintended 
consequence, a disincentive for investment in projects that could 
improve safety, efficiency and environmental performance. As an 
alternative to the case-by case approach described above, this option 
offers a practical way of implementing the reconstruction concept by 
establishing an expiration date for all grandfathered and deemed 
compliant facilities after a period of 15 years from enactment of EISA 
(i.e., after December 31, 2022), regardless of when such facilities 
commenced construction or began operation. Under such option, the 
grandfathered and deemed compliant facilities would be subject to the 
20% GHG threshold starting on January 1, 2023. Renewable fuel produced 
from these facilities after this date would be required to comply with 
the 20% threshold requirement in order to generate RINs.
    Based on our discussions with companies that construct ethanol 
plants, we believe that facility owners will make decisions about 
equipment replacements and technology upgrades that will continue to 
improve the overall operating costs and energy efficiency of the plant 
which ultimately lead to improvements in GHG emission performance as 
well. In particular, energy-intensive processes in the plant are likely 
to be replaced or upgraded to increase fuel and operating efficiency, 
thus reducing operating costs of the plant, and increasing output. 
Nilles (2006) reports that the first line of next-generation dry-grind 
ethanol plants was built with mild steel components and that in 10 or 
15 years, those components will need to be replaced entirely--most 
likely with stainless steel. Of particular importance is that durable 
materials as well as weaker materials all require maintenance and 
replacement. As such, the components and equipment in ethanol 
facilities are designed to be easily replaced and to allow simple 
maintenance.\11\
---------------------------------------------------------------------------

    \11\ Nilles, D. 2006. ``Time Testing''; Ethanol Producer 
Magazine, May, Vol. 12, No. 5.
---------------------------------------------------------------------------

    Using cost data contained in the U.S. Department of Agriculture's 
cost estimation model for construction of new ethanol plants described 
by Kwiatkowski, J. et al (2006), we calculated the cost of a 
replacement of specific components in a hypothetical 100 million gallon 
ethanol facility.12 13 We assumed that all steel tanks are 
replaced with stainless steel tanks, and that specific combustion 
equipment is replaced. Combining replacement costs with maintenance, 
repairs, upgrades and supply costs (at 2% of the capital cost of the 
facility per year), we calculated that over 15 years, the accumulated 
costs range from 50% to 75% of the capital cost of an equivalent 
facility.\14\
---------------------------------------------------------------------------

    \12\ Op Cit., Kwiatkowski, et al. (2006).
    \13\ Note to Docket (EPA-HQ-OAR-2005-0161), ``Analysis of Costs 
of Replacements and Repairs at a Hypothetical 100 MM GPY Ethanol 
Facility''; from Barry Garelick, Environmental Protection 
Specialist, Assessment and Standards Division, Office of 
Transportation and Air Quality; October 16, 2008.
    \14\ The USDA model gives the installed capitol cost of a 40 
million GPY facility at approximately $60 million (2006 dollars). 
The model also gives replacement costs of individual components 
(steel tanks and the ring dryer) at about $13 million. Ongoing 
maintenance costs are estimated at about $6 million per year.
---------------------------------------------------------------------------

    As discussed in Section 1.5.1.3 of the DRIA, per our conversations 
with builders of ethanol plants, the changes and upgrades would be made 
to improve competitiveness which will also improve operating and fuel 
efficiency, thus tending to improve overall GHG performance of the 
plant. The high price of natural gas has many ethanol plants 
considering alternative fuel sources. Greater biofuel availability and 
potential low life cycle green house gas emissions incentives may 
further encourage ethanol producers to switch from fossil fuels for 
process heat to biomass based fuels. In addition, ethanol producers may 
consider energy saving changes to the ethanol production process. 
Several process changes, including raw starch hydrolysis, corn 
fractionation, corn oil extraction, and membrane separation, are likely 
to be adopted to varying degrees. Since such changes would be 
consistent with ultimately achieving the 20% GHG reduction required of 
new facilities, we believe it is reasonable to expect that the newly 
rebuilt facilities could meet the 20% GHG reduction threshold, based on 
the results of a life cycle analysis.\15\
---------------------------------------------------------------------------

    \15\ Unless and until EPA conducts facility specific life cycle 
analyses, however, compliance with the 20% GHG reduction threshold 
would be made on the basis of fuel pathways as described in Section 
III.D.2.
---------------------------------------------------------------------------

    We solicit further information and data, particularly evidence of 
the types of replacements and ongoing maintenance that has occurred at 
existing plants and what is projected to occur in the future. We will 
evaluate such information along with other comments received during the 
public comment period. We also solicit comment on whether a period 
other than 15 years may be more appropriate.
    Under this approach, facilities that are exempted could expand 
their volume of renewable fuel production, or could switch fuels or 
feedstocks within the 15 year exemption period without fear of losing 
their temporary exemption. While some of these activities have the 
potential to worsen GHG emissions further below the 20% threshold 
requirement, we believe that the imposition of an expiration date will 
result in modifications to facilities that tend to increase the 
efficiency and GHG performance of the plant rather than worsen them. 
The need for compliance with the 20% threshold requirement by a date 
certain would provide an incentive for owners and operators of

[[Page 24930]]

such plants to ensure the changes they make over time would bring them 
into compliance with the 20% requirement at the end of the 15 year 
period.
    While the facilities built in 2008 and 2009 would be in operation 
for less than 15 years, the majority of ethanol plants will have been 
in operation for 15 years or longer. As discussed in Section V.B.1, 
approximately 15 billion gallons of corn ethanol production capacity is 
currently online, idled or under construction. While some of these 
plants/projects are currently on hold due to the economy, we anticipate 
that this corn ethanol capacity will come online in the future under 
the proposed RFS2 program. And the majority of these plants commenced 
construction prior to 2008. We solicit comment, however, on whether 
there should be a plant-specific expiration date of 15 years after 
commencement of operations for deemed compliant facilities that 
commenced construction in 2008 or 2009. Under this sub-option, the 
expiration date for such plants would be 15 years from the time the 
facility began operation, per registration made by the owner of the 
facility.
    The option of limiting the exemption period to 15 years or other 
specific time period offers certainty to industry for a 15 year period, 
and also certainty that at the end of that time period they will be 
subject to the 20% GHG reduction threshold. This time period could be 
used by facility owners to ensure the facility will ultimately meet the 
requirement. Finally, the option ensures that investments made in 
equipment to comply with RFS1 requirements are protected with respect 
to being fully depreciated for tax purposes.\16\ Furthermore, this 
approach is easy to implement, and avoids case-by-case determinations 
that can extremely be time-consuming, contentious, and costly for both 
industry and EPA. In addition, because the exemption expiration date 
would apply to all facilities, this option would provide no incentive 
to delay modifications that increase energy efficiency, safety, or 
improve environmental performance unlike the option described above 
involving case-by-case consideration of reconstruction.
---------------------------------------------------------------------------

    \16\ Specifically, Table B-2 of IRS Publication 946, ``How To 
Depreciate Property'' provides class lives and recovery periods for 
use in computing depreciation for asset classes categorized by SIC 
codes. Ethanol facilities (which are in SIC 28, Manufacture of 
Chemical and Allied Products) is given a class life of 10 years. For 
facilities that qualify for Modified Accelerated Cost Recovery 
System (MACRS), the period is 7 years.
---------------------------------------------------------------------------

(3) Expiration Date of 15 Years for Grandfathered Facilities and 
Limitation on Volume
    We also seek comment on a hybrid approach in which an expiration 
date of 15 years is established for grandfathered and deemed compliant 
facilities, but prior to then, the facilities' exemption from the 20% 
GHG threshold would be limited to their baseline volumes, as in the 
option described in Section III.B.3.c.
(4) ``Significant Production Units'' Are Defined as Facilities
    We seek comment on an approach in which ``facility'' would be 
defined on the basis of ``significant production units''. For example, 
the regulations regarding air toxic emissions for the miscellaneous 
organic chemical manufacturing industry (which includes ethanol 
manufacturing plants) under NESHAPS (40 CFR 2440(c)) apply to 
miscellaneous chemical process units and heat exchangers within a 
single facility. This option, therefore, would follow a similar 
approach, and treat as new facilities subject to the 20% GHG reduction 
requirement any new significant production units.
    Defining ``facility'' as a significant production unit would raise 
the question of when an increase in volume due to the addition of 
specific pieces of equipment should be considered augmenting current 
production lines as opposed to being a new production line. We solicit 
comment on this approach as well as how the term ``significant 
production unit'' would need to be defined in the regulations to avoid 
ambiguity. Any incidental increases in volume due to the addition of 
pieces of equipment that would not constitute a new ``significant 
production unit'' line would continue to be grandfathered, as would 
increases in volume associated with changes made to debottleneck the 
facility.
(5) Indefinite Grandfathering and No Limitations Placed on Volume
    Under our basic option, described in Section III.B.3.c.i, we would 
interpret the statutory language to mean that expansions of 
grandfathered facilities after enactment of EISA and which expand 
volume beyond a plant's inherent capacity are not among those that 
qualify for an exemption from the 20% GHG reduction requirement. 
Otherwise, a facility that qualifies for grandfathering could be 
expanded by any amount, and the additional volume would also receive 
protection. We do not believe that this was the intent of the language 
in EISA. Nevertheless, we recognize that there are alternative 
interpretations of the statute and therefore seek comment on an 
alternative that places no limitations on the volume of renewable fuel 
from grandfathered or deemed compliant facilities. Under such option, 
``new facility'' would be defined solely as a new ``greenfield'' plant.
 4. Renewable Biomass With Land Restrictions
    As explained in Section III.B.1.a, EISA lists seven types of 
feedstock that qualify as ``renewable biomass'':
    1. Planted crops and crop residue.
    2. Planted trees and tree residue.
    3. Animal waste material and animal byproducts.
    4. Slash and pre-commercial thinnings.
    5. Biomass obtained from the vicinity of buildings at risk from 
wildfire.
    6. Algae.
    7. Separated yard or food waste.

    EISA limits not only the types of feedstocks that can be used to 
make renewable fuel, but also the land that several of these renewable 
fuel feedstocks may come from. Specifically, EISA's definition of 
renewable biomass incorporates land restrictions for planted crops and 
crop residue, planted trees and tree residue, slash and pre-commercial 
thinnings, and biomass from wildfire areas. EISA does not prohibit the 
production of renewable fuel feedstock that does not meet the 
definition of renewable biomass, nor does it prohibit the production of 
renewable fuel from feedstock that does not meet the definition of 
renewable biomass. It does, however, prohibit the generation of RINs 
for renewable fuel made from feedstock that does not meet the 
definition of renewable biomass, which includes not meeting the 
associated land restrictions. The following sections discuss the 
challenges of implementing the land restrictions contained in the 
definition of renewable biomass and propose approaches for establishing 
a workable implementation scheme.
a. Definitions of Terms
    EISA's descriptions of four feedstock types noted above--planted 
crops and crop residue, planted trees and tree residue, slash and pre-
commercial thinnings, and biomass from wildfire areas--contain terms 
that can be interpreted in multiple ways. The following sections 
discuss our proposed interpretations for many of the terms contained in 
EISA's definition of renewable biomass. In developing this proposal, we 
consulted many sources, including the USDA, as well as stakeholder 
groups, in order to

[[Page 24931]]

determine the range of possible interpretations for these different 
terms. We have made every attempt to define these terms as consistently 
with USDA and industry standards as possible, while keeping them 
workable for purposes of program implementation. We seek comment on our 
proposed definitions of important terms in the following sections.
i. Planted Crops and Crop Residue
    The first type of renewable biomass described in EISA is planted 
crops and crop residue harvested from agricultural land cleared or 
cultivated at any time prior to December 19, 2007, that is either 
actively managed or fallow, and nonforested. We propose to interpret 
the term ``planted crops'' to include all annual or perennial 
agricultural crops that may be used as feedstock for renewable fuel, 
such as grains, oilseeds, and sugarcane, as well as energy crops, such 
as switchgrass, prairie grass, and other species, providing that they 
were intentionally applied to the ground by humans either by direct 
application as seed or nursery stock, or through intentional natural 
seeding by mature plants left undisturbed for that purpose. Many energy 
crops that could be used for cellulosic biofuel production, especially 
perennial cover plants, are currently grown in the U.S. without 
significant agronomic inputs such as fertilizer, pesticides, or other 
chemical treatment. These crops may be introduced or indigenous to the 
area in which they grow, and may have been originally planted decades 
ago. We propose to include this type of vegetation as a planted crop 
with the recognition that it may include some plants that were 
intentionally naturally generated, i.e., resulted from natural seeding 
from existing plants, and not planted through direct human 
intervention. We believe that given the increasing importance under 
RFS2 of biofuels produced from cellulosic feedstocks, such as 
switchgrass and other grasses, such a definition is appropriate. We 
note that because EISA contains specific provisions for planted trees 
and tree residue from tree plantations, we propose that the definition 
of planted crops in EISA exclude planted trees, even if they may be 
considered planted crops under some circumstances.
    We further propose that ``crop residue'' be limited to the residue 
left over from the harvesting of planted crops, such as corn stover and 
sugarcane bagasse. However, we seek comment on an alternative 
interpretation that would include as crop residue biomass from 
agricultural land removed for purposes of invasive species control or 
fire management. In that context ``crop residue'' would include any 
biomass removed from agricultural land that facilitates crop 
management, whether or not the crop itself is part of the residue.
    Our proposed regulations would restrict planted crops and crop 
residue to that harvested from existing agricultural land. With respect 
to what land would qualify as agricultural land, we first turned to the 
mutually exclusive categories of land defined by USDA's Natural 
Resources Conservation Service (NRCS) in its annual Natural Resources 
Inventory (NRI), a statistical survey designed to estimate natural 
resource conditions and trends on non-federal U.S. lands.\17\ The 
categories used in the NRI are cropland, pastureland, rangeland, forest 
land, Conservation Reserve Program (CRP) land, federal land, developed 
land, and ``other rural land.'' We have chosen to include in our 
proposed definition of agricultural land three of these land 
categories--cropland, pastureland, and CRP land. Using the NRI 
descriptions of these land types as models, we developed definitions 
for these land types for this proposal.
---------------------------------------------------------------------------

    \17\ Natural Resource Conservation Service, USDA, ``Natural 
Resources Inventory 2003 Annual NRI,'' February 2007. Available at 
http://www.nrcs.usda.gov/technical/NRI/2003/Landuse-mrb.pdf.
---------------------------------------------------------------------------

    We propose to define cropland as land used for the production of 
crops for harvest, including cultivated cropland for row crops or 
close-grown crops and non-cultivated cropland for horticultural crops. 
Corn, wheat, barley, and soybeans are renewable fuel feedstocks that 
would be grown on cropland. We propose to define pastureland as land 
managed primarily for the production of indigenous or introduced forage 
plants for livestock grazing or hay production, and to prevent 
succession to other plant types. Under this proposed definition, land 
would qualify as pastureland if it is maintained for grazing or hay 
production and not allowed to develop greater ecological diversity. 
Switchgrass is one example of a renewable fuel feedstock that could be 
grown on pastureland.
    We also propose that CRP land be counted as ``agricultural land'' 
under RFS2. The CRP is administered by USDA's Farm Service Agency and 
is designed to promote restoration of environmentally sensitive lands 
by offering annual rental payments in return for removing land from 
cultivation over a period of several years. To qualify for the CRP, 
land had to have been used for agricultural production for at least 
three years prior to entering the program. For this reason, we believe 
it is appropriate to propose that CRP land be included under the rubric 
of agricultural land.
    In addition, we seek comment on whether rangeland should be 
included as agricultural land under RFS2. Rangeland is land on which 
the indigenous or introduced vegetation is predominantly grasses, 
grass-like plants, forbs or shrubs and which--unlike cropland or 
pastureland--is predominantly managed as a natural ecosystem. Given the 
relative lower degree of management of such lands, it is questionable 
whether any rangeland should qualify as ``actively managed'' under EISA 
(a general discussion on our proposed interpretation of the term 
``actively managed'' is presented later in this section). On the other 
hand, we understand that there is frequently some degree of management 
on such lands, such as controlling invasive species, managing grazing 
rates, fencing, etc.
    Therefore, we believe that there may be merit in allowing planted 
crops and crop residue from rangeland to qualify as renewable biomass 
under this program. This would allow, for example, existing switchgrass 
or native grasses on rangeland to be used for renewable fuel production 
that qualifies for RIN generation under this program. However, we are 
not proposing to include rangeland as agricultural land due to our own 
implementation concerns as well as issues raised by stakeholders over 
the potential for providing any incentive for increased crop production 
in rangeland areas. We seek comment on the issue and on the points 
raised in the following discussion.
    Allowing rangeland to qualify as agricultural land under RFS2 would 
make millions of acres of additional non-cropland, non-forested land 
qualify for renewable fuel feedstock production in the U.S. This 
additional land could be important to support future expansion of 
dedicated energy crops, such as switchgrass and tall prairie grass, 
which currently grow or could grow on such lands. The availability of 
rangeland could alleviate some of the competition on cropland and 
pastureland for space to grow crops for biofuel feedstocks, thereby 
allowing continued growth of food crops on land best suited for that 
specific purpose. It would also provide rangeland owners with the 
potential for increased revenues from their lands by producing 
feedstocks for renewable fuel, and decrease the pressure for such lands 
to be converted to cropland for food crop production.

[[Page 24932]]

    However, we recognize that rangeland is a term that can be used to 
describe a wide variety of ecosystems, including certain grasslands, 
savannas, wetlands, deserts, and even tundra. These types of ecosystems 
represent land that at best could serve only marginally well for 
producing renewable fuel feedstocks, and at worst could suffer 
significantly if intensive agricultural practices were imposed upon 
them for purposes of producing crops. We also recognize that if we were 
to include rangeland as agricultural land under RFS2, there is a risk 
that some rangeland, including native grasslands and shrublands, could 
be converted to produce monoculture crops. We raise these concerns for 
two reasons. First, certain rangeland cannot be used sustainably for 
agricultural crop production, and any such short-term use could 
seriously diminish the long-term potential of these lands to be used 
for less-intensive forage production or even to return to their 
previous ecological state. Second, conversion of relatively undisturbed 
rangeland to the production of annual crops could in some cases result 
in large releases of GHGs that have been stored in the soil. EPA 
believes that Congress enacted the renewable biomass definition in part 
to minimize GHG releases from land conversion, a goal that could be 
undermined by conversion of rangeland to intensive crop production 
under RFS2. On the other hand, it may be argued that while GHGs would 
be emitted initially, planting dedicated energy crops rather than food 
crops on such land could yield more positive than negative results over 
time. Such could be the case if the alternative were to grow energy 
crops on cropland, consequently displacing food crops to other lands, 
either in the U.S. or abroad. This displacement could lead to overall 
higher direct and indirect GHG emissions. EPA solicits comment on the 
potential GHG effects if rangeland were included as eligible 
agricultural land under RFS2. We are especially interested in data that 
could help us to quantify such impacts.
    While enforcement of the overall renewable biomass provisions under 
the final RFS2 program is expected to be challenging, it is possible 
that including rangeland as qualifying agricultural land under the RFS2 
program would increase enforcement complexity. As discussed later in 
this section, in order to qualify as renewable biomass under RFS2, 
agricultural products must come from agricultural land that was cleared 
or cultivated at any time prior to enactment of EISA, and either 
actively managed or fallow, and nonforested. We believe that evidence 
of past intensive use and management of rangeland may be considerably 
more rare, and considerably less definitive, than for other types of 
agricultural land. In addition, given the continuous, open nature of 
some rangeland, there would likely be difficulty in identifying the 
precise boundaries of a parcel of qualifying rangeland. EPA seeks 
comment on these issues.
    We thus seek comment on whether or not we should include rangeland 
in the definition of ``existing agricultural land'' in the final RFS2 
program, as well as comment on whether or not the benefits of including 
rangeland exceed the disadvantages. We also seek comment on how best to 
define rangeland, and whether we can define rangeland in a meaningful 
way such that sensitive ecosystems that may generally be described as 
rangeland can be protected from cultivation for renewable fuel 
feedstock production.
    Furthermore, EPA solicits comment on an alternative option that 
would include rangeland as agricultural land, but that would interpret 
the EISA ``actively managed'' criterion in the renewable biomass 
definition (again, discussed later in this section) to limit the types 
of planted crops or crop residues from specific parcels of land that 
can qualify as renewable biomass by reference to the type of management 
(cropland, pastureland, or rangeland) being practiced on the date EISA 
was enacted. For example, if at some point in the future corn or other 
row crops are grown on land that was pastureland or rangeland when EISA 
was enacted, such row crops would not qualify as renewable biomass 
under RFS2. This approach could thus reduce the incentives for 
pastureland and rangeland owners to convert their land to cropland. We 
believe that this approach could have less environmental harm than 
allowing unrestricted use of qualifying rangeland for the production of 
crops for renewable fuel production.
    While our proposed implementation approach and alternatives are 
presented later in this section, it is important to note here that the 
principal drawback to this alternative option involves its 
implementation and enforcement. This approach would require that land 
types (again, cropland, pastureland, or rangeland) be identified as of 
the date of EISA enactment in order to determine which feedstocks grown 
on such land would qualify as renewable biomass. In practical terms, 
such an approach may mean, for example, that a renewable fuel producer 
would need to be able to identify not only whether a given shipment of 
corn was grown on agricultural land cleared or cultivated prior to 
enactment of EISA, but also that the land was not previously 
pastureland or rangeland that had been converted to cropland after 
enactment of EISA. If it was, it would not qualify as renewable 
biomass. We are concerned that adding this additional feedstock 
verification criterion to those already contained in this proposal 
could render the program unworkable and unenforceable. However, we 
invite comment on this option, and specifically request comment on how 
this option could be implemented in a workable and enforceable manner.
    In keeping with the statutory definition for renewable biomass, we 
propose to include in our definition of existing agricultural land the 
requirement that the land was cleared or cultivated prior to December 
19, 2007, and that, since December 19, 2007, it has been continuously 
actively managed (as agricultural land) or fallow, and nonforested. We 
believe the language ``cleared or cultivated at any time'' prior to 
December 19, 2007, describes most cultivable land in the U.S., since so 
much of the country's native forests and grasslands were cleared in the 
17th, 18th, and 19th centuries, if not before, for agriculture. We 
further believe that land that was cropland, pastureland, or CRP land 
on December 19, 2007, would automatically satisfy this particular 
criterion, and that therefore it is not of significant concern from an 
implementation or enforcement perspective.
    In the event that we were to include rangeland as agricultural land 
under the final RFS2 program, satisfying the ``cleared or cultivated'' 
criterion could pose significant challenges. Some rangeland has never 
been cleared or cultivated, or may have been cleared or cultivated 
prior to December 19, 2007, but no evidence exists to confirm this. 
Therefore, we could not assume that it would necessarily meet the 
``cleared or cultivated'' criterion. For instance, grasslands in the 
Midwest and West that during the Dust Bowl of the 1930s had been used 
for cultivation could meet this criterion, but other western grasslands 
and prairies used for cattle grazing may not. We seek comment on how 
best to verify that rangeland to be used for renewable fuel feedstock 
production was cleared or cultivated at some point prior to December 
2007. We also seek comment on whether the challenge associated with 
applying this criterion to rangeland is sufficient (alone or combined 
with the concerns raised earlier about the inclusion of rangeland in 
the definition of agricultural land) to exclude rangeland

[[Page 24933]]

from the final definition of agricultural land.
    We believe that the more restrictive, and therefore more important, 
criteria is whether agricultural land is actively managed or fallow, 
and nonforested, per the statutory language. We propose to interpret 
the phrase ``that is actively managed or fallow, and nonforested'' as 
meaning that land must have been actively managed or fallow, and 
nonforested, on December 19, 2007, and continuously thereafter in order 
to qualify for renewable biomass production. We believe this 
interpretation of the legislative language is reasonable and 
appropriate for the following reason. The EISA language uses the 
present tense (``is actively managed * * *'') rather than the past 
tense to describe qualifying agricultural land. We interpret this 
language to mean that at the time the planted crops or crop residue are 
harvested (i.e., now or at some time in the future), the land from 
which they come must be actively managed or fallow, and nonforested. 
However, assuming that the land was cleared or cultivated at some point 
in time, then any land converted to agricultural land after December 
19, 2007, and used to produce crops or crop residue would inherently 
meet the definition of ``is actively managed or fallow, and 
nonforested,'' and the EISA land restriction for planted crops and crop 
residue would have little meaning (except in cases where it could be 
established that the land in question had never been cleared or 
cultivated). We believe that in order for this provision to have 
meaning, we must require that agricultural land remain ``continuously'' 
either actively managed or fallow, and nonforested, since December 19, 
2007. In this way, the upper bound on acreage that qualifies for 
planted crop and crop residue production under RFS2 would be limited to 
existing agricultural land--cropland, pastureland, or CRP land--as of 
December 19, 2007, and the phrase ``is actively managed or fallow, and 
nonforested'' would be interpreted in a meaningful way.
    We propose that ``actively managed'' would mean managed for a 
predetermined outcome as evidenced by any of the following: sales 
records for planted crops, crop residue, or livestock; purchasing 
records for land treatments such as fertilizer, weed control, or 
reseeding; a written management plan for agricultural purposes; 
documentation of participation in an agricultural program sponsored by 
a Federal, state or local government agency; or documentation of land 
management in accordance with an agricultural certification program. 
Examples of government programs or product certification programs that 
would indicate active agricultural land management include USDA's 
certified organic program or the Federal Crop Insurance program.
    We realize that it may be difficult to conclude that certain land 
has been actively managed continuously since December 2007 based solely 
on the existence of receipts for fertilizer or seed. However, we have 
included sales and purchasing records in the list of written 
documentation that could be used to indicate active management due to 
the fact that there may be qualifying land that is not registered with 
any formal agricultural program, for which the owner does not receive 
government benefits, and for which no written management plan exists 
(or existed as of December 2007). We believe this may be the case 
especially for pastureland from which no crops are harvested or sold. 
Other evidence that could be used regarding the consistent management 
of pastureland since December 2007 are records associated with the sale 
of livestock that grazed on the land. We seek comment on our proposal 
to include relevant records of sales and purchasing as adequate 
documentation to prove that land was actively managed since December 
2007 and whether there may be other records, such as tax or insurance 
records, which could satisfy this requirement more effectively.
    The term ``fallow'' is generally used to describe cultivated land 
taken out of production for a finite period of time. We believe it may 
be argued that fallow land is actively managed land because there is a 
clear purpose or goal for taking the land out of production for a 
period of time (e.g., to conserve soil moisture). Nonetheless, because 
the EISA language clearly identifies a difference between actively 
managed agricultural land and fallow agricultural land, we propose to 
define fallow to mean agricultural land that is intentionally left idle 
to regenerate for future agricultural purposes, with no seeding or 
planting, harvesting, mowing, or treatment during the fallow period. 
While fallow agricultural land is characterized by a lack of activity 
on the land, we believe that the decision to let land lie fallow is 
made deliberately and intentionally by a land owner or farmer such that 
there should be documentation of such intent. We seek comment on this 
assumption and on whether there are other means of verifying whether 
land was fallow, particularly as of December 2007. We also seek comment 
on whether we should specify in the regulations a time period after 
which land that is not actively managed for agricultural purposes 
should be considered to have been abandoned for agriculture (and not 
eligible for renewable biomass production under RFS2), as opposed to 
being left fallow. If specifying such a time limit is appropriate, we 
seek comment on what the time period should be, and if there should be 
a distinction between allowable fallow periods for different types of 
agricultural land.
    Finally, in order to define the term ``nonforested,'' we first 
propose to define the term ``forestland'' as generally undeveloped land 
covering a minimum area of 1 acre upon which the predominant vegetative 
cover is trees, including land that formerly had such tree cover and 
that will be regenerated. We are also proposing that forestland would 
not include tree plantations. Under this proposal, ``nonforested'' land 
would be land that is not forestland. We believe this definition is 
sufficient to make distinctions between forestland and land that is 
considered nonforested in the field. However, we seek comment on 
whether we should incorporate into our definition of forestland more 
quantitative descriptors, such as a minimum percentage of canopy cover 
or minimum or maximum tree height, to help clarify what would be 
considered forestland. For example, the NRI definition of forestland 
includes a minimum of twenty-five percent canopy cover. We also seek 
comment on whether the one-acre minimum size designation is 
appropriate.
ii. Planted Trees and Tree Residue
    The definition of renewable biomass in EISA includes planted trees 
and tree residue from actively managed tree plantations on non-federal 
land cleared at any time prior to December 19, 2007, including land 
belonging to an Indian tribe or an Indian individual, that is held in 
trust by the United States or subject to a restriction against 
alienation imposed by the United States. We propose to define the term 
``planted trees'' to include not only trees that were established by 
human intervention such as planting saplings and artificial seeding, 
but also trees established from natural seeding by mature trees left 
undisturbed for such a purpose. We understand that, depending on the 
particular conditions at a plantation, certain trees in a stand may be 
harvested, while others are maintained, for the express purpose of 
naturally regenerating new trees. We believe that trees established in 
such a fashion, and which meet the conditions for planted trees in 
every other way, should not be

[[Page 24934]]

excluded from qualifying as renewable biomass under RFS2.
    Rather than using the term ``tree residue,'' we propose to use the 
term ``slash'' in our regulations as a more descriptive, but otherwise 
synonymous, term. According to the Dictionary of Forestry (1998, p. 
168), slash is ``the residue, e.g., treetops and branches, left on the 
ground after logging or accumulating as a result of a storm, fire, 
girdling, or delimbing.'' We believe that this substitution will 
simplify our regulations, since paragraph (iv) of the EISA definition 
of renewable biomass also uses the term ``slash.'' Furthermore, the 
term ``slash'' is a common term that has a specific meaning to 
industry. As noted earlier, we have attempted to define terms in RFS2 
using existing and commonly understood definitions to the extent 
possible. The term ``slash'' is more descriptive than ``tree residue,'' 
and yet in practice means the same thing, so we are proposing to use it 
rather than ``tree residue.'' We also propose to clarify that slash can 
include tree bark and can be the result of any natural disaster, 
including flooding.
    In concert with our proposed definition for ``planted trees,'' we 
propose to define a ``tree plantation'' as a stand of no fewer than 100 
planted trees of similar age and comprising one or two tree species, or 
an area managed for growth of such trees covering a minimum of 1 acre. 
Given that only trees from a tree plantation may be used as renewable 
biomass under RFS2, we believe that the definition should be clear and 
easily applied in the field. We recognize that this proposed definition 
is more specific than the Dictionary of Forestry's definition of ``tree 
plantation,'' which is ``a stand composed primarily of trees 
established by planting or artificial seeding.'' We seek comment on all 
aspects of our proposed definition of tree plantation.
    We also propose to apply the same management restrictions on tree 
plantations as on agricultural land and to interpret the EISA language 
as requiring that to qualify for renewable biomass production under 
RFS2, a tree plantation must have been cleared at any time prior to 
December 19, 2007, and continuously actively managed since December 19, 
2007. Similar to our proposal for actively managed agricultural land, 
we propose to define the term ``actively managed'' in the context of 
tree plantations as managed for a predetermined outcome as evidenced by 
any of the following: Sales records for planted trees or slash; 
purchasing records for seeds, seedlings, or other nursery stock; a 
written management plan for silvicultural purposes; documentation of 
participation in a silvicultural program sponsored by a Federal, state 
or local government agency; or documentation of land management in 
accordance with an agricultural or silvicultural product certification 
program. Silvicultural programs such as those of the Forest Stewardship 
Council, the Sustainable Forestry Initiative, the American Tree Farm 
System, or USDA are examples of the types of programs that could 
indicate actively managed tree plantations.
iii. Slash and Pre-Commercial Thinnings
    The EISA definition of renewable biomass includes slash and pre-
commercial thinnings from non-federal forestlands, including 
forestlands belonging to an Indian tribe or an Indian individual, that 
are held in trust by the United States or subject to a restriction 
against alienation imposed by the United States. It excludes slash and 
pre-commercial thinnings from forests or forestlands that are 
ecological communities with a global or State ranking of critically 
imperiled, imperiled, or rare pursuant to a State Natural Heritage 
Program, old growth forest, or late successional forest.
    As described in Sec. III.B.4.a.i of this preamble, our proposed 
definition of ``forestland'' is generally undeveloped land covering a 
minimum area of 1 acre upon which the primary vegetative species are 
trees, including land that formerly had such tree cover and that will 
be regenerated. Also as noted in Sec. III.B.4.a.ii of this preamble, we 
propose to adopt the definition of slash listed in the Dictionary of 
Forestry. As for ``pre-commercial thinnings,'' the Dictionary of 
Forestry defines the act of such thinning as ``the removal of trees not 
for immediate financial return but to reduce stocking to concentrate 
growth on the more desirable trees.'' \18\ Because what may now be 
considered pre-commercial may eventually be saleable as renewable fuel 
feedstock, we propose not to include any reference to ``financial 
return'' in our definition, but rather to define pre-commercial 
thinnings as those trees removed from a stand of trees in order to 
reduce stocking to concentrate growth on more desirable trees. We 
propose to include diseased trees in the definition of pre-commercial 
thinnings due to the fact that they can threaten the integrity of an 
otherwise healthy stand of trees, and their removal can be viewed as 
reducing stocking to promote the growth of more desirable trees. We 
seek comment on whether our definition of pre-commercial thinnings 
should include a maximum diameter and, if so, what the appropriate 
maximum diameter should be.
---------------------------------------------------------------------------

    \18\ Helms, John, ed. ``The Dictionary of Forestry.'' Bethesda, 
MD: Society of American Foresters, 2003.
---------------------------------------------------------------------------

    We understand that the State Natural Heritage Programs referred to 
in EISA are those comprising a network associated with NatureServe, a 
non-profit conservation and research organization. The network includes 
local programs in each of the 50 United States, other U.S. territories 
and regions including the Navajo Nation and Tennessee Valley Authority, 
eleven Canadian provinces and territories, and eleven Latin American 
countries. Individual Natural Heritage Programs collect, analyze, and 
distribute scientific information about the biological diversity found 
within their jurisdictions. As part of their activities, these programs 
survey and apply NatureServe's rankings, such as critically imperiled 
(S1), imperiled (S2), and rare (S3) to species and ecological 
communities within their respective borders. NatureServe meanwhile uses 
data gathered by these Natural Heritage Programs to apply its global 
rankings, such as critically imperiled (G1), imperiled (G2), or 
vulnerable (the equivalent of the term ``rare,'' or G3), to species and 
ecological communities found in multiple States or territories. We 
propose to prohibit slash and pre-commercial thinnings from all forest 
ecological communities with global or State rankings of critically 
imperiled, imperiled, or vulnerable (``rare'' in the case of State 
rankings) from being used for renewable fuel for which RINs may be 
generated under RFS2. We seek comment on our interpretation that the 
statutory language implies including global rankings determined by 
NatureServe, including the ranking of vulnerable (G3), in the land 
restrictions under RFS2 since State Natural Heritage Programs, which 
were explicitly referenced in EISA, do not establish global rankings.
    The various state-level Natural Heritage Programs in the U.S. and 
abroad differ in organizational affiliation, with some operated as 
agencies of state or provincial government and others residing within 
universities or non-profit organizations. According to the NatureServe 
Web site, ``consistent standards for collecting and managing data allow 
information from different programs to be shared and combined 
regionally, nationally, and internationally. The nearly 800 staff from 
across the network are experts in their fields, and include some of the 
most knowledgeable field biologists and

[[Page 24935]]

conservation planners in their regions.'' Different Natural Heritage 
Programs have different processes for initiating and performing surveys 
of ecological communities. In many cases, the programs respond to 
requests for environmental reviews or surveys from parties interested 
in specific locations, oftentimes for a fee. They do not make available 
for public consumption detailed information on the location of a ranked 
ecological community in some cases to protect the communities 
themselves and in other cases to protect private property interests. 
Additionally, the datasets maintained by different Natural Heritage 
Programs may not completely represent all of the vulnerable ecological 
communities in their respective States or territories simply due to the 
fact that surveys have not been performed for all areas.
    NatureServe, however, interacts with each of the State Natural 
Heritage Programs to update their central database to include each 
State program's ecological community rankings. We propose to use data 
compiled by NatureServe and published in a special report to identify 
``ecologically sensitive forestland.'' The report would list all forest 
ecological communities in the U.S. with a global ranking of G1, G2, or 
G3, or with a State ranking of S1, S2, or S3, and would include 
descriptions of the key geographic and biologic attributes of the 
referenced ecological community. The document would be incorporated by 
reference into the definition of renewable biomass in the final RFS2 
regulations, and the effect would be to identify specific ecological 
communities from which slash and pre-commercial thinnings could not be 
used as feedstock for the production of renewable fuel that would 
qualify for RINs under RFS2. In the future, it may be necessary to 
update this list as appropriate through notice and comment rulemaking.
    We will place a draft version of this document in the docket for 
the proposed rule as soon as it is available. EPA solicits comment both 
on this general incorporation-by-reference approach and on each 
individual listing in the document. We also seek comment on whether EPA 
should include in the document forest ecological communities outside of 
the 50 United States (such as in Canada or Latin American countries) 
that have natural heritage rankings of G1, G2, or G3 or S1, S2, or S3. 
In addition, we request comment on other ways that EPA may be able to 
provide the protections that Congress intended for important ecological 
communities with state-level rankings pursuant to a State Natural 
Heritage Program.
    To complete the definition of ``ecologically sensitive 
forestland,'' we propose to include old growth and late successional 
forestland which is characterized by trees at least 200 years old.\19\ 
We seek comment on this definition, including the proposed 200-year 
tree age, on whether we should specify a process for determining when a 
forest is ``characterized by'' trees of this or another age, and on 
other ways to identify old growth or late successional forestland.
---------------------------------------------------------------------------

    \19\ Old-growth forest is defined in the Dictionary of Forestry 
as ``the (usually) late successional stage of forest development. 
Note: Old-growth forests are defined in many ways; generally, 
structural characteristics used to describe old-growth forests 
include (a) live trees: Number and minimum size of both seral and 
climax dominants, (b) canopy conditions: Commonly including 
multilayering, (c) snags: Minimum number of specific size, and (d) 
down logs and coarse woody debris: Minimum tonnage and numbers of 
pieces of specific size. Note: Old-growth forests generally contain 
trees that are large for their species and site and sometimes 
decadent (overmature) with broken tops, often a variety of trees 
sizes, large snags and logs, and a developed and often patchy 
understory * * *.''
---------------------------------------------------------------------------

iv. Biomass Obtained From Certain Areas at Risk From Wildfire
    The EISA definition of renewable biomass includes biomass obtained 
from the immediate vicinity of buildings and other areas regularly 
occupied by people, or of public infrastructure, at risk from wildfire. 
We propose to clarify in the regulations that ``biomass'' is organic 
matter that is available on a renewable or recurring basis, and that it 
must be obtained from within 200 feet of buildings, campgrounds, and 
other areas regularly occupied by people, or of public infrastructure, 
such as utility corridors, bridges, and roadways, in areas at risk of 
wildfire. We propose to define ``areas at risk of wildfire'' as areas 
located within--or within one mile of--forestland, tree plantations, or 
any other generally undeveloped tract of land that is at least one acre 
in size with substantial vegetative cover.
    It is our understanding that 100 to 200 feet is the minimum 
distance recommended for clearing trees and brush away from homes and 
other property in certain wildfire-prone areas, depending on slope and 
vegetation.\20\ We propose that under RFS2, the term ``immediate 
vicinity'' would mean within 200 feet of a given structure or area, but 
we seek comment on the appropriateness of limiting the distance to 
within 100 feet.
---------------------------------------------------------------------------

    \20\ See Cohen, Jack. ``Reducing the Wildland Fire Threat to 
Homes: Where and How Much?'' USDA Forest Service Gen.Tech.Rep. PSW-
GTR-173. 1999. See also U.S. Federal Emergency Management Agency 
(FEMA) Web site http://www.fema.gov/hazard/wildfire/index.shtm.
---------------------------------------------------------------------------

    A great deal of work has been done to identify communities and 
areas on the landscape in the vicinity of public lands that are at risk 
of wildfire by States in cooperation and consultation with the U.S. 
Forest Service, Bureau of Land Management, and other federal, State, 
and local agencies and tribes. In order to take advantage of this work, 
we seek comment on two possible implementation alternatives. The first 
alternative would incorporate into our definition of ``areas at risk of 
wildfire'' any communities identified as ``communities at risk'' 
through a process defined within the ``Field Guidance--Identifying and 
Prioritizing Communities at Risk'' (National Association of State 
Foresters, June 2003) and covered by a community wildfire protection 
plan (CWPP) developed in accordance with ``Preparing a Community 
Wildfire Protection Plan--A Handbook for Wildland-Urban Interface 
Communities'' (Society of American Foresters, March 2004) and certified 
by a State Forester or equivalent. We believe that it may make sense to 
include communities with CWPPs in the definition of ``areas at risk of 
wildfire'' since they represent specific areas around the U.S. that are 
identified and agreed upon through a public process that includes local 
and state representatives, federal agencies, and stakeholders. 
Additionally, CWPP guidelines indicate that normally three entities 
must mutually agree to the contents of the CWPPs: The applicable local 
government, the local fire department or departments, and the state 
entity responsible for forest management (State Forester or 
equivalent). As of June 2008, there were roughly 52,000 total 
``communities at risk'' and 5,000 ``communities at risk'' covered by a 
CWPP.
    We seek comment on incorporating by reference into the final RFS2 
regulations a list of ``communities at risk'' with an approved CWPP. 
Similar to the document proposed for Natural Heritage Rankings, this 
document would be incorporated by reference into the definition of 
``areas at risk of wildfire'' in the final RFS2 regulations. Because 
this list does not currently exist, EPA would be required to seek data 
from each State in order to assemble the document. The effect of this 
incorporation by reference would be to identify specific areas in the 
U.S. at risk of wildfire and from which biomass obtained from the 
immediate vicinity of buildings and other areas regularly occupied by 
people, or of public infrastructure, could be easily identified

[[Page 24936]]

and documented as renewable biomass. In the future, it may be necessary 
to update this list as appropriate through notice and comment 
rulemaking.
    The second implementation approach on which we seek comment would 
incorporate into our definition of ``areas at risk of wildfire'' any 
areas identified as wildland urban interface (WUI) land, or land in 
which houses meet wildland vegetation or are mixed with vegetation. The 
concept of the WUI was established as part of the Healthy Forests 
Restoration Act (Pub. L. 108-148) which provided a means for 
prioritizing, planning, and executing hazardous fuels reduction 
projects on federal lands. SILVIS Lab, in the Department of Forest 
Ecology and Management and the University of Wisconsin, Madison, has, 
with funding provided by the U.S. Forest Service, mapped WUI lands 
based on data from the 2000 U.S. Census and U.S. Geological Survey 
National Land Cover Data.\21\ We seek comment on whether and how best 
to make use of this WUI map and data to help implement the land 
restrictions for biomass obtained from areas at risk of wildfire under 
RFS2.
---------------------------------------------------------------------------

    \21\ See http://silvis.forest.wisc.edu/projects/US_WUI_2000.asp.
---------------------------------------------------------------------------

b. Issues Related to Implementation and Enforceability
    Incorporating the new definition of renewable biomass into the RFS2 
program raises issues that we did not have to consider when designing 
the RFS1 program. Under RFS1, the source of a renewable fuel feedstock 
was not a central concern, and it was a relatively straightforward 
matter to require all fuel made from specified renewable feedstocks to 
be assigned RINs. However, with the terms ``renewable fuel'' and 
``renewable biomass'' being defined differently under EISA, we must 
consider potential issues related to implementation and enforcement to 
ensure that renewable fuel for which RINs are generated is produced 
from qualifying renewable biomass.
    Our proposed approach to the treatment of renewable biomass under 
RFS2 is intended to define the conditions under which RINs can be 
generated as well as the conditions under which renewable fuel can be 
produced or imported without RINs. Both of these areas are described in 
more detail below.
i. Ensuring That RINs Are Generated Only for Fuels Made From Renewable 
Biomass
    The effect of adding EISA's definition of renewable biomass to the 
RFS program is to ensure that renewable fuels are only allowed to 
participate in the program if the feedstocks from which they were made 
come from certain types of land. In the context of our regulatory 
program, this means that RINs could only be generated if it can be 
established that the feedstock from which the fuel was made came from 
these types of lands. Otherwise, no RINs could be generated to 
represent the renewable fuel produced or imported.
    We have considered the possibility that land restrictions contained 
within the definition of renewable biomass may not, in practice, result 
in a significant change in agricultural practices. For example, a 
farmer wishing to expand his production by cutting forested land could 
grow feedstock for renewable fuel on his existing agricultural land and 
move production for food, animal feed, and fiber production to newly 
cultivated land. While the EISA language is fairly clear about what 
lands may be used for harvesting renewable fuel feedstocks, it does not 
specifically address the potential for switching non-feedstock crops to 
new lands. Our proposed options recognize the potential for this 
behavior but do not attempt to prohibit it as we believe doing so would 
be beyond our mandate under EISA. EPA believes that Congress would have 
specifically directed EPA to regulate this practice if they intended 
EPA to do so.
    Another major issue we have considered is the treatment of 
domestically produced renewable fuel feedstocks versus imported 
feedstocks and imported renewable fuel, since the new EISA language 
does not distinguish between domestic renewable fuel feedstocks and 
renewable fuel and feedstocks that come from abroad. Under RFS1, RINs 
must be generated for imported renewable fuel by the renewable fuel 
importer. Foreign renewable fuel producers may not participate as 
producers in the program (i.e., may not generate RINs for their fuel) 
unless they produce cellulosic biomass or waste-derived ethanol and 
register with EPA. Because RFS1 does not define renewable fuel by its 
source, assigning RINs to imported renewable fuel under RFS1 is a 
straightforward responsibility of the importer.
    However, under RFS2, ensuring that the feedstock used to produce 
imported renewable fuel meets the definition of renewable biomass 
presents additional challenges to designing a program that can apply to 
both domestic and imported renewable fuel. The options contained in 
today's proposal attempt to address this additional constraint, as 
discussed in Section III.B.4.d of this preamble.
ii. Ensuring That RINs Are Generated for All Qualifying Renewable Fuel
    Under RFS1, virtually all renewable fuel is required to be assigned 
a RIN by the producer or importer. This requirement was developed and 
finalized in the RFS1 rulemaking in order to address stakeholder 
concerns, particularly from obligated parties, that the number of 
available RINs should reflect the total volume of renewable fuel used 
in the transportation sector in the U.S. and facilitate program 
compliance. The only circumstances under which a batch of fuel is not 
assigned a RIN in RFS1 is if the feedstock used to produce the fuel is 
not among those listed in the regulatory definition of renewable fuel 
at Sec.  80.1101(d), the producer or importer of the fuel produces or 
imports less than 10,000 gallons per year, or the fuel is produced and 
used for off-road or other non-motor vehicle purposes. As a result, we 
believe that almost all renewable fuel produced or imported into the 
U.S. is assigned RINs under the RFS1 program, and thus the number of 
RINs available to obligated parties represents as accurately as 
possible the volume of renewable fuel being used in the U.S. 
transportation sector.
    EISA has dramatically increased the mandated volumes of renewable 
fuel that obligated parties must ensure are produced and used in the 
U.S. At the same time, EISA makes it more difficult for renewable fuel 
producers to demonstrate that they have fuel that qualifies for RIN 
generation by restricting qualifying renewable fuel to that made from 
``renewable biomass,'' defined to include restrictions on the types of 
land from which feedstocks may be harvested, as discussed in this 
section. The inclusion of such land restrictions under RFS2 may mean 
that, in some situations, a renewable fuel producer would prefer to 
forgo the benefits of RIN generation to avoid the cost and difficulty 
of ensuring that its feedstocks qualify for RIN generation. If a 
sufficient number of renewable fuel producers acted in this way, it 
could lead to a situation in which not all qualifying fuel is assigned 
RINs, thus resulting in a short RIN market that could force obligated 
parties into non-compliance. Another possible outcome would be that the 
demand for and price of RINs would increase significantly, making 
compliance by obligated parties more costly and difficult than 
necessary and raising prices for consumers.
    In order to avoid situations in which obligated parties cannot 
comply with

[[Page 24937]]

their annual RVOs and the volume mandates in EISA are not met, or 
instances where the requirements are met but at an inflated price, we 
believe that our proposal should ensure that RINs are generated for all 
fuel made from feedstock that meets the definition of renewable biomass 
and which meets the GHG emissions reduction thresholds set out in EISA. 
This would require eliminating any incentive for renewable fuel 
producers to avoid ascertaining where their feedstocks come from. As 
described in Section III.B.4.d below, we propose to require a 
demonstration of the type of land used to produce any feedstock used in 
the production of renewable fuel, regardless of whether RINs are 
generated or not, and to require that RINs be generated for all 
qualifying fuel.
    However, we also seek comment on an alternative approach wherein a 
renewable fuel producer would not be required to make any demonstration 
with regard to the origin of feedstocks used in fuel production if the 
fuel producer were not generating RINs. In this situation, we would 
rely on the price of RINs in the market to encourage renewable fuel 
producers to generate RINs where possible. This approach would have the 
advantage of lessening the regulatory burden for renewable fuel 
producers using feedstock that is not renewable biomass, and would 
generally simplify the regulations relating to implementation of the 
renewable biomass definition. The disadvantage to this approach, as 
discussed above, would be the increased potential for a RIN shortage 
caused by renewable fuel producers choosing not to generate RINs for 
qualifying renewable fuel and a concurrent increase in the price of 
RINs that do exist. Under such circumstances, it is likely that some 
obligated parties could not acquire sufficient RINs for compliance 
purposes, while others could comply but at an inflated cost.
    A further step that we could take to streamline not just the 
implementation of the renewable biomass definition, but also the 
tracking and trading of RINs, would be to remove the restriction 
established under the RFS1 rule requiring that RINs be assigned to 
batches of renewable fuel and transferred with those batches. Instead, 
renewable fuel producers could sell RINs (with a K code of 2 rather 
than 1) separately from volumes of renewable fuel. While this 
alternative approach could potentially place obligated parties at 
greater risk of market manipulation by renewable fuel producers, it 
could also provide a greater incentive for producers to demonstrate 
that the renewable biomass definition has been met for their 
feedstocks. That is, by having the flexibility to sell RINs independent 
from volume, producers could potentially command higher prices for 
those RINs. This would make RINS more valuable to them, and provide an 
incentive to generate as many RINs as possible. As a result, producers 
would be motivated to demonstrate that their feedstocks meet the 
renewable biomass definition. However, this approach could also 
increase compliance costs for obligated parties. For further discussion 
of this approach, see Section III.H.4.
c. Review of Existing Programs
i. USDA Programs
    To inform our approach for designing an implementation scheme for 
the renewable biomass land restrictions under RFS2, we reviewed a 
number of programs and models that track, certify, or verify 
agricultural and silvicultural products or land use in the U.S. and 
abroad. First we looked at several existing programs administered by 
USDA that involve data collection from agricultural land owners, 
farmers, and forest owners. However, while USDA obtains and maintains 
valuable data from agricultural land owners, producers, and forest 
owners for assessing the status of agricultural land, forest land, and 
other types of land that could be used for renewable fuel feedstock 
production, Section 1619 of the Food, Conservation, and Energy Act of 
2008 (the 2008 Farm Bill) and policies of certain USDA agencies 
significantly limit EPA's ability to access such data in a timely and 
meaningful way. Given that agricultural land owners, producers, and 
forest owners already report a great deal of information to USDA, 
having access to such information could enable EPA to avoid having to 
require duplicative reporting or recordkeeping and thereby minimize any 
burden that RFS2 may place on parties in the renewable fuel feedstock 
supply chain, from feedstock producer to renewable fuel producer, while 
still allowing us to ensure that the land restrictions on renewable 
biomass production are adhered to. We request comment on how EPA could 
acquire the type of information submitted by parties such as 
agricultural land owners, producers, and forest owners to USDA agencies 
in order to aid in administering RFS2. Having access to such 
information could be valuable to EPA in informing our enforcement 
actions.
ii. Third-Party Programs
    To inform our options for how we might verify and track renewable 
biomass, we also explored non-governmental, third-party verification 
programs used for certifying and tracking agricultural and forest 
products from point of origin to point of use both within the U.S. and 
outside the U.S. The United Kingdom and the EU are looking to such 
third-party verification programs to implement the sustainability 
provisions of their biofuels programs. There is no third-party 
organization that certifies agricultural land, managed tree 
plantations, and forests; rather, each generally focuses on one area. 
Due to this constraint, we examined third party organizations that 
certify specific types of biomass from croplands and organizations that 
certify forest lands.
    We examined third-party organizations that focus on a particular 
type of feedstock used for renewable fuel production, including the 
Roundtable on Sustainable Palm Oil and the Basel Criteria for 
Responsible Soy Production. These initiatives have outlined traceable 
certification programs for industry to follow. Two other cooperative 
organizations whose primary concern is renewable fuel production from 
biomass are the Roundtable on Sustainable Biofuels (RSB) and the Better 
Sugarcane Initiative (BSI). At present, the RSB and BSI are still in 
their developmental stages and do not have fully developed 
certification processes.
    We also examined the work of the international Soy Working Group, 
comprised of representatives from industry, the Brazilian government, 
and international non-governmental organizations (NGOs), which recently 
announced a one-year extension of a moratorium on the use of soy 
harvested from recently deforested lands in the Brazilian Amazon. This 
moratorium is the result of a negotiated voluntary agreement through 
which companies that purchase Brazilian soy work with their suppliers 
to ensure that they source their soy from farms cultivated prior to 
August 2006. The Brazilian Association of Vegetable Oil Industries 
(ABIOVE) and Brazil's National Association of Grain Exporters (ANEC) 
have used aerial photography to identify whether any newly deforested 
areas were used to grow soy, and Greenpeace, one of the NGOs involved 
in the agreement, uses satellite imagery and aerial photography to 
perform spot checks for enforcement purposes.
    Another new example of a renewable fuel feedstock verification 
system is the

[[Page 24938]]

Verified Sustainable Ethanol initiative, which established a series of 
criteria for ethanol produced in Brazil and sold to Swedish ethanol 
importer SEKAB. The Brazilian sugarcane ethanol industry trade 
association, UNICA, its member companies, and SEKAB established the 
criteria to promote environmental and social sustainability of 
sugarcane ethanol exported to Sweden. The agreement is between 
companies, and it relies on a third-party auditor to inspect Brazilian 
feedstock and ethanol production facilities to verify compliance with 
the criteria.
    We also examined third-party organizations that specialize in 
certifying sustainable forest lands. The Sustainable Agriculture 
Network (SAN), through the Rainforest Alliance, provides comprehensive 
certification of wooded areas used for commercial development through 
sustainable processes in the United States and Latin American 
countries. The SAN certifies approximately 10 million acres of land 
worldwide, with minimal agricultural land certified in the U.S.\22\
---------------------------------------------------------------------------

    \22\ Forest acreage taken from USDA Economic Research Service, 
Major uses of Land in the United States, 2002, Economic Information 
Bulletin No. (EIB-14), May 2006.
---------------------------------------------------------------------------

    We examined the certification process of the Forest Stewardship 
Council (FSC) because of their international recognition for certifying 
sustainable forests and their recordkeeping requirement for ``chain of 
supply'' certification for products. The FSC certifies 22 million acres 
of land in the U.S. according to certification standards designed for 
nine separate regions within the U.S., and it provides an example for 
chain-of-custody and product segregation requirements.\23\ Finally, we 
examined the American Tree Farm program and Sustainable Forestry 
Initiative (SFI).
---------------------------------------------------------------------------

    \23\ FSC certified acreage taken from FSC-US, Prospectus, 2005.
---------------------------------------------------------------------------

    The criteria used to certify participants through third-party 
verification systems are overall more comprehensive and generally more 
stringent than the land restrictions contained within the definition of 
renewable biomass. However, three issues emerged through our 
investigation of these existing third-party verification systems that 
would make it difficult to adopt or incorporate any one of them into 
our regulations for the land restriction provisions under EISA. First, 
as previously noted, many of these third-party certifiers are limited 
in the scope of products that they certify. Second, the acreage of 
agricultural land or actively managed tree plantations certified 
through third parties in the U.S. covers only a small portion of the 
total available land and forests estimated to qualify for renewable 
biomass production under the EISA definition. Third, none of the 
existing third-party systems had definitions or criteria that perfectly 
matched the land use definitions and restrictions contained in the EISA 
definition of renewable biomass. Thus, we have determined that at this 
time we cannot rely on any existing third-party verification program 
solely to implement the land restrictions on renewable biomass under 
RFS2. We believe there is potential benefit in utilizing third-party 
verification programs if these issues can be addressed, and in the 
following section we offer one possible scenario as an implementation 
alternative. Nonetheless, we seek comment on our conclusion that there 
are currently no appropriate third-party verification systems for 
renewable biomass that could be adopted under RFS2. We further seek 
comment on whether any existing program or combination of programs 
would be able to meet the definitions and adopt the land restriction 
criteria proposed for RFS2 to assist industry in meeting their 
obligations under this proposed program.
d. Approaches for Domestic Renewable Fuel
    Consistent with RFS1, renewable fuel producers would be responsible 
for generating RINs under RFS2. In order to make a determination 
whether or not their fuel is eligible for RINs, renewable fuel 
producers would need to have at least basic information about the 
origin of their feedstock. The following approaches for implementing 
the land restrictions on renewable biomass contained in EISA illustrate 
the variety of ways that renewable fuel feedstocks could be handled 
under RFS2. These options are presented singly, but we seek comment on 
how they might be combined to create the most appropriate, practical, 
and enforceable implementation scheme for renewable biomass under RFS2.
    One approach for ensuring that producers generate RINs properly 
would be for EPA to require that renewable fuel producers obtain 
documentation about their feedstocks from their feedstock supplier(s) 
and take the measures necessary to ensure that they know the source of 
their feedstocks and can demonstrate to EPA that they have complied 
with the EISA definition of renewable biomass. Under this approach, EPA 
would require renewable fuel producers who generate RINs to certify on 
their renewable fuel production reports that the feedstock used for 
each renewable fuel batch meets the definition of renewable biomass. We 
would require renewable fuel producers to maintain sufficient records 
to support these claims. Specifically, renewable fuel producers who use 
planted crops or crop residue from existing agricultural land, or who 
use planted trees or slash from actively managed tree plantations, 
would be required to have copies of their feedstock producers' written 
records that serve as evidence of land being actively managed (or 
fallow, in the case of agricultural land) since December 2007, such as 
sales records for planted crops or trees, livestock, crop residue, or 
slash; a written management plan for agricultural or silvicultural 
purposes; or, documentation of participation in an agricultural or 
silvicultural program sponsored by a Federal, state or local government 
agency. In the case of all other biomass, we would require renewable 
fuel producers to have, at a minimum, written certification from their 
feedstock supplier that the feedstock qualifies as renewable biomass. 
We seek comment on whether we should also require renewable fuel 
producers that use slash and pre-commercial thinnings from non-federal 
forestland and biomass from areas at risk of wildfire to maintain 
additional records to support the claim that these feedstocks meet the 
definition of renewable biomass. These records could include sworn 
statements from licensed or registered foresters, contracts for tree or 
slash removal or documentation of participation in a fire mitigation 
program. We seek comment on other methods of verifying renewable fuel 
producers' claims that feedstocks qualify for these categories of 
renewable biomass. A review of such records would become part of the 
producer's annual attest engagement, the annual audit of their records 
by an independent third party (see Section IV.A for a full discussion 
of attest engagement requirements).
    A renewable fuel producer would only be permitted to produce and 
sell renewable fuel without RINs if he demonstrates that the feedstocks 
used to produce his fuel do not meet the definition of renewable 
biomass. This approach would ensure that renewable fuel producers could 
not avoid the generation of RINs simply by failing to make a 
demonstration regarding the land used to produce their feedstocks. 
Thus, renewable fuel producers would be required to keep records of 
their feedstock source(s), regardless of

[[Page 24939]]

whether RINs were generated or not. At a minimum, renewable fuel 
producers who do not generate RINs would need to have certification 
from their feedstock supplier that their feedstock does not meet the 
definition of renewable biomass. In the event that some portion of a 
load of feedstock does meet the definition of renewable biomass and 
some portion does not, the renewable fuel producer would need to 
maintain documentation from their supplier that states the percentage 
of each portion. All of these records would be included as part of the 
renewable fuel producer's annual attest engagement. The renewable fuel 
producer would also indicate on his renewable fuel production report 
that he did not generate RINs for fuel made from feedstock that did not 
meet the definition of renewable biomass.
    Some stakeholders have expressed concern about EPA specifying the 
records that a renewable fuel producer must obtain from their feedstock 
supplier. We therefore seek comment on an approach that would require 
renewable fuel producers to certify on their renewable fuel production 
reports that their feedstock either met or did not meet the definition 
of renewable biomass and would require producers to maintain sufficient 
records to support their claims, but would stop short of specifying 
what those records would have to include. We anticipate that a large 
portion of feedstocks that qualify as renewable biomass will be 
obtained from existing agricultural land or actively managed tree 
plantations, for which, by definition, documentation already exists. We 
believe that, in most other cases, feedstock producers will have or 
will be able to create other forms of documentation that could be 
provided to renewable fuel producers in order to provide adequate 
assurance that the feedstock in question meets the definition of 
renewable biomass. As described above, there are many existing 
programs, such as those administered by USDA and independent third-
party certifiers, that could be useful to verify that feedstock from 
certain land qualifies as renewable biomass.
    We anticipate that these self-certification approaches would result 
in renewable fuel producers amending their contracts and altering their 
supply chain interactions to satisfy their need for documented 
assurance and proof about their feedstock's origins. Enforcement under 
either of these approaches would rely in part on EPA's review of 
renewable fuel production reports and attest engagements of renewable 
fuel producers' records. EPA would also consult other data sources, 
including any data made available by USDA, and could conduct site 
visits or inspections of feedstock producers' and suppliers' 
facilities. We seek comment on the feasibility and practical 
limitations of EPA working with publicly available USDA data to keep 
track of significant land use changes in the U.S. and around the world 
and to note general increases in feedstock supplier productivity that 
might signal cultivation of new agricultural land for renewable fuel 
feedstock production.
    Either of these approaches would easily fold into existing and 
newly proposed registration, recordkeeping, reporting, and attest 
engagement procedures. They would also place the burden of 
implementation and enforcement on renewable fuel producers rather than 
bringing feedstock producers and suppliers directly under EPA 
regulation. In this way, they would minimize the number of regulated 
parties under RFS2. They would also allow, to varying degree, the 
renewable fuel industry to determine the most efficient means of 
verifying and tracking feedstocks from the point of production to the 
point of consumption, thereby minimizing any additional cost and 
administrative burden created by the EISA definition of renewable 
biomass.
    Another alternative would be for EPA to establish a chain-of-
custody tracking system from feedstock producer to renewable fuel 
producer through which renewable fuel producers would obtain 
information regarding the lands where their feedstocks were produced. 
This information would accompany each transfer of custody of the 
feedstock until the feedstock reaches the renewable fuel producer. 
Renewable fuel feedstock producers, suppliers and handlers would not 
have any reporting obligations. EPA would, however, require all 
feedstock producers, suppliers, and handlers to maintain as records 
these chain-of-custody documents for all biomass intended to be used as 
a renewable fuel feedstock. Renewable fuel producers would also be 
required to maintain these chain-of-custody tracking documents in their 
records and would have to include them as part of their records 
presented during their annual attest engagement.
    An additional alternative would be for EPA to require renewable 
fuel producers to set up and administer a quality assurance program 
that would create an additional level of rigor in the implementation 
scheme for the EISA land restrictions on renewable biomass. The quality 
assurance program could include (1) an unannounced independent third 
party inspection of the renewable feedstock producer's facility at 
least once per quarter or once every 15 deliveries, whichever is more 
frequent, (2) an unannounced independent third party inspection of each 
intermediary facility that stores renewable fuel feedstock received by 
the renewable fuel producer at least once per quarter, and (3) on each 
occasion when the independent third party inspection reveals 
noncompliance, the renewable fuel producer must (a) conduct an 
investigation to determine the proper number of RINs that should have 
been generated for a volume of fuel and either generate or retire an 
equal number of RINs, depending on whether the fuel's feedstock did or 
did not meet the definition of renewable biomass, (b) conduct a root 
cause analysis of the violation, and (c) refuse to accept or process 
feedstock from the renewable fuel feedstock producer unless or until 
the feedstock producer takes appropriate corrective action to prevent 
future violations.
    This alternative could provide a partial affirmative defense either 
for renewable producers that illegally generate RINs for fuel made from 
feedstocks that do not qualify as renewable biomass or for renewable 
fuel producers who do not generate enough RINs for fuel made from 
feedstocks that do qualify as renewable biomass. In either case, the 
producers must demonstrate that the violation was caused by a feedstock 
producer or supplier and not themselves; that the commercial documents 
(e.g., bills of lading) received with the feedstock indicated that the 
feedstock either met (in the case that RINs were generated illegally) 
or did not meet (in the case that an inadequate number of RINs were 
generated) the land restrictions for renewable biomass, and that they 
met EPA's quality assurance program requirements. A renewable fuel 
producer that generates RINs for fuel made from a feedstock that does 
not meet the definition of renewable biomass, but that qualifies for 
the partial affirmative defense, would still have to retire a number of 
RINs equal to the illegally generated RINs. Likewise, a renewable fuel 
producer that does not generate sufficient RINs for fuel made from a 
feedstock that does meet the definition of renewable biomass, but that 
qualifies for the partial affirmative defense, would have to generate 
enough RINs to make up the difference. However, in neither case would 
they be subject to civil penalties.
    As yet another alternative approach, EPA could bring together 
renewable fuel producers and renewable fuel feedstock producers and 
suppliers to develop an industry-wide quality assurance

[[Page 24940]]

program for the renewable fuel production supply chain, following the 
model of the successful Reformulated Gasoline Survey Association. We 
believe that this alternative could be less costly than if each 
individual renewable fuel producer were to create their own quality 
assurance program, and it would add a quality assurance element to RFS2 
while creating the possibility for a partial affirmative defense for 
renewable fuel producers and feedstock producers and suppliers.
    The program would be carried out by an independent surveyor funded 
by industry and consist of a nationwide verification program for 
renewable fuel producers and renewable feedstock producers and handlers 
designed to provide independent oversight of the feedstock designations 
and handling processes that are required to determine if a feedstock 
meets the definition of renewable biomass. Under this alternative, a 
renewable fuel producer and its renewable feedstock suppliers and 
handlers would have to participate in the funding of an organization 
which arranges to have an independent surveyor conduct a program of 
compliance surveys. Compliance surveys would be carried out by an 
independent surveyor pursuant to a detailed survey plan submitted to 
EPA for approval by November 1 of the year preceding the year in which 
the alternative quality assurance sampling and testing program would be 
implemented. The survey plan would include a methodology for 
determining when the survey samples would be collected, the locations 
of the surveys, the number of inspections to be included in the survey, 
and any other elements that EPA determines are necessary to achieve the 
same level of quality assurance as the requirement included in the RFS2 
regulations at the time.
    Under this alternative, the independent surveyor would be required 
to visit renewable feedstock producers and suppliers to determine if 
they are properly designating their product and adhering to adequate 
chain of custody requirements. This nationwide sampling program would 
be designed to ensure even coverage of renewable feedstock producers 
and suppliers. The surveyor would generate and report the results of 
the surveys to EPA each calendar quarter. In addition, where the survey 
finds improper designations or handling, the liable parties would be 
responsible for identifying and addressing the root cause of the 
violation to prevent future violations. When a violation is detected, 
the renewable fuel producer that participates in the consortium would 
be deemed to have met the quality assurance criteria for a partial 
affirmative defense. If the renewable fuel producer met the other 
applicable criteria, he would have to take corrective action to retire 
or generate the appropriate number of RINs depending on the violation, 
but he would not be subject to civil penalties.
    Some stakeholders have suggested that EPA take advantage of 
existing satellite and aerial imagery and mapping software and tools to 
implement the renewable biomass provisions of EISA. One way to do so 
would be for EPA to develop a renewable fuel mapping Web site to assist 
regulated parties in meeting their obligation to identify the location 
of land where renewable fuel feedstocks are produced. Such a Web site 
could include an interactive map that would allow renewable feedstock 
producers to trace the boundaries of their property and create an 
electronic file with information regarding the land where their 
renewable fuel feedstocks were produced, such as a code that identifies 
the plot of land. This would allow the feedstock producer to provide 
information, such as a standard land ID code, on all bills of lading or 
other commercial documents that identify the type and quantity of 
feedstock being delivered to the renewable fuel producer. Renewable 
fuel producers could then make a determination regarding whether or not 
the renewable fuel feedstock that they use meets the definition of 
renewable biomass, and is therefore eligible or not for RIN generation.
    Feedstock producers would not necessarily be required to use this 
Internet-based tool to identify the location where renewable fuel 
feedstocks are produced, since many feedstock producers already 
participate in various government or insurance programs that have 
required them to map the location of their fields. But the map would 
enable renewable fuel producers to verify the accuracy of these 
descriptions and report these locations to EPA using the interactive 
mapping tool on EPA's Web site. EPA specifically solicits comment on 
the practicability of constructing an accurate map from existing data 
sources.
    As noted above, EPA recognizes that land restrictions contained 
within the definition of renewable biomass may not, in practice, result 
in a significant change in agricultural practices. EPA also recognizes 
that the implementation options described in this proposal could impose 
costs and constraints on existing storage, transportation, and delivery 
systems for feedstocks, in particular for corn and soybeans in the U.S. 
We therefore seek comment on a stakeholder suggestion to establish a 
baseline level of production of biomass feedstocks such that reporting 
and recordkeeping requirements would be triggered only when the 
baseline production levels of feedstocks used for biofuels were 
exceeded. Such an approach would avoid imposing a new recordkeeping 
burden on the industry as long as biofuels demand is met with existing 
feedstock production. We seek comment on this alternative, including 
how to set the baseline production levels and information on 
appropriate data sources in the U.S. and in other countries that 
produce feedstocks that could be used for renewable fuel production, 
and on how to track whether the feedstock use for biofuels production 
has exceeded baseline production levels. We also solicit comment on 
whether this approach could be applied to all types of feedstocks on 
which EISA places land restrictions, or if it would only be appropriate 
for traditional agricultural crops such as corn, soybeans, and 
sugarcane for which historical acreage data exists both domestically 
and internationally.
    EPA acknowledges that under this alternative, while there could be 
a net increase in lands being cultivated for a particular crop, we 
would presume that increases in cultivation would be used to meet non-
biofuels related feedstock demand. We also acknowledge that such an 
approach would be difficult to enforce because data that could indicate 
that baseline production levels were exceeded in a given year would 
likely be delayed by many months, such that the recordkeeping 
requirements for renewable fuel producers would also be delayed. During 
the interim period, renewable fuel producers would have generated RINs 
for fuel that did not qualify for credit under the program, and any 
remedial steps to invalidate such RINs after the fact could be costly 
and burdensome to all parties in the supply chain. Nonetheless, we seek 
comment on the approach as described above.
    We seek comment on all of these approaches and what combination of 
these approaches would be the most appropriate, enforceable, and 
practical for ensuring that the land restrictions on renewable biomass 
contained in EISA are implemented under RFS2. We also seek comment on 
whether there are other possible approaches that would be superior to 
those we have described above. We also note that we intend to monitor 
RIN generation and the trends

[[Page 24941]]

in renewable fuel feedstock sources as RFS2 implementation gets 
underway, and that we may make changes to the approach we adopt in the 
final RFS2 regulations if renewable fuel feedstock production 
conditions change or if new, better renewable biomass verification 
tools become available.
e. Approaches for Foreign Renewable Fuel
    EISA creates unique challenges related to the implementation and 
enforcement of the definition of renewable biomass for foreign-produced 
renewable fuel. In order to address these issues, we propose to require 
foreign producers of renewable fuel who export to the U.S. to meet the 
same compliance obligations as domestic renewable fuel producers. These 
obligations would include facility registration and submittal of 
independent engineering reviews (described in Section III.C below), and 
reporting, recordkeeping, and attest engagement requirements. They 
would also include the same obligations that domestic producers have 
for verifying that their feedstock meets the definition of renewable 
biomass as described above, such as certifying on each renewable fuel 
production report that their renewable fuel feedstock meets the 
definition of renewable biomass and working with their feedstock 
supplier(s) to ensure that they receive and maintain accurate and 
sufficient documentation in their records to support their claims. As 
under the RFS1 program for producers of cellulosic fuel, the foreign 
producer would be required to comply with additional requirements 
designed to ensure that enforcement of the regulations at the foreign 
production facility would not be compromised. For instance, foreign 
producers would be required to designate renewable fuel intended for 
export to the U.S. as such and segregate the volume until it reaches 
the U.S. and post a bond to ensure that penalties can be assessed in 
the event of a violation. Moreover, as a regulated party under the RFS2 
program, foreign producers would have to allow for potential visits by 
EPA enforcement personnel to review the completeness and accuracy of 
records and registration information.
    We propose that a foreign renewable fuel producer, like a domestic 
renewable fuel producer, could only produce and sell renewable fuel for 
export to the U.S. without RINs if he demonstrated that the land used 
to produce his feedstocks did not meet the definition of renewable 
biomass. This approach would ensure that foreign renewable fuel 
producers could not avoid the generation of RINs for fuel shipped to 
the U.S. simply by failing to make any demonstration regarding the land 
used to produce their feedstocks. Thus, foreign renewable fuel 
producers that export their product to the U.S. would be required to 
keep records of the type of land used to produce their feedstock 
regardless of whether RINs are generated or not. Section III.D.2.b 
outlines more specifically our proposed requirements for foreign 
renewable fuel producers.
    Importers will likely have less knowledge than a foreign renewable 
fuel producer would about the point of origin of their fuel's feedstock 
and whether it meets the definition of renewable biomass. Therefore, we 
are proposing that in the event that a batch of foreign-produced 
renewable fuel does not have RINs accompanying it, an importer must 
obtain documentation from its producer that states whether or not the 
definition of renewable biomass was met by the fuel's feedstock. With 
such documentation, the importer would be required to generate RINs (if 
the definition of renewable biomass is met) or would be prohibited from 
doing so (if the definition is not met) prior to introducing the fuel 
into commerce in the U.S. Without such documentation, the fuel would 
not be permitted for importation. Section III.D.2.c outlines our 
proposed requirements for importers more fully.
    We seek comment on whether and to what extent the approaches for 
ensuring compliance with the EISA's land restrictions by foreign 
renewable fuel producers could or should differ from the proposed 
approach for domestic renewable fuel producers. In light of the 
challenges associated with enforcing the EISA's land restrictions in 
foreign countries, we believe that it may be appropriate to require 
foreign renewable fuel producers to use an alternative method of 
demonstrating compliance with these requirements. We seek comment on 
whether foreign renewable producers exporting product to the U.S. 
should have to comply with any of the alternatives described for 
domestic renewable fuel producers under this section. For example, we 
seek comment on whether a foreign renewable fuel producer should have 
to demonstrate that it had a contract in place with its renewable 
feedstock producer that required designation and chain of custody and 
handling methods similar to one of the alternatives for domestic 
renewable fuel producers discussed above. We also seek comment on 
whether foreign renewable fuel producers that export product to the 
U.S. should have to provide EPA with the location of land from which 
they will or have acquired feedstocks, along with historical satellite 
or aerial imagery demonstrating that feedstocks from these lands meet 
the definition of renewable biomass. We seek comment on whether foreign 
renewable fuel producers should also be subject to the same quality 
assurance requirements relating to their feedstock sources as domestic 
renewable fuel producers, and whether they should have the same option 
to use an approved survey consortium in lieu of implementing their own 
individual quality assurance programs.
    We also seek comment on an alternative that would provide foreign 
renewable fuel producers an option of participating in RFS2 (in a 
manner consistent with our main proposal), or not participating at all. 
If they elected not to participate in RFS2, they could export renewable 
fuel to the United States without RINs, and without providing any 
documentation as to whether or not the fuel was made with renewable 
biomass. However, they would also have to meet requirements for 
segregating their fuel from renewable fuel for which RINs were 
generated, and the importer of their fuel would be required to track it 
to ensure that the fuel remains segregated in the U.S. and is not used 
by a domestic company for illegal RIN generation. This alternative 
would provide foreign renewable fuel producers an option not available 
to domestic renewable fuel producers, who in all cases would be 
required to document whether or not their feedstock met the definition 
of renewable biomass, and who would be required to generate RINs for 
their product if it was. As discussed in Section III.B.4.b.ii of this 
preamble, EPA believes that in order for obligated parties to meet the 
increasing annual volume requirements under RFS2, all qualifying 
renewable fuel will need to have RINs generated for it. Nonetheless, 
this alternative recognizes the potential difficulty of applying 
renewable biomass verification procedures in the international context, 
and provides an exemption process that EPA expects would only be used 
by relatively small producers for whom the burden of participating in 
the RFS2 program would outweigh the benefits, and whose total 
production volume would be negligible.

C. Expanded Registration Process for Producers and Importers

    In order to implement and enforce the new restrictions on 
qualifying renewable fuel under RFS2, we are proposing that the 
registration process

[[Page 24942]]

for renewable fuel producers and importers be revised. Under the 
existing RFS1 program, all producers and importers of renewable fuel 
who produce or import more than 10,000 gallons of fuel annually must 
register with EPA's fuels program prior to generating RINs. Renewable 
fuel producer and importer registration under the existing RFS program 
consists of filling out two forms: 3520-20A (Fuels Programs Company/
Entity Registration), which requires basic contact information for the 
company and basic business activity information (e.g., for an ethanol 
producer, they need to indicate that they are a RIN generator), and 
3520-20B (Gasoline Programs Facility Registration) or 3520-20B1 (Diesel 
Programs Facility Registration), which requires basic contact 
information for each facility owned by the producer or importer. More 
detailed information on the renewable fuel production facility, such as 
production capacity and process, feedstocks, and products is not 
required for most producers or importers to generate RINs under RFS1 
(producers of cellulosic biomass ethanol and waste-derived ethanol are 
the exception to this).
    Due to the revised definitions of renewable fuel under EISA, as 
well as other changes, we believe it necessary to expand the 
registration process for renewable fuel producers and importers in 
order to implement the new program effectively. Specifically, 
generating and assigning a certain category of RIN to a volume of fuel 
is dependent on whether the feedstock used to produce the fuel meets 
the definition of renewable biomass, whether the lifecycle greenhouse 
gas emissions of the fuel meets a certain GHG reduction threshold and, 
in some cases, whether the renewable fuel production facility is 
considered to be grandfathered into the program. Unless we require 
producers, including foreign producers, and importers to provide us 
with information on their feedstocks, facilities, and products, we 
cannot adequately implement or enforce the program or have confidence 
that producers and importers are properly categorizing their fuel and 
generating RINs. In particular, our proposed approach for ensuring that 
the GHG emission reduction thresholds for each category of renewable 
fuel are met will require producers and importers to determine the 
proper category assignment for their fuel based on a combination of 
their feedstock, production processes, and products (see Section 
III.D.2 for the proposed list). Such information, therefore, is central 
to program implementation. Therefore, we are proposing new registration 
requirements for all domestic renewable fuel producers, importers, and 
foreign renewable fuel producers. We also plan on integrating 
registration procedures with the new EPA Moderated Transaction System, 
discussed in detail in Section IV.E of this preamble. We encourage 
those affected by the proposed registration requirements to review the 
document entitled ``Proposed Information Collection Request (ICR) for 
the Renewable Fuels Standard (RFS2) Program--EPA ICR 2333.01,'' and an 
Addendum to the proposed ICR, which have been placed in the public 
docket and to provide comments to us regarding the burdens associated 
with the proposed registration requirements.
1. Domestic Renewable Fuel Producers
    The most significant proposed changes to the current registration 
system pertain to the information that a producer will need to provide 
EPA prior to generating RINs. As noted above, we are proposing that 
producers provide information about their products, feedstocks, and 
facilities in order to be registered for the RFS2 program. Information 
contained in a producer's registration would be used to verify the 
validity of RINs generated and their proper categorization as either 
cellulosic biofuel, biomass-based diesel, advanced biofuel, or other 
renewable fuel.
    With respect to products, we are interested in the types of 
renewable fuel and co-products that a facility is capable of producing. 
With respect to feedstocks, we believe it is necessary to have on file 
a list of all the different feedstocks that a renewable fuel producer's 
facility is capable of converting into renewable fuel. For example, if 
a renewable fuel producer produces fuel from both cellulosic material, 
such as corn stover, and non-cellulosic material, such as corn starch, 
the producer may be eligible to generate RINs in two different 
categories (cellulosic biofuel and renewable fuel). This producer's 
registration information would be required to list both of these 
feedstocks before we would allow two different categories of RINs to be 
generated.
    With respect to the producer's facilities, we are proposing two 
types of information that would need to be reported to the Agency. 
First, we believe it is important to have information on file that 
describes each facility's fuel production processes (e.g., wet mill, 
dry mill, thermochemical, etc.), and thermal/process energy source(s). 
Second, in order to determine what production volumes would be 
grandfathered and thus deemed to be in compliance with the 20% GHG 
threshold, we would require evidence and certification of the 
facility's qualification under the definition of ``commence 
construction'' as well as information necessary to establish it's 
renewable fuel baseline volume per the proposal outlined in Section 
III.B.3 of this preamble.
    Under the existing RFS1 program, producers of cellulosic biomass 
and waste-derived ethanol are required to have an annual engineering 
review of their production records performed by an independent third 
party who is licensed Professional Engineer (P.E.) who works in the 
chemical engineering field. This independent third party need not be 
based in the United States, but must hold a P.E. Each review must be 
kept on file by both the producer and the engineer for five years. The 
independent third party must include documentation of its 
qualifications as part of the engineering review. Foreign producers of 
cellulosic biomass and waste-derived ethanol are also required to have 
an engineering review of their facilities, with a report submitted to 
EPA that describes in detail the physical plant and its operation. 
These requirements helps ensure that producers who claim to be 
producing such fuel, which earns 2.5 RINs per gallon rather than 1.0 
RIN per gallon for corn-based ethanol under RFS1, are in fact doing so.
    We believe that the requirement for an on-site engineering review 
is an effective implementation tool and propose to adopt the 
requirement under RFS2, with the following changes. First, we propose 
expanding the applicability of the requirement to all renewable fuel 
producers due to the variability of production facilities, the increase 
in the number of categories of renewable fuels, and the importance of 
generating RINs in the correct category. Second, we propose that every 
renewable fuel producer must have the on-site engineering review of 
their facility performed in conjunction with his or her initial 
registration for the new RFS program in order to establish the proper 
basis for RIN generation, and every three years thereafter to verify 
that the fuel pathways established in their initial registration are 
still applicable. These requirements would apply unless the renewable 
fuel producer updates its facility registration information to qualify 
for a new RIN category (i.e., D code), in which case the review would 
need to be performed within 60 days of the registration update. 
Finally, we propose that producers be required to

[[Page 24943]]

submit a copy of their independent engineering review to EPA rather 
than simply maintaining it in their records. We believe that this extra 
step is necessary for verification and enforcement purposes.
    In addition to the new registration requirements for all renewable 
fuel producers who produce greater than 10,000 gallons of product each 
year, we seek comment on whether to require renewable fuel producers 
and importers in the U.S. who produce or import less than 10,000 
gallons per year to register basic information about their company and 
facility (or facilities) with EPA, similar to information currently 
required of renewable fuel producers under RFS1. This information would 
complement information submitted to EPA under the Fuels and Fuel 
Additives Registration System (FFARS) program to help ensure that EPA 
has a complete record of renewable fuel production and importation in 
the U.S.
2. Foreign Renewable Fuel Producers
    Under the current RFS program, foreign renewable fuel producers of 
cellulosic biomass ethanol and waste-derived ethanol may apply to EPA 
to generate RINs for their own fuel. This allows a foreign producer of 
this renewable fuel to obtain the same benefits of higher credit value 
as domestic producers of this category of renewable fuel. Under the 
RFS1 regulations, the foreign fuel producer must meet a variety of 
requirements established to make the program effective and enforceable 
with respect to a foreign producer. These requirements mirror a number 
of similar fuel provisions that apply to foreign refiners in other 
fuels programs. For RFS2, we propose that foreign producers of 
renewable fuel must meet the same requirements as domestic producers, 
including registering information about their feedstocks, facilities, 
and products, as well as submitting an on-site independent engineering 
review of their facilities at the time of registration for the program 
and every three years thereafter. These requirements would apply to all 
foreign renewable fuel producers who export their products to the U.S., 
whether or not they qualify to generate RINs for their fuel. They would 
also be subject to the variety of enforcement related provisions that 
apply under RFS1 to foreign producers of cellulosic biomass or waste 
derived ethanol.
    As discussed in Section III.C.1, the existing RFS1 program requires 
that the independent engineering review be conducted by an independent 
third party who is a licensed P.E. who works in the chemical 
engineering field. This P.E. need not be based in the United States. 
The independent third party must include documentation of its 
qualifications as part of the engineering review.
    Since implementation of RFS1 we have received questions about 
engineers who are licensed by other countries that may have equivalent 
licensing requirements to those associated with the P.E. designation in 
the United States. The existing RFS1 program does not permit 
independent third party review by a party who is not a licensed P.E. We 
invite comment on whether or not we should permit independent third 
parties who are based in--and licensed by--foreign countries and who 
work in the chemical engineering field to demonstrate the foreign 
equivalency of a P.E. license.
    We also seek comment on requiring foreign renewable fuel producers 
to provide EPA with the location of land from which they will acquire 
feedstocks, along with historical satellite or aerial imagery 
demonstrating that the lands from which they acquire feedstock are 
eligible under the definition of renewable biomass (see Section III.B.4 
for a full discussion of our proposed and alternative approaches for 
foreign renewable fuel producers to verify their feedstocks meet the 
definition of ``renewable biomass'').
3. Renewable Fuel Importers
    A renewable fuel importer is required under RFS1 to register basic 
information about their company with EPA prior to generating RINs. 
Under the proposed new RFS2 program, we are proposing that only in 
limited cases can importers generate RINs for imported fuel that they 
receive without RINs. In any case, whether they receive fuel with or 
without RINs, an importer must rely on his supplier, a foreign 
renewable fuel producer, to provide documentation to support any claims 
for their decision to generate or not to generate RINs. An importer may 
have an agreement with a foreign renewable fuel producer for the 
importer to generate RINs if the foreign producer has not done so 
already. However, the foreign renewable fuel producer must be 
registered with EPA as noted above. Section III.D.2.c describes our 
proposed RIN generating restrictions and requirements for importers 
under RFS2.
4. Process and Timing
    We intend to make forms for expanded registration for renewable 
fuel producers and importers available electronically, with paper 
registration only in exceptional cases. We propose that registration 
forms will have to be submitted by January 1, 2010 (the proposed 
effective date of the final RFS2 regulations), or 60 days prior to a 
producer producing or importer importing any renewable fuel, whichever 
dates comes later. If a producer changes to a feedstock that is not 
listed in his registration information on file with EPA but the 
feedstock will not incur a change of RIN category for the fuel (i.e., a 
change in the appropriate D code), then we propose that the producer 
must update his registration information within seven (7) days of the 
change. However, if a producer's feedstock, facility (including 
industrial processes or thermal energy source), or products undergo 
changes that would qualify his renewable fuel for a new RIN category 
(and thus a new D code), then we propose that such an update would need 
to be submitted at least 60 days prior to the change, followed by 
submittal of a complete on-site independent engineering review of the 
producer's facility also within 60 days of the change.

D. Generation of RINs

    Under RFS2, each RIN would continue to be generated by the producer 
or importer of the renewable fuel, as in the RFS1 program. In order to 
determine the number of RINs that must be generated and assigned to a 
batch of renewable fuel, the actual volume of the batch of renewable 
fuel must be multiplied by the appropriate Equivalence Value. The 
producer or importer must also determine the appropriate D code to 
assign to the RIN to identify which of the four standards the RIN can 
be used to meet. This section describes these two aspects of the 
generation of RINs. We propose that other aspects of the generation of 
RINs, such as the definition of a batch and temperature 
standardization, as well as the assignment of RINs to batches, should 
remain unchanged from the RFS1 requirements.
1. Equivalence Values
    For RFS1, we interpreted CAA section 211(o) as allowing us to 
develop Equivalence Values representing the number of gallons that can 
be claimed for compliance purposes for every physical gallon of 
renewable fuel. We described how the use of Equivalence Values adjusted 
for renewable content and based on energy content in comparison to the 
energy content of ethanol was consistent with Congressional intent to 
treat different renewable fuels differently in different circumstances, 
and to provide

[[Page 24944]]

incentives for use of renewable fuels in certain circumstances, as 
evidenced by the specific circumstances addressed by Congress. This 
included the direction that EPA establish ``appropriate'' credit values 
in certain circumstances, as well as provisions in the statute 
providing for different credit values to be assigned to the same volume 
of different types of renewable fuels (e.g., cellulosic and waste-
derived fuels). We also noted that the use of Equivalence Values based 
on energy content was an appropriate measure of the extent to which a 
renewable fuel would replace or reduce the quantity of petroleum or 
other fossil fuel present in a fuel mixture. The result was an 
Equivalence Value for ethanol of 1.0, for butanol of 1.3, for biodiesel 
(mono alkyl ester) of 1.5, and for non-ester renewable diesel of 1.7. 
EPA stated that these provisions indicated that Congress did not intend 
to limit the RFS program solely to a straight volume measurement of 
gallons. EPA also noted that the use of Equivalence Values would not 
interfere with meeting the overall volume goals specified by Congress, 
given the various provisions that make achievement of the specified 
volumes imprecise. See 72 FR 23918-23920, and 71 FR 55570-55571.
    EISA has not changed certain of the statutory provisions we looked 
to for support under RFS1 in establishing Equivalence Values based on 
relative volumetric energy content in comparison to ethanol. For 
instance, CAA 211(o) continues to give EPA the authority to determine 
an ``appropriate'' credit for biodiesel, and also directs EPA to 
determine the ``appropriate'' amount of credit for renewable fuel use 
in excess of the required volumes.
    However, EISA made a number of other changes to CAA section 211(o) 
that impact our consideration of Equivalence Values in the context of 
the RFS2 program. For instance, EISA eliminated the 2.5-to-1 credit for 
cellulosic biomass ethanol and waste-derived ethanol and replaced this 
provision with large mandated volumes of cellulosic biofuel and 
advanced biofuels. Under the RFS1 program, an Equivalence Value of 2.5 
applies to these types of ethanol through the end of 2012. Under the 
new RFS2 program, these types of ethanol would have an Equivalence 
Value of 1.0, consistent with all other forms of ethanol.
    EISA also expanded the program to include four separate categories 
of renewable fuel (cellulosic biofuel, biomass-based diesel, advanced 
biofuel, and total renewable fuel) and included GHG thresholds in the 
definitions of each category. Each of these categories of renewable 
fuel has its own volume requirement, and thus there will exist a 
guaranteed market for each. As a result there may no longer be a need 
for additional incentives for certain fuels in the form of Equivalence 
Values greater than 1.0. In addition, the use of an energy-based 
approach to Equivalence Values raises some questions, discussed below, 
concerning the impact of such Equivalence Values on the biomass-based 
diesel volume requirement and in the initial years on the advanced 
biofuel volume requirement. Overall EPA believes that the statute 
continues to be ambiguous on this issue, and we are therefore co-
proposing and seeking comment on two options for Equivalence Values:
    1. Equivalence Values would be based on the energy content and 
renewable content of each renewable fuel in comparison to denatured 
ethanol, consistent with the approach under RFS1.
    2. All liquid renewable fuels would be counted strictly on the 
basis of their measured volumes, and the Equivalence Values for all 
renewable fuels would be 1.0 (essentially, Equivalence Values would no 
longer apply).
    While these two different approaches to volume would have an impact 
on the market values of renewable fuels with different energy contents 
as explained more fully below, the overall impact on the program would 
likely be small since we are projecting that the overwhelming majority 
of renewable fuels will be ethanol (see further discussion in Section 
V.A.2).
    Under either option, non-liquid renewable fuels such as biogas and 
renewable electricity would continue to be valued based on the energy 
contained in one gallon of denatured ethanol. In the RFS1 final 
rulemaking, we specified that 77,550 Btu of biogas be counted as the 
equivalent of 1 gallon of renewable fuel with an assigned Equivalence 
Value of 1.0. We propose to maintain this approach to non-liquid 
renewable fuels under the RFS2 program under either approach to 
Equivalence Values, but with a small modification to make the ethanol 
energy content more accurate. The energy content of denatured ethanol 
was specified as 77,550 Btu/gal under RFS1, but a more accurate value 
would be 77,930 Btu/gal. Thus we propose to use 77,930 Btu to convert 
biogas and renewable electricity into volumes of renewable fuel under 
RFS2.
    Under the second option in which all liquid renewable fuels would 
be counted strictly on the basis of their measured volumes, we would 
need to determine how to treat the small amount of denaturant in 
ethanol and the nonrenewable portion of biodiesel. Under RFS1, 
Equivalence Values were determined from a formula that included 
measures of both volumetric energy content and renewable content. The 
renewable content was intended to take into account the portion, if 
any, of a renewable fuel that originated from a fossil fuel feedstock. 
EISA eliminated the statutory language on which the inclusion of 
renewable content was based, and instead restricts renewable fuels that 
are valid under the RFS2 program to those produced from renewable 
biomass. In the case of fuels produced from both renewable and 
nonrenewable feedstocks, we have interpreted this to mean only that 
portion of the volume attributable to the renewable feedstocks (see 
further discussion in Section III.D.4 below). However, we do not 
believe that this approach is appropriate for the denaturant in ethanol 
and the small amount of non-renewable methanol used in the production 
of biodiesel, since Congress clearly intended that ethanol and 
biodiesel be included as a renewable fuel, and they are only used as a 
fuel under these circumstances. We therefore propose to treat the 
denaturant in ethanol and the nonrenewable portion of biodiesel as de 
minimus and thus count them as part of the renewable fuel volume under 
an approach to Equivalence Values in which all liquid renewable fuels 
would be counted strictly on the basis of their measured volumes. As a 
result, under this co-proposed approach we are proposing that the full 
formula used to calculate Equivalence Values under RFS1 be eliminated 
from the regulations and that the Equivalence Value for all renewable 
fuels be specified as 1.0. Nevertheless, we seek comment on this 
approach.
    Although there are several reasons for a straight volume approach 
as discussed above, there are also several reasons to maintain the 
ethanol-equivalent energy content approach to Equivalence Values of 
RFS1. For instance, in our discussions with stakeholders, some have 
argued that the existence of four standards is not a sufficient reason 
to eliminate the use of energy-based Equivalence Values for RFS2. The 
four categories are defined in such a way that a variety of different 
types of renewable fuel could qualify for each category, such that no 
single specific type of renewable fuel will have a guaranteed market. 
For example, the cellulosic biofuel requirement could be met with both 
cellulosic ethanol or cellulosic diesel. As a result, the existence of 
four standards under RFS2 may not obviate the value of standardizing 
for energy

[[Page 24945]]

content, which provides a level playing field under RFS1 for various 
types of renewable fuels based on energy content.
    More importantly, they argue that a straight volume approach would 
be likely to create a disincentive for the development of new renewable 
fuels that have a higher energy content than ethanol in the same way as 
the current ethanol tax credit structure. For a given mass of 
feedstock, the volume of renewable fuel that can be produced is roughly 
inversely proportional to its energy content. For instance, one ton of 
biomass could be gasified and converted to syngas, which could then be 
catalytically reformed into either 90 gallons of ethanol (and other 
alcohols) or 50 gallons of diesel fuel (and naphtha).\24\ If RINs were 
assigned on a straight volume basis, the producer could maximize the 
number of RINs he is able to generate and sell by producing ethanol 
instead of diesel. Thus, even if the market would otherwise lean 
towards demanding greater volumes of diesel, the greater RIN value for 
producing ethanol may favor its production instead. However, if the 
energy-based Equivalence Values were maintained, the producer could 
assign 1.7 RINs to each gallon of diesel made from biomass in 
comparison to 1.0 RIN to each gallon of ethanol from biomass, and the 
total number of RINs generated would be essentially the same for the 
diesel as it would be for the ethanol. The use of energy-based 
Equivalence Values could thus provide a level playing field in terms of 
the RFS program's incentives to produce different types of renewable 
fuel from the available feedstocks. The market would then be free to 
choose the most appropriate renewable fuels without any bias imposed by 
the RFS regulations, and the costs imposed on different types of 
renewable fuel through the assignment of RINs would be more evenly 
aligned with the ability of those fuels to power vehicles and engines, 
and displace fossil fuel-based gasoline or diesel.
---------------------------------------------------------------------------

    \24\ Another example would be a fermentation process in which 
one ton of cellulose could be used to produce either 70 gallons of 
ethanol or 55 gallons of butanol.
---------------------------------------------------------------------------

    Moreover, the technologies for producing more energy-dense fuels 
such as cellulosic diesel are still in the early stages of development 
and may benefit from not having to overcome the disincentive in the 
form of the same Equivalence Value based on straight volume. Given the 
projected tightness in the distillate market and relative excess supply 
in the gasoline market in the coming years, allowing the market to 
choose freely may be important to overall fuel supply. In the extreme, 
the cellulosic biofuel standard could then be met by roughly 10 billion 
gallons of a cellulosic diesel fuel instead of the 16 billion gallons 
of cellulosic ethanol assumed for the impacts analysis of this 
proposal. The same amount of petroleum energy would be displaced, but 
by different physical volumes.
    As discussed above, there are no provisions in EISA that explicitly 
instruct the Agency to change from the approach to Equivalence Values 
adopted in RFS1. However, there is a question of how to address the 
biomass-based diesel requirement under such an approach. In that 
context, it does appear that Congress intended the required volumes of 
biomass-based diesel to be treated as diesel volumes rather than 
ethanol-equivalent volumes. Therefore EPA proposes that, for the 
biomass-based diesel volume mandate under an ethanol-equivalent energy 
content approach to Equivalence Values, the compliance calculations 
would be structured such that this requirement is treated in effect as 
a straight volume-based requirement.\25\
---------------------------------------------------------------------------

    \25\ The proposed regulations and the ensuing discussion in 
Sections III and IV of this proposal reflect straight volume 
approach, however, the impacts analysis of the program are 
calculated using volumes based on ethanol-equivalent energy content. 
Were we to maintain the energy content approach to Equivalence 
Values, then we believe the biomass-based diesel standard should be 
treated in effect as a biodiesel volume, reflecting the nature of 
this standard, while the other three standards would be treated as 
ethanol-equivalent volumes. In order to effectuate this, we are 
considering two approaches. Under either approach all RINs would be 
generated based on ethanol-equivalent volume, including biomass-
based diesel RINs. Under one approach, we would propose that the 
biomass-based diesel standard also be expressed as an ethanol-
equivalent volume (e.g., 1.5 billion ethanol-equivalent gallons in 
2012). Another approach would be to have the standard expressed as a 
volume of biomass-based diesel, and to require the biomass-based 
diesel RINs be adjusted back to a volume basis, with this adjustment 
just for purposes of the biomass-based diesel standard but not for 
purposes of the other fuels mandates. Either approach would have the 
same result.
---------------------------------------------------------------------------

    In addition, it is also clear that Congress established the 
advanced biofuel standard in EISA to begin to take affect in 2009. 
However, if we maintain the ethanol-equivalent energy content approach 
for RFS2, and biodiesel continues to have an Equivalence Value of 1.5, 
then from 2009-2012 the combination of the biomass-based diesel 
standard and the cellulosic biofuel standard will meet or exceed the 
advanced biofuel standard. Unless we were to waive a portion of either 
the biomass-based diesel standard or the cellulosic biofuel standard, 
the advanced biofuel standard would not have an independent effect 
until 2013. While EPA recognizes this, EPA believes that the long term 
benefits of an energy based Equivalence Value may be significantly 
greater than any temporary diminishment in the real world impact of the 
advanced biofuel mandate.
    In recognition of the competing perspectives, we request comment on 
both co-proposed approaches to the Equivalence Values: (1) Retaining 
the energy-based approach of the RFS1 program, and (2) a straight 
volume approach measured in liquid gallons of renewable fuel.
2. Fuel Pathways and Assignment of D Codes
    As described in Section III.A, we propose that RINs under RFS2 
would continue to have the same number of digits and code definitions 
as under RFS1. The one change would be that, while the D code would 
continue to identify the standard to which the RIN could be applied, it 
would be modified to have four values corresponding to the four 
different renewable fuel categories defined in EISA. These four D code 
values and the corresponding categories are shown in Table III.A-1.
    In order to generate RINs for renewable fuel that meets the various 
eligibility requirements (see Section III.B), a producer or importer 
must know which D code to assign to those RINs. We propose that a 
producer or importer would determine the appropriate D code using a 
lookup table in the regulations. The lookup table would list various 
combinations of fuel type, production process, and feedstock, and the 
producer or importer would choose the appropriate combination 
representing the fuel he is producing and for which he is generating 
RINs. Parties generating RINs would be required to use the D code 
specified in the lookup table and would not be permitted to use a D 
code representing a broader renewable fuel category. For example, a 
party whose fuel qualified as biomass-based diesel could not choose to 
categorize that fuel as advanced biofuel or general renewable fuel.
    This section describes our proposed approach to the assignment of D 
codes to RINs for domestic producers, foreign producers, and importers 
of renewable fuel. Subsequent sections address the generation of RINs 
in special circumstances, such as when a production facility has 
multiple applicable combinations of feedstock, fuel type, and 
production process within a calendar year, production facilities that 
co-process renewable biomass and fossil fuels, and production

[[Page 24946]]

facilities for which the lookup table does not provide an applicable D 
code.
a. Domestic Producers
    For domestic producers, the lookup table would identify individual 
fuel ``pathways'' comprised of unique combinations of the type of 
renewable fuel being produced, the feedstock used to produce the 
renewable fuel, and a description of the production process. Each 
pathway would be assigned to one of the four specific D codes on the 
basis of the revised renewable fuel definitions provided in EISA and 
our assessment of the GHG lifecycle performance for that pathway. A 
description of the lifecycle assessment of each fuel pathway and the 
process we used for determining the associated D code can be found in 
Section VI. Note that the subsequent generation of RINs would also 
require as a prerequisite that the feedstocks used to make the 
renewable fuel meet the definition of ``renewable biomass'' as 
described in Section III.B.4, including applicable land use 
restrictions. Moreover, a domestic producer could not introduce 
renewable fuel into commerce without generating RINs unless he had 
records demonstrating that the feedstocks used to produce the fuel did 
not meet the definition of renewable biomass. See Section III.B.4.b.ii 
for further discussion of this issue.
    Through our assessment of the lifecycle GHG impacts of different 
pathways and the application of the EISA definitions for each of the 
four categories of renewable fuel, including the GHG thresholds, we 
have determined that all four categories would have pathways that could 
be used to meet the Act's volume requirements. For example, ethanol 
made from corn stover or switchgrass in an enzymatic hydrolysis process 
would count as cellulosic biofuel. Biodiesel made from waste grease 
could count as biomass-based diesel. Ethanol made from sugarcane sugar 
may count as advanced biofuel depending on the results of the lifecycle 
assessment conducted for the final rule and a determination about 
whether the GHG threshold for advanced biofuel should be adjusted 
downward. Finally, under an assumed 100-year timeframe and 2% discount 
rate for GHG emissions impacts, a variety of pathways would count as 
generic renewable fuel under the RFS2 program, including ethanol made 
from corn starch in a facility powered by biomass combustion and 
biodiesel made from soybean oil. The complete list of pathways that 
would be valid under our proposed RFS program is provided in the 
regulations at Sec.  80.1426(d), based upon an assumed 100-year 
timeframe and 2% discount rate for GHG emission impacts.
    Domestic producers would choose the appropriate D code from the 
lookup table in the regulations based on the fuel pathway that 
describes their facility. The fuel pathway must be specified by the 
producer in the registration process as described in Section III.C. If 
there were changes to a domestic producer's facility or feedstock such 
that their fuel would require a D code that was different from any D 
code(s) which their existing registration information already allowed, 
the producer would be required to revise its registration information 
with EPA 30 days prior to changing the applicable D code it uses to 
generate RINs. Situations in which multiple fuel pathways could apply 
to a single facility are addressed in Section III.D.3 below.
    For producers for whom none of the defined fuel pathways in the 
lookup table would apply, we propose two possible treatments. First, 
such producers may be able to generate RINs through our proposed system 
of default D codes as described in Section III.D.5 below. Second, if a 
producer meets the criteria for grandfathered status as described in 
Section III.B.3 and his fuel meets the definition of renewable fuel as 
described in Section III.B.1, he could continue to generate RINs for 
his fuel but would use a D code of 4 for those RINs generated under the 
grandfathering provisions. If a producer was not covered by either of 
these two treatments, we propose that he would not be permitted to 
generate RINs for his product until the lookup table in the regulations 
was modified to include a pathway applicable to his operations.
    A diesel fuel product produced from cellulosic feedstocks that 
meets the 60% GHG threshold could qualify as either cellulosic biofuel 
or biomass-based diesel. As a result, we are proposing that the 
producer of such ``cellulosic diesel'' be given the choice of whether 
to categorize his product as either cellulosic biofuel or biomass-based 
diesel. This would allow the producer to market his product and the 
associated RINs on the basis of market demand. However, we request 
comment on an alternative approach as shown in Table III.D.2.a-1 in 
which an additional D code would be defined to represent cellulosic 
diesel and an obligated party would be given the choice of using 
cellulosic diesel RINs either to meet his or her RVO for cellulosic 
biofuel or for biomass-based diesel.

    Table III.D.2.a-1--Alternative D Code Definitions To Accommodate
                            Cellulosic Diesel
------------------------------------------------------------------------
             D value              Meaning under RFS1  Meaning under RFS2
------------------------------------------------------------------------
1...............................  Cellulosic biomass  Cellulosic
                                   ethanol.            biofuel.
2...............................  Any renewable fuel  Biomass-based
                                   that is not         diesel.
                                   cellulosic
                                   biomass ethanol.
3...............................  Not applicable....  Cellulosic biofuel
                                                       or biomass-based
                                                       diesel.
4...............................  Not applicable....  Advanced biofuel.
5...............................  Not applicable....  Renewable fuel.
------------------------------------------------------------------------

    Under this alternative, producers of cellulosic diesel would assign 
a D code of 3 to their product rather than being given a choice of 
whether to assign a D code of 1 or 2. Any obligated party that acquired 
a RIN with a D code of 3 could apply that RIN to either its cellulosic 
biofuel or biomass-based diesel obligation, but not both. The advantage 
of this alternative approach is that it reflects the full compliance 
value for the product, and hence its potential value to an obligated 
party. The obligated party is then given the ability to make a choice 
about how to treat cellulosic diesel based on the market price and 
availability of RINs with D codes of 1 and 2. We request comment on 
this alternative approach to the designation of D codes for cellulosic 
diesel.
b. Foreign Producers
    Under RFS1, foreign producers have the option of generating RINs 
for the renewable fuel that they export to the U.S. if they want to 
designate their fuel as cellulosic biomass ethanol or waste-derived 
ethanol, and thereby take advantage of the additional 1.5 credit value 
afforded by the 2.5 Equivalence Value for such products. In order to

[[Page 24947]]

ensure that EPA has the ability to enforce the regulations relating to 
the generation of RINs from such foreign ethanol producers, the RFS1 
regulations require them to post a bond and submit to third-party 
engineering reviews of their production process. If a foreign producer 
does not generate RINs for the renewable fuel that it exports to the 
U.S., the U.S. importer is responsible for generating the RINs 
associated with the imported renewable fuel.
    EISA creates unique challenges in the implementation and 
enforcement of the renewable fuel standards for imported renewable 
fuel. Unlike our other fuels programs, EPA cannot determine whether a 
particular shipment of renewable fuel is eligible to generate RINs 
under the new program by testing the fuel itself. Instead, information 
regarding the feedstock that was used to produce renewable fuel and the 
process by which it was produced is vital to determining the proper 
renewable fuel category and RIN type for the imported fuel. It is for 
these reasons that we required foreign producers of cellulosic biomass 
ethanol or waste-derived ethanol under RFS1 to take additional steps to 
ensure the validity of the RINs they generate.
    For RFS2 we are proposing a similar approach to that taken under 
RFS1, but with a number of modifications to account for the changes 
that EISA makes to the definition of renewable fuel. Thus, we propose 
that foreign producers would have the option of generating RINs for any 
renewable fuel (not just the cellulosic biofuel category) that they 
export to the U.S. If the foreign producer did not generate RINs, the 
importer would be required to generate RINs for the imported renewable 
fuel. Our proposed importer provisions are covered in more detail in 
Section III.D.2.c below.
    In general, we propose that foreign producers of renewable fuel who 
intend to export their fuel to the U.S. would use the same process as 
domestic producers to generate RINs, namely the lookup table to 
identify the appropriate D code as a function of fuel type, production 
process, and feedstock. They would be required to be registered with 
the EPA as a producer under the RFS2 program and would be subject to 
the same recordkeeping, reporting, and attest engagement requirements 
as domestic producers, including those provisions associated with 
ensuring that the feedstocks they use meet the definition of renewable 
biomass. They would also be required to submit to third-party 
engineering reviews of their production process and use of feedstocks, 
just as domestic producers are. As under the RFS1 program, the foreign 
producer would also be required to comply with additional requirements 
designed to ensure that enforcement of the regulations at the foreign 
production facility would not be compromised. For instance, foreign 
producers would be required to designate renewable fuel intended for 
export to the U.S. as such and segregate the volume until it reaches 
the U.S. in order to ensure that RINs are only generated for volumes 
imported into the U.S. Foreign producers would also be required to post 
a bond to ensure that penalties can be assessed in the event of a 
violation. Moreover, as a regulated party under the RFS2 program, 
foreign producers must allow for potential visits by EPA enforcement 
personnel to review the completeness and accuracy of records and 
registration information. Non-compliance with any of these requirements 
could be grounds for refusing to allow renewable fuel from such a 
foreign producer to be imported into the U.S.
    For RFS2, we are proposing a number of additional provisions to 
address foreign companies that produce renewable fuel for export to the 
United States, but that do not generate their own RINs for that 
renewable fuel. These provisions are intended to account for the 
greater difficulties in verifying the validity of RINs for imported 
renewable fuel when the importer is generating the RINs, given that the 
importer would generally not have direct knowledge of the feedstocks 
used to produce the renewable fuel, the land used to grow those 
feedstocks, or the fuel production process. We believe that these 
additional provisions would be necessary to ensure that RINs 
representing imported renewable fuel and used by obligated parties have 
been generated appropriately.
    As described more fully in Section III.D.2.c below, importers would 
only be allowed to import renewable fuel from registered foreign 
producers and would be required to generate RINs for all imported 
renewable fuel that has not been assigned RINs by the foreign producer. 
Like domestic and foreign producers who generate RINs, the importer 
must be able to determine if the renewable biomass definition has been 
met before generating RINs. The importer must also have enough 
information about the production process and feedstock to be able to 
use the lookup table to identify the appropriate D code to include in 
the RINs he generates. Since the foreign producer is the only party who 
can provide this information, we believe that it would be appropriate 
to require the foreign producer of any renewable fuel exported to the 
U.S. to provide this information to the U.S. importer before the 
renewable fuel enters U.S. commerce even if the foreign producer is not 
generating RINs himself. Moreover, the foreign producer should be 
liable for the accuracy of this information just as if he were the 
party generating RINs. Therefore, in order to ensure that RINs are 
valid regardless of who generates them, we propose that all the 
provisions described above that would be applicable to a foreign 
producer who generates RINs would also apply to a foreign producer who 
does not generate RINs but still exports renewable fuel to the U.S. 
This would include registration with the EPA under the RFS2 program, 
being subject to all the recordkeeping, reporting, and attest 
engagement requirements, and posting a bond. The only exception would 
be that the foreign producer would not be required to segregate a 
specific volume between the foreign producer's facility and the import 
facility if the foreign producer is not generating RINs, since the 
importer would be the primary party responsible for measuring the 
volume before generating RINs.
    Although we are proposing that RINs for imported renewable fuel 
could be generated by either the importer or the foreign producer, it 
is possible that this could result in difficulty in verifying that only 
one set of RINs has been generated for a given volume of renewable 
fuel. One possible solution would be to require a foreign producer to 
make a decision regarding RIN generation that would apply for an entire 
calendar year. Under this approach, a foreign producer would be 
required to either generate RINs for all the renewable fuel that he 
exports to the U.S within a calendar year, or to generate no RINs for 
the renewable fuel that he exports to the U.S within a calendar year. 
While we are not proposing this approach it today's action, we request 
comment on it.
    As described in Section III.B.4.b.ii, we are proposing that 
domestic producers could only introduce renewable fuel into commerce 
without generating RINs if they demonstrate that feedstocks used to 
produce the fuel did not meet the definition of renewable biomass. Thus 
it would not be sufficient for a domestic producer to simply fail to 
make a demonstration that the renewable biomass definition had been 
met, and thereby avoid generation of RINs. We propose that a similar 
approach would be applied to imported renewable fuel. As a result, all 
renewable fuel that would be imported into the U.S. would be required 
to come with

[[Page 24948]]

documentation regarding the status of the feedstock's compliance with 
the renewable biomass definition. In the case of documentation 
indicating that the renewable biomass definition had been met, the 
importer would be required to generate RINs. In the case of 
documentation indicating that the renewable biomass definition had not 
been met, the importer would be prohibited from generating RINs but 
could still import the renewable fuel into the U.S. Renewable fuel that 
was not accompanied by any documentation regarding the status of the 
feedstock's compliance with the renewable biomass definition could not 
be imported into the U.S.
    Our proposed approach to foreign producers is consistent with the 
approach we propose taking for domestic producers, in that the producer 
is responsible for ensuring that RINs generated for renewable fuel used 
in the U.S. are valid and categorized appropriately. While our proposed 
approach to foreign producers of renewable fuel under RFS2 would 
require additional actions in comparison to their general requirements 
under RFS1, we believe these provisions would be necessary to ensure 
that the volume mandates shown in Table II.A.1-1 are met, given the new 
definitions for renewable fuel and renewable biomass in EISA. We 
request comment on our proposed approach to foreign producers.
c. Importers
    Under RFS1, importers who import more than 10,000 gallons in a 
calendar year must generate RINs for all imported renewable fuel based 
on its type, except for cases in which the foreign producer generated 
RINs for cellulosic biomass ethanol or waste-derived ethanol. Due to 
the new definitions of renewable fuel and renewable biomass in EISA, 
importers could no longer generate RINs under RFS2 on the basis of fuel 
type alone. Instead, they must be able to determine whether or not the 
renewable biomass definition has been met for the renewable fuel they 
intend to import, and they must also have sufficient information about 
the feedstock and process used to make the renewable fuel to allow them 
to identify the appropriate D code from the lookup table for use in the 
RINs they generate. As described in Section III.D.2.b above, we are 
proposing that in order for an importer to import renewable fuel into 
the U.S., the foreign producer would have to provide this information 
to the importer.
    Under today's proposal, importers would be able to import renewable 
fuels only under one of the following scenarios:
    1. The importer receives RINs generated by the registered foreign 
producer when he imports a volume of renewable fuel.
    2. The imported renewable fuel is not accompanied by RINs generated 
by the registered foreign producer, and the foreign producer provides 
the importer with:

--A demonstration that the renewable biomass definition has been met 
for the volume of renewable fuel being imported.
--Information about the feedstock and production process used to 
produce the renewable fuel.

    In this case, the importer would be required to generate RINs for 
the imported renewable fuel before introducing it into commerce in the 
contiguous 48 states or Hawaii.
    3. The imported renewable fuel is not accompanied by RINs generated 
by the registered foreign producer, and the foreign producer provides 
the importer with a demonstration that the renewable biomass definition 
has not been met for the volume of renewable fuel being imported. See 
further discussion of this issue in Section III.B.4.b.ii. The importer 
would be prohibited from generating RINs for the imported volume, but 
could still introduce the renewable fuel into commerce.
    If none of these scenarios applied, the importer would be 
prohibited from importing renewable fuel. Our proposed approach to 
imported fuels would apply to both neat renewable fuel and renewable 
fuels blended into gasoline or diesel.
    As described in Section III.B.4.e, we also seek comment on an 
alternative approach to imported renewable fuel in which foreign 
renewable fuel producers would have the option of not participating in 
RFS2 but still export renewable fuel to the U.S. Under this alternative 
approach, foreign producers would have to meet requirements for 
segregating their fuel from renewable fuel for which RINs were 
generated, and the importer of their fuel would be required to track it 
to ensure that the fuel remains segregated in the U.S. and is not used 
by a domestic company for illegal RIN generation.
    While it is important that all RINs be based on accurate 
information about the feedstocks and production process used to produce 
the renewable fuel, it may not be necessary to place the burden upon 
importers for acquiring this information before they generate RINs. 
Instead, an alternative approach would prohibit importers from 
generating any RINs, and instead require foreign producers to generate 
RINs for all renewable fuel that they export to the U.S. We recognize 
that this would be a significant change from RFS1, and thus we are not 
proposing it. However, since it would place the same responsibilities 
on foreign producers as domestic producers, we request comment on it.
3. Facilities With Multiple Applicable Pathways
    If a given facility's operations can be fully represented by a 
single pathway, then a single D code taken from the lookup table will 
be applicable to all RINs generated at or imported into that facility. 
However, we recognize that this will not always be the case. Some 
facilities use multiple feedstocks at the same time, or switch between 
different feedstocks over the course of a year. A facility may be 
modified to produce the same fuel but with a different process, or may 
be modified to produce a different type of fuel. Any of these 
situations could result in multiple pathways being applicable to a 
facility, and thus there may be more than one D code used for various 
RINs generated at the facility.
    If more than one pathway applies to a facility within a compliance 
period, no special steps would need to be taken if the D codes were the 
same for all the applicable pathways. In this case, all RINs generated 
at the facility would have the same D code. As for all other producers, 
the producer with multiple applicable pathways would describe its 
feedstock(s), fuel type(s), and production process(es) in its annual 
report to the Agency so that we could verify that the D code used was 
appropriate.
    However, if more than one pathway applies to a facility within a 
compliance period and these pathways have been assigned different D 
codes, then the producer must determine which D codes to use when 
generating RINs. There are a number of different ways that this could 
occur, and our proposed approach to designating D codes for RINs in 
these cases is described in Table III.D.3-1.

[[Page 24949]]



  Table III.D.3-1--Proposed Approach To Assigning Multiple D Codes for
                      Multiple Applicable Pathways
------------------------------------------------------------------------
              Case                    Description      Proposed approach
------------------------------------------------------------------------
1...............................  The pathway         The applicable D
                                   applicable to a     code used in
                                   facility changes    generating RINs
                                   on a specific       must change on
                                   date, such that     the date that the
                                   one single          fuel produced
                                   pathway applies     changes pathways.
                                   before the date
                                   and another
                                   single pathway
                                   applies on and
                                   after the date.
2...............................  One facility        The volumes of the
                                   produces two or     different types
                                   more different      of renewable fuel
                                   types of            should be
                                   renewable fuel at   measured
                                   the same time.      separately, with
                                                       different D codes
                                                       applied to the
                                                       separate volumes.
3...............................  One facility uses   For any given
                                   two or more         batch of
                                   different           renewable fuel,
                                   feedstocks at the   the producer
                                   same time to        should assign the
                                   produce a single    applicable D
                                   type of renewable   codes using a
                                   fuel.               ratio (explained
                                                       below) defined by
                                                       the amount of
                                                       each type of
                                                       feedstock used.
------------------------------------------------------------------------

    In general, we are not aware of a scenario in which a facility uses 
two different processes in parallel to convert a single type of 
feedstock into a single type of renewable fuel. Therefore, we have not 
created a case in Table III.D.3-1 to address it. However, we know that 
some corn-ethanol facilities may dry only a portion of their 
distiller's grains and leave the remainder wet. Using the lifecycle 
with an assumed 100 year timeframe and 2% discount rate for GHG 
emission impacts, the treatment of the distiller's grains could impact 
the determination of whether the 20% GHG threshold for renewable fuel 
has been met, a corn-ethanol facility that dries some portion of its 
distiller's grains would need to implement additional technologies in 
order to qualify to generate RINs for all the ethanol it produces (if 
the facility has not been grandfathered). The lifecycle analyses 
conducted for this proposal only examined cases in which a corn-ethanol 
facility dried 100% of its distiller's grains or left 100% of its 
distiller's grains wet. As a result, a corn-ethanol facility that dried 
only a portion of its distiller's grain would be treated as if it dried 
100% of its grains, and would thus need to implement additional GHG-
reducing technologies as described in the lookup table in order to 
qualify to generate RINs. This is reflected in the list of required 
production technologies in the lookup table at Sec.  80.1426(d) for 
facilities that dry any portion of their distiller's grains. In 
practice, depending on the selection of other technologies, it may be 
possible for a facility using some combination of dry and wet 
distiller's grains to meet the 20% GHG threshold. Therefore we request 
comment on whether a selection of pathways should be included in the 
lookup table that represent corn-ethanol facilities that dry only a 
portion of their distiller's grains. We also request comment on whether 
RINs could be assigned to only a portion of the facility's ethanol in 
cases wherein only a portion of the distiller's grains are dried.
    We propose that the cases listed in Table III.D.3-1 be treated as 
hierarchical, with Case 2 only being used to address a facility's 
circumstances if Case 1 is not applicable, and Case 3 only being used 
to address a facility's circumstances if Case 2 is not applicable. We 
believe that this approach covers all likely cases in which multiple 
applicable pathways may apply to a renewable fuel producer. Some 
examples in which Case 2 or 3 would apply are provided in Table 
III.D.3-2.

     Table III.D.3-2--Examples of Facilities With Multiple Pathways
------------------------------------------------------------------------
                                      Applicable
              Example                    case            Reasoning
------------------------------------------------------------------------
Facility makes both diesel and                 2  The production of two
 naphtha (a gasoline blendstock)                   types of renewable
 from gasified biomass in a Fischer-               fuel from the same
 Tropsch process.                                  feedstock and process
                                                   makes it highly
                                                   likely that the two
                                                   pathways would be
                                                   assigned the same D
                                                   code. If LCA
                                                   determined that this
                                                   was not the case, the
                                                   volumes of diesel and
                                                   naphtha can be
                                                   measured separately
                                                   and assigned separate
                                                   batch-RINs with
                                                   different D codes.
Facility produces ethanol from corn            3  There is only one fuel
 starch and corn cobs/husks.                       produced, so Case 2
                                                   cannot apply.
Facility makes both ethanol and                2  Case 2 is the default
 butanol through two different                     since there are two
 processes using corn starch.                      separate fuels
                                                   produced. However,
                                                   Case 3 would not
                                                   apply regardless
                                                   because there is only
                                                   one feedstock.
Facility makes ethanol through an              3  There is only one fuel
 enzymatic hydrolysis process using                produced, so Case 2
 both switchgrass and corn stover.                 cannot apply.
------------------------------------------------------------------------

    A facility where two or more different types of feedstock were used 
to produce a single fuel (such as Case 3 in Table III.D.3-1) would be 
required to generate two or more separate batch-RINs \26\ for a single 
volume of renewable fuel, and these separate batch-RINs would have 
different D codes. The D codes would be chosen on the basis of the 
different pathways as defined in the lookup table in Sec.  80.1426(d). 
The number of gallon-RINs that would be included in each of the batch-
RINs would depend on the relative amount of the different types of 
feedstocks used by the facility. We propose to use the useable energy 
content of the feedstocks to determine how many gallon-RINs should be 
assigned to each D code. Our proposed calculations are given in the 
regulations at Sec.  80.1126(d)(5).
---------------------------------------------------------------------------

    \26\ Batch-RINs and gallon-RINs are defined in the RFS1 
regulations at 40 CFR 80.1101(o).
---------------------------------------------------------------------------

    In determining the useable energy content of the feedstocks, we 
propose to take into account several elements to ensure that the number 
of gallon-RINs associated with each D code is appropriate. For 
instance, we propose

[[Page 24950]]

that only that portion of a feedstock which is expected to be converted 
into renewable fuel by the facility should be counted in the 
calculation. For example, a biochemical cellulosic ethanol conversion 
process that could not convert the lignin into ethanol would not 
include the lignin portion of the biomass in the calculation. This 
approach would also take into account the conversion efficiency of the 
facility. We propose that the producer of the renewable fuel would be 
required to designate this fraction for the feedstocks processed by his 
facility and to include this information as part of its reporting 
requirements.
    We are also proposing to use the energy content of the feedstocks 
instead of their mass since we believe that their relative energy 
contents are more closely related than their mass to the energy in the 
renewable fuel. Producers would be required to designate the energy 
content (in Btu/lb) of the portion of each of their feedstocks which is 
converted into fuel. We request comment on whether producers would 
determine these values independently for their own feedstocks, or 
whether a standard set of such values should be developed and 
incorporated into the regulations for use by all renewable fuel 
producers. If we did specify a standard set of energy content values, 
we request comment on what those values should be and/or the most 
appropriate sources for determining those values.
    Some components in the calculation of the useable energy content of 
feedstocks are unlikely to vary significantly for a particular type of 
feedstock. This would include that portion of a feedstock which is 
expected to be converted into renewable fuel by the facility, and the 
relative amount of energy in the two feedstocks. For these factors, we 
propose that one set of values be determined by the producer and 
applied to all renewable fuel production within a calendar year. The 
values could be reassessed annually and adjusted as necessary.
    Although we are proposing annual determinations of the portion of a 
feedstock which is expected to be converted into renewable fuel by the 
facility and the relative amount of energy in the two feedstocks, we 
are proposing daily determinations of the total mass of each type of 
feedstocks used by the facility. This approach would take into account 
the fact that the relative amount of the different feedstocks used 
could vary frequently, and thus the determination of the total useable 
energy content of the feedstocks would be unique to the renewable fuel 
produced each day. We believe that renewable fuel producers would have 
ready access to information about total feedstock mass used each day, 
such that the timely generation of RINs should not be unduly affected. 
We request comment on the effort and time involved in collecting 
information on feedstock mass and translating this information on a 
daily basis into RINs assigned to volumes of renewable fuel.
    In order to generate RINs when the processing of two or more 
different feedstocks in the same facility results in two or more 
different applicable D codes but a single renewable fuel, the producer 
would continue to determine the total number of gallon-RINs that must 
be generated for and assigned to a given volume of renewable fuel using 
the process established under RFS1. In short, the total volume of the 
renewable fuel would be multiplied by its Equivalence Value. However, 
the feedstock's useable energy content would be used to divide the 
resulting number of gallon-RINs into two or more groups, each 
corresponding to a different D code. Two, three, or more separate 
batch-RINs could then be generated and assigned to the single volume of 
renewable fuel. The sum of all gallon-RINs from the different batch-
RINs would be equal to the total number of gallon-RINs that must be 
generated to represent the volume of renewable fuel.
    As described in Section III.J, we propose that in their reports, 
producers of renewable fuel be required to submit information on the 
feedstocks they used, their production processes, and the type of 
fuel(s) they produced during the compliance period. This would apply to 
both domestic producers and foreign producers who export any renewable 
fuel to the U.S. We would use this information to verify that the D 
codes used in generating RINs were appropriate.
4. Facilities That Co-Process Renewable Biomass and Fossil Fuels
    We expect situations to arise in which a producer uses a renewable 
feedstock simultaneously with a fossil fuel feedstock, producing a 
single fuel that is only partially renewable. For instance, biomass 
might be cofired with coal in a coal-to-liquids (CTL) process that uses 
Fischer-Tropsch chemistry to make diesel fuel, biomass and waste 
plastics might be fed simultaneously into a catalytic or gasification 
process to make diesel fuel, or vegetable oils could be fed to a 
hydrotreater along with petroleum to produce a diesel fuel. In these 
cases, the diesel fuel would be only partially renewable. We propose 
that RINs must be generated in such cases, but in such a way that the 
number of gallon-RINs corresponds only to the renewable portion of the 
fuel.
    Under RFS1, we created a provision to address the co-processing of 
``renewable crudes'' along with petroleum feedstocks to produce a 
gasoline or diesel fuel that is partially renewable. See 40 CFR 
80.1126(d)(6). However, this provision would not apply in cases where 
either the renewable feedstock or the fossil fuel feedstock is a gas 
(e.g., biogas, natural gas) or a solid (e.g. biomass, coal). Therefore, 
we propose to eliminate the existing provision applicable only to 
liquid feedstocks and replace it with a more comprehensive approach 
that could apply to liquid, solid, or gaseous feedstocks and any type 
of conversion process. Our proposed approach would be similar to the 
treatment of renewable fuels with multiple D codes as described in 
Section III.D.3 above. Thus, the producer would determine the renewable 
fuel volume that would be assigned RINs based on the amount of energy 
in the renewable feedstock relative to the amount of energy in the 
fossil feedstock. Just as two different batch-RINs would be generated 
for a single volume of renewable fuel produced from two different 
renewable feedstocks, only one batch-RIN would be generated for a 
single volume of renewable fuel produced from both a renewable 
feedstock and a fossil feedstock, and this one batch-RIN would be based 
on the contribution that the renewable feedstock makes to the volume of 
renewable fuel. See Sec.  80.1426(d)(6) for our proposed calculations 
under these circumstances.
    For facilities that co-process renewable biomass and fossil fuels 
to produce a single fuel that is partially renewable, we propose to use 
the relative energy in the feedstocks to determine the number of 
gallon-RINs that should be generated. As shown in the regulations at 
Sec.  80.1426(d)(6), the calculation of the relative energy contents 
would include factors that take into account the conversion efficiency 
of the plant, and as a result, potentially different reaction rates and 
byproduct formation for the various feedstocks would be accounted for. 
The relative energy content of the feedstocks would be used to adjust 
the basic calculation of the number of gallon-RINs downward from that 
calculated on the basis of fuel volume alone. The D code that would be 
assigned to the RINs would be drawn from the lookup table in the 
regulations as if the feedstock was entirely renewable biomass. Thus, 
for instance, a coal-to-liquids plant that co-processes some cellulosic 
biomass to make diesel fuel would be treated as a plant that

[[Page 24951]]

produces only cellulosic diesel for purposes of identifying the 
appropriate D code.
    One drawback of our proposed approach is that it does nothing to 
address lifecycle GHG emissions associated with the portion of the fuel 
that comes from the fossil fuel feedstock. While the lifecycle GHG 
thresholds under RFS2 are specific to fuels made from renewable 
biomass, allowing a fuel producer to generate RINs for the co-
processing of renewable biomass with fossil fuels might provide a 
greater incentive for production of transportation fuels from processes 
that have high lifecycle GHGs. In such cases, the GHG benefits of the 
renewable fuel may be overwhelmed by the GHG increases of the fossil 
fuel. This is of particular concern for CTL processes which generally 
produce higher lifecycle GHG emissions per unit of transportation fuel 
produced than traditional refinery processes that use petroleum. Under 
our proposed approach to the treatment of co-processing of renewable 
biomass and fossil fuels, incentives would be provided for renewable 
fuels with lower lifecycle GHG emissions, but there will be little 
disincentive for production of high GHG-emitting fuels made from fossil 
fuels.
    As an alternative to our proposed approach, we could treat fuels 
produced through co-processing of renewable biomass and fossil fuel 
feedstocks in an aggregate fashion rather than focusing only on the 
renewable portion of those fuels. In this approach, we would require 
the whole fuel produced at co-processing facilities to meet the 
lifecycle GHG thresholds under RFS2. If, for instance, a diesel fuel 
produced from co-processing renewable biomass and coal in a Fischer-
Tropsch process were determined to not meet the 20% GHG threshold, no 
RINs could be generated even though the renewable portion of the diesel 
fuel might meet the 20% GHG threshold. However, this alternative 
approach would require a lifecycle analysis that is specific to the 
relative amounts of renewable biomass and fossil fuel feedstock being 
used at a particular facility, which would in turn require a facility-
specific lifecycle GHG model. As described in Section II.A.3, this is 
beyond the capabilities of our current modeling tools. Moreover, this 
alternative approach could have undesirable effects on facilities that 
produce renewable fuel from multiple renewable feedstocks. For 
instance, if a facility produced ethanol from both corn starch and corn 
stover and the lifecycle GHG assessment was conducted for this specific 
facility as a whole, it might not meet the 60% GHG threshold for 
cellulosic biofuel. As a result, the portion of the ethanol produced 
from corn stover could not be counted as cellulosic biofuel but would 
instead count only as renewable fuel, even though our lifecycle 
analyses have determined that ethanol from corn stover does meet the 
60% GHG threshold. Nevertheless, we seek comment on this alternative 
approach.
    As another alternative to using the relative energy in the 
feedstocks to determine the number of gallon-RINs that should be 
generated, we could allow renewable fuel producers to use an accepted 
test method to directly measure the fraction of the fuel which 
originates with biomass rather than a fossil fuel feedstock. For 
instance, ASTM test method D-6866 can be used to determine the 
renewable content of gasoline. However, such a test method could not 
distinguish between fuel made from feedstocks that meet the definition 
of renewable biomass, and other biomass feedstocks which do not meet 
the definition of renewable biomass. We request comment on the use of 
ASTM D-6866 or equivalent test methods to determine the number of RINs 
generated when multiple feedstocks are used simultaneously to make a 
fuel.
5. Treatment of Fuels Without an Applicable D Code
    Among all fuels covered by our proposed RFS2 program, we have 
identified a number of specific ``pathways'' of fuels, defined by fuel 
type, feedstock, and various production process characteristics. This 
list includes fuels that either already exist in the marketplace or are 
expected to exist sometime during the next decade, and for which we had 
sufficient information to conduct a lifecycle analysis of the GHG 
emissions. As described in III.D.2, we have assigned each pathway a D 
code corresponding to the four categories of renewable fuel defined in 
EISA.
    Despite our efforts to explicitly address the existing or possible 
pathways in our proposed program, it is expected that a fuel, process, 
or feedstock will arise that is a renewable fuel meeting the RFS 
definitions, and yet is not among the fuels we explicitly identified in 
the regulations as a RIN-generating fuel. This could occur for an 
entirely new fuel type, a known fuel produced from a new feedstock, or 
a known fuel produced through a unique production process. In such 
cases, the fuel may meet our definition of renewable fuel covered under 
our program, but would not have been assigned the appropriate D code in 
the regulations. To address some of these fuel pathways, we are 
proposing the use of default D codes.\27\
---------------------------------------------------------------------------

    \27\ Additional default requirements applicable to importers of 
renewable fuels are discussed in Section III.D.2.c.
---------------------------------------------------------------------------

    Under our proposed approach, the producer would be required to 
register under the RFS program and provide information about their 
facility as described in Section III.C. The producer will also be 
required to provide any information necessary for EPA to perform a 
proper lifecycle analysis. Additionally, the company would need to 
register their renewable fuel under title 40 CFR part 79 as a motor 
vehicle fuel. If EPA determines, based on the company's registration, 
that they are not producing renewable fuel, the company will not be 
able to generate RINs.
    In order to generate RINs, the producer of renewable fuel would 
apply through our registration system to use the D code that best 
represents his combination of fuel type, feedstock, and production 
process. If the producer's combination of fuel type and feedstock, but 
not production process, is represented in an already defined pathway 
combination of fuels, processes, or feedstocks, the producer would use 
the highest numerical D code applicable to the fuel and feedstock 
combination. For example, if a fuel and feedstock spans the D Codes 3 
and 4 then the producer would use 4 until the regulations were updated. 
The producer then would generate RINs using the D code 4, until EPA 
could perform a lifecycle analysis and issue a change to the 
regulations to reflect the new pathway. If the producer is making a new 
fuel or using a new feedstock that producer will still need to apply, 
but would be unable to generate RINs until the regulations were updated 
with the new pathway.
    Since certain combinations of fuel, production process, and 
feedstock have been determined through our lifecycle analysis to not 
meet the minimum 20% GHG threshold, they would be ineligible to 
generate RINs and EPA would not allow producers using those processes 
to generate RINs using a default D code. To effectuate this, we propose 
to provide a statement in the regulations of pathways that are 
prohibited from using a default D code. For example, if a producer is 
producing ethanol from cornstarch in a process that uses coal or 
natural gas for process heat, then regardless of other elements of the 
production process the producer may not use a default D code, but must 
register and provide information

[[Page 24952]]

necessary to conduct a lifecycle analysis.
    EPA will not conduct a rulemaking every year to adjust the 
regulations for new fuels, processes, or feedstocks. EPA will 
periodically update the regulations as necessary under CAA section 
211(o)(4) and may take the opportunity to update the list of fuel 
pathways. Companies are encouraged to work with EPA early to provide 
information about fuels, processes, or feedstocks not in the 
regulations so that we can do a proper lifecycle analysis before these 
fuels, processes, or feedstocks are commercially viable. EPA is 
proposing that if the regulations are not updated with in 5 years of 
receipt of the application and the application is not rejected in that 
time then the producer will no longer be able to generate RINs using a 
default D code until the regulations are updated.
6. Carbon Capture and Storage (CCS)
    One element of the production process that may enable renewable 
fuel producers to greatly improve their GHG emissions is carbon capture 
and storage (CCS). CCS involves the process of capturing CO2 
from an industrial or energy-related source, transporting it to a 
suitable storage site, and isolating it from the atmosphere for long 
periods of time. While we are not proposing a specific pathway in 
today's NPRM that would allow a renewable fuel producer to use CCS to 
demonstrate compliance with the GHG thresholds, we believe that CCS 
could be an effective method for significantly reducing the GHG 
emissions associated with renewable fuel production.
    Although there are several possible approaches for long-term 
storage of CO2, this section will only address geologic 
storage as a means to reduce CO2 emissions from renewable 
fuel production facilities. This method entails injecting 
CO2 deep underground and monitoring to ensure long-term 
isolation from the atmosphere. The remainder of this section describes 
the efforts to establish regulatory requirements for CCS, and the 
further work that needs to be done before allowing the use of CCS as an 
element in pathways eligible for generating RINs under the RFS2 
program.
    Although there is limited experience with integrated CCS systems in 
the US, where CO2 is captured, transported and injected for 
long-term storage, there are commercial CCS projects operating today 
and several DOE pilot projects underway to further demonstrate CCS in a 
variety of industrial sectors and geological settings. The EPA has been 
working closely with DOE to collectively ensure that governmental 
research programs address the range of potential environmental risks 
associated with CCS and that appropriate regulatory frameworks are in 
place to manage risks.\28\
---------------------------------------------------------------------------

    \28\ More information on the EPA's UIC Program and ongoing 
research into CCS issues is available at: http://www.epa.gov/safewater/uic/wells_sequestration.html.
---------------------------------------------------------------------------

    The EPA has experience regulating underground injection of various 
fluids and believes that well selected, designed, and managed sites can 
sequester CO2 for long periods of time. The Safe Drinking 
Water Act's (SDWA) Underground Injection Control (UIC) Program has been 
successfully regulating tens of thousands of injection wells for over 
35 years. The UIC program's siting, well construction, and monitoring 
and testing requirements are keys to ensuring that injected fluids 
remain in the geologic rock formations specifically targeted for 
injection.
    In March 2007, the EPA issued UIC permitting guidelines for pilot 
geologic sequestration projects in order to ensure that these projects 
could move forward under an appropriate regulatory framework. 
Subsequently, on July 25, 2008, EPA issued a proposed rulemaking that 
would address commercial-scale projects and establish the regulatory 
requirements for underground injection of CO2 for the 
purpose of geologic storage (73 FR 43492). These proposed regulations 
include permitting requirements, criteria for establishing and 
maintaining the mechanical integrity of wells, minimum criteria for 
siting, injection well construction and operating requirements, 
recordkeeping and reporting requirements, etc. While these regulations 
cover many operational aspects of underground injection and monitoring 
geologic sequestration sites, their purpose is to protect underground 
sources of drinking water. The SDWA does not provide authority to 
develop regulations for all areas related to CCS, including capture and 
transport of CO2 and accounting or certification for GHG 
emissions reductions. The UIC requirements will not replace or 
supersede other statutory or regulatory requirements for protection of 
human health and the environment. Thus, parties that implemented CCS 
would still need to obtain all necessary permits from appropriate State 
and Federal authorities under the Clean Air Act or any other applicable 
statutes and regulations.
    Specific areas that would need to be addressed before allowing the 
renewable fuel producers to benefit from CCS in meeting GHG thresholds 
include: the means through which the CO2 would be captured 
from the renewable fuel production facility, the minimum fraction that 
must be captured, appropriate means for transporting to the injection 
site, and appropriate monitoring procedures to ensure long-term storage 
of CO2. We believe the CO2 that would be most 
readily available for capture in an ethanol production facility would 
be that which is produced during the fermentation process, not 
CO2 that is generated during the combustion of fossil fuels 
for process energy, since CO2 from the fermentation process 
provides a more concentrated stream that is more amenable to capture. 
However, we request comment on the efficacy of capturing CO2 
from the combustion of fossil fuels for process heat.
    A mechanism for accounting for potential leakage of captured 
CO2 during transport to the storage site or after injection 
has occurred would also be required. The renewable fuel producer would 
be responsible for tracking any leaks that occur after CO2 
capture. We request comment on the type and level of surface and/or 
subsurface monitoring that would be required to demonstrate long-term 
storage of CO2. We also request comment on whether 
additional monitoring and reporting requirements would be appropriate. 
For example, whether there should be a requirement for the monitoring 
and reporting of CO2 volumes captured, transported, injected 
and stored, as well as any fugitive emissions released. We seek comment 
on the appropriateness of establishing a performance standard for 
CO2 leakage during transport, injection, and/or geologic 
storage, and any data that might be available to help develop such a 
performance standard.
    Finally, in order to generate RINs, the renewable fuel producer 
would have to, at minimum, demonstrate that a sufficient amount of 
CO2 was sequestered to reach the appropriate lifecycle GHG 
threshold. We expect that the regulations would need to specify the 
minimum fraction of CO2 emitted that must be captured and 
stored in order for a renewable fuel producer to qualify for generating 
RINs. We request comment on whether this approach is appropriate.

E. Applicable Standards

    CAA section 211(o)(3) describes how the applicable standards are to 
be calculated. The only changes made to this provision by EISA are 
substituting ``transportation fuel'' for gasoline, and reflecting the 
expanded number of years

[[Page 24953]]

and additional renewable fuel categories added by Congress in CAA 
211(o)(2). In general the form of the standard will not change under 
RFS2. The renewable fuel standards will continue to be expressed as a 
volume percentage, and will be used by each refiner, blender or 
importer to determine their renewable volume obligations. The 
applicable percentages are set so that if each regulated party meets 
the percentages, then the amount of renewable fuel, cellulosic biofuel, 
biomass-based diesel, and advanced biofuel used will meet the volumes 
specified in Table II.A.1-1.\29\
---------------------------------------------------------------------------

    \29\ Actual volumes can vary from the amounts required in the 
statute. For instance, lower volumes may result if the statutorily 
required volumes are adjusted downward according to the waiver 
provisions in CAA 211(o)(7)(D). Also, higher or lower volumes may 
result depending on the actual consumption of gasoline and diesel in 
comparison to the projected volumes used to set the standards.
---------------------------------------------------------------------------

    The new renewable fuel standards would be based on both gasoline 
and diesel volumes as opposed to only gasoline. Under CAA section 
211(o)(3), EPA must determine the refiners, blenders and importers who 
are subject to the standard. We propose that the standard would apply 
to refiners, blenders and importers of diesel in addition to gasoline, 
for both highway and nonroad uses. As described more fully in Section 
III.F.3, we are proposing at this time that other producers of 
transportation fuel, such as producers of natural gas, propane, and 
electricity from fossil fuels, would not be subject to the standard. 
Since the standard would apply to refiners, blenders and importers of 
gasoline and diesel, these are also the transportation fuels that would 
be used to determine the annual volume obligation of the refiner, 
blender or importer.
    The projected volumes of gasoline and diesel used to calculate the 
standards would continue to be provided by EIA's Short-Term Energy 
Outlook (STEO). The standards applicable to a given calendar year would 
be published by November 30 of the previous year. The renewable fuel 
standards would also continue to take into account various adjustments. 
For instance, gasoline and diesel volumes would be adjusted to account 
for the required renewable fuel volumes, and gasoline and diesel 
volumes produced by small refineries and small refiners would continue 
to be exempt through 2010.
    While the calculation methodology for determination of standards 
would not change, there would be four separate standards under the new 
RFS2 program, corresponding to the four separate volume requirements 
shown in Table II.A.1-1. The specific formulas we propose using to 
calculate the renewable fuel standards are described below in Section 
III.E.1.
    In order for an obligated party to demonstrate compliance, the 
percentage standards would be converted into the volume of renewable 
fuel each obligated party is required to satisfy. This volume of 
renewable fuel is the volume for which the obligated party is 
responsible under the RFS program, and would continue to be referred to 
as its Renewable Volume Obligation (RVO). Since there would be four 
separate standards under the RFS2 program, there would likewise be four 
separate RVOs applicable to each refiner, importer, or other obligated 
party. However, all RVOs would be determined in the same way as 
described in the current regulations at Sec.  80.1107, with the 
exception that each standard would apply to the sum of all gasoline and 
diesel produced or imported as opposed to just the gasoline volume. The 
formulas we propose using to calculate the RVOs under the RFS2 program 
are described in Section III.G.1.
1. Calculation of Standards
a. How Would the Standards Be Calculated?
    Table II.A.1-1 shows the required overall volumes of four types of 
renewable fuel specified in EISA. The four separate renewable fuel 
standards would be based primarily on (1) the 49-state \30\ gasoline 
and diesel consumption volumes projected by EIA, and (2) the total 
volume of renewable fuels required by EISA for the coming year. Each 
renewable fuel standard will be expressed as a volume percentage of 
combined gasoline and diesel sold or introduced into commerce in the 
U.S., and will be used by each obligated party to determine its 
renewable volume obligation.
---------------------------------------------------------------------------

    \30\ Hawaii opted-in to the original RFS program; that opt-in is 
carried forward to the proposed new program.
---------------------------------------------------------------------------

    While we are proposing that the standards be based on the sum of 
all gasoline and diesel, an alternative would split the standards 
between those that would be specific to gasoline and those that would 
be specific to diesel. To accomplish this, it would be necessary to 
project the fraction of the volumes shown in Table II.A.1-1 for 
cellulosic biofuel, advanced biofuel, and total renewable fuel that 
would represent gasoline-displacing renewable fuel, and apply this 
portion of the required volumes to gasoline (by definition the biomass-
based diesel standard would have no component relevant to gasoline). 
The remaining portion would apply to diesel. The result would be seven 
standards instead of four. This approach to setting standards would 
more readily align the RFS obligations with the relative amounts of 
gasoline and diesel produced or imported by each obligated party. For 
instance, a refiner that produced only diesel fuel would have no 
obligations under the RFS program for renewable fuels that are used to 
displace gasoline. However, this alternative approach relies on 
projections of the relative amounts of gasoline-displacing and diesel-
displacing renewable fuels that would need to be updated every year. 
While such projections would be available through our proposed 
Production Outlook Reports (see Section III.K), we nevertheless believe 
that such an approach would unnecessarily complicate the program, and 
thus we are not proposing it. However, we request comment on it.
    In determining the applicable percentages for a calendar year, EISA 
requires EPA to adjust the standard to prevent the imposition of 
redundant obligations on any person and to account for renewable fuel 
use during the previous calendar year by exempt small refineries, 
defined as refineries that process less than 75,000 bpd of crude oil. 
As a result, in order to be assured that the percentage standards will 
in fact result in the volumes shown in Table II.A.1-1, we must make 
several adjustments to what otherwise would be a simple calculation.
    As stated, the renewable fuel standards for a given year are 
basically the ratio of the amount of each type of renewable fuel 
specified in EISA for that year to the projected 49-state non-renewable 
combined gasoline and diesel volume for that year. While the required 
amount of total renewable fuel for a given year is provided by EISA, 
the Act requires EPA to use an EIA estimate of the amount of gasoline 
and diesel that will be sold or introduced into commerce for that year 
to determine the percentage standards. The levels of the percentage 
standards would be reduced if Alaska or a U.S. territory chooses to 
participate in the RFS2 program, as gasoline and diesel produced in or 
imported into that state or territory would then be subject to the 
standard.
    As mentioned above, we are proposing that EIA's STEO continue to be 
the source for projected gasoline, and now diesel, consumption 
estimates. These volumes include renewable fuel use. In order to 
achieve the volumes of renewable fuels specified in EISA, the gasoline 
and diesel volumes used to

[[Page 24954]]

determine the standard must be the non-renewable portion of the 
gasoline and diesel pools. In order to get total non-renewable gasoline 
and diesel volumes, we must subtract the total renewable fuel volume 
from the total gasoline and diesel volume. As with RFS1, the best 
estimation of the coming year's renewable fuel consumption is found in 
Table 11 (U.S. Renewable Energy Use by Sector: Base Case) of the STEO.
    CAA section 211(o) exempts small refineries \31\ from the RFS 
requirements until the 2011 compliance period. In RFS1, we extended 
this exemption to the few remaining small refiners not already 
exempted.\32\ Since EPA proposes that small refineries and small 
refiners continue to be exempt from the program until 2011 under the 
new RFS2 regulations, EPA will exclude their gasoline and diesel 
volumes from the overall non-renewable gasoline and diesel volumes used 
to determine the applicable percentages until 2011. EPA believes this 
is appropriate because the percentage standards need to be based on the 
gasoline and diesel subject to the renewable volume obligations, to 
achieve the overall required volumes of renewable fuel. Because the 
total small refinery and small refiner gasoline production volume is 
expected to be fairly constant compared to total U.S. transportation 
fuel production, we are proposing to estimate small refinery and small 
refiner gasoline and diesel volumes using a constant percentage of 
national consumption, as we did in RFS1. Using information from 
gasoline batch reports submitted to EPA for 2006, EIA data, and input 
from the California Air Resources Board regarding California small 
refiners, we estimate that small refinery volumes constitute 11.9% of 
the gasoline pool, and 15.2% of the diesel pool.
---------------------------------------------------------------------------

    \31\ Under section 211(o) of the Clean Air Act, small refineries 
are those with 75,000 bbl/day or less average aggregate daily crude 
oil throughput.
    \32\ See Section IV.B.2.
---------------------------------------------------------------------------

    CAA section 211(o) requires that the small refinery adjustment also 
account for renewable fuels used during the prior year by small 
refineries that are exempt and do not participate in the RFS2 program. 
Accounting for this volume of renewable fuel would reduce the total 
volume of renewable fuel use required of others, and thus directionally 
would reduce the percentage standard. However, as we discussed in RFS1, 
the amount of renewable fuel that would qualify, i.e., that was used by 
exempt small refineries and small refiners but not used as part of the 
RFS program, is expected to be very small. In fact, these volumes would 
not significantly change the resulting percentage standards. Whatever 
renewable fuels small refineries and small refiners blend will be 
reflected as RINs available in the market; thus there is no need for a 
separate accounting of their renewable fuel use in the equations used 
to determine the standards. We thus are proposing, as for RFS1, that 
this value be zero.
    Just as with their corresponding gasoline and diesel volumes, 
renewable fuels used in Alaska or U.S. territories are not included in 
the renewable fuel volumes that are subtracted from the total gasoline 
and diesel volume estimates. Section 211(o) of the Clean Air Act 
requires that the renewable fuel be consumed in the contiguous 48 
states, and any other state or territory that opts in to the program 
(Hawaii has subsequently opted in). However, because renewable fuel 
produced in Alaska or a U.S. territory is unlikely to be transported to 
the contiguous 48 states or to Hawaii, including their renewable fuel 
volumes in the calculation of the standard would not serve the purpose 
intended by section 211(o) of the Clean Air Act of ensuring that the 
statutorily required renewable fuel volumes are consumed in the 48 
contiguous states and any state or territory that opts in.
    In summary, we are proposing that the total projected non-renewable 
gasoline and diesel volumes from which the annual standards are 
calculated be based on EIA projections of gasoline and diesel 
consumption in the contiguous 48 states and Hawaii, adjusted by 
constant percentages of 11.9% and 15.2% in 2010 to account for small 
refinery/refiner gasoline and diesel volumes, respectively, and with 
built-in correction factors to be used when and if Alaska or a 
territory opt-in to the program. If actual gasoline and diesel 
consumption were to exceed the EIA projections, the result would be 
that renewable fuel volumes would exceed the statutory volumes. 
Conversely, if actual gasoline and diesel consumption was less than the 
EIA projection for a given year, actual renewable fuel volumes could be 
lower than the statutory volumes depending on market conditions. 
Additional special considerations in establishing the annual cellulosic 
biofuel standard are discussed below in Section III.E.1.c.
    The following formulas will be used to calculate the percentage 
standards:
[GRAPHIC] [TIFF OMITTED] TN26MY09.000

[GRAPHIC] [TIFF OMITTED] TN26MY09.001

[GRAPHIC] [TIFF OMITTED] TN26MY09.002

[GRAPHIC] [TIFF OMITTED] TN26MY09.003


[[Page 24955]]


Where

StdCB,i = The cellulosic biofuel standard for year i, in 
percent
StdBBD,i = The biomass-based diesel standard for year i, 
in percent
StdAB,i = The advanced biofuel standard for year i, in 
percent
StdRF,i = The renewable fuel standard for year i, in 
percent
RFVCB,i = Annual volume of cellulosic biofuel required by 
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFVBBD,i = Annual volume of biomass-based diesel required 
by section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFVAB,i = Annual volume of advanced biofuel required by 
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFVRF,i = Annual volume of renewable fuel required by 
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
Gi = Amount of gasoline projected to be used in the 48 
contiguous states and Hawaii, in year i, in gallons*
Di = Amount of diesel projected to be used in the 48 
contiguous states and Hawaii, in year i, in gallons
RGi = Amount of renewable fuel blended into gasoline that 
is projected to be consumed in the 48 contiguous states and Hawaii, 
in year i, in gallons
RDi = Amount of renewable fuel blended into diesel that 
is projected to be consumed in the 48 contiguous states and Hawaii, 
in year i, in gallons
GSi = Amount of gasoline projected to be used in Alaska 
or a U.S. territory in year i if the state or territory opts in, in 
gallons*
RGSi = Amount of renewable fuel blended into gasoline 
that is projected to be consumed in Alaska or a U.S. territory in 
year i if the state or territory opts in, in gallons
DSi = Amount of diesel projected to be used in Alaska or 
a U.S. territory in year i if the state or territory opts in, in 
gallons*
RDSi = Amount of renewable fuel blended into diesel that 
is projected to be consumed in Alaska or a U.S. territory in year i 
if the state or territory opts in, in gallons
GEi = The amount of gasoline projected to be produced by 
exempt small refineries and small refiners in year i, in gallons, in 
any year they are exempt per Sec. Sec.  80.1441 and 80.1442, 
respectively. Equivalent to 0.119 * (Gi - 
RGi).
DEi = The amount of diesel projected to be produced by 
exempt small refineries and small refiners in year i, in gallons, in 
any year they are exempt per Sec. Sec.  80.1441 and 80.1442, 
respectively. Equivalent to 0.152 * (Di - 
RDi).
    * Note that these terms for projected volumes of gasoline and 
diesel use include gasoline and diesel that has been blended with 
renewable fuel.

b. Proposed Standards for 2010
    In today's NPRM we are proposing the specific standards that would 
apply to all obligated parties in calendar year 2010. We will consider 
comments received on these standards as part of the comment period 
associated with today's NPRM, and we intend to issue a Federal Register 
notice by November 30, 2009 setting the applicable standards for 2010. 
While we are not proposing standards for 2011 and beyond, we present 
our current projections of these standards in the next section.
    Under CAA section 211(o)(7)(D)(i), EPA is required to make a 
determination each year regarding whether the required volumes of 
cellulosic biofuel for the following year can be produced. For any 
calendar year for which the projected volume of cellulosic biofuel 
production is less than the minimum required volume, the projected 
volume becomes the basis for the cellulosic biofuel standard. In such a 
case, the statute also indicates that EPA may also lower the required 
volumes for advanced biofuel and total renewable fuel.
    Based on information available to date, we believe that there are 
sufficient plans underway to build plants capable of producing 0.1 
billion gallons of cellulosic biofuel in 2010, the minimum volume of 
cellulosic biofuel required by EISA for 2010. Our April 2009 industry 
assessment concludes that there could be seven small commercial-scale 
plants online in 2010 (as well as a series of pilot and demonstration 
plants) capable of producing just over 100 million gallons of 
cellulosic biofuel. And since the majority of this production (73%) is 
projected to be cellulosic diesel, the ethanol-equivalent complaince 
volume could be closer to 145 million gallons. While it is possible 
that some of these plants could be delayed or a portion of the 
projected production may not meet the definition of ``cellulosic 
biofuel'' (due to mixed feedstocks), it is also possible that other 
plans could proceed ahead of their current schedules. For more on the 
2010 cellulosic biofuel production assessment, refer to Section 1.5.3.4 
of the DRIA
    On the basis of this information, we are not proposing that any 
portion of the cellulosic biofuel requirement for 2010 be waived. 
Therefore, we are proposing that the volumes shown in Table II.A.1-1 be 
used as the basis for the applicable standards for 2010. As described 
more fully in Section III.E.2 below, we are also proposing that the 
2010 standard for biomass-based diesel be based on the combined 
required volumes for 2009 and 2010, or a total of 1.15 billion gallons. 
The proposed standards for 2010 are shown in Table III.E.1.b-1.

             Table III.E.1.b-1--Proposed Standards for 2010
                                [Percent]
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Cellulosic biofuel.............................................     0.06
Biomass-based diesel...........................................     0.71
Advanced biofuel...............................................     0.59
Renewable fuel.................................................     8.01
------------------------------------------------------------------------

    As described more fully in Section III.E.1.d below, we are 
proposing that the RFS2 program take effect on January 1, 2010, but we 
are also taking comment on an effective date later than January 1, 
2010, including January 1, 2011 and a mid-2010 effective date. If the 
RFS2 program became effective mid-2010, the RFS1 program would apply 
during the first part of 2010 and the RFS2 program would apply for the 
remainder of the year. We request comment on whether the four proposed 
standards shown in Table III.E.1.b-1 would apply only to gasoline and 
diesel produced or imported after the RFS2 effective date or should 
apply to all gasoline and diesel produced in 2010. We also request 
comment on whether a single standard for total renewable fuel should 
apply under RFS1 regulations for the first part of 2010.
c. Projected Standards for Other Years
    As discussed above, we intend to set the percentage standards for 
each upcoming year based on the most recent EIA projections, and using 
the other sources of information as noted above. We would publish the 
standard in the Federal Register by November 30 of the preceding year. 
The standards would be used to determine the renewable volume 
obligations based on an obligated party's total gasoline and diesel 
production or import volume in a calendar year, January 1 through 
December 31. An obligated party will calculate its Renewable Volume 
Obligations (discussed in Section III.G.1) using the annual standards.
    For illustrative purposes, we have estimated the standards for 2011 
and later based on current information using the formulas discussed 
above, and assuming no modifications to the annual volumes 
required.\33\ These values are listed below in Table III.E.1.c-1. The 
required renewable fuel volumes specified in EISA are shown in Table 
II.A.1-1. The projected gasoline, diesel and renewable fuels volumes 
were determined from EIA's energy projections. Variables related to 
Alaska or territory opt-ins were set to zero since we do not have any 
information related

[[Page 24956]]

to their participation at this time. No adjustment was made for small 
refiner or small refinery volumes since their exemption is assumed to 
end at the end of the 2010 compliance period.
---------------------------------------------------------------------------

    \33\ ``Calculation of the Renewable Fuel Standard for Gasoline 
and Diesel,'' memo to the docket from Christine Brunner, ASD, OTAQ, 
EPA, April 2009.

                                Table III.E.1.c-1--Projected Standards Under RFS2
                                                    [percent]
----------------------------------------------------------------------------------------------------------------
                                                                             Biomass-
                                                               Cellulosic     based       Advanced    Renewable
                                                                biofuel       diesel      biofuel        fuel
----------------------------------------------------------------------------------------------------------------
2011........................................................         0.15         0.49         0.83         8.60
2012........................................................         0.31         0.61         1.22         9.31
2013........................................................         0.61        0.61a         1.68        10.09
2014........................................................         1.07        0.61a         2.28        11.05
2015........................................................         1.83        0.61a         3.35        12.48
2016........................................................         2.58        0.61a         4.40        13.49
2017........................................................         3.34        0.61a         5.46        14.56
2018........................................................         4.25        0.61a         6.68        15.80
2019........................................................         5.19        0.61a         7.95        17.11
2020........................................................         6.47        0.62a         9.25        18.50
2021........................................................         8.40        0.62a        11.21        20.54
2022........................................................        10.07        0.63a        13.21        22.65
----------------------------------------------------------------------------------------------------------------
\a\ These projected standards represent the minimum volume of 1.0 billion gallons required by EISA. The actual
  volume used to set the standard would be determined by EPA through a future rulemaking.

d. Alternative Effective Date
    Although we are proposing that the RFS2 regulatory program begin on 
January 1, 2010 which, depending on timing for the final rule, would 
allow approximately two months from the anticipated issuance of the 
rule to its implementation, we seek comment on whether an effective 
date later than January 1, 2010 would be necessary. If the RFS2 program 
was not made effective on January 1, 2010, the most straightforward 
alternative start date would be January 1, 2011. Delaying to 2011 would 
provide regulated parties additional lead time and would allow all the 
new requirements and standards to go into effect at the beginning of an 
annual compliance period. However, delaying to 2011 would also mean 
that demonstrating compliance with the separate requirements for 
biomass-based diesel, cellulosic biofuel, and advanced biofuel mandates 
would not go into effect until 2011. The total renewable fuel mandate 
in EISA may be able to be implemented with the RFS1 regulations until 
such time as the RFS2 regulations become effective. However, under the 
RFS1 regulations, this entire standard would be for conventional 
biofuels and would be applied to gasoline producers and importers only. 
There would be no obligation with respect to diesel fuel producers and 
importers, resulting in a numerically larger standard that would apply 
to gasoline producers only and which could compel them to market a 
larger proportion of ethanol as E85 to acquire sufficient RINs for 
compliance. One possible way to address this issue would be to reduce 
the 2010 total renewable fuel standard proportionately to reflect the 
application of the standard only to gasoline producers. However, it 
does not appear that EPA has statutory authority, or discretion under 
the RFS1 regulations, to modify the total renewable fuel mandate in 
this manner. As discussed below in Section III.E.2, any delay beyond 
January 1, 2010 also has implications for our proposed treatment of the 
biomass-based diesel volumes required for 2009. EPA invites comment on 
whether RFS2 implementation should be delayed to January 1, 2011 and, 
if so, the manner in which the EISA-mandated RFS program should be 
implemented prior to that date.
    Another alternative would be to delay the effective date of the 
RFS2 program to some time after January 1, 2010 but before January 1, 
2011. This alternative would raise the same issues described above 
(regarding the option of a delay until January 1, 2011) for that 
portion of 2010 during which RFS2 was not effective. It would also 
raise additional transition and implementation issues. For instance, we 
would need to determine whether diesel fuel producers and importers 
carry a total renewable fuel obligation calculated on the basis of 
their production for all of 2010 or just the production period in 2010 
during which the RFS2 regulations are effective. We would also need to 
determine whether the 2010 cellulosic biofuel, biomass-based diesel, 
and advanced biofuel standards applicable under RFS2 should apply to 
production of gasoline and diesel for all of 2010 or just the 
production that occurred after the RFS2 regulations were effective If 
the latter, EPA would need to determine the extent to which RFS1 RINs 
generated in the first part of 2010 could be used to satisfy RFS2 
obligations, given that some 2010 RINs would be generated under the 
RFS1 requirements while other 2010 RINs would be generated under RFS2 
requirements. To accomplish this, RINs generated under the RFS2 
requirements would need to be distinguished from RINs generated under 
RFS1 requirements through the RINs' D codes. Section III.A provides a 
more detailed description of this alternative approach to the 
assignment of D codes under the RFS2 program. For additional discussion 
of how RFS1 RINs would be treated in the transition to the RFS2 
program, see our proposed transition approach described in Section 
III.G.3.
    We are requesting comment on all issues related to the option of an 
RFS2 start date sometime after January 1, 2010, including the need for 
such a delayed start, the level of the standards, treatment of diesel 
producers and importers, whether the standards for advanced biofuel, 
cellulosic biofuel and biomass-based diesel should apply to the entire 
2010 production or just the production that would occur after the RFS2 
effective date, treatment of the 2009 and/or 2010 biomass-based diesel 
standard, and the extent to which RFS1 RINs should be valid to show 
compliance with RFS2 standards.
2. Treatment of Biomass-Based Diesel in 2009 and 2010
    We are proposing to make the RFS2 program required through EISA 
effective on January 1, 2010. The RFS2 program would include an 
expansion to four

[[Page 24957]]

separate standards, changes to the RIN system, changes to renewable 
fuel definitions, the introduction of lifecycle GHG reduction 
thresholds, and the expansion of obligated parties to include producers 
and importers of diesel and nonroad fuel. However, EISA requires 
promulgation of the final RFS2 regulations within one year of enactment 
and presumes full implementation by January 1, 2009. Moreover, EISA 
specifies new volume requirements for biomass-based diesel, advanced 
biofuel, and total renewable fuel for 2009. As described in Section 
II.A.5, it is not possible to have the full RFS2 program implemented by 
January 1, 2009. As a result, we must consider how to treat these 
separate volume requirements for 2009.
a. Proposed Shift in Biomass-Based Diesel Requirement From 2009 to 2010
    The statutory language in EISA does not indicate that the existing 
RFS1 regulations cease to apply on January 1, 2009. Rather, it directs 
us to ``revise the regulations'' to ensure that the required volumes of 
renewable fuel are contained in transportation fuel. As a result, until 
the RFS1 regulations are changed through a notice and comment 
rulemaking process, they will remain in effect. If the full RFS2 
program goes into effect on January 1, 2010, then the existing RFS1 
regulations will continue to apply in 2009.
    Under RFS1, we set the applicable standard each November for the 
following compliance period using the required volume of renewable fuel 
specified in the Clean Air Act, gasoline volume projections from EIA, 
and the formula provided in the regulations at Sec.  80.1105(d). Since 
final RFS2 regulations will not be promulgated by the end of 2008, this 
RFS1 standard-setting process will apply to the 2009 compliance period 
as well. However, EISA modifies the Clean Air Act to increase the 
required volume of total renewable fuel for 2009 from 6.1 to 11.1 
billion gallons, and thus the applicable standard for 2009, published 
in November of 2008,\34\ reflects this higher volume. This will ensure 
that the total renewable fuel requirement under EISA for 2009 is 
implemented.
---------------------------------------------------------------------------

    \34\ See 73 FR 70643.
---------------------------------------------------------------------------

    While the total renewable fuel volume of 11.1 billion gallons will 
be required in 2009, the existing RFS1 regulations do not provide a 
mechanism for requiring the 0.5 billion gallons of biomass-based diesel 
or the 0.6 billion gallons of advanced biofuel required by EISA for 
2009. Below we describe our proposed approach for biomass-based diesel. 
With regard to advanced biofuel, we believe that it is not necessary to 
implement a separate requirement for the 0.6 billion gallons. Due to 
the nested nature of the volume requirements, the 0.5 billion gallon 
requirement for biomass-based diesel would count towards meeting the 
advanced biofuel requirement, leaving just 0.1 billion gallons that we 
believe will be supplied through imports of sugar-based ethanol even 
without a specific mandate for advanced biofuel.
    We believe that the deficit carryover provision provides a 
conceptual mechanism for ensuring that the volume of biomass-based 
diesel that is required by EISA for 2009 is actually consumed. As 
described in the RFS1 final rule, the statute permits obligated parties 
to carry a deficit of any size from one compliance period to the next, 
so long as a deficit is not carried over two years in a row.\35\ In 
theory this would allow any and all obligated parties to defer 
compliance with any or all of the 2009 standards until 2010. Based on 
the precedent set by this statutory provision, we propose that the 
compliance demonstration for the 2009 biomass-based diesel requirement 
be extended to 2010. We believe this approach would provide a 
reasonable transition for biomass-based diesel, given our inability to 
issue regulations before the beginning of the 2009 calendar year. Our 
proposed approach would implement the 2009 and 2010 biomass-based 
diesel volume requirements in a way that ensures that these two years 
worth of biomass-based diesel would be used, while providing reasonable 
lead time for obligated parties. It would avoid a transition that fails 
to have any requirements related to the 2009 biomass-based diesel 
volume, and instead would require the use of the 2009 volume but would 
achieve this by extending the compliance period by one year. We believe 
this is a reasonable exercise of our authority under section 211(o)(2) 
to issue regulations that ensure that the volumes for 2009 are 
ultimately used, even though we are unable to issue final regulations 
prior to the 2009 compliance year. In addition, it is a practical 
approach that provides obligated parties with appropriate lead time.
---------------------------------------------------------------------------

    \35\ See 72 FR 23935.
---------------------------------------------------------------------------

    To implement our proposed approach, the 2009 requirement of 0.5 
billion gallons of biomass-based diesel would be combined with the 2010 
requirement of 0.65 billion gallons for a total adjusted 2010 
requirement of 1.15 billion gallons of biomass-based diesel. The net 
effect is that obligated parties can demonstrate compliance with both 
the 2009 and 2010 biomass-based diesel requirements in 2010, consistent 
with what the deficit carryover provision would have allowed had we 
been able to implement the full RFS2 program by January 1, 2009.
    Furthermore, we propose to allow all 2009 biodiesel and renewable 
diesel RINs, identifiable through an RR code of 15 or 17 respectively, 
to be valid for showing compliance with the adjusted 2010 biomass-based 
diesel standard of 1.15 billion gallons. This use of previous year RINs 
for current year compliance would be consistent with our approach to 
any other standard for any other year and consistent with the 
flexibility available to any obligated party that carried a deficit 
from one year to the next. Moreover, it allows an obligated party to 
acquire sufficient biodiesel and renewable diesel RINs during 2009 to 
comply with the 0.5 billion gallons requirement, even though their 
compliance demonstration would not occur until the 2010 compliance 
period.
    While we recognize that RINs generated in 2009 under RFS1 
regulations will differ from those generated in 2010 under RFS2 
regulations in terms of the purpose of the D code and the other 
criteria for establishing the eligibility of renewable fuel, we believe 
that the use of 2009 RINs for compliance with the 2010 adjusted 
standard is appropriate. It is also consistent with CAA section 
211(o)(5), which provides that validly generated credits may be used to 
show compliance for 12 months. The program transition issue of RINs 
generated under RFS1 but used to meet standards under RFS2 is discussed 
in more detail in Section III.G.3 below.
    Rather than reducing the 2009 volume requirement for total 
renewable fuel by 0.5 billion gallons of biomass-based diesel and 
increasing the 2010 volume requirements for advanced biofuel and total 
renewable fuel by the same amount, we are proposing that the only 
standard that would be adjusted would be that for biomass-based diesel 
in 2010. This approach would minimize the changes to the annual RFS 
volume requirements and thus would more directly implement the 
requirements of the statute. However, this approach would also require 
that we allow 2009 biodiesel and renewable diesel RINs to be used for 
compliance purposes for both the 2009 total renewable fuel standard as 
well as the 2010 adjusted biomass-based diesel standard, but not for 
the 2010 advanced biofuel or total renewable fuel standards. We have

[[Page 24958]]

identified two possible options for accomplishing this.
i. First Option for Treatment of 2009 Biodiesel and Renewable Diesel 
RINs
    In the first option, an obligated party would add up the 2009 
biodiesel and renewable diesel RINs that he used for 2009 compliance 
with the RFS1 standard for renewable fuel, and reduce his 2010 biomass-
based diesel obligation by this amount. Any remaining 2010 biomass-
based diesel obligation would need to be covered with either 2009 
biodiesel and renewable diesel RINs that were not used for compliance 
with the renewable fuel standard in 2009, or 2010 biomass-based diesel 
RINs. This is the option we are proposing in today's notice.
    The primary drawback of our proposed option is that 2009 biodiesel 
and renewable diesel RINs used to demonstrate compliance with the 2009 
renewable fuel standard could not be traded to any other party for use 
in complying with the 2010 biomass-based diesel standard. Thus, for 
instance, if a refiner acquired many 2009 biodiesel and renewable 
diesel RINs and used them for compliance with the 2009 renewable fuel 
standard, and if the number of these 2009 RINs was more than he needed 
to comply with his 2010 biomass-based diesel obligation, he could not 
trade the excess to another party. These excess RINs could never be 
applied to the adjusted 2010 biomass-based diesel standard by any 
party, and as a result the actual demand for biomass-based diesel could 
exceed 1.15 bill gal. We believe that obligated parties could avoid 
this outcome by planning ahead to use no more 2009 biodiesel and 
renewable diesel RINs for 2009 compliance with the renewable fuel 
standard than they would need for 2010 compliance with the adjusted 
biomass-based diesel standard. Moreover, this option could provide 
obligated parties with sufficient incentive to collect 0.5 billion 
gallons worth of biodiesel and renewable diesel RINs in 2009 without 
significant changes to the program's requirements.
ii. Second Option for Treatment of 2009 Biodiesel and Renewable Diesel 
RINs
    Under the second option, biodiesel and renewable diesel RINs 
generated in 2009 would be allowed to be used for compliance purposes 
in both 2009 and 2010. To enable this option, for the specific and 
limited case of biodiesel and renewable diesel RINs generated in 2009, 
we would modify the regulatory prohibition at Sec.  80.1127(a)(3) 
limiting the use of RINs for compliance demonstrations to a single 
compliance year to allow 2009 biodiesel and renewable diesel RINs to be 
used for compliance purposes in two different years. This change would 
allow all 2009 biodiesel and renewable diesel RINs to be used to meet 
the adjusted biomass-based diesel standard in 2010 regardless of 
whether they were also used to meet the total renewable fuel standard 
in 2009. We would also need to lift the 20% rollover cap that would 
otherwise limit the use of 2009 RINs in 2010, and instead allow any 
number of 2009 biodiesel and renewable diesel RINs to be used to meet 
the 2010 biomass-based diesel standard.
    This option would also require that we implement additional RIN 
tracking procedures. Under the current RFS1 regulations, RINs used for 
compliance demonstrations are removed from the RIN market, while under 
this alternative approach biodiesel and renewable diesel RINs could 
continue to be valid for compliance purposes vis a vis the adjusted 
2010 biomass-based diesel standard even if they were already used for 
compliance with the renewable fuel standard in 2009. The regulations 
would need to be changed to allow this, and both EPA's and industry's 
IT systems would need to be modified to allow for this temporary 
change.
    Due to the additional complexities associated with this option, we 
are not proposing it. Nevertheless, we request comment on it, as it 
would more explicitly reflect two separate obligations for calendar 
year 2009: An RFS1 obligation for total renewable fuel, and an 
obligation for biomass-based diesel that starts during 2009 with 
compliance required by the end of 2010 for a volume that covers both 
2009 and 2010. We also request comment on whether under this option we 
should allow 2009 biodiesel and renewable diesel RINs to continue to be 
bought and sold after 2009 if they are used to demonstrate compliance 
with the 2009 total renewable fuel standard.
b. Proposed Treatment of Deficit Carryovers and Valid RIN Life For 
Adjusted 2010 Biomass-Based Diesel Requirement
    Although our proposed transition approach is conceptually similar 
to the statutory deficit carryover provision, the regulatory 
requirements would not explicitly treat the movement of the 0.5 billion 
gallons biomass-based diesel requirement from 2009 to 2010 as a deficit 
carryover. In the absence of any modifications to the deficit carryover 
provisions, then, an obligated party that did not fully comply with the 
2010 biomass-based diesel requirement of 1.15 billion gallons could 
carry a deficit of any amount into 2011.
    If we had been able to implement the 2009 biomass-based diesel 
volume requirement of 0.5 billion gallons in calendar year 2009, the 
2010 biomass-based diesel standard would have been based on 0.65 
billion gallons. In this case, the maximum volume of biomass-based 
diesel that could have been carried into 2011 as a deficit would have 
been 0.65 billion gallons. In the context of our proposed approach to 
the treatment of biomass-based diesel in 2009 and 2010, we believe that 
it would be inappropriate to allow the full 1.15 billion gallons to be 
carried into 2011 as a deficit. Therefore, we are proposing that 
obligated parties be prohibited from carrying over a deficit into 2011 
larger than 0.65 bill gal. In practice, this would mean that deficit 
carryovers from 2010 into 2011 for biomass-based diesel could not 
exceed 57% of an obligated party's 2010 RVO.
    Similarly, the combination of the 0.5 billion gallons biomass-based 
diesel requirement from 2009 with the 2010 volume raises the question 
of whether 2008 biodiesel or renewable diesel RINs could be used for 
compliance in 2010 with the adjusted biomass-based diesel standard. 
Without a change to the regulations, this practice would not be allowed 
because RINs are only valid for compliances purposes for the year 
generated or the year after. However, if we had been able to implement 
the full RFS2 program for the 2009 compliance year, 2008 biodiesel and 
renewable diesel RINs would be valid for compliance with the 0.5 
billion gallons biomass-based diesel requirement. Therefore, we are 
proposing to modify the regulations to allow excess 2008 biodiesel and 
renewable diesel RINs to be used for compliance purposes in 2009 or 
2010. We request comment on this proposal.
    We also propose that the 20% rollover cap would continue to apply 
in all years as described in more detail in Section IV.D. However, we 
are proposing an additional constraint in the application of this cap 
to the biomass-based diesel obligation in the 2010 compliance year. If 
the 2009 biomass-based diesel volume requirement of 0.5 billion gallons 
could have been required in 2009, the use of excess 2008 biodiesel and 
renewable diesel RINs would have been limited to 20% of the 2009 
requirement, or a maximum of 0.1 billion gallons. Since we are 
proposing to require that the 2009 and 2010 biomass-based diesel 
requirements be combined for a total of 1.15 billion gallons, we 
propose that the maximum allowable portion that could be derived from 
2008 biomass-based

[[Page 24959]]

diesel RINs would be 0.1 billion gallons. This would represent 8.7% of 
the 2010 obligation (\0.1/1.15\). In addition to this limit on the use 
of 2008 RINs for 2010 compliance that is unique to this option, the 20% 
rollover cap would continue to apply to the use of all previous-year 
RINs used for compliance purposes in 2010. Thus, the total number of 
all 2008 and 2009 RINs that could be used to meet the 2010 biomass-
based diesel obligation would continue to be capped at 20%. We request 
comment on this approach.
    Finally, we are proposing to allow 2009 RINs that are retired 
because they are ultimately used for nonroad or home heating oil 
purposes to be valid for compliance with the 2010 RFS standard. 
Currently, under RFS1, RINs associated with renewable fuel that is not 
ultimately used as motor vehicle fuel must be retired. In contrast, 
under EISA, renewable fuel used for nonroad purposes, except for use in 
industrial boilers or ocean-going vessels, is considered transportation 
fuel, and is eligible for the RFS program. We are proposing that 2009 
RINs generated for renewable fuel that is ultimately used for nonroad 
or home heating oil purposes continue to be retired by the appropriate 
party pursuant to 80.1129(e). However, we are proposing that those 
retired 2009 nonroad or home heating oil RINs be eligible for 
reinstatement by the retiring party in 2010. These reinstated RINs may 
be used by that party to demonstrate compliance with a 2010 RVO, or for 
sale to other parties who would then use the RINs for compliance 
purposes. While we anticipate that this proposed provision would be 
utilized largely for biodiesel RINs that were retired by parties that 
sold them for use as nonroad fuel or home heating oil, we propose that 
the provision apply to all RINs. We request comment on this proposed 
approach.
c. Alternative Approach to Treatment of Biomass-Based Diesel in 2009 
and 2010
    Under our proposed approach, the 0.5 billion gallon requirement for 
biomass-based diesel in 2009 would be added to the 0.65 billion gallon 
requirement for 2010, and the total volume of 1.15 billion gallons 
would be used as the basis of a single adjusted standard applicable to 
obligated parties in 2010. The compliance demonstration for this single 
standard would need to be made by February 28, 2011. As an alternative, 
we could establish two separate biomass-based diesel standards for 
which compliance must be demonstrated by February 28, 2011. One of 
these standards would be based on 0.65 billion gallons and would 
represent the applicable biomass-based diesel standard for 2010. The 
other standard would be based on 0.5 billion gallons and would 
represent the applicable biomass-based diesel standard for 2009. In 
essence, the standard based on 0.5 billion gallons would be for the 
2009 calendar year even though we would extend its compliance 
demonstration until February 28, 2011.
    In this alternative, only excess 2008 or 2009 biodiesel and 
renewable diesel RINs could be used to comply with the standard based 
on 0.5 billion gallons. Excess 2009 biodiesel or renewable diesel RINs 
and 2010 biomass-based diesel RINs could be used to comply with the 
standard based on 0.65 billion gallons. The 20% rollover cap would 
apply to both standards. As a result, this alternative approach would 
effectively implement the 2009 biomass-based diesel standard in 
calendar year 2009, and thus it may come closer to the statute's 
requirements than our proposed approach. Moreover, the existing 
provisions for the valid life of RINs and deficit carryover would not 
need modification as they would under our proposed approach.
    However, this alternative would arguably provide less than 
appropriate lead time for meeting the 0.5 billion gallon obligation, as 
it would require obligated parties to begin acquiring sufficient 2008 
and 2009 biodiesel and renewable diesel RINs starting in January of 
2009 even though our final rulemaking is not expected to be issued 
until the fall of 2009. There are two reasons that this lead time might 
nevertheless be considered appropriate. First, obligated parties could 
wait until the final rule is published to begin acquiring 2008 and 2009 
biodiesel and renewable diesel RINs. Moreover, they would not need to 
demonstrate compliance with the 0.5 billion gallons standard until 
February 28, 2011, providing ample time to locate and acquire 
sufficient RINs. Second, the deficit carryover provisions would allow 
obligated parties to treat the separate 0.5 and 0.65 billion gallon 
requirements as a single requirement that must be met in total by 
February 28, 2011. In this sense, this alternative is similar to our 
proposed approach. We request comment on this alternative approach.
d. Treatment of Biomass-Based Diesel Under an RFS2 Effective Date Other 
Than January 1, 2010
    The above discussion assumes that the RFS2 program is effective on 
January 1, 2010. If the program effective date is delayed, similar 
issues arise regarding whether EISA volume mandates for fuel categories 
with no mandates under RFS1 are lost, or should be recaptured through a 
delayed compliance demonstration in the first year of the RFS2 program. 
For a delay beyond January 1, 2010, the issues relate to cellulosic 
biofuel and advanced biofuel in addition to biomass-based diesel.
    For instance, our proposed approach to biomass-based diesel 
effectively makes the one-year deficit carryover a necessary element of 
compliance for 2010, and maintains the two-year valid life of RINs. 
However, if the effective date of RFS2 were delayed to January 1, 2011, 
we could not take the same approach. By requiring compliance 
demonstrations to be made in 2011 for the required biomass-based diesel 
volumes mandated for 2009, 2010, and 2011, we would be effectively 
requiring a 2-year deficit carryover and a three-year valid life of 
RINs, contrary to the statutory limitations. As an alternative, one 
possible approach would be to only sum the required biomass-based 
diesel volumes for 2010 and 2011 and require compliance demonstrations 
at the end of 2011.
    If the RFS2 program became effective in mid-2010, we would also 
need to determine the appropriate level of the biomass-based diesel 
standard, and whether it would apply to gasoline and diesel volumes 
produced only after the RFS2 effective date, or all gasoline and diesel 
volumes produced in 2010.
    EPA invites comment on whether and how it should recapture these 
volume mandates under different start-date scenarios.

F. Fuels That Are Subject to the Standards

    Under RFS1, producers and importers of gasoline are obligated 
parties subject to the standards. Any party that produces or imports 
only diesel fuel is not subject to the standards. EISA changes this 
provision by expanding the RFS program in general to include 
transportation fuel. As discussed above, however, section 211(o)(3) 
continues to require EPA to determine which refiners, blenders, and 
importers are treated as subject to the standard. As described further 
in Section III.G below, we are proposing that the sum of all highway 
and nonroad gasoline and diesel fuel produced or imported within a 
calendar year be the basis on which the RVOs are calculated. This 
section provides our proposed definition of gasoline and diesel for the 
purposes of the RFS program.

[[Page 24960]]

1. Gasoline
    As with the RFS1 program, the volume of gasoline used in 
calculating the RVO under RFS2 would continue to include all finished 
gasoline (reformulated gasoline (RFG) and conventional gasoline (CG)) 
produced or imported for use in the contiguous United States or Hawaii, 
as well as all unfinished gasoline that becomes finished gasoline upon 
the addition of oxygenate blended downstream from the refinery or 
importer. This would include both unfinished reformulated gasoline, 
called ``reformulated gasoline blendstock for oxygenate blending,'' or 
``RBOB,'' and unfinished conventional gasoline designed for downstream 
oxygenate blending (e.g., sub-octane conventional gasoline), called 
``CBOB.'' The volume of any other unfinished gasoline or blendstock, 
such as butane or naphtha produced in a refinery, would not be included 
in the obligated volume, except where the blendstock is combined with 
other blendstock or gasoline to produce finished gasoline, RBOB, or 
CBOB. Where a blendstock is blended with other blendstock to produce 
finished gasoline, RBOB, or CBOB, the total volume of the gasoline 
blend would be included in the volume used to determine the blender's 
renewable fuels obligation. Where a blendstock is added to finished 
gasoline, only the volume of the blendstock would be included, since 
the finished gasoline would have been included in the compliance 
determinations of the refiner or importer of the gasoline. For purposes 
of this preamble, the various gasoline products described above that we 
are proposing to include in a party's obligated volume would 
collectively be called ``gasoline.''
    Also consistent with the RFS1 program, we propose to continue to 
exclude any volume of renewable fuel contained in gasoline from the 
volume of gasoline used to determine the renewable fuels obligations. 
This exclusion would apply to any renewable fuels that are blended into 
gasoline at a refinery, contained in imported gasoline, or added at a 
downstream location. Thus, for example, any ethanol added to RBOB or 
CBOB at a refinery's rack or terminal downstream from the refinery or 
importer would be excluded from the volume of gasoline used by the 
refiner or importer to determine the obligation. This is consistent 
with how the standard itself is calculated--EPA determines the 
applicable percentage by comparing the overall projected volume of 
gasoline used to the overall renewable fuel volume that is specified in 
EPAct, and EPA excludes ethanol and other renewable fuels that blended 
into the gasoline in determining the overall projected volume of 
gasoline. When an obligated party determines their RVO by applying the 
applicable percentage to the amount of gasoline they produce or import, 
it is consistent to also exclude ethanol and other renewable fuel 
blends from the calculation of the volume of gasoline produced.
    As with the RFS1 program, we are proposing that Gasoline Treated as 
Blendstock (GTAB) would continue to be treated as a blendstock under 
the RFS2 program, and thus would not count towards a party's renewable 
fuel obligation. Where the GTAB is blended with other blendstock (other 
than renewable fuel) to produce gasoline, the total volume of the 
gasoline blend, including the GTAB, would be included in the volume of 
gasoline used to determine the renewable fuel obligation. Where GTAB is 
blended with renewable fuel to produce gasoline, only the GTAB volume 
would be included in the volume of gasoline used to determine the 
renewable fuel obligation. Where the GTAB is blended with finished 
gasoline, only the GTAB volume would be included in the volume of 
gasoline used to determine the renewable fuel obligation.
2. Diesel
    As discussed above in Section II.A.4, EISA expanded the RFS program 
to include transportation fuels other than gasoline, and we are 
proposing that both highway and nonroad diesel be used in calculating a 
party's RVO. We are proposing that any party that produces or imports 
petroleum-based diesel fuel that is designated as motor vehicle, 
nonroad, locomotive, and marine diesel fuel (MVNRLM) (or any 
subcategory of MVNRLM) would be required to include the volume of that 
diesel fuel in the determination of its RVO under the RFS2 rule. We are 
proposing that diesel fuel would include any distillate fuel that meets 
the definition of MVNRLM diesel fuel as it has already been defined in 
the regulations at Sec.  80.2(qqq), including any subcategories such as 
MV (motor vehicle diesel produced for use in highway diesel engines and 
vehicles), NRLM (diesel produced for use in nonroad, locomotive, and 
marine diesel engines and equipment/vessels), NR (diesel produced for 
use in nonroad engines and equipment), and LM (diesel produced for use 
in locomotives and marine diesel engines and vessels).\36\ We are 
proposing that transportation fuels meeting the definition of MVNRLM 
would be used to calculate the RVOs, and refiners, blenders, or 
importers of MVNRLM would be treated as obligated parties. As such, 
diesel fuel that is designated as heating oil, jet fuel, or any 
designation other than MVNRLM or a subcategory of MVNRLM, would not be 
subject to the applicable percentage standard and would not be used to 
calculate the RVOs.\37\
---------------------------------------------------------------------------

    \36\ EPA's diesel fuel regulations use the term ``nonroad'' to 
designate one large category of land-based off-highway engines and 
vehicles, recognizing that locomotive and marine engines and vessels 
are also nonroad engines and vehicles under EPAct's definition of 
nonroad. Except where noted, the discussion of nonroad in reference 
to transportation fuel includes the entire category covered by 
EPAct's definition of nonroad.
    \37\ See 40 CFR 80.598(a) for the kinds of fuel types used by 
refiners or importers in designating their diesel fuel.
---------------------------------------------------------------------------

    We are also requesting comment on the idea that any diesel fuel not 
meeting these requirements, such as distillate or residual fuel 
intended solely for use in ocean-going vessels, would not be used to 
calculate the RVOs. As discussed above in Section II.A.4, EISA 
specifies that ``transportation fuels'' do not include fuels for use in 
ocean-going vessels. We are interpreting the term ``ocean-going 
vessel'' to mean those vessels that are powered by Category 3 (C3) 
marine engines and that use residual fuel or operate internationally; 
we request comment on this interpretation. As such, we are requesting 
comment on the concept that fuel intended solely for use in ocean-going 
vessels, or that an obligated party can verify as having been used in 
an ocean-going vessel, would be excluded from the renewable fuel 
standards. Further, we are also requesting comment on whether fuel used 
on such vessels with C2 engines should also be excluded from the 
renewable fuel standards, and how such an exemption should be phrased.
3. Other Transportation Fuels
    As discussed further in Section III.J.3, below, we propose that 
transportation fuels other than gasoline or MVNRLM diesel fuel (natural 
gas, propane, and electricity) would not be used to calculate the RVOs 
of any obligated party. We believe this is a reasonable way to 
implement the obligations of 211(o)(3) because the volumes are small 
and the producers cannot readily differentiate the small transport 
portion from the large non-transport portion (in fact, the producer may 
have no knowledge of its use in transport); we will reconsider this 
approach if and when these volumes grow. At the same time, it is clear 
that other fuels can meet the definition of ``transportation fuel,'' 
and we are proposing that under certain

[[Page 24961]]

circumstances, producers or generators of such other transportation 
fuels may generate RINs as a producer or importer of a renewable fuel. 
See Section III.B.1.a for further discussion of other RIN-generating 
fuels.

G. Renewable Volume Obligations (RVOs)

    Under the current RFS program, each obligated party must determine 
its RVO based on the applicable percentage standard and its annual 
gasoline volume. The RVO represents the volume of renewable fuel that 
the obligated party must ensure is used in the U.S. in a given calendar 
year. Obligated parties must meet their RVO through the accumulation of 
RINs which represent the amount of renewable fuel used as motor vehicle 
fuel that is sold or introduced into commerce within the U.S. Each 
gallon-RIN would count as one gallon of renewable fuel for compliance 
purposes.
    We propose to maintain this approach to compliance under the RFS2 
program. One primary difference between the current and new RFS 
programs in terms of demonstrating compliance would be that each 
obligated party would now have four RVOs instead of one (through 2012) 
or two (starting in 2013) under the RFS1 program. Also, as discussed 
above, RVOs would be calculated based on production or importation of 
both gasoline and diesel fuels, rather than gasoline alone.
    By acquiring RINs and applying them to their RVOs, obligated 
parties are effectively causing the renewable fuel represented by the 
RINs to be consumed as transportation fuel in highway or nonroad 
vehicles or engines. Obligated parties would not be required to 
physically blend the renewable fuel into gasoline or diesel fuel 
themselves. The accumulation of RINs would continue to be the means 
through which each obligated party shows compliance with its RVOs and 
thus with the renewable fuel standards.
    If an obligated party acquires more RINs than it needs to meet its 
RVOs, then in general it could retain the excess RINs for use in 
complying with its RVOs in the following year or transfer the excess 
RINs to another party. If, alternatively, an obligated party has not 
acquired sufficient RINs to meet its RVOs, then under certain 
conditions it could carry a deficit into the next year.
    This section describes our proposed approach to the calculation of 
RVOs under RFS2 and the RINs that would be valid for demonstrating 
compliance with those RVOs. This includes a description of the special 
treatment that must be applied to 2009 RINs used for compliance 
purposes in 2010, since RINs generated in 2009 under RFS1 would not be 
exactly the same as those generated in 2010 under RFS2. We also 
describe an alternative approach to the identification of obligated 
parties that would place the obligations under RFS2 on only finished 
gasoline and diesel rather than on certain blendstocks and unfinished 
fuels as well. The implication of this would be that the final blender 
of the gasoline or diesel would be the obligated parties rather than 
producers of blendstocks and unfinished fuels.
1. Determination of RVOs Corresponding to the Four Standards
    In order for an obligated party to demonstrate compliance, the 
percentage standards described in Section III.E.1 which are applicable 
to all obligated parties must be converted into the volumes of 
renewable fuel each obligated party is required to satisfy. These 
volumes of renewable fuel are the volumes for which the obligated party 
is responsible under the RFS program, and are referred to here as its 
RVO. Under RFS2, each obligated party would need to acquire sufficient 
RINs each year to meet each of the four RVOs corresponding to the four 
renewable fuel standards.
    The calculation of the RVOs under RFS2 would follow the same format 
as the existing formulas in the regulations at Sec.  80.1107(a), with 
one modification. The standards for a particular compliance year would 
be multiplied by the sum of the gasoline and diesel volume produced or 
imported by an obligated party in that year rather than only the 
gasoline volume as under the current program.\38\ To the degree that an 
obligated party did not demonstrate full compliance with its RVOs for 
the previous year, the shortfall would be included as a deficit 
carryover in the calculation. CAA section 211(o)(5) only permits a 
deficit carryover from one year to the next if the obligated party 
achieves full compliance with its RVO including the deficit carryover 
in the second year. Thus deficit carryovers could not occur two years 
in succession for any of the four standards. They could, however, occur 
as frequently as every other year for a given obligated party.
---------------------------------------------------------------------------

    \38\ As discussed above, the diesel fuel that is used to 
calculate the RVO is any diesel designated as MVNRLM or a 
subcategory of MVNRLM.
---------------------------------------------------------------------------

    Note that a party that produces only diesel fuel would have an 
obligation for all four standards even though he would not have the 
opportunity to blend ethanol into his own gasoline. Likewise, a party 
that produces only gasoline will have an obligation for all four 
standards even though he would not have an opportunity to blend 
biomass-based diesel into his own diesel fuel. Although these 
circumstances might imply that the four standards should be further 
subdivided into gasoline-specific and diesel-specific standards, we do 
not believe that this would be appropriate as described in Section 
III.E.1. Instead, since the obligations are met through the use of 
RINs, compliance with the standards does not require an obligated party 
to blend renewable fuel into their own or anyone else's gasoline or 
diesel fuel.
2. RINs Eligible To Meet Each RVO
    Under RFS1, all RINs had the same compliance value and thus it did 
not matter what the RR or D code was for a given RIN when using that 
RIN to meet the total renewable fuel standard. In contrast, under RFS2 
only RINs with specified D codes could be used to meet each of the four 
standards.
    As described in Section II.A.1, the volume requirements in EISA are 
generally nested within one another, so that the advanced biofuel 
requirement includes fuel that meets either the cellulosic biofuel or 
the biomass-based diesel requirements, and the total renewable fuel 
requirement includes fuel that meets the advanced biofuel requirement. 
As a result, the RINs that can be used to meet the four standards are 
likewise nested. Using the proposed D codes defined in Table III.A-1, 
the RINs that could be used to meet each of the four standards are 
shown in Table III.G.2-1.

                          Table III.G.2-1--RINs That Can Be Used To Meet Each Standard
----------------------------------------------------------------------------------------------------------------
               Standard                              Obligation                       Allowable D codes
----------------------------------------------------------------------------------------------------------------
Cellulosic biofuel....................  RVOCB..............................  1.

[[Page 24962]]

 
Biomass-based diesel..................  RVOBBD.............................  2.
Advanced biofuel......................  RVOAB..............................  1, 2, and 3.
Renewable fuel........................  RVORF..............................  1, 2, 3, and 4.
----------------------------------------------------------------------------------------------------------------

    The nested nature of the four standards also means that we must 
allow the same RIN to be used to meet more than one standard in the 
same year. Thus, for instance, a RIN with a D code of 1 could be used 
to meet three of the four standards, while a RIN with a D code of 3 
could be used to meet both the advanced biofuel and total renewable 
fuel standards. However, we propose continuing to prohibit the use of a 
single RIN for compliance purposes in more than one year or by more 
than one party.\39\
---------------------------------------------------------------------------

    \39\ Note that we are proposing an exception to this general 
prohibition for the specific and limited case of excess 2008 and 
2009 biodiesel and renewable diesel RINs used to demonstrate 
compliance with both the 2009 total renewable fuel standard and the 
2010 biomass-based diesel standard. See Section III.E.2.a.
---------------------------------------------------------------------------

3. Treatment of RFS1 RINs Under RFS2
    As described in Section II.A, we are proposing a number of changes 
to the RFS program as a result of the requirements in EISA. These 
changes would go into effect on January 1, 2010 and, among other 
things, would affect the conditions under which RINs are generated and 
their applicability to each of the four standards. As a result, RINs 
generated in 2010 under RFS2 will not be exactly the same as RINs 
generated in 2009 under RFS1. Given the valid RIN life that allows a 
RIN to be used in the year generated or the year after, we must address 
circumstances in which excess 2009 RINs are used for compliance 
purposes in 2010. We must also address deficit carryovers from 2009 to 
2010, since the total renewable fuel standards in these two years will 
be defined differently.
a. Use of 2009 RINs in 2010
    In 2009, the RFS1 regulations will continue to apply and thus 
producers will not be required to demonstrate that their renewable fuel 
is made from renewable biomass as defined by EISA, nor that their 
combination of fuel type, feedstock, and process meets the GHG 
thresholds specified in EISA. Moreover, there is no practical way to 
determine after the fact if RINs generated in 2009 meet any of these 
criteria. However, we believe that the vast majority of RINs generated 
in 2009 would in fact meet the RFS2 requirements. First, while ethanol 
made from corn must meet a 20% GHG threshold under RFS2 if produced by 
a facility that commenced construction after December 19, 2007, 
facilities that were already built or had commenced construction as of 
December 19, 2007 are exempt from this requirement. Essentially all 
ethanol produced in 2009 will meet the prerequisites for this 
exemption. Second, it is unlikely that renewable fuels produced in 2009 
will have been made from feedstocks grown on agricultural land that had 
not been cleared or cultivated prior to December 19, 2007. In the 
intervening time period, it is much more likely that the additional 
feedstocks needed for renewable fuel production would come from 
existing cropland or cropland that has lain fallow for some time. 
Finally, the text of section 211(o)(5) states that a ``credit generated 
under this paragraph shall be valid to show compliance for the 12 
months as of the date of generation,'' and EISA did not change this 
provision and did not specify any particular transition protocol to 
follow. A straightforward interpretation of this provision is to allow 
2009 RINs to be valid to show compliance for 2010 obligations.
    Since there will be separate standards for cellulosic biofuel and 
biomass-based diesel in 2010, RINs generated in 2009 that could be used 
to meet either of these two 2010 standards should meet the GHG 
thresholds of 60% and 50%, respectively. While we will not have a 
mechanism in place to determine if these thresholds have been met for 
RINs generated in 2009, and there are indications from our assessment 
of lifecycle GHG performance that at least some renewable fuels 
produced in 2009 would not meet these thresholds, nevertheless any 
shortfall in GHG performance for this one transition year is unlikely 
to have a significant impact on long-term GHG benefits of the program. 
Based on our belief that it is critical to the smooth operation of the 
program that excess 2009 RINs be allowed to be used for compliance 
purposes in 2010, we are proposing that RINs generated in 2009 to 
represent cellulosic biomass ethanol whose GHG performance has not been 
verified would still be valid for use for 2010 compliance purposes for 
the cellulosic biofuel standard. Likewise, we are proposing that RINs 
generated in 2009 to represent biodiesel and renewable diesel whose GHG 
performance has not been verified would still be valid for use for 2010 
compliance purposes for the biomass-based diesel standard. We request 
comment on this approach.
    We propose to use information contained in the RR and D codes of 
RFS1 RINs to determine how those RINs should be treated under RFS2. The 
RR code is used to identify the Equivalence Value of each renewable 
fuel, and under RFS1 these Equivalence Values are unique to specific 
types of renewable fuel. For instance, biodiesel (mono alkyl ester) has 
an Equivalence Value of 1.5, and non-ester renewable diesel has an 
Equivalence Value of 1.7, and both of these fuels may be valid for 
meeting the biomass-based diesel standard under RFS2. Likewise, RINs 
generated for cellulosic biomass ethanol in 2009 must be identified 
with a D code of 1, and these fuels may be valid for meeting the 
cellulosic biofuel standard under RFS2. Our proposed treatment of 2009 
RINs in 2010 is shown in Table III.G.3.a-1.

    Table III.G.3.a-1--Proposed Treatment of Excess 2009 RINs in 2010
------------------------------------------------------------------------
             Excess 2009 RINs                     Treatment in 2010
------------------------------------------------------------------------
RFS1 RINs with RR code of 15 or 17........  Equivalent to RFS2 RINs with
                                             D code of 2.
RFS1 RINs with D code of 1................  Equivalent to RFS2 RINs with
                                             D code of 1.
All other RFS1 RINs.......................  Equivalent to RFS2 RINs with
                                             D code of 4.
------------------------------------------------------------------------

    Although we have discussed the issue of RFS1 RINs being used for 
RFS2 purposes in the context of our proposal that the RFS2 program be 
effective on January 1, 2010, we would expect a similar treatment of 
RFS1 RINs for RFS2 compliance purposes if the RFS2 effective date is 
delayed. In that case RFS1 RINs generated in 2010 would be available to 
show compliance for both the 2010 and 2011 compliance years, in a 
manner similar to that described above.

[[Page 24963]]

b. Deficit Carryovers From the RFS1 Program to RFS2
    If the RFS2 program goes into effect on January 1, 2010, the 
calculation of RVOs in 2009 under the existing regulations will be 
somewhat different than the calculation of RVOs in 2010 under RFS2. In 
particular, 2009 RVOs will be based upon gasoline production only, 
while 2010 RVOs would be based on volumes of gasoline and diesel. As a 
result, 2010 compliance demonstrations that include a deficit carried 
over from 2009 will combine obligations calculated on two different 
bases.
    We do not believe that deficits carried over from 2009 to 2010 
would undermine the goals of the program in requiring specific volumes 
of renewable fuel to be used each year. Although RVOs in 2009 and 2010 
would be calculated differently, obligated parties must acquire 
sufficient RINs in 2010 to cover any deficit carried over from 2009 in 
addition to that portion of their 2010 obligation which is based on 
their 2010 gasoline and diesel production. As a result, the 2009 
nationwide volume requirement of 11.1 billion gallons of renewable fuel 
will be consumed over the two year period concluding at the end of 
2010. Thus, we are not proposing special treatment for deficits carried 
over from 2009 to 2010.
    We propose that a deficit carried over from 2009 to 2010 would only 
affect a party's total renewable fuel obligation in 2010 
(RVORF,i as discussed in Section III.G.1), as the 2009 
obligation is for total renewable fuel use, not a subcategory. The RVOs 
for cellulosic biofuel, biomass-based diesel, or advanced biofuel would 
not be affected, as they do not have parallel obligations in 2009 under 
RFS1.
    If the RFS2 start date is delayed to be later than January 1, 2010, 
we expect that the same principles described above would apply for any 
deficit calculated under the RFS1 program and carried forward to RFS2.
4. Alternative Approach to Designation of Obligated Parties
    Under RFS1, obligated parties who are subject to the standard are 
those that produce or import finished gasoline (RFG and conventional) 
or unfinished gasoline that becomes finished gasoline upon the addition 
of an oxygenate blended downstream from the refinery or importer. 
Unfinished gasoline includes reformulated gasoline blendstock for 
oxygenate blending (RBOB), and conventional gasoline blendstock 
designed for downstream oxygenate blending (CBOB) which is generally 
sub-octane conventional gasoline. The volume of any other unfinished 
gasoline or blendstock, such as butane, is not included in the volume 
used to determine the RVO, except where the blendstock is combined with 
other blendstock or finished gasoline to produce finished gasoline, 
RBOB, or CBOB. Thus, parties downstream of a refinery or importer are 
only obligated parties to the degree that they use non-renewable 
blendstocks to make finished gasoline, RBOB, or CBOB.
    The approach we took for RFS1 was based on our expectation at that 
time that there would be an excess of RINs at low cost, and our belief 
that the ability of RINs to be traded freely between any parties once 
separated from renewable fuel would provide ample opportunity for 
parties who were in need of RINs to acquire them from parties who had 
excess. We also pointed out that the designation of ethanol blenders as 
obligated parties would have greatly expanded the number of regulated 
parties and increased the complexity of the RFS program beyond that 
which was necessary to carry out the renewable fuels mandate under CAA 
section 211(o).
    Following the new requirements under EISA, the required volumes of 
renewable fuel will be increasing significantly above the levels 
required under RFS1. These higher volumes are already resulting in 
changes in the demand for RINs and operation of the RIN market. First, 
obligated parties who have excess RINs are increasingly opting to 
retain rather than sell them to ensure they have a sufficient number 
for the next year's compliance. Second, since all gasoline is expected 
to contain ethanol by 2013, few blenders would be able to avoid taking 
ownership of RINs by that time under the existing definition of 
obligated party. As a result, by 2013 essentially every blender would 
be a regulated party who is subject to recordkeeping and reporting 
requirements, and thus the additional burden of demonstrating 
compliance with the standard could be small. Third, major integrated 
refiners who operate gasoline marketing operations have direct access 
to RINs for ethanol blended into their gasoline, while refiners whose 
operations are focused primarily on producing refined products do not 
have such direct access to RINs. The result is that in some cases there 
are significant disparities between obligated parties in terms of 
opportunities to acquire RINs. If those that have excess RINs are 
reluctant to sell them, those who are seeking RINs may be forced to 
market a disproportionate share of E85 in order to gain access to the 
RINs they need for compliance. If obligated parties seeking RINs cannot 
acquire a sufficient number, they can only carry a deficit into the 
following year, after which they would be in noncompliance if they 
could not acquire sufficient RINs. The result might be a much higher 
price for RINs (and fuel) in the marketplace than would be expected 
under a more liquid market.
    Given the change in circumstances brought about through EISA, it 
may be appropriate to consider a change in the way that obligated 
parties are defined to more evenly align a party's access to RINs with 
that party's obligations under the RFS2 program. The most 
straightforward approach would be to eliminate RBOB and CBOB from the 
list of fuels that are subject to the standard, such that a party's RVO 
would be based only on the non-renewable volume of finished gasoline or 
diesel that he produces or imports. Parties that blend ethanol into 
RBOB and CBOB to make finished gasoline would thus be obligated 
parties, and their RVOs would be based upon the volume of RBOB and CBOB 
prior to ethanol blending. Traditional refiners that convert crude oil 
into transportation fuels would only have an RVO to the degree that 
they produced finished gasoline or diesel, with all RBOB and CBOB sold 
to another party being excluded from the calculation of their RVO.
    Since essentially all gasoline is expected to be E10 within the 
next few years (see discussion in Section V.D.2 below), this approach 
would effectively shift the obligation for all gasoline from refiners 
and importers to ethanol blenders (who in many cases are still the 
refiners). However, this approach by itself would maintain the 
obligation for diesel on refiners and importers. Thus, a variation of 
this approach would be to move the obligations for all gasoline and 
diesel downstream to parties who supply finished transportation fuels 
to retail outlets or to wholesale purchaser-consumer facilities. This 
variation would have the additional effect of more closely aligning 
obligations and access to RINs for parties that blend biodiesel and 
renewable diesel into petroleum-based diesel.
    We are not proposing to eliminate RBOB and CBOB from the list of 
fuels that are subject to the standard in today's notice since it would 
result in a significant change in the number of obligated parties and 
the movement of RINs. Many parties that are not obligated under the 
current RFS program would become obligated, and would be forced to 
implement new systems for determining and reporting compliance. 
Nevertheless, it would have certain advantages. Currently, blenders

[[Page 24964]]

that are not obligated parties are profiting from the sale of RINs they 
acquire through splash blending of ethanol. By eliminating RBOB and 
CBOB from the list of obligated fuels, these blenders would become 
directly responsible for ensuring that the volume requirements of the 
RFS program are met, and the cost of meeting the standard would be more 
evenly distributed among parties that blend renewable fuel into 
gasoline. With obligations placed more closely to the points in the 
distribution system where RINs are made available, the overall market 
prices for RINs may be lowered and consequently the cost of the program 
to consumers may be reduced.
    While eliminating the categories of RBOB and CBOB from the list of 
obligated fuels would result in a significant change in the 
distribution of obligations among transportation fuel producers, it 
could help to ensure that the RIN market functions as we originally 
intended. As a result, RINs would more directly be made available to 
the parties that need them for compliance. This is similar to the goal 
of the direct transfer approach to RIN distribution as described in the 
proposed rulemaking for the RFS1 program and presented again in Section 
III.H.4 below. We request comment on the degree to which access to RINs 
is a concern among current obligated parties. Since either the 
elimination of RBOB and CBOB from the list of obligated fuels or the 
direct transfer approach to RIN distribution could both accomplish the 
same goal, we request comment on which one would be more appropriate, 
if any.
    We have also considered a number of alternative approaches that 
could be used to help ensure that obligated parties can demonstrate 
compliance. For instance, one alternative approach would leave our 
proposed definitions for obligated parties in place, but would add a 
regulatory requirement that any party who blends ethanol into RBOB or 
CBOB must transfer the RINs associated with the ethanol to the original 
producer of the RBOB or CBOB. However, we believe that such an approach 
would be both inappropriate and difficult to implement. RBOB and CBOB 
is often transferred between multiple parties prior to ethanol 
blending. As a result, a regulatory requirement for RIN transfers back 
to the original producer would necessitate an additional tracking 
requirement for RBOB and CBOB so that the blender would know the 
identity of the original producer. It would also be difficult to ensure 
that RINs representing the specific category of renewable fuel blended 
were transferred to the producer of the RBOB or CBOB, given the 
fungible nature of RINs assigned to batches of renewable fuel. For 
these reasons, we do not believe that this alternative approach would 
be appropriate.
    In another alternative approach, some RINs that expire without 
being used for compliance by an obligated party could be used to reduce 
the nationwide volume of renewable fuel required in the following year. 
We would only reduce the required volume of renewable fuel to the 
degree that sufficient RINs had been generated to permit all obligated 
parties to demonstrate compliance, but some obligated parties 
nevertheless could not acquire a sufficient number of RINs. Moreover, 
only RINs that were expiring would be used to reduce the nationwide 
volume for the next year. This alternative approach would ensure that 
the volumes required in the statute would actually be produced and 
would prevent the hoarding of RINs from driving up demand for renewable 
fuel. However, it would also reduce the impact of the valid life limit 
for RINs.
    We could lower the 20% rollover cap applicable to the use of 
previous-year RINs to a lower value, such as 10%. This approach would 
provide a greater incentive for obligated parties with excess RINs to 
sell them but would further restrict a potentially useful means of 
managing an obligated party's risk. As described in Section IV.D, we 
are not proposing any changes in the 20% rollover cap in today's 
notice. However, we request comment on it.
    Finally, another change to the program that would not change the 
definition of obligated parties, but could help address the disparity 
of access to RINs among obligated parties, would be to remove the 
requirement developed under RFS1 that RINs be transferred with 
renewable fuel volume by the renewable fuel producers and importers. 
This alternative is discussed further in Section III.H.4 below.

H. Separation of RINs

    We propose that most of the RFS1 provisions regarding the 
separation of RINs from volumes of renewable fuel be retained for RFS2. 
However, the modifications in EISA will require a number of changes, 
primarily to the treatment of RINs associated with nonroad renewable 
fuel and renewable fuels used in heating oil and jet fuel. Our approach 
to the separation of RINs by exporters must also be modified to account 
for the fact that there would be four categories of renewable fuel 
under RFS2.
1. Nonroad
    Under RFS1, RINs associated with renewable fuels used in nonroad 
vehicles and engines downstream of the renewable fuel producer are 
required to be retired by the party who owns the renewable fuel at the 
time of blending. This provision derived from the EPAct definition of 
renewable fuel which was limited to fuel used to replace fossil fuel 
used in a motor vehicle. EISA however expands the definition of 
renewable fuel, and ties it to the definition of transportation fuel, 
which is defined as any ``fuel for use in motor vehicles, motor vehicle 
engines, nonroad vehicles, or nonroad engines (except for ocean-going 
vessels). To implement these changes, the proposed RFS2 program 
eliminates the RFS1 RIN retirement requirement for renewable fuels used 
in nonroad applications, with the exception of RINs associated with 
renewable fuels used in ocean-going vessels.
2. Heating Oil and Jet Fuel
    EISA defined `additional renewable fuel' as ``fuel that is produced 
from renewable biomass and that is used to replace or reduce the 
quantity of fossil fuel present in home heating oil or jet fuel.'' \40\ 
While we are proposing that fossil-based heating oil and jet fuel would 
not be included in the fuel used by a refiner or importer to calculate 
their RVO, we are proposing that renewable fuels used as or in heating 
oil and jet fuel may generate RINs for credit purposes. Thus, the RINs 
of a renewable fuel, such as biodiesel, that is blended into heating 
oil continue to be valid. See also discussion in Section III.B.1.e.
---------------------------------------------------------------------------

    \40\ EISA, Title II, Subtitle A-Renewable Fuel Standard, Section 
201.
---------------------------------------------------------------------------

3. Exporters
    Under RFS1, exporters are assigned an RVO representing the volume 
of renewable fuel that has been exported, and they are required to 
separate all RINs that have been assigned to fuel that is exported. 
Since there is only one standard, there is only one possible RVO 
applicable to exporters.
    Under RFS2, there are four possible RVOs corresponding to the four 
categories of renewable fuel (cellulosic biofuel, biomass-based diesel, 
advanced biofuel, total renewable fuel). However, given the fungible 
nature of the RIN system and the fact that an assigned RIN transferred 
with a volume of renewable fuel may not be the same RIN that was 
originally generated to represent that volume, there is no way for an 
exporter to determine from an assigned RIN which of the four categories 
applies to

[[Page 24965]]

an exported volume. In order to determine its RVOs, the only 
information available to the exporter is the type of renewable fuel 
that he is exporting.
    For RFS2, we are proposing that exporters use the fuel type and its 
associated volume to determine his applicable RVO. To accomplish this, 
an exporter must know which of the four renewable fuel categories 
applies to a given type of renewable fuel. We are proposing that all 
biodiesel (mono alkyl esters) and renewable diesel would be categorized 
as biomass-based diesel (D code of 4), and that exported volumes of 
these two fuels would be used to determine the exporter's RVO for 
biomass-based diesel. For all other types of renewable fuel, the most 
likely category for most of the phase-in period of the RFS2 program is 
general renewable fuel, and as a result we propose that all other types 
of renewable fuel be used to determine the exporter's RVO for total 
renewable fuel. Our proposed approach is provided at Sec.  80.1430. We 
recognize that by 2022 the required volume of cellulosic biofuel will 
exceed the required volume of general renewable fuel that is in excess 
of the advanced biofuel requirements. Thus we request comment on 
requiring all or some portion of renewable fuels other than biodiesel 
and renewable diesel to be categorized as cellulosic biofuel in 2022 
and beyond.
    An alternative approach could be required that would more closely 
estimate the amount of exported renewable fuels that fall into the four 
categories defined by EISA. In this alternative, the total nationwide 
volumes required in each year (see Table II.A.1-1) would be used to 
apportion specific types of renewable fuel into each of the four 
categories. For example, exported ethanol may have originally been 
produced from cellulose to meet the cellulosic biofuel requirement, 
from corn to meet the total renewable fuel requirement, or may have 
been imported as advanced biofuel. If ethanol were exported, we could 
divide the exported volume into three RVOs for cellulosic biofuel, 
advanced biofuel, and total renewable fuel using the same proportions 
represented by the national volume requirements for that year. However, 
we believe that this alternative approach would add considerable 
complexity to the compliance determinations for exporters without 
necessarily adding more precision. Given the expected small volumes of 
exported renewable fuel, this added complexity does not seem warranted 
at this time. Nevertheless, we request comment on it.
4. Alternative Approaches to RIN Transfers
    In the NPRM for the RFS1 rulemaking, we presented a variety of 
approaches to the transfer of RINs, ultimately requiring that RINs 
generated by renewable fuel producers and importers must be assigned to 
batches of renewable fuel and transfered along with those batches. 
However, given the higher volumes required under RFS2 and the resulting 
expansion in the number of regulated parties, we believe that two of 
the alternative approaches to RIN transfers should be considered for 
RFS2. Our proposal for an EPA-moderated RIN trading system (EMTS) may 
also support the implementation of one of these approaches.
    In one of the alternative approaches, we would entirely remove the 
restriction established under the RFS1 rule requiring that RINs be 
assigned to batches of renewable fuel and transferred with those 
batches. Instead, renewable fuel producers could sell RINs (with a K 
code of 2 rather than 1) separately from volumes of renewable fuel to 
any party. This approach could significantly streamline the tracking 
and trading of RINs. For instance, there would no longer be a need for 
K-codes and restrictions on separation of RINs, there would only be a 
single RIN market rather than two (one for RINs assigned to volume and 
another for separated RINs), there would be no need for volume/RIN 
balance calculations at the end of each quarter, and there would be no 
need for restrictions on the number of RINs that can be transfered with 
each gallon of renewable fuel. As described more fully in Section 
III.B.4.b.ii, this approach could also provide a greater incentive for 
producers to demonstrate that the renewable biomass definition has been 
met for their feedstocks. As discussed in Section III.G.4, this approch 
could help level the playing field among obligated parties for access 
to RINs regardless of whether they market a substantial volume of 
gasoline or not. However, as discussed in the RFS1 rulemaking, this 
approach could also place obligated parties at greater risk of market 
manipulation by renewable fuel producers.
    In order to address some of the concerns raised about allowing 
producers and importers to separate RINs from their volume, in the NPRM 
for the RFS1 rulemaking we also presented an alternative concept for 
RIN distribution in which producers and importers of renewable fuels 
would be required to transfer the RIN, but only to an obligated party 
(see 71 FR 55591). This ''direct transfer'' approach would require 
renewable fuel producers to transfer RINs with renewable fuel for all 
transactions with obligated parties, and sell all other RINs directly 
to obligated parties on a quarterly basis for any renewable fuel 
volumes that were not sold directly to obligated parties. Only 
renewable fuel producers, importers, and obligated parties would be 
allowed to own RINs, and only obligated parties could take ownership of 
RINs from producers and importers. This approach would spare marketers 
and distributors of renewable fuel from the burdens associated with 
transferring RINs with batches, and thus would eliminate the tracking, 
recordkeeping and reporting requirements that would continue to be 
applicable to them if RINs are transferred through the distribution 
system as required under the RFS1 program.
    Under the direct transfer alternative, the renewable fuel producer 
or importer would be required to transfer the RINs associated with his 
renewable fuel to an obligated party who purchases the renewable fuel. 
The RINs associated with any renewable fuel that is not directly 
transferred to an obligated party would not be transferred with the 
fuel as required under the RFS1 program. Instead, the renewable fuel 
producer or importer would be required to sell the RINs directly to an 
obligated party. Any RINs not sold in this way would be required to be 
offered for sale to all obligated parties through a public auction. 
This could be through an EPA moderated trading system, an existing 
internet auction web site, or through another auction mechanism 
implemented by a renewable fuel producer.
    Although we believe that the direct transfer approach has merit, 
many of the concerns laid out in the RFS1 NPRM remain valid today. In 
particular, the auctions would need to be regulated in some way to 
ensure that RIN generators could not withhold RINs from the market by 
such means as failing to adequately advertise the time and location of 
an auction, by setting the selling price too high, by specifying a 
minimum number of bids before selling, by conducting auctions 
infrequently, by having unduly short bidding windows, etc. We seek 
comment on how we could regulate such auctions to ensure that obligated 
parties could acquire sufficient RINs for compliance purposes in a 
timely manner.
    Our proposed EPA-moderated RIN trading system (see Section IV.E) 
could help to make the direct transfer approach feasible. By creating 
accounts

[[Page 24966]]

in a centralized system within which all RIN transfers between parties 
would be made, it may be more straightforward for obligated parties to 
identify available RINs owned by producers and importers, and to bid on 
those RINs. Therefore, while we are not proposing the direct transfer 
approach in today's action, we nevertheless request comment on it.
5. Neat Renewable Fuel and Renewable Fuel Blends Designated as 
Transportation Fuel, Home Heating Oil, or Jet Fuel
    Under RFS1, RINs must, with limited exceptions, be separated by an 
obligated party taking ownership of the renewable fuel, or by a party 
that blends renewable fuel with gasoline or diesel. In addition, a 
party that designates neat renewable fuel as motor vehicle fuel may 
separate RINs associated with that fuel if the fuel is in fact used in 
that manner without further blending. For purposes of the RFS program, 
``neat renewable fuel'' is defined in 80.1101(p) as ``a renewable fuel 
to which only de minimis amounts of conventional gasoline or diesel 
have been added.'' One exception to these provisions is that biodiesel 
blends in which diesel constitutes less than 20 volume percent are 
ineligible for RIN separation by a blender. As noted in the preamble to 
the final RFS1 regulations, EPA understands that in the vast majority 
of cases, biodiesel is blended with diesel in concentrations of 80 
volume percent or less.
    However, in order to account for situations in which biodiesel 
blends of 81 percent or greater may be used as motor vehicle fuel 
without ever having been owned by an obligated party, EPA is proposing 
to change the applicability of the RIN separation provisions for RFS2. 
EPA is proposing that 80.1429(b)(4) allow for separation of RINs for 
neat renewable fuel or blends of renewable fuel and or diesel fuel that 
the party designates as transportation fuel, home heating oil, or jet 
fuel, provided the neat renewable fuel or blend is used in the 
designated form, without further blending, as transportation fuel, home 
heating oil, or jet fuel. As in RFS1, those parties that blend 
renewable fuel with gasoline or diesel fuel (in a blend containing less 
than 80 percent biodiesel would in all cases be required to separate 
RINs pursuant 80.1429(b)(2).
    Thus, for example, under these proposed regulations, if a party 
intends to separate RINs from a volume of B85, the party must designate 
the blend for use as transportation fuel, home heating oil, or jet fuel 
and the blend must be used in its designated form without further 
blending. The party would also be required maintain records of this 
designation pursuant to 80.1451(b)(5). Finally, the party would be 
required to comply with the proposed PTD requirements in 
80.1453(a)(5)(iv), which serve to notify downstream parties that the 
volume of fuel has been designated for use as transportation fuel, home 
heating oil, or jet fuel, and must be used in that designated form 
without further blending. Parties could separate RINs at the time they 
complied with the designation and PTD requirements, and would not need 
to physically track ultimate fuel use.
    EPA requests comment on this proposed approach to RIN separation. 
Additionally, EPA requests comment on an alternative approach to 
modifying the current program for separation of RINs. Under this second 
approach, 80.1429(b)(2) and (b)(5)would be eliminated as redundant, and 
80.1429(b)(4) would be broadened to require separation of RINs for all 
neat renewable fuels and all blends of renewable fuels with either 
gasoline or diesel, when a party designates such fuel as transportation 
fuel, home heating oil or jet fuel, and the fuel is in fact used in 
accordance with that designation without further blending. The party 
would be required to maintain records that verify the ultimate use of 
the fuel as transportation, home heating, or jet fuel. Additionally, 
there would be a PTD requirement to inform downstream parties that the 
fuel has been designated as transportation, home heating, or jet fuel 
and may not be further blended. This proposed approach would eliminate 
the need for parties to distinguish for purposes of separating RINs 
between fuels that are neat or blended or, for biodiesel, between 
blends of E80 and below or E81 and above.

I. Treatment of Cellulosic Biofuel

1. Cellulosic Biofuel Standard
    EISA requires in section 202(e) that the Administrator set the 
cellulosic biofuel standard each November for the next year based on 
the lesser of the volume specified in the Act or the projected volume 
of cellulosic biofuel production for that year. In the event that the 
projected volume is less than the amount required in the Act, EPA may 
also reduce the applicable volume of the advanced biofuels requirement 
by the same or a lesser volume. We intend to examine EIA's projected 
volumes and other available data including the production outlook 
reports proposed in Section III.K to be submitted to the EPA to decide 
the appropriate standard for the following year. The outlook reports 
from all renewable fuel producers would assist EPA in determining what 
the cellulosic biofuel standard should be and if the advanced biofuel 
standard should be adjusted. For years where EPA determines that the 
projected volume of cellulosic biofuels is not sufficient to meet the 
levels in EISA we will consider the availability of other advanced 
biofuels in deciding whether to lower the advanced biofuel standard as 
well.
2. EPA Cellulosic Allowances for Cellulosic Biofuel
    Whenever EPA sets the cellulosic biofuel standard at a level lower 
than that required in EISA, EPA is required to provide a number of 
cellulosic credits for sale that is no more than the volume used to set 
the standard. Congress also specified the price for such credits: 
adjusted for inflation, they must be offered at the price of the higher 
of 25 cents per gallon or the amount by which $3.00 per gallon exceeds 
the average wholesale price of a gallon of gasoline in the United 
States. The inflation adjustment will be for years after 2008. We 
propose that the inflation adjustment would be based on the Consumer 
Price Index for All Urban Consumers (CPI-U) for All Items expenditure 
category as provided by the Bureau of Labor Statistics.\41\
---------------------------------------------------------------------------

    \41\ See U.S. Department of Labor, Bureau of Labor Statistics 
(BLS), Consumer Price Index Web site at: http://www.bls.gov/cpi/.
---------------------------------------------------------------------------

    Congress afforded the Agency considerable flexibility in 
implementing the system of cellulosic biofuel credits. EISA states EPA; 
``shall include such provisions, including limiting the credits' uses 
and useful life, as the Administrator deems appropriate to assist 
market liquidity and transparency, to provide appropriate certainty for 
regulated entities and renewable fuel producers, and to limit any 
potential misuse of cellulosic biofuel credits to reduce the use of 
other renewable fuels, and for such other purposes as the Administrator 
determines will help achieve the goals of this subsection.''
    Though EISA gives EPA broad flexibility, we believe the best way to 
accomplish the goals of providing certainty to both the cellulosic 
biofuel industry and the obligated parties is to propose credits with 
few degrees of freedom. We believe this would prevent speculation in 
the market and provide certainty for investments in real cellulosic 
biofuels.
    Specifically, we propose that the credits would be called 
allowances so

[[Page 24967]]

that there is no confusion with RINs, such allowances would only be 
available for the current compliance year for which we have waived some 
portion of the cellulosic biofuel standard, they would only be 
available to obligated parties, and they would be nontransferable and 
nonrefundable. Further, we propose that obligated parties would only be 
able to purchase allowances up to the level of their cellulosic biofuel 
RVO less the number of cellulosic biofuel RINs that they own. This 
would help ensure that every party that needs to meet the cellulosic 
biofuel standard will have equal access to the allowances. A company 
would also then only use an allowance to meet its total renewable and 
advanced biofuel standards if it used the allowance for the cellulosic 
biofuel standard. We believe that if a company can only purchase as 
many allowances as it needs to meet its cellulosic biofuel obligation, 
it can not hinder another obligated party from meeting the standard and 
therefore every company that needs to meet the standard will have equal 
access to the allowances in the event that they do not acquire 
sufficient cellulosic biofuel RINs. If we were to allow a company to 
purchase more allowances than they needed, another company may not be 
able to meet the standard which we believe was not the intent of 
Congress.
    We also propose that these allowances would be offered in a generic 
format rather than a serialized format, like RINs. Allowances would be 
purchased from the EPA at the time that an obligated party submits its 
annual compliance demonstration to the EPA and establishes that it owns 
insufficient cellulosic biofuel RINs to meet its cellulosic biofuel 
RVO. A company owning cellulosic biofuel RINs and cellulosic allowances 
may use both types of credits if desired to meet their RVOs, but unlike 
RINs they would not be able to carry allowances over to the next 
calendar year.
    Congress refers to allowances as ``cellulosic biofuel credits,'' 
with no indication that the ``credits'' should be given any less role 
in meeting a party's obligations under the CAA section 211(o) than 
would the purchase and use of a cellulosic biofuel RIN that reflects 
actual production and use of cellulosic biofuel. Because cellulosic 
biofuel RINs can be used to meet the advanced biofuel and total 
renewable fuel standards in addition to the cellulosic biofuel 
standard, we propose that cellulosic biofuel allowances also be 
available for use in meeting those three standards.
    We propose that the wholesale price of gasoline will be based on 
the average monthly bulk (refinery gate) price of gasoline using data 
from the most recent twelve months of data from EIA's annual cellulosic 
ethanol forecast each October.\42\ Thus we will set the allowance price 
for the following year each November along with the cellulosic biofuel 
standard for the following year. We seek comment on using the average 
monthly rack (terminal) price for the same period and changing the 
allowance price as often as quarterly. Though EISA allows EPA to change 
the price as often as quarterly we believe this will lead to 
speculation which may introduce more uncertainty for the obligated 
parties and the cellulosic biofuel industry.
---------------------------------------------------------------------------

    \42\ More information on wholesale gasoline prices can be found 
on the Department of Energy's (DOE), Energy Information 
Administration's (EIA) Web site at: http://tonto.eia.doe.gov/dnav/pet/pet_pri_allmg_d_nus_PBS_cpgal_m.htm.
---------------------------------------------------------------------------

3. Potential Adverse Impacts of Allowances
    While the credit provisions of section 202(e) of EISA ensure that 
there is a predictable upper limit to the price that cellulosic biofuel 
producers can charge for a gallon of cellulosic biofuel and its 
assigned RIN, there may be circumstances in which this provision has 
other unintended impacts. For instance, if we made all cellulosic 
allowances available to any obligated party, one obligated party could 
purchase more allowances than he needs to meet his cellulosic biofuel 
RVO and then sell the remaining allowances at an inflated price to 
other obligated parties. Thus, we are proposing that each obligated 
party could only purchase allowances from the EPA up to the level of 
their cellulosic biofuel RVO. However, even with this restriction an 
obligated party could still purchase both cellulosic biofuel volume 
with its assigned RINs sufficient to meet its cellulosic biofuel RVO, 
and also purchase allowances from the EPA. In this case, the obligated 
party would effectively be using allowances as a replacement for corn 
ethanol rather than cellulosic biofuel. To prevent this, we are 
proposing an additional restriction: an obligated party could only 
purchase allowances from the EPA to the degree that it establishes it 
owns insufficient cellulosic biofuel RINs to meet its cellulosic 
biofuel RVO. This approach forces obligated parties to apply all their 
cellulosic biofuel RINs to their cellulosic biofuel RVO before appying 
any allowances to their cellulosic biofuel RVO.
    However, even with these proposed restrictions on the purchase and 
application of allowances, the statutory provision may not operate as 
intended. For instance, if the combination of cellulosic biofuel volume 
price and RIN price is low compared to that for corn-ethanol, a small 
number of obligated parties could purchase more cellulosic biofuel than 
they need to meet their cellulosic biofuel RVOs and could use the 
additional cellulosic biofuel RINs to meet their advanced biofuel and 
total renewable fuel RVOs. Other obligated parties would then have no 
access to cellulosic biofuel volume nor cellulosic biofuel RINs, and 
would be forced to purchase allowances from the EPA. This situation 
would have the net effect of allowances replacing imported sugarcane 
ethanol and/or corn-ethanol rather than cellulosic biofuel.
    Moreover, under certain conditions it may be possible for the 
market price of corn-ethanol RINs to be significantly higher than the 
market price of cellulosic biofuel RINs, as the latter is limited in 
the market by the price of EPA-generated allowances according to the 
statutory formula described in Section III.I.2 above. Under some 
conditions, this could result in a competitive disadvantage for 
cellulosic biofuel in comparison to corn ethanol. For instance, if 
gasoline prices at the pump are significantly higher than ethanol 
production costs, while at the same time corn-ethanol production costs 
are lower than cellulosic ethanol production costs, profit margins for 
corn-ethanol producers would be larger than for cellulosic ethanol 
producers. Under these conditions, while obligated parties may still 
purchase cellulosic ethanol volume and its associated RIN rather than 
allowances, cellulosic ethanol producers would realize lower profits 
than corn-ethanol producers due to the upper limit placed on the price 
of cellulosic biofuel RINs through the pricing formula for allowances. 
For a newly forming and growing cellulosic biofuel industry, this 
competitive disadvantage could make it more difficult for investors to 
secure funding for new projects, threatening the ability of the 
industry to reach the statutorily mandated volumes.
    We have not established the likelihood that these circumstances 
would arise in practice, and we request comment on the specific market 
conditions that could lead to them. Nevertheless, we have explored a 
variety of ways that we could modify the RFS program structure to 
mitigate these potential negative outcomes. For instance, as mentioned 
in Section III.I.2 above, we are proposing that each

[[Page 24968]]

cellulosic allowance could be used to meet an obligated party's RVOs 
for cellulosic biofuel, advanced biofuel, and total renewable fuel. 
However, we could restrict the applicability of allowances to only the 
cellulosic biofuel RVO. This approach could help ensure that demand for 
imported sugarcane ethanol and corn ethanol does not fall in the event 
that a small number of obligated parties purchase all available 
cellulosic biofuel volume, compelling the remaining obligated parties 
to purchase allowances. However, this approach could also have the 
effect of making the advanced biofuel and total renewable fuel 
standards more stringent. This could occur as obligated parties are 
forced to buy additional imported sugarcane ethanol and corn ethanol to 
make up for the fact that the allowances they purchase from the EPA 
would not apply to the advanced biofuel and total renewable fuel 
standards.
    As a variation to this approach, while still restricting the 
applicability of allowances to only the cellulosic biofuel RVO, we 
could similarly make cellulosic biofuel RINs applicable to only the 
cellulosic biofuel RVO. This approach would ensure that the compliance 
value of both cellulosic biofuel RINs and allowances is the same, but 
would necessarily result in an increase in the effective stringency of 
the advanced biofuel and total renewable fuel standards.
    Finally, we could institute a ``dual RIN'' approach to cellulosic 
biofuel that has the potential to address some of the shortcomings of 
the previous approaches. In this approach, both cellulosic biofuel RINs 
(with a D code of 1) and allowances could only be applied to an 
obligated party's cellulosic biofuel RVO, but producers of cellulosic 
biofuel would also generate an additional RIN representing advanced 
biofuel (with a D code of 3). The producer would only be required to 
transfer the advanced biofuel RIN with a batch of cellulosic biofuel, 
and could retain the cellulosic biofuel RIN for separate sale to any 
party.\43\ The cellulosic biofuel and its attached advanced biofuel RIN 
would then compete directly with other advanced biofuel and its 
attached advanced biofuel RIN, while the separate cellulosic biofuel 
RIN would have an independent market value that would be effectively 
limited by the pricing formula for allowances as described in Section 
III.I.2. However, this approach would be a more significant deviation 
from the RIN generation and transfer program structure that was 
developed cooperatively with stakeholders during RFS1. It would provide 
cellulosic biofuel producers with significantly more control over the 
sale and price of cellulosic biofuel RINs, which was one of the primary 
concerns of obligated parties during the development of RFS1.
---------------------------------------------------------------------------

    \43\ The cellulosic biofuel RIN would be a separated RIN with a 
K code of 2 immediately upon generation.
---------------------------------------------------------------------------

    Due to the drawbacks of each of these potential changes to the RFS 
program structure, we are not proposing any of them in today's NPRM. 
However, we request comment on whether any of them, or alternatives, 
could address the adverse situations described above. We also request 
comment on the degree to which the adverse situations are likely to 
occur, and the degree of severity of the negative impacts that could 
result.

J. Changes to Recordkeeping and Reporting Requirements

1. Recordkeeping
    As with the existing renewable fuel standard program, recordkeeping 
under this proposed program will support the enforcement of the use of 
RINs for compliance purposes. As with the existing renewable fuels 
program, we are proposing that parties be afforded significant freedom 
with regard to the form that product transfer documents (PTDs) take. We 
propose to permit the use of product codes as long as they are 
understood by all parties. We propose that product codes may not be 
used for transfers to truck carriers or to retailers or wholesale 
purchaser-consumers. We propose that parties must keep copies of all 
PTDs they generate and receive, as well as copies of all reports 
submitted to EPA and all records related to the sale, purchase, 
brokering or transfer or RINs, for five (5) years. We also propose that 
parties must also keep copies of records that relate to flexibilities, 
as described in Section IV.A. through C. of this preamble. Such 
flexibilities are related to attest engagements, the upward delegation 
of RIN-separating responsibilities, and various small business oriented 
provisions. Upon request, parties would be responsible for providing 
their records to the Administrator or the Administrator's authorized 
representative. We would reserve the right to request to receive 
documents in a format that we can read and use.
    In Section IV.E. of this preamble, we propose an EPA-Moderated 
Trading System for RINs. If adopted, the new system would allow for 
real-time reporting of RIN generation (i.e., batch reports by producers 
and importers) and RIN transactions.
2. Reporting
    Under the existing renewable fuels program, obligated parties, 
exporters of renewable fuel, producers and importers of renewable 
fuels, and any party who owns RINs must report appropriate information 
to EPA on a quarterly and/or annual basis. We are proposing a change in 
the schedule for submission of producers' and importers' batch reports, 
and for the submission of RIN transaction reports. This proposed change 
in schedule, which is discussed in great detail in Section IV.E. of 
this preamble, is effective for 2010 only. We are proposing that, for 
2010, these reports (which were submitted quarterly under RFS1) be 
submitted monthly rather than quarterly. The reason for proposing 
monthly reporting for 2010 is to minimize difficulties associated with 
invalid RINs, while the EPA-Moderated Trading System is still under 
development. As described in detail in IV.E. we intend to have an EPA-
Moderated Trading System fully operational by 2011. At the time that 
system becomes fully operational, all batch and RIN transactional 
reporting would be submitted in real time. The following deadlines 
would apply to ``real time,' monthly, quarterly, and annual reports.
    ``Real time'' reports within the EPA-Moderating Trading System 
would be submitted within three (3) business days of a reportable event 
(e.g. generation of a RIN, a transaction occurring involving a RIN). 
Real time reporting would apply to batch reports submitted by producers 
and importers who generate RINs and to to RIN transaction reports 
submitted in 2011 and future years.
    Monthly reports would be submitted according to the following 
schedule:

               Table III.J.2-1--Monthly Reporting Schedule
------------------------------------------------------------------------
         Month covered by  report                Due date for report
------------------------------------------------------------------------
January...................................  February 28.
February..................................  March 31.
March.....................................  April 30.
April.....................................  May 31.
May.......................................  June 30.
June......................................  July 31.
July......................................  August 31.
August....................................  September 30.
September.................................  October 31.
October...................................  November 30.
November..................................  December 31.
December..................................  January 31.
------------------------------------------------------------------------

    The monthly reporting schedule would apply to batch reports 
submitted by producers and importers who generate RINs and to RIN 
transaction reports submitted for 2010 only.

[[Page 24969]]

    Quarterly reports would be submitted on the following schedule:

              Table III.J.-2--Quarterly Reporting Schedule
------------------------------------------------------------------------
        Quarter covered by  report              Due date for  report
------------------------------------------------------------------------
January-March.............................  May 31.
April-June................................  August 31.
July-September............................  November 30.
October-December..........................  February 28.
------------------------------------------------------------------------

    Quarterly reports include summary reports related to RIN 
activities.
    Annual reports (covering January through December) would continue 
to be due on February 28. Annual reports include compliance 
demonstrations by obligated parties.
    Under this proposed rule, the universe of reporting parties would 
grow, but we propose similar reporting to existing reporting. We 
believe that the proposed EPA-Moderating Trading System will make 
reporting easier for most parties. Existing reporting forms and 
instructions are posted at http://www.epa.gov/otaq/regs/fuels/rfsforms.htm. You may wish to refer to these existing forms in 
preparing your comments on this proposal.
    Simplified, secure reporting is currently available through our 
Central Data Exchange (CDX). CDX permits us to accept reports that are 
electronically signed and certified by the submitter in a secure and 
robustly encrypted fashion. Using CDX eliminates the need for wet ink 
signatures and reduces the reporting burden on regulated parties. It is 
our intention to continue to encourage the use of CDX for reporting 
under this proposed program as well.
    Due to the criteria that renewable fuel producers and importers 
must meet in order to generate RINs under RFS2, and due to the fact 
that renewable fuel producers and importers must have documentation 
about whether their feedstock(s) meets the definition of ``renewable 
biomass,'' we propose several changes to the RFS1 RIN generation 
report. We propose to make the report a more general report on 
renewable fuel production in order to capture information on all 
batches of renewable fuel, whether or not RINs are generated for them. 
All renewable fuel producers and importers above 10,000 gallons per 
year would report to EPA on each batch of their fuel and indicate 
whether or not RINs are generated for the batch. If RINs are generated, 
the producer or importer would be required to certify that his 
feedstock meets the definition of ``renewable biomass.'' If RINs are 
not generated, the producer or importer would be required to state the 
reason for not generating RINs, such as they have documentation that 
states that their feedstock did not meet the definition of ``renewable 
biomass,'' or the fuel pathway used to produce the fuel was such that 
the fuel did not qualify for any D code (see Section III.B.4.b for a 
discussion about demonstrating whether or not feedstock meets the 
definition of ``renewable biomass''). For each batch of renewable fuel 
produced, we also propose to require information about the types and 
volumes of feedstock used and the types and volumes of co-products 
produced, as well as information about the process or processes used. 
This information is necessary to confirm that the producer or importer 
assigned the appropriate D code to their fuel and that the D code was 
consistent with their registration information.
    Two minor additions are being incorporated into the RIN transaction 
report. First, for reports of RINs assigned to a volume of renewable 
fuel, we are asking that the volume of renewable fuel be reported. 
Additionally, we propose that RIN price information be submitted for 
transactions involving both separated RINs and RINs assigned to a 
renewable volume. This information is not collected under RFS1, but we 
believe this information has great programmatic value to EPA because it 
may help us to anticipate and appropriately react to market disruptions 
and other compliance challenges, will be beneficial when setting future 
renewable standards, and will provide additional insight into the 
market when assessing potential waivers. We anticipate that having 
current market information such as total number of RINs produced and 
RINs available in the separated market is incomplete. Missing is our 
ability to assess the general health and direction of the market and 
overall liquidity of RINs. Tracking price trend information will allow 
us to identify market inefficiencies and perceptions of RIN supply. 
When price information is combined with information from the production 
outlook reports, we will be better able to judge realistic expectations 
of renewable production and be in a better position when setting and 
justifying future renewable standards or pursuing relief through waiver 
provisions. Also, we believe the addition of price information will be 
highly beneficial to regulated parties. With price information being 
noted on transaction reports, buyers and sellers will have an 
additional and immediate reference when confirming transactions. 
Additionally, we believe that highly summarized price information 
(e.g., the average price of RINs traded) should be available to 
regulated parties, as well, and may help them to anticipate and avoid 
market disruptions.
    We also propose to make minor changes to compliance reports related 
to the identification of types of RINs. Please refer to Section III.B. 
of this preamble for a discussion of types of renewable fuels. Also, 
please refer to Section III.A. for a discussion of proposed changes to 
RINs.
    Under our proposed EPA-Moderated Trading System described in 
Section IV.E. of this preamble, then there would be a change in 
reporting burden on regulated parties that affects the frequency of 
reporting and the number of reports. Instead of quarterly and/or annual 
contact with EPA, there would be real time contact--i.e., as batches of 
renewable fuel are generated or as RINs are transacted. However, we 
believe that any burden is offset by the advantage of having a 
simplified system for RIN management that will promote the integrity of 
RINs and will remove ``guesswork'' now associated with RIN management. 
As things are now, a regulated party may experience frustration and 
incur expense in trying to track down and correct errors. Once an error 
is made, it propagates throughout the distribution system with each 
transfer from party to party. By having EPA moderate RIN management, we 
believe that errors would be minimized and regulated parties would be 
freed of the greater burden to attempt to track down and correct errors 
they may have made. Implementation of the EPA-Moderated Trading System 
would correspond to real-time reporting of the type of information 
contained in the following two quarterly reports: The Renewable Fuel 
Production Report, known as the RIN Generation Report or ``batch 
report'' under RFS1 (Report Form Template RFS0400), and the RIN 
Transaction Report (Report Form Template RFS0200), starting in 2011. 
For 2010, we are proposing that the type of information contained in 
these two forms be submitted monthly. These and other reports and 
instructions related to the existing renewable fuel standard program 
(RFS1) are posted at http://www.epa.gov/otaq/regs/fuels/rfsforms.htm.
3. Additional Requirements for Producers of Renewable Natural Gas, 
Electricity, and Propane
    In addition to the general reporting requirement listed above, we 
are proposing an additional item of reporting for producers of 
renewable

[[Page 24970]]

natural gas, electricity, and propane who choose to generate and assign 
RINs. While producers of renewable natural gas, electricity, and 
propane who generate and assign RINs would be responsible for filing 
the same reports as other producers of RIN-generating renewable fuels, 
we propose that additional reporting for these producers be required to 
support the actual use of their products in the transportation sector. 
We believe that one simple way to achieve this may be to add a 
requirement that producers of renewable natural gas, electricity, and 
propane add the name of the purchaser (e.g., the name of the wholesale 
purchaser-consumer (WPC) or fleet) to their quarterly RIN generation 
reports and then maintain appropriate records that further identify the 
purchaser and the details of the transaction. We are not proposing that 
a purchaser who is either a WPC or an end user would have to register 
under this scenario, unless that party engages in other activities 
requiring registration under this program.

K. Production Outlook Reports

    We are also proposing additional reporting--annual production 
outlook reports that would be required of all domestic renewable fuel 
producers, foreign renewable fuel producers who register to generate 
RINs, and importers of covered renewable fuels starting in 2010. These 
production outlook reports would be similar to the pre-compliance 
reports required under the Highway and Nonroad Diesel programs. These 
reports would contain information about existing and planned production 
capacity, long-range plans, and feedstocks and production processes to 
be used at each production facility. For expanded production capacity 
that is planned or underway at each existing facility, or new 
production facilities that are planned or underway, the progress 
reports would require information on: (1) Strategic planning; (2) 
Planning and front-end engineering; (3) Detailed engineering and 
permitting; (4) Procurement and Construction; and (5) Commissioning and 
startup. These five project phases are described in EPA's June 2002 
Highway Diesel Progress Review report (EPA document number EPA420-R-02-
016, located at: www.epa.gov/otaq/regs/hd2007/420r02016.pdf).
    The full list of requirements for the proposed production outlook 
reports is provided in the proposed regulations at Sec.  80.1449. The 
information submitted in the reports would be used to evaluate the 
progress that the industry is making towards the renewable fuels volume 
goals mandated by EISA and to set the annual cellulosic biofuel, 
advanced biofuel, biomass-based diesel, and total renewable fuel 
standards (see Section II.A.7 of this preamble). We are proposing that 
the annual production outlook reports be due annually by February 28, 
beginning in 2010 and continuing through 2022, and we are proposing 
that each annual report must provide projected information through 
calendar year 2022.
    EPA currently receives data on projected flexible-fuel vehicle 
(FFV) sales and conversions from vehicle manufacturers; however, we do 
not have information on renewable fuels in the distribution system. 
Thus, EPA is also considering whether to require the annual submission 
of data to facilitate our evaluation of the ability of the distribution 
system to deliver the projected volumes of biofuels to petroleum 
terminals that are needed to meet the RFS2 standards. We request 
comment on the extent to which such information is already publicly 
available or can be purchased from a proprietary source. We further 
request comment on the extent to which such publicly available or 
purchasable data would be sufficient for EPA to make its determination. 
To the extent that additional data might be needed, we request comment 
on the parties that should be required to report to EPA and what data 
should be required. For example, would it be appropriate to require 
terminal operators to report to EPA annually on their ability to 
receive, store, and blend biofuels into petroleum-based fuels? We 
believe that publicly available information on E85 refueling facilities 
is sufficient for us to make a determination about the adequacy of such 
facilities to support the projected volumes of E85 that would be used 
to satisfy the RFS2 standards.
    We request comment on the proposed requirement of annual production 
outlook reports, and all other aspects mentioned above (e.g., reporting 
requirements, reporting dates, etc.).

L. What Acts Are Prohibited and Who Is Liable for Violations?

    The prohibition and liability provisions applicable to the proposed 
RFS2 program would be similar to those of the RFS1 program and other 
gasoline programs. The proposed rule identifies certain prohibited 
acts, such as a failure to acquire sufficient RINs to meet a party's 
RVOs, producing or importing a renewable fuel that is not assigned a 
proper RIN category (or D Code), improperly assigning RINs to renewable 
fuel that was not produced with renewable biomass, failing to assign 
RINs to qualifying fuel, or creating or transferring invalid RINs. Any 
person subject to a prohibition would be held liable for violating that 
prohibition. Thus, for example, an obligated party would be liable if 
the party failed to acquire sufficient RINs to meet its RVO. A party 
who produces or imports renewable fuels would be liable for a failure 
to assign proper RINs to qualifying batches of renewable fuel produced 
or imported. Any party, including an obligated party, would be liable 
for transferring a RIN that was not properly identified.
    In addition, any person who is subject to an affirmative 
requirement under this program would be liable for a failure to comply 
with the requirement. For example, an obligated party would be liable 
for a failure to comply with the annual compliance reporting 
requirements. A renewable fuel producer or importer would be liable for 
a failure to comply with the applicable batch reporting requirements. 
Any party subject to recordkeeping or product transfer document (PTD) 
requirements would be liable for a failure to comply with these 
requirements. Like other EPA fuels programs, the proposed rule provides 
that a party who causes another party to violate a prohibition or fail 
to comply with a requirement may be found liable for the violation.
    EPAct amended the penalty and injunction provisions in section 
211(d) of the Clean Air Act to apply to violations of the renewable 
fuels requirements in section 211(o). Accordingly, under the proposed 
rule, any person who violates any prohibition or requirement of the 
RFS2 program may be subject to civil penalties of $32,500 for every day 
of each such violation and the amount of economic benefit or savings 
resulting from the violation. Under the proposed rule, a failure to 
acquire sufficient RINs to meet a party's renewable fuels obligation 
would constitute a separate day of violation for each day the violation 
occurred during the annual averaging period.
    As discussed above, the regulations would prohibit any party from 
creating or transferring invalid RINs. These invalid RIN provisions 
apply regardless of the good faith belief of a party that the RINs are 
valid. These enforcement provisions are necessary to ensure the RFS2 
program goals are not compromised by illegal conduct in the creation 
and transfer of RINs.
    As in other motor vehicle fuel credit programs, the regulations 
would address the consequences if an obligated party was found to have 
used invalid RINs to demonstrate compliance with its RVO.

[[Page 24971]]

In this situation, the obligated party that used the invalid RINs would 
be required to deduct any invalid RINs from its compliance 
calculations. Obligated parties would be liable for violating the 
standard if the remaining number of valid RINs was insufficient to meet 
its RVO, and the obligated party might be subject to monetary penalties 
if it used invalid RINs in its compliance demonstration. In determining 
what penalty is appropriate, if any, we would consider a number of 
factors, including whether the obligated party did in fact procure 
sufficient valid RINs to cover the deficit created by the invalid RINs, 
and whether the purchaser was indeed a good faith purchaser based on an 
investigation of the RIN transfer. A penalty might include both the 
economic benefit of using invalid RINs and/or a gravity component.
    Although an obligated party would be liable under our proposed 
program for a violation if it used invalid RINs for compliance 
purposes, we would normally look first to the generator or seller of 
the invalid RINs both for payment of penalty and to procure sufficient 
valid RINs to offset the invalid RINs. However, if, for example, that 
party was out of business, then attention would turn to the obligated 
party who would have to obtain sufficient valid RINs to offset the 
invalid RINs.
    We request comment on the need for additional prohibition and 
liability provisions specific to the proposed RFS 2 program.

IV. What Other Program Changes Have We Considered?

    In addition to the regulatory changes we are proposing today in 
response to EISA that are designed to implement the provisions of RFS2, 
there are a number of other changes to the RFS program that we are 
considering. These changes would be designed to increase flexibility, 
simplify compliance, or address RIN transfer issues that have arisen 
since the start of the RFS1 program. We have also investigated impacts 
on small businesses and are proposing approaches designed to address 
the impacts of the program on them.

A. Attest Engagements

    The purpose of an attest engagement is to receive third party 
verification of information reported to EPA. An attest engagement, 
which is similar to a financial audit, is conducted by a Certified 
Public Accountant (CPA) or Certified Independent Auditor (CIA) 
following agreed-upon procedures. Under the RFS1 program, an attest 
engagement must be conducted annually. We propose to apply the same 
provision to this proposed RFS2 rule. However, we seek comment on 
whether there should be any flexibility provisions for those who own a 
small number of RINs and what level of flexibility might be appropriate 
(e.g., allowing those who own a small number of RINs to submit an 
attest engagement every two years, rather than every year).

B. Small Refinery and Small Refiner Flexibilities

1. Small Refinery Temporary Exemption
    CAA section 211(o)(8), enacted as part of EPAct, provides a 
temporary exemption to small refineries (those refineries with a crude 
throughput of no more than 75,000 barrels of crude per day, as defined 
in section 211(o)(1)(K)) through December 31, 2010.\44\ Accordingly, 
the RFS1 program regulations exempt gasoline produced by small 
refineries from the renewable fuels standard (unless the exemption was 
waived), see 40 CFR 80.1141. EISA did not alter the small refinery 
exemption in any way. Therefore, we intend to retain this small 
refinery temporary exemption in the RFS2 program without change. 
Further, as discussed below in Section IV.B.2.c, we are proposing to 
continue one of the hardship provisions for small refineries provided 
at 40 CFR 80.1141(e).
---------------------------------------------------------------------------

    \44\ Small refineries are also allowed to waive this exemption.
---------------------------------------------------------------------------

2. Small Refiner Flexibilities
    As mentioned above, EPAct granted a temporary exemption from the 
RFS program to small refineries through December 31, 2010. In the RFS1 
final rule, 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 Congressional small refinery definition as noted above.
    As explained in the discussion of our compliance with the 
Regulatory Flexibility Act below in Section XII.C and in the Initial 
Regulatory Flexibility Analysis in Chapter 7 of the draft RIA, we 
considered the impacts of today's proposed regulations on small 
businesses. Most of our analysis of small business impacts was 
performed as a part of the work of the Small Business Advocacy Review 
Panel (SBAR Panel, or ``the Panel'') convened by EPA, pursuant to the 
Regulatory Flexibility Act as amended by the Small Business Regulatory 
Enforcement Fairness Act of 1996 (SBREFA). The Final Report of the 
Panel is available in the docket for this proposed rule. For the SBREFA 
process, we conducted outreach, fact-finding, and analysis of the 
potential impacts of our regulations on small businesses.
    During the SBREFA process, small refiners informed us that they 
would need to rely heavily on RINs and/or make capital improvements to 
comply with the RFS2 requirements. These refiners raised concerns about 
the RIN program itself, uncertainty (with the required renewable fuel 
volumes, RIN availability, and cost), and the desire for a RIN system 
review access to RINs, and the difficulty in raising capital and 
competing for engineering resources to make capital improvements.
    During the Panel process, EPA raised a concern regarding provisions 
for small refiners in the RFS2 rule; and this rule presents a very 
different issue than the small refinery versus small refiner concept 
from RFS1. This issue deals with whether or not EPA has the authority 
to provide a subset of small refineries (those that are operated by 
small refiners) with an extension of time that would be different from, 
and more than, the temporary exemption specified by Congress in section 
211(o)(9) for small refineries (temporary exemption through December 
31, 2010, with the potential for extensions of the exemption beyond 
this date if certain criteria are met.). In other words, the temporary 
exemption specified by Congress provided relief for those small 
refiners that are covered by the small refinery provision; EPA believes 
that providing these refiners with an additional exemption different 
from that provided by section 211(o)(9) may be inconsistent with the 
intent of Congress. Congress spoke directly to the relief that EPA may 
provide for small refineries, including those small refineries operated 
by small refiners, and limited it to a blanket exemption through 
December 31, 2010, with additional extensions if the criteria specified 
by Congress were met.
    The Panel recommended that EPA consider the issues raised by the 
SERs and discussions had by the Panel itself, and that EPA should 
consider comments on flexibility alternatives that would help to 
mitigate negative impacts on small businesses to the extent allowable 
by the Clean Air Act. A summary of further recommendations of the Panel 
are discussed in Section XII.C of this preamble, and a full discussion 
of the regulatory alternatives discussed and recommended by the Panel 
can be found in the SBREFA Final Panel Report.

[[Page 24972]]

a. Extension of Existing RFS1 Temporary Exemption
    As previously stated, the RFS1 program regulations provide small 
refiners who operate small refineries, as well as those small refiners 
who do not operate small refineries, with a temporary exemption from 
the standards through December 31, 2010. Small refiner SERs suggested 
that an additional temporary exemption for the RFS2 program would be 
beneficial to them in meeting the RFS2 standards; and the Panel 
recommended that EPA propose a delay in the effective date of the 
standards until 2014 for small entities, to the maximum extent allowed 
by the statute.
    We have evaluated an additional temporary exemption for small 
refiners for the required RFS2 standards, and we have also evaluated 
such an exemption with respect to our concerns about our authority to 
provide an extension of the temporary exemption for small refineries 
that is different from that provided in CAA section 211(o)(9). As a 
result, we believe that the limitations of the statute do not 
necessarily allow us the discretion to provide an exemption for small 
refiners only (i.e., small refiners but not small refineries) beyond 
that provided in section 211(o)(9). However, it is important to 
recognize that the 211(o)(9) small refinery provision does allow for 
extensions beyond December 31, 2010, with two separate provisions 
addressing extensions beyond 2010. These provisions are discussed below 
in Section IV.B.2.c.
    Therefore, we are proposing to continue the temporary exemption 
finalized in RFS1--through December 31, 2010--for small refineries and 
all qualified small refiners. We also request comment on the 
interpretation of our authority under the CAA and the appropriateness 
of providing an extension to small refiners only beyond that authorized 
by section 211(o)(9).
b. Program Review
    During the SBREFA process, the small refiner SERs also requested 
that EPA perform an annual program review, to begin one year before 
small refiners are required to comply with the program. We have slight 
concerns that such a review could lead to some redundancy since EPA is 
required to publish a notice of the applicable RFS standards in the 
Federal Register annually, and this annual process will inevitably 
include an evaluation of the projected availability of renewable fuels. 
Nevertheless, some Panel members commented that they believe a program 
review could be beneficial to small entities in providing them some 
insight to the RFS program's progress and alleviate some uncertainty 
regarding the RIN system. As we will be publishing a Federal Register 
notice annually, the Panel recommended that we include an update of RIN 
system progress (e.g., RIN trading, publicly-available information RIN 
availability, etc.) in this annual notice.
    We propose to include elements of RIN system progress--such as RIN 
trading and availability--in the annual Federal Register RFS2 standards 
notice. We also invite comment on additional elements to include in 
this review.
c. Extensions of the Temporary Exemption Based on Disproportionate 
Economic Hardship
    As noted above, there are two provisions in section 211(o)(9) that 
allow for an extension of the temporary exemption beyond December 31, 
2010. One involves a study by the Department of Energy (DOE) concerning 
whether compliance with the renewable fuel requirements would impose 
disproportionate economic hardship on small refineries, and would grant 
an extension of at least two years for a small refinery that DOE 
determines would be subject to such disproportionate hardship. Another 
provision authorizes EPA to grant an extension for a small refinery 
based upon disproportionate economic hardship, on a case-by-case basis.
    We believe that these avenues of relief can and should be fully 
explored by small refiners who are covered by the small refinery 
provision. In addition, we believe that it is appropriate to consider 
allowing petitions to EPA for an extension of the temporary exemption 
based on disproportionate economic hardship for those small refiners 
who are not covered by the small refinery provision (again, per our 
discretion under section 211(o)(3)(B)); this would ensure that all 
small refiners have the same relief available to them as small 
refineries do. Thus, we are proposing a hardship provision for small 
refineries in the RFS2 program, that any small refinery may apply for a 
case-by-case hardship at any time on the basis of disproportionate 
economic hardship per CAA section 211(o)(9)(B). While EISA stated (per 
section 211(o)(9)(A)(ii)(I)) that the small refinery temporary 
exemption shall be extended for at least two years for any small 
refinery that the DOE small refinery study determines would face 
disproportionate economic hardship in meeting the requirements of the 
RFS2 program, we are not proposing this hardship provision given the 
outcome of the DOE small refinery study (as discussed below).
    In the small refinery study, ``EPACT 2005 Section 1501 Small 
Refineries Exemption Study'', DOE's finding was that there is no reason 
to believe that any small refinery would be disproportionately harmed 
by inclusion in the proposed RFS2 program. This finding was based on 
the fact that there appeared to be no shortage of RINs available under 
RFS1, and EISA has provided flexibility through waiver authority (per 
section 211(o)(7)). Further, in the case of the cellulosic biofuel 
standard, cellulosic biofuel allowances can be provided from EPA at 
prices established in EISA (see proposed regulation section 80.1455). 
DOE thus determined that no small refinery would be subject to 
disproportionate economic hardship under the proposed RFS2 program, and 
that the small refinery exemption should not be extended beyond 
December 31, 2010. DOE noted in the study that, if circumstances were 
to change and/or the RIN market were to become non-competitive or 
illiquid, individual small refineries have the ability to petition EPA 
for an extension of their small refinery exemption (as proposed at 
draft regulation section 80.1441). We note that the findings of DOE's 
small refinery study, and a consideration of EPA's ongoing review of 
the functioning of the RIN market, could factor into the basis for 
approval of such a hardship request.
    We are also proposing a case-by-case hardship provision for those 
small refiners that do not operate small refineries, at draft 
regulation section 80.1442(h), using our discretion under CAA section 
211(o)(3)(B). This proposed provision would allow those small refiners 
that do not operate small refineries to apply for the same kind of 
extension as a small refinery. In evaluating applications for this 
proposed hardship provision, it was recommended by the SBAR Panel that 
EPA take into consideration information gathered from annual reports 
and RIN system progress updates.
d. Phase-in
    The small refiner SERs suggested that a phase-in of the obligations 
applicable to small refiners would be beneficial for compliance, such 
that small refiners would comply by gradually meeting the standards on 
an incremental basis over a period of time, after which point they 
would comply fully with the RFS2 standards, however we have concerns 
about our authority under the statute to allow for such a phase-in of 
the standards. CAA section 211(o)(3)(B) states that the renewable fuel 
obligation

[[Page 24973]]

shall ``consist of a single applicable percentage that applies to all 
categories of persons specified'' as obligated parties. This kind of 
phase-in approach would result in different applicable percentages 
being applied to different obligated parties. Further, as discussed 
above, such a phase-in approach would provide more relief to small 
refineries operated by small refiners than that provided under the 
small refinery provision. We do not believe that we can use our 
discretion under the statute to allow for such a provision; however we 
invite comment on the concept of a phase-in provision for all small 
refiners.
e. RIN-Related Flexibilities
    The small refiner SERs requested that the proposed rule contain 
provisions for small refiners related to the RIN system, such as 
flexibilities in the RIN rollover cap percentage and allowing all small 
refiners to use RINs interchangeably. Currently in the RFS program, up 
to 20% of a previous year's RINs may be ``rolled over'' and used for 
compliance in the following year. A provision to allow for 
flexibilities in the rollover cap could include a higher RIN rollover 
cap for small refiners for some period of time or for at least some of 
the four standards. While the rollover cap is the means through which 
we are implementing the limited credit lifetime provisions in section 
211(o) of the CAA, and therefore cannot simply be eliminated, the 
magnitude of the cap can be modified to some extent. Thus, there could 
be an opportunity to provide appropriate flexibility in this area. 
However, given the results of the DOE small refinery study, we do not 
believe it would be appropriate to propose a change to the RIN rollover 
cap for small refiners today. However, we request comment on the 
concept of increasing the RIN rollover cap percentage for small 
refiners. We also request comment on an appropriate level of that 
percentage. For example, would a rollover cap of 50% for small refiners 
be appropriate? Or, would an intermediate value between 20% and 50%, 
such as 35%, be more appropriate?
    The Panel recommended that we take comment on allowing RINs to be 
used interchangeably for small refiners, but not propose this concept 
because under this approach small refiners would arguably be subject to 
a different applicable percentage than other obligated parties. 
However, this concept fails to require the four different standards 
mandated by Congress (e.g., conventional biofuel could not be used 
instead of cellulosic biofuel or biomass-based diesel), and is not 
consistent with section 211(o) of the Clean Air Act. Thus, we are not 
proposing this provision in this action, however we invite comment on 
such an approach for small refiners.

C. Other Flexibilities

1. Upward Delegation of RIN-Separating Responsibilities
    Since the start of the RFS1 program on September 1, 2007, there 
have been a number of instances in which a party who receives RINs with 
a volume of renewable fuel is required to either separate or retire 
those RINs, but views the recordkeeping and reporting requirements 
under the RFS program as an unnecessary burden. Such circumstances 
typically might involve a renewable fuel blender, a party that uses 
renewable fuel in its neat form, or a party that uses renewable fuel in 
a non-highway application and is therefore required to retire the RINs 
(under RFS1) associated with the volume. In some of these cases, the 
affected party may purchase and/or use only small volumes of renewable 
fuel and, absent the RFS program, would be subject to few if any other 
EPA regulations governing fuels.
    This situation will become more prevalent with the RFS2 program, as 
EISA added diesel fuel to the RFS program. With the RFS1 rule, small 
blenders (generally farmers and other parties that use nonroad diesel 
fuel) blending small amounts of biodiesel were not covered under the 
rule as EPAct mandated renewable fuel blending for highway use only. 
EISA mandates certain amounts of renewable fuels to be blended into 
transportation fuels--which includes nonroad diesel fuel. Thus, parties 
that were not regulated under the RFS1 rule who only blend a small 
amount of renewable fuel (and, as mentioned above, are generally not 
subject to many of the EPA fuels regulations) would now be regulated by 
the program.
    Consequently, we believe it may be appropriate, and thus we are 
proposing today, to permit blenders who only blend a small amount of 
renewable fuel to allow the party directly upstream to separate RINs on 
their behalf. Such a provision would be consistent with the fact that 
the RFS1 program already allows marketers of renewable fuels to assign 
more RINs to some of their sold product and no RINs to the rest of 
their sold product. We believe that this provision would eliminate 
undue burden on small parties who would otherwise not be regulated by 
this program. We are proposing that this provision apply to small 
blenders who blend and trade less than 125,000 total gallons of 
renewable fuel per year. We also request comment on whether or not this 
threshold is appropriate.
    We envision that such a provision would be available to any blender 
who must separate RINs from a volume of renewable fuel under Sec.  
80.1429(b)(2). We also request comment on appropriate documentation to 
authorize this upward delegation. This could be something such as a 
document given to the supplier identifying the RIN separation that the 
supplier would perform. The document could include sufficient 
information to precisely identify the conditions of the authorization, 
such as the volume of renewable fuel in question and the number of RINs 
assigned to that volume. By necessity the document would need to be 
signed by both parties, and copies retained as records by both parties, 
since the supplier would then be responsible for these actions. The 
supplier would then be allowed to retain ownership of RINs assigned to 
a volume of renewable fuel when that volume is transferred, under the 
condition that the RINs be separated or retired concurrently with the 
transfer of the volume. We are proposing an annual authorization that 
would apply to all volumes of renewable fuel transferred between two 
parties for a given year (i.e., the two parties would enter into a 
contract stating that the supplier has RIN-separation responsibilities 
for all transferred volumes).
    We are proposing this provision solely for the case of blenders who 
blend and trade less than 125,000 total gallons of renewable fuel per 
year. A company that blends 100,000 gallons and trades 100,000 gallons 
would not be able to use this provision. However, we request comment on 
whether authorization to delegate RIN-separation responsibilities 
should also be allowed for other parties as well.
2. Small Producer Exemption
    Under the RFS1 program, parties who produce or import less than 
10,000 gallons of renewable fuel in a year are not required to generate 
RINs for that volume, and are not required to register with the EPA if 
they do not take ownership of RINs generated by other parties. We 
propose to maintain this exemption under the RFS2 rule. However, we 
request comment on whether the 10,000 gallon threshold should be higher 
given that the total volume of renewable fuel mandated by EISA is 
considerably higher than that required by the RFS1 program, or 
conversely whether it should be lower given that the biomass-based 
diesel standard is considerably lower than the

[[Page 24974]]

mandated volume for total renewable fuel.

D. 20% Rollover Cap

    EISA does not change the language in CAA section 211(o)(5) stating 
that renewable fuel credits must be valid for showing compliance for 12 
months as of the date of generation. As discussed in the RFS1 final 
rulemaking, we interpreted the statute such that credits would 
represent renewable fuel volumes in excess of what an obligated party 
needs to meet their annual compliance obligation. Given that the 
renewable fuel standard is an annual standard, obligated parties 
determine compliance shortly after the end of the year, and credits 
would be identified at that time. In the context of our RIN-based 
program, we have accomplished the statute's objective by allowing RINs 
to be used to show compliance for the year in which the renewable fuel 
was produced and its associated RIN first generated, or for the 
following year. RINs not used for compliance purposes in the year in 
which they were generated will by definition be in excess of the RINs 
needed by obligated parties in that year, making excess RINs equivalent 
to the credits referred to in section 211(o)(5). Excess RINs are valid 
for compliance purposes in the year following the one in which they 
initially came into existence. RINs not used within their valid life 
will thereafter cease to be valid for compliance purposes.
    In the RFS1 final rulemaking, we also discussed the potential 
``rollover'' of excess RINs over multiple years. This can occur in 
situations wherein the total number of RINs generated each year for a 
number of years in a row exceeds the number of RINs required under the 
RFS program for those years. The excess RINs generated in one year 
could be used to show compliance in the next year, leading to the 
generation of new excess RINs in the next year, causing the total 
number of excess RINs in the market to accumulate over multiple years 
despite the limit on RIN life. The rollover issue could in some 
circumstances undermine the ability of a limit on credit life to 
guarantee an ongoing market for renewable fuels.
    To implement the Act's restriction on the life of credits and 
address the rollover issue, the RFS1 final rulemaking implemented a 20% 
cap on the amount of an obligated party's RVO that can be met using 
previous-year RINs. Thus each obligated party is required to use 
current-year RINs to meet at least 80% of its RVO, with a maximum of 
20% being derived from previous-year RINs. Any previous-year RINs that 
an obligated party may have that are in excess of the 20% cap can be 
traded to other obligated parties that need them. If the previous-year 
RINs in excess of the 20% cap are not used by any obligated party for 
compliance, they will thereafter cease to be valid for compliance 
purposes.
    EISA does not modify the statutory provisions regarding credit 
life, and the volume changes by EISA also do not change at least the 
possibility of large rollovers of RINs for individual obligated 
parties. Therefore, we propose to maintain the regulatory requirement 
for a 20% rollover cap under the new RFS2 program. However, under RFS2 
obligated parties will have four RVOs instead of one. As a result, we 
are proposing that the 20% rollover cap would apply separately to all 
four RVOs. We do not believe it would be appropriate to apply the 
rollover cap to only the RVO representing total renewable fuel, leaving 
the other three RVOs with no rollover cap. Doing so would allow all 
previous-year RINs used for compliance to be those with a D code of 4, 
and this in turn would allow an obligated party to meet one of the 
nested standards, such as that for biomass-based diesel, using more 
than 20% previous-year RINs. This could result in significant rollover 
of RINs with a D code of 2, representing biomass-based diesel, and the 
valid life of these RINs would have no meaning in this case.
    Some obligated parties have suggested that the rollover cap should 
be raised to a value higher than 20%, citing the need for greater 
flexibility in the face of significantly higher volume requirements. 
However, we believe that a higher value could create disruptions in the 
RIN market as parties with excess RINs would have a greater incentive 
to hold onto them rather than sell them. This would especially be a 
concern in years where the volume of renewable fuel available in the 
market is very close to the RFS requirements. Nevertheless, we request 
comment on whether the 20% rollover cap should be raised to a higher 
value.
    As described in Section III.G.4, some parties have also suggested 
that the rollover cap should be lowered to a value lower than 20%, such 
as 10%. In the event of concerns about the availability of RINs, a 
lower rollover cap would provide a greater incentive for parties with 
excess RINs to sell them rather than hold onto them. However, a lower 
rollover cap would also reduce flexibility for many obligated parties. 
While we are not proposing it in today's notice, we request comment on 
it.

E. Concept for EPA Moderated Transaction System

1. The Need for an EPA Moderated Transaction System
    In implementing RFS1, we found that the 38-digit standardized RINs 
have proven confusing to many parties in the distribution chain. 
Parties have made various errors in generating and using RINs. For 
example, we have seen errors wherein parties have transposed digits 
within the RIN. We have seen parties creating alphanumeric RINs, 
despite the fact that RINs are supposed to consist of all numbers. We 
have also seen incorrect numbering of volume start and end codes.
    Once an error is made within a RIN, the error propagates throughout 
the distribution system. Correcting an error can require significant 
time and resources and involve many steps. Not only must reports to EPA 
be corrected, underlying records and reports reflecting RIN 
transactions must also be located and corrected to reflect discovery of 
an error. Because reporting related to RIN transactions under RFS1 is 
only on a quarterly basis, a RIN error may exist for several months 
before being discovered.
    Incorrect RINs are invalid RINs. If parties in the distribution 
system cannot track down and correct the error made by one of them in a 
timely manner, then all downstream parties that trade the invalid RIN 
will be in violation. Because RINs are the basic unit of compliance for 
the RFS1 program, it is important that parties have confidence when 
generating and using them.
    All parties in the RFS1 and the proposed RFS2 regulated community 
use RINs. These parties include producers of renewable fuels, obligated 
parties, exporters, and other owners of RINS, typically marketers of 
renewable fuels and blenders. (Anyone can own RINs, but those who do 
would be subject to registration, recordkeeping, reporting, and attest 
engagement requirements described in this preamble.). Currently under 
RFS1, all RINs are used to comply with a single standard, and in 2013 
an additional cellulosic standard would have been added. Under this 
proposed rule, there are four standards, and RINs must be generated to 
identify four types of renewable fuels: cellulosic biofuel, biomass-
based diesel, other advanced biofuels, and other renewable fuels (e.g., 
corn ethanol). (For a more detailed discussion of RINs, see Section 
III.A of this preamble.) In the proposed EPA Moderated Transaction 
System (EMTS), the four types of RINs will be managed through four 
types of account.

[[Page 24975]]

    Based upon problems we observed with the use of RINs under RFS1, 
and considering that we will now have a more complex system including 
four standards instead of just one, we believe that the best way to 
screen RINs and conduct RIN-based transactions is through EMTS.
    This section describes the proposed EMTS and options for 
implementing it. By implementing EMTS, we believe that we would be able 
to greatly reduce RIN-related errors and efficiently and accurately 
manage the universe of RINs. There are two aspects to our proposal for 
EMTS. The first aspect focuses upon creating four, generic types of RIN 
account. The second aspect focuses upon actually developing a ``real 
time'' environment for handling RIN trades.
2. How EMTS Would Work
    EMTS would be a closed, EPA-managed system that provides a 
mechanism for screening RINs as well as a structured environment for 
conducting RIN transactions. ``Screening'' RINs will mean that parties 
would have much greater confidence that the RINs they handle are 
genuine. Although screening cannot remove all human error, we believe 
it can remove most of it.
    We propose that screening and assignment of RINs be made at the 
logical point, i.e., the point when RINs are generated through 
production or importation of renewable fuel. A renewable producer would 
electronically submit, in ``real time,'' a batch report for the volume 
of renewable fuel produced or imported, as well as a list of the RINs 
generated and assigned. EMTS would automatically screen each batch and 
either reject the RINs or permit them to pass into the transaction 
system, into the RIN generator's account, as one of the four types of 
RINs. Note that under RFS1, RIN generation (batch) and RIN transaction 
reports are submitted quarterly. Batch reports are submitted by 
producers and importers quarterly and reflect how they generated and 
assigned RINS to batches. RIN transaction reports are submitted by all 
parties who engage in RIN transactions, including buying or selling 
RINs. Under this proposed approach for RFS2, these batch reports and 
RIN transaction reports would be submitted monthly for calendar year 
2010. However, once EMTS is implemented in calendar year 2011, these 
separate periodic reports may no longer be necessary. Instead the 
information would be submitted as RINs are generated and assigned 
within EMTS.
    Under RFS1, the producer or importer list RINs they generate and 
assign via the batch report. EPA, in turn, uses the batch report data 
to verify RINs generated and transacted. The report is submitted 
quarterly. Under RFS1, the purpose of the RIN transaction report is to 
document RIN transactions and to document that RINs have been sold or 
transferred from party to party in the distribution system. This report 
is also submitted quarterly. The RIN transaction report includes the 
following information in this report: its name, its EPA company 
registration number, and in some cases (where compliance is on a 
facility basis), its EPA facility identification number. For the 
quarterly reporting period, the reporting party indicates the 
transaction type (RIN purchase, RIN sale, expired RIN, or retired RIN), 
and the date of the transaction. For a RIN purchase or sale, the 
transaction report includes the trading partner's name and the trading 
partner's EPA company registration number. There is also information 
that may have to be submitted in the event a reporting party must 
report a RIN that has been retired (e.g., when a RIN has become invalid 
due to the spillage of the associated volume of renewable fuel). As 
discussed above, the shortcoming of these reports is that they are only 
submitted quarterly. RIN errors that affect compliance may not be 
discovered for many months because of the relative infrequency of 
reporting transactions to EPA. EMTS will assume the functionality of 
batch reporting and transaction reporting used by regulated parties, 
allowing EPA to better screen RINs and reduce or eliminate generation 
and transaction errors.
    Under the RFS2 program, we are proposing that batch reports 
submitted by producers and importers and RIN transaction reports be 
submitted monthly rather than quarterly in the first year of the 
program (i.e., calendar year 2010). During 2010, we will be finishing 
development and testing of the EMTS. In order to minimize the hardship 
that undiscovered, invalid RINs may cause, we propose and seek comment 
on increasing the frequency of reporting and our own review of reports 
in order to assist the regulated community with compliance. As we 
develop EMTS through calendar year 2010, we intend to invite and 
encourage interested reporting parties to ``opt in'' to EMTS. This will 
serve a two-fold purpose: regulated parties may opt to gain familiarity 
EMTS before it becomes fully operational and we may have actual 
customers with which to test EMTS prior to it becoming fully 
operational. We believe that permitting interested parties to ``opt 
in'' will result in a better EMTS for all.
    In the second year of the program (i.e., calendar year 2011 and 
forward), we anticipate fully implementing the proposed EMTS and 
receiving the data contained in batch and RIN transaction reports in 
relatively ``real time'' (i.e., as transactions occur). We propose that 
``real time'' be construed as within three (3) business days of a 
reportable event (e.g., generation and assignment of RINs, transfer of 
RINs).
    Parties who use EMTS would have to register with EPA in accordance 
with the proposed RFS2 registration program described in Section III.C 
of this preamble. They would also have to create an account (i.e., 
register) via EPA's Central Data Exchange (CDX), as we envision 
managing EMTS via CDX. CDX is a secure and central portal through which 
parties may submit compliance reports. We propose that parties must 
establish an account with EMTS by October 1, 2010 or 60 days prior to 
engaging in any transaction involving RINs, whichever is later. As 
discussed above, the actual items of information covered by reporting 
under RFS2 are nearly identical to those reported under RFS1.
    Once registration occurs with EMTS, individual RIN accounts would 
be established and the system would manage the accounts for each 
individual party. The RIN accounts would correspond to the four broad 
types of renewable fuel. RIN accounts would be established for 
cellulosic biofuel, biomass-based diesel, other advanced biofuels, and 
other renewable fuels (including corn ethanol). One big advantage of 
RIN accounts is that the system would make available generic accounts 
for transactions involving RINs of similar type. The unique 
identification of the RIN would exist within EMTS, but parties engaging 
in RIN transactions would no longer have to worry about incorrectly 
recording or using 38-digit RIN numbers. As with RFS1, there is no 
``good faith'' provision to RIN ownership. An underlying principle of 
RIN ownership is still one of ``buyer beware'' and RINs may be 
prohibited from use at any time if they are found to be invalid. 
Because of the ``buyer beware'' aspect, we intend to offer the option 
for a buyer to accept or reject RINs from specific RIN generators or 
from classes of RIN generators. Also, we propose to collect information 
about the price associated with RINs traded. This information is not 
collected under RFS1, but we believe this information has great 
programmatic value to EPA because it may help us to anticipate and

[[Page 24976]]

appropriately react to market disruptions and other compliance 
challenges, assess and develop responses to potential waivers, and 
assist in setting future renewable standards. We believe that highly 
summarized price information (e.g., the average price of RINs traded 
nationwide) may be valuable to regulated parties, as well, and may help 
them to anticipate and avoid market disruptions.
    The following is an example of how a RIN transaction might occur in 
the proposed EMTS model:
    1. Seller logs into EMTS and posts his sale of 10,000 RINs to 
Buyer. For this example, assume the RINs were generated in 2008 and 
were assigned to 10,000 gallons of ``other renewable fuel'' (corn 
ethanol). Seller's RIN account for ``other renewable fuel'' is 
automatically reduced by 10,000 with the posting of his sale to Buyer. 
Buyer receives automatic notification of the pending transaction.
    2. Buyer logs into EMTS. She sees the sale transaction pending. 
Assuming it is correct, she accepts it. Upon her acceptance, her RIN 
account for ``other renewable fuel'' (corn ethanol) is automatically 
increased by 10,000 2008 assigned RINs.
    3. After Seller has posted his sale and Buyer has accepted it, EMTS 
automatically notifies both Buyer and Seller that the transaction has 
been fully completed.
    Under EMTS as we are proposing it, the seller would always have to 
initiate any transaction. The seller's account is reduced when he posts 
his sale. The buyer must acknowledge the sale in order to have the RINs 
transferred to her account. Transactions would always be limited to 
available RINs. Notification would automatically be sent to both the 
buyer and the seller upon completion of the transaction. EPA proposes 
to consider any sale or transfer as complete upon acknowledgement by 
the buyer.
    We propose that RINs and the parameters of RIN generation (e.g., 
year) be considered public information. We also propose that summary 
RIN price information, such as average price of all RINs in a broad 
geographic area (such as a state, region, or nationwide) be considered 
public information. This summary price information would be aggregated 
from transactions conducted within EMTS, but would not be identified 
with individual companies or particular transactions that have 
occurred. Because we believe information about RIN pricing in general 
will be useful to regulated parties, we are proposing to make this 
information available to them. We propose that the actual transactions 
between parties and that individual company account information may be 
claimed as confidential business information (CBI) by the parties to 
that transaction. EPA would treat any information submitted that is 
covered by a CBI claim in accordance with the procedures at 40 CFR Part 
2 and applicable Agency policies and guidelines for the handling of 
claimed CBI.
3. Implementation of EMTS
    We anticipate that implementing EMTS will take until January 1, 
2011, although we are proposing that the RFS2 program be effective on 
January 1, 2010. We anticipate that development of EMTS will require 
significant time and effort and that a delayed effective date may 
permit better pre-testing with interested regulated parties. We propose 
to permit regulated parties who are willing to participate in EMTS 
early to voluntarily opt-in to the system before January 1, 2011. The 
actual date for these parties' opt-in will depend upon the actual 
timeline for development of EMTS. We encourage comments from interested 
parties as to how we might best make use of the development period and 
the proposed opportunity for willing and interested parties to ``opt 
in'' early.
    Under our proposed scenario, for the 2010 compliance year, 
recordkeeping and reporting would be analogous to RFS1, although 
registration would be enhanced in accordance with the discussion in 
Section III.C of this preamble and recordkeeping and reporting would 
reflect the four types of RIN described above. In order to avoid 
propagation of RIN-related errors and to prevent errors from going too 
long without being detected, we believe it is necessary to increase the 
frequency of batch reporting and RIN transaction reporting to monthly 
rather than quarterly during 2010.
    EPA will implement the EMTS during the first year of the RFS2 
program. RINs generated under the RFS1 regulations will continue to be 
traded and reported using the current processes. RINs would still have 
unique identifying information, but EMTS will allow transactions to 
take place on a generic basis having the system track the specific 
unique identifiers. We believe that EMTS will virtually eliminate 
errors related to tracking and using individual RINs. Parties will be 
required to submit RIN transactions by specifying RIN year, RIN 
assignment, RIN fuel type, and any other reporting requirement 
specified by the administrator.
    Implementation of EMTS should save considerable time and resources 
for both industry and EPA. This is most evident considering that the 
proposed system virtually eliminates multiple sources of administrative 
errors, resulting in a reduction in costs and effort expended to 
correct and regenerate product transfer documents, documentation and 
recordkeeping, and resubmitting reports to EPA. We anticipate that a 
fully functioning EMTS will result in fewer reports and easier 
reporting for industry, and fewer reports requiring processing by EPA. 
Industry will need to spend less time and effort verifying the validity 
of the RINs they procure and allowing them to procure them on the open 
market with confidence. EPA will need to spend less time tracking down 
the responsible parties for invalid RINs. This is possible because EMTS 
will remove management of the 38-digit RIN from the hands of the 
reporting community. At the same time, EPA and the reporting community 
will be working with a standardized system, reducing stresses and 
development costs on IT systems.
    In summary, the advantage to implementing EMTS is that parties may 
engage in RIN transactions with a high degree of confidence. Errors 
would be virtually eliminated. Everyone engaging in RIN transactions 
would have a simplified environment in which to work which should 
minimize the level of resources needed for implementation. However, the 
one unavoidable disadvantage that we foresee is that parties would have 
to switch to a new and different reporting system in the second year of 
the RFS2 program. Some errors may still occur in by parties who 
continue to generate and use the 38-digit RINs during 2010. As 
discussed above, we propose to increase the frequency of batch and RIN 
transaction reporting to monthly for 2010, in order that we may help 
parties discover errors and correct them before they become violations. 
We also propose to permit parties to voluntarily ``opt in'' to using 
EMTS while it is still in development in order to ease the transition. 
We invite comment from all interested parties as to how we may best 
assist regulated parties in transitioning from the ``old'' RFS1 method 
of handing RINs to the ``new,'' proposed RFS2 EMTS method on January 1, 
2011.
    We also invite comment on whether, in the event the RFS2 start date 
is delayed, EPA should nevertheless allow a one-year period during 
which use of EMTS is optional, or if EPA should begin the program at 
the inception of the delayed RFS2 program if EMTS is fully operational 
at that time.

[[Page 24977]]

F. Retail Dispenser Labelling for Gasoline With Greater Than 10 Percent 
Ethanol

    Fuel retailers expressed concern that the magnitude of the price 
discount for E85 relative to E10 that would be necessary to facilitate 
sufficient use of E85 would encourage widespread misfueling of non-flex 
fuel vehicles. Today's proposal contains labeling requirements for 
pumps that dispense blends that contain greater than 10% ethanol which 
state that the use in non-flex fuel vehicles is prohibited and may 
cause damage to the vehicle.\45\ We anticipate that the industry would 
also conduct public information activities to alert customers who may 
not have yet become accustomed to seeing E85 at retail to avoid using 
E85 in their non-flex-fuel vehicles. Uniquely colored/labeled nozzle 
handles may also be useful in helping to prevent accidental cases of 
misfueling. We believe that in most cases the warnings that the use of 
E85 in non-flex fuel vehicles is illegal, can damage the vehicle, and 
can void vehicle manufacturer warranties may be a sufficient 
disincentive to prevent intentional misfueling. In cases where 
intentional misfueling may occasionally take place, the party is likely 
to experience drivability problems and thus would not repeat the act.
---------------------------------------------------------------------------

    \45\ See section 80.1469 in the proposed regulatory text.
---------------------------------------------------------------------------

    Today's proposal does not contain requirements that E85 refueling 
hardware be configured to prevent the introduction of E85 into non-
flex-fuel vehicles. It is unclear how such an approach could be 
implemented to allow the approximately 6 million flex-fuel vehicles on 
the road today to continue to be fueled with E85 without modification 
to their filler neck hardware.\46\ In any event, we do not believe that 
unique E85 nozzles are necessary.
---------------------------------------------------------------------------

    \46\ An E85 nozzle design and corresponding flex-fuel vehicle 
filler design that would prevent the introduction of E85 into non-
flex-fuel vehicles while allowing flex fuel vehicles to be fueled 
with E10 as well as E85 would also prevent the introduction of E85 
into current flex-fuel vehicles since there is currently no 
difference in nozzle/filler neck hardware between flex-fuel and non-
flex-fuel vehicles.
---------------------------------------------------------------------------

    We request comment on whether the proposed labeling requirements 
and voluntary measures such as those described above would provide 
sufficient warning to fuel retail customers not to refuel non-flex-fuel 
vehicles with E85. To the extent that other measures to prevent 
misfueling are thought to be necessary, comment is requested on the 
specific nature of such measures and the associated potential costs and 
benefits. One additional potential measure to prevent misfueling would 
be for cards to be issued to flex fuel vehicle owners and for all E85 
dispensers to be equipped with card readers that would allow E85 to be 
dispensed only to card holders.

V. Assessment of Renewable Fuel Production Capacity and Use

    To assess the impacts of this rule, there must be a clear 
understanding of the kind of renewable fuels that could be used, the 
types and locations of their feedstocks, the fuel volumes that could be 
produced by a given feedstock, and any challenges associated with their 
use. This section provides this assessment of the potential feedstocks 
and renewable fuels that may be used to meet the Energy Independence 
and Security Act (EISA) and the rationale behind our projections of 
various fuel types to represent the control case for analysis purposes. 
Definitional issues regarding the four types of renewable fuel required 
under EISA are discussed in Section III.B of this preamble.

A. Summary of Projected Volumes

    EISA mandates the use of increasing volumes of renewable fuel. To 
assess the impacts of this increase in renewable fuel volume from 
business-as-usual (what is likely to have occurred without EISA), we 
have established a reference and control case from which subsequent 
analyses are based. The reference case is essentially a projection of 
renewable fuel volumes without the enactment of EISA. The control case 
is a projection of the volumes and types of renewable fuel that might 
be used to comply with the EISA volume mandates. Both the reference and 
control cases are discussed in further detail below.
1. Reference Case
    Our reference case renewable fuel volumes are based on the Energy 
Information Administration's (EIA) Annual Energy Outlook (AEO) 2007 
reference case projections. The AEO 2007 presents long-term projections 
of energy supply, demand, and prices through 2030 based on results from 
EIA's National Energy Modeling System (NEMS). EIA's analysis focuses 
primarily on a reference case (which we use as our reference case), 
lower and higher economic growth cases, and lower and higher energy 
price cases. AEO 2007 projections generally are based on Federal, 
State, and local laws and regulations in effect on or before October 
31, 2006.\47\ The potential impacts of pending or proposed legislation, 
regulations, and standards are not reflected in the projections. While 
AEO 2007 is not as up-to-date as AEO 2008 (or the recently released AEO 
2009), we chose to use AEO 2007 because AEO 2008 already includes the 
impact of increased renewable fuel volumes under EISA as well as fuel 
economy improvements under CAFE, whereas AEO 2007 did not. Table V.A.1-
1 summarizes the fuel types and volumes for the years 2009-2022 as 
taken from AEO 2007. For our air quality analysis we also considered a 
reference case assuming the mandated renewable fuel volumes under the 
Renewable Fuel Standard Program from the Energy Policy Act of 2005 
(EPAct). Refer to Section VII for further details.
---------------------------------------------------------------------------

    \47\ EIA. Annual Energy Outlook 2007 with Projections to 2030. 
http://www.eia.doe.gov/oiaf/archive/aeo07/index.html. Accessed 
February 2008.

                     Table V.A.1-1--AEO 2007 Reference Case Projected Renewable Fuel Volumes
                                                [billion gallons]
----------------------------------------------------------------------------------------------------------------
                                                 Advanced biofuel                  Non-advanced
                                 ------------------------------------------------     biofuel
                                    Cellulosic     Biomass-based  Other advanced ----------------      Total
              Year                    biofuel        diesel\a\        biofuel                        renewable
                                 ------------------------------------------------                      fuel
                                    Cellulosic         FAME          Imported      Corn  ethanol
                                      ethanol      biodiesel\b\       ethanol
----------------------------------------------------------------------------------------------------------------
2009............................            0.07            0.32            0.50            9.44           10.33
2010............................            0.12            0.32            0.29           10.49           11.22
2011............................            0.19            0.33            0.16           10.69           11.37
2012............................            0.25            0.33            0.18           10.81           11.57

[[Page 24978]]

 
2013............................            0.25            0.33            0.19           10.93           11.70
2014............................            0.25            0.23            0.20           11.01           11.69
2015............................            0.25            0.25            0.39           11.10           11.99
2016............................            0.25            0.35            0.51           11.16           12.27
2017............................            0.25            0.36            0.53           11.30           12.44
2018............................            0.25            0.36            0.54           11.49           12.64
2019............................            0.25            0.37            0.58           11.69           12.89
2020............................            0.25            0.37            0.60           11.83           13.05
2021............................            0.25            0.38            0.63           12.07           13.33
2022............................            0.25            0.38            0.64           12.29           13.56
----------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel includes FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. AEO
  2007 only projects FAME biodiesel volumes.
\b\ Fatty acid methyl ester (FAME) biodiesel.

2. Control Case for Analyses
    Our assessment of the renewable fuel volumes required to meet EISA 
necessitates establishing a primary set of fuel types and volumes on 
which to base our assessment of the impacts of the new standards. EISA 
contains four broad categories: cellulosic biofuel, biomass-based 
diesel, total advanced biofuel, and total renewable fuel. As these 
categories could be met with a wide variety of fuel choices, in order 
to assess the impacts of the rule, we projected a set of reasonable 
renewable fuel volumes based on our interpretation at the time we began 
our analysis of likely fuels that could come to market.
    Although actual volumes and feedstocks may be different, we believe 
the projections made for our control case are within the range of 
reasonable predictions and allow for an assessment of the potential 
impacts of the RFS2 standards. Table V.A.2-1 summarizes the fuel types 
used for the control case and their corresponding volumes for the years 
2009-2022.

                                              Table V.A. 2-1--Control Case Projected Renewable Fuel Volumes
                                                                    [billion gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                       Advanced biofuel                             Non-
                                                              -----------------------------------------------------------------   Advanced
                                                                Cellulosic  Biomass-based diesel \a\   Other advanced biofuel     Biofuel
                                                                 biofuel   -----------------------------------------------------------------    Total
                             Year                             -------------                Non-co-        Co-                                 renewable
                                                                              FAME \b\    processed    processed     Imported       Corn         fuel
                                                                Cellulosic   biodiesel    renewable    renewable     ethanol      ethanol
                                                                 ethanol                    diesel       diesel
--------------------------------------------------------------------------------------------------------------------------------------------------------
2009.........................................................         0.00         0.50         0.00         0.00         0.50         9.85        10.85
2010.........................................................         0.10         0.64         0.01         0.01         0.29        11.55        12.60
2011.........................................................         0.25         0.77         0.03         0.03         0.16        12.29        13.53
2012.........................................................         0.50         0.96         0.04         0.04         0.18        12.94        14.66
2013.........................................................         1.00         0.94         0.06         0.06         0.19        13.75        16.00
2014.........................................................         1.75         0.93         0.07         0.07         0.36        14.40        17.58
2015.........................................................         3.00         0.91         0.09         0.09         0.83        15.00        19.92
2016.........................................................         4.25         0.90         0.10         0.10         1.31        15.00        21.66
2017.........................................................         5.50         0.88         0.12         0.12         1.78        15.00        23.40
2018.........................................................         7.00         0.87         0.13         0.13         2.25        15.00        25.38
2019.........................................................         8.50         0.85         0.15         0.15         2.72        15.00        27.37
2020.........................................................        10.50         0.84         0.16         0.16         2.70        15.00        29.36
2021.........................................................        13.50         0.83         0.17         0.17         2.67        15.00        32.34
2022.........................................................        16.00         0.81         0.19         0.19         3.14        15.00        35.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel includes FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.
\b\ Fatty acid methyl ester (FAME) biodiesel.

    We needed to make this projection soon after EISA was signed to 
allow sufficient time to conduct our long lead-time analyses. As a 
result, we used the same ethanol-equivalence basis for these 
projections as was used in the RFS1 rulemaking. However, as described 
in Section III.D.1, we are also co-proposing that volumes of renewable 
fuel be counted on a straight gallon-for-gallon basis under RFS2, such 
that all Equivalence Values would be 1.0. The net effect of these two 
approaches to Equivalence Values on projected volumes is very small; 
instead of 36 billion gallons of renewable fuel in 2022, our control 
case includes 35.3 billion gallons. We do not believe that

[[Page 24979]]

this difference will substantively affect the analyses that are based 
on our projected control case volumes.
    The following subsections detail our rationale for projecting the 
amount and type of fuels needed to meet EISA as shown in Table V.A.2-1. 
For cellulosic biofuel we have assumed that the entire volume will be 
domestically produced cellulosic ethanol. Biomass-based diesel is 
assumed to be comprised of a majority of fatty-acid methyl ester (FAME) 
biodiesel and a smaller portion of non-co-processed renewable diesel. 
The portion of the advanced biofuel category not met from cellulosic 
biofuel and biomass-based diesel is assumed to come mainly from 
imported (sugarcane) ethanol with a smaller amount from co-processed 
renewable diesel. The total renewable fuel volume not required to be 
comprised of advanced biofuels is assumed to be met with corn ethanol.
    In addition, the following subsections also describe other fuels 
that have the potential to contribute to meeting EISA, but because of 
their uncertainty of use, or because their use likely might be 
negligible we have chosen to not assume any use for our analysis. 
Examples of these types of renewable fuels or blendstocks include bio-
butanol, biogas, cellulosic diesel, cellulosic gasoline, biofuel from 
algae, jatropha, or palm, imported cellulosic ethanol, other biomass-
to-liquids (BTL), and other alcohols or ethers. We intend to revisit 
these assumptions for the final rule and invite comment on whether 
these renewable fuels or other potential fuels which have not been 
included in our analyses should be included.
a. Cellulosic Biofuel
    As defined in EISA, cellulosic biofuel means renewable fuel 
produced from any cellulose, hemicellulose, or lignin that is derived 
from renewable biomass and that has lifecycle greenhouse gas emissions, 
as determined by the Administrator, that are at least 60% less than the 
baseline lifecycle greenhouse gas emissions.
    When many people think of cellulosic biofuel, they immediately 
think of cellulosic ethanol. However, cellulosic biofuel could be 
comprised of other alcohols, synthetic gasoline, synthetic diesel fuel, 
and synthetic jet fuel, propane, and biogas. Whether cellulosic biofuel 
is ethanol will depend on a number of factors, including production 
costs, the form of tax subsidies, credit programs, and issues 
associated with blending the biofuel into the fuel pool. It will also 
depend on the relative demand for gasoline and diesel fuel. For 
instance, European refineries are undersupplying the European market 
with diesel fuel and oversupplying it with gasoline, and based on the 
recent high diesel fuel price margins over gasoline, it seems that the 
U.S. is falling in line with Europe. Therefore, if the U.S. trend is 
toward being relatively oversupplied with gasoline, there could be a 
price advantage towards producing renewable fuels that displace diesel 
fuel rather than a gasoline fuel replacement like ethanol.
    Current efforts in converting cellulosic feedstocks into fuels 
focus on biochemical and thermochemical conversion processes. 
Biochemical processes use live bacteria or isolated enzymes, or acids, 
to break cellulose down into fermentable sugars. The advantage of using 
live bacteria or enzymes is that simple carbon steel could be used 
which helps to control the capital costs. However, bacteria and enzymes 
that break down cellulose are generally specific to certain types of 
cellulose, thus, the cellulosic biofuel facility may have difficulty 
processing different types of feedstocks.\48\ If live bacteria are 
used, the bacteria could be susceptible to contamination that could 
force a plant shutdown. An example of a company using enzymes to 
process cellulose into ethanol is Iogen, which has a demonstration 
plant in Canada.
---------------------------------------------------------------------------

    \48\ This is currently an area of intense research.
---------------------------------------------------------------------------

    On the other hand, biochemical processes which rely on strong acids 
will likely be less susceptible to contamination issues, and could more 
easily process mixed feedstocks. Thus, strong acid biochemical 
cellulosic ethanol plants could process MSW or a variety of feedstocks 
which may be available in areas where no single feedstock dominates. 
The strong acids, however, would likely require more expensive 
metallurgy. A company which is planning to use strong acids to 
hydrolyze the cellulose is Blue Fire Ethanol. Blue Fire is planning on 
building a MSW plant in Southern California. Once cellulose is reduced 
to simple sugars, either strong acid or enzymatic cellulosic ethanol 
plants operate in a manner similar to a corn ethanol plant. This 
consists of fermenting sugars into ethanol and then separating the 
ethanol from the water that facilitated the fermentation step.
    The thermochemical conversion process is very different from the 
biochemical process right from the beginning. For the thermochemical 
process, feedstocks are partially burned with oxygen at a very high 
temperature and converted into a synthesis gas comprised of carbon 
monoxide and hydrogen. The principal advantage of the thermochemical 
process is that virtually any hydrocarbon material could be processed 
as feedstock, as they would all be converted to the synthesis gas, even 
if they produce different relative concentrations of carbon monoxide 
and hydrogen. The synthesis gas is typically converted to ethanol or 
diesel by one of several different processes.
    Examples of companies currently pursuing the thermochemical route 
to selectively produce ethanol include Range Ethanol and Coskata. Range 
Ethanol is using a specially formulated catalyst that will primarily 
produce ethanol, but it will produce other higher molecular weight 
alcohols as well which would be recycled and mostly converted to 
ethanol. Coskata, which is being supported by General Motors, is 
planning on using bacteria to convert the synthesis gas to ethanol.
    Another thermochemical plant could employ a very similar 
gasification reactor, but instead of producing ethanol from syngas, a 
Fischer Tropsch (F-T) reactor would be used to produce a primarily 
diesel product, i.e., cellulosic diesel. The F-T reactor would use a 
specially designed iron or cobalt catalyst to convert the syngas to 
straight chain hydrocarbon compounds of varying lengths and molecular 
weights. The heavier of these hydrocarbon compounds are then 
hydrocracked to produce a very high percentage of valuable diesel fuel 
and naphtha (gasoline type compounds). The F-T diesel fuel produced 
from the F-T process is very high in quality due to its high cetane and 
essentially zero sulfur level. While the naphtha produced from the F-T 
process also contains essentially zero sulfur, it is very low in octane 
and thus is a poor gasoline blendstock (although it could still be 
desirable as a gasoline blendstock because of all the high octane 
ethanol being blended into gasoline). Cellulosic naphtha is also 
valuable as a cracking feedstock for producing various petrochemical 
compounds. Since the F-T diesel is of better quality than the naphtha, 
the heavier hydrocarbon compounds are selectively hydrocracked to 
produce more diesel over naphtha.
    No commercial cellulosic diesel plants currently exist in the U.S., 
nor elsewhere in the world. Currently, there is a cellulosic diesel 
pilot plant operated by Choren in Germany and a commercial sized plant 
in the planning stages by Choren also in Germany. Choren is planning to 
employ woody materials and agricultural residue as feedstocks. Choren 
specially developed a three-stage gasification process for dealing with 
the complexities of

[[Page 24980]]

biomass and has partnered with Shell which has commercialized a F-T 
reaction process. The Choren commercial cellulosic diesel plant in 
Germany is expected to begin operating in 2010. Although coal-to-
liquids (CTL) plants rely on coal as their feedstock, they are very 
similar to cellulosic diesel plants in design and help to demonstrate 
the feasibility of the cellulosic diesel process. There are CTL pilot 
plants which are operating today, as well as a number of commercial CTL 
plants operating today or in the planning stages. Some of these plants 
have experimented with or are being planned for co-feeding biomass 
along with the coal. A current list of proposed cellulosic diesel and 
CTL plants is provided in Chapter 1 of the DRIA.
    In terms of production costs, at least for the current state of 
technology, neither the biochemical nor thermochemical platforms 
(comparing enzymatic biochemical processing to ethanol and 
thermochemical processing to cellulosic diesel) appear to have clear 
advantages in capital costs or operating costs.\49\ Other processing 
techniques, for example, the syngas-to-ethanol process used by Coskata, 
claim to be capable of producing at even lower production costs, but 
without any commercial facilities operating today, it is hard to 
predict how these other processing techniques differ from our estimates 
of what the production costs for cellulosic biofuel facilities will be 
in the future and which technology pathways will be most economic. As 
such, both enzymatic biochemical and thermochemical technologies could 
be key processing pathways for the production of cellulosic biofuel.
---------------------------------------------------------------------------

    \49\ Wright, M. and Brown, R, ``Comparative Economics of 
Biorefineries Based on the Biochemical and Thermochemical 
Platforms,'' Biofuels, Bioprod. Bioref. 1:49-56, 2007.
---------------------------------------------------------------------------

    The economic competitiveness of cellulosic biofuels will also 
depend on the extent of financial support from the government. Under 
the Farm Bill of 2008, both cellulosic ethanol and cellulosic diesel 
receive the same tax subsidies ($1.01 per gallon each). The tax 
subsidy, however, gives ethanol producers a considerable advantage over 
those producing cellulosic diesel due to the feedstock quantity needed 
per gallon produced (i.e., typically the higher the energy content of 
the product, the more feedstock that is required). On an energy basis, 
cellulosic ethanol would receive approximately $13/mmBtu while 
cellulosic diesel would receive approximately $8/mmBtu. In a similar 
manner, if we were to finalize an approach to the Equivalence Values 
for generating RINs in which volume rather than energy content is the 
basis, there would be an advantage for the production of cellulosic 
ethanol over cellulosic diesel.
    One large advantage that cellulosic diesel has over ethanol is the 
ability for the fuel to be blended easily into the current distribution 
infrastructure at sizeable volumes. There are currently factors tending 
to limit the amount of ethanol that can be blended into the fuel pool 
(see Section V.D. for more discussion). Thus, the production of 
cellulosic diesel instead of cellulosic ethanol could help increase 
consumption of renewable fuels.
    Thus, there is uncertainty as to which mix of cellulosic biofuels 
will be produced to fulfill the 16 Bgal mandate by 2022. The latest 
release of AEO 2009, for example, estimates a mixture of cellulosic 
diesel and ethanol produced for cellulosic biofuel. For assessing the 
impacts of the RFS2 standards, we made the simplifying assumption that 
cellulosic biofuel would only consist of ethanol, though market 
realities may also result in cellulosic diesel and other products. We 
are requesting comment on the types of cellulosic biofuel that should 
be accounted for in our analyses and whether certain fuels are more 
likely to come to fruition than others.
    Cellulosic biofuel could also be produced internationally. One 
example of internationally produced cellulosic biofuel is ethanol 
produced from bagasse or straw from sugarcane processing in Brazil. 
Currently, Brazil burns bagasse to produce steam and generate 
bioelectricity. However, improving efficiencies over the coming decade 
may allow an increasing portion of bagasse to be allocated to other 
uses, including cellulosic biofuel, as the demand for bagasse for steam 
and bioelectricity could remain relatively constant.
    One recent study assessed the biomass feedstock potential for 
selected countries outside the United States and projected supply 
available for export or for biofuel production.50 51 For the 
study's baseline projection in 2017, it was estimated that 
approximately 21 billion ethanol-equivalent gallons could be produced 
from cellulosic feedstocks at $36/dry tonne or less. The majority 
(~80%) projected is from bagasse, with the rest from forest products. 
Brazil was projected to have the most potential for cellulosic 
feedstock production from both bagasse and forest products. Other 
countries include India, China, and those belonging to the Caribbean 
Basin Initiative (CBI), though much smaller feedstock supplies are 
projected as compared to Brazil. Although international production of 
cellulosic biofuel is possible, it is uncertain whether this supply 
would be available primarily to the U.S. or whether other nations would 
consume the fuel domestically. Therefore, for our analyses we have 
chosen to assume that all the cellulosic biofuel used to comply with 
RFS2 would be produced domestically.
---------------------------------------------------------------------------

    \50\ Countries evaluated include Argentina, Brazil, Canada, 
China, Colombia, India, Mexico, and CBI.
    \51\ Kline, K. et al., ``Biofuel Feedstock Assessment for 
Selected Countries,'' Oak Ridge National Laboratory, February 2008.
---------------------------------------------------------------------------

b. Biomass-Based Diesel
    Biomass-based diesel as defined in EISA means renewable fuel that 
is biodiesel as defined in section 312(f) of the Energy Policy Act of 
1992 with lifecycle greenhouse gas emissions, as determined by the 
Administrator, that are at least 50% less than the baseline lifecycle 
greenhouse gas emissions. Biomass-based diesel can include fatty acid 
methyl ester (FAME) biodiesel, renewable diesel (RD) that has not been 
co-processed with a petroleum feedstock, as well as cellulosic diesel. 
Although cellulosic diesel produced through the Fischer-Tropsch (F-T) 
process could potentially contribute to the biomass-based diesel 
category, we have assumed for our analyses that the fuel and its 
corresponding feedstocks (cellulosic biomass) are already accounted for 
in the cellulosic biofuel category discussed previously in Section 
V.A.2.a.
    FAME and RD processes can make acceptable quality fuel from 
vegetable oils, fats, and greases, and thus will generally compete for 
the same feedstock pool. For our analyses, we have assumed that the 
volume contribution from FAME biodiesel and RD will be a function of 
the available feedstock types. In our analysis we assumed that virgin 
plant oils would be preferentially processed by biodiesel plants, while 
the majority of fats and greases would be routed to RD 
production.52 53 This is because the RD process involves 
hydrotreating (or thermal depolymerization), which is more severe and 
uses multiple chemical mechanisms to reform the fat molecules into 
diesel range material. The FAME

[[Page 24981]]

process, by contrast, relies on more specific chemical mechanisms and 
requires pre-treatment if the feedstocks contain more than trace 
amounts of free fatty acids or other contaminates which are typical of 
recycled fats and greases. In terms of volume availability of 
feedstocks, supplies of fats and greases are more limited than virgin 
vegetable oils. As a result, our control case assumes the majority of 
biomass-based diesel volume is met using biodiesel facilities 
processing vegetable oils, with RD making up a smaller portion and 
using solely fats and greases.
---------------------------------------------------------------------------

    \52\ Recent changes to federal tax subsidies and market shifts 
may warrant changes to this assumption. We will reevaluate the 
relative production volumes of biodiesel and renewable diesel for 
the FRM.
    \53\ This analysis was conducted prior to the completion of our 
lifecycle analysis discussed in Section VI, and assumes the fuels 
will meet the required GHG threshold.
---------------------------------------------------------------------------

    The RD production volume must be further classified as co-processed 
or non-co-processed, depending on whether the renewable material was 
mixed with petroleum during the hydrotreating operations (more details 
on this definition are in Section III.B.1). EISA specifically forbids 
co-processed RD from being counted as biomass-based diesel, but it can 
still count toward the total advanced biofuel requirement. What 
fraction of RD will ultimately be co-processed is uncertain at this 
time, since little or no commercial production of RD is currently 
underway, and little public information is available about the 
comparative economics and feasibility of the two methods. We assumed in 
our control case that half the material will be non-co-processed and 
thus qualify as biomass-based diesel. We invite comment on whether RD 
production will favor co-processing or non-co-processing with a 
petroleum feedstock in the future.
    Perhaps the feedstock with the greatest potential for providing 
large volumes of oil for the production of biomass-based diesel is 
microalgae. Algae grown on land in photo-bioreactors or in open ponds 
could potentially yield 15 to 50 times more oil per acre than 
traditional oil crops such as soy, rapeseed, or oil palm. Additionally 
it can be cultivated on marginal land with low nutrient inputs, and 
thus does not suffer from the sheer resource constraints that make 
other biofuel feedstocks problematic at large scale. However, several 
technical hurdles do still exist. Specifically, more efficient 
harvesting, dewatering and lipid extraction methods are needed to lower 
costs to a level competitive with other biodiesel feedstocks (20-30% of 
current costs). Until these hurdles are overcome, it is unlikely that 
algae-based biodiesel can be commercially competitive with other 
biodiesel fuels. Thus, for our control case we have chosen not to 
include oil from algae as a feedstock. Although the majority of algae 
to biofuel companies are focusing on producing algae oil for 
traditional biodiesel production, several companies are alternatively 
using algae for producing ethanol or crude oil for gasoline or diesel 
which could also help contribute to the advanced biofuel mandate.\54\ 
For more detail on algae as a feedstock refer to Section 1.1 of the 
DRIA.
---------------------------------------------------------------------------

    \54\ Algenol and Sapphire Energy, see http://www.algenolbiofuels.com/ and http://www.sapphireenergy.com/.
---------------------------------------------------------------------------

    Jatropha curcas, a shrub native to Central America, is yet another 
possible biofuel feedstock. The perennial yields oil-rich seeds yearly, 
with oil yields per acre up to 4 times that of soy and twice that of 
rapeseed under optimal conditions. It can grow on low-nutrient lands, 
and is tolerant of drought. However, jatropha yields under these 
marginal conditions are hard to predict because of insufficient 
commercial experience; it is possible that jatropha will have low 
yields in the sub-optimal conditions where its cultivation would be 
most advantageous. Furthermore, jatropha seed harvesting is very labor 
intensive, and little is known about the crop's sustainability impacts, 
its long-term yield, or the feasibility of cultivation as a 
monoculture. It is unlikely that jatropha can be cultivated in the 
United States economically or sustainably, and the possibility of 
importing jatropha oil or biodiesel from producing countries is very 
uncertain because overseas cultivation efforts are still underdeveloped 
and initial volumes will likely be used domestically. As a result, we 
have not projected the use of jatropha as a feedstock under our control 
case. For more detail on the potential use of jatropha refer to Section 
1.1 of the DRIA.
c. Other Advanced Biofuel
    As defined in EISA, advanced biofuel means renewable fuel, other 
than ethanol derived from corn starch, that has lifecycle greenhouse 
gas emissions, as determined by the Administrator, that are at least 
50% less than baseline lifecycle greenhouse gas emissions. As described 
more fully in Section VI.D, we are proposing that the GHG threshold for 
advanced biofuels be adjusted to 44% or potentially as low as 40% 
depending on the results from the analyses that will be conducted for 
the final rule. As defined in EISA, advanced biofuel includes the 
cellulosic biofuel, biomass-based diesel, and co-processed renewable 
diesel categories that were mentioned in Sections V.A.2.a and V.A.2.b 
above. However, EISA requires greater volumes of advanced biofuel than 
just the volumes required of these fuels; see Table V.A.2-1. It is 
entirely possible that greater volumes of cellulosic biofuel, biomass-
based diesel, and co-processed renewable diesel than required by EISA 
could be produced in the future. Our control case, however, does not 
assume that cellulosic biofuel and biomass-based diesel volumes will 
exceed those required under EISA.\55\ As a result, to meet the total 
advanced biofuel volume required under EISA, advanced biofuel types are 
needed other than cellulosic biofuel, biomass-based diesel, and co-
processed renewable diesel through 2022.
---------------------------------------------------------------------------

    \55\ While cellulosic biofuel will not be limited by feedstock 
availability, it likely will be limited by the very aggressive ramp 
up in production volume for an industry which is still being 
demonstrated on the pilot scale and therefore is not yet 
commercially viable. On the other hand, biomass-based diesel derived 
from agricultural oils and animal fats are faced with relatively 
high feedstock costs which limit feedstock supply.
---------------------------------------------------------------------------

    We have assumed for our control case that the most likely source of 
advanced fuel other than cellulosic biofuel, biomass-based diesel, and 
co-processed renewable diesel would be from imported sugarcane 
ethanol.\56\ Our assessment of international fuel ethanol production 
and demand indicate that anywhere from 3.8-4.2 Bgal of sugarcane 
ethanol from Brazil could be available for export by 2020/2022. If this 
volume were to be made available to the U.S., then there would be 
sufficient volume to meet the advanced biofuel standard. To calculate 
the amount of imported ethanol needed to meet the EISA standards, we 
took the difference between the total advanced biofuel category and 
cellulosic biofuel, biomass-based diesel, and co-processed renewable 
diesel categories. The amount of imported ethanol required by 2022 is 
approximately 3.2 Bgal. We solicit comment on our estimate of 3.2 Bgal 
and whether or not it is reasonable to assume that Brazil (or any other 
country) could satisfy this demand.
---------------------------------------------------------------------------

    \56\ This analysis was conducted prior to the completion of our 
lifecycle analysis discussed in Section VI, and assumes the fuel 
will meet the required GHG threshold.
---------------------------------------------------------------------------

    Recent news indicates that there are also plans for sugarcane 
ethanol to be produced in the U.S in places where the sugar subsidy 
does not apply. For instance, sugarcane has been grown in California's 
Imperial Valley specifically for the purpose of making ethanol and 
using the cane's biomass to generate electricity to power the ethanol 
distillery as well as export excess electricity to the electric 
grid.\57\ There are at least two projects being developed at this time 
that could result in several

[[Page 24982]]

hundred million gallons of ethanol produced. The sugarcane is being 
grown on marginal and existing cropland that is unsuitable for food 
crops and will replace forage crops like alfalfa, Bermuda grass, Klein 
grass, etc. Harvesting is expected to be fully mechanized. Thus, there 
is potential for these projects and perhaps others to help contribute 
to the EISA biofuels mandate. This could lower the volume needed to be 
imported from Brazil.
---------------------------------------------------------------------------

    \57\ Personal communication with Nathalie Hoffman, Managing 
Member of California Renewable Energies, LLC, August 27, 2008.
---------------------------------------------------------------------------

    Butanol is another potential motor vehicle fuel which could be 
produced from biomass and used in lieu of ethanol to comply with the 
RFS2 standard. Production of butanol is being pursued by a number of 
companies including a partnership between BP and Dupont. Other 
companies which have expressed the intent to produce biobutanol are 
Baer Biofuels and Gevo. The near term technology being pursued for 
producing butanol involves fermentation of starch compounds, although 
it can also be produced from cellulose. Butanol has several inherent 
advantages compared to ethanol. First, it has higher energy density 
than ethanol which would improve fuel economy (mpg). Second, butanol is 
much less water soluble which may allow the butanol to be blended in at 
the refinery and the resulting butanol-gasoline blend then more easily 
shipped through pipelines. This would reduce distribution costs 
associated with ethanol's need to be shipped separately from its 
gasoline blendstock and also save on the blending costs incurred at the 
terminal. Third, butanol can be blended in higher concentrations than 
10% which would likely allow butanol to be blended with gasoline at 
high enough concentrations to avoid the need for most or all of high 
concentration ethanol-gasoline blends, such as E85, that require the 
use of fuel flexible vehicles. For example, because of butanol's lower 
oxygen content, it can be blended at 16% (by volume) to match the 
oxygen concentration of ethanol blended at 10% (by volume).\58\ Because 
of butanol's higher energy density, when blending butanol at 16% by 
volume, it is the renewable fuels equivalent to blending ethanol at 
about 20 percent. Thus, butanol would enable achieving most of the RFS2 
standard by blending a lower concentration of renewable fuel than 
having to resort to a sizable volume of E85 as in the case of ethanol. 
As pointed out in Section V.D., the need to blend ethanol as E85 
provides some difficult challenges. The use of butanol may be one means 
of avoiding these blending difficulties.
---------------------------------------------------------------------------

    \58\ To obtain EPA approval for butanol blends as high as 16% by 
volume would require that the butanol be blended with an approved 
corrosion inhibitor.
---------------------------------------------------------------------------

    At the same time, butanol has a couple of less desirable aspects 
relative to ethanol. First, butanol is lower in octane compared to 
ethanol--ethanol has a very high blending octane of around 115, while 
butanol's octane ranges from 87 octane numbers for normal butanol and 
94 octane numbers for isobutanol. Potential butanol producers are 
likely to pursue producing isobutanol over normal butanol because of 
isobutanol's higher octane content. Higher octane is a valuable 
attribute of any gasoline blendstock because it helps to reduce 
refining costs. A second negative property of butanol is that it has a 
much higher viscosity compared to either gasoline or ethanol. High 
viscosity makes a fuel harder to pump, and more difficult to atomize in 
the combustion chamber in an internal combustion engine. The third 
downside to butanol is that it is more expensive to produce than 
ethanol, although the higher production cost is partially offset by its 
higher energy density.
    Another potential source of renewable transportation fuel is 
biomethane refined from biogas. Biogas is a term meaning a combustible 
mixture of methane and other light gases derived from biogenic sources. 
It can be combusted directly in some applications, but for use in 
highway vehicles it is typically purified to closely resemble fossil 
natural gas for which the vehicles are typically designed. The 
definition of biogas as given in EISA is sufficiently broad to cover 
combustible gases produced by biological decomposition of organic 
matter, as in a landfill or wastewater treatment facility, as well as 
those produced via thermochemical decomposition of biomass.
    Currently, the largest source of biogas is landfill gas collection, 
where the majority of fuel is combusted to generate electricity, with a 
small portion being upgraded to methane suitable for use in heavy duty 
vehicle fleets. Current literature suggests approximately 16 billion 
gasoline gallons equivalent of biogas (referring to energy content) 
could potentially be produced in the long term, with about two thirds 
coming from biomass gasification and about one third coming from waste 
streams such as landfills and human and animal sewage 
digestion.59 60
---------------------------------------------------------------------------

    \59\ National Renewable Energy Laboratory estimate based on 
biomass portion available at $45-$55/dry ton. Using POLYSYS Policy 
Analysis System, Agricultural Policy Analysis Center, University of 
Tennessee. http://www.agpolicy.org/polysys.html. Accessed May 2008.
    \60\ Milbrandt, A., ``Geographic Perspective on the Current 
Biomass Resource Availability in the United States.'' 70 pp., NREL 
Report No. TP-560-39181, 2005.
---------------------------------------------------------------------------

    Because the majority of the biogas volume estimates assume biomass 
as a feedstock, we have chosen not to include this fuel in our analyses 
since we are projecting most available biomass will be used for 
cellulosic liquid biofuel production in the long term. The remaining 
biogas potentially available from waste-related sources would come from 
a large number of small streams requiring purification and connection 
to storage and/or distribution facilities, which would involve 
significant economic hurdles. An additional and important source of 
uncertainty is whether there would be a sufficient number of vehicles 
configured to consume these volumes of biogas. Thus, we expect future 
biogas fuel streams to continue to find non-transportation uses such as 
electrical power generation or facility heating.
d. Other Renewable Fuel
    The remaining portion of total renewable fuel not met with advanced 
biofuel is assumed to come from corn-based ethanol. EISA effectively 
sets a limit for participation in the RFS program of 15 Bgal of corn 
ethanol by 2022. It should be noted, however, that there is no specific 
``corn-ethanol'' mandated volume, and that any advanced biofuel 
produced above and beyond what is required for the advanced biofuel 
requirements could reduce the amount of corn ethanol needed to meet the 
total renewable fuel standard. This occurs in our projections during 
the earlier years (2009-2014) in which we project that some fuels could 
compete favorably with corn ethanol (e.g. biodiesel and imported 
ethanol). Beginning around 2015, fuels qualifying as advanced biofuels 
likely will be devoted to meeting the increasingly stringent volume 
mandates for advanced biofuel. It is also worth noting that more than 
15 Bgal of corn ethanol could be produced and RINs generated for that 
volume under our proposed RFS2 regulations. However, obligated parties 
would not be required to purchase more than 15 Bgal worth of corn 
ethanol RINs.
    We are assuming for our analysis that sufficient corn ethanol will 
be produced to meet the 15 Bgal limit. However, this assumes that in 
the future corn ethanol production is not limited due to environmental 
constraints, such as water quantity issues (see Section 6.10 of the 
DRIA). This also assumes that in

[[Page 24983]]

the future either corn ethanol plants are constructed or modified to 
meet the 20% GHG threshold, or that sufficient corn ethanol production 
exists that is grandfathered and not required to meet the 20% 
threshold. Our current projection is that up to 15 Bgal could be 
grandfathered, but actual volumes will be determined at the time of 
facility registration. Refer to Section 1.5.1.4 of the DRIA for more 
information. Since our current lifecycle analysis estimates that much 
of the current corn ethanol would not meet the 20% GHG reduction 
threshold required of non-grandfathered facilities without facility 
upgrades, then if actual grandfathered corn volumes are less than 15 
Bgal it may be necessary to meet the volume mandate with other 
renewable fuels or through the use of advanced technologies that could 
improve the corn ethanol lifecycle GHG estimates.

B. Renewable Fuel Production

1. Corn/Starch Ethanol
    The majority of domestic biofuel production currently comes from 
plants processing corn and other similarly-processed grains in the 
Midwest. However, there are a handful of plants located outside the 
Corn Belt and a few plants processing simple sugars from food or 
beverage waste. In this section, we will summarize the present state of 
the corn/starch ethanol industry and discuss how we expect things to 
change in the future under the proposed RFS2 program.
a. Historic/Current Production
    The United States is currently the largest ethanol producer in the 
world. In 2008, the U.S. produced almost nine billion gallons of fuel 
ethanol for domestic consumption, the majority of which came from 
locally-grown corn.\61\ Although the U.S. ethanol industry has been in 
existence since the 1970s, it has rapidly expanded over the past few 
years due to the phase-out of methyl tertiary butyl ether (MTBE),\62\ 
elevated crude oil prices, state mandates and tax incentives, the 
introduction of the Federal Volume Ethanol Excise Tax Credit 
(VEETC),\63\ and the implementation of the existing RFS1 program.\64\ 
As shown in Figure V.B.1-1, U.S. ethanol production has grown 
exponentially over the past decade.
---------------------------------------------------------------------------

    \61\ Based on total transportation ethanol reported in EIA's 
March 2009 Monthly Energy Review (Table 10.2) less imports (http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
    \62\ For more information on how the phase-out of MTBE helped 
spur ethanol production/consumption, refer to Section V.D.1.
    \63\ On October 22, 2004, President Bush signed into law H.R. 
4520, the American Jobs Creation Act of 2004 (JOBS Bill), which 
created the Volumetric Ethanol Excise Tax Credit (VEETC). The $0.51/
gal VEETC for ethanol blender replaced the former fuel excise tax 
exemption, blender's credit, and pure ethanol fuel credit. However, 
the recently-enacted 2008 Farm Bill modifies the alcohol credit so 
that corn ethanol gets a reduced credit of $0.45/gal and cellulosic 
biofuel a credit of $1.01/gal effective January 1, 2009.
    \64\ On May 1, 2007, EPA published a final rule (72 FR 23900) 
implementing the Renewable Fuel Standard (RFS) required by EPAct. 
The RFS requires that 4.0 billion gallons of renewable fuel be 
blended into gasoline/diesel by 2006, growing to 7.5 billion gallons 
by 2012.
    \65\ Based on total transportation ethanol reported in EIA's 
March 2009 Monthly Energy Review (Table 10.2) less imports (http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
[GRAPHIC] [TIFF OMITTED] TP26MY09.004


[[Page 24984]]


    As of April 1, 2009, there were 169 corn/starch ethanol plants 
operating in the U.S. with a combined estimated production capacity of 
10.5 billion gallons per year.\66\ This does not include a number of 
ethanol plants that are currently idled.\67\ The majority of today's 
ethanol (over 91% by volume) is produced exclusively from corn. Another 
8% comes from a blend of corn and/or similarly processed grains (milo, 
wheat, or barley) and less than half a percent is produced from cheese 
whey, waste beverages, and sugars/starches combined. A summary of U.S. 
ethanol production by feedstock is presented in Table V.B.1-1.
---------------------------------------------------------------------------

    \66\ Our April 2009 corn/starch ethanol industry 
characterization was based on a variety of sources including: 
Renewable Fuels Association (RFA) Ethanol Biorefinery Locations 
(updated March 31, 2009); Ethanol Producer Magazine (EPM) Producing 
plant list (last modified on April 7, 2009), and ethanol producer 
Web sites. The baseline does not include ethanol plants whose 
primary business is industrial or food-grade ethanol production nor 
does it include plants that might be located in the Virgin Islands 
or U.S. territories. Where applicable, current/historic production 
levels have been used in lieu of nameplate capacities to estimate 
production capacity. The April 2009 information presented in this 
section reflects our most recent knowledge of the corn/starch 
ethanol industry. However, for various NPRM impact analyses, an 
earlier May 2008 industry assessment was used. For more on this 
assessment, refer to Section 1.5.1.5 of the DRIA.
    \67\ In addition to idled plants, the assessment does not 
include idled production capacity at facilities that are currently 
operating at 50% or less than their nameplate capacity.

                   Table V.B.1-1--Current Corn/Starch Ethanol Production Capacity by Feedstock
----------------------------------------------------------------------------------------------------------------
                                                                Capacity    Percent of   Number of    Percent of
           Plant feedstock (Primary listed first)                 MGY        capacity      plants       plants
----------------------------------------------------------------------------------------------------------------
Corn \a\....................................................        9,605         91.2          144         85.2
Corn, Milo \b\..............................................          717          6.8           14          8.3
Corn, Wheat.................................................          130          1.2            1          0.6
Milo........................................................            3          0.0            1          0.6
Wheat, Milo.................................................           50          0.5            1          0.6
Cheese Whey.................................................            5          0.0            1          0.6
Waste Beverages \c\.........................................           19          0.2            5          3.0
Waste Sugars & Starches \d\.................................            7          0.1            2          1.2
                                                             ---------------------------------------------------
    Total...................................................       10,535          100          169          100
----------------------------------------------------------------------------------------------------------------
\a\ Includes one facility processing seed corn, two facilities also operating pilot-level cellulosic ethanol
  plants at these locations, and four facilities planning on incorporating cellulosic feedstocks in the future.
\b\ Includes one facility processing a small amount of molasses in addition to corn and milo.
\c\ Includes two facilities processing brewery waste.
\d\ Includes one facility processing potato waste that intends to add corn in the future.

    As shown in Table V.B.1-1, of the 169 operating plants, 161 process 
corn and/or other similarly processed grains. Of these facilities, 150 
utilize dry-milling technologies and the remaining 11 plants rely on 
wet-milling processes. Dry mill ethanol plants grind the entire kernel 
and generally produce only one primary co-product: Distillers grains 
with solubles (DGS). The co-product is sold wet (WDGS) or dried (DDGS) 
to the agricultural market as animal feed. However, there are a growing 
number of dry mill ethanol plants pursuing front-end fractionation or 
back-end extraction to produce fuel-grade corn oil for the biodiesel 
industry. There are also additional plants pursuing cold starch 
fermentation and other energy-saving processing technologies. For more 
on the dry-milling and wet-milling processes as well as emerging 
advanced technologies, refer to Section 1.4 of the DRIA.
    In contrast to dry mill plants, wet mill facilities separate the 
kernel prior to processing into its component parts (germ, fiber, 
protein, and starch) and in turn produce other co-products (usually 
gluten feed, gluten meal, and food-grade corn oil) in addition to DGS. 
Wet mill plants are generally more costly to build but are larger in 
size on average.\68\ As such, 11.5% of the current grain ethanol 
production comes from the 11 previously-mentioned wet mill facilities. 
The remaining eight plants which process cheese whey, waste beverages 
or sugars/starches, operate differently than their grain-based 
counterparts. These small production facilities do not require milling 
and operate a simpler enzymatic fermentation process.
---------------------------------------------------------------------------

    \68\ According to our April 2009 corn ethanol plant assessment, 
the average wet mill plant capacity was 111 million gallons per 
year--almost twice that of the average dry mill plant capacity (62 
million gallons per year). For more on average plant sizes, refer to 
Section 1.5.1.1 of the DRIA.
---------------------------------------------------------------------------

    Ethanol production is a relatively resource-intensive process that 
requires the use of water, electricity, and steam.\69\ Steam needed to 
heat the process is generally produced on-site or by other dedicated 
boilers.\70\ The ethanol industry relies primarily on natural gas. Of 
today's 169 ethanol production facilities, 142 burn natural gas \71\ 
(exclusively), three burn a combination of natural gas and biomass, one 
recently started burning a combination of natural gas, landfill biogas 
and wood, and two burn a combination of natural gas and syrup from the 
process. In addition, 20 plants burn coal as their primary fuel and one 
burns a combination of coal and biomass. Our research suggests that 25 
plants currently utilize cogeneration or combined heat and power (CHP) 
technology, although others may exist. CHP is a mechanism for improving 
overall plant efficiency. Whether owned by the ethanol facility, their 
local utility, or a third party, CHP facilities produce their own 
electricity and use the waste heat from power production for process 
steam, reducing the energy intensity of ethanol production.\72\ A 
summary of the energy sources and CHP technology utilized by today's 
ethanol plants is found in Table V.B.1-2.
---------------------------------------------------------------------------

    \69\ For more information on plant energy requirements, refer to 
Section 1.5.1.3 of the DRIA.
    \70\ We are also aware of a couple plants that pull steam 
directly from a nearby utility.
    \71\ Facilities were assumed to burn natural gas if the plant 
boiler fuel was unspecified or unavailable on the public domain.
    \72\ For more on CHP technology, refer to Section 1.4.1.3 of the 
DRIA.

[[Page 24985]]



                 Table V.B.1-2--Current Corn/Starch Ethanol Production Capacity by Energy Source
----------------------------------------------------------------------------------------------------------------
                                                   Capacity    Percent of   Number of    Percent of
   Plant energy source (primary listed first)        MGY        capacity      plants       plants     CHP tech.
----------------------------------------------------------------------------------------------------------------
Coal \a\.......................................        1,868         17.7           20         11.8            9
Coal, Biomass..................................           50          0.5            1          0.6            0
Natural Gas \b\................................        8,294         78.7          142         84.0           15
Natural Gas, Biomass \c\.......................          113          1.1            3          1.8            1
Natural Gas, Landfill Biogas, Wood.............          110          1.0            1          0.6            0
Natural Gas, Syrup.............................          101          1.0            2          1.2            0
                                                ----------------------------------------------------------------
    Total......................................       10,535        100.0          169        100.0           25
----------------------------------------------------------------------------------------------------------------
\a\ Includes four plants that are permitted to burn biomass, tires, petroleum coke, and wood waste in addition
  to coal and one facility that intends to transition to biomas in the future.
\b\ Includes one facility that intends to switch to biomass, one facility that intends to burn thin stillage
  biogas, and two facilities that might switch to coal in the future.
\c\ Includes one facility processing bran in addition to natural gas.

    Since the majority of ethanol is made from corn, it is no surprise 
that most of the plants are located in the Midwest near the Corn Belt. 
Of today's 169 ethanol production facilities, 151 are located in the 15 
states comprising PADD 2. For a map of the Petroleum Administration for 
Defense Districts or PADDs, refer to Figure V.B.1-2.
[GRAPHIC] [TIFF OMITTED] TP26MY09.005

    As a region, PADD 2 accounts for 94% (or almost 10 billion gallons) 
of today's estimated ethanol production capacity, as shown in Table 
V.B.1-3. For more information on today's ethanol plants and a detailed 
map of their locations, refer to Section 1.5 of the DRIA.

                     Table V.B.1-3--Current Corn/Starch Ethanol Production Capacity by PADD
----------------------------------------------------------------------------------------------------------------
                                                                Capacity    Percent of   Number of    Percent of
                            PADD                                  MGY        capacity      plants       plants
----------------------------------------------------------------------------------------------------------------
PADD 1......................................................          150          1.4            3          1.8
PADD 2......................................................        9,900         94.0          151         89.3
PADD 3......................................................          194          1.8            3          1.8
PADD 4......................................................          160          1.5            7          4.1
PADD 5......................................................          131          1.2            5          3.0
                                                             ---------------------------------------------------
    Total...................................................       10,535        100.0          169        100.0
----------------------------------------------------------------------------------------------------------------

    The U.S. ethanol industry is currently comprised of a mixture of 
company-owned plants and locally-owned farmer cooperatives (co-ops). 
The majority of today's ethanol production facilities are company-
owned, and on average these plants are larger in size than farmer-owned 
co-ops. Accordingly, company-owned plants account for more than 79% of 
today's ethanol production capacity.\73\ Furthermore, 30% of the total 
domestic product comes from 38 plants owned by just three different 
companies--POET Biorefining, Archer Daniels Midland (ADM), and Valero 
Renewables.\74\
---------------------------------------------------------------------------

    \73\ Farmer-owned plant status derived from Renewable Fuels 
Association (RFA), Ethanol Biorefinery Locations (updated March 31, 
2009). For more on average plant sizes, refer to Section 1.5.1 of 
the DRIA.
    \74\ Valero recently entered into the renewable fuels business 
by acquiring five idled corn ethanol plants and one construction 
site formerly owned by VeraSun Energy Corporation. Valero has since 
purchased two more idled VeraSun plants, but they have not been 
brought back online yet.

---------------------------------------------------------------------------

[[Page 24986]]

b. Forecasted Production Under RFS2
    As highlighted above, 10.5 billion gallons of corn/starch ethanol 
plant capacity was online as of April 1, 2009. So even if no additional 
capacity was added, U.S. ethanol production would grow from 2008 to 
2009, provided facilities continue to operate at or above today's 
production levels. And despite today's temporary unfavorable market 
conditions (i.e., low ethanol market values), we expect the ethanol 
industry will continue to expand in the future under RFS2. Although 
there is not a set corn ethanol standard, EISA allows for 15 billion 
gallons of the 36-billion gallon renewable fuel standard to be met by 
conventional biofuels. And we expect that corn and other sugar or 
starch-based ethanol will fulfill this requirement. Furthermore, we 
project that all new corn/starch ethanol plant capacity brought online 
under RFS2 would either meet the conventional biofuel GHG threshold 
requirement \75\ or meet the grandfathering requirement (for more 
information, refer to Section 1.5.1.4 of the DRIA).
---------------------------------------------------------------------------

    \75\ The lifecycle assessment values which assume a 2% discount 
rate over a 100-year timeframe.
---------------------------------------------------------------------------

    In addition to the 169 corn/starch ethanol plants that are 
currently online today, 36 plants are presently idled. Some of these 
constructed facilities (namely smaller ethanol plants) have been idled 
for quite some time, whereas other plants have just recently been put 
into ``hot idle'' mode. A number of ethanol producers (e.g., VeraSun) 
are idling operations, putting projects on hold, selling off plants, 
and even filing for Chapter 11 bankruptcy. In addition, we are aware of 
two facilities that are currently operating at 50% or less than their 
nameplate capacity. As crude oil and gasoline prices rise again in the 
future, corn ethanol production will become more viable again and we 
expect that these plants will resume operations. At the time of our 
April 2009 ethanol industry assessment, there were also 19 new ethanol 
plants under construction in the U.S, and two plant expansion projects 
underway. While many of these projects are also on hold due to the 
current economic conditions, we expect these facilities will eventually 
come online under the RFS2 program. A summary of the projected industry 
growth is found in Table V.B.1-4.\76\
---------------------------------------------------------------------------

    \76\ Idled plants and construction projects based on Renewable 
Fuels Association (RFA) Ethanol Biorefinery Locations (updated March 
31, 2009); Ethanol Producer Magazine (EPM) Not Producing and Under 
Construction plant lists (last modified on April 7, 2009), ethanol 
producer Web sites, and follow-up correspondence with ethanol 
producers. It is worth noting that for our industry assessment, 
``under construction'' implies that more than just a ground breaking 
ceremony has taken place.

                             Table V.B.1-4--Potential Industry Expansion Under RFS2
----------------------------------------------------------------------------------------------------------------
                                                           Growth in ethanol production
                                 -------------------------------------------------------------------------------
                                      Plants                            New
                                     currently     Idled plants/   construction      Expansion         Total
                                      online       capacity \a\      projects        projects
----------------------------------------------------------------------------------------------------------------
Plant Capacity (MGY)............          10,535           2,471           1,955              80          15,042
Total No. of Plants.............             169              36              19               2             226
----------------------------------------------------------------------------------------------------------------
\a\ Includes the idled plant capacity of the two facilities that are currently operating at 50% or less than
  nameplate capacity.

    While theoretically it only takes 12 to 18 months to build an 
ethanol plant,\77\ the rate at which new plant capacity comes online 
will be dictated by market conditions, which will in part be influenced 
by the RFS2 requirements. As mentioned above, today's proposed program 
will create a growing demand for corn ethanol reaching 15 billion 
gallons by 2015. However, it is possible that market conditions could 
drive demand even higher. Whether the nation will overcomply with the 
corn ethanol standard is uncertain and will be determined by feedstock 
availability/pricing, crude oil pricing, and the relative ethanol/
gasoline price relationship. To measure the impacts of the proposed 
RFS2 program, we assumed that corn ethanol production would not exceed 
15 billion gallons. We also assumed that all growth would come from new 
plants or plant expansion projects (in addition to idled plants being 
brought back online).\78\ However, it is possible that some of the 
growth could come from minor process improvements (e.g., 
debottlenecking) at existing facilities.
---------------------------------------------------------------------------

    \77\ For more information on plant build rates, refer to Section 
1.2.5 of the RIA.
    \78\ For our NPRM impact analyses, we relied on an earlier May 
2008 industry assessment. For more information, refer to Section 
1.5.1.5 of the DRIA.
---------------------------------------------------------------------------

    Once all the aforementioned projects are complete, we project that 
there would be 226 corn/starch ethanol plants operating in the U.S. 
with a combined production capacity of around 15 billion gallons per 
year. Much like today's ethanol industry, the overwhelming majority of 
new production capacity (93% by volume) is expected to come from corn-
fed plants. Another 7% is forecasted to come from plants processing a 
blend of corn and other grains, and a very small increase is projected 
to come from idled cheese whey and waste beverage plants coming back 
online. A summary of the forecasted ethanol production by feedstock 
under the RFS2 program is found in Table V.B.1-5.

               Table V.B.1-5--Projected RFS2 Corn/Starch Ethanol Production Capacity by Feedstock
----------------------------------------------------------------------------------------------------------------
                                                                Additional production      Total RFS2 estimate
                                                             ---------------------------------------------------
           Plant feedstock (primary listed first)               Capacity    Number of     Capacity    Number of
                                                                  MGY         plants        MGY         plants
----------------------------------------------------------------------------------------------------------------
Corn \a\....................................................        4,197           49       13,802          193
Corn, Milo \b\..............................................          185            3          902           17
Corn, Wheat.................................................            8            1          138            2
Corn, Wheat, Milo...........................................          110            2          110            2
Milo........................................................            0            0            3            1
Wheat, Milo.................................................            0            0           50            1

[[Page 24987]]

 
Cheese Whey.................................................            3            1            8            2
Waste Beverages \c\.........................................            4            1           23            6
Waste Sugars & Starches \d\.................................            0            0            7            2
                                                             ---------------------------------------------------
    Total...................................................        4,507           57       15,042          226
----------------------------------------------------------------------------------------------------------------
\a\ Includes one facility processing seed corn, another facility processing small amounts of whey, two
  facilities also operating pilot-level cellulosic ethanol plants at these locations, and four facilities
  planning on incorporating cellulosic feedstocks in the future.
\b\ Includes one facility processing a small amount of molasses in addition to corn and milo.
\c\ Includes two facilities processing brewery waste.
\d\ Includes one facility processing potato waste that intends to add corn in the future.

    Based on current industry plans, the majority of additional corn/
grain ethanol production capacity (almost 84% by volume) is predicted 
to come from new or expanded plants burning natural gas.\79\ 
Additionally, we are forecasting one new plant and a reopening of 
another plant relying on manure biogas. We are also predicting 
expansions at three coal-fired ethanol plants.\80\ Of the 55 new 
ethanol plants, our research indicates that five would utilize 
cogeneration, bringing the total number of CHP facilities to 30. A 
summary of the projected near-term ethanol plant energy sources is 
found in Table V.B.1-6.
---------------------------------------------------------------------------

    \79\ Facilities were assumed to burn natural gas if the plant 
boiler fuel was unspecified or unavailable on the public domain.
    \80\ Two of the three coal-fired plant expansions appear as new 
plants in Table V.B.1-6. This is because two of the expansion 
projects consist of adding dry milling plant capacity to an existing 
wet mill plant. However, our interpretation is that these facilities 
will rely on the same (potentially expanded) coal-fired boilers for 
process steam. Since all the aforementioned coal-fired ethanol 
production facilities appear to have commenced construction prior to 
December 19, 2007, we project that the ethanol produced at these 
facilities will be grandfathered under the proposed RFS2 rule. For 
more on our grandfathered volume estimate, refer to Section 1.5.1.4 
of the DRIA.

           Table V.B.1-6--Projected Near-Term Corn/Starch Ethanol Production Capacity by Energy Source
----------------------------------------------------------------------------------------------------------------
                                                   Additional production            Total RFS2 estimate
                                                ----------------------------------------------------------------
   Plant energy source (primary listed first)      Capacity    Number of     Capacity    Number of
                                                     MGY         plants        MGY         plants     CHP tech.
----------------------------------------------------------------------------------------------------------------
Coal \a\.......................................          610            2        2,478           22           11
Coal, Biomass..................................            0            0           50            1            0
Manure Biogas..................................          134            2          134            2            0
Natural Gas \b\................................        3,763           53       12,056          195           18
Natural Gas, Biomass \c\.......................            0            0          113            3            1
Natural Gas, Landfill Biogas, Wood.............            0            0          110            1            0
Natural Gas, Syrup.............................            0            0          101            2            0
                                                ----------------------------------------------------------------
    Total......................................        4,507           57       15,042          226           30
----------------------------------------------------------------------------------------------------------------
\a\ Includes six plants that are permitted to burn biomass, tires, petroleum coke, and wood waste in addition to
  coal and one facility that intends to transition to biomass in the future.
\b\ Includes one facility that intends to switch to biomass, one facility that intends to burn thin stillage
  biogas, and six facilities that might switch to coal in the future.
\c\ Includes one facility processing bran in addition to natural gas.

    The information in Table V.B.1.6 is based on short-term industry 
production plans at the time of our April 1, 2009 plant assessment. 
However, we are anticipating growth in advanced ethanol production 
technologies under the proposed RFS2 program. We project that fuel 
prices will drive a large number of corn ethanol plants to transition 
from conventional boiler fuels to advanced biomass-based feedstocks. We 
also believe that fossil fuel/electricity prices will drive a number of 
ethanol producers to pursue CHP technology. For more on our projected 
2022 utilization of these technologies under the RFS2 program, refer to 
Section 1.5.1.3 of the DRIA.
    Under the proposed RFS2 program, the majority of new ethanol 
production is expected to originate from PADD 2, close to where most of 
the corn is grown. However, there are a number of ``destination'' 
ethanol plants being built outside the Midwest in response to 
production subsidies, E10/E85 retail pump incentives, and state 
mandates. A summary of the forecasted ethanol production by PADD under 
the RFS2 program can be found in Table V.B.1-7.

[[Page 24988]]



                  Table V.B.1-7--Projected RFS2 Corn/Starch Ethanol Production Capacity by PADD
----------------------------------------------------------------------------------------------------------------
                                                                Additional production      Total RFS2 Estimate
                                                             ---------------------------------------------------
                            PADD                                Capacity    Number of     Capacity    Number of
                                                                  MGY         plants        MGY         plants
----------------------------------------------------------------------------------------------------------------
PADD 1......................................................          178            3          328            6
PADD 2......................................................        3,566           43       13,466          194
PADD 3......................................................          350            4          544            7
PADD 4......................................................           50            1          210            8
PADD 5......................................................          363            6          494           11
                                                             ---------------------------------------------------
    Total...................................................        4,507           57       15,042          226
----------------------------------------------------------------------------------------------------------------

2. Cellulosic Biofuel
    Ethanol currently dominates U.S. biofuel production, and more 
specifically, ethanol produced from corn and other grains. However, 
cellulosic feedstocks have the potential to greatly expand domestic 
ethanol production, both volumetrically and geographically. It is also 
possible to produce synthetic diesel fuel from cellulosic feedstocks 
(also known as ``cellulosic diesel'') through a Fischer-Tropsch 
gasification process or a thermal depolymerization process. We are also 
aware of one company using live bacteria to break down biomass and 
produce cellulosic diesel and other petroleum replacements. Before 
wide-scale commercialization of cellulosic biofuel can occur in today's 
marketplace, technical and logistical barriers must be overcome. In 
addition to today's RFS2 program which sets aggressive goals for all 
ethanol production, the Department of Energy (DOE) and other federal 
and state agencies are helping to spur industry growth.
a. Current Production/Plans
    The cellulosic biofuel industry is essentially in its infancy. With 
the exception of a 20 million-gallon-per year cellulosic diesel plant 
recently opened by Cello Energy in Bay Minette, AL, the majority of 
facilities in operation today are small pilot- or demonstration-level 
plants. Most of these facilities operate intermittently and produce 
insignificant volumes of biofuel. Some researchers are focusing on 
processing corn residues, e.g., corn stover, cobs, and/or fiber. Some 
are focusing on other agricultural residues such as sugarcane bagasse, 
rice and wheat straw. Others are looking at waste products such as 
forestry residues, citrus residues, pulp or paper mill waste, municipal 
solid waste (MSW), and construction and demolition (C&D) debris. 
Dedicated energy crops including switchgrass and poplar trees are also 
being investigated.
    Based on an April 2009 assessment of information available on the 
public domain, there are currently 25 pilot- and demonstration-level 
(or smaller) cellulosic ethanol plants operating in the United States. 
However, only 9 of these plants report measurable volumes of ethanol 
production. In addition, we are aware of one pilot-level cellulosic 
diesel plant in addition to the commercial-level Cello Energy 
plant.\81\ A summary of these 11 facilities totaling just over 23 
million gallons of annual production capacity is provided in Table 
V.B.2-1. The date listed in the table indicates when the facility first 
began operations. For more on the existing cellulosic ethanol and 
diesel plants, refer to Sections 1.5.3.1 and 1.5.3.3 of the DRIA.
---------------------------------------------------------------------------

    \81\ Our April 2009 cellulosic ethanol industry characterization 
was based on researching DOE- and USDA-supported projects, plants 
referenced in HART's Ethanol & Biodiesel News (through the April 14, 
2009 issue), plants included on the Cellulosic Ethanol Site (http://www.thecesite.com/), and plants referenced on other biofuel industry 
Web sites.

                                Table V.B.2-1--Existing Cellulosic Biofuel Plants
----------------------------------------------------------------------------------------------------------------
                                                                                   Prod     Est.
  Company or organization name             Location              Feedstocks        cap      Op.     Conv. tech.
                                                                                  (MGY)     date        \a\
----------------------------------------------------------------------------------------------------------------
Cellulosic Ethanol
----------------------------------------------------------------------------------------------------------------
Abengoa Bioenergy Corporation     York, NE.................  Wheat straw, corn      0.02   Sep-07  Bio.
 \b\.                                                         stover, energy
                                                              crops.
Bioengineering Resources, Inc.    Fayetteville, AR.........  MSW, wood waste,       0.04     1998  Therm.
 (BRI).                                                       coal.
BPI & Universal Entech..........  Phoenix, AZ..............  Paper waste            0.01     2004  Bio.
                                                              (sorted MSW).
Gulf Coast Energy...............  Livingston, AL...........  Wood waste (sorted     0.20   Dec-08  Therm.
                                                              MSW).
Mascoma Corporation.............  Rome, NY.................  Wood chips........     0.20   Feb-09  Bio.
POET Project Bell \b\...........  Scotland, SD.............  Corn cobs & fiber.     0.02   Jan-09  Bio.
Verenium........................  Jennings, LA.............  Sugarcane bagasse.     0.05     2006  Bio.
Verenium........................  Jennings, LA.............  Sugarcane bagasse,     1.50   Feb-09  Bio.
                                                              wood, energy cane.
Western Biomass Energy LLC.       Upton, WY................  Wood waste             1.50     2007  Bio.
 (WBE).                                                       (softwood).
----------------------------------------------------------------------------------------------------------------
Cellulosic Diesel
----------------------------------------------------------------------------------------------------------------
Cello Energy....................  Bay Minette, AL..........  Wood chips, hay...    20.00   Dec-08  CatDep.
Bell BioEnergy..................  Fort Stewart, GA.........  Wood chips........     0.01   Dec-08  Bact.
----------------------------------------------------------------------------------------------------------------
                              Total Existing Production Capacity 23 MGY
----------------------------------------------------------------------------------------------------------------
\a\ Bio = biochemical pre-treatment, Therm = thermochemical conversion, CatDep = catalytic depolymerization,
  Bact = involves the use of live bacteria to break down biomass for cellulosic diesel production.
\b\ Cellulosic pilot plant is collocated with a corn ethanol plant.


[[Page 24989]]

    To date, the majority of cellulosic ethanol research has focused on 
biochemical pre-treatment technologies, i.e., the use of acids and/or 
enzymes to break down cellulosic materials into fermentable sugars. 
However, there are a growing number of companies investigating the 
thermochemical pathway which involves gasification of biomass into a 
synthesis gas or pyrolysis of biomass into a bio-crude oil for 
processing. Cellulosic diesel can also be made from thermochemical as 
well as other processes. Many companies are also researching the 
potential of co-firing biomass to produce plant energy in addition to 
biofuels. For more on cellulosic biofuel processing technologies, refer 
to Section 1.4.3 of the DRIA.
    In addition to the existing facilities in Table V.B.2-1, our April 
2009 industry assessment suggests that there are currently three 
cellulosic ethanol plants under construction in the United States. Like 
the existing plants, two are pilot-level facilities that are still 
working towards proving their conversion technologies. However, Range 
Fuels, a company that received $76 million from DOE and an $80 loan 
guarantee from USDA to build one of the first commercial-scale 
cellulosic ethanol plants in the U.S., is currently building a 40 
million gallon per year plant in Soperton, GA.\82\ At this time, the 
company is just working on the initial 10 million gallon per year 
phase. Bell Bioenergy, a company that received $7.5 million in funding 
from the Department of Defense to convert biomass into cellulosic 
diesel using live bacteria, also has six pilot plants under 
construction in various locations through the country. A summary of 
these nine cellulosic biofuel plants, totaling over 10 million gallons 
of annual production capacity, is presented in Table V.B.2-2.
---------------------------------------------------------------------------

    \82\ Range Fuels' ultimate goal is to expand the Soperton, GA 
facility to produce 100 million gallons of cellulosic ethanol per 
year.
---------------------------------------------------------------------------

    As shown in Tables V.B.2-1 and V.B.2-2, unlike corn ethanol 
production, which is primarily located in the Midwest near the Corn 
Belt, cellulosic biofuel production is spread throughout the country. 
The geographic distribution of plants is due to the wide variety and 
availability of cellulosic feedstocks. Corn stover is found primarily 
in the Midwest, while the Pacific Northwest, the Northeast, and the 
Southeast all have forestry residues. Some southern states have access 
to sugarcane bagasse and citrus waste while MSW and C&D debris are 
available in highly populated areas throughout the country. For more 
information on cellulosic feedstock availability, refer to Section 
1.1.2 of the DRIA.

                      Table V.B.2-2--Cellulosic Biofuel Plants Currently Under Construction
----------------------------------------------------------------------------------------------------------------
                                                                                   Prod     Est.
       Company plant name                  Location              Feedstocks        cap      op.     Conv. tech.
                                                                                  (MGY)    date.        \a\
----------------------------------------------------------------------------------------------------------------
Cellulosic Ethanol
----------------------------------------------------------------------------------------------------------------
Coskata.........................  Madison, PA..............  MSW, natural gas,      0.04   Jul-09  Therm.
                                                              woodchips,
                                                              bagasse,
                                                              switchgrass.
DuPont Dansico Cellulosic         Vonore, TN...............  Corn cobs then         0.25   Dec-09  Bio.
 Ethanol (DDCE).                                              switchgrass.
Range Fuels \b\.................  Soperton, GA.............  Wood waste,           10.00   Dec-09  Therm.
                                                              switchgrass.
----------------------------------------------------------------------------------------------------------------
Cellulosic Diesel
----------------------------------------------------------------------------------------------------------------
Bell Bio-Energy.................  Fort Lewis, WA...........  Cellulose.........     0.01     2009  Bact.
Bell Bio-Energy.................  Fort Drum, NY............  Cellulose.........     0.01     2009  Bact.
Bell Bio-Energy.................  Fort AP Hill, VA.........  Cellulose.........     0.01     2009  Bact.
Bell Bio-Energy.................  Fort Bragg, NC...........  Cellulose.........     0.01     2009  Bact.
Bell Bio-Energy.................  Fort Benning, GA.........  Cellulose.........     0.01     2009  Bact.
Bell Bio-Energy.................  San Pedro, CA............  Cellulose.........     0.01     2009  Bact.
----------------------------------------------------------------------------------------------------------------
                         Total Under Construction Production Capacity 10 MGY
----------------------------------------------------------------------------------------------------------------
\a\ Bio = biochemical pre-treatment, Therm = thermochemical conversion, Bact = involves the use of live bacteria
  to break down biomass for cellulosic diesel production.
\b\ The first 10 MGY phase is currently under construction in Soperton, GA. Once this second 30 MGY phase is
  added, the plant will be capable of producing 40 MGY of cellulosic ethanol.

    Increased public interest, government support, technological 
advancement, and the recently-enacted EISA have helped spur many plans 
for new cellulosic biofuel plants. Although more and more plants are 
being announced, most are limited in size and contingent upon 
technology breakthroughs and efficiency improvements at the pilot or 
demonstration level. Additionally, because cellulosic biofuel 
production has not yet been proven on the commercial level, financing 
of these projects has primarily been through venture capital and 
similar funding mechanisms, as opposed to conventional bank loans.
    Consequently, recently-announced Federal grant and loan guarantee 
programs may serve as a significant asset to the cellulosic biofuel 
industry in this area. In February 2007, DOE announced that it would 
invest up to $385 million in six commercial-scale ethanol projects over 
the next four years. Since the announcement, two of the companies have 
forfeited their funding. Iogen has decided to locate its first 
commercial-scale plant in Canada and Alico has discontinued plans to 
produce ethanol all together. The four remaining ``pioneer'' plants 
(including Range Fuels) hold promise and could very well be some of the 
first plants to demonstrate the commercial-scale viability of 
cellulosic ethanol production. However, there is still more to be 
learned at the pilot level. Although technologies needed to convert

[[Page 24990]]

cellulosic feedstocks into ethanol (and diesel) are becoming more and 
more understood, there are still a number of efficiency improvements 
that need to occur before cellulosic biofuels can compete in today's 
marketplace.
    In May 2007, DOE announced that it would provide up to $200 million 
to help fund small-scale cellulosic biorefineries experimenting with 
novel processing technologies that could later be expanded to 
commercial production facilities. Four recipients were announced in 
January 2008 and three more were announced in April 2008. Three months 
later, DOE announced that it would provide $40 million more to help 
fund two additional small-scale plants. Of the nine announced small-
scale plants, seven were pursuing cellulosic ethanol production 
(including Verenium Corp.) and two are pursuing cellulosic diesel 
production. However, Lignol Innovations, recently suspended plans to 
build a 2.5 million gallon per year cellulosic ethanol plant in Grand 
Junction, CO due to market uncertainty.
    The Department of Energy has also introduced a loan guarantee 
program to help reduce risk and spur investment in projects that employ 
new, clean energy technologies. In October 2007, DOE issued final 
regulations and invited 16 project sponsors who submitted pre-
applications to submit full applications for loan guarantees. Of those 
who were invited to participate, five were pursuing cellulosic biofuel 
production. However, only three companies appear to still be 
eligible.\83\ Of the three remaining companies, two are pursuing 
cellulosic ethanol production (and are also DOE grant recipients) and 
one is pursuing cellulosic diesel production. The U.S. Department of 
Agriculture is also providing an $80 million loan guarantee to Range 
Fuels to help support construction of its 40 million-gallon-per-year 
cellulosic ethanol plant in Soperton, GA. For more on information on 
Federal support for biofuel production, refer to Section 1.5.3 of the 
DRIA.
---------------------------------------------------------------------------

    \83\ Iogen and Alico have also forfeited a potential loan 
guarantee from DOE.
---------------------------------------------------------------------------

    In addition to the companies receiving government funding, there 
are a growing number of privately-funded companies (including Cello 
Energy) with plans to build more cellulosic biofuel plants in the 
United States. These facilities range in size from pilot- and 
demonstration-level plants (similar to those currently operational or 
under construction), to small commercial plants (similar to the four 
commercial-scale plants receiving DOE funding), to large commercial 
plants (similar in size to an average corn ethanol plant). These 
projects are also at various stages of planning. According to our April 
2009 industry assessment, 11 plants are currently at advanced stages of 
planning and likely to go online in the near future. Along with those 
plants currently operational or under construction, we believe that 
these facilities will enable the U.S. to meet the 100 million gallon 
cellulosic biofuel standard in 2010. For a summary of the plants and 
their respective projected contributions, refer to Table V.B.2-3 below. 
For a greater discussion on these and other cellulosic biofuel 
projects, refer to Section 1.5.3.1 of the DRIA.

                         Table V.B.2-3--Projected Cellulosic Biofuel Production in 2010
----------------------------------------------------------------------------------------------------------------
                                                                                                        Est 2010
                                                                                            Est. 2010    ETOH-
   Company or organization name            Location         Prod cap      Est. op. date      million     equiv.
                                                             (MGY)                           gallons    million
                                                                                                        gallons
----------------------------------------------------------------------------------------------------------------
Cellulosic Ethanol
----------------------------------------------------------------------------------------------------------------
BPI & Universal Entech............  Phoenix, AZ..........       0.01  Online..............       0.01       0.01
POET Project Bell.................  Scotland, SD.........       0.02  Online..............       0.02       0.02
Abengoa Bioenergy Corporation.....  York, NE.............       0.02  Online..............       0.02       0.02
Bioengineering Resources, Inc.      Fayetteville, AK.....       0.04  Online..............       0.04       0.04
 (BRI).
Verenium..........................  Jennings, LA.........       0.05  Online..............       0.05       0.05
Gulf Coast Energy.................  Livingston, AL.......       0.20  Online..............       0.20       0.20
Mascoma Corporation...............  Rome, NY.............       0.20  Online..............       0.20       0.20
Verenium..........................  Jennings, LA.........       1.50  Online..............       1.50       1.50
Western Biomass Energy, LLC. (WBE)  Upton, WY............       1.50  Online..............       1.50       1.50
Coskata...........................  Madison, PA..........       0.04  Jul-09..............       0.04       0.04
DuPont Dansico Cellulosic Ethanol   Vonore, TN...........       0.25  Dec-09..............       0.25       0.25
 (DDCE).
Range Fuels.......................  Soperton, GA.........       10.0  Dec-09..............       10.0       10.0
Ecofin/Alltech....................  Springfield, KY......       1.30  2010................       0.65       0.65
Fulcrum Bioenergy.................  Storey County, NV....      10.50  2010................       5.25       5.25
ICM Inc...........................  St. Joseph, MO.......       1.50  2010................       0.75       0.75
RSE Pulp & Chemical...............  Old Town, ME.........       2.20  2010................       1.10       1.10
ZeaChem...........................  Boardman, OR.........       1.50  2010................       0.75       0.75
ClearFuels Technology.............  Kauai, HI............       1.50  End of 2010.........       0.38       0.38
Southeast Renewable Fuels LLC.....  Clewiston, FL........      20.00  End of 2010.........       5.00       5.00
----------------------------------------------------------------------------------------------------------------
Cellulosic Diesel
----------------------------------------------------------------------------------------------------------------
Cello Energy......................  Bay Minette, AL......      20.00  Online..............      20.00      32.00
Bell Bio-Energy...................  Fort Stewart, GA.....       0.01  2008................       0.01       0.01
Bell Bio-Energy...................  Fort Lewis, WA.......       0.01  2009................       0.01       0.01
Bell Bio-Energy...................  Fort Drum, NY........       0.01  2009................       0.01       0.01
Bell Bio-Energy...................  Fort AP Hill, VA.....       0.01  2009................       0.01       0.01
Bell Bio-Energy...................  Fort Bragg, NC.......       0.01  2009................       0.01       0.01
Bell Bio-Energy...................  Fort Benning, GA.....       0.01  2009................       0.01       0.01
Bell Bio-Energy...................  San Pedro, CA........       0.01  2009................       0.01       0.01

[[Page 24991]]

 
Cello Energy......................  TBD (AL).............      50.00  2010................      16.67      26.67
Cello Energy......................  TBD (AL).............      50.00  2010................      16.67      26.67
Cello Energy......................  TBD (GA).............      50.00  2010................      16.67      26.67
Flambeau River Biofuels...........  Park Falls, WI.......       6.00  2010................       3.00       4.80
                                   -----------------------------------------------------------------------------
    Total 2010 Production Forecast  .....................  .........  ....................     100.74     144.57
----------------------------------------------------------------------------------------------------------------

b. Federal/State Production Incentives
    In addition to helping fund a series of small-scale cellulosic 
biofuel plants, the Department of Energy, along with the U.S. 
Department of Agriculture (USDA), is also helping to fund critical 
research to help make cellulosic biofuel production more commercially 
viable. In March 2007, DOE awarded $23 million in grants to four 
companies and one university to develop more efficient microbes for 
ethanol refining. In June 2007, DOE and USDA awarded $8.3 million to 10 
universities, laboratories, and research centers to conduct genomics 
research on woody plant tissue for bioenergy. Later that same month, 
DOE announced plans to spend $375 million to build three bioenergy 
research centers dedicated to accelerating research and development of 
cellulosic ethanol and other biofuels. The centers, which will each 
focus on different feedstocks and biological research challenges, will 
be located in Oak Ridge, TN, Madison, WI, and Berkeley, CA. In December 
2007, DOE awarded $7.7 million to one company, one university, and two 
research centers to demonstrate the thermochemical conversion process 
of turning grasses, stover, and other cellulosic materials into 
biofuel. In February 2008, DOE awarded another $33.8 million to three 
companies and one research center to support the development of 
commercially-viable enzymes to support cellulose hydrolysis, a critical 
step in the biochemical breakdown of cellulosic feedstocks. Finally, in 
March 2008, DOE and USDA awarded $18 million to 18 universities and 
research institutes to conduct research and development of biomass-
based products, biofuels, bioenergy, and related processes. Since 2007, 
DOE has announced more than $1 billion and since 2006, USDA has 
invested almost $600 million for the research, development, and 
demonstration of new biofuel technology.
    Numerous states are also offering grants, tax incentives, and loan 
guarantees to help encourage biofuel production. The majority of 
efforts are centered on expanding ethanol production, and more 
recently, cellulosic ethanol production.\84\ According to a July 2008 
assessment of DOE's Energy Efficiency and Renewable Energy (EERE) Web 
site,\85\ 33 states currently offer some form of ethanol production 
incentive. The incentives range from support for ethanol producers to 
support for research and development companies to support for feedstock 
suppliers. Kansas, Maryland, and South Carolina each offer specific 
incentives towards cellulosic ethanol production. Kansas offers revenue 
bonds through the Kansas Development Finance Authority to help fund 
construction or expansion of a cellulosic ethanol plant. Additionally, 
these newly-built or expanded facilities are exempt from state property 
tax for 10 years. Maryland offers a credit towards state income tax for 
10% of cellulosic ethanol research and development expenses. They also 
have a $0.20 per gallon production credit for cellulosic ethanol. South 
Carolina gives a $0.30 per gallon production credit to cellulosic 
ethanol producers that meet certain requirements.
---------------------------------------------------------------------------

    \84\ For more on state-level biodiesel production incentives, 
refer to Section 1.5.4 of the DRIA.
    \85\ The database of ethanol incentives and laws by state is 
available at: http://www.eere.energy.gov/afdc/ethanol/incentives_laws.html.
---------------------------------------------------------------------------

    In addition to individual state incentives, a group of states in 
the Midwest have joined together to pursue ethanol and other biofuel 
production and usage goals as part of the Midwest Energy Security and 
Climate Stewardship Platform.\86\ As of June 2008, Indiana, Iowa, 
Kansas, Michigan, Minnesota, North Dakota, Ohio, South Dakota, and 
Wisconsin had all committed to these goals which emphasize energy 
independence through the growth of cellulosic ethanol production and 
availability of E85. The Platform goals are to produce cellulosic 
ethanol on a commercial level by 2012 and to have E85 offered at one-
third of refueling stations by 2025. They also want to reduce the 
energy intensity of ethanol production and supply 50% of their 
transportation fuel needs by regionally produced biofuels by 2025.
---------------------------------------------------------------------------

    \86\ Midwest Governors Association, ``Energy Security and 
Climate Stewardship Platform for the Midwest 2007'' (http://www.midwesterngovernors.org/resolutions/Platform.pdf)
---------------------------------------------------------------------------

    Finally, the passage of the Food, Conservation, and Energy Act of 
2008 (also known as the ``2008 Farm Bill'') is also helping to spur 
cellulosic ethanol production and use.\87\ The 2008 Farm Bill modified 
the existing $0.51 per gallon alcohol blender credit to give preference 
to ethanol and other biofuels produced from cellulosic feedstocks. Corn 
ethanol now receives a reduced credit of $0.45/gal while cellulosic 
biofuel earns a credit of $1.01/gal.\88\ The 2008 Farm Bill also has 
provisions that enable USDA to assist with the commercialization of 
second-generation biofuels. Section 9003 authorizes loan guarantees for 
the development, construction and retrofitting of commercial scale 
biorefineries. Section 9004 provides payments to biorefineries to 
replace fossil fuels with renewable biomass. Section 9005 provides 
payments to producers to support and ensure production of advanced 
biofuels. And finally, Section 9008 provides competitive grants, 
contracts and financial assistance to enable eligible entities to carry 
out research, development, and demonstration of biofuels and biomass-
based based products. For more information on the Federal and state 
production incentives outlined in this subsection, refer to Section 
1.5.3.2 of the DRIA.
---------------------------------------------------------------------------

    \87\ The Food, Conservation, and Energy Act of 2008 (http://www.usda.gov/documents/Bill_6124.pdf)
    \88\ Refer to Part II, Subparts A and B (Sections 15321 and 
15331).
---------------------------------------------------------------------------

c. Feedstock Availability
    A wide variety of feedstocks can be used for cellulosic ethanol 
production, including: Agricultural residues,

[[Page 24992]]

forestry biomass, municipal solid waste, construction and demolition 
waste, and energy crops. These feedstocks are much more difficult to 
convert into ethanol than traditional starch/corn crops or at least 
require new and different processes because of the more complex 
structure of cellulosic material.
    One potential barrier to commercially viable cellulosic biofuel 
production is high feedstock cost. As such, fuel producers will seek to 
acquire inexpensive feedstocks in sufficient quantities to lower their 
production costs and the risk of feedstock supply shortages. At least 
initially, the focus will be on feedstocks that are readily available, 
already produced or collected for other reasons, and even waste biomass 
which currently incurs a disposal fee. Consequently, initial volumes of 
cellulosic biofuels may benefit from low-cost feedstocks. However, to 
reach 16 Bgal will likely require reliance on more expensive feedstock 
sources purposely grown and or harvested for conversion into cellulosic 
biofuel.
    To determine the likely cellulosic feedstocks for production of 16 
billion gallons cellulosic biofuel by 2022, we analyzed the data and 
results from various sources. Sources include agricultural modeling 
from the Forestry Agriculture Sector Optimization Model (FASOM) to 
establish the most economical agriculture residues and energy crops 
(see Section IX for more details on the FASOM), consultation with USDA-
Forestry Sector experts for forestry biomass supply curves, and 
feedstock assessment estimates for urban waste.\89\
---------------------------------------------------------------------------

    \89\ It is important to note that our plant siting analysis for 
cellulosic ethanol facilities used the most current version of 
outputs from FASOM at the time, which was from April 2008. Since 
then, FASOM has been updated to reflect better assumptions. 
Therefore, the version used for the NPRM in Section IX on economic 
impacts is slightly different than the one we used here. We do not 
believe that the differences between the two versions are enough to 
have a major impact on the plant siting analysis.
---------------------------------------------------------------------------

    An important assumption in our analysis projecting which feedstocks 
will be used for producing cellulosic ethanol is that an excess of 
feedstock would have to be available for producing the biofuel. Banks 
are anticipated to require excess feedstock supply as a safety factor 
to ensure that the plant will have adequate feedstock available for the 
plant, despite any feedstock emergency, such as a fire, drought, 
infestation of pests etc. For our analysis we assumed that twice the 
feedstock of MSW, C&D waste, and forest residue would have to be 
available to justify the building of a cellulosic ethanol plant. For 
corn stover, we assumed 50% more feedstock than necessary. We used a 
lower safety factor for corn stover because it could be possible to 
remove a larger percentage of the corn stover in any given year 
(usually only 50% or less of corn stover is assumed to be sustainably 
removed in any one year).\90\ As a result, our projected cellulosic 
facilities only consume a portion of the total supply of feedstock 
available. After a cellulosic facility is fully established and certain 
risks are reduced, it is entirely possible that the facility may choose 
to consume excess feedstock in order to expand production. In addition, 
more facilities could potentially be built if financial investors 
required less excess supply. Since we are assessing the impact of 
producing 16 Bgal of cellulosic biofuel by 2022, this analysis does not 
project the construction of more facilities or more feedstocks consumed 
than necessary.
---------------------------------------------------------------------------

    \90\ The FASOM results do not take into consideration these 
feedstock safety margins. Safety margins were used, however, for the 
plant siting analysis described in Section V.B.2.c.v.
---------------------------------------------------------------------------

    Another assumption that we made is that if multiple feedstocks are 
available in an area, each would be used as feedstocks for a 
prospective cellulosic ethanol plant. For example, a particular area 
might comprise a small or medium sized city, some forest and some 
agricultural land. We would include the MSW and C&D wastes available 
from the city along with the corn stover and forest residue for 
projecting the feedstock that would be processed by the particular 
cellulosic ethanol plant.
    The following subsections describe the availability of various 
cellulosic feedstocks and the estimated amounts from each feedstock 
needed to meet the EISA requirement of 16 Bgal of cellulosic biofuel by 
2022. Refer to Section V.B.2.c.iv for the summarized results of the 
types and volumes of cellulosic feedstocks chosen based on our 
analyses.
i Urban Waste
    Cellulosic feedstocks available at the lowest cost to the ethanol 
producer will likely be chosen first. This suggests that urban waste 
which is already being gathered today and which incurs a fee for its 
disposal may be among the first to be used. Urban wood wastes are used 
in a variety of ways. Most commonly, wastes are ground into mulch, 
dumped into land-fills, or incinerated with other municipal solid waste 
(MSW) or construction and demolition (C&D) debris. Urban wood wastes 
include a variety of wood resources such as wood-based municipal solid 
waste and wood debris from construction and demolition.
    MSW consists of paper, glass, metals, plastics, wood, yard 
trimmings, food scraps, rubber, leather, textiles, etc. The portion of 
MSW containing cellulosic material and typically the focus for biofuel 
production is wood and yard trimmings. In addition, paper, which made 
up approximately 34% of the total MSW generated in 2006, could 
potentially be converted to cellulosic biofuel.\91\ Food scraps could 
also be converted to cellulosic biofuel, however, it was noted by an 
industry group that this feedstock could be more difficult to convert 
to biofuel due to challenges with separation, storage, transport, and 
degradation of the materials. Although recycling/recovery rates are 
increasing over time, there appears to still be a large fraction of 
biogenic material that ends up unused and in land-fills. C&D debris is 
typically not available in wood waste assessments, although some have 
estimated this feedstock based on population. In 1996, this was 
estimated to be approximately 124 million metric tons of C&D 
debris.\92\ Only a portion of this, however, would be made of woody 
material. Utilization of such feedstocks could help generate energy or 
biofuels for transportation. However, despite various assessments on 
urban waste resources, there is still a general lack of reliable data 
on delivered prices, issues of quality (potential for contamination), 
and lack of understanding of potential competition with other 
alternative uses (e.g. recycling, burning for electricity).
---------------------------------------------------------------------------

    \91\ EPA. Municipal Solid Waste Generation, Recycling, and 
Disposal in the United States: Facts and Figures for 2006.
    \92\ Fehrs, J., ``Secondary Mill Residues and Urban Wood Waste 
Quantities in the United States--Final Report,'' Northeast Regional 
Biomass Program Washington, DC, December 1999.
---------------------------------------------------------------------------

    We estimated that 42 million dry tons of MSW (wood and yard 
trimmings & paper) and C&D wood waste could be available for producing 
biofuels after factoring in several assumptions (e.g. percent 
contamination, percent recovered or combusted for other uses, and 
percent moisture).93 94 We assumed that approximately 25 
million dry tons (of the total 42 million dry tons) would be used. 
However, many areas of the U.S. (e.g. much of the Rocky Mountain 
States) have such sparse resources that a MSW and C&D cellulosic 
facility would not likely be justifiable. We did assume that in areas 
with other

[[Page 24993]]

cellulosic feedstocks (forest and agricultural residue), that the MSW 
would be used even if the MSW could not justify the installation of a 
plant on its own. Therefore, we have estimated that urban waste could 
help contribute to the production of approximately 2.2 billion gallons 
of ethanol.\95\ A more detailed discussion on this analysis is included 
in the DRIA Chapter 1. Subsequent to initiating our analysis, however, 
we realized that the revised renewable biomass definition in the 
statute may preclude the use of most MSW. See Section III.B.4 for a 
discussion of renewable biomass. When the definition of renewable 
biomass is finalized, it could preclude the use of some of the lowest 
cost potential feedstocks, including waste paper and C&D waste, for use 
in producing cellulosic biofuel for use toward the RFS2 standard. If 
this is the case, then our FRM analysis will be adjusted to reflect 
this.
---------------------------------------------------------------------------

    \93\ Wiltsee, G., ``Urban Wood Waste Resource Assessment,'' 
NREL/SR-570-25918, National Renewable Energy Laboratory, November 
1998.
    \94\ Biocycle, ``The State of Garbage in America,'' Vol. 47, No. 
4, 2006, p. 26.
    \95\ Assuming 90 gal/dry ton ethanol conversion yield for urban 
waste in 2022.
---------------------------------------------------------------------------

    In addition to MSW and C&D waste generated from normal day-to-day 
activities, there is also potential for renewable biomass to be 
generated from natural disasters. This includes diseased trees, other 
woody debris, and C&D debris. For instance, Hurricane Katrina was 
estimated to have damaged approximately 320 million large trees.\96\ 
Katrina also generated over 100 million tons of residential debris, not 
including the commercial sector. The material generated from these 
situations could potentially be used to generate cellulosic biofuel. 
While we acknowledge this material could provide a large source in the 
short-term, natural disasters are highly variable, making it hard to 
predict future volumes that could be generated. We seek comment on how 
to take into account such estimates to be included in future feedstock 
availability analyses.
---------------------------------------------------------------------------

    \96\ Chambers, J., ``Hurricane Katrina's Carbon Footprint on 
U.S. Gulf Coast Forests'' Science Vol. 318, 2007.
---------------------------------------------------------------------------

ii. Agricultural and Forestry Residues
    The next category of feedstocks chosen will likely be those that 
are readily produced but have not yet been commercially collected. This 
includes both agricultural and forestry residues.
    Agricultural residues are expected to play an important role early 
on in the development of the cellulosic ethanol industry due to the 
fact that they are already being grown. Agricultural crop residues are 
biomass that remains in the field after the harvest of agricultural 
crops. The most common residue types include corn stover (the stalks, 
leaves, and/or cobs), straw from wheat, rice, barley, or oats, and 
bagasse from sugarcane. The eight leading U.S. crops produce more than 
500 million tons of residues each year, although only a fraction can be 
used for fuel and/or energy production due to sustainability and 
conservation constraints.\97\ Crop residues can be found all over the 
United States, but are primarily concentrated in the Midwest since corn 
stover accounts for half of all available agricultural residues.
---------------------------------------------------------------------------

    \97\ Elbehri, Aziz. USDA, ERS. ``An Evaluation of the Economics 
of Biomass Feedstocks: A Synthesis of the Literature. Prepared for 
the Biomass Research and Development Board,'' 2007; Since 2007, a 
final report has been released. Biomass Research and Development 
Board, ``The Economics of Biomass Feedstocks in the United States: A 
Review of the Literature,'' October 2008.
---------------------------------------------------------------------------

    Agricultural residues play an important role in maintaining and 
improving soil quality, protecting the soil surface from water and wind 
erosion, helping to maintain nutrient levels, and protecting water 
quality. Thus, collection and removal of agricultural residues must 
take into account concerns about the potential for increased erosion, 
reduced crop productivity, depletion of soil carbon and nutrients, and 
water pollution. Sustainable removal rates for agricultural residues 
have been estimated in various studies, many showing tremendous 
variability due to local differences in soil and erosion conditions, 
soil type, landscape (slope), tillage practices, crop rotation 
managements, and the use of cover crops. One of the most recent studies 
by top experts in the field showed that under current rotation and 
tillage practices, about 30% of stover (about 59 million metric tons) 
produced in the U.S. could be collected, taking into consideration 
erosion, soil moisture concerns, and nutrient replacement costs.\98\ 
The same study showed that if farmers chose to convert to no-till corn 
management and total stover production did not change, then 
approximately 50% of stover (100 million metric tons) could be 
collected without causing erosion to exceed the tolerable soil loss. 
This study, however, did not consider possible soil carbon loss which 
other studies indicate may be a greater constraint to environmentally 
sustainable feedstock harvest than that needed to control water and 
wind erosion.\99\ Experts agree that additional studies are needed to 
further evaluate how soil carbon and other factors affect sustainable 
removal rates. Despite unclear guidelines for sustainable removal rates 
due to the uncertainties explained above, our agricultural modeling 
analysis assumes that 0% of stover is removable for conventional tilled 
lands, 35% of stover is removable for conservation tilled lands, and 
50% is removable for no-till lands. In general, these removal 
guidelines are appropriate only for the Midwest, where the majority of 
corn is currently grown.
---------------------------------------------------------------------------

    \98\ Graham, R.L., ``Current and Potential U.S. Corn Stover 
Supplies,'' American Society of Agronomy 99:1-11, 2007.
    \99\ Wilhelm, W.W. et. al., ``Corn Stover to Sustain Soil 
Organic Carbon Further Constrains Biomass Supply,'' Agron. J. 
99:1665-1667, 2007.
---------------------------------------------------------------------------

    As already noted, removal rates will vary within regions due to 
local differences. Given the current understanding of sustainable 
removal rates, we believe that such assumptions are reasonably 
justified. We invite comment on these assumptions. Based on our 
research we also note that residue maintenance requirements for the 
amount of biomass that must remain on the land to ensure soil quality 
is another approach for modeling sustainable residue collection 
quantities, therefore we also invite comment on this approach. This 
approach would likely be more accurate for all landscapes as site 
specific conditions such as soil type, topography, etc. could be taken 
into account. This would prevent site specific soil erosion and soil 
quality concerns that would inevitably exist when using average values 
for residue removal rates across all soils and landscapes. At the time 
of our analyses we had limited data on which to accurately apply this 
approach and therefore assumed the removal guidelines based on tillage 
practices. Refer to the Section 1.1 of the DRIA for more discussion on 
sustainable removal rates.
    Some of the challenges of relying on agricultural residues to 
produce biofuels include the development of the technology and 
infrastructure for the harvesting of biomass crops. For example, it may 
be possible to reduce costs by harvesting the corn stover at the same 
time that the corn is harvested, in a single pass operation, as opposed 
to two separate harvests. In addition, because agricultural residues 
are usually harvested only one time per year, but cellulosic ethanol 
plants must receive the feedstock throughout the year, agricultural 
residues would likely need to be stored at a secondary storage 
facility. The transportation and storage issues and costs associated 
with this secondary storage will add additional costs to using 
agricultural residue as cellulosic plant feedstock. These significant 
transportation and storage issues need to be resolved and the 
infrastructure built before agricultural

[[Page 24994]]

residues can supply a steady stream of feedstock to the biorefinery. We 
discuss these harvesting and storage challenges in Section 1.3 of the 
DRIA.
    Our agricultural modeling (FASOM) suggests that corn stover will 
make up the majority of agricultural residues used by 2022 to meet the 
EISA cellulosic biofuel standard (approximately 83 million dry tons 
used to produce 7.8 billion gallons of cellulosic ethanol).\100\ 
Smaller contributions are expected to come from other crop residues, 
including bagasse (1.2 Bgal ethanol) and sweet sorghum pulp (0.1 Bgal 
ethanol).\101\ At the time of this proposal, FASOM was able to model 
agricultural residues but not forestry biomass as potential feedstocks. 
As a result, we relied on USDA-Forest Service (FS) for information on 
the forestry sector.
---------------------------------------------------------------------------

    \100\ Assuming 94 gal/dry ton ethanol conversion yield for corn 
stover in 2022.
    \101\ Bagasse is a byproduct of sugarcane crushing and not 
technically an agricultural residue. Sweet sorghum pulp is also a 
byproduct of sweet sorghum processing. We have included it under 
this heading for simplification due to sugarcane being an 
agricultural feedstock.
---------------------------------------------------------------------------

    The U.S. has vast amounts of forest resources that could 
potentially provide feedstock for the production of cellulosic biofuel. 
One of the major sources of woody biomass could come from logging 
residues. The U.S. timber industry harvests over 235 million dry tons 
annually and produces large volumes of non-merchantable wood and 
residues during the process.\102\ Logging residues are produced in 
conventional harvest operations, forest management activities, and 
clearing operations. In 2004, these operations generated approximately 
67 million dry tons/year of forest residues that were left uncollected 
at harvest sites.\103\ Other feedstocks include those from other 
removal residues, thinnings from timberland, and primary mill residues.
---------------------------------------------------------------------------

    \102\ Smith, W. Brad et. al., ``Forest Resources of the United 
States, 2002 General Technical Report NC-241,'' St. Paul, MN: U.S. 
Dept. of Agriculture, Forest Service, North Central Research 
Station, 2004.
    \103\ USDA-Forest Service. ``Timber Products Output Mapmaker 
Version 1.0.'' 2004.
---------------------------------------------------------------------------

    Harvesting of forestry residue and other woody material can be 
conducted throughout the year. Thus, unlike agricultural residue which 
must be moved to secondary storage, forest material could be ``stored 
on the stump.'' Avoiding the need for secondary storage and the 
transportation costs for moving the feedstock there potentially 
provides a significant cost advantage for forest residue over 
agricultural residue. This could allow forest residue to be transported 
from further distances away from the cellulosic plant compared to 
agricultural residue at the same feedstock price. Section 1.1 of the 
DRIA further details some of challenges with using forestry biomass as 
a feedstock.
    EISA does not allow forestry material from national forests and 
virgin forests that could be used to produce biofuels to count towards 
the renewable fuels requirement under EISA. Therefore, we required 
forestry residue estimates that excluded such material. Most recently, 
the USDA-FS provided forestry biomass supply curves for various sources 
(i.e., logging residues, other removal residues, thinnings from 
timberland, etc.). This information suggested that a total of 76 
million dry tons of forest material could be available for producing 
biofuels (excluding forest biomass material contained in national 
forests as required under EISA). However, much of the forest material 
is in small pockets of forest which because of its regional low 
density, could not help to justify the establishment of a cellulosic 
ethanol plant. After conducting our feedstock availability analysis, we 
estimated that approximately 44 million dry tons of forest material 
could be used, which would make up approximately one fourth, or 3.8 
billion gallons, of the 16 billion gallons of cellulosic biofuel 
required to meet EISA.
iii Dedicated Energy Crops
    While urban waste, agricultural residues, and forest residues will 
likely be the first feedstocks used in the production of cellulosic 
biofuel, there may be limitations to their use due to land availability 
and sustainable removal rates. Energy crops which are not yet grown 
commercially but have the potential for high yields and a series of 
environmental benefits could help provide additional feedstocks in the 
future. Dedicated energy crops are plant species grown specifically as 
renewable fuel feedstocks. Various perennial plants have been 
researched as potential dedicated feedstocks. These include 
switchgrass, mixed prairie grasses, hybrid poplar, miscanthus, and 
willow trees.
    Perennials have several benefits over many major agricultural crops 
(the majority of which are annual plants). First, energy crops based on 
perennial species are grown from roots or rhizomes that remain in the 
soil after harvests. This reduces annual field preparation and 
fertilization costs. Second, perennial crops in temperate zones may 
also have significantly higher total biomass yield per unit of land 
area compared to annual species because of higher rates of net 
photosynthetic CO2 fixation into sugars. Third, lower 
fertilizer runoff, lower soil erosion, and increased habitat diversity 
are also attributes that make perennial crops more attractive than 
annual crops.\104\ Finally, energy crops tend to store more carbon in 
the soil compared to agricultural crops such as corn.\105\
---------------------------------------------------------------------------

    \104\ DOE., ``Breaking the Biological Barriers to Cellulosic 
Ethanol: A Joint Research Agenda,'' 2006.
    \105\ Tolbert, V.R., et al., ``Biomass Crop Production: Benefits 
for Soil Quality and Carbon Sequestration,'' March 1999.
---------------------------------------------------------------------------

    The introduction of dedicated energy crops could present some 
potential risks, however. Dedicated energy crops for cellulosic 
biofuels can be non-native to the region where their production is 
proposed.\106\ As a result, these species may potentially escape 
cultivation and damage surrounding ecosystems.\107\ In addition 
breeding and genetic engineering to increase environmental tolerance, 
increase harvestable biomass production, and enhance energy conversion 
may have unexpected ecological consequences. To minimize such risks, 
non-native species and non-wild-type native species (i.e. native 
species after genetic modification) should be introduced in a 
responsible manner and evaluated carefully in order to weigh the 
potential risks against the benefits.
---------------------------------------------------------------------------

    \106\ Lewandowski, I., J. M. O. Scurlock, E. Lindvall, and M. 
Chistou, ``The development and current status of perennial 
rhizomatous grasses as energy crops in the U.S. and Europe,'' 
Biomass Bioenergy 25:335-361, 2003.
    \107\ The Council for Agricultural Science and Technology 
(CAST), ``Biofuel Feedstocks: The Risk of Future Invasions,'' CAST 
Commentary QTA2007-1. November 2007. Accessed at: http://pdf.cast-science.org/websiteUploads/publicationPDFs/Biofuels%20Commentary%20Web%20version%20with%20color%20%207927146.pdf

---------------------------------------------------------------------------

    Currently, an energy crop receiving much attention is switchgrass. 
Switchgrass has many qualities that make it a prime cellulosic 
feedstock option. However, switchgrass and other energy crops are not 
currently harvested on a large scale. Switchgrass would likely be grown 
on a 10-year crop rotation basis, with harvest beginning in year 1 or 
2, depending on location. Because switchgrass and other dedicated 
energy crops would not be harvested annually, there will be some 
economic challenges in terms of price forecasting and contracts. 
Accordingly, 10- to 15-year arrangements may be needed to stabilize the 
market for energy crops.\108\ Despite these challenges, dedicated 
energy crops are still projected to be needed in 2022 in order to meet 
the aggressive goal of 16 Bgal of

[[Page 24995]]

cellulosic biofuel by 2022 as outlined in EISA.
---------------------------------------------------------------------------

    \108\ Zeman, N., ``Feedstock: Potential Players,'' Ethanol 
Producer Magazine, October 2006.
---------------------------------------------------------------------------

    Since energy crops are not being grown today to make fuels, their 
production and use depends on the development of a successful strategy. 
One issue is that if they were to be grown on farmland currently used 
to grow crops, the growth of switchgrass would have an opportunity cost 
associated with the loss of agricultural production. For this reason, 
energy crops may instead be grown on more marginal farm land such as 
fallow farmland and farmland which has been converted over to prairie 
grass. A study by Stanford and the Carnegie Institution found that 58 
million hectares (145 million acres) of abandoned farmland would 
potentially be available for growing energy crops here in the U.S.\109\ 
However, they also concluded that this land is marginal in quality and 
thus the production per acre would be much lower compared to prime farm 
land. Additionally, a substantial amount of this abandoned farm land is 
a part of the Conservation Reserve Program (CRP). The CRP is the U.S. 
Department of Agriculture's voluntary program that was established by 
the Food Security Act of 1985 to provide farmers with a dependable 
source of income, reduce erosion on unused farmland, and serve to 
preserve wildlife and water quality.\110\ A large portion of the 36 
million acres in the CRP land is currently planted with switchgrass and 
mixed prairie grasses.\111\ However, the 2008 Farm Bill capped the 
number of CRP acres at 32 million acres for 2010-2012, and we expect 
that some of the CRP acres that are not re-enrolled will go into crop 
production. While it may be possible to use some of the CRP acres to 
produce biofuels from switchgrass and prairie grass, the potential loss 
of the wildlife habitat and water quality benefits of CRP land would 
have to be weighed against the potential use for this land for growing 
energy crops. Also, a significant portion of the CRP land is wetlands 
and likely could not be used for growing energy crops without impacting 
water quality and wildlife.
---------------------------------------------------------------------------

    \109\ Campbell, J.E. at al., ``The global potential of bioenergy 
on abandoned agriculture lands,'' Environ. Sci. Technology, 2008.
    \110\ Charles, Dan; ``The CRP: Paying Farmers not to Farm,'' 
National Public Radio, May 5, 2008.
    \111\ Farm Service Agency, ``Conservation Reserve Program, 
Summary and Enrollment Statistics FY2006,'' May 2007.
---------------------------------------------------------------------------

    In addition to estimating the extent that agricultural residues 
might contribute to cellulosic ethanol production, FASOM also estimated 
the contribution that energy crops might provide.\112\ FASOM covers all 
cropland and pastureland in production in the 48 conterminous United 
States, however it does not contain all categories of grassland and 
rangeland captured in USDA's Major Land Use data sets. Therefore, it is 
possible there is land appropriate for growing dedicated energy crops 
that is not currently modeled in FASOM. Furthermore, we constrained 
FASOM to be consistent with the 2008 Farm Bill and assumed 32 million 
acres would stay in CRP.\113\ These constraints on land availability 
may have contributed to the model choosing a substantial amount of 
agricultural residues mostly as corn stover and a relatively small 
portion of energy crops as being economically viable feedstocks. The 
use of other models, such as USDA's Regional Environment and 
Agriculture Programming (REAP) model and University of Tennessee's 
POLYSYS model, have shown that the use of energy crops in order to meet 
EISA may be more significant than our current FASOM modeling 
results.\114\ As such, we plan to revisit these land availability 
assumptions in order to arrive at a more consistent basis for the FRM. 
We request comment on these assumptions, in addition to all the 
cellulosic yield assumptions that are contained in DRIA Chapter 1.
---------------------------------------------------------------------------

    \112\ Assuming 16 Bgal cellulosic biofuel total, 2.2 Bgal from 
Urban Waste, and 3.8 Bgal from Forestry Biomass; 10 Bgal of 
cellulosic biofuel for ag residues and/or energy crops would be 
needed.
    \113\ Beside the economic incentive of a farmer payment to keep 
land in CRP, local environmental interests may also fight to 
maintain CRP land for wildlife preservation. Also, we did not know 
what portion of the CRP is wetlands which likely could not support 
harvesting equipment.
    \114\ Biomass Research and Development Initiative (BR&DI), 
``Increasing Feedstock Production for Biofuels: Economic Drivers, 
Environmental Implications, and the Role of Research,'' http://www.brdisolutions.com December 2008.
---------------------------------------------------------------------------

iv. Summary of Cellulosic Feedstocks for 2022
    Table V.B.2-4 summarizes our internal estimate of cellulosic 
feedstocks and their corresponding volume contribution to 16 billion 
gallons cellulosic biofuel by 2022 for the purposes of our impacts 
assessment.

    Table V.B.2-4--Cellulosic Feedstocks Assumed To Meet EISA in 2022
------------------------------------------------------------------------
                                                                 Volume
                          Feedstock                              (Bgal)
------------------------------------------------------------------------
Agricultural Residues........................................        9.1
    Corn Stover..............................................        7.8
    Sugarcane Bagasse........................................        1.2
    Sweet Sorghum Pulp.......................................        0.1
Forestry Biomass.............................................        3.8
Urban Waste..................................................        2.2
Dedicated Energy Crops (Switchgrass).........................        0.9
                                                              ----------
        Total................................................       16.0
------------------------------------------------------------------------

v. Cellulosic Plant Siting
    Future cellulosic biofuel plant siting was based on the types of 
feedstocks that would be most economical as shown in Table V.B.2-4, 
above. As cellulosic biofuel refineries will likely be located close to 
biomass resources in order to take advantage of lower transportation 
costs, we've assessed the potential areas in the U.S. that grow the 
various feedstocks chosen. To do this, we used data on harvested acres 
by county for crops that are currently grown today, such as corn stover 
and sugarcane (for bagasse).\115\ In some cases, crops are not 
currently grown, but have the potential to replace other crops or 
pastureland (e.g. dedicated energy crops). We used the output from our 
economic modeling (FASOM) to help us determine which types of land are 
likely to be replaced by newly grown crops. For forestry biomass, USDA-
Forestry Service provided supply curve data by county showing the 
available tons produced. Urban waste (MSW wood, paper, and C&D debris) 
was estimated to be located near large population centers.
---------------------------------------------------------------------------

    \115\ NASS database. http://www.nass.usda.gov/.
---------------------------------------------------------------------------

    Using feedstock availability data by county/city, we located 
potential cellulosic sites across the U.S. that could justify the 
construction of a cellulosic plant facility. For more details on this 
analysis, refer to Section 1.5 of the DRIA. Table V.B.2-5 shows the 
volume of cellulosic facilities by feedstock by state projected for 
2022. The total volumes given in Table V.B.2-5 match the total volumes 
given in Table V.B.2-4 within a couple hundred million gallons. As 
these differences are relatively small, we believe the cellulosic 
facilities sited are a good estimate of potential locations.

[[Page 24996]]



                          Table V.B.2-5--Projected Cellulosic Ethanol Volumes by State
                                            [Million gallons in 2022]
----------------------------------------------------------------------------------------------------------------
                                                             Agricultural     Energy     Urban
                     State                         Total        residue        crop      waste       Forestry
                                                   volume       volume        volume     volume       volume
----------------------------------------------------------------------------------------------------------------
Alabama........................................        532               0          0        140             392
Arkansas.......................................        298               0          0          0             298
California.....................................        450               0          0        221             229
Colorado.......................................         28               0          0         28               0
Florida........................................        421             390          0         31               0
Georgia........................................        437               0          0         67             370
Illinois.......................................      1,525           1,270          0        198              58
Indiana........................................      1,109             948          0        101              60
Iowa...........................................      1,697           1,635          0         32              30
Kansas.........................................        310             250          0         29              32
Kentucky.......................................         70              70          0          0               0
Louisiana......................................      1,001             590          0        103             308
Maine..........................................        191               0          0          2             189
Michigan.......................................        505             283          0        171              51
Minnesota......................................        876             750          0         50              76
Mississippi....................................        214               0          0         22             192
Missouri.......................................        654             504          0         78              72
Montana........................................         92               0          0          9              83
Nebraska.......................................        956             851          0         31              75
Nevada.........................................         17               0          0         17               0
New Hampshire..................................        171               0         35         29             107
New York.......................................         72               0          0         72               0
North Carolina.................................        315               0          0         98             217
Ohio...........................................        598             410          0        156              32
Oklahoma.......................................        793               0        777          0              16
Oregon.........................................        244               0          0         44             200
Pennsylvania...................................         42               0          0         42               0
South Carolina.................................        213               0          0         57             156
South Dakota...................................        434             350          0          6              78
Tennessee......................................         97               0          0         19              78
Texas..........................................        576             300          0        131             145
Virginia.......................................        197               0          0         95             102
Washington.....................................        175               0          0         17             158
West Virginia..................................        149               0        101          0              48
Wisconsin......................................        581             432          0         43             106
                                                ----------------------------------------------------------------
    Total Volume...............................     16,039           9,034        913      2,139           3,955
----------------------------------------------------------------------------------------------------------------

    It is important to note, however, that there are many more factors 
other than feedstock availability to consider when eventually siting a 
plant. We have not taken into account, for example, water constraints, 
availability of permits, and sufficient personnel for specific 
locations. As many of the corn stover facilities are projected to be 
located close to corn starch facilities, there is the potential for 
competition for clean water supplies. Therefore, as more and more 
facilities draw on limited resources, it may become apparent that 
various locations are infeasible. Nevertheless, our plant siting 
analysis provides a reasonable approximation for analysis purposes 
since it is not intended to predict precisely where actual plants will 
be located. Other work is currently being done that will help address 
some of these issues, but at the time of this proposal, was not yet 
available.\116\
---------------------------------------------------------------------------

    \116\ USDA, WGA, Bioenergy Strategic Assessment project findings 
upcoming as noted in report WGA. Transportation Fuels for the Future 
Biofuels: Part I. 2008.
---------------------------------------------------------------------------

    As we are projecting the location of cellulosic plants in 2022, it 
is important to keep in mind the various uncertainties in the analysis. 
For example, future analyses could determine better recommendations for 
sustainable removal rates. In the case where lower removal rates are 
recommended, agricultural residues may be more limited and could 
require more growth in dedicated energy crops. Also, the feedstocks 
could be processed in the field to a liquid by a pyrolysis process, 
facilitating the ability to ship the preprocessed biomass to plants 
located further away from the feedstock source. Given the information 
we have to date, we believe our projected locations for cellulosic 
facilities represent a reasonable forecast for estimating the impacts 
of this rule.
3. Imported Ethanol
a. Historic World Ethanol Production and Consumption
    Although ethanol can be used for multiple purposes (fuel, 
industrial, and beverage), fuel ethanol is by far the largest market, 
accounting for about two-thirds of the total world ethanol consumed. 
According to forecasts, fuel ethanol might even exceed 80% of the 
market share by the end of the decade.\117\ In 2008, the top three fuel 
ethanol producers were the U.S., Brazil, and the European Union (EU), 
producing 9.0, 6.5, and 0.7 billion gallons, respectively.\118\ Other 
countries that have produced ethanol include

[[Page 24997]]

China, Canada, Thailand, Colombia, and India.
---------------------------------------------------------------------------

    \117\ F.O. Licht., ``World Ethanol Markets: The Outlook to 
2015'', 2006, pg. 21.
    \118\ Renewable Fuels Association (RFA), ``2007 World Fuel 
Ethanol Production,'' http://www.ethanolrfa.org/industry/statistics/#E, March 31, 2009.
---------------------------------------------------------------------------

    Consumption of fuel ethanol, like production, is also dominated by 
the United States and Brazil. The U.S. dominates world fuel ethanol 
consumption, with 9.6 billion gallons consumed in 2008 (domestic 
production plus imports).\119\ Brazil is second in consumption, with 
about 4.9 billion gallons projected to be consumed in 2007/2008.\120\ 
The EU is also a significant consumer of ethanol; however, consumption 
for the EU countries was only approximately 0.7 billion gallons in 
2007.\121\
---------------------------------------------------------------------------

    \119\ Ibid.
    \120\ UNICA, ``Sugarcane Industry in Brazil: Ethanol Sugar, 
Bioelectricity'' Brochure, 2008.
    \121\ European Bioethanol Fuel Association (eBio), ``The EU 
Market: Production and Consumption,'' http://www.ebio.org/EUmarket.php, March 31, 2009.
---------------------------------------------------------------------------

b. Historic/Current Domestic Imports
    Ethanol imports have traditionally played a relatively small role 
in the U.S. transportation fuel market due to historically low crude 
prices and the tariff on imported ethanol. While low crude prices made 
it difficult for both domestic and imported ethanol to compete with 
gasoline, the addition of the federal excise tax credit made it 
possible for domestic ethanol to be economically competitive.
    Between 2000 and 2003, the total volume of fuel ethanol imports 
into the United States remained relatively stable at 46-68 million 
gallons.\122\ During this period of time, mostly Brazilian-based 
ethanol entered the U.S. primarily through the Caribbean Basin 
Initiative (CBI) countries where it could avoid the tariff. From 2004-
2005, with rising crude oil prices, most estimates show U.S. fuel 
ethanol imports increased slightly to 135-164 million gallons, or about 
4% of the total U.S. fuel ethanol consumption (3.5 to 4.0 billion 
gallons). The volume of imports rose dramatically in 2006 to 654-720 
million gallons, or about 13% of the 2006 total ethanol consumption of 
5.4 billion gallons. The largest volume of imports in 2006 was from 
direct Brazilian imports. This increase in ethanol imports was mainly 
due to the withdrawal of MTBE from the fuel pool which increased the 
price of ethanol. MTBE was used in gasoline to fulfill the oxygenate 
requirements set by Congress in the 1990 Clean Air Act Amendments. 
EPAct further accelerated the withdrawal of MTBE because gasoline 
marketers were no longer required to use an oxygenate and gasoline 
marketers did not receive the MTBE liability protection that they had 
petitioned for. Refiners responded by removing MTBE and replacing its 
use with ethanol. As a result, the demand for ethanol increased at 
unprecedented rates as most refiners replaced MTBE with ethanol. The 
dramatic increase in crude oil costs at this time also made ethanol 
more economical by comparison.
---------------------------------------------------------------------------

    \122\ Values given report USITC and RFA data, however, EIA 
reports slightly lower numbers prior to 2004.
---------------------------------------------------------------------------

    By the end of 2006, almost all MTBE was phased out of gasoline. 
However, crude oil prices remained high, allowing ethanol imports to 
the U.S. to remain economical in comparison to the past. Although not 
as high as the volume of ethanol imported in 2006, the U.S. continued 
to import ethanol in 2007 (425-450 million gallons). In 2008, the U.S. 
imported 519-556 million gallons.\123\ As the data show, the volume of 
imported ethanol can fluctuate greatly. By looking at historical import 
data it is difficult to project the potential volume of future imports 
to the U.S. Rather, it is necessary to assess future import potential 
by analyzing the major players for foreign biofuels production and 
consumption.
---------------------------------------------------------------------------

    \123\ USITC and EIA import data reported.
---------------------------------------------------------------------------

c. Projected Domestic Imports
    In our assessment of foreign ethanol production and consumption, we 
analyzed the following countries or group of countries: Brazil, the EU, 
Japan, India, and China. Our analyses indicate that Brazil would likely 
be the only nation able to supply any meaningful amount of ethanol to 
the U.S. in the future. Depending on whether the mandates and goals of 
the EU, Japan, India, and China are enacted or met in the future, it is 
likely that this group of countries would consume any growth in their 
own production and be net importers of ethanol, thus competing with the 
U.S. for Brazilian ethanol exports.
    Brazil is expected to supply the majority of future ethanol demand 
and to expand their capacity for several reasons. First, Brazil has 
over 30 years experience in developing the research and technologies 
for producing sugarcane ethanol. As a result, Brazilians have been able 
to improve agricultural and conversion processes so that sugarcane 
ethanol is currently the least costly method for producing biofuels. 
See Section VIII for further discussion on the production costs for 
sugarcane ethanol.
    Second, it is believed that domestic demand for ethanol in Brazil 
will begin to slow as most of the national fleet of vehicles will have 
transitioned to flex-fuel within the next few years.\124\ Thus, as 
domestic demand begins to level off, some experts see a significant 
possibility that exports will become more relevant in market share 
terms.
---------------------------------------------------------------------------

    \124\ Agra FNP, ``Sugar and Ethanol in Brazil: A Study of the 
Brazilian Sugar Cane, Sugar and Ethanol Industries,'' 2007.
---------------------------------------------------------------------------

    Lastly, Brazil has large land areas for potential expansion for 
sugarcane. A study commissioned by the Brazilian government produced an 
analysis in which Brazil's arable land was evaluated for its 
suitability for cane.\125\ Setting aside areas protected by 
environmental regulations and those with a slope greater than 12% 
(those not suitable for mechanized farming), tripling ethanol 
production (a goal set by the Brazilian government by 2020) would 
require only an additional 14 million acres. This additional acreage 
would only be about 2% of suitable land for sugarcane production. Refer 
to Section 1.5 of the DRIA for more details.
---------------------------------------------------------------------------

    \125\ CGEE, ABDI, Unicamp, and NIPE, Scaling Up the Ethanol 
Program in Brazil, n.d. as quoted in Rothkopf, Garten, ``A Blueprint 
for Green Energy in the Americas,'' 2006.
---------------------------------------------------------------------------

    Although Brazil is in an excellent position to help meet the 
growing global demand for ethanol, several constraints could limit the 
expansion of ethanol production. As Brazil's government has adopted 
plans to meet global demand by tripling production by 2020,\126\ this 
would mean a total capacity of about 12.7 billion gallons, to be 
achieved through a combination of efficiency gains, greenfield 
projects, and infrastructure expansions. Estimates for the investment 
required tend to range from $2 to $4 billion a year.\127\ In addition, 
Brazil will need to improve its current ethanol infrastructure (i.e. 
improvements in power, transportation, storage, distribution logistics, 
and communications). It is estimated that Brazil will need to invest $1 
billion each year for the next 15 years in infrastructure to keep pace 
with capacity expansion and export demand.\128\ Refer to Section 1.5 of 
the DRIA for further details on the improvements needed for Brazil to 
increase ethanol production capacity.
---------------------------------------------------------------------------

    \126\ Rothkopf, Garten, ``A Blueprint for Green Energy in the 
Americas,'' 2006.
    \127\ Ibid.
    \128\ Ibid.
---------------------------------------------------------------------------

    Due to uncertainties in the future demand for ethanol domestically 
and internationally as well as uncertainties in the actual investments 
made in the Brazilian ethanol industry, there appears to be a wide 
range of Brazilian production and domestic consumption estimates. The 
most current and complete estimates indicate that total

[[Page 24998]]

Brazilian ethanol exports will likely reach 3.8-4.2 billion gallons by 
2022.129 130 131 As this volume of ethanol export is 
available to countries around the world, only a portion of this will be 
available exclusively to the United States. If the balance of the EISA 
advanced biofuel requirement not met with cellulosic biofuel and 
biomass-based diesel were to be met with imported sugarcane ethanol 
alone, it would require 3.2 billion gallons (see Table V.A.2-1), or 
approximately 80% of total Brazilian ethanol export estimates.
---------------------------------------------------------------------------

    \129\ EPE, ``Plano Nacional de Energia 2030,'' Presentation from 
Mauricio Tolmasquim, 2007.
    \130\ UNICA, ``Sugarcane Industry in Brazil: Ethanol, Sugar, 
Bioelectricity,'' 2008.
    \131\ USEPA International Visitors Program Meeting October 30, 
2007, correspondence with Mr. Rodrigues, Technical Director from 
UNICA Sao Paulo Sugarcane Agro-industry Union, stated approximately 
3.7 billion gallons probable by 2017/2020; Consistent with brochure 
``Sugarcane Industry in Brazil: Ethanol Sugar, Bioelectricity'' from 
UNICA (3.25 Bgal export in 2015 and 4.15 Bgal export in 2020).
---------------------------------------------------------------------------

    The amount of Brazilian ethanol available for shipment to the U.S. 
will be dependent on the biofuels mandates and goals set by other 
foreign countries (i.e., the EU, Japan, India, and China) in addition 
to U.S. policies to promote the use of renewable fuels. Our estimates 
show that there could be a potential demand for imported ethanol of 
4.6-14.6 billion gallons by 2020/2022 from these countries. This is due 
to the fact that some countries are unable to produce large volumes of 
ethanol because of land constraints or low production capacity. As 
such, foreign countries may have limited domestic biofuel production 
capability and may therefore require importation of biofuels in order 
to meet their mandates and goals. Refer to Section 1.5 of the DRIA for 
further details. Therefore, if other foreign country mandates and goals 
are to be met, then Brazil may need to either increase production much 
more than its government projects or export less ethanol to the U.S. 
This suggests that the U.S. may be competing for Brazilian ethanol 
exports if supplies are limited in the future. For our analysis we 
assumed that the U.S. would consume the majority of Brazilian exports 
(i.e. 80% of export estimates in 2022). This is aggressive, yet within 
the bounds of reason, therefore, we have made this simplifying 
assumption for the purposes of further analysis. We seek comment on the 
legitimacy of this assumption given the ethanol export deals and 
commitments that Brazil has made or may potentially make with other 
nations in the future.
    Generally speaking, Brazilian ethanol exporters will seek routes to 
countries with the lowest transportation costs, taxes, and tariffs. 
With respect to the U.S., the most likely route is through the 
Caribbean Basin Initiative (CBI).\132\ Brazilian ethanol entering the 
U.S. through the CBI countries is not currently subject to the 54 cent 
imported ethanol tariff and yet receives the 45 cent ethanol blender 
tax subsidy. Due to the economic incentive of transporting ethanol 
through the CBI, we expect the majority of the tariff rate quota (TRQ) 
to be met or exceeded, perhaps 90% or more. The TRQ is set each year as 
7% of the total domestic ethanol consumed in the prior year. If we 
assume that 90% of the TRQ is met and that total domestic ethanol (corn 
and cellulosic ethanol) consumed in the prior year was 28.5 Bgal, then 
approximately 1.8 Bgal of ethanol could enter the U.S. through CBI 
countries. The rest of the Brazilian ethanol exports not entering the 
CBI will compete on the open market with the rest of the world 
demanding some portion of direct Brazilian ethanol. We calculated the 
amount of direct Brazilian ethanol exports in 2022 to the U.S. as the 
total imported ethanol required (3.14 billion gallons) to meet the RFS2 
volume requirements subtracted by imported ethanol from CBI countries 
(1.8 billion gallons), or equal to 1.34 billion gallons.
---------------------------------------------------------------------------

    \132\ Other preferential trade agreements include the North 
American Free Trade Agreement (NAFTA) which permits tariff-free 
ethanol imports from Canada and Mexico and the Andean Trade 
Promotion and Drug Eradication Act (ATPDEA) which allows the 
countries of Columbia, Ecuador, Bolivia, and Peru to import ethanol 
duty-free. Currently, these countries export or produce relatively 
small amounts of ethanol, and thus we have not assumed that the U.S. 
will receive any substantial amounts from these countries in the 
future for our analyses.
---------------------------------------------------------------------------

    In the past, companies have also avoided the ethanol import tariff 
through a duty drawback.\133\ The drawback is a loophole in the tax 
rules which allowed companies to import ethanol and then receive a 
rebate on taxes paid on the ethanol when jet fuel is sold for export 
within three years. The drawback considered ethanol and jet fuel as 
similar commodities (finished petroleum derivatives).134 135 
Most recently, however, Senate Representative Charles Grassley from 
Iowa included a provision into the Farm Bill of 2008 that ended such 
refunds. The provision states that ``any duty paid under subheading 
9901.00.50 of the Harmonized Tariff Schedule of the United States on 
imports of ethyl alcohol or a mixture of ethyl alcohol may not be 
refunded if the exported article upon which a drawback claim is based 
does not contain ethyl alcohol or a mixture of ethyl alcohol.'' \136\ 
The provision is effective on or after October 1, 2008 and companies 
have until October 1, 2010 to apply for a duty drawback on prior 
transactions. With the loophole closed, it is anticipated that there 
may be less ethanol directly exported from Brazil in the future.\137\
---------------------------------------------------------------------------

    \133\ Rapoza, Kenneth, ``UPDATE: Tax Loophole Helps US Import 
Ethanol `Duty Free'--ED&F,'' INO News, Dow Jones Newswires, March 
2008. http://news.ino.com/.
    \134\ Peter Rhode, ``Senate Finance May Take Up Drawback 
Loophole As Part of Energy Bill,'' EnergyWashington Week, April 18, 
2007. As sited in Yacobucci, Brent, ``Ethanol Imports and the 
Caribbean Basin Initiative,'' CRS Report for Congress, Order Code 
RS21930, Updated March 18, 2008.
    \135\ Perkins, Jerry, ``BRAZIL: Loophole Hurt U.S. Ethanol 
Prices,'' DesMoinesRegister.com, October 18, 2007.
    \136\ Public Law Version 6124 of the Farm Bill. 2008. http://www.usda.gov/documents/Bill_6124.pdf.
    \137\ Lundell, Drake, ``Brazilian Ethanol Export Surge to End; 
U.S. Customs Loophole Closed Oct. 1,'' Ethanol and Biodiesel News, 
Issue 45, November 4, 2008.
---------------------------------------------------------------------------

    For our distribution and air quality analyses, we had to make a 
determination as to where the projected imported ethanol would likely 
enter the United States. To do so, we started by looking at 2006 
ethanol import data and made assumptions as to which countries would 
likely contribute to the CBI ethanol volumes in Table V.B.3-1, and to 
what extent.\138\ We estimated that, on average, in future years, 30% 
would come from Jamaica, 20% each would come from El Salvador and Costa 
Rica, and 15% each would originate from Trinidad & Tobago and the 
Virgin Islands. Even though to date there have not been a lot of 
ethanol imports from the Virgin Islands, we believe that they could 
become a comparable importer to Trinidad & Tobago in the future under 
the proposed RFS2 program.
---------------------------------------------------------------------------

    \138\ Source: EIA data on company-level imports (http://www.eia.doe.gov/oil_gas/petroleum/data_publications/company_level_imports/cli_historical.html).
---------------------------------------------------------------------------

    From there, we looked at 2006-2007 import data and estimated the 
general destination of Brazilian ethanol and the five contributing CBI 
countries' domestic imports. Based on these countries' geographic 
locations and import histories, we estimated that in 2022 about 75% of 
the ethanol would be imported to the East and Gulf Coasts and the 
remainder would go to the West Coast and Hawaii. To estimate import 
locations, we considered coastal port cities that had received ethanol 
or finished gasoline imports in 2006 and distributed the ethanol 
accordingly based on ethanol demand. For more information on this 
analysis, refer to Section 1.5 of the DRIA.

[[Page 24999]]

4. Biodiesel & Renewable Diesel
    Biodiesel and renewable diesel are replacements for petroleum 
diesel that are made from plant or animal fats. Biodiesel consists of 
fatty acid methyl esters (FAME) and can be used in low-concentration 
blends in most types of diesel engines and other combustion equipment 
with no modifications. The term renewable diesel covers fuels made by 
hydrotreating plant or animal fats in processes similar to those used 
in refining petroleum. Renewable diesel is chemically analogous to 
blendstocks already used in petroleum diesel, thus its use can be 
transparent and its blend level essentially unlimited. The goal of both 
biodiesel and renewable diesel conversion processes is to change the 
properties of a variety of feedstocks to more closely match those of 
petroleum diesel (such as its density, viscosity, and energy content) 
for which the engines and distribution system have been designed. Both 
processes can produce suitable fuels from biogenic sources, though we 
believe some feedstocks lend themselves better to one process or the 
other. The definition of biodiesel given in applicable regulations is 
sufficiently broad to be inclusive of both fuels.\139\ However, the 
EISA stipulates that renewable diesel that is co-processed with 
petroleum diesel cannot be counted as ``biomass-based diesel'' for 
purposes of complying with its volume mandates.\140\
---------------------------------------------------------------------------

    \139\ See Section 1515 of the Energy Policy Act of 2005. More 
discussion of the definitions of biodiesel and renewable diesel are 
given in the preamble of the Renewable Fuel Standard rulemaking, 
Section III.B.2, as published in the Federal Register Vol. 72, No. 
83, p. 23917.
    \140\ For more detailed discussion of the definition of 
coprocessing and its implications for compliance with EISA, see 
Section III.B.1 of this preamble.
---------------------------------------------------------------------------

    In general, plant and animal oils are valuable commodities with 
many uses other than transportation fuel. Therefore we expect the 
primary limiting factor in the supply of both biodiesel and renewable 
diesel to be feedstock availability and price. Expansion of their 
market volumes is dependent on being able to compete on price with the 
petroleum diesel they are displacing, which will depend largely on 
continuation of current subsidies and other incentives.
    Other biomass-based diesel fuel plants are either already built or 
being considered for construction. Cello Energy has already started up 
a 20 million gallon per year catalytic depolymerization plant that is 
producing diesel fuel from cellulose and other feedstocks, and Cello 
intends on building several 50 million gallon per year plants to be 
started up in 2010. Also, numerous other companies are planning on 
building biomass to liquids (BTL) plants that produce diesel fuel 
through the syngas and Fischer Tropsch pathway. However, for our 
analysis for this proposed rulemaking, we did not project that biomass-
based diesel fuel would be produced from these processes.
a. Historic and Projected Production
i. Biodiesel
    As of September 2008, the aggregate production capacity of 
biodiesel plants in the U.S. was estimated at 2.6 billion gallons per 
year across approximately 176 facilities.\141\ Biodiesel plants exist 
in nearly all states, with the largest density of plants in the Midwest 
and Southeast where agricultural feedstocks are most plentiful.
---------------------------------------------------------------------------

    \141\ Figures here were taken from National Biodiesel Board fact 
sheet dated September 29, 2008 (http://biodiesel.org/pdf_files/fuelfactsheets/Producers%20Map%20-%20existing.pdf). This information 
was current at the time these analyses were being done. More recent 
data maintained by Biodiesel Magazine suggests that by April 2009 
the industry had contracted to approximately 137 plants with 
aggregate capacity of 2.3 billion gal/yr (see http://www.biodieselmagazine.com/plant-list.jsp).
---------------------------------------------------------------------------

    Table V.B.4-1 gives U.S. biodiesel production capacity, sales, and 
capacity utilization in recent years. The figures suggest that the 
industry has grown out of proportion with actual biodiesel demand. 
Reasons for this include various state incentives to build plants, 
along with state and federal incentives to blend biodiesel, which have 
given rise to an optimistic industry outlook over the past several 
years. Since the cost of capital is relatively low for the biodiesel 
production process (typically four to six percent of the total per-
gallon cost), this industry developed a more grassroots profile in 
comparison to the ethanol industry, and, with median size less than 10 
million gallons/yr, consists of a large number of small plants.\142\ 
These small plants, with relatively low operating costs other than 
feedstock, have generally been able to survive producing below their 
nameplate capacities.
---------------------------------------------------------------------------

    \142\ Capital figures derived from USDA production cost models. 
A publication describing USDA modeling of biodiesel production costs 
can be found in Bioresource Technology 97(2006) 671-8.
    \143\ Capacity data taken from National Biodiesel Board. 
Production figures taken from F.O. Licht World Ethanol and Biofuels 
Report, vol. 6, no. 11, p S271, except 2008, which is an estimate 
taken from National Biodiesel Board (http://www.biodiesel.org/pdf_files/fuelfactsheets/Production_graph_slide.pdf).

                          Table V.B.4-1--U.S. Biodiesel Capacity and Production Volumes
                                             [Million gallons] \143\
----------------------------------------------------------------------------------------------------------------
                                                                                                    Utilization
                              Year                                   Capacity       Production       (percent)
----------------------------------------------------------------------------------------------------------------
2003............................................................             150              21             14%
2004............................................................             245              36              15
2005............................................................             395             115              29
2006............................................................             792             241              30
2007............................................................           1,809             499              28
2008............................................................           2,610             700              27
----------------------------------------------------------------------------------------------------------------

    Some of this industry capacity may not be dedicated specifically to 
fuel production, instead being used to make oleochemical feedstocks for 
further conversion into products such as surfactants, lubricants, and 
soaps. These products do not show up in renewable fuel sales figures.
    In 2004-5, demand for biodiesel grew rapidly, but the trend of 
increasing capacity utilization was quickly overwhelmed by additional 
plant starts. Since then, high commodity prices followed by reduced 
demand for transportation fuel have caused additional economic strain 
beyond the overcapacity situation. According to a survey conducted by 
Biodiesel Magazine staff, more than 1 in 5 plants were already idle or 
defunct as of late 2007 (though this likely varies by

[[Page 25000]]

region).\144\ A significant portion of the 2007 and 2008 production was 
exported to Europe or Asia where fuel prices and additional tax 
subsidies on top of those provided in the U.S. help cover 
transportation overseas and offset high feedstock costs. The Energy 
Information Administration is beginning to collect data on biodiesel 
imports and exports, but reports are not expected until later in 2009. 
Therefore precise figures are not available on what fraction of 
production was consumed domestically, but sources familiar with the 
industry suggest exports may have been as much as 200 million gallons 
in 2007 and likely more in 2008.\145\ We do not account for any 
biodiesel exports in our analysis, though there will be sufficient 
plant capacity to produce material beyond the volumes required in the 
EISA should an export market exist.
---------------------------------------------------------------------------

    \144\ Derived from figures published in Biodiesel Magazine, May 
2008, p. 39.
    \145\ Staff-level communication with National Biodiesel Board 
(April 2008).
---------------------------------------------------------------------------

    To perform our distribution and emission impacts analyses for this 
proposal, it was necessary to forecast the state of the biodiesel 
industry in the timeframe of the fully-phased-in RFS. In general, this 
consisted of reducing the over-capacity to be much closer to the amount 
demanded, which we assumed to be equal to the requirement under the 
EISA given uncertainties about feedstock prices and changes in tax 
incentives in the long term. This was accomplished by considering as 
screening factors the current production and sales incentives in each 
state as well as each plant's primary feedstock type and whether it was 
BQ-9000 certified.\146\ Going forward producers will compete for 
feedstocks and markets will consolidate. During this period the number 
of operating plants is expected to shrink, with surviving plants adding 
feedstock segregation and pre-treatment capabilities, giving them 
flexibility to process any mix of feedstocks available in their area. 
By the end of this period we project a mix of large regional plants and 
some smaller plants taking advantage of local market niches, with an 
overall average capacity utilization around 80% for dedicated fuel 
plants. Table V.B.4-2 summarizes this forecast. See Section 1.5.4 of 
the DRIA for more details.
---------------------------------------------------------------------------

    \146\ Information on state incentives was taken from U.S. 
Department of Energy Web site, accessed July 30, 2008, at http://www.eere.energy.gov/afdc/fuels/biodiesel_laws.html. Information on 
feedstock and BQ-9000 status was taken from Biodiesel Board fact 
sheet, accessed July 30, 2008, at http://biodiesel.org/pdf_files/fuelfactsheets/Producers%20Map%20-%20existing.pdf.

 Table V.B.4-2--Summary of Projected Biodiesel Industry Characterization
                       Used in Our Analyses \147\
------------------------------------------------------------------------
                                                          2008     2022
------------------------------------------------------------------------
Total production capacity on-line (million gal/yr)....    2,610    1,050
Number of operating plants............................      176       35
Median plant size (million gal/yr)....................        5       30
Total biodiesel production (million gal)..............      700      810
Average plant utilization.............................     0.27     0.77
------------------------------------------------------------------------

ii. Renewable Diesel
    Renewable diesel is a fuel (or blendstock) produced from animal 
fats, vegetable oils, and waste greases using chemical processes 
similar to those employed in petroleum hydrotreating. These processes 
remove oxygen and saturate olefins, converting the triglycerides and 
fatty acids into paraffins. Renewable diesel typically has higher 
cetane, lower nitrogen, and lower aromatics than petroleum diesel fuel, 
while also meeting stringent sulfur standards.
---------------------------------------------------------------------------

    \147\ Industry data for 2008 taken from National Biodiesel Board 
fact sheets at http://www.biodiesel.org/buyingbiodiesel/producers_marketers/Producers%20Map-Existing.pdf and http://www.biodiesel.org/pdf_files/fuelfactsheets/Production_graph_slide.pdf (both 
accessed April 27, 2009).
---------------------------------------------------------------------------

    In comparison to biodiesel, renewable diesel has improved storage, 
stability, and shipping properties as a result of the oxygen and 
olefins in the feedstock being removed. This allows renewable diesel 
fuel to be shipped in existing petroleum pipelines used for 
transporting fuels, thus avoiding one significant issue with 
distribution of biodiesel. For more on fuel distribution, refer to 
Section V.C.
    Considering that this industry is still in development and that 
there are no long-term projections of production volume, we base our 
production estimates primarily on the potential volume of feedstocks 
for this process, in the context of recent industry project 
announcements involving proven technology. We project that 
approximately two-thirds of renewable diesel will be produced at 
existing petroleum refineries, and half will be co-processed with 
petroleum (thus prohibiting it from counting as ``biomass-based 
diesel'' under the EISA). Tables V.B.4-3 and V.B.4-4 summarize these 
volumes.

Table V.B.4-3--Projected Renewable Diesel Volumes by Production Category
                        [Million gallons in 2022]
------------------------------------------------------------------------
                                                  Existing       New
                                                  facility     facility
------------------------------------------------------------------------
Co-processed with petroleum...................          188           --
Not co-processed with petroleum...............           63          125
------------------------------------------------------------------------

b. Feedstock Availability
    The primary feedstock for domestic biodiesel production has 
historically been soybean oil, with other plant and animal fats as well 
as recycled greases making up a smaller but significant portion of the 
biodiesel pool. Agricultural commodity modeling we have done for this 
proposal (see Section IX.A) suggests that soybean oil production will 
stay relatively flat in the future, causing supplies to tighten and 
prices to rise as demand increases for biofuels and food uses 
worldwide. The output of these models suggests that domestic soy oil 
production could support about 550 million gallons per year in 2022. 
This material is most likely to be processed by biodiesel plants due to 
the large available capacity of these facilities and their proximity to 
soybean production. Compared to other feedstocks, virgin plant oils are 
more easily processed into biofuel via simple transesterification due 
to their homogeneity of composition and lack of contaminants.
    Another source of feedstock which could provide increasing and 
significant volume is oil extracted from corn or its co-products in the 
dry mill ethanol production process. Sometimes referred to as corn 
fractionation or dry separation, these processes get additional 
products of value from the dry milling process. This idea is not

[[Page 25001]]

new, as existing wet mill plants create several product streams from 
their corn input, including oil. Corn fractionation can be seen as a 
way to get some of this added value without incurring the larger 
capital costs and potentially lower ethanol yields associated with wet 
mill plants. More detailed discussion of these processes and how they 
affect the co-product stream(s) can be found in DRIA Section 1.4.1.3.
    The corn oil process on which we have chosen to focus for cost and 
volume estimates in this proposal is one that extracts oil from the 
thin stillage after fermentation (the non-ethanol liquid material that 
typically becomes part of distillers' grains with solubles). We believe 
installation of this type of equipment will be attractive to industry 
because it can be added onto an existing dry mill plant and does not 
impact ethanol yields since it does not process the corn prior to 
fermentation. Depending on the configuration, such a system can extract 
20-50% of the oil from the co-product streams, and produces a 
distressed corn oil (non-food-grade, with some free fatty acids and/or 
oxidation by-products) product stream which can be used as feedstock by 
biodiesel facilities. Since it offers another stream of revenue, we 
believe it is reasonable to expect about 40% of projected total ethanol 
production to implement some type of oil extraction process by 2022, 
generating approximately 150 million gallons per year of corn oil 
biofuel feedstock.\148\ We expect this material to be processed in 
biodiesel plants.
---------------------------------------------------------------------------

    \148\ See Table 3 in Mueller, Steffen. An analysis of the 
projected energy use of future dry mill corn ethanol plants (2010-
2030). October 10, 2007. Available at http://www.chpcentermw.org/pdfs/2007CornEthanolEnergySys.pdf.
---------------------------------------------------------------------------

    Rendered animal fats and reclaimed cooking oils and greases are 
another potentially significant source of biodiesel feedstock. We 
estimate that just two to four percent of biodiesel in 2007 was 
produced from waste cooking oils and greases, though this number is 
likely higher more recently.\149\ Tyson Foods, in joint efforts with 
ConocoPhilips and Syntroleum, announced construction plans in 2008 for 
renewable diesel production facilities to begin operating in 2010 and 
producing up to 175 million gallons annually (combined capacity). By 
the end of our projection period, as much as 30% of rendered fats and 
waste grease could be converted to biofuel while still supporting 
production of pet food, soaps and detergents, and other 
oleochemicals.\150\ We request comment from members of these industries 
on any potential impacts of diversion of rendered materials to biofuel.
---------------------------------------------------------------------------

    \149\ Based on plant capacities reported by the National 
Biodiesel Board and data reported by F.O. Licht.
    \150\ Based on statements from the National Renderer's 
Association.
---------------------------------------------------------------------------

    Under this assumption, this material could make approximately 500 
million gallons of biofuel (though we have not chosen to allocate all 
of it in our analyses here). We estimate this type of material could be 
most economically made into renewable diesel in the long term, as that 
process does not have the same sensitivities to free fatty acids and 
other contaminates typically present in waste greases as the biodiesel 
process; however, some amount of this material may continue to be 
processed in biodiesel plants that have acid pretreatment capabilities 
where it makes economic sense. Recent market shifts and changes in tax 
subsidies enacted after analyses were done for this NPRM have affected 
the relative economics of using waste fats and greases for biodiesel 
versus renewable diesel. We will reevaluate our assumptions in the FRM.
    Our analysis of the countries with the most potential to produce 
and consume biodiesel in the future suggests that supplies of finished 
biodiesel will be tight, and prices of its feedstocks will remain high. 
Supplies to the U.S. will be limited by biofuel mandates and targets of 
other countries, preferential shipment of biodiesel to European and 
Asian nations, and the speed at which non-traditional crops such as 
jatropha can be developed. Thus, we cannot at this time project more 
than negligible amounts of biodiesel or its feedstocks being available 
for import into the U.S. in the future. For more discussion of 
international movement of biodiesel and its feedstocks, refer to 
Section 1.1 of the DRIA.
    Table V.B.4-4 shows the projected potential contribution of these 
sources we have chosen to quantify. Other potential, but less certain, 
sources for biodiesel feedstocks include conversion of some existing 
croplands used for soybeans to higher-yielding oilseed crops. 
Production of oil from algae farms is also being investigated by a 
number of companies and universities as a source of biofuel feedstock. 
For additional discussion of such sources, refer to Section 1.1 of the 
DRIA.

    Table V.B.4-4--Estimated Potential Biodiesel and Renewable Diesel
                             Volumes in 2022
                        [Million gallons of fuel]
------------------------------------------------------------------------
                                     Biomass-based diesel       Other
                                  --------------------------   advanced
                                                               biofuel
                                                 Renewable  ------------
                                    Biodiesel      diesel     Renewable
                                                                diesel
------------------------------------------------------------------------
Virgin plant oils................          660           --           --
Corn fractionation...............          150           --           --
Rendered fats and greases........           --          188          188
------------------------------------------------------------------------

C. Renewable Fuel Distribution

    The following discussion pertains to the distribution of biofuels. 
A discussion of the distribution of biofuel feedstocks and co-products 
is contained in Section 1.3.3 and 5.1 of the DRIA respectively. In 
conducting our analysis of biofuel distribution, we took into account 
the projected size and location of biofuel production facilities and 
where we project biofuels would be used.\151\
---------------------------------------------------------------------------

    \151\ The location of biofuel production facilities and where 
biofuels would be used is discussed in Sections 1.5 and 1.7 of the 
DRIA respectively and earlier in this Section V of the preamble.
---------------------------------------------------------------------------

    The current motor fuel distribution infrastructure has been 
optimized to facilitate the movement of petroleum-based fuels. 
Consequently, there are very efficient pipeline-terminal networks that 
move large volumes of petroleum-based fuels from production/import 
centers on the Gulf Coast and the Northeast into the heartland of the

[[Page 25002]]

country. In contrast, the majority of renewable fuel is expected to be 
produced in the heartland of the country and will need to be shipped to 
the coasts, flowing roughly in the opposite direction of petroleum-
based fuels. This limits the ability of renewable fuels to utilize the 
existing fuel distribution infrastructure.
    The modes of distributing renewable fuels to the end user vary 
depending on constraints arising from their physical/chemical nature 
and their point of origination. Some fuels are compatible with the 
existing fuel distribution system, while others currently require 
segregation from other fuels. The location of renewable fuel production 
plants is also often dictated by the need to be close to the source of 
the feedstocks used rather than to fuel demand centers or to take 
advantage of the existing petroleum product distribution system. Hence, 
the distribution of renewable fuels raises unique concerns and in many 
instances requires the addition of new transportation, storage, 
blending, and retail equipment.
    Significant challenges must be faced in reconfiguring the 
distribution system to accommodate the large volumes of ethanol and to 
a lesser extent biodiesel that we project will be used. While some 
uncertainties remain, particularly with respect to the ability of the 
market to support the use of the volume of E85 needed, no technical 
barriers appear to be insurmountable. The response of the 
transportation system to date to the unprecedented increase in ethanol 
use is encouraging. A U.S. Department of Agriculture (USDA) report 
concluded that logistical concerns have not hampered the growth in 
ethanol production, but that concerns may arise about the adequacy of 
transportation infrastructure as the growth in ethanol production 
continues.\152\
---------------------------------------------------------------------------

    \152\ ``Ethanol Transportation Backgrounder, Expansion of U.S. 
Corn-based Ethanol from the Agricultural Transportation 
Perspective'', USDA, September 2007, http://www.ams.usda.gov/tmd/TSB/EthanolTransportationBackgrounder09-17-07.pdf.
---------------------------------------------------------------------------

    Considerable efforts are underway by individual companies in the 
fuel distribution system, consortiums of such companies, industry 
associations, independent study groups, and inter-agency governmental 
organizations to evaluate what steps may be necessary to facilitate the 
necessary upgrades to the distribution system to support compliance 
with the RFS2 standards.\153\ EPA will continue to participate/monitor 
these efforts as appropriate to keep abreast of potential problems in 
the biofuel distribution system which might interfere with the use of 
the volumes of biofuels that we project will be needed to comply with 
the RFS2 standards. The 2008 Farm Act (Title IX) requires USDA, DOE, 
DOT, and EPA to conduct a biofuels infrastructure study that will 
assess infrastructure needs, analyze alternative development 
approaches, and provide recommendations for specific infrastructure 
development actions to be taken.\154\
---------------------------------------------------------------------------

    \153\ For example: (1) The Biomass Research and Development 
Board, a government study group, has formed a task group on biofuels 
distribution infrastructure that is composed of experts on biofuel 
distribution from a broad range of governmental agencies. (2) The 
National Commission on Energy Policy, an independent advisory group, 
has formed a task group of fuel distribution experts to make 
recommendations on the steps needed to facilitate the distribution 
of biofuels. (3) The Association of Oil Pipelines is conducting 
research to evaluate what steps are necessary to allow the 
distribution of ethanol blends by pipeline.
    \154\ http://www.ers.usda.gov/FarmBill/2008/Titles/TitleIXEnergy.htm#infrastructure.
---------------------------------------------------------------------------

    Considerations related to the distribution of ethanol, biodiesel, 
and renewable diesel are discussed in the following sections as well as 
the changes to each segment in the distribution system that would be 
needed to support the volumes of these biofuels that we project would 
be used to satisfy the RFS2 standards.\155\ We request comments on the 
challenges that will be faced by the fuel distribution system under the 
RFS2 standards and on what steps will be necessary to facilitate making 
the necessary accommodations in a timely fashion.\156\
---------------------------------------------------------------------------

    \155\ Additional discussion can be found in Section 1.6 of the 
DRIA.
    \156\ The costs associated with making the necessary changes to 
the fuel distribution infrastructure are discussed in Section VIII.B 
of today's preamble.
---------------------------------------------------------------------------

    To the extent that biofuels other than ethanol and biodiesel are 
produced in response to the RFS2 standards, this might lessen the need 
for added segregation during distribution. Distillate fuel produced 
from cellulosic feedstocks might be treated as petroleum-based diesel 
fuel blendstocks or a finished distillate fuel in the distribution 
system. Likewise, bio-gasoline or bio-butanol could potentially be 
treated as petroleum-based gasoline blendstocks.\157\ This also might 
open the possibility for additional transport by pipeline. However, the 
location of plants that produce such biofuels relative to petroleum 
pipeline origination points would continue to be an issue limiting the 
usefulness of existing pipelines for biofuel distribution.\158\
---------------------------------------------------------------------------

    \157\ Biogasoline might also potentially be treated as finished 
fuel.
    \158\ The projected location of biofuel plants would not be 
affected by the choice of whether they are designed to produce 
ethanol, distillate fuel, bio-gasoline, or butanol. Proximity to the 
feedstock would continue to be the predominate consideration. The 
use of pipelines is being considered for the shipment of bio-oils 
manufactured from cellulosic feedstocks to refineries where they 
could be converted into renewable diesel fuel or renewable gasoline. 
The distribution of biofuel feedstocks is discussed in Section 1.3 
of the DRIA.
---------------------------------------------------------------------------

1. Overview of Ethanol Distribution
    Pipelines are the preferred method of shipping large volumes of 
petroleum products over long distances because of the relative low cost 
and reliability. Ethanol is currently not commonly shipped by pipeline 
because it can cause stress corrosion cracking in pipeline walls and 
its affinity for water and solvency can result in product contamination 
concerns.\159\ Shipping ethanol in pipelines that carry distillate 
fuels as well as gasoline also presents unique difficulties in coping 
with the volumes of a distillate-ethanol mixture which would typically 
result.\160\ It is not possible to re-process this mixture in the way 
that diesel-gasoline mixtures resulting from pipeline shipment are 
currently handled.\161\ Substantial testing and analysis is currently 
underway to resolve these concerns so that ethanol may be shipped by 
pipeline either in a batch mode or blended with petroleum-based 
fuel.\162\ By the time of the publication of this proposal, results of 
these evaluations may be available regarding what actions are necessary 
by multi-product pipelines to overcome safety and product contamination 
concerns associated with shipping 10% ethanol blends. A short gasoline 
pipeline in Florida has begun shipping

[[Page 25003]]

batches of ethanol.\163\ Thus, existing petroleum pipelines in some 
areas of the country might play a role in the shipment of ethanol from 
the points of production/importation to petroleum terminals.
---------------------------------------------------------------------------

    \159\ Stress corrosion cracking could lead to a pipeline leak. 
The potential impacts on water from today's proposal are discussed 
in Section X of today's preamble.
    \160\ Different grades of gasoline and diesel fuel are typically 
shipped in multi-product pipelines in batches that abut each other. 
To the extent possible, products are sequenced in a way to allow the 
interface mixture between batches to be cut into one of the 
adjoining products. In cases where diesel fuel abuts gasoline in the 
pipeline, the resulting mixture must typically be reprocessed into 
its component parts by distillation for resale as gasoline and 
diesel fuel.
    \161\ Gasoline-ethanol mixtures can be blended into finished 
gasoline.
    \162\ Association of Oil Pipelines: http://aopl.org/go/searchresults/888/?q=ethanol&sd=&ed=. ``Hazardous Liquid Pipelines 
Transporting Ethanol, Ethanol Blends, and Other Biofuels'', Notice 
of policy statement and request for comment, Pipeline and Hazardous 
Materials Safety Administration, Department of Transportation, 
August 10, 2007, 72 FR 45002.
    \163\ Article on shipment of ethanol in Kinder Morgan pipeline: 
http://www.ethanolproducer.com/article.jsp?article_id=5149.
---------------------------------------------------------------------------

    However, the location of ethanol plants in relation to existing 
pipeline origination points will limit the role of existing pipelines 
in the shipment of ethanol.\164\ Current corn ethanol production 
facilities are primarily located in the Midwest far from the 
origination points of most existing product pipelines and the primary 
gasoline demand centers. We project that a substantial fraction of 
future cellulosic ethanol plants will also be located in the Midwest, 
although a greater proportion of cellulosic plants are expected to be 
dispersed throughout the country compared to corn ethanol plants. The 
projected locations for this subset of future cellulosic ethanol plants 
more closely coincide with the origination points of product pipelines 
in the Gulf Coast.\165\ Imported ethanol could also be brought into 
ports near the origination point of product pipelines in the Gulf Coast 
and the Northeast. Nevertheless, the majority of ethanol will continue 
to be produced at locations distant from the origination points of 
product pipelines and gasoline demand centers. The gathering of ethanol 
from production facilities located in the Midwest and shipment by barge 
down the Mississippi for introduction to pipelines in the Gulf Coast is 
under consideration. However, the additional handling steps to bring 
the ethanol to the pipeline origin points in this manner could negate 
any potential benefit of shipment by existing petroleum pipelines 
compared to direct shipment by rail.
---------------------------------------------------------------------------

    \164\ Some small petroleum product refineries are currently 
limited in their ability to ship products by pipeline because their 
relatively low volumes were not sufficient to justify connection to 
the pipeline distribution system.
    \165\ A discussion of the projected location of cellulosic 
ethanol plants is contained in Section 1.5 of the DRIA.
---------------------------------------------------------------------------

    Evaluations are also currently underway regarding the feasibility 
of constructing a new dedicated ethanol pipeline from the Midwest to 
the East Coast.\166\ Under such an approach, ethanol would be gathered 
from a number of Midwest production facilities to provide sufficient 
volume to justify pipeline operation. To the extent that ethanol 
production would be further concentrated in the Midwest due to the 
siting of cellulosic ethanol plants, this would tend to help justify 
the cost of installing a dedicated ethanol pipeline. Substantial issues 
would need to be addressed before construction on such a pipeline could 
proceed, including those associated with securing new rights-of-ways 
and establishing sufficient surety regarding the return on the several 
billion dollar investment.
---------------------------------------------------------------------------

    \166\ Magellan and Poet joint assessment of dedicated ethanol 
pipeline: http://www.magellanlp.com/news/2009/20090316_5.htm.
---------------------------------------------------------------------------

    Due to the uncertainties regarding the degree to which pipelines 
will be able to participate in the transportation of ethanol, we 
assumed that ethanol will continue to be transported by rail, barge, 
and truck to the terminal where it will be blended into gasoline. The 
distribution by these modes can be further optimized primarily through 
the increased shipment by unit train and installation of additional hub 
delivery terminals that can accept large volumes of ethanol for further 
distribution to satellite terminals. To the extent that pipelines do 
eventually play a role in the distribution of ethanol, this could tend 
to reduce distribution costs and improve reliability in supply.
    USDA estimated that in 2005 approximately 60% of ethanol was 
transported by rail, 30% was transported by tank truck, and 10% was 
transported by barge.\167\ Denatured ethanol is shipped from 
production/import facilities to petroleum terminals where it is blended 
with gasoline. When practicable, shipment by unit train is the 
preferred method of rail shipment rather than shipping on a manifest 
rail car basis. The use of unit trains, sometimes referred to as a 
virtual pipeline, substantially reduces shipping costs and improves 
reliability. Unit trains are composed entirely of 70-100 ethanol tank 
cars, and are dedicated to shuttle back and forth to large hub 
terminals.\168\ Manifest rail car shipment refers to the shipment of 
ethanol in rail tank cars that are incorporated into trains which are 
composed of a variety of other commodities. Unit trains can be 
assembled at a single ethanol production plant or if a group of plants 
is not large enough to support such service individually, can be formed 
at a central facility which gathers ethanol from a number of producers. 
The Manly Terminal in Iowa, which is the first such ethanol gathering 
facility, accepts ethanol from a number of nearby ethanol production 
facilities for shipment by unit train. Regional (Class 2) railroad 
companies are an important link bringing ethanol to gathering 
facilities for assembly into unit trains for long-distance shipment by 
larger (Class 1) railroads. Ethanol is sometimes carried by multiple 
modes before finally arriving at the terminal where it is blended into 
gasoline. For example, some ethanol is currently shipped from the 
Midwest to a hub terminal on the East Coast by unit train where a 
portion is further shipped to satellite terminals by barge or tank 
truck.
---------------------------------------------------------------------------

    \167\ ``Ethanol Transportation Backgrounder, Expansion of U.S. 
Corn-based Ethanol from the Agricultural Transportation 
Perspective'', USDA, September 2007, http://www.ams.usda.gov/tmd/TSB/EthanolTransportationBackgrounder09-17-07.pdf.
    \168\ Hub ethanol receipt terminals can be located at large 
petroleum terminals or at rail terminals.
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    Ethanol is blended into gasoline at either 10 or 85 volume percent 
at terminals (to produce E10 and E85) for delivery to retail and fleet 
facilities by tank truck. Special retail delivery hardware is needed 
for E85 which can be used in flexible fuel vehicles only.\169\ The 
large volume of ethanol that we project will be used by 2022 means that 
more ethanol will need to be used than can be accommodated by blending 
to the current legal limit of 10% in all of the gasoline used in the 
country. This will require the installation of a substantial number of 
new E85 refueling facilities and the addition of a substantial number 
of flex-fuel vehicles to the fleet. Concerns have been raised regarding 
the inducements that would be necessary for retailers to install the 
needed E85 facilities and for consumers to purchase E85.\170\ As 
discussed in Section V.D. of today's preamble, this is prompting many 
to evaluate whether a mid-level ethanol blend (e.g. E15) might be 
allowed for use in existing (non-flex-fuel) vehicles. Current refueling 
equipment (not designed for E85) is only certified for ethanol blends 
up to 10 volume percent (E10).\171\ Hence, if a mid-level ethanol blend 
were to be introduced, fuel retail facilities would need to ensure that 
the equipment used to store/dispense mid-level ethanol

[[Page 25004]]

blends is compatible with the mid-level ethanol blend.\172\ 
Underwriters Laboratories has one certification standard for fuel 
retail equipment that covers ethanol blends up to 10%, and a separate 
certification standard for equipment that dispenses ethanol blends 
above 10% (including E85).\173\
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    \169\ The cost of retail dispensing hardware which is tolerant 
to ethanol blends greater than E10 is discussed in Section VIII.B. 
of today's preamble and discussed in more detail in Section 4.2 of 
the DRIA.
    \170\ See Section V.D of today's preamble for a discussion of 
issues related to use of the projected volumes of ethanol that would 
be produced to comply with the RFS2 standards.
    \171\ Underwriters Laboratory certifies retail refueling 
equipment. UL stated that they have data which indicates that the 
use of fuel dispensers certified for up to E10 blends to dispense 
blends up to a maximum ethanol content of 15 volume percent would 
not result in critical safety concerns (http://www.ul.com/newsroom/newsrel/nr021909.html). Based on this, UL stated that it would 
support authorities having jurisdiction who decide to permit legacy 
equipment originally certified for up to E10 blends to be used to 
dispense up to 15 volume percent ethanol. The UL announcement did 
address the compatibility of underground storage tank systems with 
greater than E10 blends.
    \172\ Although it has yet to be established, most underground 
steel storage tanks themselves would likely be compatible with 
ethanol blends greater than 10 percent. The compatibility of piping, 
submersed pumps, gaskets, and seals associated with these tanks with 
ethanol blends greater than 10% would also need to be evaluated. 
Some fiberglass tanks are incompatible and would need to be 
replaced. It is difficult and sometimes impossible to verify the 
suitability of underground storage tanks and tank-related equipment 
for E85 use. The State of California prohibits the conversion of 
underground storage tanks to E85 use. Significant changes to 
dispensers, including hoses, nozzles, and other miscellaneous 
fittings would be needed to ensure they are compatible with ethanol 
blends greater than 10 percent.
    \173\ Joint UL/DOE Legacy System Certification Clarification 
http://www.ul.com/global/eng/documents/offerings/industries/chemicals/flammableandcombustiblefluids/development/UL_DOE_LegacySystemCertification.pdf.
---------------------------------------------------------------------------

    Should other biofuels be introduced that do not require 
differentiation from diesel fuel or gasoline in place of some of the 
volume of ethanol that we project would be used under the RFS2 
standards, this may tend to reduce the need for changes at fuel retail 
facilities and the need for flex-fuel vehicles. Concerns about the 
difficulties/costs associated with expanding the ethanol distribution 
infrastructure and adding a sufficient number of vehicles capable of 
using 10% ethanol to fleet is generating increased industry interest in 
renewable diesel and gasoline which would be more transparent to the 
existing fuel distribution system.
2. Overview of Biodiesel Distribution
    Biodiesel is currently transported from production plants by truck, 
manifest rail car, and by barge to petroleum terminals where it is 
blended with petroleum-based diesel fuel. Unblended biodiesel must be 
transported and stored in insulated/heated containers in colder climes 
to prevent gelling. Insulated/heated containers are not needed for 
biodiesel that has been blended with petroleum-based diesel fuel (i.e., 
B2, B5). Biodiesel plants are not as dependent on being located close 
to feedstock sources as are corn and cellulosic ethanol plants.\174\ 
Biodiesel feedstocks are typically preprocessed to oil prior to 
shipment to biodiesel production facilities. This can substantially 
reduce the volume of feedstocks shipped to biodiesel plants relative to 
ethanol plants, and has allowed some biodiesel plants to be located 
adjacent to petroleum terminals. Biodiesel production facilities are 
more geographically dispersed than ethanol facilities and the 
production volumes also tend to be smaller than ethanol 
facilities.\175\ These characteristics in combination with the smaller 
volumes of biodiesel that we project will be used under the RFS2 
standards compared to ethanol allow relatively more biodiesel to be 
used within trucking distance of the production facility. However, we 
project that there will continue to be a strong and growing demand for 
biodiesel as a blending component in heating oil which could not be 
satisfied alone by local sources of production. It is likely that state 
biodiesel mandates will also need to be satisfied in part by out-of-
state production. Fleets are also likely to continue to be a 
substantial biodiesel user, and these will not always be located close 
to biodiesel producers. Thus, we are assuming that a substantial 
fraction of biodiesel will continue to be shipped long distances to 
market. Downstream of the petroleum terminal, B2 and B5 can be 
distributed in the same manner as petroleum diesel.
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    \174\ Biodiesel feedstocks are typically preprocessed to oil 
prior to shipment to biodiesel production facilities. This can 
substantially reduce the volume of feedstocks shipped to biodiesel 
plants relative to ethanol plants.
    \175\ Section 1.2 contains a discussion of our projections 
regarding the location of biodiesel production facilities.
---------------------------------------------------------------------------

    Concerns remain regarding the shipment of biodiesel by pipeline 
(either by batch mode or in blends with diesel fuel) related to the 
contamination of other products (particularly jet fuel), the solvency 
of biodiesel, and compatibility with pipeline gaskets and seals.\176\ 
The smaller anticipated volumes of biodiesel and the more dispersed and 
smaller production facilities relative to ethanol also make biodiesel a 
less attractive candidate for shipment by pipeline. Due to the 
uncertainties regarding the suitability of transporting biodiesel by 
pipeline, we assumed that biodiesel which needs to be transported over 
long distance will be carried by manifest rail car and to a lesser 
extent barge. Due to the relatively small plant size and dispersion of 
biodiesel plants, we anticipate the volumes of biodiesel that can be 
gathered at a single location will continue to be insufficient to 
justify shipment by unit train. To the extent that pipelines do 
eventually play a role in the distribution of biodiesel, this could 
tend to reduce distribution costs and improve reliability in supply.
---------------------------------------------------------------------------

    \176\ Industry evaluations are currently underway to resolve 
these concerns.
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3. Overview of Renewable Diesel Distribution
    We believe that renewable diesel fuel will be confirmed to be 
sufficiently similar to petroleum-based diesel fuel blendstocks with 
respect to distribution system compatibility. Hence, renewable diesel 
fuel could be treated in the same manner as any petroleum-based diesel 
fuel blendstock with respect to transport in the existing petroleum 
distribution system. Approximately two-thirds of renewable diesel fuel 
is projected to be produced at petroleum refineries.\177\ The transport 
of such renewable diesel fuel would not differ from petroleum-based 
diesel fuel since it would be blended to produce a finished diesel fuel 
before leaving the refinery. The other one-third of renewable diesel 
fuel is projected to be produced at stand-alone facilities located more 
closely to sources of feedstocks. We anticipate that such renewable 
diesel fuel would be shipped by tank truck to nearby petroleum 
terminals where it would be blended directly into diesel fuel storage 
tanks. Because of its high cetane and value, we anticipate that all 
renewable diesel fuel would likely be blended with petroleum based 
diesel fuel prior to use. Downstream of the terminal, renewable/
petroleum diesel fuel mixtures would be distributed the same as 
petroleum diesel.
---------------------------------------------------------------------------

    \177\ Either co-processed with crude oil or processed in 
separate units at the refinery for blending with other refinery 
diesel blendstocks.
---------------------------------------------------------------------------

4. Changes in Freight Tonnage Movements
    To evaluate the magnitude of the challenge to the distribution 
system up to the point of receipt at the terminal, we compared the 
growth in freight tonnage for all commodities from the AEO 2007 
reference case to the growth in freight tonnage under the RFS2 
standards in which ethanol increases, as does the feedstock (corn) and 
co-products (distillers grains). We did not include a consideration of 
the distribution of cellulosic ethanol feedstocks on freight tonnage 
for the proposal. We intend to evaluate this in the final rule. For 
purposes of this analysis, we focused on only the ethanol portion of 
the renewable fuel goals for ease of calculation and because ethanol 
represents the vast majority of the total volume of biofuel. The 
resulting calculations serve as an indicator of changes in freight 
tonnages associated with increases in renewable fuels. We calculated 
the freight tonnage for the total of all modes of transport as well as 
the individual cases of rail, truck, and barge.

[[Page 25005]]

    In calculating the reference case percent growth rate in total 
freight tonnage, we used data compiled by the Federal Highway 
Administration to calculate the tonnages associated with these 
commodities.\178\ We then calculated the growth in freight tonnage for 
2022 under the RFS2 standards and compared the difference with the 
reference case. The comparisons indicate that across all transport 
modes, the incremental increase in freight tonnage of ethanol and 
accompanying feedstocks and co-products associated with the increased 
ethanol volume under the RFS2 standards are small. The percent increase 
for total freight across all modes (including pipeline) by 2022 is 0.9 
percent. Because pipelines currently do not carry ethanol, and the 
increase in the volume of ethanol used in motor vehicles displaces a 
corresponding volume of gasoline, pipelines showed a decrease in the 
total tonnage carried due to a decrease in the volume of gasoline 
carried by pipeline. The displaced gasoline also resulted in some 
decrease in tonnage in other modes that slightly reduced the overall 
increases in tonnage reflected in the totals.
---------------------------------------------------------------------------

    \178\ http://www.ops.fhwa.dot.gov/freight/freight_analysis/faf/index.htm.
---------------------------------------------------------------------------

    To further evaluate the magnitude of the increase in freight 
tonnage under the RFS2 standards, we calculated the portion of the 
total freight tonnage for rail, barge, and truck modes made up of 
ethanol-related freight for both the 2022 and control cases. The 
freight associated with ethanol constitutes only a very small portion 
of the total freight tonnage for all commodities. Specifically, ethanol 
freight represents approximately 0.5% and 2.5% of total freight for the 
reference case and RFS2 standards case, respectively. The results of 
this analysis suggest that it should be feasible for the distribution 
infrastructure upstream of the terminal to accommodate the additional 
freight associated with this RFS2 standards especially given the lead 
time available. Specific issues related to transportation by rail, 
barge, and tank truck are discussed in the following sections. We 
intend to incorporate the results of a recently completed study by Oak 
Ridge National Laboratory (ORNL) on the potential constraints in 
ethanol distribution into the analysis for the final rule.\179\ The 
ORNL study concluded that the increase in ethanol transport would have 
minimal impacts on the overall transportation system. However, the ORNL 
study did identify localized areas where significant upgrades to the 
rail distribution system would likely be needed.
---------------------------------------------------------------------------

    \179\ ``Analysis of Fuel Ethanol Transportation Activity and 
Potential Distribution Constraints'', prepared for EPA by Oak Ridge 
National Laboratory, March 2009.
---------------------------------------------------------------------------

5. Necessary Rail System Accommodations
    Many improvements to the freight rail system will be required in 
the next 15 years to keep pace with the large increase in the overall 
freight demand. Improvements to the freight railroad infrastructure 
will be driven largely by competition in the burgeoning inter-model 
transport sector. As inter-model freight represents the vast majority 
of all freight hauled by these railroads, the biofuels transport sector 
can be expected to benefit from the infrastructure build-out resulting 
from inter-model transport sector competition. As such, most of the 
needed upgrades to the rail freight system are not specific to the 
transport of renewable fuels and would be needed irrespective of 
today's proposed rule. We also expect that the excess rail capacity 
associated with inter-model build-out to be adequately large to absorb 
potential increases in truck transport associated with fuel cost 
increases. The modifications required to satisfy the increase in demand 
include upgrading tracks to allow the use of heavier trains at faster 
speeds, the modernization of train braking systems to allow for 
increased traffic on rail lines, the installation of rail sidings to 
facilitate train staging and passage through bottlenecks.
    Some industry groups \180\ and governmental agencies in discussions 
with EPA, and in testimony provided for the Surface Transportation 
Board (STB) expressed concerns about the ability of the rail system to 
keep pace with the large increase in demand even under the reference 
case (27% by 2022). For example, the electric power industry has had 
difficulty keeping sufficient stores of coal in inventory at power 
plants due to rail transport difficulties and has expressed concerns 
that this situation will be exacerbated if rail congestion worsens. One 
of the more sensitive bottleneck areas with respect to the movement of 
ethanol from the Midwest to the East coast is Chicago. The City of 
Chicago commissioned its own analysis of rail capacity and congestion, 
which found that the lack of rail capacity is ``no longer limited to a 
few choke points, hubs, and heavily utilized corridors.'' Instead, the 
report finds, the lack of rail capacity is ``nationwide, affecting 
almost all the nation's critically important trade gateways, rail hubs, 
and intercity freight corridors.''
---------------------------------------------------------------------------

    \180\ Industry groups include the Alliance of Automobile 
Manufacturers, American Chemistry Council, and the National 
Industrial Transportation League; governmental agencies include the 
Federal Railroad Administration (FRA), the Government Accountability 
Office (GAO), and the American Association of State Highway 
Transportation Officials (AASHTO). Testimony for the STB public 
hearings includes Ex Parte No. 671, Rail Capacity and Infrastructure 
Requirements and Ex Parte No. 672, Rail Transportation and Resources 
Critical to the Nation's Energy Supply.
---------------------------------------------------------------------------

    Significant private and public resources are focused on making the 
modifications to the rail system to cope with the increase in demand. 
Rail carriers report that they typically invest $16 to $18 billion a 
year in infrastructure improvements.\181\ Substantial government loans 
are also available to small rail companies to help make needed 
improvements by way of the Railroad Rehabilitation and Improvement 
Finance (RRIF) Program, administered by Federal Railroad Administration 
(FRA), as well as Section 45G Railroad Track Maintenance Credits, 
offered by the Internal Revenue Service (IRS). The American Association 
of State Highway Transportation Officials (AASHTO) estimates that 
between $175 billion and $195 billion must be invested over a 20-year 
period to upgrade the rail system to handle the anticipated growth in 
freight demand, according to the report's base-case scenario.\182\ The 
report suggests that railroads should be able to provide up to $142 
billion from revenue and borrowing, but that the remainder would have 
to come from other sources including, but not limited, to loans, tax 
credits, sale of assets, and other forms of public-sector 
participation. Given the reported historical investment in rail 
infrastructure, it may be reasonable to assume that rail carriers would 
be able to manage the $7.1 billion in annual investment from rail 
carriers that AASHTO projects would be needed to keep pace with the 
projected increase in freight demand.
---------------------------------------------------------------------------

    \181\ ``The Importance of Adequate Rail Investment'', 
Association of American Railroads, http://www.aar.org/GetFile.asp?File_ID=150.
    \182\ AASHTO Freight-Rail Bottom-Line Report, 2003.
---------------------------------------------------------------------------

    However, the Government Accounting Office (GAO) found that it is 
not possible to independently confirm statements made by Class I rail 
carriers regarding future investment plans.\183\ In

[[Page 25006]]

addition, questions persist regarding allocation of these investments, 
with the Alliance of Automobile Manufacturers, American Chemistry 
Council, National Industrial Transportation League, and others 
expressing concern that their infrastructural needs may be neglected by 
the Class I railroads in favor of more lucrative intermodal traffic. 
Moreover, the GAO has raised questions regarding the competitive nature 
and extent of Class I freight rail transport. This raises some concern 
that providing sufficient resources to facilitate the transport of 
increasing volumes of ethanol and biodiesel might not be a first 
priority for rail carriers. In response to GAO concerns, the Surface 
Transportation Board (STB) agreed to undertake a rigorous analysis of 
competition in the freight railroad industry.\184\
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    \183\ The railroads interviewed by GAO were generally unwilling 
to discuss their future investment plans with the GAO. Therefore, 
GAO was unable to comment on how Class I freight rail companies are 
likely to choose among their competing investment priorities for the 
future, including those of the rail infrastructure, GAO testimony 
Before the Subcommittee on Surface Transportation and Merchant 
Marine, Senate Committee on Commerce, Science, and Transportation, 
U.S. Senate, Freight Railroads Preliminary Observations on Rates, 
Competition, and Capacity Issues, Statement of JayEtta Z. Hecker, 
Director, Physical Infrastructure Issues, GAO, GAO-06-898T 
(Washington, DC: June, 21, 2006).
    \184\ GAO, Freight Railroads: Industry Health Has Improved, but 
Concerns about Competition and Capacity Should Be Addressed, GAO-07-
94 (Washington, DC: Oct. 6, 2006); GAO, Freight Railroads: Updated 
Information on Rates and Other Industry Trends, GAO-07-291R Freight 
Railroads (Washington, DC: Aug. 15, 2007). STB's final report, 
entitled Report to the U.S. STB on Competition and Related Issues in 
the U.S. Freight Railroad Industry, is expected to be completed 
November, 1, 2008.
---------------------------------------------------------------------------

    Given the broad importance to the U.S. economy of meeting the 
anticipated increase in freight rail demand, and the substantial 
resources that seem likely to be focused on this cause, we believe that 
overall freight rail capacity would not be a limiting factor to the 
successful implementation of the biofuel requirements to meet the RFS2 
standards. Evidence from the recent ramp up of ethanol use has also 
shown that rail carriers are enthusiastically pursuing the shipment of 
ethanol. Class 2 railroads have been particularly active in gathering 
sufficient numbers of ethanol cars to allow Class 1 railroads to ship 
ethanol by unit train. Likewise, we believe that that Class 2 railroads 
and, to a lesser extent, the trucking industry, will play a key role in 
the transportation of DDGs and other byproducts from regions with 
concentrated ethanol production facilities to those with significant 
livestock operations. Based on this recent experience, we believe that 
ethanol will be able to compete successfully with other commodities in 
securing its share of freight rail service.
    While many changes to the overall freight rail system are expected 
to occur irrespective of today's proposed rule, a number of ethanol-
specific modifications will be needed. For instance, a number of 
additional rail terminals are likely to be configured for receipt of 
unit trains of ethanol for further distribution by tank truck or other 
means to petroleum terminals. The placement of ethanol unit train 
receipt facilities at rail terminals would be particularly useful in 
situations where petroleum terminals might find it difficult or 
impossible to install their own ethanol rail receipt capability. We 
anticipate that ethanol storage will typically be installed at rail 
terminal ethanol receipt hubs over the long run. We do not anticipate 
that the rail industry will experience substantial difficulty in 
installing such ethanol-specific facilities once a clear long term 
demand for ethanol in the target markets has been established to 
justify the investment. However, the need for long-term demand to be 
established prior to the construction of such facilities will likely 
mean that the needed facilities will, at best, come on-line on a just-
in-time basis. This may lead to use of less efficient means of ethanol 
transport in the short term. The ability to rely on transloading while 
ethanol storage facilities at rail terminal ethanol receipt hub 
facilities are constructed will speed the optimization of the 
distribution of ethanol by rail by allowing the construction of ethanol 
storage at rail terminal hubs to be delayed.
    We estimate that a total of 44,000 rail cars would be needed to 
distribute the volumes of ethanol and biodiesel that we project would 
be used in 2022 to satisfy the RFS2 requirements.\185\ Our analysis of 
ethanol and biodiesel rail car production capacity indicates that 
access to these cars should not represent a serious impediment to 
meeting the requirements under the RFS2 standards. Ethanol tank car 
production has increased approximately 30% per year since 2003, with 
over 21,000 tank cars expected to be produced in 2007. The volume of 
these newly-produced tank cars, coupled with that of an existing tank 
car fleet already dedicated to ethanol and biodiesel transport, 
suggests that an adequate number of these tank cars will be in place to 
transport the proposed renewable fuel volume requirements in the time 
available.
---------------------------------------------------------------------------

    \185\ A discussion of how we arrived at the estimated number of 
tank cars needed is contained in Section 4.2 of the DRIA.
---------------------------------------------------------------------------

    We request comment on the extent to which the rail system will be 
able to deliver the additional volumes of ethanol and biodiesel that we 
anticipate would be used in response to the RFS2 standards in a timely 
and reliable fashion. A recently completed report by ORNL identifies 
specific segments of the rail system which would likely see the most 
significant increase in traffic due to increased shipments of ethanol 
under the EISA.\186\
---------------------------------------------------------------------------

    \186\ ``Analysis of Fuel Ethanol Transportation Activity and 
Potential Distribution Constraints'', prepared for EPA by Oak Ridge 
National Laboratory, March 2009.
---------------------------------------------------------------------------

6. Necessary Marine System Accommodations
    The American Waterway's Association has expressed concerns about 
the need to upgrade the inland waterway system in order to keep pace 
with the anticipated increase in overall freight demand. The majority 
of these concerns have been focused on the need to upgrade the river 
lock system on the Mississippi River to accommodate longer barge tows 
and on dredging inland waterways to allow for movement of fully loaded 
vessels. We do not anticipate that a substantial fraction of renewable/
alternative fuels will be transported via these arteries. Thus, we do 
not believe that the ability to ship ethanol/biodiesel by inland marine 
will represent a serious barrier to the implementation of 
implementation of the requirements under RFS2 standards. Substantial 
quantities of the corn ethanol co-product dried distiller grains (DDG) 
is expected to be exported from the Midwest via the Mississippi River 
as the U.S. demand for DDG becomes saturated. We anticipate that the 
volume of exported DDG would take the place of corn that would be 
shifted from export to domestic use in the production of ethanol. Thus, 
we do not expect the increase in DDG exports to result in a substantial 
increase in river freight traffic. We request comment on the extent to 
which marine transport may be used in the transport of cellulosic 
ethanol feedstocks.
7. Necessary Accommodations to the Road Transportation System
    Concerns have been raised regarding the ability of the trucking 
industry to attract a sufficient number of drivers to handle the 
anticipated increase in truck freight.\187\ The American Trucking 
Association projected the need for additional 54,000 drivers each year. 
We estimate that the growth in the use of biofuels through 2022 due to 
the RFS2 standards would result in the need for a total of 
approximately 3,000

[[Page 25007]]

additional trucks drivers. Given the relatively small number of new 
truck drivers needed to transport the volumes of biofuels needed to 
comply with the RFS2 standards through 2022 compared to the total 
expected increase in demand for drivers over the same time period 
(>750,000), we do not expect that the implementation of the RFS2 
standards would substantially impact the potential for a shortage of 
truck drivers. However, specially certified drivers are required to 
transport ethanol and biodiesel because these fuels are classified as 
hazardous liquids. Thus, there may be a heightened level of concern 
about the ability to secure a sufficient number of such specially 
certified tank truck drivers to transport ethanol and biodiesel. The 
trucking industry is involved in efforts to streamline the 
certification of drivers for hazardous liquids transport and more 
generally to attract and retrain a sufficient number of new truck 
drivers.
---------------------------------------------------------------------------

    \187\ ``The U.S. Truck Driver Shortage: Analysis and 
Forecasts'', Prepared by Global Insights for the American Trucking 
Association, May 2005. http://www.truckline.com/NR/rdonlyres/E2E789CF-F308-463F-8831-0F7E283A0218/0/ATADriverShortageStudy05.pdf.
---------------------------------------------------------------------------

    Truck transport of biofuel feedstocks to production plants and 
finished biofuels and co-products from these plants is naturally 
concentrated on routes to and from these production plants. This may 
raise concerns about the potential impact on road congestion and road 
maintenance in areas in the proximity of these facilities. We do not 
expect that such potential concerns would represent a barrier to the 
implementation of the RFS2 standards. The potential impact on local 
road infrastructure and the ability of the road network to be upgraded 
to handle the increased traffic load is an inherent part in the 
placement of new biofuel production facilities. Consequently, we expect 
that any issues or concerns would be dealt with at the local level.
    We request comment on the extent to which satisfying the 
requirements under the RFS2 standards might exacerbate the anticipated 
shortage of truck drivers or lead to localized road congestion and 
condition problems. Comment is further requested on the means to 
mitigate such potential difficulties to the extent they might exist.
8. Necessary Terminal Accommodations
    Terminals will need to install additional storage capacity to 
accommodate the volume of ethanol/biodiesel that we anticipate will be 
used in response to the RFS2 standards. Questions have been raised 
about the ability of some terminals to install the needed storage 
capacity due to space constraints and difficulties in securing 
permits.\188\ Overall demand for fuel used in spark ignition motor 
vehicles is expected to remain relatively constant through 2022. Thus, 
much of the demand for new ethanol and biodiesel storage could be 
accommodated by modifying storage tanks previously used for the 
gasoline and petroleum-based diesel fuels that would displaced by 
ethanol and biodiesel. The areas served by existing terminals also 
often overlap. In such cases, one terminal might be space constrained 
while another serving the same area may be able to install the 
additional capacity to meet the increase in demand. Terminals with 
limited ethanol storage (or no access to rail/barge ethanol shipments) 
could receive truck shipments of ethanol from terminals with more 
substantial ethanol storage (and rail/barge receipt) capacity. The 
trend towards locating ethanol receipt and storage capability at rail 
terminals located near petroleum terminals is likely to be an important 
factor in reducing the need for large volume ethanol receipt and 
storage facilities at petroleum terminals. In cases where it is 
impossible for existing terminals to expand their storage capacity due 
to a lack of adjacent available land or difficulties in securing the 
necessary permits, new satellite storage or new separate terminal 
facilities may be needed for additional ethanol and biodiesel storage. 
However, we believe that there would be few such situations.
---------------------------------------------------------------------------

    \188\ The Independent Fuel Terminal Operators Association 
represents terminals in the Northeast.
---------------------------------------------------------------------------

    Another question is whether the storage tank construction industry 
would be able to keep pace with the increased demand for new tanks that 
would result from today's proposal. The storage tank construction 
industry recently experienced a sharp increase in demand after years of 
relatively slack demand for new tankage. Much of this increase in 
demand was due to the unprecedented increase in the use of ethanol. 
Storage tank construction companies have been increasing their 
capabilities which had been pared back during lean times.\189\ Given 
the projected gradual increase in the need for biofuel storage tanks, 
it seems reasonable to conclude that the storage tank construction 
industry would be able to keep pace with the projected demand.
---------------------------------------------------------------------------

    \189\ It currently may take 4 to 8 months to begin construction 
of a storage tank after a contract is signed due to tightness in 
construction assets and steel supply.
---------------------------------------------------------------------------

    The RFG and anti-dumping regulations currently require certified 
gasoline to be blended with denatured ethanol to produce E85. The 
gasoline must meet all applicable RFG and anti-dumping standards for 
the time and place where it is sold. We understand that some parties 
may be blending butanes and or pentanes into gasoline before it is 
blended with denatured ethanol in order to meet ASTM minimum volatility 
specifications for E85 that were set to ensure proper drivability, 
particularly in the winter.\190\ If terminal operators add blendstocks 
to finished gasoline for use in manufacturing E85, the terminal 
operator would need to register as a refiner with EPA and meet all 
applicable standards for refiners.
---------------------------------------------------------------------------

    \190\ ``Specification for Fuel Ethanol (Ed75-Ed85) for Spark-
Ignition Engines'', American Society for Testing and Materials 
standard ASTM D5798.
---------------------------------------------------------------------------

    Recent testing has shown that much of in-use E85 does not meet 
minimum ASTM volatility specifications.\191\ However, it is unclear if 
noncompliance with these specifications has resulted in a commensurate 
adverse impact on drivability. This has prompted a re-evaluation of the 
fuel volatility requirements for in-use E85 vehicles and whether the 
ASTM E85 volatility specifications might be relaxed.\192\ For the 
purpose of our analysis, we are assuming that certified gasoline 
currently on hand at terminals can be used to make up the non-ethanol 
portion of E85.\193\
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    \191\ Coordinating Research Council (CRC) report No. E-79-2, 
Summary of the Study of E85 Fuel in the USA Winter 2006-2007, May 
2007. http://www.crcao.org/reports/recentstudies2007/E-79-2/E-79-2%20E85%20Summary%20Report%202007.pdf.
    \192\ CRC Cold Start and Warm-up E85 Driveability Program, 
http://www.crcao.com/about/Annual%20Report/2007%20Annual%20Report/Perform/CM-133.htm.
    \193\ This is different from the approach taken in the refinery 
modeling which assumed that special blendstocks would be used to 
blend E85. A discussion of the refinery modeling can be found in 
Section 4 of the DRIA.
---------------------------------------------------------------------------

    We request comment on the extent that this will be the case in 
light of the projected outcome of the ASTM process. Comment is 
requested on the fraction of terminals that currently have butane/
pentane blending capability and the logistical/cost implications of 
adding such capability including sourcing and transportation issues 
associated with supplying these blending components to the terminal for 
the purpose of blending E85 to ASTM specifications. We also seek 
comment on whether we should include a separate section in the RFS2 
regulations to specify the requirements for producing E85, and whether 
we should provide E85 manufacturers who use blendstocks to produce E85 
with any flexibilities in complying with the refiner requirements.\194\
---------------------------------------------------------------------------

    \194\ Certain accommodations for butane blenders into gasoline 
were provided in a direct final rule published on December 15, 2005 
entitled, ``Modifications to Standards and Requirements for 
Reformulated and Conventional Gasoline Including Butane Blenders and 
Attest Engagements'', 70 FR 74552.

---------------------------------------------------------------------------

[[Page 25008]]

    A significant challenge facing terminals and one that is currently 
limiting the volume of ethanol that can be used is the ability to 
receive ethanol by rail. Only a small fraction of petroleum terminals 
currently have rail receipt capability and a number likely have space 
constraints or are located too far from the rail system which prevents 
the installation of such capability. The trend to locate ethanol unit 
train destinations at rail terminals will help to alleviate these 
concerns. Petroleum terminals within trucking distance of each other 
are also likely to cooperate so that only one would need to install 
rail receipt capability. Given the timeframe during which the projected 
volumes of ethanol ramp up, we believe that these means can be utilized 
to ensure that a sufficient number of terminals have access to ethanol 
shipped by rail although some will need to rely on secondary shipment 
by truck from large ethanol hub receipt facilities. We request comment 
on the current rail receipt capability at terminals and the extent to 
which petroleum terminals can be expected to install such capability. 
Comment is also requested on the extent to which the installation of 
ethanol receipt facilities at rail terminals can help to meet the need 
to bring ethanol by rail to petroleum terminals. Our current analysis 
estimated that half of the new ethanol rail receipt capability needed 
to support the use of the projected ethanol volumes under the EISA 
would be installed at petroleum terminals, and half would be installed 
at rail terminals. A recently completed study by ORNL estimated that 
all new ethanol rail receipt capability would be installed at existing 
rail terminals given the limited ability to install such capability at 
petroleum terminals.\195\ We intend to review our estimates regarding 
the location of the additional ethanol rail receipt facilities for the 
final rule in light of the ORNL study.
---------------------------------------------------------------------------

    \195\ ``Analysis of Fuel Ethanol Transportation Activity and 
Potential Distribution Constraints'', prepared for EPA by Oak Ridge 
National Laboratory, March 2009.
---------------------------------------------------------------------------

9. Need for Additional E85 Retail Facilities
    We estimate that an additional 24,250 E85 retail facilities would 
be needed to facilitate the consumption of the additional amount of 
ethanol that we project would be used by 2022 in response to the 
requirements under the RFS2 standards.\196\ On average, this equates to 
approximately 1,960 new E85 facilities that would need to be added each 
year from 2009 through 2022 in order to satisfy this goal. This is a 
very ambitious timeline given that there are less than 2,000 E85 retail 
facilities in service today. Nevertheless, we believe the addition of 
these numbers of new E85 facilities may be possible for the industries 
that manufacture and install E85 retail equipment. Underwriters 
Laboratories recently finalized its certification requirements for E85 
retail equipment.\197\ Equipment manufactures are currently evaluating 
the changes that will be needed to meet these requirements.\198\ 
However, we anticipate the needed changes will not substantially 
increase the difficulty in the manufacture of such equipment compared 
to equipment which is specifically manufactured for dispensing E85 
today.
---------------------------------------------------------------------------

    \196\ See Section 1.6 of the DRIA for a discussion of the 
projected number of E85 refueling facilities that would be needed. 
There would need to be a total of 28,750 E85 retail facilities, 
4,500 of which are projected to have been placed in service absent 
the RFS2 standards.
    \197\ See http://ulstandardsinfonet.ul.com/outscope/0087A.html.
    \198\ All dispenser equipment except the hose used to dispense 
fuel to the vehicle has been evaluated by UL. Once suitable hoses 
have been evaluated, a complete E85 dispenser system can be 
certified by UL.
---------------------------------------------------------------------------

    We estimate that the cost of installing E85 refueling equipment 
will average $122,000 per facility which equates to $3 billion by 
2022.\199\ These costs include the installation of an underground 
storage tank, piping, dispensers, leak detection, and other ancillary 
equipment that is compatible with E85.\200\ Our E85 facility cost 
estimates are based on input from fuel retailers and other parties with 
familiarity in installing E85 compatible equipment. We understand that 
a certification has yet to be finalized by Underwriters Laboratories 
for a complete equipment package necessary to store/dispense E85 at a 
retail facility.\201\ Thus, there is some uncertainty regarding the 
type of equipment that will be needed for compliance with the E85 
equipment certification requirements, and the associated costs. 
Nevertheless, we believe that the E85 equipment that is eventually 
certified for use will not be substantially different from that on 
which our cost estimates are based.\202\
---------------------------------------------------------------------------

    \199\ See Section 4.2 of the DRIA for a discussion of E85 
facility costs. These costs include the installation of 2 pumps with 
4 E85 refueling positions at 40% of new facilities, and 1 pump with 
2 refueling positions at 60% of new facilities. A sensitivity case 
was evaluated where it was assumed that all new E85 facilities would 
install 3 pumps with 6 refueling positions. The cost per facility 
under this sensitivity case is $166,000.
    \200\ 40 CFR 280.32 requires that underground storage tank 
systems must be made of or lined with materials that are compatible 
with the substance stored in the system.
    \201\ Underwriters Laboratories recently finalized their 
requirements for the certification of E85 compatible equipment. No 
certifications have been completed to date, because of the time 
needed to complete the application for certification including 
necessary testing.
    \202\ All retail dispenser components except the hose that 
connects the nozzle to the dispenser have been evaluated by UL. Once 
such hoses have been evaluated by UL, a certification for the 
complete fuel dispenser assembly may be finalized by UL.
---------------------------------------------------------------------------

    Petroleum retailers expressed concerns about their ability to bear 
the cost installing the needed E85 refueling equipment. Today's 
proposal does not contain a requirement for retailers to carry E85. We 
understand that retailers will only install E85 facilities if it is 
economically advantageous for them to do so and that they will price 
their E85 and E10 in a manner to recover these costs. While the $3 
billion total cost for E85 refueling facilities is a substantial sum, 
it equates to just 1.5 cents per gallon of E85 throughput.\203\ 
Therefore, we do not believe that the cost of installing E85 refueling 
equipment will represent an undue burden to retailers given the very 
large projected consumer demand for E85.
---------------------------------------------------------------------------

    \203\ E85 facility costs were amortized over 15 years at 7% and 
the costs spread over the projected volume of E85 dispensed.
---------------------------------------------------------------------------

    Petroleum retailers also expressed concern regarding their ability 
to discount the price of E85 sufficiently to persuade flexible fuel 
vehicle owners to choose E85 given the lower energy density of ethanol. 
This issue is discussed in Section V.D.2.e. of today's preamble.

D. Ethanol Consumption

1. Historic/Current Ethanol Consumption
    Ethanol and ethanol-gasoline blends have a long history as 
automotive fuels. However, cheap gasoline/blendstocks kept ethanol from 
making a significant presence in the transportation sector until the 
end of the 20th century when environmental regulations and tax 
incentives helped to stimulate growth.
    In 1978, the U.S. passed the Energy Tax Act which provided an 
excise tax exemption for ethanol blended into gasoline that would later 
be modified through subsequent regulations.\204\ In the 1980s, EPA 
initiated a phase-out of leaded gasoline which created some interest in 
ethanol as a gasoline

[[Page 25009]]

oxygenate. Upon passage of the 1990 CAA amendments, states implemented 
winter oxygenated fuel (``oxyfuel'') programs to monitor carbon 
monoxide emissions. EPA also established the reformulated gasoline 
(RFG) program to help reduce emissions of smog-forming and toxic 
pollutants. Both the oxyfuel and RFG programs called for oxygenated 
gasoline. However, petroleum-derived ethers, namely methyl tertiary 
butyl ether (MTBE), dominated oxygenate use until drinking water 
contamination concerns prompted a switch to ethanol. Additional support 
came in 2004 with the passage of the Volumetric Ethanol Excise Tax 
Credit (VEETC). The VEETC provided domestic ethanol blenders with a 
$0.51/gal tax credit, replacing the patchwork of existing 
subsidies.\205\ The phase-out of MTBE and the introduction of the VEETC 
along with state mandates and tax incentives created a growing demand 
for ethanol that surpassed the traditional oxyfuel and RFG markets. By 
the end of 2004, not only was ethanol the lead oxygenate, it was found 
to be blended into a growing number of states' conventional 
gasoline.\206\
---------------------------------------------------------------------------

    \204\ Gasohol, a fuel containing at least 10% biomass-derived 
ethanol, received a partial exemption from the federal gasoline 
excise tax. This exemption was implemented in 1979 and a blender's 
tax credit and a pure alcohol fuel credit were added to the mix in 
1980.
    \205\ The 2008 Farm Bill, discussed in more detail in Section 
V.B.2.b, replaces the $0.51/gal ethanol blender credit with a $0.45/
gal corn ethanol blender credit and also introduces a $1.01/gal 
cellulosic biofuel producer credit. Both credits are effective 
January 1, 2009.
    \206\ Based on 2004 Federal Highway Association (FHWA) State 
Gasohol Report less estimated RFG and oxyfuel ethanol usage based on 
EPA's 2004 RFG Fuel Survey results and knowledge of state oxyfuel 
programs and fuel oxygenates. For more on historical ethanol usage 
by state and fuel type, refer to Section 1.7.1.1 of the DRIA.
---------------------------------------------------------------------------

    In the years that followed, rising crude oil prices and other 
favorable market conditions continued to drive ethanol usage. In May 
2007, EPA promulgated a Renewable Fuel Standard (``RFS1'') in response 
to EPAct. The RFS1 program set a floor for renewable fuel use reaching 
7.5 billion gallons by 2012, the majority of which was ethanol. The 
country is currently on track for exceeding the RFS1 requirements and 
meeting the introductory years of today's proposed RFS2 program. For a 
summary of the growth in U.S. ethanol usage over the past decade, refer 
to Table V.D.1.-1.

       Table V.D.1-1--U.S. Ethanol Consumption (Including Imports)
------------------------------------------------------------------------
                                                  Total ethanol use \a\
                                               -------------------------
                     Year                         Trillion
                                                    BTU          Bgal
------------------------------------------------------------------------
1999..........................................          120          1.4
2000..........................................          138          1.6
2001..........................................          144          1.7
2002..........................................          171          2.0
2003..........................................          233          2.8
2004..........................................          292          3.5
2005..........................................          334          4.0
2006..........................................          451          5.3
2007..........................................          566          6.7
2008..........................................          792          9.4
------------------------------------------------------------------------
\a\ EIA Monthly Energy Review March 2009 (Table 10.2).

    Through the years, there have also been several policy initiatives 
to increase the number of flexible fuel vehicles (FFVs) capable of 
consuming up to 85 volume percent ethanol blends (E85). The Alternative 
Motor Vehicle Fuels Act of 1988 provided automakers with Corporate 
Average Fuel Economy (CAFE) credits for producing alternative-fuel 
vehicles, including FFVs as well as CNG and propane vehicles. 
Furthermore, the Energy Policy Act of 1992 required government fleets 
to begin purchasing alternative-fuel vehicles, and the majority of 
fleets chose FFVs.\207\ As a result of these two policy measures, there 
are over 7 million FFVs on the road today.\208\ These vehicles increase 
our nation's ethanol consumption potential beyond what is capable with 
conventional vehicles. However, most FFVs are currently refueling on 
conventional gasoline (E0 or E10) due to limited E85 availability and 
the fact that E85 is typically priced 20-30 cents per gallon higher 
than gasoline on an energy equivalent basis. As such, we are not 
currently tapping into the full ethanol consumption potential of our 
FFV fleet. However, we expect refueling patterns to change in the 
future under the RFS2 program.
---------------------------------------------------------------------------

    \207\ Source: June 23, 2008 Federal Times, Special Report: Fleet 
Management.
    \208\ Source: DOE Energy Efficiency and Renewable Energy 
(worksheet available at www.eere.energy.gov/afdc/data/index.html.)
---------------------------------------------------------------------------

2. Increased Ethanol Use under RFS2
    To meet the RFS2 standards, ethanol consumption will need to be 
much higher than both today's levels and those projected to occur 
absent RFS2. The Energy Information Administration (EIA) projected that 
under business-as-usual conditions, ethanol usage would grow to just 
over 13 billion gallons by 2022.\209\ This represents significant 
growth from today's usage, however, this volume of ethanol is capable 
of being consumed by today's vehicle fleet albeit with some fuel 
infrastructure improvements.\210\ Although EIA projected a small 
percentage of ethanol to be blended as E85 in 2022, 13 billion gallons 
of ethanol could also be consumed by displacing about 90% of our 
country's forecasted gasoline energy demand with E10. The maximum 
amount of ethanol our country is capable of consuming as E10 compared 
to the projected RFS2 ethanol volumes is shown below in Figure V.D.2-
1.\211\
---------------------------------------------------------------------------

    \209\ Source: EIA Annual Energy Outlook 2007, Table 17.
    \210\ For more information on distribution accommodations, refer 
to Section V.C.
    \211\ The maximum E10 volumes are a function of the gasoline 
energy demand reported in EIA's Annual Energy Outlook 2009, Table 2 
adjusted with lower heating values.

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[[Page 25010]]

[GRAPHIC] [TIFF OMITTED] TP26MY09.006

    As shown in Figure V.D.2-1, under the proposed RFS2 program, we are 
projected to hit the E10 ``blend wall'' of about 14.5 billion gallons 
of ethanol by 2013. This volume corresponds to 100% E10 nationwide. 
However, if gasoline demand falls, or if E10 cannot get distributed 
nationwide, the nation could hit the blend wall sooner. Regardless, to 
get beyond the blend wall and consume more than 14-15 billion gallons 
of ethanol, we are going to need to see significant increases in the 
number FFVs on the road, the number of E85 retailers, and the FFV E85 
refueling frequency. In the subsections that follow, we will highlight 
the variables that impact our nation's ethanol consumption potential 
and, more specifically, what measures the market may need to take in 
order to consume 34 billion gallons of ethanol by 2022 (assuming the 
cellulosic biofuel standard and the majority of the advanced biofuel 
standard are met with ethanol).
---------------------------------------------------------------------------

    \212\ Based on the assumption that the cellulosic biofuel 
standard and the majority of the advanced biofuel standard would be 
met with ethanol.
---------------------------------------------------------------------------

    As explained in Section V.A.2, our primary RFS2 analysis focuses on 
ethanol as the main biofuel in the future.\213\ In addition, from an 
ethanol consumption standpoint, we have focused on an E10/E85 world. 
While E0 is capable of co-existing with E10 and E85 for a while, we 
assumed that E10 would replace E0 as expeditiously as possible and that 
all subsequent ethanol growth would come from E85. Furthermore, for our 
primary analysis, we assumed that no ethanol consumption would come 
from the mid-level ethanol blends (i.e., E15 or E20) as they are not 
currently approved for use in non-FFVs. However, in Section V.D.3 
below, we discuss the potential approval pathways for mid-level ethanol 
blends and the volume implications.
---------------------------------------------------------------------------

    \213\ For consideration of other biofuels, refer to Section 
V.D.3.d.
---------------------------------------------------------------------------

    We acknowledge that, if approved, mid-level ethanol blends could 
help the nation meet the proposed RFS2 volume requirements. First, non-
FFVs could consume more ethanol per gallon of ``gasoline''. This could 
result in greater ethanol consumption nationwide. In addition, mid-
level blends could allow gasoline retailers to continue to price 
ethanol relative to gasoline (as it currently is for E10). For these 
reasons, it is possible that mid-level ethanol blends could help the 
nation get beyond the E10 blend wall. However, as explained in Section 
V.D.3.b, there are numerous actions that would need to be taken to 
bring mid-level ethanol blends to market. In addition, mid-level 
ethanol blends alone (even if made available nationwide) are not 
capable of fulfilling the RFS2 requirements in later years. We would 
essentially hit another blend wall 1-6 years later depending on the 
intermediate blend, how quickly it could be brought to market, and how 
widely mid-level ethanol blends were distributed at retail stations 
nationwide. Nevertheless, this time could be very valuable when it 
comes to expanding E85/FFV infrastructure and/or commercializing other 
non-ethanol cellulosic biofuels.
    Regardless, our primary analysis focuses on an E10/E85 world 
because mid-level ethanol blends are not currently approved for use in 
conventional gasoline vehicles and nonroad equipment. Before usage 
could be legalized, as discussed more in Section V.D.3 below, EPA would 
need to grant a waiver declaring that mid-level blends are 
substantially similar or ``sub-sim'' to gasoline or perhaps even 
reinterpret the meaning of ``sub-sim''. While such a waiver has not yet 
been granted, several organizations/agencies are performing vehicle 
emission testing and investigating other impacts of mid-

[[Page 25011]]

level blends.\214\ Therefore, as a sensitivity analysis, we have 
analyzed what might need to be done to bring mid-level ethanol blends 
to market (should a sub-sim waiver be approved) and the extent to which 
such blends could help our nation meet the RFS2 ethanol standards, at 
least in the near term. Finally we end our ethanol usage discussion by 
looking at other strategies for getting beyond the E10 blend wall.
---------------------------------------------------------------------------

    \214\ For more information on mid-level ethanol blends testing, 
refer to Section V.D.3.b.
---------------------------------------------------------------------------

a. Projected Gasoline Energy Demand
    The maximum amount of ethanol our country is capable of consuming 
in any given year is a function of the total gasoline energy demanded 
by the transportation sector. Our nation's gasoline energy demand is 
dependent on the number of gasoline-powered vehicles on the road, their 
average fuel economy, vehicle miles traveled (VMT), and driving 
patterns. For analysis purposes, we relied on the gasoline energy 
projections reported by EIA in AEO 2008.\215\ Unlike AEO 2007, AEO 2008 
takes the fuel economy improvements set by EISA into consideration and 
also assumes a slight dieselization of the vehicle fleet. The result is 
a 15% reduction in the projected 2022 gasoline energy demand from AEO 
2007 to AEO 2008.\216\ EIA basically has gasoline energy demand 
(petroleum-based gasoline plus ethanol) flattening out, and even 
slightly decreasing, as we move into the future and implement the EISA 
vehicle standards.\217\
---------------------------------------------------------------------------

    \215\ For blend wall discussions, we rely on the most recent AEO 
2009 projections. However for our detailed ethanol consumption 
analysis presented in this section (and in more detail in Section 
1.7.1 of the DRIA), we relied on AEO 2008.
    \216\ EIA Annual Energy Outlook 2007 & 2008, Table 2.
    \217\ For more information on gasoline energy projections, refer 
to Section 1.7.1.2.1 of the DRIA.
---------------------------------------------------------------------------

b. Projected Growth in Flexible Fuel Vehicles
    According to DOE's Department of Energy Efficiency and Renewable 
Energy, there are currently over 7 million FFVs on the road today 
capable of consuming E85.\218\ And that number is growing steadily. 
Automakers are incorporating more and more FFVs into their light-duty 
production plans. While the FFV system (i.e., fuel tank, sensor, 
delivery system, etc.) used to be an option on some vehicles, most FFV 
producers are moving in the direction of converting entire product 
lines over to E85-capable systems. Still, the number of FFVs that will 
be manufactured and purchased in future years is uncertain. For our 
cost analysis, we examined several different FFV production scenarios. 
But for our ethanol usage analysis, we focused on one primary FFV 
scenario, described in more detail below.\219\
---------------------------------------------------------------------------

    \218\ DOE Energy Efficiency and Renewable Energy August 2008 
estimate (worksheet available at www.eere.energy.gov/afdc/data/index.html).
    \219\ For more on the FFV production scenarios we considered, 
refer to Section 1.7.1.2.2 of the DRIA.
---------------------------------------------------------------------------

    In response to President Bush's ``20-in-10'' plan of reducing 
American gasoline usage by 20% in 10 years, domestic automakers 
responded with aggressive FFV production goals. General Motors, Ford 
and Chrysler (referred to hereafter as ``The Detroit 3'') announced 
plans to produce 50% FFVs by 2012.\220\ And despite the current state 
of the economy and the auto industry, it appears U.S. automakers are 
still moving forward with their FFV production plans.\221\ Assuming 
that The Detroit 3 continue to maintain 50% market share and that total 
vehicle sales remain around 16 million per year, at least 4 million 
FFVs will be produced by the 2012 model year. Based on 2008 offerings, 
we assumed that approximately 80% of The Detroit 3's FFV production 
commitment would be met by light-duty trucks and the remaining 20% 
would be cars.222 223 We also assumed that all the FFVs in 
existence today were produced by The Detroit 3 (and therefore share the 
same aforementioned car/truck ratio) and that production would ramp up 
linearly beginning in 2008 to reach the 2012 commitment.
---------------------------------------------------------------------------

    \220\ Ethanol Producer Magazine, ``View From the Hill.'' July 
2007.
    \221\ Ethanol Producer Magazine, ``Automakers Maintain FFV 
Targets in Bailout Plans.'' February 2009.
    \222\ NEVC 2008 Purchasing Guide for Flexible Fuel Vehicles.
    \223\ Several of the FFV assumptions may need to be revised for 
the FRM in light of recent events.
---------------------------------------------------------------------------

    Although non-domestic automakers have not made any official FFV 
production commitments, Nissan, Mercedes, Izuzu, and Mazda all included 
at least one flexible fuel vehicle in their 2008 model year 
offerings.\224\ And we anticipate that additional FFVs (or FFV options) 
will be added in the future. Ultimately, we predict that non-domestic 
FFV production could be as high as 25%, or about 2 million FFVs per 
year. While we are not forecasting an official FFV production 
commitment from the non-domestic automakers, we believe that this 
represents an aggressive, yet reasonable FFV production estimate for 
analysis purposes. Furthermore, based on current offerings, we assumed 
that the majority of non-domestic FFV production would be trucks. With 
respect to timing, we expect that the non-domestic automakers would 
ramp up FFV production later than The Detroit 3. For analysis purposes, 
we assumed that non-domestic automakers would ramp up FFV production 
beginning in 2013, and like The Detroit 3, it would take about five 
years for them to reach their FFV production goals (or in this case, 
the assumed 25% production level)
---------------------------------------------------------------------------

    \224\ Ibid.
---------------------------------------------------------------------------

    Based on these FFV assumptions and forecasted vehicle phase-out, 
VMT, and fuel economy estimates provided by EPA's MOVES Model, we 
calculate that the maximum percentage of fuel (gasoline/ethanol mix) 
that could feasibly be consumed by FFVs in 2022 would be about 30%. For 
more information on our FFV analysis, refer to Section 1.7.1.2.2 of the 
DRIA.
c. Projected Growth in E85 Access
    According to the National Ethanol Vehicle Coalition (NEVC), there 
are currently over 1,900 retailers offering E85 in 45 states plus the 
District of Columbia.\225\ While this represents significant industry 
growth, it still only translates to about 1% of U.S. retail stations 
nationwide carrying the fuel.\226\ As a result, most FFV owners clearly 
do not have reasonable access to E85. For our FFV/E85 analysis, we have 
defined ``reasonable access'' as one-in-four pumps offering E85 in a 
given area.\227\ Accordingly, just over 4% of the nation currently has 
reasonable access to E85, up from 3% in 2007 (based on a mid-year NEVC 
E85 pump estimate).\228\
---------------------------------------------------------------------------

    \225\ NEVC FYI Newsletter: Volume 15, Issue 5: March 9, 2009.
    \226\ Based on National Petroleum News gasoline station estimate 
of 161,768 in 2008.
    \227\ For a more detailed discussion on how we derived our one-
in-four reasonable access assumption, refer to Section 1.6 of the 
DRIA. For the distribution cost implications as well as the cost 
impacts of assuming reasonable access is greater than one-in-four 
pumps, refer to Section 4.2 of the DRIA.
    \228\ Computed as percent of stations with E85 (1,963/161,768 as 
of March 2009 or 1,251/164,292 as of July 2007) divided by 25% (one-
in-four stations).
---------------------------------------------------------------------------

    There are a number of states promoting E85 usage by offering FFV/
E85 awareness programs and/or retail pump incentives. A growing number 
of states are also offering infrastructure grants to help expand E85 
availability. Currently, nine Midwest states have adopted a progressive 
Energy Security and Climate Stewardship Platform.\229\

[[Page 25012]]

The platform includes a Regional Biofuels Promotion Plan with a goal of 
making E85 available at one third of all stations by 2025. In addition, 
on July 31, 2008, Congresswoman Stephanie Herseth Sandlin (D-SD) and 
John Shimkus (R-IL) introduced The E85 and Biodiesel Access Act that 
would amend IRS tax code and increase the existing federal income tax 
credit from $30,000 or 30% of the total cost of improvements to 
$100,000 or 50% of the total cost of needed alternative fuel equipment 
and dispensing improvements.\230\ While not signed into law, such a tax 
credit could provide a significant retail incentive to expand E85 
infrastructure.
---------------------------------------------------------------------------

    \229\ The following states have adopted the plan: Indiana, 
Kansas, Michigan, Minnesota, Ohio, South Dakota, Wisconsin, Iowa, 
and most recently, North Dakota. For more information, visit: http://www.midwesterngovernors.org/resolutions/Platform.pdf.
    \230\ A copy of House Rule 6734 can be accessed at: http://www.e85fuel.com/news/2008/080108_shimkus_release/shimkus.pdf.
---------------------------------------------------------------------------

    Given the growing number of state infrastructure incentives and the 
proposed Federal alternative fuel infrastructure subsidy, it is clear 
that E85 infrastructure will continue to expand in the future. However, 
the extent to which nationwide E85 access will grow is difficult to 
predict, let alone quantify. For analysis purposes, as a practical 
upper bound, we have selected 70% by 2022. This is roughly equivalent 
to all urban areas in the United States offering reasonable (one-in-
four-station) access to E85.\231\ We are not concluding that the 
percentage of the nation with reasonable access to E85 could not exceed 
70% (as a sensitivity, we also modeled the cost impacts of nationwide 
access to E85) or that availability would necessarily be concentrated 
in urban areas. However, for analysis purposes, we believe that 70% is 
a good surrogate for a practical portion of the country that could have 
reasonable one-in-four access to E85 by 2022 under the proposed RFS2 
program. On average, this translates to about 18% of retail stations 
nationwide offering E85. As discussed in Section V.C, we believe this 
is feasible based on our assessment of the distribution infrastructure 
capabilities. For more information on the projected growth in E85 
access, refer to Section 1.7.1.2.3 of the DRIA.
---------------------------------------------------------------------------

    \231\ For this analysis, we've defined ``urban'' as the top 150 
metropolitan statistical areas according to the U.S. census and/or 
counties with the highest VMT projections according the EPA MOVES 
model, all RFG areas, winter oxy-fuel areas, low-RVP areas, and 
other relatively populated cities in the Midwest.
---------------------------------------------------------------------------

d. Required Increase in E85 Refueling Rates
    As mentioned above, there were approximately 7 million FFVs on the 
road in 2008. If all FFVs refueled on E85 100% of the time, this would 
translate to about 6.5 billion gallons of E85 use.\232\ However, E85 
usage was only around 12 million gallons in 2008.\233\ This means that, 
on average, FFV owners were only tapping into about 0.2% of their 
vehicles' E85/ethanol usage potential last year. Assuming that only 4% 
of the nation had reasonable one-in-four access to E85 in 2008 (as 
discussed above), this equates to an estimated 5% E85 refueling 
frequency for those FFVs that had reasonable access to the fuel.
---------------------------------------------------------------------------

    \232\ Based on the assumption that FFV owners travel 
approximately 12,000 miles per year and get about 18 miles per 
gallon on average under actual in-use driving conditions. For more 
information, refer to Section 1.7.1.2.4 of the DRIA.
    \233\ EIA Annual Energy Outlook 2009, Table 17.
---------------------------------------------------------------------------

    There are several reasons for today's low E85 refueling frequency. 
For starters, many FFV owners may not know they are driving a vehicle 
that is capable of handling E85. As mentioned earlier, more and more 
automakers are starting to produce FFVs by engine/product line, e.g., 
all 2008 Chevy Impalas are FFVs.\234\ Consequently, consumers 
(especially brand loyal consumers) may inadvertently buy a flexible 
fuel vehicle without making a conscious decision to do so. And without 
effective consumer awareness programs in place, these FFV owners may 
never think to refuel on E85. In addition, FFV owners with reasonable 
access to E85 and knowledge of their vehicle's E85 capabilities may 
still not choose to refuel on E85. They may feel inconvenienced by the 
increased E85 refueling requirements. Based on its lower energy 
density, FFV owners will need to stop to refuel 21% more often when 
filling up on E85 over E10 (and likewise, 24% more often when refueling 
on E85 over conventional gasoline).\235\ In addition, some FFV owners 
may be deterred from refueling on E85 out of fear of reduced vehicle 
performance or just plain unfamiliarity with the new motor vehicle 
fuel. However, as we move into the future, we believe the biggest 
determinant will be price--whether E85 is priced competitively with 
gasoline based on its reduced energy density and the fact that you need 
to stop more often, drive a little further to find an E85 station, and 
depending on the retail configuration, wait in longer lines to fill up 
on E85.
---------------------------------------------------------------------------

    \234\ NEVC, ``2008 Purchasing Guide for Flexible Fuel 
Vehicles.'' Refers to all mass produced 3.5 and 3.9L Impalas. 
However, it is our understanding that consumers may still place 
special orders for non-FFVs.
    \235\ Based on our assumption that denatured ethanol has an 
average lower heating value of 77,930 BTU/gal and conventional 
gasoline (E0) has average lower heating value of 115,000 BTU/gal. 
For analysis purposes, E10 was assumed to contain 10 vol% ethanol 
and 90 vol% gasoline. Based on EIA's AEO 2008 report, E85 was 
assumed to contain 74 vol% ethanol and 26 vol% gasoline on average.
---------------------------------------------------------------------------

    To comply with the proposed RFS2 program and consume 34 billion 
gallons of ethanol by 2022, not only would we need more FFVs and more 
E85 retailers, we would need to see a significant increase in the 
current FFV E85 refueling frequency. Based on the FFV and retail 
assumptions described above in subsections (b) and (c), our analysis 
suggests that FFV owners with reasonable access to E85 in 2022 would 
need to fill up on it 74% of the time, a significant increase from 
today's estimated 5% refueling frequency. Were there to be fewer FFVs 
in the fleet, the E85 refueling frequency would need to be even higher. 
Similarly, with more FFVs in the fleet, the E85 refueling frequency 
could be lower and still meet the proposed RFS2 requirements. However, 
even with an FFV mandate, our analysis suggests that we would need to 
see an increase from today's average FFV E85 refueling frequency. In 
order for this to be possible, there will need to be an improvement in 
the current E85/gasoline price relationship.
e. Market Pricing of E85 Versus Gasoline
    According to a recent online fuel price survey, E85 is currently 
priced almost 30 cents per gallon higher than conventional gasoline on 
an energy-equivalent basis.\236\ To increase our nation's E85 refueling 
frequency to the levels described above, E85 needs to be priced 
competitively with (if not lower than) conventional gasoline based on 
its reduced energy content, increased time spent at the pump, and 
limited availability. Our analysis, described in more detail in Section 
1.7.1.2.5 of the DRIA, suggests that E85 would need to be priced about 
one-third lower than gasoline at retail (based on 2006 prices) in order 
for it to be cost-competitive. As expected, higher crude prices could 
make E85 look slightly more attractive while lower crude oil prices 
could make E85 look less attractive.
---------------------------------------------------------------------------

    \236\ Based on average E85 and regular unleaded gasoline prices 
reported at http://www.fuelgaugereport.com/ on April 23, 2009.
---------------------------------------------------------------------------

    In Brazil, charts are posted at gas stations informing flex-fuel 
vehicle owners whether it makes sense to fill up on ``gasoline'' 
(containing 20-25% denatured anhydrous ethanol) \237\ or ``alcohol'' 
(100% denatured hydrous ethanol) based on the price and relative energy 
density of each. However, in the U.S., FFV owners will likely be on 
their

[[Page 25013]]

own for figuring out which fuel is more economical.
---------------------------------------------------------------------------

    \237\ The government-mandated gasoline ethanol content was 25% 
as of July 2007. Source: F.O. Licht World Ethanol & Biofuels Report 
Vol. 5 No. 21 July 9, 2007.
---------------------------------------------------------------------------

    Although in some areas of the country E85 is already priced 
significantly lower than gasoline, this is a far cry from a nationwide 
trend. And as we move into the future and incorporate cellulosic 
ethanol (a fuel that is currently more expensive to produce than corn 
ethanol), it may be even more difficult to produce ethanol for a price 
that the market would accept. However, a number of measures could be 
taken to help encourage FFV E85 refueling.
    The first is increased consumer awareness. To maximize ethanol 
usage, it is important that FFV owners are aware of their vehicle's 
fueling capabilities, i.e., that their vehicle is capable of refueling 
on E85. It is equally important that FFV owners are aware of E85 
refueling outlets that may be available to them. Automakers and/or car 
dealerships could notify FFV owners of E85 stations in their area. 
Together, increased automaker and retail awareness could help increase 
our nation's E85 throughput potential. However, in order for consumers 
to actually choose E85 over conventional gasoline on a regular basis, 
there needs to be a marked price incentive at the pump.
    Current federal and most state tax code does not differentiate 
between ethanol sold as E10 and as E85. As of July 2008, state excise 
taxes were reported to account for more than $0.18 per gallon of 
gasoline (on average).\238\ However, there are a number of states 
(e.g., Illinois, Indiana, North Dakota, and South Dakota) that 
currently waive or discount excise taxes on E85. This type of fuel tax 
structure helps contribute to a retail price relationship that favors 
E85 over conventional gasoline.\239\ If states continue to waive/reduce 
E85 fuel taxes under RFS2, this could help increase the FFV E85 
refueling frequency. As expected, this would have the greatest impact 
on ethanol consumption in the areas of the country with the most FFVs.
---------------------------------------------------------------------------

    \238\ Source: The American Petroleum Institute July 2008 
Gasoline Tax Report available at: http://www.api.org/statistics/fueltaxes/upload/July_2008_gasoline_and_diesel_summary_pages.pdf.
    \239\ Source: DOE Energy Efficiency and Renewable Energy Web 
site (http://www.eere.energy.gov/).
---------------------------------------------------------------------------

    The E10/E85 price relationship could also be modified by the 
refining industry. Under the proposed program, gasoline refiners (as 
well as importers) would be required to purchase RINs to demonstrate 
that sufficient volumes of renewable/alternative fuels were used to 
meet their volume obligations. This could provide an incentive for 
these parties to take the steps necessary to ensure adequate ethanol 
use levels to facilitate compliance. One potential action that refiners 
might take to ensure a sufficient RIN supply would be to subsidize the 
price of the ethanol used to manufacture E85. Such a subsidy might be 
financed by an increase in their selling price of gasoline. In 
addition, refiners with marketing arms could adjust the retail price 
relationship of E10 in E85 in way that encourages E85 throughput while 
still maintaining the same average net profit. However, a relatively 
small proportion of refiners market their own gasoline and thus have 
the ability to make retail price adjustments. Consequently, relying 
solely on market mechanisms may create some competitive concerns. We 
request comment on viable and cooperative ways refiners and gasoline 
retailers could promote E85 throughput to meet the proposed RFS2 
requirements.
3. Other Mechanisms for Getting Beyond the E10 Blend Wall
a. Mandate for FFV Production
    One way to increase ethanol usage under RFS2 would be if there were 
more FFVs in the fleet. As described above, our primary analysis is 
based on the assumption that The Detroit 3 would follow through with 
their commitment to produce 50% FFVs by 2012 and the non-domestic 
automakers would ramp up FFV production beginning in 2013 and produce 
25% FFVs by 2017. Based on the projected number of FFVs in the fleet 
(and our E85 infrastructure growth assumptions), FFV owners with 
reasonable one-in-four access to E85 would need to refuel on it 74% of 
the time. To achieve this optimistic refueling frequency, we believe 
there would need to be significant improvements to the E10/E85 price 
relationship.
    One way to reduce the required FFV E85 refueling frequency (and in 
turn decrease some of the pressure off E85 prices) would be to further 
increase the number of FFVs in the fleet. While EPA does not have the 
authority to require automakers to produce FFVs, there are a number of 
bills in Congress that are set out to do just that. On July 22, 2008 
Senator Sam Brownback (R-KS) on behalf of himself and Senators Susan 
Collins (R-ME), Joseph Lieberman (I-CT), Ken Salazar (D-CO), and John 
Thune (R-SD) introduced the Open Fuel Standard Act of 2008, a bill that 
calls for 50% of the U.S. vehicle fleet to be FFVs capable of using 
high blends of ethanol or methanol (in addition to gasoline) by 2012. 
This number would grow to 80% by 2015.\240\ A similar FFV bill was 
introduced by Eliot Engel (D-NY) in the House on July 22, 2008.\241\
---------------------------------------------------------------------------

    \240\ Refer to Senate Bill 3303 which can be found at: http://thomas.loc.gov/cgi-bin/query/z?c110:S.3303.
    \241\ Refer to House Rule 6559 which can be found at: http://thomas.loc.gov/cgi-bin/bdquery/z?d110:H.R.6559.
---------------------------------------------------------------------------

    Since a future congressional mandate on FFV production in being 
discussed, we have modeled the impact that such a mandate could have on 
the RFS2 program. For our sensitivity analysis, we found that if 
automakers were required to make all light-duty vehicles E85-capable by 
2015 (and our same E85 infrastructure growth assumptions applied), FFV 
owners with reasonable one-in-four access to E85 would only need to 
refuel on it 33% of the time. This represents a smaller increase from 
today's estimated 5% refueling rate. However, implementing such a FFV 
mandate would have significant cost implications on the auto industry 
and would still not provide certainty that FFV owners would fuel on 
E85. For more information on this analysis, as well as other FFV 
production scenarios we considered, refer to Section 1.7.1.2.2 of the 
DRIA.
b. Waiver of Mid-Level Ethanol Blends (E15/E20)
    For our primary ethanol usage analysis, we considered that there 
would only be two fuels in the future, E10 and E85. And as explained in 
Section V.D.2, we believe it is feasible to consume 34 billion gallons 
of ethanol by 2022 given growth in FFV production and E85 availability 
and projected improvements in the current E10/E85 price relationship.
    However, several organizations and government entities are 
interested in increasing the concentration of ethanol beyond the 
current 10% limit in the commercial gasoline pool. Section 211(f)(1) of 
the Clean Air Act prohibits the introduction into commerce, or increase 
in the concentration in use of, gasoline or gasoline additives for use 
in motor vehicles unless they are substantially similar to the gasoline 
or gasoline additives used in the certification of new motor vehicles 
or motor vehicle engines. EPA may grant a waiver of this prohibition 
under Section 211(f)(4) provided that the fuel or fuel additive ``will 
not cause or contribute to a failure of any emission control device or 
system (over the useful life of the motor vehicle, motor vehicle 
engine, nonroad engine or nonroad vehicle in which the device or system 
is used) to achieve compliance by the vehicle or engine with the 
emission standards to

[[Page 25014]]

which it has been certified.'' The most recent ``substantially 
similar'' interpretive rule for unleaded gasoline presently allows 
oxygen content up to 2.7% by weight for certain ethers and 
alcohols.\242\ E10 contains approximately 3.5% oxygen by weight, which 
makes a gasoline-ethanol blend with ten% ethanol not ``substantially 
similar'' to certification fuel under the current interpretation.\243\ 
Since any mid-level blend would have a greater than allowed oxygen 
content, any mid-level blend would need to have a waiver under Section 
211(f)(4) of the CAA in order to be sold commercially.
---------------------------------------------------------------------------

    \242\ 73 FR 22277 (April 25, 2008).
    \243\ Gas Plus, Inc. submitted an application for a 211(f)(4) 
waiver for E10 which was granted, see 44 FR 20777 (April 6, 1979).
---------------------------------------------------------------------------

    Before EPA grants a 211(f)(4) waiver for a new fuel or fuel 
additive, an applicant must prove that the new fuel or fuel additive 
will meet the waiver requirements outlined in the statute. EPA has 
required that applicants provide vehicle/engine testing for tailpipe 
emissions, evaporative emissions, materials compatibility, and 
driveability. Testing needs to include emissions over the full useful 
life of vehicle and equipment. Several interested parties are 
investigating the impact that mid-level ethanol blends (e.g., E15 or 
E20) may have on these areas among others (i.e. catalyst, engine, and 
fuel system durability, and onboard diagnostics). In order to use the 
information collected for waiver application purposes, the mid-level 
ethanol blend testing will need to consider the different engines and 
fuel systems currently in service that could be exposed to mid-level 
ethanol blends and the long-term impact of using such blends.\244\ 
After receiving a waiver application, EPA must give public notice and 
comment and has 270 days to grant or deny the waiver request.
---------------------------------------------------------------------------

    \244\ EPA has expressed what such a waiver testing program might 
look like, see Karl Simon, ``Mid Level Ethanol Blend Experimental 
Framework: Epa Staff Recommendations,'' June 2008, and Ed Nam 
``Vehicle Selection & Sample Size Issues for Catalyst and Evap 
Durability Testing,'' November 2008, in the docket (EPA-HQ-OAR-2005-
0161).
---------------------------------------------------------------------------

    The Department of Energy (DOE) has developed and initiated a 
comprehensive testing program to investigate the potential impacts of 
mid-level blends of ethanol. Initial testing was conducted on a limited 
number of high-volume vehicles and small non-road engines and a 
preliminary report was published in October, 2008.\245\ In addition, 
DOE is in the process of leveraging existing EPA vehicle and small 
engine test programs (originally designed to test up to 10% ethanol) to 
add mid-level ethanol blends to the fuel matrix. DOE's comprehensive 
test program is intended to evaluate a wide range of emission, 
performance, and durability issues associated with mid-level ethanol 
blends (additional reports forthcoming).
---------------------------------------------------------------------------

    \245\ Effects of Intermediate Ethanol Blends on Legacy Vehicles 
and Small Non-Road Engines, Report 1, Prepared by Oak Ridge National 
Laboratory for the Department of Energy, October 2008.
---------------------------------------------------------------------------

    DOE is not alone in pursuing mid-level blends. In 2005, the State 
of Minnesota, a large producer of corn ethanol, passed a law requiring 
that by 2015, 20% of gasoline (by volume) must be replaced by ethanol. 
While this level could be achieved with a high percentage of E85 usage 
by FFVs, the state has also expressed an interest in moving to 20% 
ethanol blends. Several other states and organizations have also 
expressed interest in increasing ethanol use by adopting E15 or E20. 
The Renewable Fuels Association (RFA) and the American Coalition for 
Ethanol (ACE) have been working with various government entities to 
investigate the impact of mid-level blends
    On March 6, 2009, Growth Energy and 54 ethanol manufacturers 
submitted an application for a waiver of the prohibition of the 
introduction into commerce of certain fuels and fuel additives set 
forth in section 211(f) of the Act. This application seeks a waiver for 
ethanol-gasoline blends of up to 15 percent by volume ethanol. The 
statute directs the Administrator of EPA to grant or deny this 
application within 270 days of receipt by EPA, in this instance 
December 1, 2009. EPA recently issued a federal register notice 
announcing receipt of the Growth Energy waiver application and 
soliciting comment on all aspects of it. Refer to 74 FR 18228 (April 
21, 2009).
    While the current Growth Energy waiver application is still under 
review, as a sensitivity, we considered the implications that adding 
E15 or E20 to the marketplace could have on ethanol usage and the 
supporting fuel infrastructure should such blends be permitted. For 
each case, we assumed that E10 would need to continue to remain in 
existence to meet the demand of legacy vehicle and non-road engine 
owners. This would also provide consumer choice. Experience in past 
fuel programs has shown that many consumers will not be comfortable 
refueling on higher ethanol blends and will blame any problems that may 
occur on the new fuel (regardless of the actual cause of the vehicle 
problems) causing a backlash against the new fuel requirements. 
Therefore, we believe it is critical to continue to allow consumers the 
choice between mid-level ethanol blends and conventional gasoline 
(assumed to be E10 in the future).
    For our optimistic mid-level ethanol blends scenario, we assumed 
that E15 or E20 could be available at all retail stations nationwide by 
the time the nation hits the E10 blend wall, or around 2013. This 
assumes a number of actions are taken to bring mid-level blends to 
market (explained in more detail below).\246\ We assumed that E10 would 
be marketed as premium-grade gasoline, the mid-level ethanol blend (E15 
or E20) would serve as regular, and like today, midgrade would be 
blended from the two fuels. Those vehicles and equipment which are 
unable to refuel on mid-level ethanol blends (or choose not to) could 
continue to fill up on E10. This mid-level ethanol blends scenario, 
described in more detail in Section 1.7.1.3 of the DRIA, concluded that 
if mid-level ethanol blends were to be distributed at all retail 
stations nationwide, they could help increase ethanol usage to over 19 
billion gallons (with E15) and 25 billion gallons (with E20).
---------------------------------------------------------------------------

    \246\ Results for other cases are discussed in Section 1.7.1.3 
of the DRIA.

---------------------------------------------------------------------------

[[Page 25015]]

[GRAPHIC] [TIFF OMITTED] TP26MY09.007

    As shown in Figure V.D.2-2, in this optimistic phase-in scenario, 
adding E15 could postpone the blend wall by about three years to 2016 
and adding E20 could postpone it another three years to 2019. Although 
mid-level ethanol blends will fall short of meeting the RFS2 
requirements, they could provide interim relief while the county ramps 
up E85/FFV infrastructure and/or finds other non-ethanol alternatives 
(e.g., cellulosic diesel or biobutanol) to reach the RFS2 volumes.
    Our nation's whole system of gasoline fuel regulation, fuel 
production, fuel distribution, and fuel use is built around gasoline 
with ethanol concentrations limited to E10. As a result, while a waiver 
may legalize the use of mid-level ethanol blends under the CAA, there 
are a number of other actions that would have to occur to bring mid-
level blends to retail. The time needed to take these actions could 
delay the penetration of mid-level ethanol blends into the market. The 
CAA only provides a 1 pound RVP waiver for ethanol blends of 10 volume 
percent or less. Lacking such an RVP waiver, a special low-RVP gasoline 
blendstock would be needed at terminals to allow the formulation of 
mid-level ethanol blends that are complaint with EPA RVP requirements. 
Providing such a separate gasoline blendstock would present significant 
logistical challenges and costs to the fuel distribution system.\247\ A 
number of changes would be needed to EPA regulations including those 
pertaining to reformulated gasoline, anti-dumping, and gasoline deposit 
control additives to accommodate and mid-level ethanol blends. Such 
changes would need to be made through the notice and comment process 
similar to today's action. In addition, most states require that fuel 
comply with the applicable ASTM International (formally known as the 
American Standards for Testing and Materials) specification. The 
development of an ASTM International specification for mid-level 
ethanol blends through an industry consensus process is currently being 
initiated.
---------------------------------------------------------------------------

    \247\ It may be possible for refiners to formulate a gasoline 
blendstock that would be suitable for manufacturing mid-level 
ethanol blends and E10 at the terminal. While this would avoid the 
logistical problems associated with maintaining separate 
blendstocks, there could be significant additional refining costs.
---------------------------------------------------------------------------

    There are a number of requirements regarding the fire and leak 
protection safety of retail fuel dispensing and storage equipment. The 
Occupational Safety and Health Administration (OSHA) requires that 
retail fuel handling equipment be listed with an independent standards 
body such as Underwriters Laboratories (UL). No independent standards 
body has listed fuel handling equipment for mid-level ethanol blends. 
Furthermore, UL has stated that it would not expand listings for in-use 
fuel retail equipment originally listed for E10 blends to cover greater 
than E10 blends.\248\ EPA's Office of Underground Storage Tanks (OUST) 
requires that UST systems must be compatible with the fuel stored in 
the system. These requirements pertain to all components of the system 
including the storage tank, connecting piping, pumps, seals and leak 
detection equipment.
---------------------------------------------------------------------------

    \248\ UL stated that they have data which indicates that the use 
of fuel dispensers certified for up to E10 blends to dispense blends 
up to a maximum ethanol content of 15 volume percent would not 
result in critical safety concerns (http://www.ul.com/newsroom/newsrel/nr021909.html). Based on this, UL stated that it would 
support authorities having jurisdiction who decide to permit legacy 
equipment originally certified for up to E10 blends to be used to 
dispense up to 15 volume percent ethanol. The UL announcement did 
address the compatibility of underground storage tank systems with 
greater than E10 blends.
---------------------------------------------------------------------------

    States typically adopt fire safety codes from either the National 
Fire Protection Association (NFPA) or the International Code Council 
(ICC). These organizations currently do not have provisions that would 
allow the mid-level ethanol blends to be stored/dispensed from existing 
equipment at retail. Local safety officials (e.g. fire marshals) 
referred to as ``Authorities Having Jurisdiction'' (AHJ's) often 
require a UL certification for fuel retail storage/dispensing equipment 
although some will accept

[[Page 25016]]

other substantiation of equipment safety such as a manufacture 
certification. Fuel retailers must also satisfy the requirements of the 
insurance company that they are insured through which may be more 
stringent than the legal requirements. Given the liability concerns 
associated with leaks from underground storage tanks, these issues have 
to be resolved in order to facilitate the widespread use of mid-level 
ethanol blends.
    The Department of Energy and EPA are currently working with 
industry to evaluate what changes may be necessary to underground 
storage tank systems, fuel dispensers, and refueling vapor recovery 
equipment at fuel retail facilities to handle a mid-level ethanol 
blend. If existing equipment proves tolerant to a mid-level ethanol 
blend, this could substantially facilitate its introduction at retail. 
If the data supports the suitability of legacy retail equipment to 
store/dispense a mid-level blend, then the process of seeking 
acceptance by the standard bodies discussed above could commence. The 
normal processes used by these standards bodies can be lengthy. For 
example, the NFPA has a 3 year cycle for evaluating changes to its 
codes with proposals for the current cycle due this June. Thus, apart 
from the need to technically evaluate the suitability of legacy retail 
equipment to handle a mid-level ethanol blend, the need to secure 
recognition from standards bodies could delay the introduction of a 
mid-level ethanol blend at retail should a waiver be granted by EPA.
    If some components of the above-ground existing retail hardware are 
found to be incompatible with a mid-level ethanol blend, it may be 
possible for them to be replaced through normal attrition. For example 
the ``hanging hardware'' which includes the nozzle and hose from the 
dispenser is typically replaced every 3 to 5 years. It is also possible 
that only minor changes might be needed to equipment that has a longer 
service life which might be accomplished without too much difficulty/
cost. However, if extensive new equipment is needed and particularly if 
this involves the breaking of concrete, we believe that it is unlikely 
that fuel retailer would opt to install equipment specifically for a 
mid-level ethanol blend given the projected future need for retail 
equipment capable of handling E85.\249\
---------------------------------------------------------------------------

    \249\ As discussed previously, significant penetration of E85 is 
projected to be needed to facilitate the use of the volumes of 
ethanol we project would be needed to satisfy the requirements of 
the EISA.
---------------------------------------------------------------------------

    Finally, all vehicles and nonroad equipment currently in use are 
only warranted for ethanol levels not exceeding E10 (except for FFVs), 
and the owner's manuals are written to reflect this. Before widespread 
acceptance of mid-level ethanol blends by consumers can occur, these 
warranty issues would need to be addressed.
c. Partial Waiver for Mid-Level Blends
    CAA section 211(f)(4), the waiver provision, states that the 
Administrator may grant a fuel waiver if a fuel manufacturer can 
demonstrate that the fuel ``will not cause or contribute to a failure 
of any emission control device or system (over the useful life of the 
motor vehicle, motor vehicle engine, nonroad engine or nonroad vehicle 
in which such device or system is used) to achieve compliance by the 
vehicle or engine with the emission standards with respect to which it 
has been certified.'' For reasons discussed below, it may be possible 
that these criteria for a mid-level blend waiver may be met for a 
subset of gasoline vehicles or engines but not for all gasoline 
vehicles or engines. The waiver criteria are applied over the useful 
life of ``the motor vehicle, motor vehicle engine, nonroad engine or 
nonroad vehicle in which such device or system is used.'' Assuming the 
criteria is met for a certain subset of vehicles, and that adequate 
measures could be put in place to ensure that a waiver fuel were only 
used in that subset of vehicles or engines, one interpretation of this 
provision is that the waiver could apply only to that subset of 
vehicles or engines.
    One potential outcome from a review of the entire body of 
scientific and technical information available may be an indication 
that mid-level ethanol blends could meet the criteria of a section 
211(f)(4) waiver for some vehicles and engines but not for others. It 
may be that certain vehicles and engines operate as intended using mid-
level blends but others may be more susceptible to emissions increases 
or durability problems. For example, vehicles or engines without newer 
technology that do not readily adjust for the higher oxygen level in 
the fuel may experience problems, while newer technology vehicles such 
as those meeting our Tier 2 standards may be able to adjust for such 
changes as a result of more advanced emissions and fuel control 
equipment. Nonroad engines, which are typically small, are likely to be 
most susceptible given the less sophisticated technology associated 
with such engines. Given this potential outcome, EPA requests comment 
on all aspects, both legal and technical, as to the possibility that a 
section 211(f)(4) waiver might be granted, in a partial way with 
conditions, such that the use of mid-level blends would be restricted 
to a subset of the gasoline vehicles or engines covered by the waiver 
provision, while those nonroad engines and vehicles not covered by the 
waiver would continue using fuels with blends no greater than E10.
    Any waiver approval, either fully or partially, is likely to elicit 
a market response to add E15 blends to E10 and E0 blends in the 
marketplace, rather than replace them. Thus consumers would merely have 
an additional choice of fuel.
    Experience in past fuel programs has shown that even with consumer 
education and fuel implementation efforts, there sometimes continues to 
be public concern for new fuel requirements. Several examples include 
the phasedown of the amount of lead allowed in gasoline in the 1980s 
and the introduction of reformulated gasoline (RFG) in 1995. Some 
segments of the public were convinced that the new fuels caused vehicle 
problems or decreases in fuel economy. Although substantial test data 
proved otherwise, these concerns lingered in some cases for several 
years. As a direct result of these experiences, EPA wants to be assured 
that prior to potentially granting a waiver for mid-level blends, 
sufficient testing has been conducted to demonstrate the compatibility 
of a waiver fuel with engine, fuel and emission control system 
components.
    EPA has previously granted waivers with certain restrictions or 
conditions. Among other things, these restrictions have included 
requiring fuels to meet certain voluntary consensus-based gasoline 
standards such as those developed by the American Society of Testing 
and Materials (ASTM standards), requirements that precautions be taken 
to prevent using the waiver fuel as a base fuel for adding oxygenates, 
and that certain corrosion inhibitors be utilized when producing the 
waived fuel.\250\ However, in those waivers, the conditions placed upon 
the fuel manufacturer were directly related to manufacturing the fuel 
itself. Here, the conditions placed upon the fuel manufacturer would be 
on the use of the fuel in certain vehicles or engines. In other words, 
the fuel manufacturer would have to ensure that the mid-level blend was 
only used in that particular subset of vehicles or engines to be able 
to legally manufacture and sell the fuel

[[Page 25017]]

under the terms of the waiver. Since it would become the fuel 
manufacturer's responsibility to prevent misfueling, the following 
discussion highlights some of the ideas that the fuel manufacturer 
could implement, based on particular subsets of vehicles,\251\ to 
prevent misfueling.
---------------------------------------------------------------------------

    \250\ See, for example, 53 FR 3636, February 8, 1988, and 53 FR 
33846, September 1, 1988.
    \251\ Although it is not possible at this time to know the 
contours of a partial waiver with conditions, or even if one might 
be appropriate, the remainder of this discussion will refer only to 
vehicles covered by the waiver (and not engines) since newer 
vehicles are more likely to have more sophisticated emissions and 
fuel control equipment, while certain engines might be more affected 
for the reasons stated above.
---------------------------------------------------------------------------

    If a partial waiver covered only newly manufactured vehicles, 
methods focused on the manufacturing of the vehicle could be utilized 
to inform the buyer that the vehicle was capable of operating on the 
waiver fuel. In this case, approaches such as the use of vehicle 
fueling inlet labels and owner's manuals could be utilized in tandem 
with retail station fuel dispenser labels. Such an approach depends on 
the attention of the vehicle operator to ensure compliance with the 
waiver. Additionally, retail station attendants could be trained to 
provide guidance to operators on which vehicles are covered under the 
waiver.
    If only vehicles of certain model years were covered, owners would 
know if they could utilize the mid-level blends simply by knowing the 
model year (again, in tandem with pump labeling). Alternatively, if 
some portion of the existing fleet, not based upon model-year (such as 
vehicles meeting EPA Tier 2 emission standards), would also be covered, 
the approach would have to include some means by which the operator of 
such a vehicle would be made aware that the vehicle being fueled was 
covered or not covered by the waiver. Such an approach would likely 
involve notification of owners of covered vehicles, through direct 
contact or education campaigns, and would likely require the assistance 
of the vehicle manufacturers. This approach, as with other approaches, 
would require pump labeling.
    Other approaches may bring about tighter control of misfueling 
situations but may present additional challenges. For example, one 
approach might be to provide owners of covered vehicles with a 
transaction card similar to a credit card that could be swiped at the 
dispenser to allow for the dispensing of a waived mid-level blend. 
Presumably, software and/or hardware at dispensing pumps may be able to 
be adjusted to accommodate such an approach. Some retail station chains 
have already utilized transponder mechanisms to record sales. Similar 
transponder systems could be utilized in place of transaction cards.
    The above discussion is not meant to be an exhaustive list of 
possible approaches for ensuring compliance with a partial waiver, nor 
does it explore all the facets of any single approach. EPA recognizes 
that there may be legal and practical limitations on what a fuel 
manufacturer may be able to do to ensure compliance with the conditions 
of the partial waiver. EPA has not previously imposed this type of 
``downstream'' condition on the fuel manufacturer as part of a section 
211(f)(4) waiver. EPA does, however, have experience with compliance 
problems occurring when two types of gasoline have been available at 
service stations. Beginning in the mid-1970s with the introduction of 
unleaded gasoline and continuing into the 1980s as leaded gasoline was 
phased out, there was significant intentional misfueling by consumers. 
At the time most service stations had pumps dispensing both leaded and 
unleaded gasoline and a price differential as small as a few cents per 
gallon was enough to cause some consumers to misfuel. Higher price 
differentials could occur if, as expected, mid-level ethanol blends 
were to be marketed as the regular grade and E0 or E10 as the premium 
grade. The Agency seeks comment regarding whether this is a reasonable 
or practical condition for this type of waiver. EPA acknowledges that 
the issue of misfueling would be challenging in a situation where a 
partial waiver is granted. Therefore, EPA solicits comments on what 
measures a fuel manufacturer, EPA or others in the gasoline 
distribution network could take for ensuring compliance with a partial 
waiver.
    While EPA has not analyzed the specific cost of a conditional 
waiver, such a waiver would likely carry a cost similar to the costs 
described above in Section V.D.3.b. Because existing equipment in 
retail stations is certified by Underwriters Laboratories only up to 
ten percent ethanol, existing equipment would need to be evaluated for 
its acceptability for use with mid-level blends (and deemed to be 
acceptable if possible) or it would have to be modified/replaced before 
any ethanol blend greater than ten percent could be effectuated in the 
marketplace.\252\ If existing retail equipment is found not to be 
acceptable for storing/dispensing mid-level blends, the aforementioned 
infrastructure challenges would be present and additional costs would 
be associated with measures adopted for the prevention of releases due 
to material incompatibility, as well as those associated with 
misfueling. EPA therefore seeks comment on the compatibility of the 
existing retail fuel storage/dispensing equipment with mid-level 
ethanol blends. Further, adoption of such a waiver would mean that 
fewer vehicles/engines would be able to utilize mid-level blends and, 
therefore, the full impact of mid-level blends on the E10 blend wall 
under such a scenario would not be as significant as full unrestricted 
utilization of such blends.
---------------------------------------------------------------------------

    \252\ See previous discussion in Section V.D.3.b of this 
preamble regarding the issues that would need to be addressed to 
facilitate the introduction of mid-level ethanol blends at retail.
---------------------------------------------------------------------------

d. Non-Ethanol Cellulosic Biofuel Production
    While our analysis describes possible pathways by which the market 
could meet the RFS2 requirements with 34 billion gallons of ethanol as 
E10 and E85, our analysis of the required FFV and E85 infrastructure 
growth as well as the required changes to the E10/E85 price 
relationship suggests some inherent challenges. Furthermore, we 
conclude that the introduction of mid-level ethanol blends (contingent 
upon waiver approval) would by itself not allow the country to achieve 
the RFS2 standards. Another means of achieving the RFS2 volume 
requirements would be through the introduction of non-ethanol 
cellulosic biofuels. The growing spread in gasoline and diesel pricing 
implies that we are currently moving in the direction of being 
oversupplied with gasoline and undersupplied with diesel.\253\ As such, 
it makes sense that the market might preferentially investigate diesel 
fuel replacements, e.g., cellulosic diesel via Fischer-Tropsch 
synthesis, pyrolysis, or catalytic depolymerization. These fuels would 
meet the definition of cellulosic biofuel (as well as advanced biofuel) 
under the proposed RFS2 program and help reduce the ethanol blend wall 
impacts associated with this rule. Although for our analysis we assumed 
that the cellulosic biofuel standard would be met with ethanol, the 
market could choose a significant volume of other non-ethanol renewable 
fuels. DOE and other agencies are currently providing grants to support 
critical

[[Page 25018]]

research into these second-generation cellulosic feedstock conversion 
technologies. DOE is also providing loan guarantees to help with the 
commercialization of such technologies. For more information on non-
ethanol cellulosic biofuels, refer to Section V.A. or Section 1.4.3 of 
the DRIA.
---------------------------------------------------------------------------

    \253\ According to EIA, gasoline and diesel prices were pretty 
similar on average for a decade from 1995-2004. However, over the 
past four years, diesel prices have begun to track consistently 
higher than gasoline prices. To date in 2008, diesel has been priced 
more than $0.50/gallon higher than gasoline on average. Source: 
http://tonto.eia.doe.gov/oog/info/gdu/gasdiesel.asp.
---------------------------------------------------------------------------

e. Measurement Tolerance For E10
    Some stakeholders have suggested that the implementation of a 
tolerance in the measurement of the ethanol content of gasoline could 
allow more ethanol to be used in existing vehicles without the need for 
a formal waiver and without the need for more FFVs. Such a tolerance 
could allow ethanol contents slightly higher than 10 volume percent 
while still treating such blends as meeting the 10 volume percent 
limitation on the ethanol content of gasoline.
    Although there is no explicit written precedent for permitting 
ethanol contents higher than 10 vol%, some have speculated that current 
vehicles would not exhibit any noticeable change in performance, 
durability, or emissions if a small measurement tolerance for ethanol 
content of gasoline were allowed. The current specified test method for 
oxygen content ASTM D-5599-00 includes estimates of the measurement 
reproducibility that could be used to inform the determination of an 
appropriate tolerance for ethanol content in gasoline. For instance, 
based on the provided reproducibility, a measurement as high as 11 vol% 
ethanol in gasoline might be possible for gasoline that was blended to 
meet a 10 vol% ethanol requirement. Historically, however, EPA has 
always enforced the 10 vol% waiver at the 10 vol% level without any 
tolerance.
    The 1978 gasohol waiver application requested a blend of 90% 
unleaded gasoline and 10% anhydrous ethanol. Although not specified in 
the application, the convention and the practical approach for blending 
ethanol into gasoline in 1978 was by volume, and it has continued to be 
by volume. Thus, the limit on ethanol in gasoline under the waiver is 
10% by volume. This is approximately 3.5% oxygen by weight. The waiver 
request did not apply to a level of ethanol in gasoline beyond 10%, and 
since the application was approved by default after 180 days due to the 
fact that the Administrator did not make an explicit decision in this 
timeframe, there is no formal approval that could have indicated what 
measurement tolerances might have been acceptable. Thus it has 
historically been enforced at the 10 vol% limit without any enforcement 
tolerance. However, parties who have raised this option have suggested 
that the Agency's previous treatment of the oxygenate content of 
gasoline may provide a precedent that would allow for a higher 
measurement tolerance for ethanol content.
    Prior to and after 1981, several waivers issued by the Agency 
allowed the use of various alcohols and ethers in unleaded gasoline. In 
1981, the ``substantially similar'' interpretive rule for unleaded 
gasoline allowed certain alcohols and ethers at up to 2.0% oxygen by 
weight. In 1991 the limit was increased to 2.7% oxygen by weight. For 
each of these waivers, the unleaded gasoline base to which the 
oxygenate was to be added was to be initially free of oxygenate. With 
the exception of ethanol, oxygenates, mostly MTBE, were blended at the 
refinery, with the refiner in control of the gasoline used for 
blending. This enabled the refiner to ensure that it was free of 
oxygenate prior to blending. Ethanol was primarily blended at 
terminals. In order to ensure that gasoline blended with ethanol at the 
terminal was free of other oxygenates, the ethanol blender first had to 
check for the presence of other oxygenates in the base gasoline. In the 
mid-1980's ethanol blenders informed EPA that they were having 
difficulty finding oxygenate-free gasoline. Much of gasoline had at 
least trace amounts of MTBE due to commingling of gasolines with 
different oxygenates in the fungible pipeline system. In order to 
continue to allow the blending of ethanol up to the 10 vol% limit, EPA 
issued a letter stating that it would not consider it to be a violation 
of the ethanol sub-sim waiver if up to 10% by volume ethanol were added 
to unleaded gasoline containing no more than 2% by volume MTBE. 
However, the MTBE must have been present only as a result of 
commingling during storage or transport and not purposefully added as 
an additional component to the ethanol blend.
    Subsequently, two other statements by EPA provided guidance on the 
allowable oxygen content of oxygenated fuels. For instance, in a 
memorandum dated October 5, 1992, EPA provided interim guidance for 
states that allowed averaging programs.\254\ This guidance allowed the 
oxygen content of ethanol to be as high as 3.8% by weight, but did not 
indicate that the ethanol concentration could be higher than 10 vol%. 
Also, in a 1995 RFG/Anti-dumping Q&A it was noted that the maximum 
oxygen range for the simple and complex models was 4.0% by weight. This 
range was implemented to once again continue to allow the blending of 
ethanol up to the 10 vol% limit in cases where an extremely low 
gasoline density might increase the calculated weight percent oxygen 
content for E10 above the more typical 3.5-3.7 wt% range.
---------------------------------------------------------------------------

    \254\ Memorandum from Mary T. Smith, Director of the Field 
Operations and Support Division, to State/Local Oxygenated Fuels 
Contacts, October 5, 1992. Subject: ``Testing Tolerance''.
---------------------------------------------------------------------------

    Although we acknowledge that the currently specified test method 
ASTM D-5599-00 includes some variability, ethanol is different than 
many other fuel properties and components that are controlled in other 
fuel programs in one important respect. Fuel properties such as RVP, 
and components such as sulfur and benzene, are natural characteristics 
of gasoline as a result of the chemical nature of crude oil and the 
refining process. Their level or concentration in gasoline is unknown 
until measured, and then is dependent upon accuracy of the test method. 
In contrast, ethanol is intentionally added in known amounts using 
equipment designed to ensure a specific concentration within a small 
fraction of one percent. Parties that blend ethanol into gasoline 
therefore have precise control over the final concentration. Thus, a 
measurement tolerance for ethanol would be less appropriate than 
measurement tolerances for other fuel properties and components.
    We request comment on whether a measurement tolerance should be 
allowed for the ethanol content of gasoline, the basis for such a 
tolerance, and what tolerance if any would be appropriate. We also 
request comment on whether such a tolerance would fit within the 
existing Underwriters Laboratories, Inc. (UL) approval for the safety 
of equipment at refueling stations, including underground storage 
tanks, pumps, piping, seals, etc.
f. Redefining ``Substantially Similar'' to Allow Mid-Level Ethanol 
Blends
    Section 211(f)(1) prohibits the introduction into commerce, or 
increase in the concentration in use of, gasoline or gasoline additives 
for use in motor vehicles unless they are substantially similar to the 
gasoline or gasoline additives used in the certification of new motor 
vehicles or motor vehicle engines. EPA may grant a waiver of this 
prohibition under section 211(f)(4) of the Clean Air Act provided that 
the fuel or fuel additive ``will not cause or contribute to a failure 
of any emission control device or system (over the useful life of the 
motor vehicle, motor vehicle engine, nonroad engine or nonroad vehicle 
in which the device or system

[[Page 25019]]

is used) to achieve compliance by the vehicle or engine with the 
emission standards to which it has been certified.''
    EPA first interpreted the term ``substantially similar'' for 
unleaded gasoline and its additives in 1978.\255\ Recognizing that this 
interpretation was too limited, EPA updated it in 1980, and again in 
1981.\256\ EPA set the limits contained in the interpretation based on 
the physical and chemical similarities of the fuel or fuel additives to 
those used in the motor vehicle certification process. EPA also 
considered information available regarding the emission effects that 
such fuels and additives would exhibit relative to the emissions 
performance of the certification fuels and fuel additives. The 1981 
interpretative rule identified the characteristics and specifications 
that EPA determined would make a fuel or fuel additive ``substantially 
similar'' to those used in certification. Under this rule, a fuel or 
fuel additive would be considered substantially similar if it satisfied 
certain limits on fuel and fuel additive composition, did not exceed a 
maximum allowable oxygen content of fuel at 2.0% by weight, and met 
certain ASTM specifications. Comments on this interpretative rule 
requested that EPA increase the maximum oxygen concentration up to 3.5% 
oxygen by weight, but EPA rejected this recommendation, stating that it 
would keep the limit at 2.0% because of concerns over emissions, 
material compatibility, and drivability from use of various alcohols at 
higher oxygen contents.
---------------------------------------------------------------------------

    \255\ 43 FR 11258 (March 17, 1978), 43 FR 24131 (June 2, 1978).
    \256\ 45 FR 67443 (October 10, 1980), 46 FR 38582 (July 28, 
1981).
---------------------------------------------------------------------------

    In 1991, EPA amended the interpretive rule by revising the oxygen 
content criteria to allow fuels containing aliphatic ethers and/or 
alcohols (excluding methanol) to contain up to 2.7% by weight 
oxygen.\257\ EPA based this increase in the oxygen content on its 
review of information on a wide variety of alcohol and ether blends, 
leading it to determine that ``unleaded gasolines with such oxygen 
content are chemically and physically substantially similar to, and 
have been shown to have emissions properties substantially similar to, 
unleaded gasolines used in light-duty vehicle certification.'' \258\ 
Finally, in 2008, EPA amended the interpretive rule to allow 
flexibility for the vapor/liquid ratio specification for fuel 
introduced into commerce in the state of Alaska to improve cold 
starting for vehicles during the winter months in Alaska.\259\ Thus the 
``substantially similar'' interpretive rule for unleaded gasoline 
presently allows oxygen content up to 2.7% by weight for certain ethers 
and alcohols.
---------------------------------------------------------------------------

    \257\ 56 FR 5352 (February 11, 1991).
    \258\ 56 FR at 5353.
    \259\ 73 FR 22277 (April 25, 2008).
---------------------------------------------------------------------------

    A waiver of the substantially similar prohibition was provided by 
operation of law in 1979 under CAA section 211(f)(4), allowing a 
gasoline-alcohol fuel blend with up to 10% ethanol by volume (E10) 
(``E10 Waiver''). E10 has an oxygen content which typically ranges 
between 3.5 and 3.7% by weight, depending on the specific gravity of 
the gasoline. Any ethanol blends with greater than 10% ethanol by 
volume would have an oxygen content which exceeds the 2.7% by weight 
allowed under the current interpretation of ``substantially similar.'' 
Therefore, under the 1991 interpretive rule, mid-level ethanol blends 
would not be considered substantially similar and would require a CAA 
section 211(f)(4) waiver.
    It has been suggested to EPA that we should update the interpretive 
rule such that mid-level ethanol blends would be considered 
substantially similar. As in the past, this would involve consideration 
of the physical and chemical similarities of such mid-level blends to 
fuels used in the certification process, as well as information about 
the expected emissions effects of such mid-level blends.\260\ EPA 
invites comment on whether mid-level blends of ethanol are physically 
and chemically similar enough to the fuels used in the motor vehicle 
certification process such that they could be considered 
``substantially similar'' to the certification fuels used by EPA. With 
respect to the emissions effects of mid-level blends on emissions 
performance, EPA recognizes that there may be different impacts 
depending on the kind of motor vehicle involved. For example, it has 
been suggested that older technology motor vehicles and engines may 
have emissions and durability impacts from ethanol blends higher than 
10 percent, while Tier 2 and later technology vehicles--2004 and later 
model year vehicles--may have fewer such impacts.\261\ These more 
recent technology vehicles represent an ever growing proportion of the 
in-use fleet. DOE is currently conducting various test programs to 
ascertain the impacts of higher level ethanol blends on vehicles and 
equipment.
---------------------------------------------------------------------------

    \260\ One point to be clear on is that the substantially similar 
provision relates to fuels used in certification. It is not an issue 
of whether mid-level blends are substantially similar to a fuel that 
has received a waiver of this prohibition. See 46 FR 38582, 38583 
(July 28, 1981). The fuels used in certification include the test 
fuels used for exhaust testing, test fuels for evaporative emissions 
testing, and the fuels used in the durability process.
    \261\ It has also been suggested that nonroad engines and 
equipment may experience greater emissions effects and durability 
problems when using mid-level blends.
---------------------------------------------------------------------------

    EPA seeks comment on all of the issues involved with reconsidering 
its interpretation of the term ``substantially similar'' to include 
gasoline blended with ethanol to contain up to 4.5% oxygen by weight. 
If EPA revised the substantially similar interpretation in this manner, 
gasoline blended with up to 12% ethanol by volume (E12) would be 
considered ``substantially similar.'' \262\ Given the possibility, 
based upon engineering judgment, of a varying impact of a mid-level 
ethanol blends on different technology vehicles, EPA invites comment on 
limiting such an interpretation to gasoline intended for use in Tier 2 
and later motor vehicles. We estimate that defining E12 as 
``substantially similar'' for Tier 2 and later motor vehicles could 
delay the saturation of the gasoline market with ethanol for up to a 
year, allowing for more comprehensive testing on higher blend levels to 
be carried out. However, before EPA could determine whether it was 
appropriate to revise the interpretation of ``substantially similar'' 
for gasoline to include gasoline-alcohol fuels blended with up to 12% 
ethanol, information would need to be provided to EPA that would allow 
for a robust assessment of the impact of E12 over the full useful life 
of Tier 2 and later motor vehicles addressing emissions (both tailpipe 
and evaporative emissions), materials compatibility, and drivability. 
Furthermore, E12 would still need to fulfill registration requirements 
(i.e. speciation and health effects testing found at 40 CFR 79.52 and 
40 CFR 79.53).
---------------------------------------------------------------------------

    \262\ As mentioned earlier, EPA has typically used the oxygen 
weight percent convention when interpreting the ``substantially 
similar'' provision. A change in the ``substantially similar'' 
interpretation to allow for up to 4.5% oxygen by weight in the form 
of ethanol would essentially accommodate ethanol blends up to 12% by 
volume since the vast majority of gasolines blended at 12% by volume 
ethanol would not exceed this oxygen weight percent limit.
---------------------------------------------------------------------------

    EPA also seeks comments on additional regulatory and implementation 
issues that would arise as a result of changing the ``substantially 
similar'' definition to allow for E12. These issues as identified for 
mid-level blends in the discussion in Section V.D.3.b include, but are 
not necessarily limited to, the applicability of the 1.0 psi RVP waiver 
with regard to 10% ethanol blends found at 40 CFR

[[Page 25020]]

80.27(d), Clean Air Act section 211(h); the accommodation of ethanol 
blends in making calculations utilizing the complex model for 
reformulated and conventional gasoline at 40 CFR 80.45; and detergent 
certification requirements found at 40 CFR 80 (Subpart G). Emissions 
speciation and health effects testing is required for oxygenate-
specific blends under 40 CFR 79 (Subpart F). Such testing is currently 
underway for 10% ethanol blends but not for ethanol levels higher than 
10 percent. Additionally, if E12 was allowed under the ``substantially 
similar'' definition, presumably such a blend would have to meet one of 
the volatility classes of ASTM D4814-88, which is not now the case with 
some blends of 10% ethanol blended under the E10 Waiver. Any change in 
the allowable maximum ethanol level in motor fuels will impact these 
and, potentially, other motor fuel regulations.
    Furthermore, there are also implications beyond EPA's motor fuel 
regulations. Existing equipment in retail stations is certified by 
Underwriters Laboratories only up to 10% ethanol. Thus, either existing 
equipment would need to be recertified for E12 (if possible) or it 
would have to be replaced before E12 could be effectuated in the 
marketplace. In addition, the substantially similar prohibition applies 
to the fuel manufacturer, and if the reinterpretation only applied to 
gasoline used with Tier 2 and later motor vehicles, then the 
manufacturer of a mid-level blend could not introduce it into commerce 
for use with any other motor vehicles. This means that the fuel 
distribution system would need to be structured in such a way that the 
fuel manufacturer could appropriately ensure that the fuel was only 
used in Tier 2 or later motor vehicles. Preventing the misfueling of 
mid-level blends into vehicles and engines not specified in the 
interpretive rule, and ensuring the availability of fuels for other 
vehicles and engines, poses a major problem with reinterpreting 
``substantially similar'' to include mid-level blends with a 
restriction for use in Tier 2 and later motor vehicles. (For a more 
detailed discussion on this issue, see Section V.D.3.c above). We seek 
comment on these logistical and regulatory concerns as well.

VI. Impacts of the Program on Greenhouse Gas Emissions

A. Introduction

    Lifecycle modeling, often referred to as fuel cycle or well-to-
wheel analysis, assesses the net impacts of a fuel throughout each 
stage of its production and use including production/extraction of the 
feedstock, feedstock transportation, fuel production, fuel 
transportation and distribution, and tailpipe emissions.\263\ This 
section describes and seeks comment on the methodology developed by EPA 
to determine the lifecycle greenhouse gas (GHG) emissions of biofuels 
fuels as required by EISA as well as the petroleum-based transportation 
fuels being replaced. While much of the discussion below focuses on 
those portions of lifecycle assessment particularly important to 
biofuel production, the basic methodology was the same for analyzing 
both petroleum-based fuels and biofuels. This methodology was utilized 
to determine which biofuels (both domestic and imported) qualify for 
the four different GHG reduction thresholds established in EISA. This 
threshold assessment compares the lifecycle emissions of a particular 
biofuel including its production pathway against the lifecycle 
emissions of the petroleum-based fuel it is replacing (e.g., ethanol 
replacing gasoline or biodiesel replacing diesel). This section also 
seeks comment on the Agency's proposal to utilize the discretion 
provided in EISA to adjust these thresholds downward should certain 
conditions be met. We also explain how feedstocks and fuel types not 
included in our analysis will be addressed and incorporated in the 
future. The overall GHG benefits of the RFS program, which are based on 
the same methodology presented here, are provided in Section VI.F.
---------------------------------------------------------------------------

    \263\ In this preamble, we are considering ``lifecycle 
analysis'' in the context of estimating GHG emissions, as required 
by EISA. More generally, the term ``lifecycle analysis'' or 
``assessment'' has been defined as an evaluation of all the 
environmental impacts across the range of media/exposure pathways 
that are associated with a ``cradle to grave'' view of a product or 
set of policies. For more information on this broader context, 
please see the 2006 EPA publication ``Life Cycle Assessment: 
Principles and Practice (EPA/600/R-06/060).
---------------------------------------------------------------------------

    As described in detail below, EPA has analyzed the lifecycle GHG 
impacts of the range of biofuels currently expected to contribute 
significantly to meeting the volume mandates of EISA through 2022. In 
these analyses we have used the best science available. Our analysis 
relies on peer reviewed models and the best estimate of important 
trends in agricultural practices and fuel production technologies as 
these may impact our prediction of individual biofuel GHG performance 
through 2022. We have identified and highlighted assumptions and model 
inputs that particularly influence our assessment and seek comment on 
these assumptions, the models we have used and our overall methodology 
so as to assure the most robust assessment of lifecycle GHG performance 
for the final rule.
    EPA believes that compliance with the EISA mandate--determining the 
aggregate GHG emissions related to the full fuel lifecycle, including 
both direct emissions and significant indirect emissions such as land 
use changes--makes it necessary to assess those direct and indirect 
impacts that occur not just within the United States and also those 
that occur in other countries. This applies to determining the 
lifecycle emissions for petroleum-based fuels, to determine the 
baseline, as well as the lifecycle emissions for biofuels. For 
biofuels, this includes evaluating significant emissions from indirect 
land use changes that occur in other countries as a result of the 
increased production and importation of biofuels in the U.S. As 
detailed below, we have included the GHG emission impacts of 
international indirect land use changes. We recognize the significance 
of including international land use emissions impact and in our 
analysis presentation we have been transparent in breaking out the 
various sources of GHG emissions so that the reader can readily see the 
impact of including international land use impacts.
    In addition to the many technical issues addressed in this 
proposal, this section also discusses the emissions decreases and 
increases associated with the different parts of the lifecycle 
emissions of various biofuels, and the timeframes in which these 
emissions changes occur. Determining a single lifecycle value that best 
represents this combination of emissions increases and decreases 
occurring over time led EPA to consider various alternative ways to 
analyze the timeframe of emissions related to biofuel production and 
use as well as options for adjusting or discounting these emissions to 
determine their net present value. Several variations of time period 
and discount rate are discussed. The analytical time horizon and the 
choice whether to discount GHG emissions and, if so, at what 
appropriate rate can have a significant impact on the final assessment 
of the lifecycle GHG emissions impacts of individual biofuels as well 
as the overall GHG impacts of these EISA provisions and this rule.
    We believe that our lifecycle analysis is based on the best 
available science, and recognize that in some aspects it represents a 
cutting edge approach to addressing lifecycle GHG emissions. Because of 
this, varying degrees of uncertainty are in our analysis. For this 
proposal, we conducted a number of

[[Page 25021]]

sensitivity analyses which focus on key parameters and demonstrate how 
our assessments might change under alternative assumptions. By focusing 
attention on these key parameters, the comments we receive as well as 
additional investigation and analysis by EPA will allow narrowing of 
uncertainty concerns for the final rule. In addition to this 
sensitivity analysis approach, we will also explore options for more 
formal uncertainty analyses for the final rule to the extent possible.
    Because lifecycle analysis is a new part of the RFS program, in 
addition to the formal comment period on the proposed rule, EPA is 
making multiple efforts to solicit public and expert feedback on our 
proposed approach. As discussed in Section XI, EPA plans to hold a 
public workshop during the comment period focused specifically on our 
lifecycle analysis to help ensure full understanding of the analyses 
conducted, the issues addressed and options that should be considered. 
We expect that this workshop will help ensure that we receive the most 
thoughtful and useful comments to this proposal and that the best 
methodology and assumptions are used for calculating GHG emissions 
impacts of fuels for the final rule. Additionally we will conduct peer-
reviews of key components of our analysis. As explained in more detail 
in the following sections, EPA is specifically seeking peer review of: 
Our use of satellite data to project future land use changes; the land 
conversion GHG emissions factors estimated by Winrock; our estimates of 
GHG emissions from foreign crop production; methods to account for the 
variable timing of GHG emissions; and how models are used together to 
provide overall lifecycle GHG estimates.
    The regulatory purpose of the lifecycle greenhouse gas emissions 
analysis is to determine whether renewable fuels meet the GHG 
thresholds for the different categories of renewable fuel.
1. Definition of Lifecycle GHG Emissions
    The GHG provisions in EISA are notable for the GHG thresholds 
mandated for each category of renewable fuel and also the mandated 
lifecycle approach to those thresholds. Renewable fuel must, unless 
``grandfathered'' as discussed in Section II.B.3., achieve at least 20% 
reduction in lifecycle greenhouse gas emissions compared to the average 
lifecycle greenhouse gas emissions for gasoline or diesel sold or 
distributed as transportation fuel in 2005. Similarly, biomass-based 
diesel and advanced biofuels must achieve a 50% reduction, and 
cellulosic biofuels a 60% reduction, unless these thresholds are 
adjusted according to the provisions in EISA. To EPA's knowledge, the 
GHG reduction thresholds presented in EISA are the first lifecycle GHG 
performance requirements included in federal law. These thresholds, in 
combination with the renewable fuel volume mandates, are designed to 
ensure significant GHG emission reductions from the use of renewable 
fuels and encourage the use of GHG-reducing renewable fuels.
    The definition of lifecycle greenhouse gas emissions established by 
Congress is also critical. Congress specified that:

    The term `lifecycle greenhouse gas emissions' means the 
aggregate quantity of greenhouse gas emissions (including direct 
emissions and significant indirect emissions such as significant 
emissions from land use changes), as determined by the 
Administrator, related to the full fuel lifecycle, including all 
stages of fuel and feedstock production and distribution, from 
feedstock generation or extraction through the distribution and 
delivery and use of the finished fuel to the ultimate consumer, 
where the mass values for all greenhouse gases are adjusted to 
account for their relative global warming potential.\264\
---------------------------------------------------------------------------

    \264\ Clean Air Act Section 211(o)(1).

    This definition requires EPA to look broadly at lifecycle analyses 
and to develop a methodology that accounts for all the important 
factors that may significantly influence this assessment, including the 
secondary or indirect impacts of expanded biofuels use. EPA's analysis 
described below indicates that the assessment of lifecycle GHG 
emissions for biofuels is significantly affected by the secondary 
agricultural sector GHG impacts from increased biofuel feedstock 
production (e.g., changes in livestock emissions due to changes in 
agricultural commodity prices) and also by the international impact of 
land use change from increased biofuel feedstock production. Thus, 
these factors must be appropriately incorporated into EPA's lifecycle 
methodology to properly assess full lifecycle GHG performance of 
biofuels in accordance with the EISA definition.
2. History and Evolution of GHG Lifecycle Analysis
    Traditionally, the GHG lifecycle analysis of fuels has involved 
calculating the emissions associated with each individual stage in the 
production and use of the fuel (e.g., growing or extracting the 
feedstock, moving the feedstock to the processing plant, processing the 
feedstock into fuel, moving the fuel to market, and combusting the 
fuel.) EPA used this approach for the lifecycle modeling conducted for 
the RFS1 program in 2005. However, it has become increasingly apparent 
that this type of first order or attributional lifecycle modeling has 
notable shortcomings, especially when evaluating the implications of 
biofuel policies.\265\ In fact, the main criticism EPA received in 
reaction to our previous RFS1 lifecycle analysis was that we did not 
include important secondary, indirect, or consequential impacts of 
biofuel production and use.
---------------------------------------------------------------------------

    \265\ See also, Conceptual and Methodological Issues in 
Lifecycle Analysis of Transportation Fuels, Mark A. Delucchi, 
Institute of Transportation Studies, University of California, 
Davis, 2004, UCD-ITS-RR-04-45 for a description of issues with 
traditional lifecycle analysis used to model GHG impacts of biofuels 
and biofuel policies.
---------------------------------------------------------------------------

    Several studies and analyses conducted since the completion of RFS1 
have contributed to our understanding of the lifecycle GHG emissions of 
biofuel production. These studies, and others, have highlighted the 
potential impacts of biofuel production on the agricultural sector and 
have specifically identified land use change impacts as an important 
consideration when determining GHG impacts of 
biofuels.266 267 In the meantime, the dramatic increase in 
U.S. production of biofuels has heightened the concern about the 
impacts biofuels might have on land use and has increased the 
importance of considering these indirect impacts in lifecycle analysis.
---------------------------------------------------------------------------

    \266\ Fargione, J., J. Hill, D. Tilman, S. Polasky, and P. 
Hawthorne. 2008. Land clearing and the biofuel carbon debt. Science 
319:1235-1238. See http://www.sciencemag.org/cgi/reprint/319/5867/1235.pdf.
    \267\ Searchinger, T., R. Heimlich, R.A. Houghton, F. Dong, A. 
Elobeid, J. Fabiosa, S. Tokgoz, D. Hayes, and T.-H. Yu. 2008. Use of 
U.S. croplands for biofuels increases greenhouse gases through 
emissions from land-use change. Science 319:1238-1240. See http://www.sciencemag.org/cgi/reprint/319/5867/1238.pdf.
---------------------------------------------------------------------------

    Based on the evolution of lifecycle analysis and the new 
requirements of EISA, we have developed a comprehensive methodology for 
estimating the lifecycle GHG emissions associated with renewable fuels. 
Through dozens of meetings with a wide range of experts and 
stakeholders, EPA has shared and sought input on this methodology. We 
also have relied on the expertise of the U.S. Department of Agriculture 
(USDA) and the Department of Energy (DOE) to help inform many of the 
key assumptions and modeling inputs for this analysis. Dialogue with 
the State of California and the European Union on their parallel, on-
going efforts in GHG

[[Page 25022]]

lifecycle analysis has also helped inform EPA's methodology. As part of 
this discussion, we have identified several of the key drivers 
associated with these lifecycle GHG emissions estimates, including 
assumptions about international land use change and the timing of GHG 
emissions over time. The inputs we have received through these 
interactions are reflected throughout this section.
    Specifically EPA has worked closely with the California Air 
Resources Board (CARB) regarding their development of transportation 
fuels lifecycle GHG impacts. California Executive Order S-1-07, the Low 
Carbon Fuel Standard (LCFS) (issued on January 18, 2007), calls for a 
reduction of at least 10 percent in the carbon intensity of 
California's transportation fuels by 2020. CARB has worked to develop 
lifecycle GHG impacts of different fuels for this Executive Order 
rulemaking. More information about this rulemaking and the lifecycle 
analysis conducted by California can be found at http://www.arb.ca.gov/fuels/lcfs/lcfs.htm. EPA will continue to coordinate with California on 
this rulemaking and the biofuels lifecycle GHG analysis work.
    Because this lifecycle GHG emissions analysis is complex and 
requires the use of sophisticated computer models, we have taken 
several steps to increase the transparency associated with our 
analysis. For example, we have updated the model documentation for the 
Forest and Agricultural Sector Optimization Model (FASOM), which is 
included in the docket. In addition, we have highlighted key 
assumptions in FASOM and the Food and Agricultural Policy Research 
Institute (FAPRI) models that impact the results of our analysis. 
Finally, this NPRM provides an important opportunity for the Agency to 
present our work and to receive input from stakeholders and experts in 
this field. We will also continue to refine our analysis between the 
proposed and final rules, and we will add or update information to the 
docket as it becomes available.

B. Methodology

    This section describes EPA's methodology for assessing the 
lifecycle GHG emissions associated with each biofuel evaluated as well 
as the petroleum-based gasoline and diesel fuel these biofuels would 
replace. Whereas lifecycle GHG emission methodologies have been well 
studied and established for petroleum-based gasoline and diesel fuel, 
much of EPA's work has focused on newly developing lifecycle 
methodologies for biofuels. Therefore, much of the following section 
describes the biofuels-related methodologies and identifies important 
issues for comment. Assessing the complete lifecycle GHG impact for 
each individual biofuel mandated by EISA requires that a number of key 
methodological issues be addressed--from the choice of a baseline to 
the selection of the most credible technique for predicting 
international land use conversion due to the increase in U.S. renewable 
fuels demand, to accounting for the time dimension of changes in GHG 
emissions. In this section, we first describe the scenarios we have 
analyzed for this proposal. Second, we discuss the scope of our 
analysis and what is included in our estimates. Third, we provide 
details on the tools and models we used to quantify the GHG emissions 
associated with the different fuels. Fourth, we discuss the 
uncertainties associated with lifecycle analysis and how we have 
addressed them. Fifth, we describe the different components of the 
lifecycle that we have analyzed and the key questions we have addressed 
in this analysis.
1. Scenario Description
    To quantify the lifecycle GHG emissions associated with the 
increase in renewable fuel mandated by EISA, we compared the 
differences in total GHG emissions between two future scenarios. The 
first assumed a ``business as usual'' volume of a particular renewable 
fuel based on what would likely be in the fuel pool in 2022 without 
EISA, as predicted by the Energy Information Agency's Annual Energy 
Outlook (AEO) for 2007 (which took into account the economic and policy 
factors in existence in 2007 before EISA). The second assumed the 
higher volume of renewable fuels as mandated by EISA for 2022. For each 
individual biofuel, we analyzed the incremental GHG emission impacts of 
increasing the volume of that fuel to the total mix of biofuels needed 
to meet the EISA requirements. Rather than focus on the impacts 
associated with a specific gallon of fuel and tracking inputs and 
outputs across different lifecycle stages, we determined the overall 
aggregate impacts across sections of the economy in response to a given 
volume change in the amount of biofuel produced.\268\
---------------------------------------------------------------------------

    \268\ We then normalize those impacts for each gallon of fuel 
(or Btu) by dividing total impacts over the given volume change.
---------------------------------------------------------------------------

    This analysis is not a comparison of biofuel produced today versus 
biofuel produced in the future. Instead, it is a comparison of two 
future scenarios. Any projected changes in factors such as crop yields, 
energy costs, or production plant efficiencies, both domestically and 
internationally, are reflected in both scenarios. We focused our 
analyses on 2022 results for three reasons. First, it would require an 
extremely complex assessment and administratively difficult 
implementation program to track how biofuel production might 
continuously change from month to month or year to year. Instead, it 
seems appropriate that each biofuel be assessed a level of GHG 
performance that is constant over the implementation of this rule, 
allowing fuel providers to anticipate how these GHG performance 
assessments should affect their production plans. Second, it is 
appropriate to focus on 2022, the final year of ramp up in the required 
volumes of renewable fuel as this year. Assessment in this year allows 
the complete fuel volumes specified in EISA to be incorporated. Third, 
since the GHG assessment compares performance between a business as 
usual case and the mandated volumes case, many of the factors that 
change over time such as crop yield per acre are reflected in both 
cases. Therefore the differences in these parallel assessments are 
unlikely to vary significantly over time.
    EPA requests comment on its proposal to adopt fixed assessments of 
fuels meeting the GHG thresholds based on a 2022 performance 
assessment. Additional information on the scenarios modeled and the 
supplemental analyses that will be conducted for the final rule is 
included in Chapter 2 of the DRIA.
    In the existing Renewable Fuel Standard rules adopted in response 
to the Energy Policy Act of 2005, biofuels and RINs associated with 
them are not based on regional differences of where the feedstock was 
grown or the biofuel was produced. In effect, the RINs apply to a 
national average of the fuel type. Similarly, this proposal does not 
distinguish biofuel on the basis of where within the country the 
biofuel feedstock was grown or the biofuel produced. Thus, for example, 
ethanol produced from corn starch using the same production technology 
will receive the same GHG lifecycle assessment regardless of where the 
corn was grown or at what facility the biofuel was produced. There are 
regional differences in soil types, weather conditions, and other 
factors which could affect, for example, the amount of fertilizer 
applied and thus the GHG impact of corn production. Such factors could 
vary somewhat across a region, within a state and even within a county. 
The agricultural models used to conduct this analysis do distinguish 
crop production

[[Page 25023]]

by region domestically and by country internationally. However, biofuel 
feedstocks such as corn or soybean oil are well traded commodities 
including internationally. So, for example, if corn in a certain 
location in Iowa is used to produce ethanol, corn from all other 
regions will be used to replace that corn for all its other potential 
uses. Therefore, it is not appropriate to ascribe the indirect affects, 
both domestically and internationally, to corn grown in one area 
differently to corn (or other biofuel feedstock) grown in another area. 
Our national treatment of biofuel feedstock also pertains to fuels 
produced in other countries. Thus for example, sugarcane-based ethanol 
produced in Brazil is all treated the same regardless of where the 
sugarcane was grown in Brazil. Nevertheless, comments are invited on 
the option of differentiating biofuels in the future based on the 
location of their feedstock production within a country.
2. Scope of the Analysis
a. Legal Interpretation of Lifecycle Greenhouse Gas Emissions
    As described in VI.A.1, the definition of lifecycle greenhouse gas 
emissions refers to the ``aggregate quantity of GHG emissions'' that 
are ``related to the full fuel lifecycle.'' The fuel lifecycle includes 
``all stages of fuel and feedstock production and distribution, from 
feedstock generation or extraction through * * * use of the finished 
fuel to the ultimate consumer.'' The aggregate quantity of GHG 
emissions includes ``direct emissions'' and ``significant indirect 
emissions such as significant emission from land use changes.'' This 
provision is written in generally broad and expansive terms, such as 
``aggregate quantity'', ``related to'', ``full fuel lifecycle'', and 
``all stages'' of production and distribution. At the same time, these 
and other terms are not themselves defined and provide discretion to 
the Administrator in implementing this definition. For example, the 
word ``significant,'' which is used to modify ``indirect emissions,'' 
is not defined.
    The definition includes both ``direct'' and ``significant 
indirect'' emissions related to the full fuel lifecycle. We consider 
direct emissions as those that are emitted from each stage of the full 
fuel lifecycle, and indirect emissions as those from second order 
effects that occur as a consequence of the full fuel lifecycle. For 
example, direct emissions for a renewable fuel would include those from 
the growing of renewable fuel feedstock, the distribution of the 
feedstock to the renewable fuel producer, the production of renewable 
fuel, the distribution of the finished fuel to the consumer, and the 
use of the fuel by the consumer as transportation fuel. Similarly, 
direct emissions associated with the baseline fuel would include 
extraction of the crude oil, distribution of the crude oil to the 
refinery, the production of gasoline and diesel from the crude oil, the 
distribution of the finished fuel to the consumer, and the use of the 
fuel by the consumer. Indirect emissions would include other emissions 
impacts that result from fuel production or use, such as changes in 
livestock emissions resulting from changes in livestock numbers, or 
shifts in acreage between different crop types. The definition of 
indirect emissions specifically includes ``land use changes'' which 
would include changes in the kind of usage that land is put to such as 
changes in forest, pasture, savannah, and crop use.\269\
---------------------------------------------------------------------------

    \269\ Arguably shifts in acreage between different crops also 
could be considered a land use change, but we believe there will be 
less confusion if the term land use change is used with respect to 
changes in land such as changing from savannah or forest to 
cropland. There is no difference in result, as in both cases the 
emissions need to be significant.
---------------------------------------------------------------------------

    In considering how to address land use changes in our lifecycle 
analysis, two distinct questions have been raised--whether to account 
for emissions that occur outside of the U.S., and under what 
circumstances land use change should properly be included in the 
lifecycle analysis.
    On the question of considering GHG emissions that occur outside of 
the U.S., it is important to be clear that including such emissions in 
the lifecycle analysis does not exercise regulatory authority over 
activities that occur solely outside the U.S., and does not raise 
questions of extra-territorial jurisdiction. EPA's regulatory action 
involves classification of products either produced in the U.S. or 
imported into the U.S. EPA is simply assessing whether the use of these 
products in the U.S. satisfies requirements under the Clean Air Act for 
the use of designated volumes of renewable fuel, cellulosic biofuel, 
biomass-based diesel and advanced biofuel, as those terms are defined 
in the Act. Considering international emissions in determining the 
lifecycle GHG emissions of the domestically produced or imported fuel 
does not change the fact that the actual regulation of the product 
involves its use solely inside the U.S.
    When looking at the issue of international versus domestic 
emissions, it is important to recognize that a large variety of 
different activities outside the U.S. play a major part of the full 
fuel lifecycle of baseline and renewable fuels. For example, for 
baseline fuels (i.e., gasoline and diesel fuels used as transportation 
fuel in 2005), GHG emissions associated with extraction and delivery of 
crude oil imported to the U.S. all have occurred overseas. In addition, 
for imported gasoline or diesel, all of the crude extraction and 
delivery emissions, as well as the emissions associated with refining 
and distribution of the finished product to the U.S., would have 
occurred overseas. For imported renewable fuel all of the emissions 
associated with feedstock production and distribution, processing of 
the feedstock into renewable fuel, and delivery of the finished 
renewable fuel to the U.S. would have occurred overseas. The definition 
of lifecycle greenhouse gas emissions makes it clear that EPA is to 
determine the aggregate emissions related to the ``full'' fuel 
lifecycle, including ``all stages of fuel and feedstock production and 
distribution.'' Thus, EPA could not, as a legal matter, ignore those 
parts of a fuel lifecycle that occur overseas.
    Drawing a distinction between GHG emissions that occur inside the 
U.S. as compared to emissions that occur outside the U.S. would 
dramatically alter the lifecycle analysis in a way that bears no 
apparent relationship to the purpose of this provision. The purpose of 
including lifecycle GHG thresholds in this statutory provision is to 
require the use of renewable fuels that achieve reductions in GHG 
emissions compared to the baseline. Drawing a distinction between 
domestic and international emissions would ignore a large part of the 
GHG emission associated with the different fuels, and would result in a 
GHG analysis of baseline renewable fuels that bears no relationship to 
the real world emissions impact of the fuels. The baseline would be 
significantly understated, given the large amount of imported crude 
used to produce gasoline and diesel, and the importation of finished 
gasoline and diesel, in 2005. Likewise, the emissions associated with 
imported renewable fuel would be understated, as it would only consider 
the emissions from distribution of the fuel to the consumer and the use 
of the fuel by the consumer, and would ignore both the emissions that 
occurred overseas as well as the emissions reductions from the intake 
of CO2 from growing of the feedstock. While large 
percentages of GHG emissions would be ignored, this would take place in 
a context where the global warming impact of emissions is irrespective 
of

[[Page 25024]]

where the emissions occur. Thus taking such an approach would 
essentially undermine the provision, and would be an arbitrary 
interpretation of the broadly phrased text used by Congress.
    While the emissions discussed above would more typically be 
considered direct emissions related to the full fuel lifecycle, there 
would also be no basis to cover just foreign direct emissions while 
excluding foreign indirect emissions. The text of the statute draws no 
such distinction, nor is there a distinction in achieving the purposes 
of the provision. GHG emissions impact global warming wherever they 
occur, and if the purpose is to achieve some reduction in GHG emissions 
in order to help address global warming, then ignoring GHG emissions 
because they are emitted outside our borders versus inside our borders 
interferes with the ability to achieve this objective.
    For example, domestic production of a renewable fuel could lead to 
indirect emissions, whether from land use changes or otherwise, some 
occurring within the U.S. and some occurring in other countries. 
Similarly, imported renewable fuel could have resulted in the same 
indirect emissions whether occurring in the country that produced the 
biofuel or in other countries. It would be arbitrary to assign the 
indirect emissions to the domestic renewable fuel but not to assign the 
identical indirect emissions that occur overseas to an imported 
product.
    Based on the above, EPA believes that the definition of lifecycle 
greenhouse gas emissions is properly interpreted as including all 
direct and significant indirect GHG emissions related to the full fuel 
lifecycle, whether or not they occur in the U.S. This applies to both 
the baseline lifecycle greenhouse emissions as well as the lifecycle 
greenhouse gas emissions for various renewable fuels.
    EPA recognizes, as discussed later, our estimates of domestic 
indirect emissions are more certain than our estimate of international 
indirect emissions. The issue of how to evaluate and weigh the various 
elements of the lifecycle analysis, and properly account for 
uncertainty in our estimates, is a different issue, however. The issue 
here is whether the definition of lifecycle greenhouse gas emissions is 
properly interpreted as including direct and significant indirect 
emissions that occur outside the U.S. as well as those that occur 
inside the U.S.
    As to the question of which land use changes should be included in 
our lifecycle analyses, a central element to focus on is the 
requirement that such indirect emissions be related to the full fuel 
lifecycle. The term ``related to'' is generally interpreted as 
providing a broad and expansive scope for a provision. It has routinely 
been interpreted as meaning to have a connection to or refer to a 
matter. To determine whether an indirect emission has the appropriate 
connection to the full fuel lifecycle, we must look at both the 
objectives of this provision as well as the nature of the relationship.
    In this case, EPA has used a global model that projects a variety 
of agricultural impacts that stem from the use of feedstocks to produce 
renewable fuel. We have estimated shifts in types of crops planted and 
increases in crop acres planted. There is a direct relationship between 
these shifts in the agricultural market as a consequence of the 
increased demand for biofuels in the U.S. Increased U.S. demand for 
biofuel feedstocks diverts these feedstocks from other competing uses, 
and also increases the price of the feedstock, thus spurring 
production. To the extent feedstocks like corn and soybeans are traded 
internationally, this combined impact of lower supply from the U.S. and 
higher commodity prices encourages international production to fill the 
gap. Our analysis uses country specific information to determine the 
amount, location, and type of land use change that would occur to meet 
this change in production patterns. The linkages are generally close, 
and are not extended or overly complex. While there is clearly 
significant uncertainty in determining the specific degree of land use 
change and the specific impact of those changes, there is considerable 
overall certainty as to the existence of the land use changes in 
general, the fact that GHG emissions will result, and the cause and 
effect linkage of these emissions impacts to the increased use of 
feedstock for production of renewable fuels.
    Overall, EPA is confident that it is appropriate to consider the 
estimated emissions from land use changes as well as the other indirect 
emissions as ``related to'' the full fuel lifecycle, based on the 
reasonable technical basis provided by the modeling for the connection 
between the full fuel lifecycle and the indirect emissions, as well as 
for the determination that the emissions are significant. EPA believes 
uncertainty in the resulting aggregate GHG estimates should be taken 
into consideration, but that it would be inappropriate to exclude 
indirect emissions estimates from this analysis. Developing a 
reasonable estimate of these kinds of indirect emissions will allow for 
a reasoned evaluation of total GHG impacts, which is needed to promote 
the objectives of this provision, as compared to ignoring or not 
accounting for these indirect emissions.
b. System Boundaries
    It is important to establish clear system boundaries in this 
analysis. By determining a common set of system boundaries, different 
fuel types can then be validly compared. As described in the previous 
section, we have assessed the direct and indirect GHG impacts in each 
stage of the full fuel lifecycle for biofuels and petroleum fuels.
    To capture the direct emissions impacts of feedstock production in 
our analysis, we included the agricultural inputs (e.g., the fuel used 
in the tractor, the energy used to produce and transport fertilizer to 
the field) needed to grow crops directly used in biofuel production. We 
also included the N2O emissions associated with agricultural 
sector practices used in biofuel production (including direct and 
indirect N2O emissions from synthetic fertilizer 
application, N fixing crops, crop residue, and manure management), as 
well as the land use change associated with converting land to grow 
crops directly used in biofuel production. To capture the indirect, or 
secondary, GHG emissions that result from biofuel feedstock production, 
we relied on the internationally accepted lifecycle assessment 
standards developed by the International Organization for 
Standardization (ISO). Examples of significant secondary impacts 
include the agricultural inputs associated with crops indirectly 
impacted by the use of feedstock for biofuel production (domestically 
and internationally), the emissions associated with land use change 
that are indirectly impacted by using feedstocks for biofuel production 
(e.g., to make up for lost U.S. exports), changes in livestock herd 
numbers that result from higher feed costs, and changes in rice methane 
emissions indirectly impacted by shifts in acres to produce feedstocks 
for biofuel production. These indirect or secondary impacts would not 
have occurred if it were not for the use of biomass to produce a 
biofuel.
    We did not include the infrastructure related GHG emissions (e.g., 
the energy needed to manufacture the tractor used on the farm) or the 
facility construction-related emissions (e.g., steel or concrete needed 
to construct a refinery). As part of the GHG analysis performed for 
RFS1, we performed a sensitivity analysis on expanding the corn 
production system to include farm equipment production to determine the 
impact it has on the overall results of our analysis. We found that 
including

[[Page 25025]]

farm equipment production energy use and emissions increases corn 
ethanol lifecycle energy use and GHG emissions and decreases the corn 
ethanol lifecycle GHG benefit as compared to petroleum gasoline by 
approximately 1%. Furthermore, to be consistent in the modeling if 
system boundaries are expanded to include production of farming 
equipment they should also be expanded to include producing other 
material inputs to both the ethanol and petroleum lifecycles. The net 
effect of this would be a slight increase in both the ethanol and 
petroleum fuel lifecycle results and a smaller or negligible effect on 
the comparison of the two.
    For this proposal, we have not yet incorporated secondary energy 
sector impacts, however we plan to have this analysis complete for the 
final rule. Additional details on the system boundaries are included in 
the DRIA Chapter 2.
3. Modeling Framework
    Currently, no single model can capture all of the complex 
interactions associated with estimating lifecycle GHG emissions for 
biofuels, taking into account the ``significant indirect emissions such 
as significant emissions from land use change'' required by EISA. For 
example, some analysis tools used in the past focus on process 
modeling--the energy and resultant emissions associated with the direct 
production of a fuel at a petroleum refinery or biofuel production 
facility. But this is only one component in the production of the fuel. 
Clearly in the case of biofuels, impacts from and on the agricultural 
sector are important, because this sector produces feedstock for 
biofuel production. Commercial agricultural operations make many of 
their decisions based on an economic assessment of profit maximization. 
Assessment of the interactions throughout the agricultural sector 
requires an analysis of the commodity markets using economic models. 
However, existing economy wide general equilibrium economic models are 
not detailed enough to capture the specific agricultural sector 
interactions critical to our analysis (e.g., changes in acres by crop 
type) and would not provide the types of outputs needed for a thorough 
GHG analysis. As a result, EPA has used different tools that have 
different strengths for each specific component of the analysis to 
create a more comprehensive estimate of GHG emissions. Where no direct 
links between the different models exist, specific components and 
outputs of each are used and combined to provide an analytical 
framework and the composite lifecycle assessment results. As this is a 
new application of these modeling tools, EPA plans to organize peer 
review of our modeling approach. The individual models are described in 
the following sections and in more detail in Chapter 2 of the DRIA.
    To quantify the emissions factors associated with different steps 
of the production and use of various fuels (e.g., extraction of 
petroleum products, transport of feedstocks), we used the spreadsheet 
analysis tool developed by Argonne National Laboratories, the 
Greenhouse gases, Regulated Emissions, and Energy use in Transportation 
(GREET) model. This analysis tool includes the GHG emissions associated 
with the production and combustion of fossil fuels (diesel fuel, 
gasoline, natural gas, coal, etc.). These fossil fuels are used both in 
the production of biofuels, (e.g., diesel fuel used in farm tractors 
and natural gas used at ethanol plants) and could also be displaced by 
renewable fuel use in the transportation sector. GREET also estimates 
the GHG emissions estimates associated with electricity production 
required for biofuel and petroleum fuel production. For the 
agricultural sector, we also relied upon GREET to provide GHG emissions 
associated with the production and transport of agricultural inputs 
such as fertilizer, herbicides, pesticides, etc. While GREET provides 
direct GHG emissions estimates associated with the extraction-through-
combustion phases of fuel use, it does not capture some of the 
secondary impacts associated with the fuel, such as changes in the 
composition of feed used for animal production, which would be expected 
due to changes in cost. EPA addresses these secondary impacts through 
other models described later in this section. GREET has been under 
development for several years and has undergone extensive peer review 
through multiple updates. Of the available sources of information on 
lifecycle GHG emissions of fossil energy consumed, we believe that 
GREET offers the most comprehensive treatment of emissions from the 
covered sources.
    For some steps in the production of biofuels, we used more detailed 
models to capture some of the dynamic market interactions that result 
from various policies. Here, we briefly describe the different models 
incorporated into our analysis to provide specific details for various 
lifecycle components.
    To estimate the changes in the domestic agricultural sector (e.g., 
changes in crop acres resulting from increased demand for biofuel 
feedstock or changes in the number of livestock due to higher corn 
prices) and their associated emissions, we used the FASOM model, 
developed by Texas A&M University and others. FASOM is a partial 
equilibrium economic model of the U.S. forest and agricultural sectors. 
EPA selected the FASOM model for this analysis for several reasons. 
FASOM is a comprehensive forestry and agricultural sector model that 
tracks over 2,000 production possibilities for field crops, livestock, 
and biofuels for private lands in the contiguous United States. It 
accounts for changes in CO2, methane, and N2O 
from most agricultural activities and tracks carbon sequestration and 
carbon losses over time. Another advantage of FASOM is that it captures 
the impacts of all crop production, not just biofuel feedstock. Thus, 
as compared to some earlier assessments of lifecycle emissions, using 
FASOM allows us to determine secondary agricultural sector impacts, 
such as crop shifting and reduced demand due to higher prices. It also 
captures changes in the livestock market (e.g., smaller herd sizes that 
result from higher feed costs) and U.S. export changes. FASOM also has 
been used by EPA to consider U.S. forest and agricultural sector GHG 
mitigation options.\270\
---------------------------------------------------------------------------

    \270\ Greenhouse Gas Mitigation Potential in U.S. Forestry and 
Agriculture, EPA Document 430-R-05-006. See http://www.epa.gov/sequestration/greenhouse_gas.html.
---------------------------------------------------------------------------

    To estimate the impacts of biofuels feedstock production on 
international agricultural and livestock production, we used the 
integrated FAPRI international models, developed by Iowa State 
University and the University of Missouri. These models capture the 
biological, technical, and economic relationships among key variables 
within a particular commodity and across commodities. FAPRI is a 
worldwide agricultural sector economic model that was run by the Center 
for Agricultural and Rural Development (CARD) at Iowa State University 
on behalf of EPA. The FAPRI models have been previously employed to 
examine the impacts of World Trade Organization proposals and changes 
in the European Union's Common Agricultural Policy, to analyze farm 
bill proposals since 1984, and to evaluate the impact of biofuel 
development in the United States. In addition, the FAPRI models have 
been used by the USDA Office of Chief Economist, Congress, and the 
World Bank to examine agricultural impacts from government policy 
changes, market developments, and land use shifts.
    Although FASOM predicts land use and export changes in the U.S. due 
to

[[Page 25026]]

greater demand for domestic biofuel feedstock, it does not assess how 
international agricultural production might respond to these changes in 
commodity prices and U.S. exports. The FAPRI model does predict how 
much crop land will change in other countries but does not predict what 
type of land such as forest or pasture will be affected. We used data 
analyses provided by Winrock International to estimate what land types 
will be converted into crop land in each country and the GHG emissions 
associated with the land conversions. Winrock has used 2001-2004 
satellite data to analyze recent land use changes around the world that 
have resulted from the social, economic, and political forces that 
drive land use. Winrock has then combined the recent land use change 
patterns with various estimates of carbon stocks associated with 
different types of land at the state level. This international land use 
assessment is an important consideration in our lifecycle GHG 
assessment and is explained in more detail later in this section.
    To test the robustness of the FASOM, FAPRI and Winrock results, we 
are also evaluating the Global Trade Analysis Project (GTAP) model, a 
multi-region, multi-sector, computable general equilibrium model that 
estimates changes in world agricultural production. Maintained through 
Purdue University, GTAP projects international land use change based on 
the economics of land conversion, rather than using the historical data 
approach applied by FAPRI/Winrock. GTAP is designed to project changes 
in international land use as a result of the change in U.S. biofuel 
policies, based on the relative land use values of cropland, forest, 
and pastureland. The GTAP design has the advantage of explicitly 
modeling the competition between different land types due to a change 
in policy. As further discussed in Section VI.B.5.iv, GTAP has several 
disadvantages, some of which prevented its use for the proposal. We 
expect to correct several of these shortcomings between the proposed 
and final rules and therefore continue to evaluate how the GTAP model 
could be used as part of the final rule.
    The assessments provided in this proposal use the values provided 
by the Intergovernmental Panel on Climate Change (IPCC) to estimate the 
impacts of N2O emissions from fertilizer application. 
However, due to concern that this may underestimate N2O 
emissions from fertilizer application, \271\ we are working with the 
CENTURY and DAYCENT models, developed by Colorado State University, to 
update our assessments. The DAYCENT model simulates plant-soil systems 
and is capable of simulating detailed daily soil water and temperature 
dynamics and trace gas fluxes (CH4, N2O, 
NOX and N2). The CENTURY model is a generalized 
plant-soil ecosystem model that simulates plant production, soil carbon 
dynamics, soil nutrient dynamics, and soil water and temperature. We 
anticipate the results of this new modeling work will be reflected in 
our assessments for the final rule. More description of this ongoing 
work is included in the Chapter 2 of the DRIA.
---------------------------------------------------------------------------

    \271\ Crutzen, P. J., Mosier, A. R., Smith, K. A., and 
Winiwarter, W.: N2O release from agro-biofuel production 
negates global warming reduction by replacing fossil fuels, Atmos. 
Chem. Phys., 8, 389-395, 2008. See http://www.atmos-chem-phys.net/8/389/2008/acp-8-389-2008.pdf.
---------------------------------------------------------------------------

    To estimate the GHG emissions associated with renewable fuel 
production, we used detailed ASPEN-based process models developed by 
USDA and DOE's National Renewable Energy Laboratory (NREL). While GREET 
contains estimates for renewable fuel production, these estimates are 
based on existing technology. We expect biofuel production technology 
to improve over time, and we projected improvements in process 
technology over time based on available information. These projections 
are discussed in DRIA Chapter 4. We then utilized the ASPEN-based 
process models to assess the impacts of these improvements. We also 
cross-checked the ASPEN-based process model predictions by comparing 
them to a number of industry sources and other modeling efforts that 
estimate potential improvements in ethanol production over time, 
including the Biofuel Energy Systems Simulator (BESS) model. BESS is a 
software tool developed by the University of Nebraska that calculates 
the energy efficiency, greenhouse gas (GHG) emissions, and natural 
resource requirements of corn-to-ethanol biofuel production systems. We 
used the GREET model to estimate the GHG emissions associated with 
current technology as used by petroleum refineries, because we do not 
expect significant changes in petroleum refinery technology.
    We used the EPA-developed Motor Vehicle Emission Simulator (MOVES) 
to estimate vehicle tailpipe GHG emissions. The MOVES modeling system 
estimates emissions for on-road and nonroad sources, covers a broad 
range of pollutants, and allows multiple scale analysis, from fine-
scale analysis to national inventory estimation.
    Finally, for the FRM we intend to use an EPA version of the Energy 
Information Administration's National Energy Modeling System (NEMS) to 
estimate the secondary impacts on the energy market associated with 
increased renewable fuel production. NEMS is a modeling system that 
simulates the behavior of energy markets and their interactions with 
the U.S. economy by explicitly representing the economic decision-
making involved in the production, conversion, and consumption of 
energy products. NEMS can reflect the secondary impacts that greater 
renewable fuel use may have on the prices and quantities of other 
sources of energy, and the greenhouse gas emissions associated with 
these changes in the energy sector. It was not possible to complete 
this analysis in time for the NPRM
    While EPA is using state-of-the-art tools available today for each 
of the lifecycle components considered, using multiple models 
necessitates integrating these models and, where possible, applying a 
common set of assumptions. As discussed later in this section, this is 
particularly important for the two agricultural sector models, FASOM 
and FAPRI, which are being used in combination to describe the 
agricultural sector impacts domestically and internationally. As 
described in more detail in the DRIA Chapter 5, we have worked with the 
FAPRI and FASOM models to align key assumptions. As a result, the 
projected agricultural impacts described in Section IX are relatively 
consistent across both models. One outstanding issue is the differences 
between the modeling results associated with increased soybean-based 
biodiesel production. We intend to further refine the soybean biodiesel 
scenarios for the final rule. Additional details on all of the models 
used can be found in DRIA Chapter 2. Finally, as noted earlier, we are 
planning to have a number of aspects of our modeling framework peer 
reviewed before finalizing these regulations. In the sections below, we 
have identified specific peer review plans.
4. Treatment of Uncertainty
    While EPA believes the methodology presented here represents a 
robust and scientifically credible approach, we recognize that some 
calculations of GHG emissions are relatively straight-forward, while 
others are not. The direct, domestic emissions are relatively well 
known. These estimates are based on well-established process models 
that can relatively accurately capture

[[Page 25027]]

emissions impacts. For example, the energy and GHG emissions used by a 
natural gas-fired ethanol plant to produce one gallon of ethanol can be 
calculated through direct observations, though this will vary somewhat 
between individual facilities. The indirect domestic emissions are also 
fairly well understood; however, these results are sensitive to a 
number of key assumptions (e.g., current and future corn yields). We 
address uncertainty in this area by testing the impact of changing 
these assumptions on our results. Finally, the indirect, international 
emissions are the component of our analysis with the highest level of 
uncertainty. For example, identifying what type of land is converted 
internationally and the emissions associated with this land conversion 
are critical issues that have a large impact on the GHG emissions 
estimates. We address this uncertainty by using sensitivity analyses to 
test the robustness of the results based on different assumptions. We 
also identify areas of additional work that will be completed prior to 
the final rulemaking. For example, while we utilized an approach using 
comprehensive agricultural sector models and recent satellite data to 
determine the emissions resulting from international land use impacts, 
we are also considering an alternative methodology (the analyses using 
GTAP) that estimates changes in land use based on the relative land use 
values of cropland, forest, and pastureland. Additionally, we are 
considering country-specific information which may allow us to better 
predict specific trends in land use such as the degree to which 
marginal or abandoned pasture land will need to be replaced if used 
instead for crop production. In addition to the sensitivity analysis 
approach, we will also explore options for more formal uncertainty 
analyses for the final rule to the extent possible. However, formal 
uncertainty analyses generally include an assumption of a statistically 
based distribution of likely outcomes. In the time available for 
developing this proposal, we have not developed an analytical technique 
which allows us to determine the likelihood of a range of possible 
outcome across the wide range of critical factors affecting lifecycle 
GHG assessment. We specifically ask for recommendations on how best to 
conduct a sound, statistically based uncertainty analysis for the final 
rule.
    Despite the uncertainty associated with international land use 
change, we would expect at least some international land use change to 
occur as demand for crop land increases as a result of this rule. 
Furthermore, the conversion of crop land will lead to GHG emission from 
land conversion that must be accounted for in the calculation of 
lifecycle GHG emissions. As discussed above, we believe that 
uncertainty in the effects and extent of land use changes is not a 
sufficient reason for ignoring land use change emissions. Although 
uncertainties are associated with these estimates, it would be far less 
scientifically credible to ignore the potentially significant effects 
of land use change altogether than it is to use the best approach 
available to assess these known emissions. We anticipate that comment 
and information received in response to this proposal as well as 
additional analyses will improve our assessment of land use impacts for 
the final rule. Finally, we note that further research on key variables 
will result in a more robust assessment of these impacts in the future.
5. Components of the Lifecycle GHG Emissions Analysis
    As described previously, GHG emissions from many stages of the full 
fuel lifecycle are included within the system boundaries of this 
analysis. Details on how these emissions were calculated are included 
in the DRIA Section 2. This section highlights the key questions that 
we have attempted to address in our analysis. In addition, this section 
identifies some of the key assumptions that influence the GHG emissions 
estimates in the following section.
a. Feedstock Production
    Our analysis addresses the lifecycle GHG emissions from feedstock 
production by capturing both the direct and indirect impacts of growing 
corn, soybeans, and other renewable fuel feedstocks. For both domestic 
and international agricultural feedstock production, we analyzed four 
main sources of GHG emissions: agricultural inputs (e.g., fertilizer 
and energy use), fertilizer N2O, livestock, and rice 
methane. (Emissions related to land use change are discussed in the 
next section).
    As described in Section IX.A, EPA uses FASOM to model domestic 
agricultural sector impacts and uses FAPRI to model international 
agricultural sector impacts. However, we also recognize that these 
emission estimates rely on a number of key assumptions, including crop 
yields, fertilizer application rates, use of distiller grains and other 
co-products, and fertilizer N2O emission rates. As described 
in the following sections, we have used sensitivity analyses to test 
the impact of changing these assumptions on our results.

i. Domestic Agricultural Sector Impacts

    Agricultural Sector Inputs: GHG emissions from agricultural sector 
inputs (chemical and energy) are determined based on output from FASOM 
combined with default factors for GHG emissions from GREET. Fuel use 
emissions from GREET include both the upstream emissions associated 
with production of the fuel and downstream combustion emissions. Inputs 
are based on historic rates by region and include projected increases 
to account for yield improvements over time. This yield increase does 
not capture changes due to cropping practices such as shifts to corn-
after-corn rotations.
    N2O Emissions: FASOM estimates N2O emissions 
from fertilizer application and nitrogen fixing crops based on the 
amount of fertilizer used and different regional factors to represent 
the percent of nitrogen (N) fertilizer applied that result in 
N2O emissions. This approach is consistent with IPCC 
guidelines for calculating N2O emissions from the 
agricultural sector.\272\ A recent paper \273\ raised the question of 
whether N2O emissions are significantly higher than 
previously estimated. To better understand this issue, we are working 
with Colorado State University to analyze N2O emissions. 
Specifically, Colorado State University will provide several key 
refinements for a re-analysis of land use and cropping trends and GHG 
emissions in the FASOM assessment, including:
---------------------------------------------------------------------------

    \272\ 2006 Intergovernmental Panel on Climate Change (IPCC) 
Guidelines for National Greenhouse Gas Inventories, Volume 4, 
Chapter 11, N2O emissions from Managed Soils, and 
CO2 Emissions from lime and Urea Application. See http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol4.html.
    \273\ Crutzen et al., 2008.
---------------------------------------------------------------------------

     Direct N2O emissions based on DAYCENT 
simulations with an accounting of all N inputs to agricultural soils, 
including mineral N fertilizer, organic amendments, symbiotic N 
fixation, asymbiotic N fixation, crop residue N, and mineralization of 
soil organic matter. Colorado State University will provide (1) the 
total emission rate on an acre basis for each simulated bioenergy crop 
in the 63 FASOM regions and (2) a total emissions for each N source.
     Indirect N2O emissions on a per acre basis 
using results from DAYCENT simulations of volatilization, leaching and 
runoff of N from each bioenergy crop included in the analysis for the 
63 FASOM regions, combined with IPCC

[[Page 25028]]

factors for the N2O emission associated with the simulated N 
losses.
    The analyses with updated N2O estimates are not yet 
complete and are not included in this proposal. We expect to complete 
these analyses for the final rule.
    Livestock Emissions: GHG emissions from livestock have two main 
sources: enteric fermentation and manure management. Enteric 
fermentation produces methane emissions as part of the normal digestive 
processes in animals. The FASOM modeling reflects changes in livestock 
enteric fermentation emissions due to changes in livestock herds. As 
more corn is used in producing ethanol the price of corn increases, 
driving changes in livestock production costs and demand. The FASOM 
model predicts reductions in livestock herds. IPCC factors for 
different livestock types are applied to herd values to get GHG 
emissions. The management of livestock manure can produce methane and 
N2O emissions. Methane is produced by the anaerobic 
decomposition of manure. N2O is produced as part of the 
nitrogen cycle through the nitrification and denitrification of the 
organic nitrogen in livestock manure and urine. FASOM calculates these 
manure management emissions based on IPCC default factors for emissions 
factors from the different types of livestock and management methods. 
Manure management emissions are projected to be reduced as a result of 
lower livestock animal numbers. Use of distiller grains (DGs), as 
discussed in Section VI.B.5.b, has been shown to decrease methane 
produced from enteric fermentation if replacing corn as animal 
feed.\274\ This effect is not currently captured in the models but will 
be considered for the final rule.
---------------------------------------------------------------------------

    \274\ Salil Arora, May Wu, and Michael Wang, ``Update of 
Distillers Grains Displacement Ratios for Corn Ethanol Life-Cycle 
Analysis,'' September 2008. See http://www.transportation.anl.gov/pdfs/AF/527.pdf.
---------------------------------------------------------------------------

    Methane from Rice: Most of the world's rice, and all rice in the 
United States, is grown in flooded fields. When fields are flooded, 
aerobic decomposition of organic material gradually depletes most of 
the oxygen present in the soil, causing anaerobic soil conditions. Once 
the environment becomes anaerobic, methane is produced through 
anaerobic decomposition of soil organic matter by methanogenic 
bacteria. FASOM predicts changes in rice acres resulting from the RFS2 
program and calculates changes in methane emissions using IPCC factors.

ii. International Agricultural Sector GHG Impacts

    Agricultural Sector Inputs: The FAPRI model does not directly 
provide an assessment of the GHG impacts of changes in international 
agricultural practices (e.g., changes in fertilizer load and fuels 
usage), however it does predict changes in the land area and production 
by crop type and by country. We therefore determined international 
fertilizer and energy use based on international data collected by the 
Food and Agriculture Organization (FAO) of the United Nations and the 
International Energy Agency (IEA). We used the historical trends based 
on these FAO and IEA data to project chemical and energy use in 2022. 
Additional details on the data used are included in DRIA Chapter 2. We 
intend to review input changes required to increase yields for the 
final rule and request comment on the extent to which historic trends 
adequately project what could occur in 2022 or what alternative 
assumptions should be made and the bases for these assumptions. For 
example, will changes in farming practices or seed varieties likely 
result in significantly different impacts on fertilizer use 
internationally than suggested by recent trends? Additionally, we 
intend to have the selection and application of this data peer reviewed 
before the final rule.
    N2O Emissions: For international N2O 
emissions from crops, we apply the IPCC emissions factors based on 
total amount of fertilizer applied and N2O impacts of crop 
residue by type of crop produced. As noted above, we are also working 
with Colorado State University to update these factors as part of the 
final rule analysis. Additional details on the factors used are 
included in DRIA Chapter 2.
    Livestock Emissions: Similar to domestic livestock impacts 
associated with an increase in biofuel production, FAPRI model predicts 
international changes in livestock production due to changes in 
commodity prices. The GHG impacts of these livestock changes, including 
enteric fermentation and manure management GHG emissions, were included 
in our analysis. Unlike FASOM, the FAPRI model does not have GHG 
emissions built in and therefore livestock GHG impacts were based on 
activity data provided by the FAPRI model (e.g., number and type of 
livestock by country) multiplied by IPCC default factors for GHG 
emissions. We seek comments on the extent to which the use of this 
methodology is appropriate.
    Rice Emissions: To estimate rice emission impacts internationally, 
we used the FAPRI model to predict changes in international rice 
production as a result of the increase in biofuels demand in the U.S. 
Since FAPRI does not have GHG emissions factors built into the model, 
we applied IPCC default factors by country based on predicted changes 
in rice acres. We seek comments on this methodology.
b. Land Use Change
    We are also addressing GHG emissions associated with land use 
changes that occur domestically and internationally as a result of the 
increase in renewable fuels demand in the U.S. Key questions we address 
in this analysis include the land area converted to crop production, 
where those acreage changes occur, lands types converted, and the GHG 
emission impacts associated with different types of land conversion.
    EPA recognizes that analyzing international impacts of land use 
change can introduce additional uncertainty to the GHG emissions 
estimates. At this time, we do not have the same quality of data for 
international crop production and projected future trends as we do for 
the United States. For example, prediction of the economic and 
geographic development of developing country agricultural systems is 
far more difficult than prediction of future U.S. agricultural 
development. The U.S. has a very mature agriculture system in which the 
high quality agricultural lands are already under production and the 
infrastructure to move crops to market is already in place. This is not 
necessarily the case in other countries. Some very large countries 
expected to play a significant role in future agricultural production 
are still developing their agricultural system. Brazil, for example, 
has vast areas of land that may be suitable for commercial agricultural 
production that would allow for significant expansion in crop lands. 
One of the restraints on expansion is the relative lack of 
infrastructure (e.g., road and rail systems) that would allow shipment 
of expanded crop production to market. Identifying what type of land is 
converted internationally and the emissions associated with this land 
conversion can significantly affect our assessment of GHG impacts. We 
present a range of results for differences in these and other 
assumptions in Section VI.C.2, and we seek comment on our approach so 
that the final rule will use the best science to provide credible 
estimates of lifecycle GHG emissions for each biofuel.

[[Page 25029]]

i. Amount of Land Converted

    The main question regarding the amount of new land needed to meet 
an increasing demand for biofuels hinges on assumptions about the 
intensification of existing production versus expansion of production 
to other lands. This interaction is driven by the relative costs and 
returns associated with each option, but there are other factors as 
described below.
    Co-Products: One factor determining the amount of new crop acres 
required under an increased biofuel scenario is the treatment of co-
products. For example, distillers grains (DGs) are the major co-product 
of dry mill ethanol production that is also used as animal feed. 
Therefore, using the DGs as an animal feed to replace the use of corn 
tends to offset the loss of corn to ethanol production, and reduces the 
need to grow additional corn to feed animals. As the renewable fuels 
industry expands, the handling and use of co-products is also 
expanding. Some uncertainty is associated with how these co-products 
will be used in the future (e.g., whether it can be reformulated for 
higher incorporation into pork and poultry diets, whether it will be 
dried and shipped long distances, whether fractionation will become 
widespread).
    Both our FASOM and FAPRI models account for the use of DGs in the 
agricultural sector. The FASOM and FAPRI models both assume that a 
pound of co-product would displace roughly a pound of feed. However, a 
recent paper by Argonne National Laboratory \275\ estimates that 1 
pound of DGs can displace more than a pound of feed due to the higher 
nutritional value of DGs compared to corn.
---------------------------------------------------------------------------

    \275\ Salil et al., 2008.
---------------------------------------------------------------------------

    The Argonne replacement ratios do not take into account the dynamic 
least cost feed decisions faced by livestock producers. The actual use 
of DGs will depend on the maximum inclusion rates for each type of 
animal (based on the digestibility of DGs), the displacement ratio for 
each type of animal (based on DGs energy and protein content), and the 
adoption rate (based on the feed value relative to price). Furthermore, 
as world vegetable oil prices increase, dry mill ethanol producers will 
have an incentive to extract the corn oil from the DGs. This step 
changes the nutritional content of the DGs, which results in different 
replacement rates than the ones currently used in FASOM or described by 
Argonne. As we plan to evaluate and incorporate a least cost feed 
rationing approach for the final rule, we invite comment on the 
expected future uses of DGs and their displacement ratios.
    Crop Yields: Assumptions about yields and how they may change over 
time can also influence land use change predictions. Domestic yields 
were based on USDA projections, extrapolated out to 2022. In 2022, we 
estimate that the U.S. average corn yield will be approximately 180 
bushels/acre (a 1.6% annual increase consistent with recent trends) and 
average U.S. soybean yields will be approximately 50 bushels per acre 
(a 0.4% annual increase).\276\ Using the FASOM model, we conducted a 
sensitivity analysis on the impact of higher and lower yields in the 
U.S. Details on this scenario are included in DRIA Chapter 5.1. 
International yields changes are also based on the historic trends. The 
FAPRI model contains projected yields and yield growths that are 
generally lower in other countries compared to the U.S. We request 
comment on the projected increase in crop yields in the U.S (including 
consideration of how emerging seed types might be expected to increase 
average crop yields). We also request comment on the use of historical 
trends to predict future agricultural production in other countries and 
request information on alternative methodologies and supporting data 
that would allow us to base our predictions on alternative assumptions.
---------------------------------------------------------------------------

    \276\ Note that these same assumptions apply in both the 
reference case and the control cases.
---------------------------------------------------------------------------

    The FASOM and FAPRI models currently do not take into account 
changes in productivity as crop production shifts to marginal acres or 
the impact of price induced yield changes on land use change. We would 
expect these two factors could work in opposite directions and 
therefore could tend to offset each other's impacts. Marginal acres in 
fully developed agricultural systems are expected to have lower yields, 
because most productive acres are already under cultivation. This may 
not be the case in developing systems where prime agricultural lands 
are not currently in full production due to, for example, lack of 
supporting infrastructure. Changes in agricultural inputs (e.g., 
fertilizer, pesticides) can also change crop yield per acre. Higher 
commodity prices might provide an incentive to increase production in 
existing acres. If the costs of increasing productivity on existing 
land were minimal relative to the value of the increased production, 
then agricultural landowners would presumably adopt these productivity-
enhancing actions under the reference case. Although it is reasonable 
to assume a trend wherein some productivity-enhancing practices may 
become profitable if commodity prices are high enough such as might 
occur as the result of increased biofuel production, it is not clear 
that farmers would find significant increases in production per acre 
profitable. If crop yields either domestically or international are 
significantly impacted by higher commodity prices driven by general 
increase in worldwide demand, this could affect our assessment of land 
use impacts and the resulting GHG emissions due to increased biofuel 
demand in the U.S. However, as described in Section IX, the change in 
commodity prices associated with the increase in U.S. biofuel as a 
result of the EISA mandates are very small and perhaps not large enough 
to induce significant increased yield changes. We invite comment on 
projected yields and the potential impact of increased use of marginal 
lands and price induced yield changes. For the final rule we plan to 
explicitly model the impact of price induced yield changes.
    Land Conversion Costs: The assumed cost associated with different 
types of land conversion can also play a key role in determining how 
much land will be converted. In FASOM, the decision to convert land 
from pasture or forest to cropland is based on whether the landowner 
can increase the net present value of expected returns through 
conversion (including any costs of conversion). Among other things, the 
decision to convert land depends on regional yields, costs, and other 
factors affecting profitability and on the returns to alternative land 
uses. In other words, FASOM assumes that land conversion is based on 
maximizing profits rather than minimizing costs. Additional details on 
land conversions costs incorporated in FASOM are included in DRIA 
Chapter 2.
    FAPRI does not explicitly model land conversion costs, however the 
international production supply curves used by the FAPRI model 
implicitly take into account conversion costs. FAPRI's supply curves 
are based on historical responses to price changes, which take into 
account the conversion costs of land, based on expected future returns 
associated with land conversion. Thus, we believe that our assessments 
of international land use changes are based on economic land-use 
decisions.
ii. Where Land is Converted
    The first step in determining what domestic and international land 
will be converted due to biofuels production is to estimate the extent 
to which the increased demand for biofuel feedstock

[[Page 25030]]

will be met through increased U.S. agriculture production or reductions 
in U.S. exports.
    This question has several implications. For example, U.S. 
agriculture production is typically more energy and input intensive but 
has higher yields than agricultural production in other parts of the 
world. This implies that increased production in the U.S. has higher 
input GHG emission impacts but lower land use change impacts compared 
to overseas production. In addition, the types of land where 
agriculture would expand would be different in the U.S. vs. other parts 
of the world.
    EPA's analysis relies on FASOM predictions to represent changes in 
the U.S. agricultural sector, including land use, and on FAPRI to 
predict the resulting international agricultural sector impacts 
including the amount of additional cropland needed under different 
scenarios. The impact on the international agricultural sector is 
highly dependent on the U.S. export assumptions. As the FASOM model was 
used to represent domestic agricultural sector impacts with an assumed 
export picture, the international agricultural sector impacts from 
FAPRI needed to be based on a consistent set of export assumptions. We 
worked with FASOM and FAPRI modelers to ensure this consistency. This 
involved coordinating crop yields, ethanol yields and co-product use, 
assumptions regarding CRP acres, a consistent export response, and a 
consistent livestock demand and feed use in both models.
    As shown in Chapter 2 of the DRIA, coordination of assumptions has 
generated a consistent export picture response from both the FASOM and 
FAPRI model for the majority of biofuel and feedstock scenarios 
considered. Differences in responses in the biodiesel scenario remain 
between the two models. FASOM assumes more biodiesel will come from new 
soybean acres (but total domestic acres are relatively constant as 
reductions in other crops offset the increase in soybean acres). In 
comparison, FAPRI contains more types of oil seed crops and has a more 
elastic demand in the soybean oil market. The FAPRI model also allows 
for some corn oil fractionation from DGs, which can be used as a 
substitute for soybean oil. The FASOM model predicts a larger change in 
net exports than the FAPRI model. Since we are using the FAPRI model as 
the basis for estimating international land use changes, we may be 
underestimating the international land use change emissions associated 
with soybean based biodiesel. For the final rule, EPA will work, in 
particular, to resolve the differences in soybean production impact 
between the models. This, too, may modify our assessment of the 
biodiesel lifecycle GHG emissions.
    Due to the wide range of carbon and biomass properties associated 
with land in different parts of the world, the location of crop 
conversion is also important to our lifecycle analysis. For example, an 
average acre of forest in Southeast Asia stores a much larger quantity 
of carbon than a typical acre of forest in Northern Europe. The FAPRI 
model provides estimates of the acreage change by country and crop that 
result from a decrease in U.S. exports due to the increase in U.S. 
biofuel demand. These estimates are based on historic responsiveness to 
changes in prices in other countries. Implicit in these supply curves 
are the costs associated with converting new land to crop production 
and the relative competitiveness of each country to increase production 
based on production costs, yields, transportation costs, and currency 
fluctuations. FAPRI also includes in its baseline projections of future 
population growth, GDP growth, and other macroeconomic changes. FAPRI 
also takes into account the fact that not all U.S. exports will need to 
be made up in international production, as there is a small decreases 
in demand due to shifts in crop production and higher prices.

iii. What Type of Land is Converted

    In the same way that the location of land conversion is important, 
the type of land that is converted is critical to the magnitude of 
impact on the GHG emissions associated with biofuel production. For 
example, the conversion of rainforest results in a much larger increase 
in GHG emissions than the conversion of grassland. There are several 
options for determining what type of land will be converted to crop 
acreage. One option is to model land rental rates for different types 
of land (e.g., forest, pasture, and crop production), and allow the 
model to choose the type of land that is expected to have the highest 
net returns. This approach is used by FASOM on the domestic side. 
Another option is to use historical land conversion trends in a given 
country or region. The FAPRI/Winrock approach uses this approach for 
international land use conversion.
    Domestic: The FASOM model includes competition between land types, 
agriculture, pasture, and forest land. The interaction is based on 
providing the highest rate of return across the different land types. 
Therefore domestically we have the ability to explicitly model what 
types of land would be converted to increased agriculture based on the 
rates of return for different land types for the 63 regions in FASOM. 
For this draft proposal we incorporated the agricultural component 
(which includes both existing cropland and pasture) of the FASOM model, 
but not the forestry component (see Section IX.A for explanation). 
Therefore, this analysis assumes that all additional cropland predicted 
by FASOM comes from pasture. As we incorporate the forestry component 
for the final rule analysis we would expect to see more interaction 
between the forestry and agriculture sector such that there may be 
conversion of forest to agriculture based on additional cropland 
needed. While we do not know if forest will be converted to cropland or 
the extent that this might occur, if domestic forests were converted to 
cropland, we would expect domestic GHG emissions would increase. This 
work will be incorporated for our final rule.
    International: Basing land use change on the economics and rates of 
return of different land uses offers advantages for capturing potential 
future land use changes. However, the only model potentially capable of 
fully incorporating this calculation internationally, GTAP, is still in 
the process of being updated and modified for this purpose. Thus, EPA 
has chosen to use historical patterns as identified by satellite images 
to estimate future land conversion. This approach is referred to here 
as the FAPRI/Winrock approach because it relies on the integration of 
each of these tools.
    EPA believes that FAPRI/Winrock is a scientifically credible 
modeling approach at this time. However, we will continue to work with 
the GTAP model to help test the results generated by our primary 
approach.

FAPRI/Winrock

    Since FAPRI does not contain information on what type of land is 
being converted into cropland, we worked with Winrock International, a 
global nonprofit organization, to address this question. A key 
advantage of Winrock is that they can accurately measure and monitor 
trends in forest and land use change, forest carbon content, 
biodiversity, and the impact of infrastructure development. 
Furthermore, several of the Winrock staff were involved in the 
development of the IPCC land use change good practice guidance and are 
widely recognized as the leaders in this field.
    Using satellite data from 2001-2004, Winrock provided a breakdown 
of the types of land that have been converted

[[Page 25031]]

into cropland for a number of key agriculturally producing countries 
based on the International Geosphere-Biosphere Programme (IGBP).\277\ 
The IGBP land cover list includes eleven classes of natural vegetation, 
three classes of developed and mosaic lands, and three classes of non-
vegetated lands. The natural vegetation units distinguish evergreen and 
deciduous, broadleaf and needle-leaf forests, mixed forests, where 
mixtures occur; closed shrublands and open shrublands; savannas and 
woody savannas; grasslands; and permanent wetlands of large areal 
extent. The three classes of developed and mosaic lands distinguish 
among croplands, urban and built-up lands, and cropland/natural 
vegetation mosaics. Classes of non-vegetated land cover units include 
snow and ice; barren land; and water bodies. Winrock aggregated these 
categories into five similar classes: five classes of forest were 
combined into one, two classes of savanna were combined into one, and 
two classes of shrubland were combined into one. The final land cover 
categories for this analysis are forest, cropland, grassland, savanna, 
and shrubland. The rest of the IGBP categories not of interest to this 
analysis were reclassified into the background. The satellite data 
represents different types of land cover, which we are using as a proxy 
for land use.
---------------------------------------------------------------------------

    \277\ U.S. Geological Survey MODIS Data Set Documentation. See 
http://edcdaac.usgs.gov/modis/mod12q1v4.asp.
---------------------------------------------------------------------------

    A key strength of this approach is that satellite information is 
based on empirical data instead of modeled predictions. Furthermore, it 
is reasonable to assume that recent land use changes have been driven 
largely by economics and recent historical patterns will continue in 
the future absent major economic or land use regime shifts caused, for 
example, by changes in government policies. We are using the FAPRI 
model to predict where in the world, based on economic conditions, the 
most likely increase in agriculture production will occur as a result 
of the EISA mandates. We are then using the historical satellite data 
to address the key question: If additional land is needed for crop 
production in a particular country, what type of land will be used? The 
Winrock analysis addresses this question by calculating the weighted 
average type of land that was converted to cropland between 2001 and 
2004. Essentially, we are using the Winrock data to determine the type 
of land that is most likely to be converted to cropland, should 
additional acres be needed as predicted by FAPRI.
    Table VI.B.5-1 shows the percentage of land converted to cropland 
between 2001 and 2004 according to the Winrock satellite data analysis 
for the countries currently available. We use these percentages to 
calculate a weighted average of the types of land converted into 
cropland. For example, if FAPRI predicts that one additional acre of 
cropland will be brought into production in Argentina, we used the 
Winrock data to estimate that 8% on average of that acre will come from 
forest, 40% of that acre will come from grassland, 45% of that land 
will come from savanna, and 8% of that land will come from shrubland. 
Using GTAP might result in different percentage weights.

                         Table VI.B.5-1--Types of Land Converted to Cropland by Country
                                                  [In percent]
----------------------------------------------------------------------------------------------------------------
                     Country                          Forest         Grassland        Savanna          Shrub
----------------------------------------------------------------------------------------------------------------
Argentina.......................................               8              40              45               8
Brazil..........................................               4              18              74               4
China...........................................              17              38              23              21
EU..............................................              27              16              36              21
India...........................................               7               7              33              53
Indonesia.......................................              34               5              58               4
Malaysia........................................              74               3              19               3
Nigeria.........................................               4              56              36               4
Philippines.....................................              49               5              44               3
South Africa....................................              10              22              53              15
----------------------------------------------------------------------------------------------------------------
Source: Winrock Satellite Data (2001-2004).

    We are assuming that the weighted average, resulting from 
agriculture demand as well as other possible drivers, is a reasonable 
estimate of the land use change attributable to increased agricultural 
demand. A shortcoming of this approach is that it assumes that when new 
crop acres are needed to meet increased agricultural demand these crop 
acres will follow the average pattern of recent historical land 
conversion, recognizing that this pattern is based on a variety of 
drivers of land use change, not all of which are associated with 
agricultural demand. This approach is not able to isolate from the 
historical pattern the land use changes stemming just from increased 
agricultural demand. For example, it is likely that in some cases trees 
are being removed from forests for the value of the wood. However, 
having removed valuable wood, additional clearing may occur to allow 
the land to be used for pasture or cropland. In that case the GHG 
emissions associated with the removal of the trees would not occur as a 
consequence of increased agricultural demand, but as a consequence of 
increased demand for the wood, while the GHG emissions associated with 
the additional clearing would occur as a consequence of the 
agricultural demand.
    As a result, the Winrock data also does not distinguish between the 
land-use impacts associated with one crop versus another. Indeed, at 
least in the case of sugarcane production in Brazil, a number of 
researchers argue that expanded sugarcane production is likely to occur 
in significant part through the use of degraded or abandoned pasture 
land without additional land use impact.\278\ These research reports 
suggest that general historical trends in land use change to grow crops 
in Brazil may not pertain to expected growth in sugarcane production. 
Ideally, an analysis of a U.S. biofuels policy's influence on land use 
change would

[[Page 25032]]

model the marginal impact that U.S. biofuel would have on land use and 
land use change in addition to baseline land use change. Use of 
historic land use change data is capturing some of this baseline land 
use change. Comments are requested on our approach of assuming 
historical land use changes will continue to be followed in response to 
increased agricultural demand associated with our biofuel policy. We 
also invite comment on what alternative methodologies and data are 
available, if any, to better link the impacts of biofuels to land use 
change. To the extent additional information or data may be available 
for certain countries such as the example of Brazil, we also ask how 
this country-specific data and similar information might best be 
integrated with the modeling results otherwise available. Furthermore, 
to the extent different government policies can shift land use patterns 
(e.g., through regulations, financial supports), these weighted 
averages could change in the future. We request comment on whether 
these government policies and regulations should be incorporated into 
the future land use change calculations and the best methodology for 
taking into account these changes.
---------------------------------------------------------------------------

    \278\ See for example ``Mitigation of GHG emissions using 
sugarcane bio-ethanol--Working Paper'' by Isaias C. Macedo and 
Joaquim E. A. Seabra, and ``Prospects of the Sugarcane Expansion in 
Brazil: Impacts on Direct and Indirect Land Use Changes--Working 
Paper'' by Andre Nassar et al., both received by EPA October 13, 
2008.
---------------------------------------------------------------------------

    The Winrock data and analyses present an aggregate picture of land 
use changes; they cannot predict the nature of the land use change that 
will result due to an additional acre of corn planted in a country 
versus an additional acre of sugarcane or soybeans. In reality, 
sugarcane may be more suitable for planting in different regions with 
different soil types compared to corn or soybeans. However, because we 
are using weighted averages to characterize the type of land that is 
converted to crop acres, all additional crop acres in a particular 
country are treated identically.
    Winrock also provides information on land conversions between other 
categories (e.g., forest to savanna). For one set of GHG analyses, we 
assumed that land taken out of actively managed use \279\ (e.g., 
pasture used for livestock production) would have to be replaced with 
new pasture acreage, thereby capturing some of the domino effect 
associated with converting previously productive land into cropland. 
Therefore, in addition to land conversion shown in Table VI.B.5-1, we 
also include land conversion to replace some of the grassland and 
savanna that is used as pasture. An alternative approach would be to 
assume that no additional land is necessary, since there is a 
significant amount of pastureland that could be used more intensively 
for grazing purposes. For example, as noted above, in Brazil almost all 
of the direct land conversion associated with expanding sugarcane 
production is coming out of existing pasture land, in some cases, 
depleted, low value pasture land, that may have relatively low levels 
of stored carbon compared to other land. Also in Brazil there is a 
trend toward more intensive use of existing pasture land by grazing 
higher numbers of cattle per unit of pasture, decreasing the need to 
replace pasture converted to cropland. This more intensive use of 
pasture is encouraged by two factors: improved grasses which can 
sustain more intensive grazing and lack of transportation 
infrastructure which tends to constrain geographic expansion of pasture 
lands. However, we also note that depleted cropland in Brazil might 
also be suitable for other crop production. To extend sugarcane limits 
to production of these other crops on this land, the indirect effect 
could be that these crops move into other areas of Brazil and resulting 
in increased emissions due to land use change. We invite comment on 
alternative methodologies for predicting land use changes in particular 
in other countries. Some alternative methodologies are described in 
more detail in Chapter 2 of the DRIA.
---------------------------------------------------------------------------

    \279\ GTAP Land Cover Data (2000-2001).
---------------------------------------------------------------------------

    The FAPRI model results have been used in peer reviewed literature 
in conjunction with satellite data to assess land use changes \280\ and 
we also believe it is an appropriate method for projecting biofuel 
induced land use changes. However, we recognize the uncertainty 
associated with this approach and, in addition to seeking public 
comment, we plan to conduct an expert peer review of the data and 
methods used, including the appropriateness of using historic satellite 
data to project future land use changes.
---------------------------------------------------------------------------

    \280\ Searchinger et al., 2008.
---------------------------------------------------------------------------

iv. What Are the GHG Emissions Associated With Different Types of Land 
Conversion?
    Our estimates of domestic land use change GHG emissions are based 
on outputs of the FASOM model. As we are just using the agricultural 
portion of the FASOM model for this analysis the land use change GHG 
emissions are limited to changes in land use for existing crop and 
pasture land. Some of that crop land could currently be fallow and some 
of the pasture land could currently be unused. However, no new crop or 
pasture land (beyond some Conservation Reserve Program (CRP) land due 
to legislative changes in the program) is added compared to current 
levels. Thus FASOM only models shifts in the use of this land.
    Changes in the agricultural sector due to increased corn used for 
ethanol have impacts on land use change in a number of ways. FASOM 
explicitly models change in soil carbon from increased crop production 
acres and from different types of crop production. FASOM also models 
changes in soil carbon from converting non crop land into crop 
production. Land converted to crop land could include pasture land. As 
recommended by USDA, we are assuming that 32 million acres of CRP land 
will remain in that program even if crop prices increase and thus 
increase land values. This assumption is consistent with the 2008 Farm 
Bill, which limits CRP acres to 32 million. A sensitivity analysis on 
this assumption is included in Chapter 5 of the DRIA.
    For the international impacts, we used the 2006 IPCC Agriculture, 
Forestry, and Other Land Use (AFOLU) Guidelines \281\ and the Winrock 
provided GHG emissions factors for each country based on the weighted 
average type of land converted. GHG emissions estimates were based on 
immediate releases (e.g., changes in biomass carbon stocks, soil carbon 
stocks, and non-CO2 emissions assuming the land is cleared 
with fire) and foregone forest sequestration (the future growth in 
vegetation and soil carbon). Additional details on these calculations 
are included in Chapter 2 of the DRIA. For the emissions factors 
presented, we assume forests cleared would have continued to sequester 
carbon for another 80 years, based on the amount of time it takes for 
forests to reach a general equilibrium stage. We request comment on 
whether it is appropriate to include foregone sequestration in the GHG 
emissions estimates. Carbon soil calculations \282\ take into account 
the annual changes in carbon content in the top 30 centimeters of soil 
over the first 20 years, based on IPCC recommendations.\283\ We also 
request comment on whether soil carbon calculations should be based on 
the top 30 centimeters of soil. These emission factors do not include 
credits for harvested wood products, based on the expectation that they 
would have a

[[Page 25033]]

very small impact on our estimates of land use change emissions. 
However, we intend to analyze the impact of wood product credits for 
the final rule. We invite comment on whether it is appropriate to 
include wood product credits in the GHG emissions estimates.
---------------------------------------------------------------------------

    \281\ 2006 IPCC Guidelines for National Greenhouse Gas 
Inventories, Volume 4, Agriculture, Forestry and Other Land Use 
(AFOLU). See http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol4.html.
    \282\ See ftp://www.daac.ornl.gov/data/global_soil/IsricWiseGrids.
    \283\ 2006 IPCC Guidelines for National Greenhouse Gas 
Inventories, Volume 4, Section 5.3.3.4.
---------------------------------------------------------------------------

    GHG emissions associated with land use changes vary significantly 
based on the type of land and the geographic region. For example, the 
GHG emissions associated with converting an acre of grassland to 
cropland in China are lower than the emissions associated with 
converting an acre of shrubland to cropland in China. Similarly, the 
GHG emissions associated with converting an acre of forest to cropland 
in Malaysia are larger than the emissions associated with converting an 
acre of forest in Nigeria to cropland. Where country specific emission 
factors were not available in time for the proposal, we used world 
average. For the proposal, we focused on the countries with the largest 
projected changes in crop acreage. The Winrock data currently covers 
63% of total land use change acres associated with corn ethanol, 53% of 
the acres associated with biodiesel, 57% of the acres associated with 
switchgrass, and 87% of the acres associated sugarcane ethanol. We will 
continue to add additional countries for our analysis for the final 
rule. Two changes that may impact these results for the final rule 
include the addition of perennial crops and the conversion on land with 
peat soils. We request comment on our calculation of emission factors 
due to land use change; improved data and assumptions are specifically 
requested. Additionally, we plan to have the calculation of these 
emissions factors reviewed by experts in this field. Details on the 
Winrock estimates are included in the DRIA Chapter 2.

GTAP Approach:

    GTAP is an economy-wide general equilibrium model that was 
originally developed for addressing agricultural trade issues among 
countries. The databases and versions of the model are widely used 
internationally.\284\ Since its inception in 1993, GTAP has rapidly 
become a common ``language'' for many of those conducting global 
economic analysis. For example, the WTO and the World Bank co-sponsored 
two conferences on the so-called Millennium Round of Multilateral Trade 
talks in Geneva. Here, virtually all of the quantitative, global 
economic analyses were based on the GTAP framework. Over the past few 
years, a version of the model was developed to explicitly model global 
competition among different land types (e.g., forest, agricultural 
land, pasture) and different qualities of land based on the relative 
value of the alternative land-uses. More recently, it was modified to 
include biofuel substitutes for gasoline and diesel. In simulating land 
use changes due to biofuels production, GTAP explicitly models land-use 
conversion decisions, as well as land management intensification. For 
example, it allows for price-induced yield changes (e.g., farmers can 
reallocate inputs to increase yields when commodity prices are high) 
and considers the marginal productivity of additional land (e.g., 
expansion of crop land onto lower quality land as a result of the 
increased use of biofuels). Most importantly, in contrast to other 
models, GTAP is designed with the framework of predicting the amount 
and types of land needed in a region to meet demands for both food and 
fuel production. The GTAP framework also allows predictions to be made 
about the types of land available in the region to meet the needed 
demands, since it explicitly represents different land types within the 
model.
---------------------------------------------------------------------------

    \284\ https://www.gtap.agecon.purdue.edu.
---------------------------------------------------------------------------

    The global modeling of land-use competition and land management 
decisions is relatively new, and evolving.\285\ GTAP does not yet 
contain cellulosic feedstocks in the model. In addition, GTAP does not 
currently contain unmanaged land, which could be a major factor driving 
current GTAP land use projections and is a significant potential source 
of GHG emissions. We expect to update GTAP with cellulosic feedstocks 
and unmanaged land in time for the final rule.
---------------------------------------------------------------------------

    \285\ See Hertel, Thomas, Steven Rose, Richard Tol (eds.), (in 
press). Economic Analysis of Land Use in Global Climate Change 
Policy, Routledge Publishing.
---------------------------------------------------------------------------

    Our proposal is therefore based on the FAPRI/Winrock estimates. 
There are advantages and disadvantages associated with any model choice 
and we have chosen the FAPRI/Winrock combination as the best approach 
available for preparing the proposal. Although we have not relied on 
the current version of GTAP for the principal analyses in this 
proposal, others have used versions of the current model to assess land 
use changes which could result from expanded biofuel demand. The 
California Air Resources Board as part of the analysis for their low 
carbon fuel standard used GTAP to model indirect land use change for 
biofuels. More information on their program and GTAP analysis can be 
found at http://www.arb.ca.gov/fuels/lcfs/lcfs.htm. Furthermore, 
researchers from Purdue University have released a report on work using 
GTAP to look at land use change associated with corn ethanol production 
scenarios.\286\ This work was partially funded by Argonne National Lab 
for possible inclusion in the GREET model. We anticipate additional 
refinements will be made to the GTAP model between the proposal and 
final rule and we will include this information and results in the 
docket as they become available. We invite comments in this NPRM on the 
use of the GTAP model in helping to establish the GHG emissions 
estimates for the final rule.
---------------------------------------------------------------------------

    \286\ Land Use Change Carbon Emissions due to US Ethanol 
Production, Wallace E. Tyner, Farzad Taheripour, Uris Baldos, 
January 2009. Available at http://www.agecon.purdue.edu/papers/biofuels/Argonne-GTAP_Revision%204a.pdf.
---------------------------------------------------------------------------

v. Assessing GHG Emissions Impacts Over Time and Potential Application 
of a GHG Discount Rate
    When comparing the lifecycle GHG emissions associated with biofuels 
to those associated with gasoline or diesel emissions, it is critical 
to take into consideration the time profile associated with each fuel's 
GHG emissions stream. With gasoline, a majority of the lifecycle GHG 
emissions associated with extraction, conversion, and combustion are 
likely to be released over a short period of time (i.e., annually) as 
crude oil is converted into gasoline or diesel fuel which quickly pass 
to market. This means that the lifecycle GHG emissions of a gallon of 
gasoline produced one year are unlikely to vary much from the lifecycle 
GHG emissions of a similar gallon of gasoline produced in a subsequent 
year.
    In contrast, the lifecycle GHG emissions from the production of a 
typical biofuel may continue to occur over a long period of time. As 
with petroleum based fuels, renewable fuel lifecycle GHG emissions are 
associated with the conversion and combustion of biofuels in every year 
they are produced. In addition, GHG emissions could be released through 
time if new acres are needed to produce corn, soybeans or other crops 
as a replacement for crops that are directly used for biofuel 
production or displaced due to biofuels production. The GHG emissions 
associated with converting land into crop production would accumulate 
over time with the largest release occurring in the first few years due 
to clearing with fire or biomass decay. After the land is converted, 
moderate amounts of soil carbon would continue to be released for

[[Page 25034]]

approximately 20 years.\287\ Furthermore, there would be foregone 
sequestration associated with forest clearing as this forest would have 
continued to sequester carbon had it not been cleared for approximately 
80 years.
---------------------------------------------------------------------------

    \287\ Following Section 5.3.3.4 of the IPCC AFOLU guidelines, 
the total difference in soil carbon stocks before and after 
conversion was averaged over 20 years.
---------------------------------------------------------------------------

    Therefore, we have included an analysis which considers GHG 
emissions from land use change that may continue for up to 80 years, 
based on our estimate of the average length of foregone sequestration 
after a forest is cleared. Annual foregone sequestration rates were 
estimated by ecological region using growth rates for forests greater 
then 20 years old from the 2006 IPCC guidelines for Agriculture, 
Forestry and Other Land Use.\288\ Studies have estimated that new 
forests grow for 90 years to over 120 years.\289\ More recent estimates 
suggest that old growth forests accumulate carbon for up to 800 
years.\290\ The foregone sequestration methods used in this proposal 
are within the range supported by the scientific literature and the 
2006 IPCC guidelines. Details of the foregone sequestration estimates 
are included in DRIA Chapter 2. We seek comment on our estimate of the 
average length of annual foregone forest sequestration for 
consideration in biofuel lifecycle GHG analysis.
---------------------------------------------------------------------------

    \288\ Table 4.9 from the 2006 GL AFOLU was used to estimate the 
lost C sequestration of forests that were converted to another land 
use.
    \289\ See Greenhouse Gas Mitigation Potential in U.S. Forestry 
and Agriculture, EPA Document 430-R-05-006 for a discussion of the 
time required for forests to reach carbon saturation.
    \290\ Luyassert, S et al., 2008. Old-growth forests as global 
carbon sinks. Nature 455: 213-215. Link: http://www.nature.com/nature/journal/v455/n7210/abs/nature07276.html.
---------------------------------------------------------------------------

    Figure VI.B.5-1 shows how lifecycle GHG emissions vary over time 
for a natural gas fired dry mill corn ethanol plant assuming that all 
land use change occurs in 2022. While biomass feedstocks grown each 
year on new cropland can be converted to biofuels that offer an annual 
GHG benefit relative to the petroleum product they replace, these 
benefits may be small compared to the upfront release of GHG emissions 
from land use change. Depending on the specific biofuel in question, it 
can take many years for the benefits of the biofuel to make up for the 
large initial releases of carbon that result from land conversion 
(e.g., the payback period). As shown in Figure VI.B.5-1, the payback 
period for a natural gas-fired dry mill corn ethanol plant which begins 
operation in 2022 would be approximately 33 years. We present a similar 
payback period calculation for the full range of biofuels analyzed in 
Section VI.C.
[GRAPHIC] [TIFF OMITTED] TP26MY09.008

    As required by EISA, our analysis must demonstrate whether biofuels 
reduce GHG emissions by the required percentage relative to the 2005 
petroleum baseline. A payback period alone cannot answer that question. 
Since the payback period alone is not sufficient for our analysis, we 
have considered accounting methods for capturing the full stream of 
emissions and benefits over time. There are at least two necessary 
criteria for the accounting methods we have considered. First, they 
must provide an estimate of renewable fuel lifecycle GHG emissions that 
is consistent over time. Otherwise, for example, all of the upfront 
emissions due to land clearing would be assigned to corn ethanol 
produced in the first year, and none of those emissions to corn ethanol 
produced the following years even though this land use change is 
central to the production over these following years. Second, the 
accounting method must also provide a common metric that allows for a 
direct comparison of biofuels to gasoline or

[[Page 25035]]

diesel. When accounting for the time profile of lifecycle GHG 
emissions, the two most important assumptions in the determination of 
whether a biofuel meets the specified emissions reduction thresholds 
include: (1) The time period considered and (2) the discount rate 
(which could be zero) applied to future emissions streams.

Time Periods Considered

    The illustration of the payback period in Figure VI.B.5-1 
demonstrates the importance of the time period over which to consider 
both the lifecycle GHG emissions increases associated with the 
production of a biofuel as well as the benefits from using the biofuel. 
As mentioned above, based on our lifecycle GHG analysis for this 
proposed rule we estimate that the payback period for corn ethanol 
produced in a natural gas-fired dry mill is approximately 33 years. In 
this case, if we measure GHG impacts over a time period of less than 33 
years we will determine that the total corn ethanol produced over this 
time period increases lifecycle GHG emissions. Conversely, total corn 
ethanol production will reduce net lifecycle GHG emissions if we look 
beyond 33 years, with net emissions reductions increasing the further 
into the future we extend our analysis. To inform our decision of which 
time period for analysis is most appropriate, we must consider a number 
of factors including but not limited to the length of time over which 
we expect a particular biofuel to be produced, the time over which 
biofuel production continues to impact GHG emissions into the future, 
the importance of achieving near-term GHG emissions reductions, and the 
increasing uncertainty of projecting GHG emissions impacts into the 
future. Based on these considerations, our discussion of lifecycle 
analyses prepared for this proposed rule focuses on time periods of 100 
years and 30 years.
    There are advantages and disadvantages to using the 100 and 30 year 
time frames to represent both emissions impacts as well as emissions 
benefits of use of biofuels over time. There are several principal 
reasons for using the 100 year time frame. First, greenhouse gases are 
chemically stable compounds and persist in the atmosphere over long 
time scales that span two or more generations. Second, the 100 year 
time frame captures the emissions associated with land use change that 
may continue for a long period of time after biofuel-induced land 
conversion first takes place.\291\ For example, physical changes in 
carbon stocks on unmanaged lands may not slow until after 100 years, 
and optimal forest rotation ages can influence greenhouse gas emissions 
for 100 years on managed lands. Similarly, a 100 year time frame would 
allow estimating the future changes in the land should the need for 
these changes due to biofuel production cease. For example, as 
discussed in more detail below, if production of a biofuel ended, then 
the land use impacts associated with that biofuel would also tend to go 
away in a process known as land use reversion. A longer time frame 
would allow assessment of the impacts of that land use reversion.
---------------------------------------------------------------------------

    \291\ Luyassert, S et al., 2008. Old-growth forests as global 
carbon sinks. Nature 455: 213-215. Link: http://www.nature.com/nature/journal/v455/n7210/abs/nature07276.html.
---------------------------------------------------------------------------

    For a number of reasons we believe that biofuel production could 
continue for a long time into the future. As biofuel technologies 
advance and production costs are decreased, it is likely that renewable 
fuels will become increasingly competitive with petroleum-based fuels. 
Another reason for expecting long term biofuel production is that, 
unlike a specific facility that has an expected lifetime, the RFS 
program does not have a specified expiration date. The expectation that 
renewable fuel production will continue for a long time provides 
justification for using a longer time frame for analysis, such as 100 
years. Another reason for considering an inter-generational time period 
such as 100 years for lifecycle GHG analysis is that climate change is 
a long-term environmental problem that may require GHG emissions 
reductions for many decades.
    The 100 year time frame also has drawbacks. A general concern with 
projecting impacts over a very long time period is that uncertainty 
increases the further the analysis is extended into the future. For 
example, a 100 year analysis presumes that production of a particular 
biofuel will continue for at least 100 years. Although we expect 
renewable fuel production as a whole to continue for a long time, it is 
possible that due to changing market conditions or other factors, the 
use of first generation biofuels (e.g., corn ethanol) could see a 
decline in use over a shorter period of time.
    For this proposal, we are also showing the results of analyzing 
both GHG emissions impacts of producing a biofuel as well as benefits 
from using the biofuel over 30 years, a time frame which has been used 
in the literature to estimate the greenhouse gas impacts of 
biofuels.292 293 Since a time period such as 30 years would 
truncate the potential GHG benefits that accumulate over time, this 
second option would reduce the GHG benefits of biofuels relative to 
gasoline or diesel compared to assuming a longer time frame for biofuel 
production such as 100 years.
---------------------------------------------------------------------------

    \292\ Searchinger et al., 2008.
    \293\ M. Delucchi, ``A multi-country analysis of lifecycle 
emissions from transportation fuels and motor vehicles'' (UCD-ITS-
RR-05-10, University of California at Davis, Davis, CA 2005). See 
also http://www.its.ucdavis.edu/people/faculty/delucchi/.
---------------------------------------------------------------------------

    One advantage of using a shorter time period is that it is more 
``conservative'' from a climate change policy perspective. In general, 
the further out into the future an analysis projects, the more 
uncertainty is introduced into the results. For example, with a longer 
time period for analysis, it is more likely that significant changes in 
market factors or policies will change the incentives for producing 
biofuels. If a biofuel only has greenhouse benefits when considered in 
an extended future time frame, it is not clear that these benefits will 
be realized due to the inherent uncertainty of the future. Also, 
potential irreversible climate change impacts or future actions in 
other sectors of the economy, such as reductions from stationary 
sources, could influence the relative importance of renewable fuel GHG 
impacts. The timing and severity of these potential irreversible 
climate change impacts are clearly uncertain as is the degree to which 
near-term lifecycle emissions related to biofuel production influences 
these climate change impacts. Given these uncertainties, it may be 
appropriate to limit our analysis horizon to a much shorter time period 
such as 30 years.
    Several disadvantages are also associated with choosing the 30 year 
time frame to represent both emissions impacts as well as emissions 
benefits. One key disadvantage is that it ignores the potential sources 
of GHG emissions impacts of producing biofuel after 30 years such as 
foregone sequestration from forests that may have been removed which 
could have continuing impacts even after production of a biofuel has 
ended. Thus, it doesn't account for the full land use emissions 
``signature'' of biofuels. In addition, even if second generation fuels 
start to dominate new construction, building a first generation fuel 
production facility such as a corn ethanol refinery represents a 
significant capital investment. Once the facility is built and 
financed, it may continue

[[Page 25036]]

producing biofuel as long as it is covering its operating costs. This 
suggests that, once a plant is built, if the variable cost of corn 
ethanol production is less than the cost to produce gasoline, then corn 
ethanol production at that facility may continue. This economic 
advantage may contribute to the longevity of first generation biofuel 
production and usage far into the future.
    An appropriate time frame for analysis could also be different for 
different biofuels. While we could assume that corn ethanol would be 
phased out after a shorter time period such as 30 years, it might be 
more appropriate to use a longer time period over which to analyze the 
benefits of other advanced biofuels such as cellulosic biofuels. It 
could be reasonably assumed that cellulosic biofuels will be produced 
for more than 30 years, perhaps for 100 years or longer. However, even 
if cellulosic biofuels are expected to be produced for 100 years or 
longer, a shorter time period, such as 30 years, may still be the most 
relevant period over which to assess GHG emissions, given the 
importance of near-term emissions reductions and the increasing 
uncertainty of future events. We specifically seek comments on the 100 
year and 30 year time frames discussed in this proposal. We also seek 
general comments on the most appropriate time periods for analysis of 
biofuels, and whether we should use different time periods for 
different types of renewable fuels.
    Another way to look at the time period issue, which we have not 
specifically analyzed for this proposed rule, would separate the time 
period into two parts. The first part would consider how long we expect 
production of a particular biofuel to continue into the future. We 
refer to this concept, which is similar to the project lifetime often 
considered in traditional cost benefit analysis, as the ``project'' 
time horizon. The second part would address the length over which to 
account for the changes in GHG emissions due to land use changes which 
result from biofuel production. We call this the ``impact'' time 
horizon.
    Our analysis for this proposed rule has not considered a scenario 
where the project time horizon is shorter than impact time horizon. 
However, we are considering this option for the final rule. For 
example, we could look at a scenario where corn ethanol production 
continues for 30 years and land use related GHG emissions are estimated 
for 100 years. Specifically, we are considering whether to use 30 years 
after 2015 (as an approximation of when ethanol production from corn 
starch reaches 15 billion gallons) as a reasonable estimate of when 
corn will no longer be used for ethanol production due to advances in 
other biofuels and the competing demand to use corn for food rather 
than biofuel feedstock. We specifically ask whether a 30 year estimate 
of continued corn starch ethanol production (i.e., through 2045) is a 
reasonable estimate for assessing the stream of GHG benefits from corn 
ethanol use while 100 years would be appropriate for assessing impacts 
of the land use change. Under such an assumption a 100 time horizon 
would capture the longer term emission impacts of corn ethanol 
production (including indirect land use impacts) while the benefits 
from 31 through 100 years would be zero since corn ethanol would be 
modeled as no longer in use.
    In that scenario, we would have to consider the lifecycle GHG 
impacts after the production of corn ethanol ends. This would include 
the issue of land reversion, or what happens to the land used to 
produce a biofuel feedstock after its use for biofuel production has 
ceased. A full accounting of land reversion would involve economic 
modeling to determine how long we expect production of a particular 
biofuel to last, and to determine the land use changes after that 
biofuel production ends. Ideally this modeling would extend well beyond 
2022 to the point where land reversion is complete, and it would 
include projections for global crop yield improvements, population 
trends, food demand, and other key factors. For this proposal, we have 
not projected the GHG emissions associated with land reversion, but we 
plan to consider land reversion in our final rule analysis and we seek 
comments on methodologies and approaches for doing this. We also seek 
comment on the related issue of how best to estimate how long each type 
of biofuel is most likely to continue to be produced, and whether 
production of these biofuels is likely to end abruptly or phase out 
gradually.
    Agricultural and economic models that look beyond 2022 would not 
only help to estimate the impacts of land reversion after biofuel 
production ends, they would also help to project how evolving 
agricultural conditions could influence the lifecycle GHG emissions of 
biofuels beyond 2022. For example, corn yields per acre are expected to 
continue increasing after 2022; this increase in yields per acre will 
decrease the amount of land required to produce a bushel of corn. At 
higher yields, fewer acres are required to grow the corn used for the 
15 billion gallons of corn starch ethanol modeled for the rule. The 
indirect impacts of maintaining 15 billion gallons of corn ethanol 
production would similarly be reduced. EPA intends to more carefully 
model these transitions in particular to better account for future land 
use impacts and we invite comments on methodology, sources of data, 
factors that should be considered in assessing whether and when a 
particular biofuel such as ethanol from corn starch, for example, will 
no longer be produced and recommendations on how to improve on our 
assessment of the likely stream of GHG emissions after 2022 that will 
result from the EISA mandates.
    A complicating consideration in this analysis arises in determining 
future use of the land (post-biofuel production) is the fact that 
perhaps significant land use change occurred as a result of biofuel 
production and that land is now more easily suited for alternative uses 
compared to its pre-biofuel state. For example, the demand created by 
biofuel production may have justified clearing forested lands and 
turning them into productive cropland. Even if the need for the land to 
produce crops in response to biofuel demand ceases when the biofuel 
production ends, the land will still be in an altered form making it, 
for example, more economically available for other crop production than 
when it had been forested. How this land is subsequently used can 
affect its impact on GHG emissions. If it is used for intensive crop 
production, the land will have a much different carbon sequestration 
profile, for example, than if it returned to its pre-biofuel forested 
state. EPA asks for suggestions on how to best treat these lingering 
effects of land use change when attributing the effects of biofuel 
demand to uses of land even after biofuel production ends.
    For the determination of whether biofuels meet the GHG emissions 
reduction required by EISA, we present the results for a range of time 
periods, including both 100 years and 30 years in Section VI.C and 
specifically invite comment on whether use of a 100 year time frame, a 
30 year time frame, or some other time frame, would be most 
appropriate.
    In addition to this general issue of the appropriate time frames 
for analysis, several more specific issues exist. Since it would be 
likely that corn starch ethanol production will phase out gradually 
rather than stopping all of a sudden in 2045, we also are evaluating 
options for estimating the phase out of corn starch ethanol production. 
One simplifying assumption would have corn ethanol production phase out

[[Page 25037]]

linearly between 2022 and 2045 as production of other biofuels such as 
cellulosic biofuels continue to expand. Comments are requested on the 
option of linearly phasing out corn ethanol production from 2022 
through 2045 and other approaches for estimating this transition in 
corn ethanol production. Finally, its not only corn starch ethanol that 
might be replaced in future years. For example, the use of soy oil for 
biodiesel fuel production might be replaced by other non-food oils such 
as oil from algae. Comments are requested on whether other biofuels 
will similarly phase out of use and therefore the land use change 
impacts need to be similarly considered.
    In addition to seeking comments on all of the issues related to the 
time periods for lifecycle analysis, EPA plans to convene a peer review 
of the range of time periods considered in this proposed rule. This 
peer review will also seek expert feedback on all of the issues raised 
above in this section, including how to determine the most appropriate 
time periods for consideration in the final rule.

Discounting of Lifecycle GHG Emissions

    Economic theory suggests that in general consumers have a time 
preference for benefits received today versus receiving them in the 
future. Therefore, future benefits are often valued at a discounted 
rate. Although discount rates are most often applied to the monetary 
valuation of future versus present benefits, a discounting approach can 
also be used to compare physical quantities (i.e., total GHG emissions 
per gallon of fuel used).
    The concept of weighting physical units accruing at different times 
has been used in the environmental and resource economics 
literature,\294\ and is analogous to valuing the monetary cost and 
benefits of a policy, only that in this case the metric that we `value' 
is the reduction in GHG emissions. \295\ An important part of the 
economic theory of time is the idea that benefits expected to accrue in 
the long term are less certain than benefits in the near term. This is 
true in the case of GHG emissions changes from biofuel production which 
are dependent upon how long biofuel production will continue, how 
technologies will develop over time, and other factors. Another reason 
to give more weight to near-term emissions changes is that the risks 
associated with climate change in the future include the possibility of 
extreme climate change and threshold impacts (e.g., species and 
ecosystem thresholds, catastrophic events). Increased GHG emissions in 
the near-term may be more important in terms of physical damage to the 
world's environment. Some scientists, for example, believe that effects 
on factors such as arctic summer ice, Himalayan-Tibetan Glaciers, and 
the Greenland ice sheet are more likely to be effected by near-term GHG 
emissions, causing non-linearities in the effects attributable to GHG 
emissions.\296\ Long-term GHG reductions may be too late to mitigate 
these irreversible impacts, providing further justification for 
discounting GHG emissions changes that are expected in the distant 
future. Under this perspective, it would be appropriate to discount the 
physical quantities of future emissions, and especially in a long term 
analysis of lifecycle GHG emissions. Thus in our analysis with a 100 
year time frame, or impact horizon, we discount the value of future GHG 
emissions changes.
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    \294\ Herzog et al. 2003 (See http://sequestration.mit.edu/pdf/climatic_change.pdf), Richards 1997, Stavins and Richards 2005 (See 
http://www.pewclimate.org/docUploads/Sequest_Final.pdf).
    \295\ Sunstein and Rowell, 2007, On Discounting Regulatory 
Benefits: Risk, Money, and Intergenerational Equity, Chicago Law 
Review.
    \296\ Ramanathan and Feng, 2008. On avoiding dangerous 
anthropogenic interference with the climate system: Formidable 
challenges ahead. Proceedings of the National Academy of Sciences 
105:143245-14250.
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    Despite the rationale for discounting future GHG emissions changes 
discussed above, there are reasons to be cautious about the application 
of discounting in lifecycle GHG analysis. One argument is that it may 
only be appropriate to discount monetized values. Our lifecycle 
analysis estimates GHG emission impacts, not their monetary value, and 
under this argument emissions should not be directly discounted. 
Rather, the physical GHG emissions should be converted into monetary 
impacts, where these monetary impacts are also a function of climate 
science. The resulting climate impacts would then have to be translated 
into monetary values. This presents significant challenges for 
lifecycle GHG analysis because it is difficult to translate dynamic GHG 
emissions into a single estimate of physical impacts, much less a 
single estimate of monetized impacts. This is the case for a number of 
reasons, including the complex physical systems associated with climate 
change (e.g., the relationship between atmospheric degradation rates 
with atmospheric carbon stocks) that may create non-constant marginal 
damages from GHG emissions over time. Furthermore, converting lifecycle 
GHG emissions into monetized impacts may be inconsistent with the EISA 
definition of lifecycle GHG emissions provided above in Section VI.A.1, 
which stipulates that lifecycle GHG emissions are the ``aggregate 
quantity of greenhouse gas emissions * * * where the mass values for 
all greenhouse gases are adjusted to account for their relative global 
warming potential.''
    Another argument against discounting GHG emissions changes is the 
concept of inter-generational equity, which argues that benefits or 
damages affecting future generations merit just as much weight as 
impacts felt by current generations. It is argued that this would 
invalidate the practice of discounting emissions impacts that could 
affect future generations.
    Finally, earlier in this section we discussed the possible ranges 
of time frames for analyzing the GHG emissions impacts. For shorter 
time frames such as 30 years, there would be less uncertainty in the 
emissions stream so the benefit of discounting to address uncertainty 
is also lessoned.
    Comments are requested on the concept of discounting a stream of 
GHG emissions for the purpose of estimating lifecycle GHG emissions 
from transportation fuels as specified in EISA.

Appropriate Level of Discount Rate

    As described in more detail in Section IX on GHG emission reduction 
benefits, GHG emissions have primarily consumption effects and inter-
generational impacts, as changes in GHG emissions today will continue 
to have impacts on climate change for decades to centuries. If a 
discount rate is applied to future GHG emissions, an appropriate 
discount rate should be based on a consumption-based discount rate 
given that monetized climate change impacts are primarily consumption 
effects (i.e., impacts on household purchases of goods and services). A 
consumption-based discount rate reflects the implied tradeoffs between 
consumption today and in the future. Discount rates of 3% or less are 
considered appropriate for discounting climate change impacts, since 
they reflect the long run uncertainty in economic growth and interest 
rates and the risk of high impact climate damages that could reduce 
economic growth.\297\
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    \297\ Technical Support Document on Benefits of Reducing GHG 
Emissions, U.S. Environmental Protection Agency, June 12, 2008, 
www.regulations.gov (search phrase ``Technical Support Document on 
Benefits of Reducing GHG Emissions'').

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[[Page 25038]]

    When analyzing the GHG emissions associated with a 100 year time 
period, we examined a variety of alternative discount rates (e.g., 0, 
2, 3, 7 percent) to show the sensitivity of greenhouse gas emissions 
estimates to the choice of the discount rate. A zero discount rate 
estimates GHG emission impacts as if each ton of GHG emissions is 
treated equally through time. Previous methodologies of lifecycle GHG 
benefits have presented results using a zero discount rate.\298\ 
However, some of the climate change literature supports using a higher 
discount rate, as described in Section IX.C. We show the 7% discount 
rate for illustrative purposes; however climate change benefit analyses 
from global long-run growth models typically use discount rates well 
under 7% for standard analysis.\299\ High discount rates imply very low 
values for the future GHG emission impacts resulting from today's 
actions on the welfare of future generations. Therefore, lower discount 
rates such as 2-3% are considered more appropriate for discounting long 
term climate change impacts.\300\
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    \298\ Searchinger et al., 2008.
    \299\ Tol, 2005.
    \300\ Newell and Pizer, 2003.
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    In the analysis for this proposal we use a 2% discount rate to 
assess the present value of GHG emissions changes which occur over a 
100 year time frame. This discount rate is consistent with the Office 
of Management and Budget (OMB) \301\ and EPA \302\ guidance and is one 
of the discount rates that has been used in the literature to monetize 
the impacts of climate change.\303\ EPA has considered this issue 
previously, and after weighing the pros and cons of different values, 
set forth a guidance document recommending using a range of consumption 
based discount rates of 0.5-3%. OMB and EPA guidance on inter-
generational discounting suggests using a low but positive discount 
rate if there are important inter-generational benefits and costs. In 
selecting a 2% discount rate coupled with a 100 year emission stream 
estimate, EPA would be recognizing the long term nature of the emission 
impacts of biofuel production, the uncertainty in estimating these 
emission impacts and their consequences plus the significance of nearer 
term emission changes in avoiding future consequences. Other options 
for intergenerational discounting have been discussed in the economic 
literature, such as dealing with uncertainty by using a non-constant, 
declining, or negative discount rate.\304\ Comments could consider how 
discounting appropriately reflects the uneven emission of greenhouse 
gases from biofuels over time, the uncertainty in predicting emissions 
in more distant futures and the impacts these emissions could have on 
climate change. Alternative approaches for inter-generational 
discounting are described in Chapter 5.3 of the DRIA.
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    \301\ OMB Circular A-4, 2003 provides a range of 1-3% for 
consumption based discount rates.
    \302\ EPA Guidelines for Preparing Economic Analyses, 2000.
    \303\ Tol (2005, 2007).
    \304\ Newell and Pizer, 2003, Weitzman (1999, 2001), Nordhaus 
(2008), Guo et al., (2006), Saez, C.A. and J.C. Requena, 
``Reconciling sustainability and discounting in Cost-Benefit 
Analysis: A methodological proposal'', Ecological Economics, 2007, 
vol. 60, issue 4, pages 712-725.
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    Because we are considering not discounting GHG emissions and in 
particular since the justifications for discounting physical emissions 
are not as strong for shorter time periods, in Section VI.C.2, we also 
present the GHG emissions reductions associated with biofuels using a 
30 year time period and no discount rate. Using a zero percent or no 
discount rate implies that all emission releases and uptakes during 
this time period are valued equally. For a shorter time period such as 
thirty years, we are relatively certain of the emission trends. 
Furthermore, all of these emissions occur in a relatively short period 
of time so their impact on climate change and the consequences of that 
climate change could all be considered the same regardless of whether 
those emissions occurred early or late in this 30-year time period.
    We specifically invite comment on our use of a 2% discount rate 
with a 100 year time period for analysis of lifecycle GHG emissions, 
and our use of no discount rate in our analysis of GHG emissions over 
30 years. We also invite comments on whether using physical science 
metrics such as the actual quantities of climate forcing gasses in the 
atmosphere, actual quantities of climate forcing gasses in the 
atmosphere weighted by global warming potential (GWP), or cumulative 
radiative forcing should be used to evaluate emissions over time. 
Specifically, we seek comment on an approach for comparing GHG 
emissions based on the time profile of the greenhouse gas emissions in 
the atmosphere, and whether this approach would be consistent with the 
legal definition of lifecycle GHG emissions in EISA. One such method is 
the Fuel Warming Potential as outlined in a memo to the EPA from the 
Union of Concerned Scientists which is available on the public docket 
for this rulemaking.\305\ This approach is based on the ratio of the 
cumulative radiative forcing between the biofuel and the gasoline case 
over a specified time frame.
---------------------------------------------------------------------------

    \305\ See Memo to EPA, Office of Transportation and Air Quality 
from Union of Concerned Scientists, Re: Treatment of Time in Life 
Cycle Accounting, February 18, 2009.
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    The EISA definition of lifecycle GHG emissions stipulates that the 
mass values for all greenhouse gas emissions shall be adjusted to 
account for their relative GWP. We are proposing to use the standard 
100-year GWP's published in the IPCC Second Assessment 
Report.306 307 We invite comment on whether it is 
appropriate to discount GWP-weighted emissions and how such discounting 
might appropriately apply across the several greenhouse gases.
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    \306\ See http://www.ipcc.ch/ipccreports/assessments-reports.htm.
    \307\ O'Hare, Plevin, Martin, Jones, Kendal and Hopson; ``Proper 
accounting for time increases crop-based biofuel's greenhouse gas 
deficit versus petroleum''; Environmental Research Letters, 4 (2009) 
024001.
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    Furthermore, if alternative time periods for the production of 
biofuels and the GHG impacts of biofuel production are considered as 
discussed above, and the choice is made to discount GHG emissions, the 
question that arises is: What discount rate or combination of discount 
rates should be considered? For example, if ethanol production is 
assumed to occur for 30 years and the GHG impacts are assumed to span 
across 80-100 years, should a single discount rate be applied to the 
emissions stream or alternative discount rates based upon the different 
time frames? EPA is taking comment on whether and how to apply 
discounting when different time frames between the production and long-
run GHG impacts are utilized to analysis biofuels. Specifically, EPA is 
considering and requests comment on the option of using either no 
discount rate or a 3% discount rate to assess those emissions that 
occur during the relatively shorter time frame for biofuel use which 
could phase out within 30 years as in our corn ethanol example and a 2% 
discount rate over the reminder of the 100 years in assessing the 
longer term GHG emissions impacts resulting from land use changes 
related to biofuel production (including land reversion 
considerations).
    EPA is considering a range of discount rates including zero or no 
discounting for reasons as described above and requests comments on the 
appropriate discount rate to use when assessing the stream of GHG 
emission changes that are likely to result from biofuel production and 
use. Other

[[Page 25039]]

options for intergenerational discounting have been discussed in the 
economic literature, such as dealing with uncertainty by using a non-
constant, declining, or negative discount rate.\308\ Comments could 
consider how discounting appropriately reflects the uneven release of 
greenhouse gases from biofuels over time, the uncertainty in predicting 
emissions in more distant futures and the impacts these emissions could 
have on climate change. Alternative approaches for inter-generational 
discounting are described in Chapter 5.3 of the DRIA.
---------------------------------------------------------------------------

    \308\ Newell and Pizer, 2003, Weitzman (1999, 2001), Nordhaus 
(2008), Guo et al., (2006), Saez, C.A. and J.C. Requena, 
``Reconciling sustainability and discounting in Cost-Benefit 
Analysis: A methodological proposal'', Ecological Economics, 2007, 
vol. 60, issue 4, pages 712-725.
---------------------------------------------------------------------------

    EPA recognizes that the time horizon for analysis and the treatment 
of future emissions including the appropriateness of applying discount 
factors are key factors in determining biofuel lifecycle GHG impacts; 
therefore, we plan to organize an expert peer review of these issues 
before the final rule.
c. Feedstock Transport
    The GHG impacts of transporting corn from the field to the ethanol 
facility and transporting the co-product DGs from the ethanol facility 
to the point of use were included in this analysis. The GREET default 
of truck transportation of 50 miles was used to represent corn 
transportation from farm to plant. Transportation assumptions for DGs 
transport were 14% shipped by rail 800 miles, 2% shipped by barge 520 
miles, and 86% shipped by truck 50 miles. The percent shipped by mode 
was from data provided by USDA and based on Association of American 
Railroads, Army Corps of Engineers, Commodity Freight Statistics, and 
industry estimates. The distances DGs were shipped were based on GREET 
defaults for other commodities shipped by those transportation modes. 
The GHG emissions from transport of corn and DGs are based on GREET 
default emission factors for each type of vehicle including capacity, 
fuel economy, and type of fuel used. Similar detailed analyses were 
conducted for the transport of cellulosic biofuel feedstock and 
biomass-based diesel feedstock.
    As part of this rulemaking analysis we have conducted a more 
detailed analysis of biofuel production locations and transportation 
distances and modes of transport used in the criteria pollutant 
emissions inventory calculations described in DRIA Chapter 1.6 and for 
the cost analysis of this rule described in DRIA Chapter 4.2. Given the 
timing of when the current analysis was completed we were not able to 
incorporate this updated transportation information into our lifecycle 
analysis but plan to do that for the final rule.
    Furthermore, the transportation modes and distances assumed for 
corn and DGs do not account for the secondary or indirect 
transportation impacts. For example, decreases in exports might reduce 
overall domestic agricultural commodity transport and emissions but 
might increase transportation of commodities internationally. We plan 
to consider these secondary transportation impacts in our final rule 
analysis.
d. Processing
    The GHG emissions estimates associated with the processing of 
renewable fuels is dependent on a number of assumptions and varies 
significantly based on a number of key variables. The ethanol yield 
impacts the total amount of corn used and associated