[Federal Register Volume 75, Number 58 (Friday, March 26, 2010)]
[Rules and Regulations]
[Pages 14669-14904]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2010-3851]



[[Page 14669]]

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Part II

Book 2 of 2 Books

Pages 14669-15320





Environmental Protection Agency





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40 CFR Part 80



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

Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules 
and Regulations

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA-HQ-OAR-2005-0161; FRL-9112-3]
RIN 2060-A081


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: Under the Clean Air Act Section 211(o), as amended by the 
Energy Independence and Security Act of 2007 (EISA), 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. This action finalizes the regulations that 
implement the requirements of EISA, including the cellulosic, biomass-
based diesel, advanced biofuel, and renewable fuel standards that will 
apply to all gasoline and diesel produced or imported in 2010. The 
final 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. This final rule also implements 
the revised statutory definitions and criteria, most notably the new 
greenhouse gas emission thresholds for renewable fuels and new limits 
on renewable biomass feedstocks. This rulemaking marks the first time 
that greenhouse gas emission performance is being applied in a 
regulatory context for a nationwide program. As mandated by the 
statute, our greenhouse gas emission assessments consider the full 
lifecycle emission impacts of fuel production from both direct and 
indirect emissions, including significant emissions from land use 
changes. In carrying out our lifecycle analysis we have taken steps to 
ensure that the lifecycle estimates are based on the latest and most 
up-to-date science. The lifecycle greenhouse gas assessments reflected 
in this rulemaking represent significant improvements in analysis based 
on information and data received since the proposal. However, we also 
recognize that lifecycle GHG assessment of biofuels is an evolving 
discipline and will continue to revisit our lifecycle analyses in the 
future as new information becomes available. EPA plans to ask the 
National Academy of Sciences for assistance as we move forward. Based 
on current analyses we have determined that ethanol from corn starch 
will be able to comply with the required greenhouse gas (GHG) threshold 
for renewable fuel. Similarly, biodiesel can be produced to comply with 
the 50% threshold for biomass-based diesel, sugarcane with the 50% 
threshold for advanced biofuel and multiple cellulosic-based fuels with 
their 60% threshold. Additional fuel pathways have also been determined 
to comply with their thresholds. The assessment for this rulemaking 
also indicates the increased use of renewable fuels will have important 
environmental, energy and economic impacts for our Nation.

DATES: This final rule is effective on July 1, 2010, and the percentage 
standards apply to all gasoline and diesel produced or imported in 
2010. The incorporation by reference of certain publications listed in 
the rule is approved by the Director of the Federal Register as of July 
1, 2010.

ADDRESSES: EPA has established a docket for this action under Docket ID 
No. EPA-HQ-OAR-2005-0161. All documents in the docket are listed in the 
http://www.regulations.gov Web site. Although listed in the index, some 
information is not publicly available, e.g., confidential business 
information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material, such as copyrighted material, is 
not placed on the Internet and will be publicly available only in hard 
copy form. Publicly available docket materials are available either 
electronically through http://www.regulations.gov or in hard copy at 
the Air and Radiation Docket and Information Center, EPA/DC, EPA West, 
Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public 
Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through 
Friday, excluding legal holidays. The telephone number for the Public 
Reading Room is (202) 566-1744, and the telephone number for the Air 
Docket is (202) 566-1742.

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

SUPPLEMENTARY INFORMATION:

General Information

I. Does This Final Rule Apply to Me?

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

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                                           NAICS \1\
               Category                      codes       SIC \2\ 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 
final action. This table lists the types of entities that EPA is now 
aware could potentially be regulated by this final action. Other types 
of entities not listed in the table could also be regulated. To 
determine whether your activities would be regulated by this final 
action, you should carefully examine the applicability criteria in 40 
CFR part 80. If you have any questions regarding the applicability of 
this final action to a

[[Page 14671]]

particular entity, consult the person listed in the preceding section.

Outline of This Preamble

I. Executive Summary
    A. Summary of New Provisions of the RFS Program
    1. Required Volumes of Renewable Fuel
    2. Standards for 2010 and Effective Date for New Requirements
    a. 2010 Standards
    b. Effective Date
    3. Analysis of Lifecycle Greenhouse Gas Emissions and Thresholds 
for Renewable Fuels
    a. Background and Conclusions
    b. Fuel Pathways Considered and Key Model Updates Since the 
Proposal
    c. Consideration of Fuel Pathways Not Yet Modeled
    4. Compliance with Renewable Biomass Provision
    5. EPA-Moderated Transaction System
    6. Other Changes to the RFS Program
    B. Impacts of Increasing Volume Requirements in the RFS2 Program
II. Description of the Regulatory Provisions
    A. Renewable Identification Numbers (RINs)
    B. New Eligibility Requirements for Renewable Fuels
    1. Changes in Renewable Fuel Definitions
    a. Renewable Fuel
    b. Advanced Biofuel
    c. Cellulosic Biofuel
    d. Biomass-Based Diesel
    e. Additional Renewable Fuel
    f. Cellulosic Diesel
    2. Lifecycle GHG Thresholds
    3. Renewable Fuel Exempt From 20 Percent GHG Threshold
    a. General Background of the Exemption Requirement
    b. Definition of Commenced Construction
    c. Definition of Facility Boundary
    d. Proposed Approaches and Consideration of Comments
    i. Comments on the Proposed Basic Approach
    ii. Comments on the Expiration of Grandfathered Status
    e. Final Grandfathering Provisions
    i. Increases in Volume of Renewable Fuel Produced at 
Grandfathered Facilities Due to Expansion
    ii. Replacements of Equipment
    iii. Registration, Recordkeeping and Reporting
    4. New Renewable Biomass Definition and 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
    v. Algae
    b. Implementation of Renewable Biomass Requirements
    i. Ensuring That RINs Are Generated Only For Fuels Made From 
Renewable Biomass
    ii. Whether RINs Must Be Generated For All Qualifying Renewable 
Fuel
    c. Implementation Approaches for Domestic Renewable Fuel
    i. Recordkeeping and Reporting for Feedstocks
    ii. Approaches for Foreign Producers of Renewable Fuel
    (1) RIN-Generating importers
    (2) RIN-Generating foreign producers
    iii. Aggregate Compliance Approach for Planted Crops and Crop 
Residue From Agricultural Land
    (1) Analysis of Total Agricultural Land in 2007
    (2) Aggregate Agricultural Land Trends Over Time
    (3) Aggregate Compliance Determination
    d. Treatment of Municipal Solid Waste (MSW)
    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. Producers
    b. Importers
    c. Additional Provisions for Foreign Producers
    3. Facilities With Multiple Applicable Pathways
    4. Facilities That Co-Process Renewable Biomass and Fossil Fuels
    5. Facilities That Process Municipal Solid Waste
    6. RINless Biofuel
    E. Applicable Standards
    1. Calculation of Standards
    a. How Are the Standards Calculated?
    b. Standards for 2010
    2. Treatment of Biomass-Based Diesel in 2009 and 2010
    a. Shift in 2009 Biomass-Based Diesel Compliance Demonstration 
to 2010
    b. Treatment of Deficit Carryovers, RIN Rollover, and RIN Valid 
Life For Adjusted 2010 Biomass-Based Diesel Requirement
    3. Future Standards
    F. Fuels That Are Subject to the Standards
    1. Gasoline
    2. Diesel
    3. Other Transportation Fuels
    G. Renewable Volume Obligations (RVOs)
    1. Designation of Obligated Parties
    2. Determination of RVOs Corresponding to the Four Standards
    3. RINs Eligible To Meet Each RVO
    4. Treatment of RFS1 RINs Under RFS2
    a. Use of RFS1 RINs To Meet Standards Under RFS2
    b. Deficit Carryovers From the RFS1 Program to RFS2
    H. Separation of RINs
    1. Nonroad
    2. Heating Oil and Jet Fuel
    3. Exporters
    4. Requirement to Transfer RINs With Volume
    5. Neat Renewable Fuel and Renewable Fuel Blends Designated as 
Transportation Fuel, Heating Oil, or Jet Fuel
    I. Treatment of Cellulosic Biofuel
    1. Cellulosic Biofuel Standard
    2. EPA Cellulosic Biofuel Waiver Credits for Cellulosic Biofuel
    3. Application of Cellulosic Biofuel Waiver Credits
    J. Changes to Recordkeeping and Reporting Requirements
    1. Recordkeeping
    2. Reporting
    3. Additional Requirements for Producers of Renewable Natural 
Gas, Electricity, and Propane
    4. Attest Engagements
    K. Production Outlook Reports
    L. What Acts Are Prohibited and Who Is Liable for Violations?
III. Other Program Changes
    A. The EPA Moderated Transaction System (EMTS)
    1. Need for the EPA Moderated Transaction System
    2. Implementation of the EPA Moderated Transaction System
    3. How EMTS Will Work
    4. A Sample EMTS Transaction
    B. Upward Delegation of RIN-Separating Responsibilities
    C. Small Producer Exemption
    D. 20% Rollover Cap
    E. Small Refinery and Small Refiner Flexibilities
    1. Background--RFS1
    a. Small Refinery Exemption
    b. Small Refiner Exemption
    2. Statutory Options for Extending Relief
    3. The DOE Study/DOE Study Results
    4. Ability To Grant Relief Beyond 211(o)(9)
    5. Congress-Requested Revised DOE Study
    6. What We're Finalizing
    a. Small Refinery and Small Refiner Temporary Exemptions
    b. Case-by-Case Hardship for Small Refineries and Small Refiners
    c. Program Review
    7. Other Flexibilities Considered for Small Refiners
    a. Extensions of the RFS1 Temporary Exemption for Small Refiners
    b. Phase-in
    c. RIN-Related Flexibilities
    F. Retail Dispenser Labeling for Gasoline With Greater Than 10 
Percent Ethanol
    G. Biodiesel Temperature Standardization
IV. Renewable Fuel Production and Use
    A. Overview of Renewable Fuel Volumes
    1. Reference Cases
    2. Primary Control Case
    a. Cellulosic Biofuel
    b. Biomass-Based Diesel
    c. Other Advanced Biofuel
    d. Other Renewable Fuel
    3. Additional Control Cases Considered
    B. Renewable Fuel Production
    1. Corn/Starch Ethanol
    a. Historic/Current Production
    b. Forecasted Production Under RFS2
    2. Imported Ethanol
    3. Cellulosic Biofuel
    a. Current State of the Industry
    b. Setting the 2010 Cellulosic Biofuel Standard
    c. Current Production Outlook for 2011 and Beyond
    d. Feedstock Availability
    i. Urban Waste
    ii. Agricultural and Forestry Residues
    iii. Dedicated Energy Crops

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    iv. Summary of Cellulosic Feedstocks for 2022
    4. Biodiesel & Renewable Diesel
    a. Historic and Projected Production
    i. Biodiesel
    ii. Renewable Diesel
    b. Feedstock Availability
    C. Biofuel Distribution
    1. Biofuel Shipment to Petroleum Terminals
    2. Petroleum Terminal Accommodations
    3. Potential Need for Special Blendstocks at Petroleum Terminals 
for E85
    4. 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. Consideration of >10% Ethanol Blends
V. Lifecycle Analysis of Greenhouse Gas Emissions
    A. Introduction
    1. Open and Science-Based Approach to EPA's Analysis
    2. Addressing Uncertainty
    B. Methodology
    1. Scope of Analysis
    a. Inclusion of Indirect Land Use Change
    b. Models Used
    c. Scenarios Modeled
    2. Biofuel Modeling Framework & Methodology for Lifecycle 
Analysis Components
    a. Feedstock Production
    i. Domestic Agricultural Sector Impacts
    ii. International Agricultural Sector Impacts
    b. Land Use Change
    i. Amount of Land Area Converted and Where
    ii. Type of Land Converted
    iii. GHG Emissions Associated With Conversion
    (1) Domestic Emissions
    (2) International Emissions
    iv. Timeframe of Emission Analysis
    v. GTAP and Other Models
    c. Feedstock Transport
    d. Biofuel Processing
    e. Fuel Transportation
    f. Vehicle Tailpipe Emissions
    3. Petroleum Baseline
    C. Threshold Determination and Assignment of Pathways
    D. Total GHG Reductions
    E. Effects of GHG Emission Reductions and Changes in Global 
Temperature and Sea Level
VI. 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. Particulate Matter
    a. Current Levels
    b. Projected Levels Without RFS2 Volumes
    c. Projected Levels With RFS2 Volumes
    2. Ozone
    a. Current Levels
    b. Projected Levels Without RFS2 Volumes
    c. Projected Levels With RFS2 Volumes
    3. Air Toxics
    a. Current Levels
    b. Projected Levels
    i. Acetaldehyde
    ii. Formaldehyde
    iii. Ethanol
    iv. Benzene
    v. 1,3-Butadiene
    vi. Acrolein
    vii. Population Metrics
    4. Nitrogen and Sulfur Deposition
    a. Current Levels
    b. Projected Levels
    E. Health Effects of Criteria and Air Toxics Pollutants
    1. Particulate Matter
    a. Background
    b. Health Effects of PM
    2. Ozone
    a. Background
    b. Health Effects of Ozone
    3. NOX and SOX
    a. Background
    b. Health Effects of NOX
    c. Health Effects of SOX
    4. Carbon Monoxide
    5. Air Toxics
    a. Acetaldehyde
    b. Acrolein
    c. Benzene
    d. 1,3-Butadiene
    e. Ethanol
    f. Formaldehyde
    g. Peroxyacetyl Nitrate (PAN)
    h. Naphthalene
    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. Environmental Effects of Air Toxics
VII. 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 for Cellulosic Biofuels
    c. Imported Sugarcane Ethanol
    2. Biodiesel and Renewable Diesel Production Costs
    a. Biodiesel
    b. Renewable Diesel
    B. Biofuel Distribution Costs
    1. Ethanol Distribution Costs
    2. Cellulosic Distillate and Renewable Diesel Distribution Costs
    3. Biodiesel Distribution Costs
    C. Reduced U.S. Refining Demand
    D. Total Estimated Cost Impacts
    1. Refinery Modeling Methodology
    2. Overall Impact on Fuel Cost
VIII. Economic Impacts and Benefits
    A. Agricultural and Forestry Impacts
    1. Biofuel Volumes Modeled
    2. Commodity Price Changes
    3. Impacts on U.S. Farm Income
    4. Commodity Use Changes
    5. U.S. Land Use Changes
    6. Impact on U.S. Food Prices
    7. 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
    3. Combining Energy Security and Other Benefits
    4. Total Energy Security Benefits
    C. Benefits of Reducing GHG Emissions
    1. Introduction
    2. Derivation of Interim Social Cost of Carbon Values
    3. Application of Interim SCC Estimates to GHG Emissions 
Reductions
    D. Criteria Pollutant Health and Environmental Impacts
    1. Overview
    2. Quantified Human Health Impacts
    3. Monetized Impacts
    4. What Are the Limitations of the Health Impacts Analysis?
    E. Summary of Costs and Benefits
IX. Impacts on Water
    A. Background
    1. Agriculture and Water Quality
    2. Ecological Impacts
    3. Impacts to the Gulf of Mexico
    B. Upper Mississippi River Basin Analysis
    1. SWAT Model
    2. AEO 2007 Reference Case
    3. Reference Cases and RFS2 Control Case
    4. Case Study
    5. Sensitivity Analysis
    C. Additional Water Issues
    1. Chesapeake Bay Watershed
    2. Ethanol Production and Distribution
    a. Production
    b. Distillers Grain With Solubles
    c. Ethanol Leaks and Spills From Fueling Stations
    3. Biodiesel Plants
    4. Water Quantity
    5. Drinking Water
X. Public Participation
XI. 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. Reporting, Recordkeeping, and Compliance
    5. Related Federal Rules
    6. Steps Taken To Minimize the Significant Economic Impact on 
Small Entities
    a. Significant Panel Findings
    b. Outreach With Small Entities (and the Panel Process)
    c. Panel Recommendations, Proposed Provisions, and Provisions 
Being Finalized
    i. Delay in Standards
    ii. Phase-in
    iii. RIN-Related Flexibilities
    iv. Program Review

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    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
    7. Conclusions
    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
    K. Congressional Review Act
XII. Statutory Provisions and Legal Authority

I. Executive Summary

    Through this final rule, the U.S. Environmental Protection Agency 
is revising the National Renewable Fuel Standard program to implement 
the requirements of the Energy Independence and Security Act of 2007 
(EISA). EISA made significant changes to both the structure and the 
magnitude of the renewable fuel program created by the Energy Policy 
Act of 2005 (EPAct). The EISA fuel program, hereafter referred to as 
RFS2, mandates the use of 36 billion gallons of renewable fuel by 
2022--a nearly five-fold increase over the highest volume specified by 
EPAct. EISA also established four separate categories of renewable 
fuels, each with a separate volume mandate and each with a specific 
lifecycle greenhouse gas emission threshold. 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 
to 16 billion gallons by 2022, representing the bulk of the increase in 
the renewable fuels mandate.
    EPA's proposed rule sought comment on a multitude of issues, 
ranging from how to interpret the new definitions for renewable biomass 
to the Agency's proposed methodology for conducting the greenhouse gas 
lifecycle assessments required by EISA. The decisions presented in this 
final rule are heavily informed by the many public comments we received 
on the proposed rule. In addition, and as with the proposal, we sought 
input from a wide variety of stakeholders. 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. We also have worked closely with other Federal agencies and 
in particular with the Departments of Energy and Agriculture.
    This section provides an executive summary of the final RFS2 
program requirements that EPA is implementing as a result of EISA. The 
RFS2 program will replace the RFS1 program promulgated on May 1, 2007 
(72 FR 23900).\1\ Details of the final requirements can be found in 
Sections II and III, with certain lifecycle aspects detailed in Section 
V.
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    \1\ 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.
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    This section also provides a summary of EPA's assessment of the 
environmental and economic impacts of the use of higher renewable fuel 
volumes. Details of these analyses can be found in Sections IV through 
IX and in the Regulatory Impact Analysis (RIA).

A. Summary of New Provisions of the RFS Program

    Today's notice establishes new regulatory requirements for the RFS 
program that will be implemented through a new subpart M to 40 CFR part 
80. EPA is maintaining several elements of the RFS1 program such as 
regulations governing the generation, transfer, and use of Renewable 
Identification Numbers (RINs). At the same time, we are making a number 
of updates to reflect the changes brought about by EISA
1. Required Volumes of Renewable Fuel
    The RFS program is intended to require a minimum volume of 
renewable fuel to be used each year in the transportation sector. In 
response to EPAct 2005, under RFS1 the required volume was 4.0 billion 
gallons in 2006, ramping up to 7.5 billion gallons by 2012. Starting in 
2013, the program also required that the total volume of renewable fuel 
contain at least 250 million gallons of fuel derived from cellulosic 
biomass.
    In response to EISA, today's action makes four 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, with certain exceptions 
applicable to existing facilities, that each of these mandated volumes 
of renewable fuels achieve certain minimum thresholds of GHG emission 
performance. Fourth, it requires that all renewable fuel be made from 
feedstocks that meet the new definition of renewable biomass including 
certain land use restrictions. The volume requirements in EISA are 
shown in Table I.A.1-1.
BILLING CODE 6560-50-P

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[GRAPHIC] [TIFF OMITTED] TR26MR10.414

BILLING CODE 6560-50-C

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    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 V.C 
for further discussion of which specific types of fuel may qualify for 
the four categories shown in Table I.A.1-1.
2. Standards for 2010 and Effective Date for New Requirements
    While EISA established the renewable fuel volumes shown in Table 
I.A.1-1, it also requires that the Administrator set the standards 
based on these volumes each November for the following year based in 
part on information provided from the Energy Information Agency (EIA). 
In the case of the cellulosic biofuel standard, section 211(o)(7)(D) of 
EISA specifically requires that the standard be set based on the volume 
projected to be available during the following year. If the volume is 
lower than the level shown in Table I.A.1-1, then EISA allows the 
Administrator to also lower the advanced biofuel and total renewable 
fuel standards each year accordingly. Given the implications of these 
standards and the necessary judgment that can't be reduced to a formula 
akin to the RFS1 regulations, we believe it is appropriate to set the 
standards through a notice-and-comment rulemaking process. Thus, for 
future standards, we intend to issue an NPRM by summer and a final rule 
by November 30 of each year in order to determine the appropriate 
standards applicable in the following year. However, in the case of the 
2010 standards, we are finalizing them as part of today's action.
a. 2010 Standards
    While we proposed that the cellulosic biofuel standard would be set 
at the EISA-specified level of 100 million gallons for 2010, based on 
analysis of information available at this time, we no longer believe 
the full volume can be met. Since the proposal, we have had detailed 
discussions with over 30 companies that are in the business of 
developing cellulosic biofuels and cellulosic biofuel technology. Based 
on these discussions, we have found that many of the projects that 
served as the basis for the proposal have been put on hold, delayed, or 
scaled back. At the same time, there have been a number of additional 
projects that have developed and are moving forward. As discussed in 
Section IV.B.3, the timing for many of the projects indicates that 
while few will be able to provide commercial volumes for 2010, an 
increasing number will come on line in 2011, 2012, and 2013. The 
success of these projects is then expected to accelerate growth of the 
cellulosic biofuel industry out into the future. EIA provided us with a 
projection on October 29, 2009 of 5.04 million gallons (6.5 million 
ethanol-equivalent gallons) of cellulosic biofuel production for 2010. 
While our company-by-company assessment varies from EIA's, as described 
in Section IV.B.3., and actual cellulosic production volume during 2010 
will be a function of developments over the course of 2010, we 
nevertheless believe that 5 million gallons (6.5 million ethanol 
equivalent) represents a reasonable, yet achievable level for the 
cellulosic standard for 2010. While this is lower than the level 
specified in EISA, no change to the advanced biofuel and total 
renewable fuel standards is warranted. With the inclusion of an energy-
based Equivalence Value for biodiesel and renewable diesel, 2010 
compliance with the biomass-based diesel standard will be more than 
enough to ensure compliance with the advanced biofuel standard for 
2010.
    Today's rule also includes special provisions to account for the 
2009 biomass-based diesel volume requirements in EISA. As described in 
the NPRM, in November 2008 we used the new total renewable fuel volume 
of 11.1 billion gallons from EISA as the basis for the 2009 total 
renewable fuel standard that we issued under the RFS1 regulations.\2\ 
While this approach ensured that the total mandated renewable fuel 
volume required by EISA for 2009 was used, the RFS1 regulatory 
structure did 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 we proposed, and as is described 
in more detail in Section II.E.2, we are addressing this issue in 
today's rule by combining the 2010 biomass-based diesel requirement of 
0.65 billion gallons with the 2009 biomass based diesel requirement of 
0.5 billion gallons to require that obligated parties meet a combined 
2009/2010 requirement of 1.15 billion gallons by the end of the 2010 
compliance year. No similar provisions are required in order to fulfill 
the 2009 advanced biofuel volume mandate.
---------------------------------------------------------------------------

    \2\ 73 FR 70643, November 21, 2008
---------------------------------------------------------------------------

    The resulting 2010 standards are shown in Table I.A.2-1. These 
standards represent the fraction of a refiner's or importer's gasoline 
and diesel volume which must be renewable fuel. Additional discussion 
of the 2010 standards can be found in Section II.E.1.b.

                    Table I.A.2-1--Standards for 2010
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Cellulosic biofuel.........................................       0.004%
Biomass-based diesel.......................................        1.10%
Advanced biofuel...........................................        0.61%
Renewable fuel.............................................        8.25%
------------------------------------------------------------------------

b. Effective Date
    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 I.A.1-1 that begin in 2009 
for certain categories of renewable fuel. As described in the NPRM, we 
were not able to promulgate final RFS2 program requirements by December 
19, 2008.
    Under today's rule, the transition from using the RFS1 regulatory 
provisions regarding registration, RIN generation, reporting, and 
recordkeeping to using comparable provisions in this RFS2 rule will 
occur on July 1, 2010. This is the start of the 1st quarter following 
completion of the statutorily required 60-day Congressional Review 
period for such a rulemaking as this. This will provide adequate lead 
time for all parties to transition to the new regulatory requirements, 
including additional time to prepare for RFS2 implementation for those 
entities who may find it helpful, especially those covered by the RFS 
program for the first time. In addition, making the transition at the 
end of the quarter will help simplify the recordkeeping and reporting 
transition to RFS2. To facilitate the volume obligations being based on 
the full year's gasoline and diesel production, and to enable the 
smooth transition from the RFS1 to RFS2 regulatory provisions, 
Renewable Identification Numbers (RINs--which are used in the program 
for both credit trading and for compliance demonstration) that were 
generated under the RFS1 regulations will continue to be valid for 
compliance with the RFS2 obligations. Further discussion of transition 
issues can be found in Sections II.A and II.G.4, respectively.
    According to EISA, the renewable fuel obligations applicable under 
RFS2 apply on a calendar basis. That is, obligated parties must 
determine their

[[Page 14676]]

renewable volume obligations (RVOs) at the end of a calendar year based 
on the volume of gasoline or diesel fuel they produce during the year, 
and they must demonstrate compliance with their RVOs in an annual 
report that is due two months after the end of the calendar year.
    For 2010, today's rule will follow this same general approach. The 
four RFS2 RVOs for each obligated party will be calculated on the basis 
of all gasoline and diesel produced or imported on and after January 1, 
2010, through December 31, 2010. Obligated parties will be required to 
demonstrate by February 28 of 2011 that they obtained sufficient RINs 
to satisfy their 2010 RVOs. We believe this is an appropriate approach 
as it is more consistent with Congress' provisions in EISA for 2010, 
and there is adequate lead time for the obligated parties to achieve 
compliance.
    The issue for EPA to resolve is how to apply the four volume 
mandates under EISA for calendar year 2010. These volume mandates are 
translated into applicable percentages that obligated parties then use 
to determine their renewable fuel volume obligations based on the 
gasoline and diesel they produce or import in 2010. There are three 
basic approaches that EPA has considered, based on comments on the 
proposal. The first is the approach adopted in this rule--the four RFS2 
applicable percentages are determined based on the four volume mandates 
covered by this rule, and the renewable volume obligation for a refiner 
or importer will be determined by applying these percentages to the 
volume of gasoline and diesel fuel they produce during calendar year 
2010. Under this approach, there is no separate applicable percentage 
under RFS1 for 2010, however RINs generated in 2009 and 2010 under RFS1 
can be used to meet the four volume obligations for 2010 under the RFS2 
regulations. Another option, which was considered and rejected by EPA, 
is much more complicated--(1) determine an RFS1 applicable percentage 
based on just the total renewable fuel volume mandate, using the same 
total volume for renewable fuel as used in the first approach, and 
require obligated parties to apply that percentage to the gasoline 
produced from January 1, 2010 until the effective date of the RFS2 
regulations, and (2) determine the four RFS2 applicable percentages as 
discussed above, but require obligated parties to apply them to only 
the gasoline and diesel in 2010 after the effective date of the RFS2 
regulations. Of greater concern than its complexity, the second 
approach fails to ensure that the total volumes for three of the volume 
mandates are met for 2010. In effect EPA would be requiring that 
obligated parties use enough cellulosic biofuel, biomass-based diesel, 
and advanced biofuel to meet approximately 75% of the total volumes 
required for these fuels under EISA. While the total volume mandate 
under EISA for renewable fuel would likely be met, the other three 
volumes mandates would only be met in part. The final option would 
involve delaying the RFS2 requirements until January 1, 2011, which 
would avoid the complexity of the second approach, but would be even 
less consistent with EISA's requirements.
    The approach adopted in this rule is clearly the most consistent 
with EISA's requirement of four different volume mandates for all of 
calendar year 2010. In addition, EPA is confident that obligated 
parties have adequate lead-time to comply with the four volume 
requirements under the approach adopted in this rule. The volume 
requirements are achieved by obtaining the appropriate number of RINs 
from producers of the renewable fuel. The obligated parties do not need 
lead time for construction or investment purposes, as they are not 
changing the way they produce gasoline or diesel, do not need to design 
to install new equipment, or take other actions that require longer 
lead time. Obtaining the appropriate amount of RINs involves 
contractual or other arrangements with renewable fuel producers or 
other holders of RINs. Obligated parties now have experience 
implementing RFS1, and the actions needed to comply under the RFS2 
regulations are a continuation of these kinds of RFS1 activities. In 
addition, an adequate supply of RINs is expected to be available for 
compliance by obligated parties. RFS1 RINs have been produced 
throughout 2009 and continue to be produced since the beginning of 
2010. There has been and will be no gap or lag in the production of 
RINS, as the RFS1 regulations continue in effect and require that 
renewable fuel producers generate RINs for the renewable fuel they 
produce. These 2009 and 2010 RFS1 RINs will be available and can be 
used towards the volume requirements of obligated parties for 2010. 
These RFS1 RINS combined with the RFS2 RINs that will be generated by 
renewable fuel producers are expected to provide an adequate supply of 
RINs to ensure compliance for all of the renewable volume mandates. For 
further discussion of the expected supply of renewable fuel, see 
section IV.
    In addition, obligated parties have received adequate notice of 
this obligation. The proposed rule called for obligated parties to meet 
the full volume mandates for all four volume mandates, and to base 
their volume obligation on the volume of gasoline and diesel produced 
starting January 1, 2010. While the RFS2 regulations are not effective 
until after January 1, 2010, the same full year approach is being taken 
for the 2010 volumes of gasoline and diesel. Obligated parties have 
been on notice based on EPA's proposal, discussions with many 
stakeholders during the rulemaking, the issuance of the final rule 
itself, and publication of this rule in the Federal Register. As 
discussed above, there is adequate time for obligated parties to meet 
their 2010 volume obligations by the spring of 2011.
    This approach does not impose any retroactive requirements. The 
obligation that is imposed under the RFS2 regulations is forward 
looking--by the spring of 2011, when compliance is determined, 
obligated parties must satisfy certain volume obligations. These future 
requirements are calculated in part based on volumes of gasoline and 
diesel produced prior to the effective date of the RFS2 regulations, 
but this does not make the RFS2 requirement retroactive in nature. The 
RFS2 regulations do not change in any way the legal obligations or 
requirements that apply prior to the effective date of the RFS2 
regulations. Instead, the RFS2 requirements impose new requirements 
that must be met in the future. There is adequate lead time to comply 
with these RFS2 requirements, and they achieve a result that is more 
consistent with Congress' goals in establishing 4 volume mandates for 
calendar year 2010, and for these reasons EPA is adopting this approach 
for calendar year 2010.
    Parties that intend to generate RINs, own and/or transfer them, or 
use them for compliance purposes after July 1, 2010 will need to 
register or re-register under the RFS2 provisions and modify their 
information technology (IT) systems to accommodate the changes we are 
finalizing today. As described more fully in Section II, these changes 
include redefining the D code within the RIN that identifies which 
standard a fuel qualifies for, adding a process for verifying that 
feedstocks meet the renewable biomass definition, and calculating 
compliance with four standards instead of one. EPA's registration 
system is available now for parties to complete the registration 
process. Further details on this process can be found elsewhere in 
today's preamble as well as at http://www.epa.gov/otaq/regs/fuels/

[[Page 14677]]

fuelsregistration.htm. Parties that produce motor vehicle, nonroad, 
locomotive, and marine (MVNRLM) diesel fuel but not gasoline will be 
newly obligated parties and may be establishing IT systems for the RFS 
program for the first time.
3. Analysis of Lifecycle Greenhouse Gas Emissions and Thresholds for 
Renewable Fuels
a. Background and Conclusions
    A significant aspect of the RFS2 program is the requirement that 
the lifecycle GHG emissions of a qualifying renewable fuel must be less 
than the lifecycle GHG emissions of the 2005 baseline average gasoline 
or diesel fuel that it replaces; four different levels of reductions 
are required for the four different renewable fuel standards. These 
lifecycle performance improvement thresholds are listed in Table I.A.3-
1. Compliance with each threshold requires a comprehensive evaluation 
of renewable fuels, as well as the baseline for gasoline and diesel, on 
the basis of their lifecycle emissions. As mandated by EISA, the 
greenhouse gas emissions assessments must evaluate the aggregate 
quantity of greenhouse gas emissions (including direct emissions and 
significant indirect emissions such as significant emissions form land 
use changes) related to the full lifecycle, including all stages of 
fuel and feedstock production, distribution and use by the ultimate 
consumer.

        Table I.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.

    It is important to recognize that fuel from the existing capacity 
of current facilities and the capacity of all new facilities that 
commenced construction prior to December 19, 2007 (and in some cases 
prior to December 31, 2009) are exempt, or grandfathered, from the 20% 
lifecycle requirement for the Renewable Fuel category. Therefore, EPA 
has in the discussion below emphasized its analysis on those plants and 
fuels that are likely to be used for compliance with the rule and would 
be subject to the lifecycle thresholds. Based on the analyses and 
approach described in Section V of this preamble, EPA is determining 
that ethanol produced from corn starch at a new facility (or expanded 
capacity from an existing) using natural gas, biomass or biogas for 
process energy and using advanced efficient technologies that we expect 
will be most typical of new production facilities will meet the 20% GHG 
emission reduction threshold compared to the 2005 baseline gasoline. We 
are also determining that biobutanol from corn starch meets the 20% 
threshold. Similarly, EPA is making the determination that biodiesel 
and renewable diesel from soy oil or waste oils, fats and greases will 
exceed the 50% GHG threshold for biomass-based diesel compared to the 
2005 petroleum diesel baseline. In addition, we have now modeled 
biodiesel and renewable diesel produced from algal oils as complying 
with the 50% threshold for biomass-based diesel. EPA is also 
determining that ethanol from sugarcane complies with the applicable 
50% GHG reduction threshold for advanced biofuels. The modeled pathways 
(feedstock and production technology) for cellulosic ethanol and 
cellulosic diesel would also comply with the 60% GHG reduction 
threshold applicable to cellulosic biofuels. As discussed later in 
section V, there are also other fuels and fuel pathways that we are 
determining will comply with the GHG thresholds.
    Under EISA, EPA is allowed to adjust the GHG reduction thresholds 
downward by up to 10% if necessary based on lifecycle GHG assessment of 
biofuels likely to be available. Based on the results summarized above, 
we are not finalizing any adjustments to the lifecycle GHG thresholds 
for the four renewable fuel standard categories.
    EPA recognizes that as the state of scientific knowledge continues 
to evolve in this area, the lifecycle GHG assessments for a variety of 
fuel pathways are likely to be updated. Therefore, while EPA is using 
its current lifecycle assessments to inform the regulatory 
determinations for fuel pathways in this final rule, as required by the 
statute, the Agency is also committing to further reassess these 
determinations and lifecycle estimates. As part of this ongoing effort, 
we will ask for the expert advice of the National Academy of Sciences, 
as well as other experts, and incorporate their advice and any updated 
information we receive into a new assessment of the lifecycle GHG 
emissions performance of the biofuels being evaluated in this final 
rule. EPA will request that the National Academy of Sciences evaluate 
the approach taken in this rule, the underlying science of lifecycle 
assessment, and in particular indirect land use change, and make 
recommendations for subsequent lifecycle GHG assessments on this 
subject. At this time we are estimating this review by the National 
Academy of Sciences may take up to two years. As specified by EISA, if 
EPA revises the analytical methodology for determining lifecycle 
greenhouse gas emissions, any such revision will apply to renewable 
fuel from new facilities that commence construction after the effective 
date of the revision.
b. Fuel Pathways Considered and Key Model Updates Since the Proposal
    EPA is making the GHG threshold determination based on a 
methodology that includes an analysis of the full lifecycle, including 
significant emissions related to international land-use change. As 
described in more detail below and in Section V of this preamble, EPA 
has used the best available models for this purpose, and has 
incorporated many modifications to its proposed approach based on 
comments from the public and peer reviewers and developing science. EPA 
has also quantified the uncertainty associated with significant 
components of its analyses, including important factors affecting GHG 
emissions associated with international land use change. As discussed 
below, EPA has updated and refined its modeling approach since proposal 
in several important ways, and EPA is confident that its modeling of 
GHG emissions associated with international land use is comprehensive 
and provides a reasonable and scientifically robust basis for making 
the threshold determinations described above. As discussed below, EPA 
plans to continue to improve upon its analyses, and will update it in 
the future as appropriate.
    Through technical outreach, the peer review process, and the public 
comment period, EPA received and reviewed a significant amount of data, 
studies, and information on our proposed lifecycle analysis approach. 
We incorporated a number of new, updated, and peer-reviewed data 
sources in our final rulemaking analysis including better satellite 
data for tracking land use changes and improved assessments of N2O 
impacts from agriculture. The new and updated data sources are 
discussed further in this section, and in more detail in Section V.
    We also performed dozens of new modeling runs, uncertainty 
analyses, and sensitivity analyses which are leading to greater 
confidence in our results. We have updated our analyses in conjunction 
with, and based on, advice from experts from government,

[[Page 14678]]

academia, industry, and not for profit institutions.
    The new studies, data, and analysis performed for the final 
rulemaking impacted the lifecycle GHG results for biofuels in a number 
of different ways. In some cases, updates caused the modeled analysis 
of lifecycle GHG emissions from biofuels to increase, while other 
updates caused the modeled emissions to be reduced. Overall, the 
revisions since our proposed rule have led to a reduction in modeled 
lifecycle GHG emissions as compared to the values in the proposal. The 
following highlights the most significant revisions. Section V details 
all of the changes made and their relative impacts on the results.
    Corn Ethanol: The final rule analysis found less overall indirect 
land use change (less land needed), thereby improving the lifecycle GHG 
performance of corn ethanol. The main reasons for this decrease are:
     Based on new studies that show the rate of improvement in 
crop yields as a function of price, crop yields are now modeled to 
increase in response to higher crop prices. When higher crop yields are 
used in the models, less land is needed domestically and globally for 
crops as biofuels expand.
     New research available since the proposal indicates that 
the corn ethanol production co-product, distillers grains and solubles 
(DGS), is more efficient as an animal feed (meaning less corn is needed 
for animal feed) than we had assumed in the proposal. Therefore, in our 
analyses for the final rule, domestic corn exports are not impacted as 
much by increased biofuel production as they were in the proposal 
analysis.
     Improved satellite data allowed us to more finely assess 
the types of land converted when international land use changes occur, 
and this more precise assessment led to a lowering of modeled GHG 
impacts. Based on previous satellite data, the proposal assumed 
cropland expansion onto grassland would require an amount of pasture to 
be replaced through deforestation. For the final rulemaking analysis we 
incorporated improved economic modeling of demand for pasture area and 
satellite data which indicates that pasture is also likely to expand 
onto existing grasslands. This reduced the GHG emissions associated 
with an amount of land use change.
    However, we note that not all modeling updates necessarily reduced 
predicted GHG emissions from land use change. As one example, since the 
proposal a new version of the GREET model (Version 1.8C) has been 
released. EPA reviewed the new version and concluded that this was an 
improvement over the previous GREET release that was used in the 
proposal analysis (Version 1.8B). Therefore, EPA updated the GHG 
emission factors for fertilizer production used in our analysis to the 
values from the new GREET version. This had the result of slightly 
increasing the GHG emissions associated with fertilizer production and 
thus slightly increasing the GHG emission impacts of domestic 
agriculture.
    For the final rule, EPA has analyzed a variety of corn ethanol 
pathways including ethanol made from corn starch using natural gas, 
coal, and biomass as process energy sources in production facilities 
utilizing both dry mill and wet mill processes. For corn starch 
ethanol, we also considered the technology enhancements likely to occur 
in the future such as the addition of corn oil fractionation or 
extraction technology, membrane separation technology, combined heat 
and power and raw starch hydrolysis.
    Biobutanol from corn starch: In addition to ethanol from corn 
starch, for this final rule, we have also analyzed bio-butanol from 
corn starch. Since the feedstock impacts are the same as for ethanol 
from corn starch, the assessment for biobutanol reflects the differing 
impacts due to the production process and energy content of biobutanol 
compared to that of ethanol.
    Soybean Biodiesel: The new information described above for corn 
ethanol also leads to lower modeled GHG impacts associated with soybean 
biodiesel. The revised assessment predicts less overall indirect land 
use change (less land needed) and less impact from the land use changed 
that does occur (due to updates in types of converted land assumed). In 
addition, the latest IPCC guidance indicates reduced domestic soybean 
N2O emissions, and updated USDA and industry data show reductions in 
biodiesel processing energy use and a higher co-product credit, all of 
which further reduced the modeled soybean biodiesel lifecycle GHG 
emissions. This has resulted in a significant improvement in our 
assessment of the lifecycle performance of soybean biodiesel as 
compared to the estimate in the proposal.
    Biodiesel and Renewable Diesel from Algal Oil and Waste Fats and 
Greases: In addition to biodiesel from soy oil, biodiesel and renewable 
diesel from algal oil (should it reach commercial production) and 
biodiesel from waste oils, fats and greases have been modeled. These 
feedstock sources have little or no land use impact so the GHG impacts 
associate with their use in biofuel production are largely the result 
of energy required to produce the feedstock (in the case of algal oil) 
and the energy required to turn that feedstock into a biofuel.
    Sugarcane Ethanol: Sugarcane ethanol was analyzed considering a 
range of technologies and assuming alternative pathways for dehydrating 
the ethanol prior to its use as a biofuel in the U.S. For the final 
rule, our analysis also shows less overall indirect land use change 
(less land needed) associated with sugarcane ethanol production. For 
the proposal, we assumed sugarcane expansion in Brazil would result in 
cropland expansion into grassland and lost pasture being replaced 
through deforestation. Based on newly available regional specific data 
from Brazil, historic trends, and higher resolution satellite data, in 
the final rule, sugarcane expansion onto grassland is coupled with 
greater pasture intensification, such that there is less projected 
impact on forests. Furthermore, new data provided by commenters showed 
reduced sugarcane ethanol process energy, which also reduced the 
estimated lifecycle GHG impact of sugarcane ethanol production.
    Cellulosic Ethanol: We analyzed cellulosic ethanol production using 
both biochemical (enzymatic) and thermo-chemical processes with corn 
stover, switchgrass, and forestry thinnings and waste as feedstocks. 
For cellulosic diesel, we analyzed production using the Fischer-Tropsch 
process. For the final rule, we updated the cellulosic ethanol 
conversion rates based on new data provided by the National Renewable 
Energy Laboratory (NREL.) As a result of this update, the gallons per 
ton yields for switchgrass and several other feedstock sources 
increased in our analysis for the final rule, while the predicted 
yields from corn residue and several other feedstock sources decreased 
slightly from the NPRM values. In addition, we also updated our 
feedstock production yields based on new work conducted by the Pacific 
Northwest National Laboratory (PNNL). This analysis increased the tons 
per acre yields for several dedicated energy crops. These updates 
increased the amount of cellulosic ethanol projected to come from 
energy crops. While the increase in crop yields and conversion 
efficiency reduced the GHG emissions associated with cellulosic 
ethanol, there remains an increased demand for land to grow dedicated 
energy crops; this land use impact resulted in increased GHG emissions 
with the net result varying by the type of cellulosic feedstock source.

[[Page 14679]]

    We note that several of the renewable fuel pathways modeled are 
still in early stages of development or commercialization and are 
likely to continue to develop as the industry moves toward commercial 
production. Therefore, it will be necessary to reanalyze several 
pathways using updated data and information as the technologies 
develop. For example, biofuel derived from algae is undergoing wide 
ranging development. Therefore for now, our algae analyses presume 
particular processes and energy requirements which will need to be 
reviewed and updated as this fuel source moves toward commercial 
production.
    For this final rule we have incorporated a statistical analysis of 
uncertainty about critical variables in our pathway analysis. This 
uncertainty analysis is explained in detail in Section V and is 
consistent with the specific recommendations received through our peer 
review and public comments on the proposal. The uncertainty analysis 
focused on two aspects of indirect land use change--the types of land 
converted and the GHG emission associated with different types of land 
converted. In particular, our uncertainty analysis focused on such 
specific sources of information as the satellite imaging used to inform 
our assessment of land use trends and the specific changes in carbon 
storage expected from a change in land use in each geographic area of 
the world modeled. We have also performed additional sensitivity 
analyses including analysis of two yield scenarios for corn and soy 
beans to assess the impact of changes in yield assumptions.
    This uncertainty analysis provides information on both the range of 
possible outcomes for the parameters analyzed, an estimate of the 
degree of confidence that the actual result will be within a particular 
range (in our case, we estimated a 95% confidence interval) and an 
estimate of the central tendency or midpoint of the GHG performance 
estimate.
    In the proposal, we considered several options for the timeframe 
over which to measure lifecycle GHG impacts and the possibility of 
discounting those impacts. Based on peer review recommendations and 
other comments received, EPA is finalizing its assessments based on an 
analysis assuming 30 years of continued emission impacts after the 
program is fully phased in by 2022 and without discounting those 
impacts.
    EPA also notes that it received significant comment on our proposed 
baseline lifecycle greenhouse gas assessment of gasoline and diesel 
(``petroleum baseline''). While EPA has made several updates to the 
petroleum analysis in response to comments (see Section V for further 
discussion), we are finalizing the approach based on our interpretation 
of the definition in the Act as requiring that the petroleum baseline 
represent an average of the gasoline and diesel fuel (whichever is 
being replaced by the renewable fuel) sold as transportation fuel in 
2005.
    As discussed in more detail later, the modeling results developed 
for purposes of the final rule provide a rich and comprehensive base of 
information for making the threshold determinations. There are numerous 
modeling runs, reflecting updated inputs to the model, sensitivity 
analyses, and uncertainty analyses. The results for different scenarios 
include a range and a best estimate or mid-point. Given the potentially 
conservative nature of the base crop yield assumption, EPA believes the 
actual crop yield in 2022 may be above the base yield; however we are 
not in a position to characterize how much above it might be. To the 
extent actual yields are higher, the base yield modeling results would 
underestimate to some degree the actual GHG emissions reductions 
compared to the baseline.
    In making the threshold determinations for this rule, EPA weighed 
all of the evidence available to it, while placing the greatest weight 
on the best estimate value for the base yield scenario. In those cases 
where the best estimate for the base yield scenario exceeds the 
reduction threshold, EPA judges that there is a good basis to be 
confident that the threshold will be achieved and is determining that 
the bio-fuel pathway complies with the applicable threshold. To the 
extent the midpoint of the scenarios analyzed lies further above a 
threshold for a particular biofuel pathway, we have increasingly 
greater confidence that the biofuel exceeds the threshold.
    EPA recognizes that certain commenters suggest that there is a very 
high degree of uncertainty associated in particular with determining 
international indirect land use changes and their emissions impacts, 
and because of this EPA should exclude any calculation of international 
indirect land use changes in its lifecycle analysis. Commenters say EPA 
should make the threshold determinations based solely on modeling of 
other sources of lifecycle emissions. In effect, commenters argue that 
the uncertainty of the modeling associated with international indirect 
land use change means we should use our modeling results but exclude 
that part of the results associated with international land use change.
    For the reasons discussed above and in more detail in Section V, 
EPA rejects the view that the modeling relied upon in the final rule, 
which includes emissions associated with international indirect land 
use change, is too uncertain to provide a credible and reasonable 
scientific basis for determining whether the aggregate lifecycle 
emissions exceed the thresholds. In addition, as discussed elsewhere, 
the definition of lifecycle emissions includes significant indirect 
emissions associated with land use change. In deciding whether a bio-
fuel pathway meets the threshold, EPA has to consider what it knows 
about all aspects of the lifecycle emissions, and decide whether there 
is a valid basis to find that the aggregate lifecycle emissions of the 
fuel, taking into account significant indirect emissions from land use 
change meets the threshold. Based on the analyses conducted for this 
rule, EPA has determined international indirect land use impacts are 
significant and therefore must be included in threshold compliance 
assessment.
    If the international land use impacts were so uncertain that their 
impact on lifecycle GHG emissions could not be adequately determined, 
as claimed by commenters, this does not mean EPA could assume the 
international land use change emissions are zero, as commenters 
suggest. High uncertainty would not mean that emissions are small and 
can be ignored; rather it could mean that we could not tell whether 
they are large or small. If high uncertainty meant that EPA were not 
able to determine that indirect emissions from international land use 
change are small enough that the total lifecycle emissions meet the 
threshold, then that fuel could not be determined to meet the GHG 
thresholds of EISA and the fuel would necessarily have to be excluded 
from the program.
    In any case, that is not the situation here as EPA rejects 
commenters' suggestion and does not agree that the uncertainty over the 
indirect emissions from land use change is too high to make a reasoned 
threshold determination. Therefore biofuels with a significant 
international land use impact are included within this program.
c. Consideration of Fuel Pathways Not Yet Modeled
    Not all biofuel pathways have been directly modeled for this rule. 
For example, while we have modeled cellulosic biofuel produced from 
corn

[[Page 14680]]

stover, we have not modeled the specific GHG impact of cellulosic 
biofuel produced from other crop residues such as wheat straw or rice 
straw. Today, in addition to finalizing a threshold compliance 
determination for those pathways we specifically modeled, in some 
cases, our technical judgment indicates other pathways are likely to be 
similar enough to modeled pathways that we are also assured these 
similar pathways qualify. These pathways include fuels produced from 
the same feedstock and using the same production process but produced 
in countries other than those modeled. The agricultural sector modeling 
used for our lifecycle analysis does not predict any soybean biodiesel 
or corn ethanol will be imported into the U.S., or any imported 
sugarcane ethanol from production in countries other than Brazil. 
However, these rules do not prohibit the use in the U.S. of these fuels 
produced in countries not modeled if they are also expected to comply 
with the eligibility requirements including meeting the thresholds for 
GHG performance. Although the GHG emissions of producing these fuels 
from feedstock grown or biofuel produced in other countries has not 
been specifically modeled, we do not anticipate their use would impact 
our conclusions regarding these feedstock pathways. The emissions of 
producing these fuels in other countries could be slightly higher or 
lower than what was modeled depending on a number of factors. Our 
analyses indicate that crop yields for the crops in other countries 
where these fuels are also most likely to be produced are similar or 
lower than U.S. values indicating the same or slightly higher GHG 
impacts. Agricultural sector inputs for the crops in these other 
countries are roughly the same or lower than the U.S. pointing toward 
the same or slightly lower GHG impacts. If crop production were to 
expand due to biofuels in the countries where the models predict these 
biofuels might additionally be produced would tend to lower our 
assessment of international indirect impacts but could increase our 
assessment of the domestic (i.e., the country of origin) land use 
impacts. EPA believes, because of these offsetting factors along with 
the small amounts of fuel potentially coming from other countries, that 
incorporating fuels produced in other countries will not impact our 
threshold analysis. Therefore, fuels of the same fuel type, produced 
from the same feedstock using the same fuel production technology as 
modeled fuel pathways will be assessed the same GHG performance 
decisions regardless of country of origin. These pathways also include 
fuels that might be produced from similar feedstock sources to those 
already modeled and which are expected to have less or no indirect land 
use change. In such cases, we believe that in order to compete 
economically in the renewable fuel marketplace such pathways are likely 
to be at least as energy efficient as those modeled and thus have 
comparable lifecycle GHG performance. Based on these considerations, we 
are extending the lifecycle results for the fuel pathways already 
modeled to 5 broader categories of feedstocks. This extension of 
lifecycle modeling results is discussed further in Section V.C.
    We have established five categories of biofuel feedstock sources 
under which modeled feedstock sources and feedstock sources similar to 
those modeled are grouped and qualify on the basis of our existing 
modeling. These are:
    1. Crop residues such as corn stover, wheat straw, rice straw, 
citrus residue.
    2. Forest material including eligible forest thinnings and solid 
residue remaining from forest product production.
    3. Annual cover crops planted on existing crop land such as winter 
cover crops.
    4. Separated food and yard waste including biogenic waste from food 
processing.
    5. Perennial grasses including switchgrass and miscanthus.
    The full set of pathways for which we have been able to make a 
compliance decision are described in Section V.
    Threshold determinations for certain other pathways were not 
possible at this time because sufficient modeling or data is not yet 
available. In some of these cases, we recognize that a renewable fuel 
is already being produced from an alternative feedstock. Although we 
have the data needed for analysis, we did not have sufficient time to 
complete the necessary lifecycle GHG impact assessment for this final 
rule. We will model and evaluate additional pathways after this final 
rule on the basis of current or likely commercial production in the 
near-term and the status of current analysis at EPA. EPA anticipates 
modeling grain sorghum ethanol, woody pulp ethanol, and palm oil 
biodiesel after this final rule and including the determinations in a 
rulemaking within 6 months. Our analyses project that they will be used 
in meeting the RFS2 volume standard in the near-term. During the course 
of the NPRM comment period, EPA received detailed information on these 
pathways and is currently in the process of analyzing these pathways. 
We have received comments on several additional feedstock/fuel 
pathways, including rapeseed/canola, camelina, sweet sorghum, wheat, 
and mustard seed, and we welcome parties to utilize the petition 
process described in Section V.C to request EPA to examine additional 
pathways.
    We anticipate there could be additional cases where we currently do 
not have information on which to base a lifecycle GHG assessment 
perhaps because we are not yet aware of potential unique plant 
configurations or operations that could result in greater efficiencies 
than assumed in our analysis. In many cases, such alternative pathways 
could have been explicitly modeled as a reasonably straightforward 
extension of pathways we have modeled if the necessary information had 
been available. For example, while we have modeled specific 
enhancements to corn starch ethanol production such as membrane 
separation or corn oil extraction, there are likely other additional 
energy saving or co-product pathways available or under development by 
the industry. It is reasonable to also consider these alternative 
energy saving or co-product pathways based upon their technical merits. 
Other current or emerging pathways may require new analysis and 
modeling for EPA to fully evaluate compliance. For example, fuel 
pathways with feedstocks or fuel types not yet modeled by EPA may 
require additional modeling and, it follows, public comment before a 
determination of compliance can be made.
    Therefore, for those fuel pathways that are different than those 
pathways EPA has listed in today's regulations, EPA is establishing a 
petition process whereby a party can petition the Agency to consider 
new pathways for GHG reduction threshold compliance. As described in 
Section V.C, the petition process is meant for parties with serious 
intention to move forward with production via the petitioned fuel 
pathway and who have moved sufficiently forward in the business process 
to show feasibility of the fuel pathway's implementation. In addition, 
if the petition addresses a fuel pathway that already has been 
determined to qualify as one or more types of renewable fuel under RFS 
(e.g., renewable fuel, or advanced biofuel), the pathway must have the 
potential to result in qualifying for a renewable fuel type for which 
it was not previously qualified. Thus, for example, the Agency will not 
undertake any additional review for a party wishing to get a modified 
LCA value for a

[[Page 14681]]

previously approved fuel pathway if the desired new value would not 
change the overall pathway classification.
    The petition must contain all the necessary information on the fuel 
pathway to allow EPA to effectively assess the lifecycle performance of 
the new fuel pathway. See Section V.C for a full description. EPA will 
use the data supplied via the petition and other pertinent data 
available to the Agency to evaluate whether the information for that 
fuel pathway, combined with information developed in this rulemaking 
for other fuel pathways that have been determined to exceed the 
threshold, is sufficient to allow EPA to evaluate the pathway for a 
determination of compliance. We expect such a determination would be 
pathway specific. For some fuel pathways with unique modifications or 
enhancements to production technologies in pathways otherwise modeled 
for the regulations listed today, EPA may be able to evaluate the 
pathway as a reasonably straight-forward extension of our current 
assessments. In such cases, we would expect to make a decision for that 
specific pathway without conducting a full rulemaking process. We would 
expect to evaluate whether the pathway is consistent with the 
definitions of renewable fuel types in the regulations, generally 
without going through rulemaking, and issue an approval or disapproval 
that applies to the petitioner. We anticipate that we will subsequently 
propose to add the pathway to the regulations. Other current or 
emerging fuel pathways may require significant new analysis and/or 
modeling for EPA to conduct an adequate evaluation for a compliance 
determination (e.g., feedstocks or fuel types not yet included in EPA's 
assessments for this regulation). For these pathways, EPA would give 
notice and seek public comment on a compliance determination under the 
annual rulemaking process established in today's regulations. If we 
make a technical determination of compliance, then we anticipate the 
fuel producer will be able to generate RINs for fuel produced under the 
additional pathway following the next available quarterly update of the 
EPA Moderated Transaction System (EMTS). EPA will process those 
petitions as expeditiously as possible for those pathways which are 
closer to the commercial production stage than others. In all events, 
parties are expected to begin this process with ample lead time as 
compared to their commercial start dates. Further discussion of this 
petition process can be found in Section V.C.
    We note again that the continued work of EPA and others is expected 
to result in improved models and data sources, and that re-analysis 
based on such updated information could revise these determinations. 
Any such reassessment that would impact compliance would necessarily go 
through rulemaking and would only be applicable to production from 
future facilities after the revised rule was finalized, as required by 
EISA.
4. Compliance With Renewable Biomass Provision
    EISA changed the definition of ``renewable fuel'' to require that 
it be made from feedstocks that qualify as ``renewable biomass.'' 
EISA's definition of the term ``renewable biomass'' limits the types of 
biomass as well as the types of land from which the biomass may be 
harvested. The definition includes:
     Planted crops and crop residue from agricultural land 
cleared prior to December 19, 2007 and actively managed or fallow on 
that date.
     Planted trees and tree residue from tree plantations 
cleared prior to December 19, 2007 and actively managed on that date.
     Animal waste material and byproducts.
     Slash and pre-commercial thinnings from non-federal 
forestlands that are neither old-growth nor listed as critically 
imperiled or rare by a State Natural Heritage program.
     Biomass cleared from the vicinity of buildings and other 
areas at risk of wildfire.
     Algae.
     Separated yard waste and food waste.
    In today's rule, EPA is finalizing definitions for the many terms 
included within the definition of renewable biomass. Where possible, 
EPA has adhered to existing statutory, regulatory or industry 
definitions for these terms, although in some cases we have altered 
definitions to conform to EISA's statutory language, to further the 
goals of EISA, or for ease of program implementation. For example, EPA 
is defining ``agricultural land'' from which crops and crop residue can 
be harvested for RIN-generating renewable fuel production as including 
cropland, pastureland, and land enrolled in the Conservation Reserve 
Program. An in-depth discussion of the renewable biomass definitions 
can be found in Section II.B.4.
    In keeping with EISA, under today's final rule, renewable fuel 
producers may only generate RINs for fuels made from feedstocks meeting 
the definition of renewable biomass. In order to implement this 
requirement, we are finalizing three potential mechanisms for domestic 
and foreign renewable fuel producers to verify that their feedstocks 
comply with this requirement. The first involves renewable biomass 
recordkeeping and reporting requirements by renewable fuel producers 
for their individual facilities. As an alternative to these individual 
recordkeeping and reporting requirements, the second allows renewable 
fuel producers to form a consortium to fund an independent third-party 
to conduct an annual renewable biomass quality-assurance survey, based 
on a plan approved by EPA. The third is an aggregate compliance 
approach applicable only to crops and crop residue from the U.S. It 
utilizes USDA's publicly available agricultural land data as the basis 
for an EPA determination of compliance with the renewable biomass 
requirements for these particular feedstocks. This determination will 
be reviewed annually, and if EPA finds it is no longer warranted, then 
renewable fuel producers using domestically grown crops and crop 
residue will be required to conduct individual or consortium-based 
verification processes to ensure that their feedstocks qualify as 
renewable biomass. These final provisions are described below, with a 
more in-depth discussion in Section II.B.4.
    For renewable fuel producers using feedstocks other than planted 
crops or crop residue from agricultural land that do not choose to 
participate in the third-party survey funded by an industry consortium, 
the final renewable biomass recordkeeping and reporting provisions 
require that individual 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. Specifically, EPA's renewable biomass reporting 
requirements for producers who generate RINs include a certification on 
renewable fuel production reports that the feedstock used for each 
renewable fuel batch meets the definition of renewable biomass. 
Additionally, producers will be required to include with their 
quarterly reports a summary of the types and volumes of feedstocks used 
throughout the quarter, as well as maps of the land from which the 
feedstocks used in the quarter were harvested. EPA's final renewable 
biomass recordkeeping provisions require renewable fuel producers to

[[Page 14682]]

maintain sufficient records to support their claims that their 
feedstocks meet the definition of renewable biomass, including maps or 
electronic data identifying the boundaries of the land where the 
feedstocks were produced, documents tracing the feedstocks from the 
land to the renewable fuel production facility, other written records 
from their feedstock suppliers that serve as evidence that the 
feedstock qualifies as renewable biomass, and for producers using 
planted trees or tree residue from tree plantations, written records 
that serve as evidence that the land from which the feedstocks were 
obtained was cleared prior to December 19, 2007 and actively managed on 
that date.
    Based on USDA's publicly available agricultural land data, EPA is 
able to establish a baseline of the aggregate amount of U.S. 
agricultural land (meaning cropland, pastureland and CRP land in the 
United States) that is available for the production of crops and crop 
residues for use in renewable fuel production consistent with the 
definition of renewable biomass. EPA has determined that, in the 
aggregate this amount of agricultural land (land cleared or cultivated 
prior to EISA's enactment (December 19, 2007) and actively managed or 
fallow, and nonforested on that date) is expected to, at least in the 
near term, be sufficient to support EISA renewable fuel obligations and 
other foreseeable demands for crop products, without clearing and 
cultivating additional land. EPA also believes that economic factors 
will lead farmers to use the ``agricultural land'' available for crop 
production under EISA rather than bring new land into crop production. 
As a result, EPA is deeming renewable fuel producers using 
domestically-grown crops and crop residue as feedstock to be in 
compliance with the renewable biomass requirements, and those producers 
need not comply with the recordkeeping and quarterly reporting 
requirements as established for the non[dash]crop-based biomass sector. 
However, EPA will annually review USDA data on lands in agricultural 
production to determine if these conclusions remain valid. If EPA 
determines that the 2007 baseline amount of eligible agricultural land 
has been exceeded, EPA will publish a notice of that finding in the 
Federal Register. At that point, renewable fuel producers using planted 
crops or crop residue from agricultural lands would be subject to the 
same recordkeeping and reporting requirements as other renewable fuel 
producers.
5. EPA-Moderated Transaction System
    We introduced the EPA Moderated Transaction System (EMTS) in the 
NPRM as a new method for managing the generation of RINs and 
transactions involving RINs. EMTS is designed to resolve the RIN 
management issues of RFS1 that lead to widespread RIN errors, many 
times resulting in invalid RINs and often tedious remedial procedures 
to resolve those errors. It is also designed to address the added RIN 
categories, more complex RIN generation requirements, and additional 
volume of RINs associated with RFS2. Commenters broadly support EMTS 
and most stated that its use should coincide with the start of RFS2; 
however, many commenters expressed concerns over having sufficient time 
to implement the new system. In today's action, we are requiring the 
use of EMTS for all RFS2 RIN generations and transactions beginning 
July 1, 2010. EPA has utilized an open process for the development of 
EMTS since it was first introduced in the NPRM, conducting workshops 
and webinars, and soliciting stakeholder participation in its 
evaluation and testing. EPA pledges to work with the regulated 
community, as a group and individually, to ensure EMTS is successfully 
implemented. EPA anticipates that with this level of assistance, 
regulated parties will not experience significant difficulties in 
transitioning to the new system, and EPA believes that the many 
benefits of the new system warrant its immediate use.
6. Other Changes to the RFS Program
    Today's final rule also makes a number of other changes to the RFS 
program that are described in more detail in Sections II and III below, 
including:
     Grandfathering provisions: Renewable fuel from existing 
facilities is exempt from the lifecycle GHG emission reduction 
threshold of 20% up to a baseline volume for that facility that will be 
established at the time of registration. As discussed in Section 
II.B.3, the exemption from the 20% GHG threshold applies only to 
renewable fuel that is produced from facilities which commenced 
construction on or before December 19, 2007, or in the case of ethanol 
plants that use natural gas or biodiesel for process heat, on or before 
December 31, 2009.
     Renewable fuels produced from municipal solid waste (MSW): 
The new renewable biomass definition in EISA modified the ability for 
MSW-derived fuels to qualify under the RFS program by restricting it to 
``separated yard waste or food waste.'' We are finalizing provisions 
that would allow certain portions of MSW to be included as renewable 
biomass, provided that reasonable separation has first occurred.
     Equivalence Values: We are generally maintaining the 
provisions from RFS1 that the Equivalence Value for each renewable fuel 
will be based on its energy content in comparison to ethanol, adjusted 
for renewable content. The cellulosic biofuel, advanced biofuel, and 
renewable fuel standards can be met with ethanol-equivalent volumes of 
renewable fuel. However, since the biomass-based diesel standard is a 
``diesel'' standard, its volume must be met on a biodiesel-equivalent 
energy basis.
     Cellulosic biofuel waiver credits: If EPA reduces the 
required volume of cellulosic biofuel according to the waiver 
provisions in EISA, EPA will offer a number of credits to obligated 
parties no greater than the reduced cellulosic biofuel standard. These 
waiver credits are not allowed to be traded or banked for future use, 
and are only allowed to be used to meet the cellulosic biofuel standard 
for the year that they are offered. In response to concerns expressed 
in comments on the proposal, we are implementing certain restrictions 
on the use of these waiver credits. For example, unlike Cellulosic 
Biofuel RINs, waiver credits may not be used to meet either the 
advanced biofuel standard or the total renewable fuel standard. For the 
2010 compliance period, since the cellulosic standard is lower than the 
level otherwise required by EISA, we are making cellulosic waiver 
credits available to obligated parties for end-of-year compliance 
should they need them at a price of $1.56 per gallon-RIN.
     Obligated fuels: EISA expanded the program to cover 
``transportation fuel'', not just gasoline. Therefore, under RFS2, 
obligated fuel volumes will include all gasoline and all MVNRLM diesel 
fuel. Other fuels such as jet fuel and fuel intended for use in ocean-
going vessels are not obligated fuels under RFS2. However, renewable 
fuels used in jet fuel or heating oil are valid for meeting the 
renewable fuel volume mandates. Similarly, while we are not including 
natural gas, propane, or electricity used in transportation as 
obligated fuels at this time, we will allow renewable forms of these 
fuels to qualify under the program for generating RINs.

B. Impacts of Increasing Volume Requirements in the RFS2 Program

    The displacement of gasoline and diesel with renewable fuels has a 
wide

[[Page 14683]]

range of environmental and economic impacts. As we describe in Sections 
IV-IX, we have assessed many of these impacts for the final rule. It is 
difficult to ascertain how much of these impacts might be due to the 
natural growth in renewable fuel use due to market forces as crude oil 
prices rise versus what might be forced by the RFS2 standards. 
Regardless, these assessments provide important information on the 
wider public policy considerations related to renewable fuel production 
and use, climate change, and national energy security. Where possible, 
we have tried to provide two perspectives on the impacts of the 
renewable fuel volumes mandated in EISA--both relative to the RFS1 
mandated volumes, and relative to a projection from EIA (AEO 2007) of 
renewable fuel volumes that would have been expected without EISA.
    Based on the results of our analyses, when fully phased in by 2022, 
the increased volume of renewable fuel required by this final rule in 
comparison to the AEO 2007 forecast would result in 138 million metric 
tons fewer CO2-equivalent GHG emissions (annual average over 
30 years), the equivalent of removing 27 million vehicles from the road 
today.
    At the same time, increases in emissions of hydrocarbons, nitrogen 
oxides, particulate matter, and other pollutants are projected to lead 
to increases in population-weighted annual average ambient PM and ozone 
concentrations, which in turn are anticipated to lead to up to 245 
cases of adult premature mortality. The air quality impacts, however, 
are highly variable from region to region. Ambient PM2.5 is 
likely to increase in areas associated with biofuel production and 
transport and decrease in other areas; for ozone, many areas of the 
country will experience increases and a few areas will see decreases. 
Ethanol concentrations will increase substantially; for the other 
modeled air toxics there are some localized impacts, but relatively 
little impact on national average concentrations. We note that the air 
quality modeling results presented in this final rule do not constitute 
the ``anti-backsliding'' analysis required by Clean Air Act section 
211(v). EPA will be analyzing air quality impacts of increased 
renewable fuel use through that study and will promulgate appropriate 
mitigation measures under section 211(v), separate from this final 
action.
    In addition to air quality, there are also expected to be adverse 
impacts on both water quality and quantity as the production of 
biofuels and their feedstocks increase.
    In addition to environmental impacts, the increased volumes of 
renewable fuels required by this final rule are also projected to have 
a number of other energy and economic impacts. The increased renewable 
fuel use is estimated to reduce dependence on foreign sources of crude 
oil, increase domestic sources of energy, and diversify our energy 
portfolio to help in moving beyond a petroleum-based economy. The 
increased use of renewable fuels is also expected to have the added 
benefit of providing an expanded market for agricultural products such 
as corn and soybeans and open new markets for the development of 
cellulosic feedstock industries and conversion technologies. Overall, 
however, we estimate that the renewable fuel standards will result in 
significant net benefits, ranging between $16 and $29 billion in 2022.
    Table I.B-1 summarizes the results of our impacts analyses of the 
volumes of renewable fuels required by the RFS2 standards in 2022 
relative to the AEO2007 reference case and identifies the section where 
you can find further explanation of it. As we work to implement the 
requirements of EISA, we will continue to assess these impacts. These 
are the annual impacts projected in 2022 when the program is fully 
phased in. Impacts in earlier years would differ but in most cases were 
not able to be modeled or assessed for this final rule.

 Table I.B-1--Impact Summary of the RFS2 Standards in 2022 Relative to the AEO2007 Reference Case (2007 Dollars)
----------------------------------------------------------------------------------------------------------------
                 Category                                 Impact in 2022                   Section  discussed
----------------------------------------------------------------------------------------------------------------
                                            Emissions and Air Quality
----------------------------------------------------------------------------------------------------------------
GHG Emissions............................  -138 million metric tons...................  V.D.
Non-GHG Emissions (criteria and toxic      -1% to +10% depending on the pollutant.....  VI.A.
 pollutants).
Nationwide Ozone.........................  +0.12 ppb population-weighted seasonal max   VIII.D.
                                            8 hr average.
Nationwide PM2.5.........................  +0.002 [mu]g/m\3\ population-weighted        VIII.D.
                                            annual average PM2.5.
Nationwide Ethanol.......................  +0.409 [mu]g/m\3\ population-weighted        VI.D.
                                            annual average.
Other Nationwide Air Toxics..............  -0.0001 to -0.023 [mu]g/m\3\ population-     VI.D.
                                            weighted annual average depending on the
                                            pollutant.
PM2.5-related Premature Mortality........  33 to 85 additional cases of adult           VIII.D.
                                            mortality (estimates vary by study).
Ozone-related Premature Mortality........  36 to 160 additional cases of adult          VIII.D.
                                            mortality (estimates vary by study).
----------------------------------------------------------------------------------------------------------------
                                           Other Environmental Impacts
----------------------------------------------------------------------------------------------------------------
Loadings to the Mississippi River from     Nitrogen: +1,430 million lbs. (1.2%).......  IX.
 the Upper Mississippi River Basin.        Phosphorus: +132 million lbs. (0.7%).......
----------------------------------------------------------------------------------------------------------------
                                                   Fuel Costs
----------------------------------------------------------------------------------------------------------------
Gasoline Costs...........................  -2.4[cent]/gal.............................  VII.D.
Diesel Costs.............................  -12.1 [cent]/gal...........................  VII.D.
Overall Fuel Cost........................  -$11.8 Billion.............................  VII.D.
Gasoline and Diesel Consumption..........  -13.6 Bgal.................................  VII.C.
----------------------------------------------------------------------------------------------------------------
                                                   Food Costs
----------------------------------------------------------------------------------------------------------------
Corn.....................................  +8.2%......................................  VIII.A.
Soybeans.................................  +10.3%.....................................  VIII.A.

[[Page 14684]]

 
Food.....................................  +$10 per capita............................  VIII.A.
----------------------------------------------------------------------------------------------------------------
                                                Economic Impacts
----------------------------------------------------------------------------------------------------------------
Energy Security..........................  +$2.6 Billion..............................  VIII.B.
Monetized Health Impacts.................  -$0.63 to -$2.2 Billion....................  VIII.D.
GHG Impacts (SCC) \a\....................  +$0.6 to $12.2 Billion (estimates vary by    VIII.C.
                                            SCC assumption).
Oil Imports..............................  -$41.5 Billion.............................  VIII.B
Farm Gate Food...........................  +$3.6 Billion..............................  VIII.A.
Farm Income..............................  +$13 Billion (+36%)........................  VIII.A.
Corn Exports.............................  -$57 Million (-8%).........................  VIII.A.
Soybean Exports..........................  -$453 Million (-14%).......................  VIII.A.
Total Net Benefits \b\...................  +$13 to $26 Billion (estimates vary by SCC   VIII.F.
                                            assumption).
----------------------------------------------------------------------------------------------------------------
\a\ The models used to estimate SCC values have not been exercised in a systematic manner that would allow
  researchers to assess the probability of different values. Therefore, the interim SCC values should not be
  considered to form a range or distribution of possible or likely values. See Section VIII.D for a complete
  summary of the interim SCC values.
\b\ Sum of Overall Fuel Costs, Energy Security, Monetized Health Impacts, and GHG Impacts (SCC).

II. Description of the Regulatory Provisions

    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, many of the regulatory 
requirements of the RFS1 program will remain largely or, in some cases, 
entirely unchanged. These provisions 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 are changing to 
implement the requirements in EISA fall primarily into the following 
seven 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) New definitions of renewable fuel, advanced biofuel, biomass-
based diesel, and cellulosic biofuel.
    (4) New requirement that renewable fuels meet certain lifecycle 
emission reduction thresholds.
    (5) New definition of renewable biomass from which renewable fuels 
can be made, including certain land use restrictions.
    (6) Expansion of the types of fuels that are subject to the 
standards to include diesel.
    (7) Inclusion of specific types of waivers for different categories 
of renewable fuels and, in certain circumstances, 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 used as 
transportation fuel in the U.S. Since the RIN-based system generally 
has been successful in meeting the statutory goals, we are maintaining 
much of its structure under RFS2.
    This section describes the regulatory changes we are finalizing to 
implement the new EISA provisions. Section III describes other changes 
to the RFS program that we considered or are finalizing, including an 
EPA-moderated RIN trading system that provides a context within which 
all RIN transfers will occur.

A. Renewable Identification Numbers (RINs)

    Under RFS2, each RIN will continue to represent one gallon of 
renewable fuel in the context of demonstrating compliance with 
Renewable Volume Obligations (RVO), consistent with our approach under 
RFS1, and the RIN will continue to have unique information similar to 
the 38 digits in RFS1. However in the EPA Moderated Transaction System 
(EMTS), RIN detail information will be available but generally hidden 
during transactions. In general the codes within the RIN will have the 
same meaning under RFS2 as they do under RFS1, with the exception of 
the D code which will be expanded to cover the four categories of 
renewable fuel defined in EISA.
    As described in Section I.A.2, the RFS2 regulatory program will go 
into effect on July 1, 2010, but the 2010 percentage standards issued 
as part of today's rule will apply to all gasoline and diesel produced 
or imported on or after January 1, 2010. As a result, some 2010 RINs 
will be generated under the RFS1 requirements and others will be 
generated under the RFS2 requirements, but all RINs generated in 2010 
will be valid for meeting the 2010 annual standards. Since RFS1 RINs 
and RFS2 RINs will differ in the meaning of the D codes, we are 
implementing a mechanism for distinguishing between these two 
categories of RINs in order to appropriately apply them to the 
standards. In short, we are requiring the use of D codes under RFS2 
that do not overlap the values for the D codes under RFS1. Table II.A-1 
describes the D code definitions we are finalizing in today's action.

[[Page 14685]]



                                     Table II.A-1--Final 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.
7......................................  Not applicable.................  Cellulosic diesel.
----------------------------------------------------------------------------------------------------------------

    Under this approach, D code values of 1 and 2 are only relevant for 
RINs generated under RFS1, and D code values of 3, 4, 5, 6, and 7 are 
only relevant for RINs generated under RFS2. As described in Section 
I.A.2, the RFS1 regulations will apply in January through June of 2010, 
while the RFS2 regulations will become effective on July 1, 2010. RINs 
generated under RFS1 regulations in the first three months of 2010 can 
be used for meeting the four 2010 standards applicable under RFS2. To 
accomplish this, these RFS1 RINs will be subject to the RFS1/RFS2 
transition provisions wherein they will be deemed equivalent to one of 
the four RFS2 RIN categories using their RR and/or D codes. See Section 
II.G.4 for further description of how RFS1 RINs will be used to meet 
standards under RFS2. The determination of which D code will be 
assigned to a given batch of renewable fuel is described in more detail 
in Section II.D.2 below.
    Table II.A-1 includes one D code corresponding to each of the four 
renewable fuel categories defined in EISA, and an additional D code of 
7 corresponding to the unique, additional type of renewable fuel called 
cellulosic diesel. As described in the NPRM, a diesel fuel product 
produced from cellulosic feedstocks that meets the 60% GHG threshold 
could qualify as either cellulosic biofuel or biomass-based diesel. The 
NPRM described two possible approaches to this unique category of 
renewable fuel:
    1. Have the producer of the cellulosic diesel designate their fuel 
up front as either cellulosic biofuel with a D code of 3, or biomass-
based diesel with a D code of 4, limiting the subsequent potential in 
the marketplace for the RIN to be used for just one standard or the 
other.
    2. Have the producer of the cellulosic diesel designate their fuel 
with a new cellulosic D code of 7, allowing the subsequent use of the 
RIN in the marketplace interchangeably for either the cellulosic 
biofuel standard or the biomass-based diesel standard.
    We are finalizing the second option. By creating an additional D 
code of 7 to represent cellulosic diesel RINs, we believe its value in 
the marketplace will be maximized as it will be priced according to the 
relative demand for cellulosic biofuel and biomass-based diesel RINs. 
For instance, if demand for cellulosic biofuel RINs is higher than 
demand for biomass-based diesel RINs, then cellulosic diesel RINs will 
be priced as if they are cellulosic biofuel RINs. Not only does this 
approach benefit producers, but it allows obligated parties the 
flexibility to apply a RIN with a D code of 7 to either their 
cellulosic biofuel RVO or their biomass-based diesel RVO, depending on 
the number of RINs they have acquired to meet these two obligations. It 
also helps the functionality of the RIN program by helping protect 
against the potential for artificial RIN shortages in the marketplace 
for one standard or the other even though sufficient qualifying fuel 
was produced.
    Under RFS2, each batch-RIN generated will continue to uniquely 
identify not only a specific batch of renewable fuel, but also every 
gallon-RIN assigned to that batch. Thus the RIN will 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 is determined based on the types of feedstocks that are 
used, the land that is used to grow feedstocks for renewable fuel 
production, the processes that are used to convert those feedstocks 
into fuel, and the lifecycle greenhouse gas (GHG) emissions that are 
emitted in comparison to the gasoline or diesel that the renewable fuel 
displaces. This section describes these eligibility criteria and how we 
are implementing them for the RFS2 program.
1. Changes in Renewable Fuel Definitions
    Under the previous Renewable Fuel Standards (RFS1), renewable fuel 
was 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 included motor 
vehicle fuels produced from biomass material such as grain, starch, 
fats, greases, oils, and biogas. The definition specifically included 
cellulosic biomass ethanol, waste derived ethanol, and biodiesel, all 
of which were defined separately. (See 72 FR 23915).
    The definitions of renewable fuels under today's rule (RFS2) are 
based on the new statutory definition in EISA. Like the previous 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 II.B.2. The specific definitions and how they 
differ from RFS1 follow below.
a. Renewable Fuel
    ``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.

[[Page 14686]]

``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). Also renewable fuel now includes 
heating fuel and jet 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. However, we are allowing fuel 
producers, importers and end users to include electricity, natural gas, 
and propane made from renewable biomass as a RIN-generating renewable 
fuel in RFS only if they can identify the specific quantities of their 
product which are actually used as a transportation fuel,. This may be 
possible for some portion of renewable electricity and biogas 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 renewable electricity 
or biogas who documents the use of his product in a vehicle or engine 
through a contractual pathway would be allowed to generate RINs to 
represent that product, if it met the definition of renewable fuel. 
(This is also discussed in Section II.D.2.a)
b. Advanced Biofuel
    ``Advanced Biofuel'' is a renewable fuel other than ethanol derived 
from corn starch and for which lifecycle GHG emissions are at least 50% 
less than the gasoline or diesel fuel it displaces. Advanced biofuel 
would be assigned a D code of 5 as shown in Table II.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 50% GHG emission reduction threshold. Thus, even 
if corn starch-derived ethanol were made so that it met the 50% GHG 
reduction threshold, it will still be excluded from being defined as an 
advanced biofuel. Such ethanol while not an advanced biofuel will still 
qualify as a renewable fuel for purposes of meeting the standards.
c. Cellulosic Biofuel
    Cellulosic biofuel is renewable fuel 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 3 as shown in Table II.A-1. 
Cellulosic biofuel in general also qualifies as both ``advanced 
biofuel'' and ``renewable fuel''.
    The 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 such as 
cellulosic gasoline or diesel 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 the final rule.
d. Biomass-Based Diesel
    ``Biomass-based diesel'' includes both biodiesel (mono-alkyl 
esters) and non-ester renewable diesel (including cellulosic diesel). 
The definition of biodiesel is the same very broad definition of 
``biodiesel'' that was in EPAct and in RFS1, and thus, it includes any 
diesel fuel made from biomass feedstocks. However, EISA added three 
restrictions. First, EISA requires that such fuel be made from 
renewable biomass. Second, its lifecycle GHG emissions must be at least 
50% less than the 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 our proposed 
rule, we sought comment on two options for how co-processing could be 
treated. The first option considered co-processing to occur only if 
both petroleum and biomass feedstock are processed in the same unit 
simultaneously. The second option considered 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 selected the first option to be used in the final rule. Under 
this approach, a batch of fuel qualifying for the D code of 4 that is 
produced in a processing unit in which only renewable biomass is the 
feedstock for such batch, will 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 will 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 rule, any fuel that does not satisfy the definition 
of biomass-based diesel only because it is co-processed with petroleum 
will still meet the definition of ``Advanced Biofuel'' provided it 
meets the 50% GHG threshold and other criteria for the D code of 5. 
Similarly it will meet the definition of renewable fuel if it meets a 
GHG emission reduction threshold of 20%. In neither case, however, will 
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.\3\ 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.
---------------------------------------------------------------------------

    \3\ 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

[[Page 14687]]

from renewable biomass that is used to replace or reduce fossil fuels 
used in 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 (i.e., highway fuel) are valid for compliance 
purposes. We therefore 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 have modified the regulatory requirements to allow RINs assigned to 
renewable fuel blended into heating oil or jet fuel in addition to 
highway and nonroad transportation fuels to continue to be valid for 
compliance purposes. From a regulatory standpoint, there is no 
difference between renewable fuels used for transportation purposes, 
versus heating oil and jet fuels.
    EISA uses the term ``home heating oil'' in the definition of 
``additional renewable fuel.'' The statute does not clarify whether the 
term should be interpreted to refer only to heating oil actually used 
in homes, or to all fuel of a type that can be used in homes. We note 
that the term ``home heating oil'' is typically used in industry in the 
latter manner, to refer to a type of fuel, rather than a particular use 
of it, and the term is typically used interchangeably in industry with 
heating oil, heating fuel, home heating fuel, and other terms depending 
on the region and market. We believe this broad interpretation based on 
typical industry usage best serves the goals and purposes of the 
statute. If EPA interpreted the term to apply only to heating oil 
actually used in homes, we would necessarily require tracking of 
individual gallons from production through ultimate use in use in homes 
in order to determine eligibility of the fuel for RINs. Given the 
fungible nature of the oil delivery market, this would likely be 
sufficiently difficult and potentially expensive so as to discourage 
the generation of RINs for renewable fuels used as home heating oil. 
This problem would be similar to that which arose under RFS1 for 
certain renewable fuels (in particular biodiesel) that were produced 
for the highway diesel market but were also suitable for other markets 
such as heating oil and non-road applications where it was unclear at 
the time of fuel production (when RINs are typically generated under 
the RFS program) whether the fuel would ultimately be eligible to 
generate RINs. Congress eliminated the complexity with regards to non-
road applications in RFS2 by making all fuels used in both motor 
vehicle and nonroad applications subject to the renewable fuel standard 
program. We believe it best to interpret the Act so as to also avoid 
this type of complexity in the heating oil context. Thus, under today's 
regulations, RINs may be generated for renewable fuel used as ``heating 
oil,'' as defined in existing EPA regulations at 80.2(ccc). In addition 
to simplifying implementation and administration of the Act, this 
interpretation will best realize the intent of EISA to reduce or 
replace the use of fossil fuels,
f. Cellulosic Diesel
    In the proposed rule, we sought comment on how diesel made from 
cellulosic feedstocks should be considered. Specifically, a diesel fuel 
product produced from cellulosic feedstocks that meets the 60% GHG 
threshold could qualify as either cellulosic biofuel or biomass-based 
diesel. Based on comments received, and as discussed previously in 
Section II.A, today's rule requires the cellulosic diesel producer to 
categorize their product as cellulosic diesel with a D code of 7. It 
can then be traded in the marketplace and used for compliance with 
either the biomass-based diesel standard or the cellulosic biofuel 
standard.
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 II.B.2-1 lists the 
thresholds established by EISA.

            Table II.B.2-1--Lifecycle GHG Thresholds in EISA
       [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 are ``grandfathered.'' See Section II.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 can be made only if it is 
determined that the 50% threshold is not commercially feasible for 
fuels made using a variety of feedstocks, technologies, and processes.
    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 can be made only if it is 
determined that the 60% threshold is 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 V, identified a range of fuel pathways that are capable of 
complying with the GHG performance thresholds for each of these 
separate fuel standards. Thus, we have determined that the GHG 
thresholds in Table II.B.2-1 should not be adjusted. Further discussion 
of this determination can be found in Section V.C.

[[Page 14688]]

3. Renewable Fuel Exempt From 20 Percent GHG Threshold
    After considering comments received, the Agency has decided to 
implement the proposed option for interpreting the grandfathering 
provisions that provide an indefinite exemption from the 20 percent GHG 
threshold for renewable fuel facilities which have commenced 
construction prior to December 19, 2007. For these facilities, only the 
baseline volume of renewable fuel is exempted. For ethanol facilities 
which commenced construction after that date and which use natural gas, 
biofuels or a combination thereof, we proposed that such facilities 
would be ``deemed compliant'' with the 20 percent GHG threshold. The 
exemption for such facilities is conditioned on construction being 
commenced on or before December 31, 2009, and is specific only to 
facilities which produce ethanol only, per language in EISA. The 
exemption would continue indefinitely, provided the facility continues 
to use natural gas and/or biofuel. This section provides the background 
and summary of the original proposal, and the reasons for the selection 
of this option.
a. General Background of the Exemption Requirement
    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.
    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.'' Since all renewable fuel 
production facilities that commenced construction prior to the date of 
EISA enactment are covered by the more general grandfathering 
provision, this exemption can only apply to those facilities that 
commenced construction after enactment of EISA, and before the end of 
2009. We proposed 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 on 
or before December 31, 2009, complete such construction in a reasonable 
amount of time, and continue to burn only natural gas, biomass, or a 
combination thereof. Most commenters generally agreed with our 
proposal, while other commenters argued that the exemption was only 
meant to last for a two-year period. As we noted in the NPRM, we 
believe that it would be a harsh result for investors in these new 
facilities, and would be generally inconsistent with the energy 
independence goals of EISA, to interpret the Act such that these 
facilities would only be guaranteed two years of participation in the 
RFS2 program. In light of these considerations, we continue to believe 
that it is an appropriate interpretation of the Act to allow the deemed 
compliant exemption to continue indefinitely with the limitations we 
proposed. Therefore we are making final this interpretation in today's 
rule.
b. Definition of Commenced Construction
    In defining ``commence'' and ``construction'', we proposed to use 
the definitions of ``commence'' and ``begin actual construction'' from 
the Prevention of Significant Deterioration (PSD) regulations, which 
draws upon definitions in the Clean Air Act. (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 
proposed adding language to the definition that is currently not in the 
PSD definition with respect to multi-phased projects. We proposed 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 addressing 
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 proposed that for 
RFS2 a reasonable time to complete construction of renewable fuel 
facilities be no greater than 3 years from initial commencement of 
construction. We sought comment on this time frame.
    Commenters generally agreed with our proposed definition of 
commenced construction. Some commenters felt that the 3 year time frame 
was not a ``reasonable time'' to complete construction in light of the 
economic difficulties that businesses have been and will likely 
continue to be facing. We recognize that there have been extreme 
economic problems in the past year. Based on historical data which show 
construction of ethanol plants typically take about one year, we 
believe that the 3-year time frame allows such conditions to be taken 
into account and that it is an appropriate and fair amount of time to 
allow for completion. Therefore, we are not extending the amount of 
time that constitutes ``reasonable'' to five years as was suggested.
c. Definition of Facility Boundary
    We proposed 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 proposed to modify the definition, however, to focus on the 
typical renewable fuel plant. We proposed 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. 
Commenters agreed with our proposed definition of ``facility'' and we 
are making that definition final today.
d. Proposed Approaches and Consideration of Comments
    We proposed one basic approach to the exemption provisions and 
sought 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 sought

[[Page 14689]]

comment were: (1) Expiration of exemption for grandfathered and 
``deemed compliant'' 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.
i. Comments on the Proposed Basic Approach
    Generally, commenters supported the basic approach in which the 
volume of renewable fuel from grandfathered facilities exempt from the 
20% GHG reduction threshold would be limited to baseline volume. One 
commenter objected to the basic approach and argued that the statute's 
use of the word ``new'' and the phrase ``after December 19, 2007'' 
provided evidence that facilities which commenced construction prior to 
that date would not ever be subject to the threshold regardless of the 
volume produced from such facilities. In response, we note first that 
the statute does not provide a definition of the term ``new 
facilities'' for which the 20% GHG threshold applies. We believe that 
it would be reasonable to include within our interpretation of this 
term a volume limitation, such that a production plant is considered a 
new facility to the extent that it produces renewable fuel above 
baseline capacity. This approach also provides certainty in the 
marketplace in terms of the volumes of exempt fuel, and a relatively 
straightforward implementation and enforcement mechanism as compared to 
some of the other alternatives considered. Furthermore, EPA believes 
that the Act should not be interpreted as allowing unlimited expansion 
of exempt facilities for an indefinite time period, with all volumes 
exempt, as suggested by the commenter. Such an approach would likely 
lead to a substantial increase in production of fuel that is not 
subject to any GHG limitations, which EPA does not believe would be 
consistent with the objectives of the Act.
    We solicited comment on whether changes at a facility that resulted 
in an increase in GHG emissions, such as a change in fuel or feedstock, 
should terminate the facility's exemption from the 20 percent GHG 
threshold. Generally, commenters did not support such a provision, 
pointing out that there are many variations within a plant that cannot 
be adequately captured in a table of fuel and feedstock pathways as we 
proposed (see 74 FR 24927). Implementing such a provision would create 
questions of accounting and tracking that would need to be evaluated on 
a time-consuming case-by-case basis. For example, if a switch to a 
different feedstock or production process resulted in less efficiency, 
facilities may argue that they are increasing energy efficiency 
elsewhere (e.g. purchasing waste heat instead of burning fuel onsite to 
generate steam). We would then need to assess such changes to track the 
net energy change a plant undergoes. Given the added complexity and 
difficulty in carrying out such an option, we have decided generally 
not to implement it. There is an exception, however, for ``deemed 
compliant'' facilities. These facilities achieve their status in part 
by being fired only by natural gas or biomass, or a combination 
thereof. Today's rule provides, as proposed, that these facilities will 
lose their exemption if they switch to a fuel other than natural gas, 
biomass, or a combination thereof, since these were conditions that 
Congress deemed critical to granting them the exemption from the 20% 
GHG reduction requirement.
    We also solicited 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 to allow for 
increases in volume due to debottlenecking. Some favored this concept, 
while others argued that the tolerance should be set at 20 percent. 
After considering the comments received, we have decided that a 10% 
(and 20%) level is not appropriate for this regulation for the 
following reasons: (1) We have decided to interpret the exemption of 
the baseline volume of renewable fuel from the 20 percent requirement 
as extending indefinitely. Any tolerance provided could, therefore, be 
present in the marketplace for a considerable time period; (2) 
increases in volume of 10% or greater could be the result of 
modifications other than debottlenecking. Consistent with the basic 
approach we are taking today towards interpreting the grandfathering 
and deemed compliant provisions, we believe that the fuel produced as a 
result of such modifications comes from ``new facilities'' within the 
meaning of the statute, and should be subject to the 20% GHG reduction 
requirement; (3) we are allowing baseline volume to be based on the 
maximum capacity that is allowed under state and federal air permits. 
With respect to the last reason, facilities that have been operating 
below the capacity allowed in their state permits would be able to 
claim a baseline volume based on the maximum capacity. As such, these 
facilities may indeed be able to increase their volume by 10 to 20 
percent by virtue of how their baseline volume is defined. We believe 
this is appropriate, however, since their permits should reflect their 
design, and the fuel resulting from their original pre-EISA (or pre-
2010, for deemed compliant facilities) design should be exempt from the 
20% GHG reduction requirement. Nevertheless, we recognize and agree 
with commenters that some allowances should be made for minor changes 
brought about by normal maintenance which are consistent with the 
proper operation of a facility. EPA is not aware of a particular study 
or analysis that could be used as a basis for picking a tolerance level 
reflecting this concept, We believe, however, that the value should be 
relatively small, so as not to encourage plant expansions that are 
unrelated to debottlenecking. We believe that a 5% tolerance level is 
consistent with these considerations, and have incorporated that value 
in today's rule.
ii. Comments on the Expiration of Grandfathered Status
    Commenters who supported an expiration of the exemption did so 
because of concerns that the proposed approach of providing an 
indefinite exemption would not provide any incentives to bring these 
plants into compliance with current standards. They also objected to 
plants being allowed an indefinite period beyond the time period when 
it could be expected that they would have paid off their investors. The 
commenters argued that the cost of operation for such plants would be 
less than competing plants that do have to comply with current 
standards; as such, commenters opposed to the basic approach felt an 
indefinite exemption would be a subsidy to plants that will never 
comply with the 20 percent threshold level. The renewable fuels 
industry, on the other hand, viewed the options that would set an 
expiration date (either via cumulative reconstruction, or a 15-year 
period from date of enactment) as harsh, particularly if the lifecycle 
analysis results make it costly for existing facilities to meet the 20% 
threshold. Some also argued that no such temporal limitation appears in 
the statute.
    We considered such comments, but in light of recent lifecycle 
analyses we conducted in support of this rule we have concluded that 
many of the current

[[Page 14690]]

technology corn ethanol plants may find it difficult if not impossible 
to retrofit existing plants to comply with the 20 percent GHG reduction 
threshold. In addition, the renewable fuels industry viewed the 
alternative proposals that would set an expiration date (either via 
cumulative reconstruction, or a 15-year period from date of enactment) 
as harsh, particularly if the lifecycle analysis results make it costly 
for existing facilities to meet the 20% threshold. Given the difficulty 
of meeting such threshold, owners of such facilities could decide to 
shut down the plant. Given such implications of meeting the 20 percent 
threshold level for existing facilities we have chosen not to finalize 
any expiration date.
e. Final Grandfathering Provisions
    For the reasons discussed above, the Agency has decided to proceed 
with the proposed baseline volume approach, rather than the expiration 
options. We hold open the possibility, therefore, of revisiting and 
reproposing the exemption provision in a future rulemaking to take such 
advances into account. Ending the grandfathering exemption after its 
usefulness is over would help to streamline the ongoing implementation 
of the program.
    The final approach adopted today is summarized as follows:
i. 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 defining the baseline volume of renewable fuel exempt from 
the 20% GHG threshold requirement to be the maximum volumetric capacity 
of the facility that is allowed in any applicable state air permit or 
Federal Title V operating permit.\4\ We had proposed in the NPRM that 
nameplate capacity be defined as permitted capacity, but that if the 
capacity was not stipulated in any federal, state or local air permit, 
then the actual peak output should be used. We have decided that since 
permitted capacity is the limiting condition, by virtue of it being an 
enforceable limit contained in air permits, that the term ``nameplate 
capacity'' is not needed. In addition, we are allowing a 5% tolerance 
as discussed earlier. Therefore, today's rule defines permitted 
capacity as 105% of the maximum permissible volume output of renewable 
fuel allowed under operating conditions specified in all applicable 
preconstruction, construction and operating permits issued by 
regulatory authorities (including local, regional, state or a foreign 
equivalent of a state, and federal permits). If the capacity of a 
facility is not stipulated in such air permits, then the grandfathered 
volume is 105% of the maximum annual volume produced for any of the 
last five calendar years prior to 2008. Volumes greater than this 
amount which may typically be due to expansions of the facility which 
occur after December 19, 2007, will be subject to the 20% GHG reduction 
requirement if the facility wishes to generate RINs for the incremental 
expanded volume. The increased volume will 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 are irrelevant--they remain grandfathered as long 
as the overall volume falls within the baseline volume. Thus, for 
example, if an ethanol facility changed its operation to produce 
butanol, but the baseline volume remained the same, the fuel so 
produced would be exempt from the 20% GHG reduction requirement.
---------------------------------------------------------------------------

    \4\ Volumes also include expansions to existing facilities, 
provided that the construction for such expansion commences prior to 
December 19, 2007. In such instances, the total volume from the 
original facility plus the additional volume due to expansion is 
grandfathered.
---------------------------------------------------------------------------

    The baseline volume will be defined as above for deemed compliant 
facilities (those ethanol facilities fired by natural gas or biomass or 
a combination thereof that commenced construction after December 19, 
2007 but before January 1, 2010) with the exception that if the maximum 
capacity is not stipulated in air permits, then the exempt volume is 
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, their status will be lost, and they will 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, 
if there are any changes in the mix of renewable fuels produced by the 
facility, only the ethanol volume remains grandfathered. We had 
solicited comment on whether fuels other than ethanol could also be 
deemed compliant. Based on comments received and additional 
consideration to this matter, we decided that because the Act does not 
authorize EPA to allow fuels other than ethanol, the deemed compliant 
provisions will apply only to facilities producing that fuel.
    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 will need to 
be converted to an annual rate. Because assumption of a 24-hour per day 
production over 365 days per year (8,760 production hours) may 
overstate the maximum annual capacity we are requiring a conversion 
rate of 95% of the total hours in a year (8,322 production hours) based 
on typical operating ``uptime'' of ethanol facilities.
    The facility registration process (see Section II.C) will be used 
to define the baseline volume for individual facilities. Owners and 
operators must submit information substantiating the permitted capacity 
of the plant, or the maximum annual peak capacity if the maximum 
capacity is not stipulated in a federal, state or local air permit, or 
EPA Title V operating permit. Copies of applicable air permits which 
stipulate the maximum annual capacity of the plant, must be provided as 
part of the registration process. Subsequent expansions at a 
grandfathered facility that results in an increase in volume above the 
baseline volume will subject the increase in volume to the 20% GHG 
emission reduction threshold (but not the original baseline volume). 
Thus, any new expansions will need to be designed to achieve the 20% 
GHG reduction threshold if the facility wants to generate RINs for that 
volume. Such determinations will be made on the basis of EPA-defined 
fuel pathway categories that are deemed to represent such 20% 
reduction.
    EPA enforcement personnel commented that claims for an exemption 
from the 20% GHG reduction requirement should be made promptly, so that 
they can be verified with recent supporting information. They were 
concerned, in particular, that claims for exempt status could be made 
many years into the future for facilities that may or may not have 
concluded construction within the required time period, but delayed 
actual production of renewable fuel due to market conditions or other 
reasons. EPA believes that this comment has merit, and has included a 
requirement in Section 80.1450(f) of the final rule for registration of 
facilities claiming an exemption from the 20% GHG reduction requirement 
by May 1,

[[Page 14691]]

2013. This provision does not require actual fuel production, but 
simply the filing of registration materials that assert a claim for 
exempt status. It will benefit both fuel producers, who will likely be 
able to more readily collect the required information if it is done 
promptly, and EPA enforcement personnel seeking to verify the 
information. However, given the potentially significant implications of 
this requirement for facilities that may qualify for the exemption but 
miss the registration deadline, the rule also provides that EPA may 
waive the requirement if it determines that the submission is 
verifiable to the same extent as a timely-submitted registration.
ii. 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 final rule--the baseline volume of fuel would continue to be 
exempt from the 20% GHG threshold. We sought 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. Some commenters supported such an approach. We agreed, 
however, with other commenters who point out that the language in EISA 
provides for an indefinite exemption for grandfathered facilities. 
While we interpret the statute to limit the exemption to the baseline 
volume of a grandfathered facility, we do not interpret the language to 
allow EPA to require that replacements of coal fired units be natural 
gas or biofuel. Thus replacements of coal fired equipment will not 
affect the facility's grandfathered status.
iii. Registration, Recordkeeping and Reporting
    Facility owner/operators will be required to provide evidence and 
certification of commencement of construction. Such certification will 
require copies of all applicable air permits that apply to the 
construction and operation of the facility. 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 will be required to provide 
certification as well. Since the definition of commencement of 
construction includes having all necessary air permits, we will require 
that facilities outside the United States certify that such facilities 
have obtained all necessary permits for construction and operation 
required by the appropriate national and local environmental agencies.
4. New Renewable Biomass Definition and Land Restrictions
    As explained in Section I, EISA lists seven types of feedstock that 
qualify as ``renewable biomass.'' EISA limits not only the types of 
feedstocks that can be used to make renewable fuel, but also the land 
that 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 prohibits 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 describe EPA's interpretation of several key terms related to 
the definition of renewable biomass, and the approach in today's rule 
to implementing the renewable biomass requirements.
a. Definitions of Terms
    EISA's renewable biomass definition includes a number of terms that 
require definition. The following sections discuss EPA's definitions 
for these terms, which were developed with ease of implementation and 
enforcement in mind. We have made every attempt to define these terms 
as consistently with other federal statutory and regulatory definitions 
as well as industry standards as possible, while keeping them workable 
for purposes of program implementation.
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 proposed 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. We received 
numerous comments on our proposed definition of ``planted crops,'' 
largely in support of our proposed definition. However, some commenters 
noted that ``microcrops,'' such as duckweed, a flowering plant 
typically grown in ponds or tanks, are also being investigated for used 
as renewable fuel feedstocks. These microcrops are typically grown in a 
similar manner to algae, but cannot be categorized as algae since they 
are relatively more complex organisms. EPA's proposed definition would 
have unintentionally excluded microcrops such as duckweed through the 
requirement that planted crops be ``applied to the ground.'' After 
considering comments received, EPA does not believe that there is any 
basis under EISA for excluding from the definition of renewable biomass 
crops such as duckweed that are applied to a tank or pond for growth 
rather than to the soil. As with other planted crops, these ponds or 
tanks must be located on existing ``agricultural land,'' as described 
below, to qualify as renewable biomass under EISA. Therefore, including 
such microcrops within the definition of renewable biomass will not 
result in the direct loss of forestland or other ecologically sensitive 
land that Congress sought to protect through the land restrictions in 
the definition of renewable biomass. Doing so will further the 
objectives of the statute of promoting the development of emerging 
technologies to produce clean alternatives to petroleum-based fuels, 
and to further U.S. energy independence.
    For these reasons, we are finalizing our proposed definition of 
``planted crops,'' with the inclusion of provisions allowing for the 
growth of ``microcrops'' in ponds or tanks that are located on 
agricultural land. Our final definition also includes a reference to 
``vegetative propagation,'' in which a new plant is produced from an 
existing vegetative structure, as one means by which planted crops may 
reproduce, since this is an important method of reproduction for 
microcrops such as duckweed. The final definition of ``planted crops'' 
includes all annual or perennial agricultural crops from existing 
agricultural land 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, duckweed and other species (but not 
including algae species or planted trees), providing that they

[[Page 14692]]

were intentionally applied by humans to the ground, a growth medium, or 
a pond or tank, either by direct application as seed or plant, or 
through intentional natural seeding or vegetative propagation by mature 
plants introduced or left undisturbed for that purpose. We note that 
because EISA contains specific provisions for planted trees and tree 
residue from tree plantations, our final definition of planted crops in 
EISA excludes planted trees, even if they may be considered planted 
crops under some circumstances.
    We proposed that ``crop residue'' be limited to the residue, such 
as corn stover and sugarcane bagasse, left over from the harvesting of 
planted crops. We sought comment on including biomass from agricultural 
land removed for purposes of invasive species control or fire 
management. We received many comments supporting the inclusion of 
biomass removed from agricultural land for purposes of invasive species 
control and/or fire management. We believe that such biomass is 
typically removed from agricultural land for the purpose of preserving 
or enhancing its value in agricultural crop production. It may be 
removed at the time crops are harvested, post harvest, periodically 
(e.g., for pastureland) or during extended fallow periods. We agree 
with the commenters that this material is a form of biomass residue 
related to crop production, whether or not derived from a crop itself, 
and, therefore, are modifying the proposed definition of ``crop 
residue'' to include it. We also received comments encouraging us to 
expand the definition of crop residue to include materials left over 
after the processing of the crop into a useable resource, such as 
husks, seeds, bagasse and roots. EPA agrees with these comments and has 
altered the final definition to cover such materials. Based on comments 
received, our final definition of ``crop residue'' is the biomass left 
over from the harvesting or processing of planted crops from existing 
agricultural land and any biomass removed from existing agricultural 
land that facilitates crop management (including biomass removed from 
such lands in relation to invasive species control or fire management), 
whether or not the biomass includes any portion of a crop or crop 
plant.
    Our proposed regulations restricted planted crops and crop residue 
to that harvested from existing agricultural land, which, under our 
proposed definition, includes three land categories--cropland, 
pastureland, and Conservation Reserve Program (CRP) land. We proposed 
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. We proposed 
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. We also 
proposed that CRP land, which is administered by USDA's Farm Service 
Agency, qualify as ``agricultural land'' under RFS2.
    EPA received numerous comments on our proposed definition of 
existing agricultural land. Generally, commenters were in support of 
our definition of ``cropland'' and its inclusion in the definition of 
existing agricultural land. Additionally, commenters generally did not 
object to CRP lands or pastureland being included in the definition of 
agricultural land. Based on our consideration of comments received on 
the proposed rule, EPA is including cropland, pastureland and CRP land 
in the definition of existing agricultural land, as proposed.
    We sought comment in the proposal 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. EPA 
received a number of comments concerning whether rangeland should be 
included in the definition of existing agricultural land under RFS2. 
Some commenters urged EPA to expand the definition of existing 
agricultural land to include rangeland, arguing that rangelands could 
serve as important sources of renewable fuel feedstocks. Many of these 
commenters argued that, although it is generally less intensively 
managed than cropland, rangeland is nonetheless actively managed 
through control of brush or weed species, among other practices. In 
contrast, other commenters argued against the inclusion of rangeland, 
contending that the potential conversion of rangeland into cropland for 
growing renewable biomass would lead to losses of carbon, soil, water 
quality, and biodiversity.
    Under EISA, renewable biomass includes crops and crop residue from 
agricultural land cleared or cultivated at any time prior to the 
enactment of EISA that is either ``actively managed of fallow'' and 
nonforested. In determining whether rangeland should be considered 
existing agricultural land under this provision, EPA must decide if 
rangeland qualifies as ``actively managed or fallow.'' EPA believes 
that the term ``actively managed'' is best interpreted by reference to 
the type of material and practices that this provision addresses--
namely crops and residue associated with growing crops. We think it is 
appropriate to inquire whether the type of management involved in a 
land type is consistent with that which would occur on land where crops 
are harvested. Thus, while we acknowledge that some types of rangeland 
are managed to a certain degree, the level of ``active management'' 
that is typically associated with land dedicated to growing 
agricultural crops is far more intensive than the types of management 
associated with rangeland. For example, rangeland is rarely tilled, 
fertilized or irrigated as croplands and, to a lesser degree, 
pasturelands, are. Furthermore, since rangeland encompasses a wide 
variety of ecosystems, including native grasslands or shrublands, 
savannas, wetlands, deserts and tundra, including it in the definition 
of agricultural land would increase the risk that these sensitive 
ecosystems would become available under EISA for conversion into 
intensively managed mono-culture cropland. Finally, the conversion of 
relatively undisturbed rangeland to the production of annual crops 
could in some cases lead to large releases of GHGs stored in the soil, 
as well as a loss of biodiversity, both of which would be contrary to 
EISA's stated goals. For these reasons, EPA is not including rangeland 
in the definition of ``existing agricultural land'' in today's final 
rule.
    We proposed 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 proposed 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 received extensive comments on this interpretation. Many 
commenters suggested an interpretation of the requirement that 
agricultural land be ``actively managed'' to mean that the land had to 
be ``actively managed'' at the time EISA was passed on December 17, 
2007, such that the amount of land available for biofuel feedstock 
production was established at that point

[[Page 14693]]

and would not diminish over time. Other commenters supported our 
proposed interpretation, which would mean that the amount of land 
available for biofuel feedstock production could diminish over time if 
parcels of land cease to be actively managed at any point, thus taking 
them out of contention for biofuel feedstock cultivation. Some 
commenters argued that this interpretation is contrary to Congress' 
intent and the basic premise of the RFS program since, over time, it 
could lead to a reduction in the amount of renewable biomass available 
for use as renewable fuel feedstocks, while the statutorily required 
volumes of renewable fuel increase over time. These commenters further 
argue that the active management provision should be interpreted as a 
``snapshot'' of agricultural land existing and actively managed on 
December 19, 2007. Under this interpretation, the land that was cleared 
or cultivated prior to December 19, 2007 and was actively managed on 
that date, would be eligible for renewable biomass production 
indefinitely.
    We agree that the goal of the EISA and RFS program, to increase the 
presence of renewable fuels in transportation fuel, will be better 
served by interpreting the ``actively managed or fallow'' requirement 
in the renewable biomass definition as applying to land actively 
managed or fallow on December 19, 2007, rather than interpreting this 
requirement as applying beginning on December 19, 2007 and continuously 
thereafter. In addition, by simplifying the requirement in this 
fashion, there will be significantly less burden on regulated parties 
in ensuring that their feedstocks come from qualifying lands. For these 
reasons, we are modifying the definition of existing agricultural land 
so that the ``active management'' requirement is satisfied for those 
that were cleared or cultivated and actively managed or fallow, and 
non-forested on December 19, 2007.
    Further, we proposed and are finalizing that ``actively managed'' 
means 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. While we received comments indicating that 
including a definitive checklist of required evidential records would 
be helpful to have explicitly identified in the regulations, we are not 
doing so in order to maintain flexibility, as feedstock producers may 
vary in the types of evidence they can readily obtain to show that 
their agricultural land was actively managed. We are adding, however, a 
clarification that the records must be traceable to the land in 
question. For example, it will not be sufficient to have a receipt for 
seed purchase if there is not additional evidence indicating that the 
seed was applied to the land which is claimed as existing agricultural 
land.
    The term ``fallow'' is generally used to describe cultivated land 
taken out of production for a finite period of time. We proposed and 
sought comment on defining 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. We also proposed and sought comment on requiring 
documentation of such intent. We received many comments that supported 
our proposed definition of fallow. We also received comments indicating 
that EPA should set a time limit for land to qualify as fallow (as 
opposed to abandoned for agricultural purposes). We have decided not to 
include a time limit for land to qualify as ``fallow'' because we 
understand that agricultural land may be left fallow for many different 
purposes and for varying amounts of time. Any particular timeframe that 
EPA might choose for this purpose would be somewhat arbitrary. Further, 
EISA does not indicate a time limit on the period of time that 
qualifying land could be fallow, so EPA does not believe that it would 
be appropriate to do so in its regulations. Therefore, EPA is 
finalizing its proposed definition of ``fallow.''
    Finally, in order to define the term ``nonforested'' as used in the 
definition of ``existing agricultural land,'' we proposed first to 
define the term ``forestland'' as generally undeveloped land covering a 
minimum area of one acre upon which the predominant vegetative cover is 
trees, including land that formerly had such tree cover and that will 
be regenerated. We also proposed that forestland would not include tree 
plantations. ``Nonforested'' land under our proposal would be land that 
is not forestland.
    We received many comments on our proposed definition of forestland. 
Some commenters urged EPA to broaden the definition of ``forestland'' 
to include tree plantations, arguing that plantations are well-accepted 
as a subset of forestland. Others advocated that EPA should make every 
effort to distinguish between tree plantations and forestland so as not 
to run the risk of allowing native forests to be converted into less 
diverse tree plantations from which trees could be harvested for 
renewable fuel production. For today's final rule, EPA is including 
tree plantations as a subset of forestland since it is commonly 
understood as such throughout the forestry industry. Under EISA, 
renewable biomass may include ``slash and pre-commercial thinnings'' 
from non-federal forestlands, and ``planted trees and tree residue'' 
from actively managed tree plantations on non-federal land. One effect 
under EISA of the modification from the proposed rule to include tree 
plantations as a subset of forestland is to allow pre-commercial 
thinnings and slash, in addition to planted trees and tree residue, 
harvested from tree plantations to serve as qualifying feedstocks for 
renewable fuel production. EPA believes it is appropriate to include 
pre-commercial thinnings and slash from actively managed tree 
plantations as renewable biomass, consistent with the EISA provision 
allowing harvested trees and tree residue from tree plantations to 
qualify as renewable biomass. Another effect of including the tree 
plantations as a kind of forestland is that, since crops and crop 
residue must come from land that was ``non-forested'' as of the date of 
EISA enactment, a tract of land managed as a tree plantation on the 
date of EISA enactment could not be converted to cropland for the 
production of feedstock for RIN-generating renewable fuel. EPA believes 
that this result in keeping with Congressional desire to avoid the 
conversion of new lands to crop production for renewable fuel 
production.
    Additionally, EPA received comments indicating that, in order to be 
consistent with existing statutory and/or regulatory definitions of 
``forestland,'' EPA should exclude tree covered areas in intensive 
agricultural crop production settings, such as fruit orchards, or tree-
covered areas in urban settings such as city parks from the definition 
of forestland. EPA agrees that these types of land cannot be 
characterized as ``forestland,'' and is thus excluding them from the 
definition. EPA's final definition of forestland is ``generally 
undeveloped land covering a minimum of 1 acre upon which the primary 
vegetative species is trees, including land that formerly had such tree 
cover and that will be regenerated and tree plantations.

[[Page 14694]]

Tree covered areas in intensive agricultural crop production settings, 
such as fruit orchards, or tree-covered areas in urban settings such as 
city parks, are not considered forestland.''
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 proposed 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. 
Some commenters disagreed with our inclusion of naturally seeded trees 
in our definition of ``planted trees.'' They argue that an area which 
is managed for natural regeneration of trees is more akin to a natural 
forest than a tree plantation, and that the difference between the two 
types of land should be clear in order to distinguish between the two 
and to avoid the effective conversion of natural forests to tree 
plantations under EISA. EPA agrees that the inclusion of natural 
reseeding in the definition of ``planted trees'' would make 
distinguishing between tree plantations and forests difficult or 
impossible, thus negating the separate restrictions that Congress 
placed on the two types of land. On the other hand, EPA believes that 
trees that are naturally seeded and grown together with hand- or 
machine-planted trees in a tree plantation should not categorically be 
excluded from qualifying as renewable biomass. Such natural reseeding 
may occur after planting the majority of trees in a tree plantation, 
and may be consistent with the management plan for a tree plantation. 
EPA has decided, therefore, to modify its proposed definition of 
``planted tree'' to be trees harvested from a tree plantation. The term 
``tree plantation'' is defined as a stand of no less than 1 acre 
composed primarily of trees established by hand- or machine-planting of 
a seed or sapling, or by coppice growth from the stump or root of a 
tree that was hand- or machine-planted.'' The net effect is that as 
long as a tree plantation consists ``primarily'' of trees that were 
hand- or machine planted (or derived therefrom, as described below), 
then all trees from the tree plantation, including those established 
from natural seeding by mature trees left undisturbed for such a 
purpose, will qualify as renewable biomass.
    We also received a number of comments suggesting that EPA broaden 
the definition of planted trees to include other methods of tree 
regeneration, such as coppice (the production of new stems from stumps 
or roots), that are frequently used in the forestry industry to 
regenerate tree plantations. EPA believes that ``planted'' implies 
direct human intervention, and that allowing stump-growth from the 
stump or roots of a tree that was hand- or machine-planted is 
consistent with this concept. Therefore, today's final rule broadens 
the concept of ``planted trees'' from a tree plantation to include ``a 
tree established by hand- or machine-planting of a seed or sapling, or 
by coppice growth from the stump or root of a tree that was hand- or 
machine-planted.'' This new language will appear in the definition of 
``tree plantation.''
    In the NPRM, we proposed 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 one acre. We received numerous comments on our definition 
of tree plantation. Several commenters urged EPA to define tree 
plantation more broadly by using the definition from the Dictionary of 
Forestry--``a stand composed primarily of trees established by planting 
or artificial seeding,'' However, this definition does not provide 
sufficiently clear guidelines for determining whether a given parcel of 
land would be considered a tree plantation rather than a natural 
forest. Since trees are considered renewable biomass under RFS2 only if 
they are harvested from tree plantations, we believe that our proposed 
definition was clearer and more easily applied in the field. 
Accordingly, EPA has not adopted the definition of this term from the 
Dictionary of Forestry. Other commenters argued that there is no 
technical justification for limiting the number of species or number of 
trees in a plantation, and that many tree plantations include a variety 
of species. EPA believes that there is merit in these comments. 
Accordingly, EPA is finalizing a broadened definition of ``tree 
plantation,'' by removing the limitations on the number and species of 
trees. EPA is defining tree plantation as ``a stand of no less than 1 
acre composed primarily of trees established by hand- or machine-
planting of a seed or sapling, or by coppice growth from the stump or 
root of a tree that was hand- or machine-planted.''
    We proposed to apply similar management restrictions to tree 
plantations as would apply to existing agricultural land and also to 
interpret the EISA language as requiring that to qualify as renewable 
biomass for renewable fuel 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. Consistent with 
our final position regarding actively managed existing agricultural 
land, we are defining the term ``actively managed'' in the context of 
tree plantations as managed for a predetermined outcome as evidenced by 
any of the following that must be traceable to the land in question: 
Sales records for planted trees or slash; purchasing records for seeds, 
seedlings, or other nursery stock together with other written 
documentation connecting the land in question to these purchases; a 
written management plan for silvicultural purposes; documentation of 
participation in a silvicultural program sponsored by a Federal, state 
or local government agency; documentation of land management in 
accordance with an agricultural or silvicultural product certification 
program; an agreement for land management consultation with a 
professional forester that identifies the land in question; or evidence 
of the existence and ongoing maintenance of a road system or other 
physical infrastructure designed and maintained for logging use, 
together with one of the above-mentioned documents. 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. As with the definition of ``actively 
managed'' as it applies to crops from existing agricultural lands, we 
received extensive comments on this interpretation. As with our final 
position for crops from existing agricultural lands, we are 
interpreting the ``active management'' requirement for tree plantations 
to apply on the date of EISA's enactment, December 19, 2007. Those tree 
plantations that were cleared or cultivated and actively managed on 
December 19, 2007 are eligible for the production of planted trees, 
tree residue, slash and pre-commercial thinnings for renewable fuel 
production.
    In lieu of the term ``tree residue,'' we proposed to use the term 
``slash'' in our regulations as a more descriptive, but otherwise 
synonymous, term. According

[[Page 14695]]

to the Dictionary of Forestry (1998, p. 168), a source of commonly 
understood industry definitions, 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 also proposed to 
clarify that slash can include tree bark and can be the result of any 
natural disaster, including flooding. We received comments in support 
of this additional inclusion and are expanding the definition of 
``slash'' to include tree bark and residue resulting from natural 
disaster, including flooding. We received general support for our 
proposal to substitute our definition of ``slash'' for ``tree 
residue,'' however, several commenters argued that our definition of 
slash is too narrow to be substituted for ``tree residue,'' which 
should include woody residues from saw mills and paper mills that 
process planted trees from tree plantations. EPA agrees that the term 
``residue'' should include this material. Therefore, EPA is expanding 
the definition of ``tree residue'' to include residues from processing 
planted trees at lumber and paper mills, but is limiting it to the 
biogenically derived portion of the residues that can be traced back to 
feedstocks meeting the definition of renewable biomass (i.e. planted 
trees and tree residue from actively managed tree plantations on non-
federal land cleared at any time prior to December 19, 2007). RINs may 
only be generated for the fraction of fuel produced that represents the 
biogenic portion of the tree residue, using the procedures described in 
ASTM test method D-6866. Thus, if the tree residues are mixed with 
chemicals or other materials during processing at the lumber or paper 
mills, producers may only generate RINs for the portion of the mixture 
that is actually derived from planted trees. EPA's final definition of 
``tree residue'' is ``slash and any woody residue generated during the 
processing of planted trees from actively managed tree plantations for 
use in lumber, paper, furniture or other applications, providing that 
such woody residue is not mixed with similar residue from trees that do 
not originate in 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. However, EISA 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. II.B.4.a.i of this preamble, our definition of 
``forestland'' is generally undeveloped land covering a minimum of 1 
acre upon which the primary vegetative species is trees, including land 
that formerly had such tree cover and that will be regenerated and tree 
plantations. Tree-covered areas in intensive agricultural crop 
production settings, such as fruit orchards or tree-covered areas in 
urban setting such as city parks, are not considered forestland. Also 
as noted in Sec. III.B.4.a.ii of this preamble, we are adopting the 
definition of slash listed in the Dictionary of Forestry, with the 
addition of tree bark and residue resulting from natural disaster, 
including flooding.
    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.'' Because what may now be considered pre-
commercial may eventually be saleable as renewable fuel feedstock, we 
proposed 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. Additionally, we proposed 
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 sought 
comment on whether our definition of pre-commercial thinnings should 
include a maximum diameter and, if so, what the appropriate maximum 
diameter should be. We received comments on our proposed definition of 
pre-commercial thinnings that were generally supportive of our proposed 
definition. Many commenters argued that EPA should not use a maximum 
tree diameter as a basis for defining pre-commercial thinning as tree 
diameter varies greatly by forest type and location, making any 
diameter limitation EPA might set arbitrary. EPA agrees with this 
assessment. Commenters also argued that pre-commercial thinnings may 
include other non-tree vegetative material that is removed to promote 
and improve tree growth. EPA is attempting to utilize standard industry 
definitions to the extent practicable, and believes that the proposed 
definition of pre-commercial thinnings, based largely on the Dictionary 
of Forestry definition with the addition of other vegetative material 
removed to promote tree growth, is appropriate. Therefore, we are 
finalizing the proposed definition of ``pre-commercial thinnings,'' 
with the addition of the phrase ``or other vegetative material that is 
removed to promote tree growth.''
    We proposed 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. 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 
proposed and sought comment on prohibiting 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 proposed to use data compiled by NatureServe and published in 
special reports to identify ``ecologically sensitive forestland.'' The 
reports listed 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 included descriptions of the key geographic and biologic 
attributes of the referenced ecological community. We proposed that the 
document be incorporated by reference into the definition of renewable 
biomass in the final RFS2 regulations (and updated as appropriate 
through notice and comment rulemaking). The document would 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. Draft versions 
of the

[[Page 14696]]

document containing the global and State rankings were placed in the 
docket for the proposed rule.
    EPA received several comments on our proposed interpretation of 
EISA's State Natural Heritage Program requirement and the reports 
listing G1-G3 and S1-S3 ecological communities. Several commenters 
argued that while EISA authorizes EPA to exclude slash and pre-
commercial thinnings from S1-3 and G1 and G2 communities, it does not 
authorize the exclusion of biomass from G3 communities, which are 
designated as ``vulnerable,'' not ``critically imperiled, imperiled or 
rare,'' as EISA requires. The commenters further argue that there is 
little or no environmental benefit to adding G3 communities to the list 
of lands unavailable for renewable fuel feedstock production, and that 
their inclusion limits the availability of forest-derived biomass. EPA 
agrees with these comments, and has drafted today's final rule so as 
not to specifically exclude from the definition of renewable biomass 
slash and pre-commercial thinnings from G3-ranked ``vulnerable'' 
ecological communities to qualify as renewable biomass for purposes of 
RFS2. We are interpreting EISA's language to exclude from the 
definition of renewable biomass any biomass taken from ecological 
communities in the U.S. with Natural Heritage Programs global ranking 
of G1 or G2, or with a State ranking of S1, S2, or S3. We are including 
in today's rulemaking docket (EPA-HQ-OAR-2005-0161) the list of 
ecological communities fitting this description.
    To complete the definition of ``ecologically sensitive 
forestland,'' we proposed to include old growth and late successional 
forestland which is characterized by trees at least 200 years old. We 
received comments on this proposed definition recommending that EPA not 
use a single tree age in the define old growth and late-successional 
forests, as this criterion does not apply to all types of forests. 
While EPA understands that there are a number of criteria for 
determining whether a forest is old growth and that the criteria differ 
depending on the type of forest, for purposes of the RFS2 rule, EPA 
seeks to use definitive criteria that can be applied by non-
professionals. EPA is finalizing the definition of ``old growth'' as 
proposed.
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 proposed 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.
    Furthermore, we proposed 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. We sought 
comment on two possible implementation alternatives for identifying 
areas at risk of wildfire. The first proposed alternative would 
incorporate into our definition of ``areas at risk of wildfire'' any 
communities identified as ``communities at risk'' and covered by a 
community wildfire protection plan (CWPP). Communities at risk are 
defined through a process within the document, ``Field Guidance--
Identifying and Prioritizing Communities at Risk'' (National 
Association of State Foresters, June 2003). CWPPs are 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 sought comment on incorporating by reference into the 
final RFS2 regulations a list of ``communities at risk'' with an 
approved CWPP. We also sought comment on a second implementation 
approach, which 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. We noted that 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 the 2000 Census and the U.S. Geological Survey National Land 
Cover Data (NLCD), and we sought comment on how best to use this map.
    We received comments on the proposal and on the two proposed 
alternative options for identifying areas at risk of wildfire. A number 
of commenters argued that EPA should define ``areas at risk of 
wildfire'' using an existing definition of WUI from the Healthy Forests 
Restoration Act (Pub. L. 108-148). Many commenters recommended that EPA 
include both lands covered by a CWPP as well as lands meeting the 
Healthy Forests Restoration Act definition of WUI in order to maximize 
the amount of land available for biomass feedstock and to encourage the 
removal of hazardous fuel for wildfires. EPA understands that very few 
communities that might be eligible for a CWPP actually have one in 
place, due to the numerous administrative steps that must be taken in 
order to have a CWPP approved, so the option of defining areas at risk 
of wildfire exclusively by reference to a list of communities with an 
approved CWPP would be underinclusive of all lands that a professional 
forester would consider to be at risk of wildfire. Furthermore, EPA 
believes that the statutory definition of WUI from the Healthy Forests 
Restoration Act (Pub. L. 108-148) is too vague using directly in 
implementing the RFS2 program. If EPA used this WUI definition, 
individual plots of land would have to be assessed by a professional 
forester on a case-by-case basis in order to determine if they meet the 
WUI definition, creating an expensive burden for landowners seeking to 
sell biomass from their lands as renewable fuel feedstocks.
    In light of the comments received and the need for a simple way for 
landowners and renewable fuel producers to track the status of 
particular plots of land, for the final rule we are identifying ``areas 
at risk of wildfire'' as those areas identified as wildland urban 
interface. Those areas are depicted and mapped at http://silvis.forest.wisc.edu/Library/WUILibrary.asp. The electronic WUI map 
is a readily accessible reference tool that was prepared by experts in 
the field of identifying areas at risk of wildfire, and is thus an 
ideal reference for purposes of implementing RFS2. EPA has included in 
the rulemaking docket instructions on using the WUI map to find the 
status of a plot of land.
v. Algae
    EISA specifies that ``algae'' qualify as renewable biomass. EPA did 
not propose a definition for this term. A number of commenters have 
requested clarification, specifically asking whether cyanobacteria 
(also known as blue-green algae), diatoms, and angiosperms are within 
the definition. Technically, the term ``algae'' has recently been 
defined as ``thallophytes (plants lacking roots, stems and leaves) that 
have chlorophyll a as their primary photosynthetic pigment and lack a 
sterile covering of

[[Page 14697]]

cells around the reproductive cells.'' \5\ Algae are relatively simple 
organisms that are virtually ubiquitous, occurring in freshwater, 
brackish water, saltwater, and terrestrial habitats. When present in 
water, they may be suspended, or grow attached to various substrates. 
They range in size from unicellular to among the longest living 
organisms (e.g. sea kelp). There is some disagreement among scientists 
as to whether cyanobacteria should be considered bacteria or algae. 
Some consider them to be bacteria because of their cellular 
organization and biochemistry. However, others find it more significant 
that they contain chlorophyll a, which differs from the chlorophyll of 
bacteria which are photosynthetic, and also because free oxygen is 
liberated in blue-green algal photosynthesis but not in that of the 
bacteria.\6\ EPA believes that it furthers the purposes of EISA to 
interpret the term ``algae'' in EISA broadly to include cyanobacteria, 
since doing so will make available another possible feedstock for 
renewable fuel production that will further the energy independence and 
greenhouse gas reduction objectives of the Act. Further, EPA expects 
that cyanobacteria used in biofuel production would be cultivated, as 
opposed to harvested, and therefore that there would be no significant 
impact from use of cyanobacteria for biofuel production on naturally 
occurring algal populations. Diatoms are generally considered by the 
scientific community to be algae,\7\ and, consistent with this general 
scientific consensus, EPA interprets the EISA definition of algae to 
include them. Microcrop angiosperms, however, do not meet the 
definition of algae, even if they live in an aquatic habitat, since 
they are relatively more complex organisms than the algae. A discussion 
of microcrop angiosperms is included above in the discussion of 
``planted crops and crop residue.''
---------------------------------------------------------------------------

    \5\ Phycology, Robert Edward Lee, Cambridge University Press, 
2008, page 3.
    \6\ See, generally, Introduction to the Algae. Structure and 
Reproduction, by Harold C. Bold and Michael J. Wynne, Prentice-Hall 
Inc. 1978, page 31.
    \7\ See id.
---------------------------------------------------------------------------

b. Implementation of Renewable Biomass Requirements
    Our proposed approach to the treatment of renewable biomass under 
RFS2 was 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. Our proposed and final approaches to 
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 eligible for the 
program if made from certain feedstocks, and if some of those 
feedstocks 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 
meets EISA's definitions of renewable biomass include land 
restrictions. Otherwise, no RINs could be generated to represent the 
renewable fuel produced or imported. The EISA language does not 
distinguish between domestic renewable fuel feedstocks and renewable 
fuel feedstocks that come from abroad, so our final rule requires 
similar feedstock affirmation and recordkeeping requirements for both 
RIN-generating domestic renewable fuel producers and RIN-generating 
foreign producers or importers.
    We acknowledge that incidental contaminants can be introduced into 
feedstocks during cultivation, transport or processing. It is not EPA's 
intent that the presence of such contaminants should disqualify the 
feedstock as renewable biomass. The final regulations therefore 
stipulate that the term ``renewable biomass'' includes incidental 
contaminants related to customary feedstock production and transport 
that are present in feedstock that otherwise meets the definition if 
such incidental contaminants are impractical to remove and occur in de 
minimus levels. By ``related to customary feedstock production and 
transport,'' we refer to contaminants related to crop production, such 
as soil or residues related to fertilizer, pesticide and herbicide 
applications to crops, as well as contaminants related to feedstock 
transport, such as nylon rope used to bind feedstock materials. It 
would also include agricultural contaminants introduced to the 
feedstock during sorting or shipping, such as miscellaneous sorghum 
grains present in a load of corn kernels. However, contamination is not 
related to customary feedstock production and transport, so such 
feedstocks would not qualify, and in particular, any hazardous waste or 
toxic chemical contaminant in feedstock would disqualify the feedstock 
as renewable biomass.
ii. Whether RINs Must Be 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. 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.'' The inclusion of such 
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 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 shortage of RINs in the market 
that could force obligated parties into non-compliance even though 
biofuels are being produced and used. 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.
    With these concerns in mind, EPA proposed to preserve in RFS2 the 
RFS1 requirement that RINs be generated for all qualifying renewable 
fuel. We also proposed that renewable fuel producers maintain records 
showing that they utilized feedstocks made from renewable biomass if 
they are generating RINs, or, if they are not generating RINs, that 
they did not use feedstocks that qualify as renewable biomass. However, 
we considered this matter further, and we realize that the implication 
of these proposed requirements is that renewable fuel producers would 
be caught in the untenable position of being forced to participate in 
the RFS2 program (register, keep records, etc.) even if they are unable 
to generate RINS because their feedstocks do not meet the definition of 
renewable biomass. We received many comments on the proposed 
requirement to generate RINs for all qualifying renewable fuel. Most

[[Page 14698]]

commenters argued that the requirement to keep records for non-
qualifying renewable fuels was excessively onerous and served little 
purpose for the program.
    After considering the comments received, EPA has determined that 
this requirement would be overly burdensome and unreasonable for 
producers. The burden stems from the requirement that producers prove 
that their feedstocks do not qualify if they are not generating RINs. 
If the data did not exist or could not be obtained, producers could not 
produce the fuel, even if no RINs would be generated. Thus, for the 
final rule, EPA is requiring only that producers that do generate RINs 
have the requisite records (as discussed in section II.B.4.c.i. of this 
preamble) documenting that their fuel is produced from feedstocks 
meeting the definition of renewable biomass. Non-RIN generating 
producers need not maintain any paperwork related to their feedstocks 
and their origins.
    Although EPA is not requiring that RINs be generated for all 
qualifying renewable fuel, EPA is seeking to avoid situations where 
biofuels are produced, but RINs are not made available to the market 
for compliance. EPA received comments requesting that we consider a 
provision in which any volume of renewable fuel for which RINs were not 
generated would be an obligated volume for that producer, to serve as a 
disincentive for those producers who might not generate RINs in order 
to avoid the RFS program requirements. While EPA is not finalizing this 
provision in today's rule, we may consider a future rulemaking to 
promulgate a provision such as this if we find that EISA volumes are 
not being met due to producers declining to generate RINs for their 
qualifying renewable fuel. We also note that it is ultimately the 
availability of qualifying renewable fuel, as determined in part by the 
number of RINs in the marketplace, that will determine the extent to 
which EPA should issue a waiver of RFS requirements on the basis of 
inadequate domestic supply. It is in the interest of renewable fuel 
producers to avoid a situation where a waiver of the EISA volume 
requirements appears necessary. EPA encourages renewable fuel producers 
to generate RINs for all fuel that is made from feedstocks meeting the 
definition of renewable biomass and that meets the GHG emissions 
reduction thresholds set out in EISA. Please see section II.D.6 for 
additional discussion of this issue.
c. Implementation Approaches for Domestic Renewable Fuel
    Consistent with RFS1, renewable fuel producers will be responsible 
for generating Renewable Identification Numbers (RINs) under RFS2. In 
order to determine whether or not their fuel is eligible for generating 
RINs, renewable fuel producers will generally need to have at least 
basic information about the origin of their feedstocks, to ensure they 
meet the definition of renewable biomass. In the proposal, EPA 
described and sought comment on several approaches for implementing the 
land restrictions on renewable biomass contained in EISA.
    The proposed approach for ensuring that producers generate RINs 
properly was that EPA would 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 
fall within the EISA definition of renewable biomass. EPA would require 
renewable fuel producers who generate RINs to affirm on their renewable 
fuel production reports that the feedstock used for each renewable fuel 
batch meets the definition of renewable biomass. EPA would also require 
renewable fuel producers to maintain sufficient records to support 
these claims. Specifically, we proposed that 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 proposed to require renewable fuel producers to have, at a 
minimum, written records from their feedstock supplier that serve as 
evidence that the feedstock qualifies as renewable biomass.
    We sought comment on this approach generally as well as other 
methods of verifying renewable fuel producers' claims that feedstocks 
qualify as renewable biomass. EPA received extensive comments on the 
proposed approach. Many affected parties argued that the proposed 
approach would pose an unnecessary recordkeeping burden on both 
feedstock and renewable fuel producers when, in practice, new lands 
will not be cleared, at least in the near future, for purposes of 
growing renewable fuel feedstocks. Commenters argued that individual 
recordkeeping was onerous, when compliance with the renewable biomass 
requirements could be determined through the use of existing data and 
third-party programs. Commenters contend that the recordkeeping and 
feedstock tracking requirements are particularly arduous for corn, 
soybeans and other agricultural crops that are used as renewable fuel 
feedstocks due to both the maturity and the highly fungible nature of 
those feedstock systems. In contrast, other commenters argued that 
recordkeeping and reporting requirements are necessary to ensure that 
feedstocks are properly verified as renewable biomass to prevent 
undesirable impacts on natural ecosystems and wildlife habitat 
globally.
    We also sought comment on the possible use under EISA of 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. We examined third-
party organizations that certify specific types of biomass from 
croplands and organizations that certify forest lands, including the 
Roundtable on Sustainable Palm Oil, the Basel Criteria for Responsible 
Soy Production, the Roundtable on Sustainable Biofuels (RSB) and the 
Better Sugarcane Initiative (BSI). Additionally, we examined the work 
of the international Soy Working Group, the Brazilian Association of 
Vegetable Oil Industries (ABIOVE) and Brazil's National Association of 
Grain Exporters (ANEC), Greenpeace, Verified Sustainable Ethanol 
initiative, the Sustainable Agriculture Network (SAN), the Forest 
Stewardship Council (FSC), American Tree Farm program and Sustainable 
Forestry Initiative (SFI). We proposed not to solely rely on any 
existing third-party verification program to implement the land 
restrictions on renewable biomass under RFS2 for several reasons. These 
programs are limited in the scope of products they certify, the acreage 
of land certified through third parties in the U.S. covers only a small 
portion of the total available land estimated to qualify for renewable 
biomass production under the EISA definition, and none of the existing 
third-party systems had definitions or criteria that perfectly match 
the land use definitions

[[Page 14699]]

and restrictions contained in the EISA definition of renewable biomass.
    We received several comments indicating that producers would like 
to use evidence of their participation in these types of programs to 
prove that their feedstocks meet the definition of renewable biomass. 
Others argued that while, at this time, the requirements of third-party 
programs may not encompass all of the restrictions and requirements of 
EISA's renewable biomass definition, the programs may alter their 
criteria in the future to parallel EISA's requirements. EPA agrees that 
this is a possibility and, in the future, will consider the use of 
these programs in order to simplify compliance with the renewable 
biomass requirements. We encourage fuel producers to work to identify 
changes to such programs that could allow them to be used as a viable 
compliance option.
    In the proposal, EPA also acknowledged that land restrictions 
contained within the definition of renewable biomass may not, in 
practice, result in a significant change in agricultural practices, 
since biomass from nonqualifying lands may still be used for non-fuel 
(e.g., food) purposes. Therefore, we sought 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. Additionally, EPA offered as an alternative 
the use of existing satellite and aerial imagery and mapping software 
and tools to implement the renewable biomass provisions of EISA. We 
received numerous comments in support of these options. Commenters 
argued that USDA collects and maintains ample data on land use that EPA 
could use to demonstrate that, due to increasing crop yields and other 
considerations, agricultural land acreage will not expand, at least in 
the near term, to accommodate the increased renewable fuel obligations 
of RFS2.
    EPA also sought comment on an additional alternative in which EPA 
would require renewable fuel producers to set up and administer a 
company-wide quality assurance program that would create an additional 
level of rigor in the implementation scheme for the EISA land 
restrictions on renewable biomass. EPA is not finalizing this company-
wide quality assurance program approach, but rather, is encouraging the 
option for an industry-wide quality assurance program, as described in 
the following section, to be administered.
i. Recordkeeping and Reporting for Feedstocks
    After considering the comments we received on the proposed 
approach, EPA is finalizing reporting and recordkeeping requirements 
comparable to those in the approach we discussed in the proposed rule 
for all categories of renewable biomass, with the exception of planted 
crops and crop residue from agricultural land in the United States, 
which will be covered by the aggregate compliance approach discussed 
below in Section II.B.4.c.iii. EPA believes that these requirements on 
the fuel producer utilizing feedstocks other than crops and crop 
residue are necessary to ensure that the definition of renewable 
biomass is being met, and to allow feedstocks to be traced from their 
original producer to the renewable fuel production facility. 
Furthermore, we believe that, in most cases, feedstock producers will 
already have or will be able to easily generate the specified 
documentation for renewable fuel producers necessary to provide them 
with adequate assurance that the feedstock in question meets the 
definition of renewable biomass.
    Under today's rule, all renewable fuel producers must maintain 
written records from their feedstock suppliers for each feedstock 
purchase that identify the type and amount of feedstocks and where the 
feedstock was produced and that are sufficient to verify that the 
feedstock qualifies as renewable biomass. Specifically, renewable fuel 
producers must maintain maps and/or electronic data identifying the 
boundaries of the land where the feedstock was produced, product 
transfer documents (PTDs) or bills of lading tracing the feedstock from 
that land to the renewable fuel production facility, and other written 
records that serve as evidence that the feedstock qualifies as 
renewable biomass. We believe the maps or electronic data can be easily 
generated using existing Web-based information.
    Producers using planted trees and tree residue from tree 
plantations must maintain additional documentation that serves as 
evidence that the tree plantation was cleared prior to December 19, 
2007, and actively managed as a tree plantation on December 19, 2007. 
This documentation must consist of the following types of records which 
must be traceable to the land in question: Sales records for planted 
trees or slash; purchasing records for fertilizer, weed control, or 
reseeding, including seeds, seedlings, or other nursery stock together 
with other written documentation connecting the land in question to 
these purchases; 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 a silvicultural product certification 
program; an agreement for land management consultation with a 
professional forester that identifies the land in question; or evidence 
of the existence and ongoing maintenance of a road system or other 
physical infrastructure designed and maintained for logging use. There 
are many existing programs, such as those administered by USDA and 
independent third-party certifiers, that could be used as documentation 
that verifies that feedstock from certain land qualifies as renewable 
biomass. For example, many tree plantation owners already participate 
in a third-party certification program such as FSC or SFI. Written 
proof of participation by a tract of land in a program of this type on 
December 19, 2007 would be sufficient to show that a tree plantation 
was cleared prior to that date and that it was actively managed on that 
date. The tree plantation owner would need to send copies of this 
documentation to the renewable fuel producer when supplying them with 
biomass that will be used as a renewable fuel feedstock.
    We anticipate that the recordkeeping requirements will result in 
renewable fuel producers amending their contracts and modifying their 
supply chain interactions to satisfy the requirement that producers 
have documented assurance and proof about their feedstock's origins. 
Enforcement will rely in part on EPA's review of renewable fuel 
production reports and attest engagements of renewable fuel producers' 
records. EPA will also consult other data sources, including any data 
made available by USDA, and may conduct site visits or inspections of 
feedstock producers' and suppliers' facilities.
    The reporting requirements for renewable biomass in today's final 
rule include, as proposed, include an affirmation by the renewable fuel 
producer for each batch of renewable fuel for which they generate RINs 
that the feedstocks used to produce the batch meet the definition of 
renewable biomass. Additionally, the final reporting requirements 
include a quarterly report to be sent to EPA by each renewable fuel 
producer that includes a summary of the types and volumes of feedstocks 
used throughout the quarter, as well as electronic data or maps 
identifying the land from which those feedstocks were harvested.

[[Page 14700]]

Producers need not provide duplicate maps if purchasing feedstocks 
multiple times from one plot of land; producers may cross-reference the 
previously submitted map. Producers will also be required to keep 
records tracing the feedstocks from the land to the renewable fuel 
production facility, other written records from their feedstock 
suppliers that serve as evidence that the feedstock qualifies as 
renewable biomass, and for producers using planted trees or tree 
residue from tree plantations, written records that serve as evidence 
that the land from which the feedstocks were obtained was cleared prior 
to December 19, 2007 and actively managed on that date. These 
requirements will apply to renewable fuel producers using feedstocks 
from foreign sources (unless special approvals are granted in the 
future, as described below), or from domestic sources, except for 
planted crops or crop residue (discussed below).
    This approach will be integrated into the existing registration, 
recordkeeping, reporting, and attest engagement procedures for 
renewable fuel producers. It places the burden of implementation and 
enforcement on renewable fuel producers rather than bringing feedstock 
producers and suppliers directly under EPA regulation, minimizing the 
number of regulated parties under RFS2.
    EPA also sought comment on, and is finalizing as an option, an 
alternative approach in which EPA allows renewable fuel producers and 
renewable fuel feedstock producers and suppliers to develop a quality 
assurance program for the renewable fuel production supply chain, 
similar to the model of the successful Reformulated Gasoline Survey 
Association. While individual renewable fuel producers may still choose 
to comply with the individual renewable biomass recordkeeping and 
reporting requirements rather than participate in a quality assurance 
program, we believe that this preferred alternative could be less 
costly than an individual compliance demonstration, and it would add a 
quality assurance element to RFS2. Those participating renewable fuel 
producers would be presumed to be in compliance with the renewable 
biomass requirements unless and until the quality assurance program 
finds evidence to the contrary. Under today's rule, renewable fuel 
producers must choose either to comply with the individual renewable 
biomass recordkeeping and reporting described above, or they must 
participate in the quality assurance program.
    The quality assurance program must be carried out by an independent 
auditor funded by renewable fuel producers and feedstock suppliers. The 
program must consist of a verification program for participating 
renewable fuel producers and renewable feedstock producers and handlers 
designed to provide independent oversight of the feedstock handling 
processes that are required to determine if a feedstock meets the 
definition of renewable biomass. Under this option, a participating 
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 auditor conduct a program of 
compliance surveys. The compliance audit must be carried out by an 
independent auditor pursuant to a detailed survey plan submitted to EPA 
for approval by November 1 of the year preceding the year in which the 
alternative compliance program would be implemented. The compliance 
survey program plan must include a statistically supportable 
methodology for the survey, the locations of the surveys, the frequency 
of audits 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 individual recordkeeping and reporting requirements included in 
the RFS2 regulations.
    Under this alternative compliance program, the independent auditor 
would be required to visit participating renewable feedstock producers 
and suppliers to determine if the biomass they supply to renewable fuel 
producers meets the definition of renewable biomass. This program would 
be designed to ensure representative coverage of participating 
renewable feedstock producers and suppliers. The auditor 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 
renewable fuel producers would be responsible for identifying and 
addressing the root cause of the problem. The renewable fuel producers 
would have to take corrective action to retire the appropriate number 
of invalid RINs depending on the violation. EPA received comments from 
a number of parties who were supportive of this option as an 
alternative and less-burdensome way of ensuring that renewable fuel 
feedstocks meet the definition of renewable biomass. EPA believes this 
option to be an efficient and effective means of implementing and 
enforcing the renewable biomass requirements of EISA, and has therefore 
included it as a compliance option in today's final rule.
ii. Approaches for Foreign Producers of Renewable Fuel
    The EISA renewable biomass language does not distinguish between 
domestic renewable fuel and fuel feedstocks and renewable fuel and fuel 
and feedstocks that come from abroad. EPA proposed that foreign 
producers of renewable fuel that is exported to the U.S. be required to 
meet the same compliance obligations as domestic renewable fuel 
producers, as well as some additional measure, discussed in Section 
II.C., designed to facilitate EPA enforcement in other countries. These 
proposed obligations include facility registration and submittal of 
independent engineering reviews (described in Section II.C below), and 
reporting, recordkeeping, and attest engagement requirements. The 
proposal also would have included for foreign producers the same 
obligations that domestic producers have for verifying that their 
feedstock meets the definition of renewable biomass, 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 suppliers to ensure that they receive and maintain 
accurate and sufficient documentation in their records to support their 
claims.
(1) RIN-Generating Importers
    EPA proposed to allow importers to generate RINs for renewable fuel 
they are importing into the U.S. only if the foreign producer of that 
renewable fuel had not already done so. Under the proposal, in order to 
generate RINs, importers would need to obtain information from the 
registered foreign producers concerning the point of origin of their 
fuel's feedstock and whether it meets the definition of renewable 
biomass. Therefore, we proposed that in the event that a batch of 
foreign-produced renewable fuel does not have RINs accompanying it when 
it arrives at a U.S. port, an importer must obtain documentation that 
proves that the fuel's feedstock meets the definition of renewable 
biomass (as described in Section II.B.4.a. of this preamble) from the 
fuel's producer, who must have registered with the RFS program and 
conducted a third-party engineering review. With such documentation, 
the importer could generate RINs prior to introducing the fuel into 
commerce in the U.S.
    We sought comment on this proposed approach and whether and to what 
extent the approaches for ensuring

[[Page 14701]]

compliance with the EISA's land restrictions by foreign renewable fuel 
producers should differ from the proposed approach for domestic 
renewable fuel producers. We received comments on the proposed 
implementation option for importers of foreign renewable fuel. Some 
argue that the proposed recordkeeping requirements for imported fuel 
were overly burdensome. On the other hand, others argued that 
importers, similarly to domestic producers, should be required to 
obtain information that can serve as evidence that the feedstocks meet 
the definition of renewable biomass, in order to avoid fraud. Some 
commenters also argued that importers should be able to generate RINs 
for fuel imported from foreign producers that are not registered with 
EPA under the RFS2 program.
    For the final rule, EPA is requiring that importers may only 
generate RINs for renewable fuel if the foreign producer has not 
already done so. The foreign producers must be registered with EPA 
under the RFS2 program, and must have conducted an independent 
engineering review. Furthermore, we are requiring that importers obtain 
from the foreign producer and maintain in their records written 
documentation that serves as evidence that the renewable fuel for which 
they are generating RINs was made from feedstocks meeting the 
definition of renewable biomass. The foreign producer that originally 
generated the fuel must ensure that these feedstock records are 
transferred with each batch of fuel and ultimately reach the RIN-
generating importer. A requirement that importers maintain these 
renewable biomass records is consistent with the renewable biomass 
recordkeeping requirements imposed on domestic producers of renewable 
fuel.
(2) RIN-Generating Foreign Producers
    Foreign producers that intend to generate RINs would be required to 
designate renewable fuel intended for export to the U.S. as such, 
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, as 
discussed in Section II.D.2.b. Similarly to domestic producers of 
renewable fuel, foreign producers must obtain and maintain written 
documentation from their feedstock providers that can serve as evidence 
that their feedstocks meet the definition of renewable biomass. Foreign 
producers may also develop a quality assurance program for their 
renewable fuel production supply chain, as described above. However, 
while domestic renewable fuel producers using crops or crop residues 
may rely on the aggregate compliance approach described below to ensure 
that their feedstocks are renewable biomass, this approach is not 
available at this time to foreign renewable fuel producers, as 
described below.
    EPA believes that the renewable biomass recordkeeping provisions 
are necessary in order for EPA to ensure that RINs are being generated 
for fuel that meets EISA's definition of renewable fuel. Just as for 
domestic producers, foreign producers must maintain evidence that the 
fuel meets the GHG reduction requirements and is made from renewable 
biomass.
iii. Aggregate Compliance Approach for Planted Crops and Crop Residue 
From Agricultural Land
    In light of the comments received on the proposed renewable biomass 
recordkeeping requirements and implementation options, EPA sought 
assistance from USDA in determining whether existing data and data 
sources might suggest an alternative method for verifying compliance 
with renewable biomass requirements associated with the use of crops 
and crop residue for renewable fuel production. Taking into 
consideration publicly available data on agricultural land available 
from USDA and USGS as well as expected economic incentives for 
feedstock producers, EPA has determined that an aggregate compliance 
approach is appropriate for certain types of renewable biomass, namely 
planted crops and crop residue from the United States.
    Under the aggregate compliance approach, EPA is determining for 
this rule the total amount of ``existing agricultural land'' in the 
U.S. (as defined above in Section II.B.4.a.) at the enactment date of 
EISA, which is 402 million acres. EPA will monitor total agricultural 
land annually to determine if national agricultural land acreage 
increases above this 2007 national aggregate baseline. Feedstocks 
derived from planted crops and crop residues will be considered to be 
consistent with the definition of renewable biomass and renewable fuel 
producers using these feedstocks will not be required to maintain 
specific renewable biomass records as described below unless and until 
EPA determines that the 2007 national aggregate baseline is exceeded. 
If EPA finds that the national aggregate baseline is exceeded, 
individual recordkeeping and reporting requirements as described below 
will be triggered for renewable fuel producers using crops and crop 
residue. We believe that the aggregate approach will fully ensure that 
the EISA renewable biomass provisions related to crops and crop residue 
are satisfied, while also easing the burden for certain renewable fuel 
producers and their feedstock suppliers vis-[agrave]-vis verification 
that their feedstock qualifies as renewable biomass.
    As discussed in more detail below, there are five main factors 
supporting the aggregate compliance approach we are taking for planted 
crops and crop residue. First, EPA is using data sets that allow us to 
obtain an appropriately representative estimate of the agricultural 
lands available under EISA for the production of crops and crop residue 
as feedstock for renewable fuel production. Second, USDA data indicate 
an overall trend of agricultural land contraction. These data, together 
with EPA economic modeling, suggest that 2007 aggregate baseline 
acreage should be sufficient to support EISA renewable fuel obligations 
and other foreseeable demands for crop products, at least in the near 
term, without clearing and cultivating additional land. Third, EPA 
believes that existing economic factors for feedstock producers favor 
more efficient utilization practices of existing agricultural land 
rather than converting non-agricultural lands to crop production. 
Fourth, if, at any point, EPA finds that the total amount of land in 
use for the production of crops including crops for grazing and forage 
is equal or greater than 397 million acres (i.e. within 5 million acres 
of EPA's established 402 million acre baseline), EPA will conduct 
further investigations to evaluate whether the presumption built into 
the aggregate compliance approach remains valid. Lastly, EPA has set up 
a trigger mechanism that in the event there are more than the baseline 
amount of acres of cropland, pastureland and CRP land in production, 
renewable fuel producers will be required to meet the same individual 
or consortium-based recordkeeping and reporting requirements applicable 
to RIN-generating renewable fuel producers using other feedstocks. 
Taken together, these factors give EPA high confidence that the 
aggregate compliance approach for domestically grown crops and crop 
residues meets the statutory obligation to ensure feedstock volumes 
used to meet the renewable fuel requirements also comply with the 
definition of renewable biomass.
(1) Analysis of Total Agricultural Land in 2007
    As described in Section II.B.4.a. above, EPA is defining ``existing 
agricultural land'' for purposes of the

[[Page 14702]]

EISA land use restrictions on crops and crop residue to include 
cropland, pastureland and CRP land that was cleared and actively 
managed or fallow and nonforested on the date of EISA enactment. To 
determine the aggregate total acreage of existing agricultural land for 
the aggregate compliance approach on the date of EISA enactment, EPA 
obtained from USDA data representing total cropland (including fallow 
cropland), pastureland, and CRP land in 2007 from three independently 
gathered national land use data sources (discussed in further detail 
below): The Farm Service Agency (FSA) Crop History Data, the USDA 
Census of Agriculture (2007), and the satellite-based USDA Crop Data 
Layer (CDL). In addition, CRP acreage is provided by FSA's annually 
published ``Conservation Reserve Program: Summary and Enrollment 
Statistics.'' By definition, the cropland, pastureland, and CRP land 
included in these data sources for 2007 were cleared or cultivated on 
the date of EISA enactment (December 19, 2007) and, consistent with the 
principles set forth in Section II.4.a.i, would be considered 
``actively managed'' or fallow and nonforested on that date. These 
categories of lands include those from which traditional crops, such as 
corn, soy, wheat and sorghum, would likely be grown. Therefore 
quantification of cropland, pastureland, and CRP land from these data 
sources represents a reasonable assessment of the acreage in the United 
States that is available under the Act for the production of crops and 
crop residues that could satisfy the definition of renewable biomass in 
EISA.
    Conservation Reserve Program Data. FSA reports CRP enrollment 
acreage each year in the publication ``Conservation Reserve Program: 
Summary and Enrollment Statistics.'' The CRP program includes the 
general CRP, the Conservation Reserve Enhancement Program (CREP), and 
the Farmable Wetlands Program (FWP). The Wetlands Reserve Program (WRP) 
and Grasslands Reserve Program (GRP) are not under CRP and are not 
included in the total agricultural land figure in this rulemaking. The 
2007 CRP acreage was 36.7 million acres. This is an exact count of 
acreage within the CRP program in 2007.
    Farm Service Agency Crop History Data. The FSA maintains annual 
records of field-level land use data for all farms enrolled in FSA 
programs. Almost all national cropland and pastureland is reported 
through FSA and recorded in this data set. We used the ``Cropland'' 
category to determine total agricultural land. Pastureland is reported 
by farms under the category ``Cropland'' as cropland used for grazing 
and forage under the crop type ``mixed forage.'' Timber land and any 
grazed native grass was removed from the ``Cropland'' category, because 
these land types represent either forestland or rangeland, which are 
not within the definition of existing agricultural land. CRP lands and 
other conservation program lands are also reported as cropland. Because 
GRP and WRP lands are not within the definition of ``existing 
agricultural land'' as defined in today's regulations, they were also 
subtracted from the ``Cropland'' category total. FSA Crop History Data 
show that there was 402 million acres of agricultural land, as defined 
here, in the U.S. in 2007 (See Table II.B.4-1).

   Table II.B.4-1--Total U.S. Agricultural Land in 2007 From USDA Data
                                 Sources
------------------------------------------------------------------------
                                             FSA crop      Agricultural
              Land category                history data     census data
------------------------------------------------------------------------
Cropland and Pastureland................             365             367
CRP Land................................              37              37
                                         -------------------------------
    Total Land..........................             402             404
------------------------------------------------------------------------

    USDA Census of Agriculture. USDA conducts a full census of the U.S. 
agricultural sector once every five years. The data are available for 
the U.S., each of the 50 States, and for each county. The most recent 
census available is the 2007 Census of Agriculture. For the purpose of 
this rulemaking, USDA provided EPA total acreage and 95% confidence 
intervals for the Census category ``Total Cropland,'' which includes 
the sub-categories ``Harvested cropland,'' ``Cropland used only for 
pasture and grazing,'' and ``Other cropland.'' WRP and GRP acreage are 
included in ``Other cropland,'' so, for purposes of this rulemaking, 
they were subtracted from the sub-category number (see above). The 
analysis excluded the ``Permanent rangeland and pasture'' category, as 
the pasture data cannot be separated from rangeland in this category. 
Total CRP acreage in 2007 was added to ``Total cropland.'' With these 
adjustments, the Census of Agriculture showed 404 million acres (95% 
confidence range 401-406 million acres) of existing agricultural land 
as defined in today's rule, in the U.S. in 2007 (See Table II.B.4-1).
    Crop Data Layer. The USDA National Agricultural Statistics Service 
(NASS) Crop Data Layer (CDL) is a raster, geo-referenced, crop-specific 
land cover data layer suitable for use in geographic information 
systems (GIS) analysis. Based on satellite data, the CDL has a ground 
resolution of 56 meters and was verified using FSA surveys. The CDL 
covers 21 major agricultural states for 2007 and therefore cannot be 
used to determine a 2007 national aggregate agricultural land baseline. 
There will be full coverage of the 48 contiguous states for 2009, and 
the CDL can be used for analysis validation purposes during monitoring. 
From 2010 onward, it coverage of the 48 contiguous states will be 
dependent on available funding. GIS analyses of the CDL will include 
all cropland and pastureland data for each state. To ensure that non-
pasture grasslands are not included in the final sum, all areas of the 
``Grassland herbaceous'' category from the U.S. Geological National 
Land Cover Data layer (NLCD) that overlap the CDL layers are removed 
from the total agricultural land number. Producer and user accuracies 
\8\ are available for the CDL crop categories.
---------------------------------------------------------------------------

    \8\ ``Producer Accuracy'' indicates the probability that a 
groundtruth pixel will be correctly mapped and measures errors of 
omission; ``User Accuracy'' indicates the probability that a pixel 
from the classification actually matches the groundtruth data and 
measures errors of omission.
---------------------------------------------------------------------------

    Primary Data Source Selection for Aggregate Compliance Approach. 
EPA has determined that the FSA Crop History Data will be used as the 
data set on which the total existing agricultural land baseline will be 
based for the aggregate compliance approach. The FSA Crop History Data 
is the only complete data set for 2007 that is collected annually, 
enabling EPA to monitor agricultural land expansion or

[[Page 14703]]

contraction from year to year using a consistent data set. The total 
existing agricultural land value derived from FSA Crop History Data 
rests within the 95% confidence interval of the 2007 Census of 
Agriculture and is only 2 million acres less than the Census of 
Agriculture point estimate. The Census of Agriculture provides slightly 
fuller coverage than the FSA Crop History Data due to the nature of the 
data collection; however, given that both data collection systems have 
consistent and long-standing methodologies, the disparity between the 
two should remain approximately constant. Therefore, the FSA Crop 
History Data will provide a consistent data set for analyzing any 
expansion or contraction of total national agricultural land in the 
U.S.
    During its annual monitoring, EPA will use the FSA Crop History 
Data and the CDL analyses as a secondary source to validate our annual 
assessment. In years when the Census of Agriculture is updated, this 
data will also be used to validate our annual assessment. Other data 
sources, such as the annual NASS Farms, Land in Farms and Livestock 
Operations may also be useful as secondary data checks. Lastly, EPA 
intends to consider, as appropriate, other data sources for the annual 
monitoring analysis of total agricultural land as new technologies and 
data sources come online that would improve the accuracy and robustness 
of annual monitoring.
(2) Aggregate Agricultural Land Trends Over Time
    The Census of Agriculture (conducted every five years) shows that 
U.S. agricultural land has decreased by 44 million acres from 1997 to 
2007, indicating an overall decade trend of contraction of agricultural 
land utilization despite some year-to-year variations that can be seen 
by reference to the annual FSA Crop History records (See Table II.B.4-2 
and Table II.B.4-3). EPA's FASOM modeling results, which model full 
EISA volumes in 2022, support this contraction trend, indicating that 
total cropland, pastureland, and CRP land in the U.S. in 2022, under a 
scenario of full renewable fuel volume as required by EISA, would be 
less than the 2007 national acreage reported in the FSA Crop History 
Data (See preamble Section VII and RIA Chapter 5).

Table II.B.4-2--Total Agricultural Land (as Defined in Section II.B.4.a)
           Counted in the Census of Agriculture From 1997-2007
------------------------------------------------------------------------
                                                 Total agricultural land
                  Census year                      (millions of acres)
------------------------------------------------------------------------
2007...........................................                      404
2002 *.........................................                      431
1997 *.........................................                      445
------------------------------------------------------------------------
\*\ 2002 data do not include farms with land in FWP or CREP.


Table II.B.4-3--Total Agricultural Land (as Defined in Section II.B.4.a)
            Recorded in FSA Crop History Data From 2005-2007
------------------------------------------------------------------------
                                                 Total agricultural land
                      Year                         (millions of acres)
------------------------------------------------------------------------
2007...........................................                      402
2006...........................................                      393
2005...........................................                      392
------------------------------------------------------------------------

(3) Aggregate Compliance Determination
    The foundation of the aggregate compliance approach is 
establishment of a baseline amount of eligible agricultural land that 
was cleared or cultivated and actively managed or fallow and non-
forested on December 19, 2007. Based on USDA-FSA Crop History Data, EPA 
is establishing a baseline of 402 million acres of U.S. agricultural 
land, as defined in Section II.B.4.a and based upon the methods 
described in Section II.B.4.c.iii.(1), that is eligible for production 
of planted crops and crop residue meeting the EISA definition of 
renewable biomass. EPA will monitor total U.S. agricultural land 
annually, using FSA Crop History Data as a primary determinant, but 
using other data sources for support (See Section II.4.c.iii.(1)). If, 
at any point, EPA finds that the total land in use for the production 
of crops, including crops for grazing and forage, is greater than 397 
million acres (i.e. within 5 million acres of EPA's established 402 
million acre baseline), EPA will conduct further investigations to 
evaluate whether the presumption built into the aggregate compliance 
approach remains valid. Additionally, if EPA determines that the data 
indicates that this 2007 baseline level of eligible agricultural land 
has been exceeded, EPA will publish in the Federal Register a finding 
to that effect, and additional requirements will be triggered for 
renewable fuel producers to verify that they are using planted crops 
and crop residue from ``existing agricultural land'' as defined in 
today's rule as their renewable fuel feedstock. EPA's findings will be 
published by November 30, at the latest. If in November the 402 million 
acres baseline is found to be exceeded, then on July 1 of the following 
year, renewable fuel producers using feedstocks qualifying for this 
aggregate compliance approach, namely planted crops and crop residue 
from the United States, will be required to comply with the 
recordkeeping and reporting requirements applicable to producers using 
other types of renewable biomass, as described in the previous 
sections. This includes the option that fuel producers could utilize a 
third-party consortium to demonstrate compliance.
    EPA acknowledges that it is possible that under this approach some 
of the land available under EISA for crop production on the date of 
EISA enactment could be retired and other land brought into production, 
without altering the assessment of the aggregate amount of cropland, 
pastureland and CRP land. Under EISA, crops or crop residues from the 
new lands would not qualify as renewable biomass. However, EPA expects 
such shifts in acreage to be de minimus, as long as the total aggregate 
amount of agricultural land does not exceed the 2007 national aggregate 
baseline. EPA expects that new lands are unlikely to be cleared for 
agricultural purposes for two reasons. First, it can be assumed that 
most undeveloped land that was not used as agricultural land in 2007 is 
generally not suitable for agricultural purposes and would serve only 
marginally well for production of renewable fuel feedstocks. Due to the 
high costs and significant inputs that would be required to make the 
non-agricultural land suitable for agricultural purposes, it is highly 
unlikely that farmers will undertake the effort to ``shift'' land that 
is currently non-agricultural into agricultural use. Second, crop 
yields are projected to increase, reducing the need for farmers to 
clear new land for agricultural purposes. We believe that this effect 
is reflected in the overall trend, discussed earlier, of an overall 
contraction in agricultural land acreage over time.
    If EPA determines that the baseline is exceeded, and that 
individual compliance with the renewable biomass reporting and 
recordkeeping requirements is triggered, renewable fuel producers using 
crops and crop residue as a feedstock for renewable fuel would become 
responsible, beginning July 1 of the following year, for meeting 
individual recordkeeping and reporting requirements related to 
renewable biomass verification. These requirements are identical to 
those that

[[Page 14704]]

apply to producers using other types of renewable biomass feedstocks, 
such as planted trees from tree plantations, as described in the 
previous sections. Renewable fuel producers generating RINs under the 
RFS2 program would continue to be required to affirm (through EMTS--EPA 
Moderated Transaction System) for each batch of renewable fuel that 
their feedstocks meet the definition of renewable biomass. 
Additionally, producers would send a quarterly report to EPA that 
includes a summary of the types and volumes of feedstocks used 
throughout the quarter, as well as electronic data or maps identifying 
the land from which those feedstocks were harvested.
    Furthermore, those RIN-generating renewable fuel producers will be 
required to obtain and maintain in their files written records from 
their feedstock suppliers for each feedstock purchase that identify 
where the feedstocks were produced and that are sufficient to verify 
that the feedstocks qualify as renewable biomass. This includes maps 
and/or electronic data identifying the boundaries of the land where the 
feedstock was produced, PTDs or bills of lading tracing the feedstock 
from that land to the renewable fuel production facility, and other 
written records that serve as evidence that the feedstock qualifies as 
renewable biomass. Finally, producers using planted crops and crop 
residue must maintain additional documentation that serves as evidence 
that the agricultural land used to produce the crop or crop residue was 
cleared or cultivated and actively managed or fallow, and nonforested 
on December 19, 2007. This documentation must consist of the following 
types of records which must be traced to the land in question: sales 
records for planted crops, crop residue, or livestock, purchasing 
records for land treatments such as fertilizer, weed control, or 
reseeding or a written agricultural management plan or documentation of 
participation in an agricultural program sponsored by a Federal, State 
or local government agency.
    Alternatively, if the baseline is exceeded and the requirements are 
triggered for individual producer verification that their feedstocks 
are renewable biomass renewable fuel producers may choose to work with 
other renewable fuel producers as well as feedstock producers and 
suppliers to develop a quality assurance program for the renewable fuel 
production supply chain. This quality assurance program would take the 
place of individual accounting and would consist of an independent 
third party quality-assurance survey of all participating renewable 
fuel producers and their feedstock suppliers, completed in accordance 
with an industry-developed, EPA-approved plan, to ensure that they are 
utilizing feedstocks that meet the definition of renewable biomass. An 
in-depth discussion of this industry survey option is included in the 
previous section.
    While the aggregate compliance approach is appropriate for planted 
crops and crop residues from agricultural land in the United States, 
due in part to certain additional or different constraints imposed by 
EISA, the aggregate approach cannot be applied, at this time, to the 
other types of renewable biomass. Renewable fuel producers utilizing 
these types of renewable biomass, including planted trees and tree 
residues from tree plantations, slash and pre-commercial thinnings from 
non-federal forestland, animal waste, separated yard and food waste, 
etc., will be subject to the individual reporting and recordkeeping 
requirements discussed in the previous section.
    Additionally, EPA is not finalizing the aggregate compliance 
approach for foreign producers of renewable fuel. EPA does not, at this 
time, have sufficient data to make a finding that non-domestically 
grown crops and crop residues used in renewable fuel production satisfy 
the definition of renewable biomass. Nevertheless, if, in the future, 
adequate land use data becomes available to make a finding that, in the 
aggregate, crops and crop residues used in renewable fuel production in 
a particular country satisfy the definition of renewable biomass, EPA 
is willing to consider an aggregate compliance approach for renewable 
biomass on a country by country basis, in lieu of the individual 
recordkeeping and reporting requirements.
d. Treatment of Municipal Solid Waste (MSW)
    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.''
    We solicited 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. On the other hand, we noted that EISA does not 
define the term ``separated,'' and so does not specify the degree of 
separation required. We also noted that there was some evidence in the 
Act that Congress did not intend to exclude MSW entirely from the 
definition of renewable biomass. The definition of ``advanced biofuel'' 
includes a list of fuels that are ``eligible for consideration'' as 
advanced biofuel, including ``ethanol derived from waste material'' and 
biogas ``including landfill gas.''
    As an initial matter, we note that some materials clearly fall 
within the definition of ``separated yard or food waste.'' The statute 
itself identifies ``recycled cooking and trap grease'' as one example 
of separated food waste. An example of separated yard waste is the leaf 
waste that many municipalities pick up at curbside and keep separate 
from other components of MSW for mulching or other uses. However, a 
large quantity of food and yard waste is disposed of together with 
other household waste as part of MSW. EPA estimates that about 120 
million tons of MSW are disposed of annually much of it inextricably 
mixed with yard and especially food waste. This material offers a 
potentially reliable, abundant and inexpensive source of feedstock for 
renewable fuel production which, if used, could reduce the volume of 
discarded materials sent to landfills and could help achieve both the 
GHG emissions reductions and energy independence goals of EISA. Thus, 
EPA believes we should consider under what conditions yard and food 
waste that is present in MSW can be deemed sufficiently separated from 
other materials to qualify as renewable biomass.
    One commenter stated that it is clear that MSW does not qualify as 
renewable biomass under EISA, since the 2005 Energy Policy Act 
explicitly allowed for qualifying renewable fuel to be made from MSW, 
and EISA has no mention of it. Commenters from the renewable fuel 
industry generally favored maximum flexibility for the use of MSW in 
producing qualifying fuels under EISA, offering a variety of arguments 
based on the statutory text and reasons why it would benefit the 
environment and the nation's energy policy to do so. They favored 
either (1) a determination that unsorted MSW can be used as a feedstock 
for advanced biofuel even if it does not meet the definition of

[[Page 14705]]

renewable biomass, (2) that the Act be interpreted to include MSW as 
renewable biomass, or (3) that MSW from which varying amounts of 
recyclable materials have been removed could qualify as renewable 
biomass. A consortium of ten environmental groups said that for EISA 
volume mandates to be met, it is important to take advantage of biomass 
resources from urban wastes that would otherwise be landfilled. They 
urged that post-recycling residues (i.e., those wastes that are left 
over at material recovery facilities after separation and recycling) 
would fit within the letter and spirit of the definition of renewable 
biomass.
    EPA does not believe that the statute can be reasonably interpreted 
to allow advanced biofuel to be made from material that does not meet 
the definition of renewable biomass as suggested in the first approach. 
The definition of advanced biofuel specifies that it is a form of 
``renewable fuel,'' and renewable fuel is defined in the statute as 
fuel that is made from renewable biomass. While the definition of 
advanced biofuel includes a list of materials that ``may'' be 
``eligible for consideration'' as advanced biofuel, and that list 
includes ``ethanol derived from waste materials'' and biogas 
``including landfill gas,'' the fact that the specified items are 
``eligible for consideration'' indicates that they do not necessarily 
qualify but must meet the definitional requirements--being ``renewable 
fuel'' made from renewable biomass and having life cycle greenhouse gas 
emissions that are at least 50% less than baseline fuel. There is 
nothing in the statute to suggest that Congress used the term 
``renewable fuel'' in the definition of ``advanced biofuel'' to have a 
different meaning than the definition provided in the statute. The 
result of the commenter's first approach would be that general 
renewable fuel and cellulosic biofuel would be required to be made from 
renewable biomass because the definitions of those terms specifically 
refer to renewable biomass, whereas advanced biofuel and biomass-based 
diesel would not, because their definitions refer to ``renewable fuel'' 
rather than ``renewable biomass.'' EPA can discern no basis for such a 
distinction. EPA believes that the Act as a whole is best interpreted 
as requiring all types of qualifying renewable fuels under EISA to be 
made from renewable biomass. In this manner the land and feedstock 
restrictions that Congress deemed important in the context of biofuel 
production apply to all types of renewable fuels.
    EPA also does not agree with the commenter who suggested that the 
listing in the definition of renewable biomass of ``biomass obtained 
from the immediate vicinity of buildings and other areas regularly 
occupied by people, or of public infrastructure, at risk from 
wildfire'' should be interpreted to include MSW. It is clear that the 
term ``at risk of wildfire'' modifies the entire sentence, and the 
purpose of the listing is to make the biomass that is removed in 
wildfire minimization efforts, such as brush and dead woody material, 
available for renewable fuel production. Such material does not 
typically include MSW. Had Congress intended to include MSW in the 
definition of renewable biomass, EPA believes it would have clearly 
done so, in a manner similar to the approach taken in EPAct.
    EPA also does not believe that it would be reasonable to interpret 
the reference to ``separated yard or food waste'' to include unsorted 
MSW. Although MSW contains yard and food waste, such an approach would 
not give meaning to the word ``separated.''
    We do believe, however, that yard and food wastes that are part of 
MSW, and are separated from it, should qualify as renewable biomass. 
MSW is the logical source from which yard waste and food waste can be 
separated. As to the degree of separation required, some commenters 
suggested a simple ``post recycling'' test be appropriate. They would 
leave to municipalities and waste handlers a determination of how much 
waste should be recycled before the residue was used as a feedstock for 
renewable fuel production. EPA believes that such an approach would not 
guarantee sufficient ``separation'' from MSW of materials that are not 
yard waste or food waste to give meaning to the statutory text. 
Instead, EPA believes it would be reasonable in the MSW context to 
interpret the word ``separated'' in the term ``separated yard or food 
waste'' to refer to the degree of separation to the extent that is 
reasonably practicable. A large amount of material can be, and is, 
removed from MSW and sold to companies that will recycle the material. 
EPA believes that the residues remaining after reasonably practicable 
efforts to remove recyclable materials other than food and yard waste 
(including paper, cardboard, plastic, textiles, metal and glass) from 
MSW should qualify as separated yard and food waste. This MSW-derived 
residue would likely include some amount of residual non-recyclable 
plastic and rubber of fossil fuel origin, much of it being wrapping and 
packaging material for food. Since this material cannot be practicably 
separated from the remaining food and yard waste, EPA believes it is 
incidental material that is impractical to remove and therefore 
appropriate to include in the category of separated food and yard 
waste. In sum, EPA believes that the biogenic portion of the residue 
remaining after paper, cardboard, plastic, textiles metal and glass 
have been removed for recycling should qualify as renewable biomass. 
This interpretation is consistent with the text of the statute, and 
will promote the productive use of materials that would otherwise be 
landfilled. It will also further the goals of EISA in promoting energy 
independence and the reduction of GHG emissions from transportation 
fuels.
    EPA notes there are a variety of recycling methods that can be 
used, including curbside recycling programs, as well as separation and 
sorting at a material recovery facility (MRF). For the latter, the 
sorting could be done by hand or by automated equipment, or by a 
combination of the two. Sorting by hand is very labor intensive and 
much slower than using an automated system. In most cases the ``by-
hand'' system produces a slightly cleaner stream, but the high cost of 
labor usually makes the automated system more cost-effective. 
Separation via MRFs is generally very efficient and can provide 
comparable if not better removal of recyclables to that achieved by 
curbside recycling.
    Based on this analysis, today's rule provides that those MSW-
derived residues that remain after reasonably practicable separation of 
recyclable materials other than food and yard waste is renewable 
biomass. What remains to be addressed is what regulatory mechanisms 
should be used to ensure the appropriate generation of RINs when 
separated yard and food waste is used as a feedstock. We are finalizing 
two methods.
    The first method would apply primarily to a small subset of 
producers who are able to obtain yard and/or food wastes that have been 
kept separate since waste generation from the MSW waste stream. 
Examples of such wastes are lawn and leaf waste that have never entered 
the general MSW waste stream. Typically, such wastes contain incidental 
amounts of materials such as the plastic twine used to bind twigs 
together, food wrappers, and other extraneous materials. As with our 
general approach to the presence of incidental, de minimus contaminants 
in feedstocks that are unintentionally present and impractical to 
remove, the presence of such material in separated yard or food waste 
will not disqualify such wastes as renewable biomass, and the 
contaminants may be disregarded by producers and importers generating

[[Page 14706]]

RINs. (See definition of renewable biomass and 80.1426(f)(1).) Waste 
streams kept separate since generation from MSW that consist of yard 
waste are expected to be composed almost entirely of woody material or 
leaves, and therefore will be deemed to be composed of cellulosic 
materials. Waste streams consisting of food wastes, however, may 
contain both cellulosic and non-cellulosic materials. For example, a 
food processing plant may generate both wastes that are primarily 
starches and sugars (such as carrot and potato peelings, as well as 
fruits and vegetables that are discarded) as well as corn cobs and 
other materials that are cellulosic. We will deem waste streams 
consisting of food waste to be composed entirely of non-cellulosic 
materials, and qualifying as advanced biofuels, unless the producer 
demonstrates that some portion of the food waste is cellulosic. The 
cellulosic portion would then qualify as cellulosic biofuel. The method 
for quantifying the cellulosic and non-cellulosic portions of the food 
waste stream is to be described in a written plan which must be 
submitted to EPA under the registration procedures in 80.1450(b)(vii) 
for approval and which indicates the location of the facility from 
which wastes are obtained, how identification and quantification of 
waste material is to be accomplished, and evidence that the wastes 
qualify as fully separated yard or food wastes. The producer must also 
maintain records regarding the source of the feedstock and the amounts 
obtained.
    The second method would involve use as feedstock by a renewable 
fuel producer of the portion of MSW remaining after reasonably 
practical separation activities to remove recyclable materials, 
resulting in a separated MSW-derived residue that qualifies as 
separated yard and food waste. Today's rule requires that parties that 
intend to use MSW-derived residue as a feedstock for RIN-generating 
renewable fuel production ensure that reasonably practical efforts are 
made to separate recyclable paper, cardboard, textiles, plastics, metal 
and glass from the MSW, according to a plan that is submitted by the 
renewable fuel producer and approved by EPA under the registration 
procedures in 80.1450(b)(viii). In determining whether the plan 
submittals provide for reasonably practicable separation of recyclables 
EPA will consider: (1) The extent and nature of recycling that may have 
occurred prior to receipt of the MSW material by the renewable fuel 
producer, (2) available recycling technology and practices, and (3) the 
technology or practices selected by the fuel producer, including an 
explanation for such selection and reasons why other technologies or 
practices were not selected. EPA asks that any CBI accompanying a plan 
or a party's justification for a plan be segregated from the non-CBI 
portions of the submissions, so as to facilitate disclosure of the non-
CBI portion of plan submittals, and approved plans, to interested 
members of the public.
    Producers using this second option, will need to determine what 
RINs to assign to a fuel that is derived from a variety of materials, 
including yard waste (largely cellulosic) and food waste (largely 
starches and sugar), as well as incidental materials remaining after 
reasonably practical separation efforts such as plastic and rubber of 
fossil origin. EPA has not yet evaluated the lifecycle greenhouse gas 
performance of fuel made from such mixed sources of waste, so is unable 
at this time to assign a D code for such fuel. However, if a producer 
uses ASTM test method D-6866 on the fuel made from MSW-derived 
feedstock, it can determine what portion of the rule is of fossil and 
non-fossil origin. The non-fossil portion of the fuel will likely be 
largely derived from cellulosic materials (yard waste, textiles, paper, 
and construction materials), and to a much smaller extent starch-based 
materials (food wastes). Unfortunately, EPA is not aware of a test 
method that is able to distinguish between cellulosic- and starch-
derived renewable fuel. Under these circumstances, EPA believes that it 
is appropriate for producers to base RIN assignment on the predominant 
component and, therefore, to assume that the biogenic portion of their 
fuel is entirely of cellulosic origin. The non-biogenic portion of the 
fuel, however, would not qualify for RINs at this time. Thus, in sum, 
we are providing via the ASTM testing method an opportunity for 
producers using an MSW-derived feedstock to generate RINs only for the 
biogenic portion of their renewable fuel. There is no D code for the 
remaining fossil-derived fraction of the fuel in today's rule nor for 
the entire volume of renewable fuel produced when using MSW-derived 
residue as a feedstock. The petition process for assigning such codes 
in today's rule can be used for such purpose.
    Procedures for the use of ASTM Method D-6866 are detailed in 40 CFR 
80.1426(f)(9) of today's rule. We solicited comment on this method, and 
while the context of the discussion of method D-6866 was with respect 
to using it for gasoline (see 74 FR 24951), the comments we received 
provided us information on the method itself. Also, commenters were 
supportive of its use. Fuel producers must either run the ASTM D-6866 
method for each batch of fuel produced, or run it on composite samples 
of the food and yard waste-derived fuel derived from post-recycling MSW 
residues. Producers will be required at a minimum to take samples of 
every batch of fuel produced over the course of one month and combine 
them into a single composite sample. The D-6866 test would then be 
applied to the composite sample, and the resulting non-fossil derived 
fraction will be deemed cellulosic biofuel, and applied to all batches 
of fuel produced in the next month to determine the appropriate number 
of RINs that must be generated. The producer would be required to 
recalculate this fraction at least monthly. For the first month, the 
producer can estimate the non-fossil fraction, and then make a 
correction as needed in the second month. (The procedure using the ASTM 
D-6866 method applies not only to the waste-derived fuel discussed here 
but also to all partially renewable transportation fuels, and is 
discussed in further detail in Section II.D.4. See also the regulations 
at Sec.  80.1426(f)(4)).
    The procedures for assigning D codes to the fuel produced from such 
wastes are discussed in further detail in Section II.D.5.
    One commenter suggested that biogas from landfills should be 
treated in the same manner as renewable fuel produced from MSW. EPA 
agrees with the commenter to a certain extent. The definition of 
``advanced biofuels'' in EISA identifies ``Biogas (including landfill 
gas and sewage waste treatment gas) produced through the conversion of 
organic matter from renewable biomass'' as ``eligible for 
consideration'' as an advanced biofuel. However, as with MSW, the 
statute requires that advanced biofuel be a ``renewable fuel'' and that 
such fuel be made from ``renewable biomass.'' The closest reference 
within the definition of renewable biomass to landfill material is 
``separated yard or food waste.'' However, in applying the 
interpretation of ``separated'' yard and food waste described above for 
MSW to landfill material, we come to a different result. Landfill 
material has by design been put out of practical human reach. It has 
been disposed of in locations, and in a manner, that is designed to be 
permanent. For example, modern landfills are placed over impermeable 
liners and sealed with a permanent cap. In addition, the food and yard 
waste present in a landfill has over time become intermingled with 
other

[[Page 14707]]

materials to an extraordinary extent. This occurs in the process of 
waste collection, shipment, and disposal, and subsequently through 
waste decay, leaching and movement within the landfill. Additionally, 
we note that the process of biogas formation in a landfill provides 
some element of separation, in that it is formed only from the biogenic 
components of landfill material, including but not strictly limited to 
food and yard waste. Thus, plastics, metal and glass are effectively 
``separated'' out through the process of biogas formation. As a result 
of the intermixing of wastes, the fact that biogas is formed only from 
the biogenic portion of landfill material, and the fact that landfill 
material is as a practical matter inaccessible for further separation, 
EPA believes that no further practical separation is possible for 
landfill material and biogas should be considered as produced from 
separated yard and food waste for purposes of EISA. Therefore, all 
biogas from landfills is eligible for RIN generation.
    We have considered whether to require biogas producers to use ASTM 
Method D-6866 to identify the biogenic versus non-biogenic fractions of 
the fuel. However, as noted above, biogas is not formed from non-
biogenic compounds in landfills. (Kaplan, et al., 2009) \9\ Thus, no 
purpose would be solved in using the ASTM method in the biogas context.
---------------------------------------------------------------------------

    \9\ Kaplan, et al. (2009). ``Is it Better to Burn or Bury Waste 
for Clean Electricity Generation?'' Environmental Science & 
Technology 2009 43(6), 1711-1717 (Found in Table S1 of supplemental 
material to the article, at http://pubs.acs.org/doi/suppl/10.1021/es802395e/suppl_file/es802395e_si_001.pdf).
---------------------------------------------------------------------------

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 revising the registration 
process for renewable fuel producers and importers. Under the 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 RFS1 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 and 3520-20B (Gasoline Programs Facility 
Registration) or 3520-20B1 (Diesel Programs Facility Registration), 
which require 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 was 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).
    Additionally, EPA recommends companies register their renewable 
fuels or fuel additives under title 40 CFR part 79 as a motor vehicle 
fuel. In fact, renewable fuels intended for use in motor vehicles will 
be required to be registered under title 40 CFR part 79 prior to any 
introduction into commerce. Manufacturers and subsequent parties of 
fuels and fuel additives not registered under part 79 will be liable 
for separate penalties under 40 CFR parts 79 and 80 in the event their 
unregistered product is introduced into commerce for use in a motor 
vehicle. Further if a registered fuel or fuel additive is used in 
manner that is not consistent with their product's registration under 
part 79 the manufacturer and subsequent parties will be liable for 
penalties under parts 79 and 80. 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 and the RINs generated for 
fuel produced from nonrenewable sources will be invalidated.
    Due to the revised definitions of renewable fuel under EISA, we 
proposed to expand the registration process for renewable fuel 
producers and importers in order to implement the new program 
effectively. We received a number of comments that opposed the expanded 
registration as commenters deemed it overly burdensome, costly and 
unnecessary. However, EPA is finalizing the proposed expanded 
registration requirements for the following reasons. The information to 
be collected through the expanded registration process is essential to 
generating and assigning a certain category of RIN to a volume of fuel. 
Additionally, the information collected is essential to determining 
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. Therefore, we are requiring producers, 
including foreign producers, and importers that generate RINs to 
provide us with information on their feedstocks, facilities, and 
products, in order to implement and enforce the program and have 
confidence that producers and importers are properly categorizing their 
fuel and generating RINs. The registration procedures will be 
integrated with the new EPA Moderated Transaction System, discussed in 
detail in Section III.A of this preamble.
1. Domestic Renewable Fuel Producers
    Information on products, feedstocks, and facilities contained in a 
producer's registration will 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. In 
addition, producers of renewable fuel from facilities that qualify for 
the exemption from the 20% GHG reduction threshold (as discussed in 
Section II.B.3) must provide information that demonstrates when the 
facility commenced construction, and that establishes the baseline 
volume of the fuel. For those facilities that would qualify as 
grandfathered but are not in operation we are allowing until May 1, 
2013 to submit and receive approval for a complete facility 
registration. This provision does not require actual fuel production, 
but simply the filing of registration materials that assert a claim for 
exempt status. It will benefit both fuel producers, who will likely be 
able to more readily collect the required information if it is done 
promptly, and EPA enforcement personnel seeking to verify the 
information. However, given the potentially significant implications of 
this requirement for facilities that may qualify for the exemption but 
miss the registration deadline, the rule also provides that EPA may 
waive the requirement if it determines that the submission is 
verifiable to the same extent as a timely-submitted registration.
    With respect to products, we are requiring that producers provide 
information on the types of renewable fuel and co-products that a 
facility is capable of producing. With respect to feedstocks, we are 
requiring producers to provide to EPA a list of all the different 
feedstocks that a renewable fuel producer's facility is likely to use 
to convert into renewable fuel. With respect to the producer's 
facilities, two types of information must be reported to the Agency. 
First, producers must describe 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

[[Page 14708]]

thus deemed to be in compliance with the 20% GHG threshold, we are 
requiring evidence and certification of the facility's qualification 
under the definition of ``commence construction'' as well as 
information necessary to establish its renewable fuel baseline volume 
per the requirement outlined in Section II.B.3 of this preamble.
    EPA proposed to require that renewable fuel producers have a third-
party engineering review of their facilities prior to generating RINs 
under RFS2, and every 3 years thereafter. EPA received comments that 
the on-site engineering review was overly burdensome, unnecessary and 
costly. A number of commenters noted that the time allotted for 
conducting the reviews, between the rule's publication and prior to RIN 
generation, is not adequate for producers to hire an engineer and 
conduct the review for all of their facilities. Several commenters 
requested that on-site licensed engineers be allowed to conduct any 
necessary facility reviews.
    EPA is finalizing the proposed requirement for an on-site 
engineering review of facilities producing renewable fuel due to the 
variability of production facilities, the increase in the number of 
categories of renewable fuels, and the importance of ensuring that RINs 
are generated in the correct category. Without these engineering 
reviews, we do not believe it would be possible to implement the RFS2 
program in a manner that ensured the requirements of EISA were being 
fulfilled. Additionally, the engineering review provides a check 
against fraudulent RIN generation. In order to establish the proper 
basis for RIN generation, we are requiring that every renewable fuel 
producer have the on-site engineering review of their facility 
performed in conjunction with his or her initial registration for the 
new RFS program. The engineering reviews must be conducted by 
independent third parties who can maintain impartiality and objectivity 
in evaluating the facilities and their processes. Additionally, the on-
site engineering review must be conducted every three years thereafter 
to verify that the fuel pathways established in the initial 
registration are still applicable. These requirements 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 needs to be performed within 60 days of the registration update. 
Finally, producers are required to submit a copy of their independent 
engineering review to EPA, for verification and enforcement purposes.
2. Foreign Renewable Fuel Producers
    Under RFS1, foreign renewable fuel producers of cellulosic biomass 
ethanol and waste-derived ethanol may apply to EPA to generate RINs for 
their own fuel. For RFS2, we proposed that foreign producers of 
renewable fuel 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 apply to all 
foreign renewable fuel producers who plan to export their products to 
the U.S. as part of the RFS2 program, whether the foreign producer 
generates RINs for their fuel or an importer does.
    Foreign producers, like domestic producers, must also undergo an 
independent engineering review of their facilities, conducted by an 
independent third party who is a licensed professional engineer (P.E.), 
or foreign equivalent who works in the chemical engineering field. The 
independent third party must provide to EPA documentation of his or her 
qualifications as part of the engineering review, including proof of 
appropriate P.E. license or foreign equivalent. The third-party 
engineering review must be conducted by both foreign producers who plan 
to generate RINs and those that don't generate RINs but anticipate 
their fuel will be exported to the United States by an importer who 
will generate the RINs.
3. Renewable Fuel Importers
    We are requiring importers who generate RINs for imported fuel that 
they receive without RINs may only do so under certain circumstances. 
If an importer receives fuel without RINs, the importer may only 
generate RINs for that fuel if they can verify the fuel pathway and 
that feedstocks use meet the definition of renewable biomass. An 
importer must rely on his supplier, a foreign renewable fuel producer, 
to provide documentation to support any claims for their decision 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 and must have had a 
third-party engineering review conducted, as noted above, in order for 
EPA to be able to verify that the renewable biomass and GHG reduction 
requirements of EISA are being fulfilled. Section II.D.2.b describes 
the RIN generating restrictions and requirements for importers under 
RFS2.
4. Process and Timing
    We are making forms for expanded registration for renewable fuel 
producers and importers, as well as forms for registration of other 
regulated parties, available electronically with the publication of 
this final rule. Paper registration forms will only be accepted in 
exceptional cases. Registration forms must be submitted and accepted by 
the EPA by July 1, 2010, or 60 days prior to a producer producing or 
importer importing any renewable fuel, whichever dates come later. If a 
producer changes its fuel pathway (feedstock, production process, or 
fuel type) to not listed in his registration information on file with 
EPA but the change will not incur a change of RIN category for the fuel 
(i.e., a change in the appropriate D code), the producer must update 
his registration information within seven (7) days of the change. 
However, if the fuel producer changes its fuel pathway in a manner that 
would result in a change in its RIN category (and thus a new D code), 
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. If EPA finds that these deadlines and requirements have not 
been met, or that a facility's registered profile, dictated by the 
various parameters for product, process and feedstock, does not reflect 
actual products produced, processes employed, or feedstocks used, then 
EPA reserves the right to void, ab initio, any affected RINs generated 
and may impose significant penalties. For example a newly registered 
(i.e. not grandfathered) ethanol production facility claims in their 
registration that they qualify to generate RINs based upon the use of 
two advanced engineering practices (1) corn oil fractionation and (2) 
production of wet DGS co-product that is, at a minimum, 35% of its 
total DGS produced annually. However, during an audit of the producer's 
records, it is found that of all their DGS produced, less than 15% was 
wet. In this example, the producer has committed a violation that 
results in the disqualification of their eligibility to generate RINs; 
that is, they no longer have an eligible pathway that demonstrates 
qualification with the 20% GHG threshold requirement for corn ethanol 
producers. As such any and all RINs produced may be deemed invalid and 
the producer may be subject to Clean Air Act penalties.

[[Page 14709]]

    The required independent engineering review as discussed above for 
domestic and foreign renewable fuel producers is an integral part of 
the registration process. The agency recognizes, through comments 
received, that there are significant concerns involving timing 
necessary and ability to produce a completed engineering review to 
satisfy registration requirements. Since the publication of the RFS2 
NPRM, we have delivered consistently a message stating that advanced 
planning and preparation was necessary from all parties, EPA and the 
regulated community inclusive, for successful implementation of this 
program. In an effort to reduce demand on engineering resources, we are 
allowing grandfathered facilities an additional six months to submit 
their engineering review. This will direct the focus of engineering 
review resources on producers of advanced, cellulosic and biomass based 
diesel. EPA fully expects these producers of advanced renewable fuels 
to meet the engineering review requirement; however, if they are having 
difficulties producing engineer's reports prior to April 1, we ask that 
they contact us.

D. Generation of RINs

    Under RFS2, each RIN will 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. Other aspects of the generation of RINs, such as 
the definition of a batch, as well as the assignment of RINs to 
batches, will remain unchanged from the RFS1 requirements. We received 
several comments regarding the method for calculating temperature 
standardization of biodiesel and address this issue in Section III.G.
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 the sections of EPAct 
that provided extra credit for cellulosic and waste-derived renewable 
fuels, and the direction that EPA establish ``appropriate'' credit for 
biodiesel and renewable fuel volumes in excess of the mandated volumes. 
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. EPA stated that these provisions 
indicated that Congress did not intend to restrict EPA discretion in 
implementing the program to utilizing a straight volume measurement of 
gallons. See 72 FR 23918-23920, and 71 FR 55570-55571. 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.
    In the NPRM we noted that EISA made a number of changes to CAA 
section 211(o) that impacted 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. 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 of 
these new requirements, we indicated that there may no longer be a need 
for additional incentives for certain fuels in the form of Equivalence 
Values greater than 1.0.
    In the NPRM we co-proposed and took 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, with the addition 
that biomass-based diesel standard would be based on energy content in 
comparison to biodiesel.
    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).
    In response to the NPRM, some stakeholders pointed to the 
aforementioned changes brought about by EISA as support for a straight 
volume approach to Equivalence Values, and argued that it had always 
been the intent of Congress that the statutory volume mandates be 
treated as straight volumes. Stakeholders taking this position were 
generally producers of corn ethanol. However, a broad group of other 
stakeholders including refiners, biodiesel producers, a broad group of 
advanced biofuel producers, fuel distributor and States indicated that 
the first option for an energy-based approach to Equivalence Values was 
both supported by the statute and necessary to provide for equitable 
treatment of advanced biofuels. They noted that EISA did not change 
certain of the statutory provisions EPA 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 direct EPA 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. Had 
Congress intended to change these provisions they could have easily 
done so. Moreover, some stakeholders 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 does not obviate the value of standardizing for 
energy content, which provides a level playing field under RFS1 for 
various types of renewable fuels based on energy content.
    Some stakeholders who supported an energy-based approach to 
Equivalence Values also argued 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. 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 80 gallons of ethanol (and 
another 14 gal of other alcohols) or 50

[[Page 14710]]

gallons of diesel fuel (and naphtha).\10\ 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 their 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. Since the technologies for 
producing more energy-dense fuels such as cellulosic diesel are still 
in the early stages of development, they may benefit from not having to 
overcome the disincentive in the form of the same Equivalence Value 
based on straight volume.
---------------------------------------------------------------------------

    \10\ 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.
---------------------------------------------------------------------------

    Based on our interpretation of EISA as allowing the use of energy-
based Equivalence Values, and because we believe it provides a level 
playing field for the development of different fuels that can displace 
the use of fossil fuels, and that this approach therefore furthers the 
energy independence goals of EISA, we are finalizing the energy-based 
approach to Equivalence Values in today's action. We also note that a 
large number of companies have already made investments based on the 
decisions made for RFS1, and using energy-based Equivalence Values will 
maintain consistency with RFS1 and ease the transition into RFS2. 
Insofar as renewable fuels with volumetric energy contents higher than 
ethanol are used, the actual volumes of renewable fuel that are 
necessary to meet the EISA volume mandates will be smaller than those 
shown in Table I.A.1-1. The impact on the physical volume will depend 
on actual volumes of various advanced biofuels produced in the future. 
The main scenario modeled for this final rule includes a forecast for 
considerable volumes of relatively high energy diesel fuel made from 
renewable biomass, and still results in a physical volume mandate of 
30.5 billion gallons. The energy-based approach results in the advanced 
biofuel standard being automatically met during the first few years of 
the program. For instance, the biomass-based diesel mandated volume for 
2010 is 0.65 billion gallons, which will be treated as 0.975 billion 
gallons (1.5 x 0.65) in the context of meeting the advanced biofuel 
standard. Since the mandated volume for advanced biofuel in 2010 is 
0.95 billion gallons, this requirement is automatically met by 
compliance with the biomass-based diesel standard.
    Although we are finalizing an energy-based approach to Equivalence 
Values, we believe that Congress intended the biomass-based diesel 
volume mandate to be treated as diesel volumes rather than as ethanol-
equivalent volumes. Since all RINs are generated based on energy 
equivalency to ethanol, to accomplish this, we have modified the 
formula for calculating the standard for biomass-based diesel to 
compensate such that one physical gallon of biomass-based diesel will 
count as one gallon for purposes of meeting the biomass-based diesel 
standard, but will be counted based on their Equivalence Value for 
purposes of meeting the advanced biofuel and total renewable fuel 
standards. Since it is likely that the statutory volume mandates were 
based on projections for biodiesel, we have chosen to use the 
Equivalence Value for biodiesel, 1.5, in this calculation. See Section 
II.E.1.a for further discussion. Other diesel fuel made from renewable 
biomass can also qualify as biomass-based diesel (e.g., renewable 
diesel, cellulosic diesel). But since the variation in energy content 
between them is relatively small, variation in the total physical 
volume of biomass-based diesel will likewise be small.
    In the NPRM we also proposed that the energy content of denatured 
ethanol be changed from the 77,550 Btu/gal value used in the RFS1 
program to 77,930 Btu/gal (lower heating value). The revised value was 
intended to provide a more accurate estimate of the energy content of 
pure ethanol, 76,400 Btu/gal, rather than the rounded value of 76,000 
Btu/gal that was used under RFS1. Except for the Renewable Fuels 
Association who supported this change, most stakeholders did not 
comment on this proposal. However, based on new provisions in the Food, 
Conservation, and Energy Act of 2008, we have since determined that the 
denaturant content of ethanol should be assumed to be 2% rather than 
the 5% used in the RFS1 program. This additional change results in a 
denatured ethanol energy content of 77,000 Btu/gal and a renewable 
content of denatured ethanol of 97.2%.\11\ The value of 77,000 Btu/gal 
will be used to convert biogas and renewable electricity into volumes 
of renewable fuel under RFS2. This change also affects the formula for 
calculating Equivalence Values assigned to renewable fuels. The new 
formula is shown below:

    \11\ Value is lower than 98% because it is based on energy 
content of denaturant versus ethanol, not relative volume.
---------------------------------------------------------------------------

EV = (R/0.972) * (EC/77,000)

Where:

EV = Equivalence Value for the renewable fuel, rounded to the 
nearest tenth.
R = Renewable content of the renewable fuel. This is a measure of 
the portion of a renewable fuel that came from a renewable source, 
expressed as a percent, on an energy basis.
EC = Energy content of the renewable fuel, in Btu per gallon (lower 
heating value).

Under this new formula, Equivalence Values assigned to specific types 
of renewable fuel under RFS1 will continue unchanged under RFS2. 
However, non-ester renewable diesel will be required to have a lower 
energy content of at least 123,500 Btu/gal in order to qualify for an 
Equivalence Value of 1.7. A non-ester renewable diesel with a lower 
energy content would be required to apply for a different Equivalent 
Value according to the provisions in Sec.  80.1415.
2. Fuel Pathways and Assignment of D Codes
    As described in Section II.A, RINs under RFS2 would in general 
continue to have the same number of digits and code definitions as 
under RFS1. The one change will be that, while the D code will continue 
to identify the standard to which the RIN can be applied, it will 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 II.A-1.
    In order to generate RINs for renewable fuel that meets the various 
eligibility requirements (see Section II.B), a producer or importer 
must know which D code to assign to those RINs. Following the approach 
we described in the NPRM, a producer or importer will determine the 
appropriate D code using a lookup table in the regulations. The

[[Page 14711]]

lookup table lists various combinations of fuel type, production 
process, and feedstock, and the producer or importer chooses the 
appropriate combination representing the fuel he is producing and for 
which he is generating RINs. Parties generating RINs are required to 
use the D code specified in the lookup table and are not 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 for purposes of RIN generation.\12\
---------------------------------------------------------------------------

    \12\ However, a biomass-based diesel RIN can be used to satisfy 
Renewable Volume Obligations (RVO) for biomass-based diesel, 
advanced biofuel, and total renewable fuel. See Section II.G.3 for 
further discussion of the use of RINs for compliance purposes.
---------------------------------------------------------------------------

    This section describes our 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 facilities for which the 
lookup table does not provide an applicable D code.
a. Producers
    For both domestic and foreign producers of renewable fuel, the 
lookup table identifies 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 is assigned to one of the 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 V.
    Note that the generation of RINs also requires as a prerequisite 
that the feedstocks used to make the renewable fuel meet the definition 
of ``renewable biomass'' as described in Section II.B.4, including 
applicable land use restrictions. If a producer is not able to 
demonstrate that his feedstocks meet the definition of renewable 
biomass, RINs cannot be generated. However, as noted in Section 
II.B.4.b.1, feedstocks typically include incidental contaminants. These 
contaminants may have been intentionally added to promote cultivation 
(e.g., pesticides, herbicides, fertilizer) or transport (e.g., nylon 
baling rope). In addition, there may be some incidental contamination 
of a particular load of feedstocks with co-product during feedstock 
production, or with other agricultural materials during shipping. For 
example, there may be incidental corn kernels remaining on some corn 
cobs used to produce cellulosic biofuel, or some sorghum kernels left 
in a shipping container that are introduced into a load of corn kernels 
being shipped to a biofuel production facility. The final regulations 
clarify that in assigning D codes for renewable fuel, producers and 
importers should disregard the presence of incidental contaminants in 
their feedstocks if the incidental contaminants are related to 
customary feedstock production and transport, and are impractical to 
remove and occur in de minimus levels.
    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 will 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 
will count as cellulosic biofuel. Biodiesel made from waste grease or 
soybean oil can count as biomass-based diesel. Ethanol made from 
sugarcane sugar will count as advanced biofuel. Finally, a variety of 
pathways will count as renewable fuel under the RFS2 program. The 
complete list of pathways that are valid under our final RFS2 program 
is discussed in Section V.C and are provided in the regulations at 
Sec.  80.1426(f).
    Producers must 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 II.C. If there are changes 
to a 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 is 
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 II.D.3 below.
    For producers for whom none of the defined fuel pathways in the 
lookup table apply, a producer can still generate RINs if he meets the 
criteria for grandfathered or deemed compliant status as described in 
Section II.B.3 and his fuel meets the definition of renewable fuel as 
described in Section II.B.1. In this case he would use a D code of 6 
for those RINs generated under the grandfathering or deemed compliant 
provisions.
    A diesel fuel product produced from cellulosic feedstocks that 
meets the 60% GHG threshold can qualify as either cellulosic biofuel or 
biomass-based diesel. In the NPRM, we proposed that the producer of 
such ``cellulosic diesel'' be required to choose whether to categorize 
his product as either cellulosic biofuel or biomass-based diesel. 
However, we requested comment on an alternative approach in which an 
additional D code would be defined to represent cellulosic diesel 
allowing the cellulosic diesel RIN to be sold into either market. As 
described more fully in Section II.A above, we are finalizing this 
alternative approach in today's final rule. Producers or importers of a 
fuel that qualifies as both biomass-based diesel and cellulosic biofuel 
must use a D code of 7 in the RINs they generate, and will thus have 
the flexibility of marketing such RINs to parties seeking either 
cellulosic biofuel or biomass-based diesel RINs, depending on market 
demand. Obligated parties can apply RINs with a D code of 7 to either 
their cellulosic biofuel or biomass-based diesel RVOs, but not both.
    In addition to the above comments, we received comments requesting 
that the use of biogas as process heat in the production of ethanol, 
should not be limited to use at the site of renewable fuel production. 
Specifically, commenters point out that the introduction of gas 
produced from landfills or animal wastes to fungible pipelines is the 
only practical manner for most renewable fuel facilities to acquire and 
use landfill gas, since very few are located adjacent to landfills, or 
have dedicated pipelines from landfill gas operations to their 
facilities.\13\ The commenters suggested that ethanol plants causing 
landfill gas to be introduced into a fungible gas pipeline be allowed 
to claim those volumes. The alternative would be to allow landfill

[[Page 14712]]

gas that is only used onsite to be counted in establishing the pathway.
---------------------------------------------------------------------------

    \13\ This suggestion was also made by several companies with 
respect to the RFS1 definition of cellulosic biomass ethanol, which 
allowed corn-based ethanol to be deemed cellulosic if 90% of the 
fossil fuel used at the ethanol facility to make ethanol was 
displaced by fuel derived from animal or other waste materials, 
including landfill gas.
---------------------------------------------------------------------------

    We believe that the suggested approach has merit. We agree that it 
does not make any difference in terms of the beneficial environmental 
attributes associated with the use of landfill gas whether the 
displacement of fossil fuel occurs in a fungible natural gas pipeline, 
or in a specific facility that draws gas volume from that pipeline. In 
fact, a similar approach is widely used with respect to electricity 
generated by renewable biomass that is placed into a commercial 
electricity grid. A party buying the renewable power is credited with 
doing so in state renewable portfolio programs even though the power 
from these sources is placed in the fungible grid and the electrons 
produced by a renewable source may never actually be used by the party 
purchasing it. In essence these programs assume that the renewable 
power purchased and introduced into the grid is in fact used by the 
purchaser, even though all parties acknowledge that use of the actual 
renewable-derived electrons can never be verified once placed in the 
fungible grid. We believe that this approach will ultimately further 
the GHG reduction and energy security goals of RFS2.
    Producers may therefore take into account such displacement 
provided that they demonstrate that a verifiable contractual pathway 
exists and that such pathway ensures that (1) a specific volume of 
landfill gas was placed into a commercial pipeline that ultimately 
serves the transportation fueling facility and (2) that the drawn into 
this facility from that pipeline matches the volume of landfill gas 
placed into the pipeline system. Thus facilities using such a fuel 
pathway may then use an appropriate D code for generation of RINs.
    This approach also applies to biogas and electricity made from 
renewable fuels and which are used for transportation. Producers of 
such fuel will be able to generate RINs, provided that a contractual 
pathway exists that provides evidence that specific quantities of the 
renewable fuel (either biogas or electricity) was purchased and 
contracted to be delivered to a specific transportation fueling 
facility.\14\ We specify that the pipeline (or transmission line) 
system must ultimately serve the subject facility. For electricity that 
is produced by the co-firing of fossil fuels with renewable biomass 
derived fuels, we are requiring that the resulting electricity is pro-
rated to represent only that amount of electricity generated by the 
qualifying biogas, for the purpose of computing RINs.
---------------------------------------------------------------------------

    \14\ Note that biogas used for transportation fuel includes 
propane made from renewable biomass.
---------------------------------------------------------------------------

    We are also providing for those situations in which biogas or 
renewable electricity is provided directly to the transportation 
facility, rather than using a commercial distribution system such as 
pipelines or transmission lines. For both cases--dedicated use and 
commercial distribution--producers must provide contractual evidence of 
the production and sale of such fuel, and there are also reporting and 
recordkeeping requirements to be followed as well.
    Presently, there is no D code for electricity that is produced from 
renewable biomass. The petition process for assigning such codes in 
today's rule can be used for such purpose.
b. Importers
    For imported renewable fuel under RFS2, we are anticipating the 
importer to be the primary party responsible for generating RINs. 
However, the foreign producer of renewable fuel can instead elect to 
generate RINs themselves under certain conditions as described more 
fully in Section II.D.2.c below. This approach is consistent with the 
approach under RFS1.
    Under RFS1, importers who import more than 10,000 gallons in a 
calendar year were required to 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 can no longer generate RINs under RFS2 on the basis of 
fuel type alone. Instead, they must be able to demonstrate that the 
renewable biomass definition has been met for the renewable fuel they 
intend to import and for which they will generate RINs. 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 the RINs they generate. Therefore, in 
order to generate RINs, the importer will be required to obtain this 
information from a foreign producer. RINs can only be generated if a 
demonstration is made that the feedstocks used to produce the renewable 
fuel meet the definition of renewable biomass.
    In summary, under today's final rule, importers can import any 
renewable fuel, but can only generate RINs to represent the imported 
renewable fuel under the two conditions described below. If these 
conditions do not apply, the importer can import biofuel but cannot 
generate RINs to represent that biofuel.
    1. The imported renewable fuel is not accompanied by RINs generated 
by the registered foreign producer
    2. The importer obtains from the foreign producer:
--Documentation demonstrating that the renewable biomass definition has 
been met for the volume of renewable fuel being imported.
--Documentation about the feedstock and production process used to 
produce the renewable fuel to allow the importer to determine the 
appropriate D-code designation in the RINs generated.

We are also finalizing additional requirements for foreign producers 
who either generate RINs or provide documentation to an importer 
sufficient to allow the importer to generate RINs. As described more 
fully in the next section, these additional requirements include 
restrictions on mixing of biofuels in the distribution system as it 
travels from the foreign producer to the importer.
    Finally, EPA is assessing whether additional requirements on 
foreign-generated fuel may be necessary for situations in which 
importers are generating RINs for the fuel. Additional requirements may 
be necessary to ensure that the importers have sufficient information 
to properly generate the RINs and that EPA has sufficient information 
to determine whether those RINs have been legitimately generated. EPA 
will pursue an amendment to the final RFS2 regulations if we find that 
additional requirements are appropriate and necessary.
c. Additional Provisions for Foreign Producers
    In general, we are requiring foreign producers of renewable fuel to 
meet the same requirements as domestic producers with respect to 
registration, recordkeeping and reporting, attest engagements, and the 
transfer of RINs they generate with the batches of renewable fuel that 
those RINs represent. However, we are also placing additional 
requirements on foreign producers to ensure that RINs entering the U.S. 
are valid and that the regulations can be enforced at foreign 
facilities. These additional requirements are designed to accommodate 
the more limited access that EPA enforcement personnel have to foreign 
entities that are regulated parties under RFS2, and also the fact that 
foreign-produced biofuel intended for export to the U.S. is often mixed 
with biofuel that will not be exported to the U.S.

[[Page 14713]]

    Under RFS1, foreign producers had the option of generating RINs for 
the renewable fuel that they export to the U.S. if they wanted 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 
ensure that EPA had the ability to enforce the regulations relating to 
the generation of RINs from such foreign ethanol producers, the RFS1 
regulations specified additional requirements for them, including 
posting a bond, admitting EPA enforcement personnel, and submitting to 
third-party engineering reviews of their production process. For RFS2, 
we are maintaining these additional requirements for foreign producers 
because EPA enforcement personnel have the same limitations under RFS2 
with regard to access to foreign entities that are regulated parties as 
they did under RFS1.
    EISA also creates other unique challenges in the implementation and 
enforcement of the renewable fuel standards for foreign-produced 
renewable fuel imported into the U.S. 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 under the RFS2 program. Thus, whether foreign 
producers or importers generate RINs, this information must be 
collected and maintained by the RIN generator.
    If a foreign producer generates RINs for renewable fuel that it 
produces and exports to the U.S., we are requiring that ethanol must be 
dewatered and denatured by the foreign producer prior to leaving the 
production facility and prior to the generation of RINs. This is 
consistent with our definition of renewable fuel in which ethanol that 
is valid under RFS2 must be denatured. Moreover, the foreign producer 
is required to strictly segregate a batch of renewable fuel and its 
associated RINs from all other volumes of renewable fuel as it travels 
from the foreign producer to the importer. The strict segregation 
ensures that RINs entering the U.S. appropriately represent the 
renewable fuel imported into the U.S. both in terms of renewable fuel 
type and volume.
    Several commenters requested that in general the importer be the 
RIN generator for imported renewable fuel. Since most imported ethanol 
is currently made in Brazil and is not denatured by the foreign 
producer, any RINs generated must be generated by the importer. 
However, to accomplish this, the importer must obtain the appropriate 
information from a foreign producer regarding compliance with the 
renewable biomass definition and a description of the associated 
pathway for the renewable fuel. Under these circumstances, the foreign 
producer must ensure that the information is transferred along with the 
renewable fuel through the distribution system until it reaches the 
importer. The foreign producer's volume of renewable fuel need not be 
strictly segregated from other volumes in this case, so long as a 
volume of chemically indistinguishable renewable fuel is tracked 
through the distribution system from the foreign producer to the 
importer, and the information needed by the importer to generate RINs 
follows this same path through the distribution system. Strict 
segregation of the volume is not necessary in this case, and the 
importer will determine appropriate number of RINs for the specific 
volume and type of renewable fuel that he imports.
    Finally, if a foreign producer chooses not to participate in the 
RFS2 program and thus neither generates RINs nor provides information 
to the importer so that the importer can generate RINs, the foreign 
producer can still export biofuel to the U.S. However, under these 
circumstances the biofuel would not be renewable fuel under RFS2, no 
RINs could be generated by any party, and thus the foreign producer 
would not be subject to any of the registration, recordkeeping, 
reporting, or attest engagement requirements.
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 for fuel produced at 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 applicable D code for 
various RINs generated at the facility.
    If more than one pathway applies to a facility within a compliance 
period, no special steps will need to be taken if the D code is the 
same for all the applicable pathways. In this case, all RINs generated 
at the facility will have the same D code regardless. Such a producer 
with multiple applicable pathways must still describe its feedstock(s), 
fuel type(s), and production process(es) in its initial registration 
and annual report to the Agency so that we can 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. For instance, a producer could change feedstocks, production 
processes, or the type of fuel he produces in the middle of a 
compliance period. Or, he could use more than one feedstock or produce 
more than one fuel type simultaneously. The approach we are finalizing 
for designating D codes for RINs in these cases follows the approach 
described in the NPRM and is summarized in Table II.D.3-1.

   Table II.D.3-1--Approach To Assigning Multiple D Codes for Multiple
                           Applicable Pathways
------------------------------------------------------------------------
            Case/Description                    Proposed approach
------------------------------------------------------------------------
1. The pathway applicable to a facility  The applicable D code used in
 changes on a specific date, such that    generating RINs must change on
 one single pathway applies before the    the date that the fuel
 date and another single pathway          produced changes pathways.
 applies on and after the date.
2. One facility produces two or more     The volumes of the different
 different types of renewable fuel at     types of renewable fuel should
 the same time.                           be measured separately, with
                                          different D codes applied to
                                          the separate volumes.

[[Page 14714]]

 
3. One facility uses two or more         For any given batch of
 different feedstocks at the same time    renewable fuel, the producer
 to produce a single type of renewable    should assign the applicable D
 fuel.                                    codes using a ratio (explained
                                          below) defined by the amount
                                          of each type of feedstock
                                          used.
------------------------------------------------------------------------

    Commenters were generally supportive of this approach to multiple 
applicable pathways, and as a result we are finalizing it with few 
modifications from the proposal. Further discussion of the comments we 
received can be found in Section 3.5.4 of the S&A document.
    Following our proposal, cases listed in Table II.D.3-1 will 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. This approach covers all likely cases in which multiple 
applicable pathways may apply to a renewable fuel producer. Some 
examples of how Case 2 or 3 would apply are provided in the NPRM.
    A facility where two or more different types of feedstock are used 
to produce a single fuel (such as Case 3 in Table II.D.3-1) will be 
required to generate two or more separate batch-RINs \15\ for a single 
volume of renewable fuel, and these separate batch-RINs will have 
different D codes. The D codes will be chosen on the basis of the 
different pathways as defined in the lookup table in Sec.  80.1426(f). 
The number of gallon-RINs that will be included in each of the batch-
RINs will depend on the relative amount of the different types of 
feedstocks used by the facility. In the NPRM, we proposed to use the 
relative energy content of the feedstocks to determine how many gallon-
RINs should be assigned to each D code. Commenters generally did not 
address this aspect of our proposal, and we are finalizing it in 
today's action. Thus, the useable energy content of each feedstock must 
be used to divide the total number of gallon-RINs generated for a batch 
of renewable fuel into two or more groups, each corresponding to a 
different D code. Several separate batch-RINs can then be generated and 
assigned to the single volume of renewable fuel. The applicable 
calculations are given in the regulations at Sec.  80.1426(f)(3).
---------------------------------------------------------------------------

    \15\ Batch-RINs and gallon-RINs are defined in the regulations 
at 40 CFR 80.1401.
---------------------------------------------------------------------------

    We proposed several elements of the calculation of the useable 
energy content of the feedstocks, including the following:
    1. Only that fraction of a feedstock which is expected to be 
converted into renewable fuel by the facility can be counted in the 
calculation, taking into account facility conversion efficiency.
    2. The producer of the renewable fuel is required to designate this 
fraction once each year for the feedstocks processed by his facility 
during that year, and to include this information as part of his 
reporting requirements.
    3. Each producer is required to designate the energy content (in 
Btu/lb) once each year of the portion of each of his feedstocks which 
is converted into fuel. The producer may determine these values for his 
own feedstocks, or may use default values provided in the regulations 
at Sec.  80.1426(f)(7).
    4. Each producer is required to determine the total mass of each 
type of feedstock used by the facility on at least a daily basis.
    Based on the paucity of comments we received on this issue, we are 
finalizing the provisions regarding the calculation of useable energy 
content of the feedstocks as it was proposed in the NPRM. As described 
in Section II.J, producers of renewable fuel will be required to submit 
information in their reports on the feedstocks they used, their 
production processes, and the type of fuel(s) they produced during the 
compliance period. This will apply to both domestic producers and 
foreign producers who export any renewable fuel to the U.S. We will 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 co-fired 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 will be only partially renewable. RINs can be 
generated in such cases, but must be done 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 are eliminating the RFS1 provision applicable only to 
liquid feedstocks and replacing it with a more comprehensive approach 
that will apply to liquid, solid, or gaseous feedstocks and any type of 
conversion process. In this final approach, producers are required to 
use the relative energy content of their renewable and non-renewable 
feedstocks to determine the renewable fraction of the fuel that they 
produce. This fraction in turn is used to determine the number of 
gallon-RINs that should be generated for each batch. Commenters said 
little about our proposed methodology to use the relative energy 
content of the feedstocks, and we are therefore finalizing it largely 
as proposed.
    We also requested comment on allowing renewable fuel producers to 
use an accepted test method to directly measure the fraction of the 
fuel that is derived from biomass rather than a fossil fuel feedstock. 
For instance, ASTM D-6866 is a radiocarbon dating test method that can 
be used to determine the renewable content of transportation fuel. The 
use of such a test method can be used in lieu of the calculation of the 
renewable portion of the fuel based on the relative energy content of 
the renewable biomass and fossil feedstocks. Commenters generally 
supported the option of using a radiocarbon dating approach. As a 
result, we believe it would be appropriate and are finalizing a 
provision to allow parties that co-process renewable biomass and fossil 
fuels to choose between using the relative energy in the feedstocks or 
ASTM D-6866 to determine the number of gallon-RINs that should be 
generated. Regardless of the approach chosen, the

[[Page 14715]]

producer will still need to separately verify that the renewable 
feedstocks meet the definition of renewable biomass.
    If a producer chose to use the energy content of the feedstocks, 
the calculation would be similar to the treatment of renewable fuels 
with multiple D codes as described in Section II.D.3 above. As shown in 
the regulations at Sec.  80.1426(f)(3), 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. Only one batch-RIN would be generated 
for a single volume of fuel produced from both a renewable feedstock 
and a fossil feedstock, and this one batch-RIN must be based on the 
contribution that the renewable feedstock makes to the total volume of 
fuel. The calculation of the relative energy contents includes 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 will be accounted for. The relative energy 
content of the feedstocks is used to adjust the basic calculation of 
the number of gallon-RINs downward from that calculated on the basis of 
batch fuel volume and the applicable Equivalence Value. The D code that 
must be assigned to the RINs is 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 produces 
only cellulosic diesel for purposes of identifying the appropriate D 
code for the fraction of biofuel that qualifies as renewable fuel under 
EISA.
    If a producer chose to use D-6866, he would be required to either 
apply this test to every batch, or alternatively to take samples of 
every batch of fuel he produced over the course of one month and 
combine them into a single composite sample. The D-6866 test would then 
be applied to the composite sample, and the resulting renewable 
fraction would be applied to all batches of fuel produced in the next 
month to determine the appropriate number of RINs that must be 
generated. For the first month, the producer can estimate the non-
fossil fraction, and then make a correction as needed in the second 
month. The producer would be required to recalculate the renewable 
fraction every subsequent month. See the regulations at Sec.  
80.1426(f)(9).
5. Facilities That Process Municipal Solid Waste
    As described in Section II.B.4.d, only the separated yard and food 
waste of municipal solid waste (MSW) are considered to be renewable 
biomass and may be used to produce renewable fuels under the RFS2 
program. While renewable fuel producers may produce fuel from all 
organic components of MSW, they may generate RINs for only that portion 
of MSW that qualifies as renewable biomass. We are providing two 
methods for determining the appropriate number of RINs to generate for 
each batch of fuel, depending on whether the feedstock is pure food and 
yard waste, or separated municipal solid waste, as described in Section 
II.B.4.d. While not all biogenic material in the separated MSW is 
cellulosic, the vast majority of it is likely to be in most situations. 
Specifically, separated municipal solid waste may contain some non-
biogenic materials such as plastics that were unable to be recycled due 
to market conditions. We are requiring producers of renewable fuel made 
from separated municipal solid waste to use the radiocarbon dating 
method D-6866 to calculate the biogenic fraction, presumed to be 
composed of cellulosic materials. Therefore, unless a renewable fuel 
producer is using MSW streams that are clearly not cellulosic, we 
anticipate that a D code of either 3 or 7 will be appropriate for such 
RINs. See the regulations at Sec.  80.1426(f).
6. RINless Biofuel
    Under the RFS1 program, all renewable fuel made from renewable 
feedstocks and used as motor vehicle fuel in the U.S. was assigned 
RINs. Therefore, aside from the very small amounts of biofuel used in 
nonroad applications or as heating oil, all renewable fuel produced or 
imported counted towards the mandated volume goals of the RFS program. 
Although conventional diesel fuel was not subject to the standards 
under RFS1, all other motor vehicle fuel fell into two groups: fuel 
subject to the standards, and fuel for which RINs were generated and 
was used to meet those standards.
    Under RFS2, our approach to compliance with the renewable biomass 
provision will allow the possibility for some biofuel to be produced 
without RINs. As described in Section II.B.4 above, we are modifying 
our approach to compliance with the renewable biomass provision so that 
renewable fuel producers using feedstocks from domestic planted crops 
and crop residue will be presumed to meet the renewable biomass 
provision. Under this ``aggregate compliance'' approach, these 
producers will be generating RINs for all their renewable fuel. 
However, producers who use foreign-grown crops or crop residue or other 
feedstocks such as planted trees or forestry residues will not be able 
to take advantage of this aggregate compliance approach. Instead, they 
will be required to demonstrate that their feedstocks meet the 
renewable biomass definition, including the associated land use 
restrictions, before they will be permitted to generate RINs. Absent 
such a demonstration, these producers can still produce biofuel but 
will not generate RINs. In addition, fuel producers whose fuel does not 
qualify as renewable fuel under this program because it does not meet 
the 20% GHG threshold (and is not grandfathered) can still produce 
biofuel but will not be allowed to generate RINs. Transportation fuel 
consumed in the U.S. will therefore be comprised of three groups: fuel 
subject to the standards (gasoline and diesel), fuel for which RINs are 
generated and will be used to meet those standards, and RINless 
biofuel. RINless biofuel will not be covered under any aspect of the 
RFS2 program, despite the fact that in many cases it will meet the EISA 
definition of transportation fuel upon blending with gasoline or 
diesel.
    In their comments in response to the NPRM, several refiners 
suggested that RINless biofuel should be treated as an obligated volume 
similar to gasoline and diesel, and thus be subject to the standards. 
Doing so would ensure that all transportation fuels are covered under 
the RFS2 program, consistent with RFS1. Such an approach would also 
provide renewable fuel producers with an incentive to demonstrate that 
their feedstocks meet the renewable biomass definition and thus 
generate RINs for all the biofuel that they produce. There could be 
less potential for market manipulation on the part of biofuel producers 
who might be considering producing RINless biofuel as a means for 
increasing demand for renewable fuel and RINs.
    Nevertheless, we do not believe that it would be appropriate at 
this time to finalize a requirement that RINless biofuel be considered 
an obligated fuel subject to the standards. We did not propose such an 
approach in the NPRM, and as a result many renewable fuel producers who 
could be affected did not have an opportunity to consider and comment 
on it. Moreover, the volume of RINless biofuel is likely to be small 
compared to the volume of renewable fuel with RINs since RINs have 
value and producers currently have an

[[Page 14716]]

incentive to generate them. However, if in the future RIN values should 
fall--for instance, if crude oil prices rise high enough and the market 
drives up demand for biofuels--the incentive to demonstrate compliance 
with the renewable biomass definition may decrease and there may be an 
increase in the volume of RINless biofuel. Under such circumstances it 
may be appropriate to reconsider whether RINless biofuel should be 
designated as an obligated volume subject to the standards.

E. Applicable Standards

    The renewable fuel standards are expressed as a volume percentage, 
and are used by each refiner, blender or importer to determine their 
renewable fuel volume obligations. The applicable percentages are set 
so that if each regulated party meets the percentages, then the amount 
of renewable fuel, cellulosic biofuel, biomass-based diesel, and 
advanced biofuel used will meet the volumes specified in Table I.A.1-
1.\16\
---------------------------------------------------------------------------

    \16\ 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 formulas finalized today for use in deriving annual renewable 
fuel standards are based in part on an estimate of combined gasoline 
and diesel volumes, for both highway and nonroad uses, for the year in 
which the standards will apply. The standards will apply to refiners, 
blenders, and importers of these fuels. As described more fully in 
Section II.F.3, other producers of transportation fuel, such as 
producers of natural gas, propane, and electricity from fossil fuels, 
are not subject to the standards. Since the standards apply to 
refiners, blenders and importers of gasoline and diesel, these are also 
the transportation fuels that are used to determine the annual volume 
obligations of an individual refiner, blender, or importer.
    The projected volumes of gasoline and diesel used to calculate the 
standards will continue to be provided by EIA's Short-Term Energy 
Outlook (STEO). The standards applicable to a given calendar year will 
be published by November 30 of the previous year. Gasoline and diesel 
volumes will continue to be adjusted to account for the required 
renewable fuel volumes. In addition, gasoline and diesel volumes 
produced by small refineries and small refiners will be exempt through 
2010, and that year's standard is adjusted accordingly, as discussed 
below.
    As discussed in the proposal, four separate standards are required 
under the RFS2 program, corresponding to the four separate volume 
requirements shown in Table I.A.1-1. The specific formulas we use to 
calculate the renewable fuel standards are described below in Section 
II.E.1.
    In order for an obligated party to demonstrate compliance, the 
percentage standards are 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 continues to be referred to as its Renewable 
Volume Obligation (RVO). Since there are four separate standards under 
the RFS2 program, there are likewise four separate RVOs applicable to 
each obligated party. Each standard applies to the sum of all gasoline 
and diesel produced or imported. Determination of RVOs is discussed in 
Section II.G.2.
1. Calculation of Standards
a. How Are the Standards Calculated?
    The four separate renewable fuel standards are based primarily on 
(1) the 49-state \17\ gasoline and diesel consumption volumes projected 
by EIA, and (2) the total volume of renewable fuels required by EISA 
for the coming year. Table I.A.2-1 shows the required overall volumes 
of four types of renewable fuel specified in EISA. Each renewable fuel 
standard is expressed as a volume percentage of combined gasoline and 
diesel sold or introduced into commerce in the U.S., and is used by 
each obligated party to determine its renewable volume obligation.
---------------------------------------------------------------------------

    \17\ Hawaii opted-in to the original RFS program; that opt-in is 
carried forward to this program.
---------------------------------------------------------------------------

    Today we are finalizing an approach to setting standards that is 
based in part on the sum of all gasoline and diesel produced or 
imported in the 48 contiguous states and Hawaii. An approach we are not 
adopting but which we discussed in the proposal would have split the 
standards between those that would be specific to gasoline and those 
that would be specific to diesel. Though 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, we are not adopting this approach because it relies on 
projections of the relative amounts of gasoline-displacing and diesel-
displacing renewable fuels. These projections would need to be updated 
every year, and as stated in the proposal, we believe that such an 
approach would unnecessarily complicate the program.
    While the required amount of total renewable fuel for a given year 
is provided by EISA, the Act requires EPA to base the standards on an 
EIA estimate of the amount of gasoline and diesel that will be sold or 
introduced into commerce for that year. As discussed in the proposal, 
EIA's STEO will continue to be the source for projected gasoline, and 
now diesel, consumption estimates. In order to achieve the volumes of 
renewable fuels specified in EISA, the gasoline and diesel volumes used 
to determine the standard must be the non-renewable portion of the 
gasoline and diesel pools. Because the STEO volumes include renewable 
fuel use, we must subtract the total renewable fuel volume from the 
total gasoline and diesel volume to get total non-renewable gasoline 
and diesel volumes. The Act also requires EPA to use EIA estimates of 
renewable fuel volumes; the best estimation of the coming year's 
renewable fuel consumption is found in Table 8 (U.S. Renewable Energy 
Supply and Consumption) of the STEO. Additional information on 
projected renewable fuel use will be included as it becomes available.
    As discussed in Section II.D.1, we are finalizing the energy 
content approach to Equivalence Values for the cellulosic biofuel, 
advanced biofuel, and total renewable fuel standards. However, the 
biomass-based diesel standard is based on the volume of biodiesel. In 
order to align both of these approaches simultaneously, biodiesel will 
continue to generate 1.5 RINs per gallon as in RFS1, and the biomass-
based diesel volume mandate from EISA is then adjusted upward by the 
same 1.5 factor. The net result is a biomass-based diesel gallon being 
worth 1.0 gallons toward the biomass-based diesel standard, but 1.5 
gallons toward the other standards.
    CAA section 211(o) exempts small refineries \18\ from the RFS 
requirements until the 2011 compliance period. In RFS1, we extended 
this exemption to the few remaining small refiners not already 
exempted.\19\ Small refineries and small refiners will continue to be 
exempt from the program until 2011 under the new RFS2 regulations. Thus 
we have excluded their gasoline and diesel volumes from the overall 
non-renewable gasoline and diesel volumes used to determine the 
applicable percentages until 2011. As discussed in

[[Page 14717]]

the proposal, total small refinery and small refiner gasoline 
production volume is expected to be fairly constant compared to total 
U.S. transportation fuel production. Thus we estimated 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.
---------------------------------------------------------------------------

    \18\ 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.
    \19\ See Section III.E.
---------------------------------------------------------------------------

    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 standards. 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 proposed and are 
finalizing this value as zero.
    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. 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. Therefore, 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.
    In summary, the total projected non-renewable gasoline and diesel 
volumes from which the annual standards are calculated are 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.
    The following formulas are used to calculate the percentage 
standards:
[GRAPHIC] [TIFF OMITTED] TR26MR10.415

[GRAPHIC] [TIFF OMITTED] TR26MR10.416

[GRAPHIC] [TIFF OMITTED] TR26MR10.417

[GRAPHIC] [TIFF OMITTED] TR26MR10.418

Where

StdCB,i = The cellulosic biofuel standard for year i, in 
percent
StdBBD,i = The biomass-based diesel standard (ethanol-
equivalent basis) for year i, in percent
StdAB,i = The advanced biofuel standard for year i, in 
percent
StdRF,i = The renewable fuel standard for year i, in 
percent
RFVCB,i = Annual volume of cellulosic biofuel required by 
section 211(o)(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

[[Page 14718]]

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. Standards for 2010
    We are finalizing the standards for 2010 in today's action. As 
explained in Section I.A.2, while the rulemaking is not effective until 
July 1, 2010, the 2010 standards we are setting are annual standards 
with compliance demonstrations are due by February 28, 2011.
    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.
    As discussed in Section IV.B., we are utilizing the EIA projection 
of 5.04 million gallons (6.5 million ethanol equivalent gallons) of 
cellulosic biofuel as the basis for setting the percentage standard for 
cellulosic biofuel for 2010. This is lower than the 100 million gallon 
standard set by EISA that we proposed upholding, but reflects the 
current state of the industry, as discussed in section V.B. We expect 
continued growth in the industry in 2011 and beyond. Since the advanced 
biofuel standard is met by just the biomass-based diesel volume 
required in 2010, and additional volumes of other advanced biofuels 
(e.g., sugarcane ethanol) are available as well, no change to the 
advanced biofuel standard is necessary for 2010. Moreover, given the 
nested nature of the volume mandates, since no change in the advanced 
biofuel standard is necessary, the total renewable fuel standard need 
not be changed either.

                  Table II.E.1.b-1--Standards for 2010
------------------------------------------------------------------------
                                                               Percent
------------------------------------------------------------------------
Cellulosic biofuel........................................         0.004
Biomass-based diesel......................................         1.10
Advanced biofuel..........................................         0.61
Renewable fuel............................................         8.25
------------------------------------------------------------------------

2. Treatment of Biomass-Based Diesel in 2009 and 2010
    As described in Section I.A.2, the four separate 2010 standards 
issued in today's rule will apply to all gasoline and diesel produced 
in 2010. However, EISA included volume mandates for biomass-based 
diesel, advanced biofuel, and total renewable fuel that applied in 
2009. Since the RFS2 program was not effective in 2009 and thus the 
volume mandates for biomass-based diesel and advanced biofuel were not 
implemented in 2009, our NPRM proposed a mechanism to ensure that the 
2009 biomass-based diesel volume mandate would eventually be met. In 
today's final rule we are finalizing the proposed approach.
a. Shift in 2009 Biomass-Based Diesel Compliance Demonstration to 2010
    Under the RFS1 regulations that applied in 2009, we set the 
applicable standard for total renewable fuel in November 2008 \20\ 
using the required volume of 11.1 billion gallons specified in the 
Clean Air Act (as amended by EISA), gasoline volume projections from 
EIA, and the formula provided in the regulations at Sec.  80.1105(d). 
The existing RFS1 regulations did not provide a mechanism for requiring 
the use of 0.5 billion gallons of biomass-based diesel or the 0.6 
billion gallons of advanced biofuel mandated by EISA for 2009.
---------------------------------------------------------------------------

    \20\ See 73 FR 70643 (November 21, 2008).
---------------------------------------------------------------------------

    In the NPRM we proposed that the compliance demonstration for the 
2009 biomass-based diesel requirement of 0.5 bill gal be extended to 
2010. This approach would combine the 0.5 bill gal requirement for 2009 
and the 0.65 bill gal requirement for 2010 into a single requirement of 
1.15 bill gal for which compliance demonstrations would be made by 
February 28, 2011. As described in the NPRM, we believe that the 
deficit carryover provision provides a conceptual mechanism for this 
approach, since it would have allowed obligated parties to defer 
compliance with any or all of the 2009 standards until 2010. We are 
finalizing this approach in today's action. We believe it will ensure 
that these two year's worth of biomass-based diesel will be used, while 
providing reasonable lead time for obligated parties. It avoids a 
transition that fails to have any requirements related to the 2009 
biomass-based diesel volume, and instead requires the use of the 2009 
volume but achieves 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 were unable to issue final 
regulations prior to the 2009 compliance year. We announced our 
intentions to implement the 2009 and 2010 biomass-based diesel 
requirements in this manner in the November 2008 Federal Register 
notice cited previously. We reiterated these intentions in our NPRM. 
Thus, obligated parties will have had sufficient lead time to acquire a 
sufficient number of biomass-based diesel RINs by the end of 2010 to 
comply with the standard based on 1.15 bill gal.
    Data available at the time of this writing suggests that 
approximately 450 million gallons of biodiesel was produced in 2009, 
thus requiring 700 million gallons to be produced in 2010 to satisfy 
the combined 2009 and 2010 volume mandates. Information from commenters 
and other contacts in the biodiesel industry indicate that feedstocks 
and production facilities will be available in 2010 to produce this 
volume.
    Refiners generally commented that the proposed approach to 2009 and 
2010 biomass-based diesel volumes was not appropriate and should not be 
implemented. They also recommended that the RFS2 program should be made 
effective on January 1, 2011 with no carryover of any previous-year 
obligations for biomass-based diesel or any other volume mandate. In 
contrast, the National Biodiesel Board and several individual biodiesel 
producers supported the proposed approach, but believed it was 
insufficient to compel obligated parties to purchase biodiesel in 2009, 
something they considered critical to the survival of the biodiesel 
industry. Many of these commenters requested that we conduct an interim 
rulemaking that would apply to 2009 to implement the EISA mandated 
volume of 0.5 billion gallons of biomass-based diesel. If the RFS2 
program could not be implemented until 2011, they likewise requested 
that interim measures be taken for 2010 to ensure that the full 1.15 
bill gal requirement would be implemented. However, putting in place 
this new volume requirement without also putting in place EISA's new 
definition for biomass-based diesel, renewable fuel, and renewable 
biomass

[[Page 14719]]

would have raised significant legal and policy issues that would 
necessarily have required a new proposal with its own public notice and 
comment process. Because of the significant time required for notice 
and comment rulemaking, the need to provide industry with adequate lead 
time for new requirements, and the fact that we were already well into 
calendar year 2009 at the time the request for an interim rule was 
received, it was unlikely that any interim rule could have impacted 
biodiesel demand in 2009. Moreover, Agency resources applied to the 
interim rulemaking would have been unavailable for development of the 
final RFS2 rulemaking. Developing an interim rule could have undermined 
EPA's ability to complete the full RFS2 program regulations in time for 
2010 implementation. As a result, we did not pursue an interim 
rulemaking.
    With regard to advanced biofuel, it is not necessary to implement a 
separate requirement for the 0.6 billion gallon mandate for 2009. Due 
to the nested nature of the volume requirements and the fact that 
Equivalence Values will be based on the energy content relative to 
ethanol, the 0.5 billion gallon requirement for biomass-based diesel 
will count as 0.75 billion gallons of advanced biofuel, exceeding the 
requirement of 0.6 billion gallons. Thus compliance with the biomass-
based diesel requirement in 2009 automatically results in compliance 
with the advanced biofuel standard.
    All 2009 biodiesel and renewable diesel RINs, identifiable through 
an RR code of 15 or 17 respectively under the RFS1 regulations, will 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 is consistent with our approach to any 
other standard for any other year and consistent with the flexibility 
available to any obligated party that carries 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.
    We did not reduce the 2009 volume requirement for total renewable 
fuel by 0.5 billion gallons to account for the fact that we intended to 
move the compliance demonstration for this volume has been moved to the 
2010 compliance period. Instead, we are allowing 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). To accomplish this, we proposed in the 
NPRM that an obligated party would add up the 2009 biodiesel and 
renewable diesel RINs that he used for 2009 compliance with the RFS1 
standard for total renewable fuel, and reduce his 2010 biomass-based 
diesel obligation by this amount. Thus, 2009 biodiesel and renewable 
diesel RINs are essentially used twice. Any remaining 2010 biomass-
based diesel obligation would need to be covered either with 2009 
biodiesel and renewable diesel RINs that were not used for compliance 
in 2009 or with 2010 biomass-based diesel RINs. We are finalizing this 
approach in today's notice.
b. Treatment of Deficit Carryovers, RIN Rollover, and RIN Valid Life 
for Adjusted 2010 Biomass-Based Diesel Requirement
    Our transition approach for biomass-based diesel is conceptually 
similar, but not identical, to the statutory deficit carryover 
provision. In a typical deficit carryover situation, an obligated party 
can carry forward any amount of a current-year deficit to the following 
year. In the absence of any modifications to the deficit carryover 
provisions for our biomass-based diesel transition 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. As described in the NPRM, we believe that the deficit 
carryover provisions should be modified in the context of the 
transition biomass-based diesel approach to more closely represent what 
would have occurred if we had been able to implement the 0.5 bill gal 
requirement in 2009. Specifically, we are prohibiting obligated parties 
from carrying over a biomass-based diesel deficit into 2011 larger than 
that based on the 0.65 bill gal volume requirement for 2010. This is 
the amount that would have been permitted had we been able to implement 
the biomass-based diesel requirements in 2009. In practice, this means 
that deficit carryovers from 2010 into 2011 for biomass-based diesel 
cannot not exceed 57% (0.65/1.15) of an obligated party's 2010 RVO. 
This approach also helps to ensure a minimum volume mandate for 
companies producing biomass-based diesel each year.
    Similarly, in the absence of any modifications to the provisions 
regarding valid life of RINs, 2008 biodiesel and renewable diesel RINs 
could not be used for compliance in 2010 with the adjusted biomass-
based diesel standard, despite the fact that the 2010 standard includes 
the 2009 requirement for which 2008 RINs should be valid. The National 
Biodiesel Board opposed this approach on the basis that the use of 2008 
RINs for 2010 compliance demonstrations violated the 2-year valid life 
limit for RINs. However, since the 2010 compliance demonstration will 
include the obligation that would have applied in 2009, and 2008 RINs 
would be valid for 2009 compliance, we are allowing excess 2008 
biodiesel and renewable diesel RINs that were not used for compliance 
purposes in 2008 to be used for compliance purposes in 2009 or 2010.
    As described in Section III.D, we are requiring the 20% RIN 
rollover cap to apply in all years, and separately for all four 
standards. However, consistent with our approach to deficit carryovers, 
we believe that an additional constraint is warranted in the 
application of the rollover cap to the biomass-based diesel obligation 
in the 2010 compliance year to more closely represent what would have 
occurred if we had been able to implement the 0.5 bill gal requirement 
in 2009. Specifically, we are limiting the use of excess 2008 RINs to 
20% of the statutory 2009 requirement of 0.5 bill gal. This is 
equivalent to 0.1 bill gal (20% of 0.5 bill gal), or 8.7% of the 
combined 2009/2010 obligation of 1.15 bill gal (0.1/1.15). Thus, 
obligated parties will be allowed to use excess 2008 and 2009 biodiesel 
and renewable diesel RINs for compliance with the 2010 combined 
standard of 1.15 bill gal, so long as the sum of all previous-year RINs 
(2008 plus 2009 RINs) does not exceed 20% of their 2010 obligation, and 
the 2008 RINs do not exceed 8.7% of their 2010 obligation.
    Under RFS1, RINs are generated when renewable fuel is produced, but 
if the fuel is ultimately used for purposes other than as motor vehicle 
fuel the RINs must generally be retired. Under EISA, however, RINs 
generated for renewable fuel that is ultimately used for nonroad 
purposes, heating oil, or jet fuel are valid for compliance purposes. 
To more closely align our transition approach for biomass-based diesel 
to what could have occurred if we had issued the RFS2 standards prior 
to 2009, we are allowing 2009 RINs that are retired because they are 
ultimately used for nonroad, heating oil or jet fuel purposes to be 
valid for compliance with the 2010 standards. Such RINs can

[[Page 14720]]

be reinstated by the retiring party in 2010.
3. Future Standards
    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 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 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. These 
provisions will be implemented as part of an annual standard-setting 
process.

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 all 
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 II.G below, under this rule, the sum of all highway and 
nonroad gasoline and diesel fuel produced or imported within a calendar 
year will be the basis on which the RVOs are calculated. This section 
provides our final definition of gasoline and diesel for the purposes 
of the RFS2 program.
1. Gasoline
    As with the RFS1 rule, the volume of gasoline used in calculating 
the RVO under RFS2 will 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 includes 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) or exported 
gasoline, will 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 will 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 will 
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 including in a party's obligated volume are 
collectively called ``gasoline.''
    Also consistent with the RFS1 program, we are continuing the 
exclusion of any volume of renewable fuel contained in gasoline from 
the volume of gasoline used to determine the renewable fuels 
obligations. This exclusion applies 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 will 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 
the statute, and EPA excludes ethanol and other renewable fuels that 
are 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 rule, Gasoline Treated as Blendstock (GTAB) will 
continue to be treated as a blendstock under the RFS2 program, and thus 
will 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, will 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 will 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 will be 
included in the volume of gasoline used to determine the renewable fuel 
obligation.
2. Diesel
    EISA expanded the RFS program to include transportation fuels other 
than gasoline, thus both highway and nonroad diesel must be used in 
calculating a party's RVO. 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) will be required to include the volume of that 
diesel fuel in the determination of its RVO under the RFS2 rule. Diesel 
fuel includes 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 
fuel produced for use in highway diesel engines and vehicles), NRLM 
(diesel fuel produced for use in nonroad, locomotive, and marine diesel 
engines and equipment/vessels), NR (diesel fuel produced for use in 
nonroad engines and equipment), and LM (diesel fuel produced for use in 
locomotives and marine diesel engines and vessels).\21\ Transportation 
fuels meeting

[[Page 14721]]

the definition of MVNRLM will be used to calculate the RVOs, and 
refiners, blenders, or importers of MVNRLM will 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, 
will not be subject to the applicable percentage standard and will not 
be used to calculate the RVOs.\22\ We requested 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.
---------------------------------------------------------------------------

    \21\ 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.
    \22\ See 40 CFR 80.598(a) for the kinds of fuel types used by 
refiners or importers in designating their diesel fuel.
---------------------------------------------------------------------------

    One commenter expressed support for including heating oil and jet 
fuel into the RIN program, but not to subject these fuels to the RVO 
mandate. The commenter stated that fluctuating weather conditions make 
it hard to predict with any reliability the volumes of heating oil that 
will be used in a given year. Another commenter stated that it supports 
the extension of the RFS program to transportation fuels, including 
diesel and nonroad fuels.
    With respect to fuels for use in ocean-going vessels, EISA 
specifies that ``transportation fuels'' do not include such fuels. We 
are interpreting that ``fuels for use in ocean-going vessels'' means 
residual or distillate fuels other than MVNRLM intended to be used to 
power large ocean-going vessels (e.g., those vessels that are powered 
by Category 3 (C3), and some Category 2 (C2), marine engines and that 
operate internationally). Thus, fuel for use in ocean-going vessels, or 
that an obligated party can verify as having been used in an ocean-
going vessel, will be excluded from the renewable fuel standards. Also, 
in the context of the recently finalized fuel standards for C3 marine 
vessels, this would mean that fuel meeting the 1,000 ppm fuel sulfur 
standard would not be considered obligated volume, while all MVNRLM 
diesel fuel would.
3. Other Transportation Fuels
    Transportation fuels other than gasoline or MVNRLM diesel fuel 
(natural gas, propane, and electricity) will 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 portion used 
in the transportation sector from the large portion used in other 
sectors (in fact, the producer may have no knowledge of its ultimate 
use). We will reconsider this approach if and when these volumes grow. 
At the same time, it is clear that these fuels can be used as 
transportation fuel, and under certain circumstances, producers of such 
``other transportation fuels'' may generate RINs as a producer or 
importer of a renewable fuel. See Section II.D.2.a for further 
discussion of other RIN-generating fuels.

G. Renewable Volume Obligations (RVOs)

    Under RFS1, each obligated party was required to determine its RVO 
based on the applicable percentage standard and its annual gasoline 
volume. The RVO represented the volume of renewable fuel that the 
obligated party was required to ensure was used in the U.S. in a given 
calendar year. Obligated parties were required to meet their RVO 
through the accumulation of RINs which represent the amount of 
renewable fuel used as motor vehicle fuel that was sold or introduced 
into commerce within the U.S. Each gallon-RIN counted as one gallon of 
renewable fuel for compliance purposes.
    We are maintaining this approach to compliance under the RFS2 
program. However, one primary difference between RFS1 and the new RFS2 
program in terms of demonstrating compliance is that each obligated 
party now has four RVOs instead of one (through 2012) or two (starting 
in 2013) under the RFS1 program. Also, as discussed above, RVOs are now 
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 deemed to have satisfied their obligation to cause the 
renewable fuel represented by the RINs to be consumed as transportation 
fuel in highway or nonroad vehicles or engines. Obligated parties are 
not required to physically blend the renewable fuel into gasoline or 
diesel fuel themselves. The accumulation of RINs will 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 can retain the excess RINs for use in 
complying with its RVOs in the following year (subject to the 20% 
rollover cap discussed in Section III.D) 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 can 
carry a deficit into the next year.
    This section describes our approach to the calculation of RVOs 
under RFS2 and the RINs that are valid for demonstrating compliance 
with those RVOs. This includes a description of the special treatment 
that must be applied to RFS1 RINs used for compliance purposes under 
RFS2, since RINs generated under RFS1 regulations are not exactly the 
same as those generated in under RFS2.
1. Designation of Obligated Parties
    In the NPRM, we proposed to continue to designate obligated parties 
under the RFS2 program as they were designated under RFS1, with the 
addition of diesel fuel producers and importers. Regarding gasoline 
producers and importers, we proposed that obligated parties who are 
subject to the standard would be 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 would include 
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, would not be included in the volume used to determine the RVO, 
except where the blendstock was combined with other blendstock or 
finished gasoline to produce finished gasoline, RBOB, or CBOB. Thus, 
parties downstream of a refinery or importer would only be obligated 
parties to the degree that they use non-renewable blendstocks to make 
finished gasoline, RBOB, CBOB, or diesel fuel.
    We also took comment on two alternative approaches to the 
designation of obligated parties:

--Elimination of 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, thereby moving a portion of the obligation to downstream 
blenders of renewable fuels into RBOB and CBOB.
--Moving the obligations for all gasoline and diesel downstream of 
refineries and importers to parties who supply finished transportation 
fuels to retail outlets or to wholesale purchaser-consumer facilities.

[[Page 14722]]

These alternative approaches have the potential to more evenly align a 
party's access to RINs with that party's obligations under the RFS2 
program. As described more fully in the NPRM, we considered these 
alternatives because of market conditions that had changed since the 
RFS1 program began. For instance, obligated parties who have excess 
RINs have been observed to retain rather than sell them to ensure they 
have a sufficient number for the next year's compliance. This was most 
likely to occur with major integrated refiners who operate gasoline 
marketing operations and thus have direct access to RINs for ethanol 
blended into their gasoline. Refiners whose operations are focused 
primarily on producing refined products with less marketing do not have 
such direct access to RINs and could potentially find it difficult to 
acquire a sufficient number for compliance despite the fact that the 
total nationwide volume of renewable fuel meets or exceeds the 
standard. The result might be a higher price for RINs (and fuel) in the 
marketplace than would be expected under a more liquid RIN market. For 
similar reasons, we also took comment on possible changes to the 
requirement that RINs be transferred with volume through the 
distribution system as discussed more fully in Section II.H.4.
    In response to the NPRM, stakeholders differed significantly on 
whether EPA should implement one of these alternative approaches. For 
instance, while some refiners expressed support for moving the 
obligations to downstream parties such as blenders, terminals, and/or 
wholesale purchaser-consumers, other refiners preferred to maintain the 
current approach. Blenders and other downstream parties generally 
expressed opposition to a change in the designation of obligated 
parties, citing the additional burden of demonstrating compliance with 
the standard especially for small businesses. They also pointed to the 
need to implement new systems for determining and reporting compliance, 
the short leadtime for doing so, and the fewer resources that smaller 
downstream companies have to manage such work in comparison to the much 
larger refiners. Finally, they pointed to the additional complexity 
that would be added to the RFS program beyond that which is necessary 
to carry out the renewable fuels mandate under CAA section 211(o).
    When the RFS1 regulations were drafted, the obligations were placed 
on the relatively small number of refiners and importers rather than on 
the relatively large number of downstream blenders and terminals in 
order to minimize the number of regulated parties and keep the program 
simple. However, with the expanded RFS2 mandates, essentially all 
downstream blenders and terminals are now regulated parties under RFS2 
since essentially all gasoline will be blended with ethanol. Thus the 
rationale in RFS1 for placing the obligation on just the upstream 
refiners and importers is no longer valid. Nevertheless, based on the 
comments we received, we do not believe that the concerns expressed 
warrant a change in the designation of obligated parties for the RFS2 
program at this time. We continue to believe that the market will 
provide opportunities for parties who are in need of RINs to acquire 
them from parties who have excess. Refiners who market considerably 
less gasoline or diesel than they produce can establish contracts with 
splash blenders to purchase RINs. Such refiners can also purchase 
ethanol from producers directly, separate the RINs, and then sell the 
ethanol without RINs to blenders. Since the RFS program is based upon 
ownership of RINs rather than custody of volume, refiners need never 
take custody of the ethanol in order to separate RINs from volumes that 
they own. Moreover, a change in the designation of obligated parties 
would result in a significant change in the number of obligated parties 
and the movement of RINs, changes that could disrupt the operation of 
the RFS program during the transition from RFS1 to RFS2.
    We will continue to evaluate the functionality of the RIN market. 
Should we determine that the RIN market is not operating as intended, 
driving up prices for obligated parties and fuel prices for consumers, 
we will consider revisiting this provision in future regulatory 
efforts.
    In the NPRM we also took comment on several other possible ways to 
help ensure that obligated parties can demonstrate compliance. For 
instance, one alternative approach would have left our proposed 
definitions for obligated parties in place, but would have added 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. Stakeholders generally opposed this 
change, agreeing with our assessment that it would be extremely 
difficult to implement given that RBOB and CBOB are often transferred 
between multiple parties prior to ethanol blending. As a result, a 
regulatory requirement for RIN transfers back to the original producer 
would have necessitated 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 have not 
finalized this alternative approach.
    Another alternative approach on which we took comment would have 
allowed use of RINs that expire without being used for compliance by an 
obligated party to be used to reduce the nationwide volume of renewable 
fuel required in the following year. This alternative approach could 
have helped to prevent the hoarding of RINs from driving up demand for 
renewable fuel. However, it would also effectively alter the valid life 
limit for RINs. Comments from stakeholders did not change our position 
that such an approach is not warranted at this time, and thus we have 
not finalized it.
2. Determination of RVOs Corresponding to the Four Standards
    In order for an obligated party to demonstrate compliance, the 
percentage standards described in Section II.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 will 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 follows the same format as 
the formulas in the RFS1 regulations at Sec.  80.1107(a), with one 
modification. The standards for a particular compliance year must 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 RFS1 program.\23\ To the degree that an 
obligated party did not demonstrate full compliance with its RVOs for 
the previous year, the shortfall will 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 each of its RVOs including the deficit 
carryover

[[Page 14723]]

in the second year. Thus deficit carryovers cannot occur two years in 
succession for any of the four individual standards. They can, however, 
occur as frequently as every other year for a given obligated party for 
each standard.
---------------------------------------------------------------------------

    \23\ 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 will have an 
obligation for all four standards even though he will 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 will not have an opportunity to blend biomass-
based diesel into his own diesel fuel.
3. 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 can be used to meet each of the four 
standards.
    As described in Section I.A.1, the volume requirements in EISA are 
generally nested within one another, so that any fuel that satisfies 
the advanced biofuel requirement also satisfies the total renewable 
fuel requirement, and fuel that meets either the cellulosic biofuel or 
the biomass-based diesel requirements also satisfies the advanced 
biofuel requirement. As a result, the RINs that can be used to meet the 
four standards are likewise nested. Using the D codes defined in Table 
II.A-1, the RFS2 RINs that can be used to meet each of the four 
standards are shown in Table II.G.3-1. RFS1 RINs generated in 2010 and 
identified by a D code of 1 or 2 can also be applied to these standards 
using the protocol described in Section II.G.4 below.

       Table II.G.3-1--RINs That Can Be Used To Meet Each Standard
------------------------------------------------------------------------
           Standard                 Obligation       Allowable D codes
------------------------------------------------------------------------
Cellulosic biofuel............  RVOCB............  3 and 7.
Biomass-based diesel..........  RVOBBD...........  4 and 7.
Advanced biofuel..............  RVOAB............  3, 4, 5, and 7.
Renewable fuel................  RVORF............  3, 4, 5, 6, and 7.
------------------------------------------------------------------------

    The nested nature of the four standards also means that in some 
cases 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 3 
can be used to meet three of the four standards, while a RIN with a D 
code of 5 can be used to meet both the advanced biofuel and total 
renewable fuel standards. However, a D code of 6 can only be used to 
meet the renewable fuel standard. Consistent with our proposal, we are 
continuing to prohibit the use of a single RIN for compliance purposes 
in more than one year or by more than one party.\24\
---------------------------------------------------------------------------

    \24\ Note that we are finalizing an exception to this general 
prohibition for the specific and limited case of 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 II.E.2.a.
---------------------------------------------------------------------------

4. Treatment of RFS1 RINs Under RFS2
    As described in the introduction to this section, we are 
implementing a number of changes to the RFS program as a result of the 
requirements in EISA. These changes will go into effect on July 1, 2010 
and, among other things, will 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 these RFS2 regulations will not 
be exactly the same as RINs generated under RFS1 regulations. 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. Also, since RINs generated in 
January through June of 2010 will be generated under RFS1 regulations, 
we must provide a means for them to be used to meet the annual 2010 
RFS2 standards. Finally, we must address deficit carryovers from 2009 
to 2010, since the total renewable fuel standards in these two years 
will be defined differently.
a. Use of RFS1 RINs To Meet Standards Under RFS2
    In 2009 and the first three months of 2010, 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 under 
RFS1 regulations meet any of these criteria. However, we believe that 
the vast majority of RFS1 RINs generated in 2009 and the first two 
months of 2010 will 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 and the first three months of 2010 will 
meet the prerequisites for this exemption. Second, it is unlikely that 
renewable fuels produced in 2009 or the first three months of 2010 will 
have been made from feedstocks that do not meet the new renewable 
biomass definition. It is very unlikely that new land would have been 
cleared or cultivated since December 19, 2007 for use in growing crops 
for renewable fuel production, and thus the land use restrictions 
associated with the renewable biomass definition will very likely be 
met. 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 RFS1 RINs generated in 2009 and early 2010 to be valid to show 
compliance for the annual 2010 obligations.
    The separate definitions for cellulosic biofuel and biomass-based 
diesel require GHG thresholds of 60% and 50%, respectively. While we do 
not have a mechanism in place to determine if these thresholds have 
been met for RFS1 RINs generated in 2009 or early 2010, any shortfall 
in GHG performance for this one transition period is unlikely to have a 
significant impact on long-term GHG benefits of the program. Few 
stakeholders commented on our proposed treatment of RFS1 RINs under 
RFS2. Of those that did, most supported our proposed approach to the 
use of RFS1 RINs to meet RFS2 obligations. Based on our belief that it 
is critical to

[[Page 14724]]

the smooth operation of the program that excess 2009 RINs be allowed to 
be used for compliance purposes in 2010, we are allowing RFS1 RINs that 
were generated in 2009 or 2010 representing cellulosic biomass ethanol 
to be valid for use in satisfying the 2010 cellulosic biofuel standard. 
Likewise, we are allowing RFS1 RINs that were generated in 2009 or 2010 
representing biodiesel and renewable diesel to be valid for use in 
satisfying the 2010 biomass-based diesel standard.
    Consistent with our proposal, we have used 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 under 
RFS1 regulations must be identified with a D code of 1, and these fuels 
will be valid for meeting the cellulosic biofuel standard under RFS2. 
Our final treatment of RFS1 RINs for compliance under RFS2 is shown in 
Table II.G.4.a-1.

                      Table II.G.4.a-1--Treatment of RFS1 RINs for RFS2 Compliance Purposes
----------------------------------------------------------------------------------------------------------------
      RINs generated under RFS1 \a\                               Treatment under RFS2 \b\
----------------------------------------------------------------------------------------------------------------
Any RIN with D code of 2 and RR code of    Equivalent to RFS2 RINs with D code of 4.
 15 or 17.
All other RINs with D code of 2..........  Equivalent to RFS2 RINs with D code of 6.
Any RIN with D code of 1.................  Equivalent to RFS2 RINs with D code of 3.
----------------------------------------------------------------------------------------------------------------
\a\ See RFS1 RIN code definitions at Sec.   80.1125.
\b\ See RFS2 RIN code definitions at Sec.   80.1425.

b. Deficit Carryovers From the RFS1 Program to RFS2
    The calculation of RVOs in 2010 under the RFS2 regulations will be 
somewhat different than the calculation of RVOs in 2009 under RFS1. In 
particular, 2009 RVOs were based on gasoline production only, while 
2010 RVOs will 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 will 
undermine the goals of the program in requiring specific volumes of 
renewable fuel to be used each year. Although RVOs in 2009 and 2010 
will 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 implementing any special treatment for deficits 
carried over from 2009 to 2010.
    A deficit carried over from 2009 to 2010 will only affect a party's 
total renewable fuel obligation in 2010, as the 2009 obligation is for 
total renewable fuel use, not a subcategory. The RVOs for biomass-based 
diesel or advanced biofuel will not be affected, as they do not have 
parallel obligations in 2009 under RFS1.\25\
---------------------------------------------------------------------------

    \25\ There is no cellulosic biofuel standard for 2010.
---------------------------------------------------------------------------

H. Separation of RINs

    As we proposed in the NPRM, we are requiring the RFS1 provisions 
regarding the separation of RINs from volumes of renewable fuel to be 
retained for RFS2. However, the modifications in EISA required changes 
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 were 
required to be retired by the party who owned 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. However, EISA 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 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.
    Since RINs have a valid life of two years, the NPRM proposed that a 
2009 RFS1 RIN that is retired because the renewable fuel associated 
with it was used in nonroad vehicles or engines could be reinstated in 
2010 for use in compliance with the 2010 standards. Stakeholders 
supported this approach, and we are finalizing it in today's action.
2. Heating Oil and Jet Fuel
    EISA defines ``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.'' 
\26\ While we are not requiring fossil-based heating oil and jet fuel 
to be included in the fuel used by a refiner or importer to calculate 
their RVOs, we are allowing renewable fuels used as or in heating oil 
and jet fuel to generate RINs. Similarly, RINs associated with a 
renewable fuel, such as biodiesel, that is blended into heating oil 
will continue to be valid for compliance purposes. See also discussion 
in Section II.B.1.e.
---------------------------------------------------------------------------

    \26\ EISA, Title II, Subtitle A--Renewable Fuel Standard, 
Section 201.
---------------------------------------------------------------------------

3. Exporters
    Under RFS1, exporters were assigned an RVO representing the volume 
of renewable fuel that was exported, and they were required to separate 
all RINs that were assigned to fuel that was exported. Since there was 
only one standard, there was 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, and total renewable fuel). However, given the 
fungible nature of the RIN system and the fact that an

[[Page 14725]]

assigned RIN transferred with a volume of renewable fuel may not be the 
same RIN that was originally generated to represent that volume, RINs 
from different fuel types can accompany volumes. Thus, there may be no 
way for an exporter to determine from an assigned RIN which of the four 
categories applies to an exported volume. In order to determine its 
RVOs, the only information available to the exporter may be the type of 
renewable fuel that he is exporting.
    However, if an exporter knows, or has reason to know, that the 
renewable fuel that it is exporting is either cellulosic biofuel or 
advanced biofuel, we are requiring the exporter to determine an RVO for 
the exported fuel based upon these fuel types. For instance, if an 
exporter purchases cellulosic biofuel or advanced biofuel directly from 
a producer or if the fuel has been segregated from other fuels, we 
would expect the exporter to know or have reason to know the type of 
fuel that it is exporting. Another example of when we would expect an 
exporter to know or have reason to know that the fuel that it is 
exporting is cellulosic or advanced biofuel would be if the commercial 
documents that accompany the purchase or sale of the renewable fuel 
identify the product as cellulosic or advanced biofuel.
    EPA recognizes that in many situations, exporters will not know or 
have reason to know which of the four categories of renewable fuel 
apply to the exported fuel. If this is the case, we are requiring 
exporters to follow the approach proposed in the NPRM. Exported volumes 
of biodiesel (mono alkyl esters) and renewable diesel must be used to 
determine the exporter's RVO for biomass-based diesel. For all other 
types of renewable fuel, the most likely category is general renewable 
fuel. Thus, we are requiring that all renewable fuels be used to 
determine the exporter's RVO for total renewable fuel. Our final 
approach is provided at Sec.  80.1430.
    In the NPRM we took comment on an alternative approach in which the 
total nationwide volumes required in each year (see Table I.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, as described in the NPRM, we believe that this 
alternative approach would have added considerable complexity to the 
compliance determinations for exporters without necessarily adding more 
precision. Given the expected small volumes of exported renewable fuel, 
we continue to believe that this added complexity is not warranted at 
this time.
    As described above, exporters must separate any RINs assigned to 
renewable fuel that they export. However, since RINs are fungible and 
the owner of a batch of renewable fuel has the flexibility to assign 
between zero and 2.5 gallon-RINs to each gallon, we have made this 
flexibility explicit for exporters. Thus, an exporter can separate up 
to 2.5 gallon-RINs for each gallon of renewable fuel that he exports. 
While the exporter is not required to retain these separated RINs for 
use in complying with his RVOs calculated on the basis of the exported 
volumes, this would be the most straightforward approach and would 
ensure that the exporter has sufficient RINs to comply. However, we are 
aware of some exporters who sell RINs that they separate as a source of 
revenue, with the intention to purchase replacement RINs on the open 
RIN market later in the year to comply with their RVOs. At this time we 
are not aware of such activities resulting in noncompliance, and thus 
the RFS2 regulations promulgated today will continue to allow this. 
However, we may revisit this issue in the future if there is evidence 
that exporters are failing to comply because they are selling RINs that 
they separate from exported volumes.
4. Requirement To Transfer RINs With Volume
    In the NPRM, we proposed that the approach to RIN transfers 
established under RFS1--that RINs generated by renewable fuel producers 
and importers must be assigned to batches of renewable fuel and 
transferred along with those batches--be continued under RFS2. However, 
given the higher volumes required under RFS2 and the resulting 
expansion in the number of regulated parties, we also took comment on 
two alternative approaches to RIN transfers. Along with the alternative 
approaches for designation of obligated parties as described in Section 
II.G.1 above, a change to the requirement to transfer RINs with batches 
had the potential to more evenly align a party's access to RINs with 
that party's obligations under the RFS2 program. Nevertheless, for the 
reasons described below, we have determined that it would not be 
appropriate to implement these alternative approaches at this time.
    In the first alternative approach, we would have removed 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 have sold RINs (with a 
K code of 2 rather than 1) separately from volumes of renewable fuel to 
any party.
    In the second alternative approach, producers and importers of 
renewable fuels would be required to separate and transfer the RIN, but 
only to an obligated party. 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. Any RINs 
not sold in this way would be required to be offered for sale to any 
obligated party through a public auction. Only renewable fuel 
producers, importers, and obligated parties would be allowed to own 
RINs.
    Many renewable fuel producers supported the concept of allowing 
them to separate the RINs from renewable fuel that they produce. They 
generally argued in favor of a free market approach to RINs in which 
there would be no restrictions on whom they could sell RINs to, or in 
what timeframe. The direct transfer approach was unnecessary, they 
argued, since the market would compel them to sell all RINs they 
generated, and all RINs would eventually end up in the hands of the 
obligated parties that need them. However, other renewable fuel 
producers opposed any change to the requirement that RINs be assigned 
to volumes of renewable and transferred with those volumes through the 
distribution system. They argued that the system established under RFS1 
has proven to work and it would create an unwarranted burden to require 
producers to modify their IT systems for RFS2.
    Marketers and distributors were generally opposed to our proposed 
alternative approaches to RIN transfers. Moreover, SIGMA and NACS, as 
in the RFS1 rulemaking process, recommended that RINs not be generated 
by producers at all, but rather by the party that blends renewable fuel 
into gasoline or diesel, or uses renewable fuel in its neat form as a 
transportation fuel.

[[Page 14726]]

    Obligated parties generally opposed any change to the RFS1 
requirement that RINs be assigned to volumes of renewable fuel by the 
producer or importer, and transferred with volumes through the 
distribution system. They reiterated their concern, first raised in the 
RFS1 rulemaking, that a free market approach would place them at 
greater risk of market manipulation by renewable fuel producers. 
Moreover, while generally expressing support for the concept of a 
direct transfer approach, they also expressed doubt that the auctions 
could be regulated in such a way as 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. These concerns were exacerbated by the 
nested standards required by EISA, under which many obligated parties 
have expressed concern about being able to acquire sufficient RINs for 
compliance.
    Given the significant challenges associated with a change to the 
requirement that RINs be transferred with volume and the opposing views 
among stakeholders, we are not making any change in today's final rule.
5. Neat Renewable Fuel and Renewable Fuel Blends Designated as 
Transportation Fuel, 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. 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. While 
EPA understands that in the vast majority of cases, biodiesel is 
blended with diesel in concentrations of 80 volume percent or less, 
there may be instances in which biodiesel is blended with diesel in 
concentrations of more than 80 percent biodiesel, but the blender is 
prohibited from separating RINs under the RFS1 regulations.
    Thus, in order to account for situations in which biodiesel blends 
of 81 percent or greater may be used as transportation fuel, heating 
oil, or jet fuel without ever having been owned by an obligated party, 
EPA proposed, and is finalizing a change to the applicability of the 
RIN separation provisions for RFS2. Section 80.1429(b)(4) will allow 
for separation of RINs for neat renewable fuel or blends of renewable 
fuel and diesel fuel that the party designates as transportation fuel, 
heating oil, or jet fuel, provided the neat renewable fuel or blend is 
used in the designated form, without further blending, as 
transportation fuel, heating oil, or jet fuel. Those parties that blend 
renewable fuel with gasoline or diesel fuel (in a blend containing 80 
percent or less biodiesel) must separate RINs pursuant to Sec.  
80.1429(b)(2).
    Thus, for example, if a party intends to separate RINs from a 
volume of B85, the party must designate the blend for use as 
transportation fuel, heating oil, or jet fuel and the blend must be 
used in its designated form without further blending. The party is also 
required to maintain records of this designation pursuant to Sec.  
80.1454(b)(5). Finally, the party is required to comply with the 
proposed PTD requirements in Sec.  80.1453(a)(11)(iv), which serve to 
notify downstream parties that the volume of fuel has been designated 
for use as transportation fuel, heating oil, or jet fuel, and must be 
used in that designated form without further blending. Parties may 
separate RINs at the time they comply with the designation and PTD 
requirements, and do not need to physically track ultimate fuel use.

I. Treatment of Cellulosic Biofuel

1. Cellulosic Biofuel Standard
    EISA requires 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 based on EIA estimates 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 total renewable fuel 
and advanced biofuels requirement by the same or a lesser volume. We 
will examine EIA's projected volumes and other available data including 
the required production outlook reports discussed in Section II.K to 
decide the appropriate standard for the following year. The outlook 
reports from all renewable fuel producers will assist EPA in 
determining what the cellulosic biofuel standard should be and if the 
total renewable fuel and/or advanced biofuel standards 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.
    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 may 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. Thus, the Act requires EPA to examine the total and advanced 
renewable fuel standards and volumes in the event of a cellulosic 
volume waiver. EPA will look at projections for each year on an 
individual yearly basis to determine if the standards should be 
adjusted. EPA believes that since the standards are nested and the 
total and advanced renewable fuel volume mandates are met in part by 
the cellulosic volume mandate, Congress gave EPA the flexibility to 
lower the required total and advanced volumes, but Congress also wanted 
to encourage the development of advanced renewable fuels as well and 
allow in appropriate circumstances for the use of those fuels in the 
event they can meet that year's required volumes that would have been 
met by the cellulosic mandate.
2. EPA Cellulosic Biofuel Waiver Credits for Cellulosic Biofuel
    Whenever EPA sets the cellulosic biofuel standard at a level lower 
than that required in EISA, but greater than zero, 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. The inflation adjustment will be based on the standard US 
inflation measure Consumer Price Index for All Urban Consumers (CPI-U) 
for All Items

[[Page 14727]]

expenditure category as provided by the Bureau of Labor Statistics.\27\
---------------------------------------------------------------------------

    \27\ 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.''
    We have fashioned a number of limitations on the use of cellulosic 
that reflect these considerations. Specifically, the credits will be 
called ``Cellulosic Biofuel Waiver Credits'' (or ``waiver credits'') so 
that there is no confusion with RINs or allowances used in the acid 
rain program. Such waiver credits will only be available for the 
current compliance year for which we have waived some portion of the 
cellulosic biofuel standard, they will only be available to obligated 
parties, and they will be nontransferable and nonrefundable. Further, 
obligated parties may only purchase waiver credits up to the level of 
their cellulosic biofuel RVO less the number of cellulosic biofuel RINs 
that they own. A company owning cellulosic biofuel RINs and cellulosic 
waiver credits may use both types of credits if desired to meet their 
RVOs, but unlike RINs obligated parties will not be able to carry 
waiver credits over to the next calendar year. Obligated parties may 
not use waiver credits to meet a prior year deficit obligation. These 
restrictions help ensure that waiver credits are not overutilized at 
the expense of actual renewable volume.
    In the NPRM, EPA proposed that the credits could be usable for the 
advanced and total renewable standards similarly to cellulosic biofuel 
RINs. Several commenters stated this provision could displace advanced 
and total renewable fuel that was actually produced which would be 
against the intent of the Act, and that unlike RINs a company should 
only be permitted to use waiver credits to meet its cellulosic biofuel 
obligation. We agree, and are limiting the use of waiver credits for 
compliance with only a company's cellulosic biofuel RVO.
    In the event the total volume of conventional gasoline and diesel 
fuel produced or imported in the country exceeds the projections used 
to set the standard, companies will still be able to purchase waiver 
credits up to their cellulosic volume obligation. When setting a 
reduced cellulosic biofuel standard EPA makes a determination that the 
cellulosic volume specified in EISA will not be met and that 
determination is not based on how much nonrenewable motor fuel will be 
produced. EPA sets the standard based on the volumes in the Act and a 
projection of gasoline production to ensure the obligation is broken up 
most equitably. EPA believes that Congress wanted all obligated parties 
to have equal access to the waiver credits in the event of the waiver 
and did not want obligated parties to incur a deficit due to the timing 
of when they purchased waiver credits.
    Cellulosic Biofuel Waiver Credits, in the event of a waiver, will 
be offered in a generic format rather than a serialized format, like 
RINs. Waiver credits can be purchased using procedures defined by the 
EPA, and 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. EPA will define these procedures with the U.S. Treasury before the 
end of the first annual compliance period. EPA will publish these 
procedures with the obligated party annual compliance report template. 
EPA will provide the forms necessary to purchase the credits. EPA 
intends to provide options for obligated parties to use Pay.Gov or if 
desired to mail payment to the U.S. Treasury.
    The wholesale price of gasoline used by EPA in setting the price of 
the waiver credits 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 available to EPA at the time it develops the 
cellulosic biofuel standard.\28\ EPA will use refinery gate price, U.S. 
Total Gasoline Bulk Sales (Price) by Refiners from EIA in calculating 
the average, since it is the price most reflective of what most 
obligated parties are selling their fuel. EPA will use the most recent 
twelve months of data provided by EIA to develop an average price on 
actual volumes produced in the year prior to the compliance year. In 
order to provide regulatory certainty, we will set the waiver credits 
price for the following year each November when and if we set a 
cellulosic biofuel standard for the following year that is based on 
achieving a lower volume of cellulosic biofuel use than is specified in 
EISA.
---------------------------------------------------------------------------

    \28\ 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/hist/LeafHandler.ashx?n=PET&s=A103B00002&f=M.
---------------------------------------------------------------------------

    For the 2010 compliance period, since the cellulosic standard is 
lower than the level otherwise required by EISA, we are also making 
cellulosic waiver credits available to obligated parties for end-of-
year compliance should they need them at a price of $1.56 per gallon-
RIN.'' The price for the 2011 compliance period, if necessary will be 
set when we announce the 2011 cellulosic biofuel standard.
3. Application of Cellulosic Biofuel Waiver Credits
    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 consequences. This could occur in situations where the 
cost of total renewable fuel RINs exceeds the cost of the cellulosic 
waiver credits. To prevent this, we sought comment on and are 
finalizing an additional restriction: An obligated party may only 
purchase waiver credits 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 applying 
any waiver credits to their cellulosic biofuel RVO.
    Even with this restriction the approach in the NPRM might not have 
operated as intended. For instance, if the combination of cellulosic 
biofuel volume price and RIN price were to become low compared to that 
for general renewable fuel, a small number of obligated parties could 
have purchased more cellulosic biofuel than they need to meet their 
cellulosic biofuel RVOs and could have used the additional cellulosic 
biofuel RINs to meet their advanced biofuel and total renewable fuel 
RVOs. Other obligated parties would then have had no access to 
cellulosic biofuel volume nor cellulosic biofuel RINs, and would have 
been forced to purchase waiver credits from the EPA. This situation 
would have had the net effect of waiver credits replacing advanced 
biofuels and/or general renewable fuel rather than cellulosic biofuel. 
Based on comments received on the NPRM, EPA is placing the additional 
restriction of only allowing the waiver credits to count

[[Page 14728]]

towards the cellulosic biofuel standard and not the advanced or 
renewable fuel standards.
    Moreover, under certain conditions it may be possible for the 
market price of general renewable fuel 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 waiver credits 
according to the statutory formula described in Section II.I.2 above. 
Under some conditions, this could result in a competitive disadvantage 
for cellulosic biofuel in comparison to corn ethanol, for example. 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 will be larger than for 
cellulosic ethanol producers. Under these conditions, while obligated 
parties may still purchase cellulosic ethanol volume and its associated 
RINs rather than waiver credits, cellulosic ethanol producers will 
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 waiver credits. 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.
    Finally, in the NPRM we sought comment on a ``dual RIN'' approach 
to cellulosic biofuel. In this approach, both cellulosic biofuel RINs 
(with a D code of 3) and waiver credits would have only been 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 5). The producer would have only 
been 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.\29\ The cellulosic biofuel and its attached 
advanced biofuel RIN would then have competed 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 have been effectively limited by the pricing formula for 
waiver credits as described in Section II.I.2. However, this approach 
would have been a more significant deviation from the RIN generation 
and transfer program structure that was developed cooperatively with 
stakeholders during RFS1. It would have provided 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. Therefore, EPA is 
treating the transfer of cellulosic RINs in the same manner as the 
other required volumes.
---------------------------------------------------------------------------

    \29\ The cellulosic biofuel RIN would be a separated RIN with a 
K code of 2 immediately upon generation.
---------------------------------------------------------------------------

J. Changes to Recordkeeping and Reporting Requirements

1. Recordkeeping
    Recordkeeping, including product transfer documents (PTDs), will 
support the enforcement of the use of RINs for compliance purposes. 
Parties are afforded significant freedom with regard to the form that 
PTDs take. Product codes may be used as long as they are understood by 
all parties, but they may not be used for transfers to truck carriers 
or to retailers or wholesale purchaser-consumers. 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. Parties must keep 
copies of records that relate to program flexibilities, such as small 
business-oriented provisions. Upon request, parties are responsible for 
providing their records to the Administrator or the Administrator's 
authorized representative. We reserve the right to request to receive 
documents in a format that we can read and use.
    In Section III.A. of this preamble, we describe an EPA-Moderated 
Transaction System (EMTS) for RINs. The new system allows for ``real-
time'' recording of transactions involving RINs.
2. Reporting
    Producers and importers who generate or take ownership of RINs 
shall submit RIN Transaction Reports \30\ and/or RIN Generation Reports 
quarterly. Renewable fuel exporters and obligated parties shall submit 
their RIN Transaction Reports quarterly, and RIN owners shall submit 
their RIN Transaction Reports quarterly. EMTS will be used by all 
parties to record ``real time'' generation of RINs and transactions 
involving RINs starting July 1, 2010. ``Real time'' means recordation 
within five (5) business days of generation or any transaction 
involving a RIN.
---------------------------------------------------------------------------

    \30\ For ease of reference, the current RFS (i.e. RFS1) form may 
be viewed at the EPA Fuels Reporting Web site at the following URL: 
http://www.epa.gov/otaq/regs/fuels/rfsforms.htm (accessed November 
16, 2009). These forms will be updated for RFS2.
---------------------------------------------------------------------------

    Quarterly reports are to be submitted on the following schedule. 
Quarterly reports include RIN Activity Reports and, with EMTS, 
simplified reporting and certification of the RIN Generation and RIN 
Transaction Reports.

               Table II.J-1--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.
------------------------------------------------------------------------

    Annual reports (covering January through December) would continue 
to be due on February 28. The only annual report is the Obligated Party 
Annual Compliance Report.\31\
---------------------------------------------------------------------------

    \31\ For RFS1, this form is numbered RFS0300.
---------------------------------------------------------------------------

    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. EMTS 
will also make use of the CDX environment.
    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 proposed several changes to the RIN Generation 
Report.\32\ We proposed 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. 
This final rule adopts the proposed approach. All renewable fuel 
producers and importers above 10,000 gallons per year must 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 is required to certify that his feedstock meets the definition 
of ``renewable biomass.'' If RINs are not generated, the producer or 
importer must state the reason for not generating RINs, such as they 
have documentation that states that

[[Page 14729]]

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 to generate RINs as a renewable fuel. For each batch of 
renewable fuel produced, we 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. In this final rule, we 
adopt the approach set forth in the notice of proposed rulemaking.
---------------------------------------------------------------------------

    \32\ For RFS1, this form is numbered RFS0400.
---------------------------------------------------------------------------

    In addition, we proposed two changes for the RIN Transaction 
Report.\33\ First, for reports of RINs assigned to a volume of 
renewable fuel, the volume of renewable fuel must be reported. Second, 
RIN price information must be submitted for transactions involving both 
separated RINs and RINs assigned to a renewable volume. This 
information was not collected under RFS1, but because we believe this 
information has great programmatic value to EPA, we proposed to collect 
it for RFS2. As we explained in the proposed rule, price information 
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. Our incomplete knowledge 
regarding RIN pricing for RFS1 adversely affected our ability to assess 
the general health and direction of the market and overall liquidity of 
RINs. Because we believe the inclusion of price information in reports 
will be beneficial to both EPA and to regulated parties, this final 
rule includes that information element in reports, as well as 
incorporating it as part of the ``real time'' transactional information 
collected via EMTS.
---------------------------------------------------------------------------

    \33\ For RFS1, this form is numbered RFS0200.
---------------------------------------------------------------------------

3. Additional Requirements for Producers of Renewable Natural Gas, 
Electricity, and Propane
    In addition to the general reporting requirement listed above, we 
are requiring an additional item of reporting for producers of 
renewable 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 are responsible for filing the 
same reports as other producers of RIN-generating renewable fuels, we 
are requiring that additional reporting for these producers 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 RIN generation reports and then 
maintain appropriate records that further identify the purchaser and 
the details of the transaction. We are not requiring 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.
4. 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. We have found the information in 
attest engagements submitted under RFS1 to be extremely valuable as a 
compliance monitoring tool. The approach adopted in this final rule is 
identical to the approach adopted under the RFS1 program,\34\ although 
the universe of obligated parties and renewable fuels producers is 
broader under this final rule for RFS2.
---------------------------------------------------------------------------

    \34\ See ``Regulation of Fuel and Fuel Additives: Renewable Fuel 
Standard Program,'' 72 FR 23900, 23949-23950 (May 1, 2007) for a 
detailed discussion of attest engagement requirements under RFS1.
---------------------------------------------------------------------------

    As with the RFS1 program, an attest engagement must be conducted by 
an individual who is a Certified Public Accountant (CPA) or Certified 
Internal Auditor (CIA), who is independent of the party whose records 
are being reviewed, and who will follow agreed-upon procedures to 
determine whether underlying records, reported items, and transactions 
agree. The CPA or CIA will generate a report as to their findings.
    We have received numerous questions and comments related to how 
attest engagements apply to foreign companies and whether or not a 
foreign accountant may perform the required agreed-upon procedures. EPA 
will accept an attest engagement performed by a foreign accountant who 
holds an equivalent credential to an American CPA or CIA. A written 
explanation as to the foreign accountant's qualifications and the 
equivalency of the credential must accompany the attest engagement.
    Producers of renewable fuels, obligated parties, exporters, and any 
party who owns RINs must arrange for an annual attest engagement. The 
attest engagement report for any given year must be submitted to EPA by 
no later than May 31 of the following year. Section 80.1464 of the 
regulations specifies the attest engagement procedures to be followed.

K. Production Outlook Reports

    Under this program we are requiring the submission, starting in 
2010, of annual production outlook reports from all domestic renewable 
fuel producers, foreign renewable fuel producers who register to 
generate RINs, and importers of renewable fuels. These production 
outlook reports will be similar in nature to the pre-compliance reports 
required under the Highway and Nonroad Diesel programs. These reports 
will 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 will require information on: (1) Strategic planning; (2) 
Planning and front-end engineering; (3) Detailed engineering and 
permitting; (4) Procurement and construction; (5) Commissioning and 
startup; (6) Projected volumes; (7) Contracts currently in place 
(feedstocks, sales, delivery, etc.); and (8) Whether or not feedstocks 
have been purchased. The first 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). In the proposed rule, we asked for comment on the first 
five project phases, and whether or not they were appropriate for 
renewable fuels production. We also proposed additional phases in order 
to provide better specificity for ascertaining industry status. EPA 
plans to use this information in order to provide annual summary 
reports regarding such planned capacity.
    The full list of requirements for the production outlook reports is 
provided in the regulations at Sec.  80.1449. The information submitted 
in the reports will be used to evaluate the progress that the industry 
is making towards the renewable fuels volume goals mandated by EISA. 
They will help EPA set the annual cellulosic biofuel standard and 
consider whether waivers would be

[[Page 14730]]

appropriate with respect to the advanced biofuel, biomass-based diesel, 
and total renewable fuel standards (see Section II.I of this preamble 
for more discussion on this). Production outlook reports will be due 
annually by March 31 (except that for the year 2010, the report will be 
due September 1) and each annual report must provide projected 
information, including any updated information from the previous year's 
report.
    As mentioned in the preamble to the proposed rule, EPA currently 
receives data on projected flexible-fuel vehicle (FFV) sales and 
conversions from vehicle manufacturers. These are helpful in providing 
EPA with information regarding the potential market for renewable 
fuels. We requested comment on whether we should 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, the 
extent to which such information is already publicly available or can 
be purchased from a proprietary source, and the extent to which such 
publicly available or purchasable data would be sufficient for EPA to 
make its determination. We further requested comment on the parties 
that should be required to report to EPA, and data requirements. We 
believe that publicly available information on E15, E85, and other 
refueling facilities is sufficient for us to make a determination about 
the adequacy of such facilities to support the projected volumes that 
would be used to satisfy the RFS2 standards. Therefore, we are not 
finalizing such a requirement.
    While we understand that the types of projections we request in the 
Outlook Reports could be somewhat speculative in nature, we believe 
that the projections will provide us with the most reliable information 
possible to inform the annual RFS standards and waiver considerations. 
Further, we believe this information will be more useful to us than 
other public information that is released in other contexts (e.g., 
announcements for marketing purposes). As mentioned above in Section 
II.I, we believe that we can use this information to supplement other 
available information (such as volume projections from EIA) to help set 
the standard for the following year. Specifically, it will provide more 
accurate information for setting the cellulosic biofuel and biomass-
based diesel standards, and any adjustments to the advanced biofuel and 
total renewable fuel standards.
    We received comments that both support and oppose the Production 
Outlook Reports, or some element of them. One commenter stated that EPA 
provided no reasonable explanation to require the information being 
requested for the reports; the commenter further stated that such 
information is not needed to assist parties to come into compliance. 
Another commenter stated that the renewable fuels industry cannot 
confidently project what will happen in 2010, or even 2020, because 
there are too many unknowns, no previous history of renewable fuels 
mandates, and no sense of continued tax rebate. The commenter suggested 
that until the industry operates for a few years under the RFS2 carve-
outs and the issues on the tax rebates for renewables are resolved, the 
industry cannot develop a meaningful outlook forecast. The commenter 
further suggested that EPA instead hire a consultant who can look at 
the big picture and provide a more meaningful evaluation than could the 
individual members of the biofuels industry. However, as discussed 
above, while these reports will have their limitations, we believe they 
will provide the best and most up to date information available for us 
to use in setting the standards and considering any waiver requests. We 
will of course also look to other publicly available information, and 
may consider using contractors to help out in this regard, but it 
cannot replace the need for the production outlook report data.
    A commenter noted that this provision is similar to reports 
required under the diesel program. The commenter further stated that if 
the required information can be captured by EMTS, the commenter fully 
supports this requirement. However, the commenter stated that it is 
opposed to some of the required elements of the reports for planned 
expanded or new production (strategic planning, planning and front-end 
engineering, detailed engineering and permitting, procurement and 
construction, and commissioning and start-up); these are an aspect of 
financial planning that the commenter believes EPA has no jurisdiction 
over and cannot derive basis from EISA in any form regardless of 
interpretation. As explained above, this information will be used by 
EPA to inform us for setting the standards on an annual basis and in 
responding to any waiver petitions. It will not be used to assess 
compliance with the program. The other provisions for registration, 
recordkeeping and reporting serve that purpose.
    Another commenter stated that the reports should be required, but 
that EPA should not rely too heavily upon the data (particularly for 
new biofuel technologies). Some commenters noted that they believe that 
requiring Production Outlook Reports is duplicative in nature and/or a 
burden to the industry. These commenters also believe that EPA already 
receives such information through the reporting that currently exists, 
and that EPA could also obtain this information from DOE's Energy 
Information Administration (EIA) and the National Biodiesel Board 
(NBB). Other commenters expressed concern over reporting such 
confidential and strategic information (even as confidential business 
information (CBI)), and that information out to 2022 seems excessive 
and useless; and that the reports should be limited to just domestic 
and foreign producers of renewable fuels but not importers (as they 
tend to import renewable fuels based on variable economic conditions 
and will not likely have the ability to reliably predict their future 
import volumes). The information that currently exists from other 
sources is current and historical information. For the purposes of 
setting future standards, we need to have information on future plans 
and projections. We understand that reality will always be different 
from the projections, but they will still give us the best possible 
source of information. Furthermore, by having projections five years 
out into the future, and then obtaining new reports every year, we will 
be able to assess the trends in the data and reports to better utilize 
them over time.
    Some commenters have expressed concern that the information 
required for Production Outlook Reports is not needed, won't provide 
useful information because it is speculative, or asks for information 
that could be sensitive/confidential. However, we continue to believe 
that such information is essential to our annual cellulosic biofuel 
standard setting, and consideration of whether waivers should be 
provided for other standards. All information submitted to EPA will be 
treated as confidential business information (CBI), and if used by EPA 
in a regulatory context will only be reported out in very general 
terms. As with our Diesel Pre-compliance Reports, we fully expect that 
the information will be somewhat speculative in the early reports, and 
we will weight it accordingly. As the program progresses, however, 
information submitted for the reports will continue to improve. We 
believe that any information, whether speculative or concrete, will be 
helpful for the purposes described above. Thus

[[Page 14731]]

we are finalizing Production Outlook Reports, and the required elements 
at Sec.  80.1449.

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

    The prohibition and liability provisions under this rule are 
similar to those of the RFS1 program and other fuels programs in 40 CFR 
part 80. The 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 is liable for violating that prohibition. Thus, for 
example, an obligated party is liable if the party failed to acquire 
sufficient RINs to meet its RVO. A party who produces or imports 
renewable fuels is liable for a failure to assign proper RINs to 
qualifying batches of renewable fuel produced or imported. Any party, 
including an obligated party, is liable for transferring a RIN that was 
not properly identified.
    In addition, any person who is subject to an affirmative 
requirement under this program is liable for a failure to comply with 
the requirement. For example, an obligated party is liable for a 
failure to comply with the annual compliance reporting requirements. A 
renewable fuel producer or importer is liable for a failure to comply 
with the applicable batch reporting requirements. Any party subject to 
recordkeeping or product transfer document (PTD) requirements is liable 
for a failure to comply with these requirements. Like other EPA fuels 
programs, this rule provides that a party who causes another party to 
violate a prohibition or fail to comply with a requirement may also 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, any person who 
violates any prohibition or requirement of this rule is subject to 
civil penalties of up to $37,500 per day and per each individual 
violation, plus the amount of any economic benefit or savings resulting 
from each violation. Under this rule, a failure to acquire sufficient 
RINs to meet a party's renewable fuels obligation constitutes a 
separate day of violation for each day the violation occurred during 
the annual averaging period.
    As discussed above, the regulations 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 
address the consequences if an obligated party is found to have used 
invalid RINs to demonstrate compliance with its RVO. In this situation, 
the obligated party that used the invalid RINs will be required to 
deduct any invalid RINs from its compliance calculations. An obligated 
party is 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 is 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.

III. Other Program Changes

    In addition to the regulatory changes we are finalizing today in 
response to comments received on the proposed rule and EISA (which are 
designed to implement the provisions of RFS2), there are a number of 
other changes to the RFS program that we are making. We believe that 
these changes will increase flexibility, simplify compliance, or 
address RIN transfer issues that have arisen since the start of the 
RFS1 program. Throughout the rulemaking process, we also investigated 
impacts on small businesses and we are finalizing provisions to address 
the impacts of the program on them.

A. The EPA Moderated Transaction System (EMTS)

    The EPA Moderated Transaction System (EMTS) emerged as a result of 
our experiences with and lessons learned from implementing RFS1. 
Recognizing that the addition of significant volumes of renewable fuels 
and expansion of renewable fuel categories were adding complexity to an 
already stressed system, EMTS was introduced as a new approach for 
managing RINs in our NPRM. We received broad acceptance of the EMTS 
concept in the public comments as well as support for its expeditious 
implementation. This section describes the need for EMTS, 
implementation of EMTS, and an explanation of how EMTS will work. By 
implementing EMTS, we believe that we will be able to greatly reduce 
RIN-related errors while efficiently and accurately managing the 
universe of RINs. EMTS will save considerable time and resources for 
both industry and EPA. This is most evident considering that the system 
virtually eliminates multiple sources of administrative errors, 
resulting in a reduction of costs and effort expended to correct and 
regenerate product transfer documents, documentation and recordkeeping, 
and resubmitting reports to EPA. Use of EMTS will result in fewer 
report resubmissions and easier reporting for industry, while leaving 
fewer reports to be processed by EPA. Industry will spend less time and 
effort validating the RINs they procure with greater assurance and 
confidence in the RIN market. EPA will spend less time tracking down 
invalid RINs and working with regulated parties on complex remedial 
actions. This is possible because EMTS removes 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.
    We received comments suggesting that EPA remove the attest 
engagement requirements and certain recordkeeping requirements due to 
the use of EMTS. While we believe that EMTS will simplify and reduce 
burdens on the regulated community, it is important to point out that 
EMTS is strictly a RIN tracking and managing tool designed to 
facilitate reporting under the Renewable Fuel Standard program. Product 
transfer documents are the commercial documents used to memorialize 
transactions of RINs between a buyer and a seller in the market. The 
EMTS will rely on references to these

[[Page 14732]]

documents, which can take many forms, but it is not capable of 
replacing those documents. Attest engagements are used to verify that 
the records required to be kept by regulated parties, including 
information retained by a regulated party as well as information 
reported to EPA such as laboratory test results, contracts between 
renewable fuel/RIN buyers and sellers, feedstock documentation, etc. is 
correctly maintained or reported. The information reported via EMTS is 
but a subset of the information required to be maintained in a 
regulated party's records, and both PTDs and attest engagements are 
necessary to ensure that the information collected and tracked in EMTS 
concurs with actual events.
1. Need for the EPA Moderated Transaction System
    In implementing RFS1, we found that the 38-digit standardized RINs 
proved to be confusing to many parties in the distribution chain. 
Parties made various errors in generating and using RINs. For example, 
parties transposed digits within the RIN and incorrectly referenced 
volume numbering. Also, parties created alphanumeric RINs, despite the 
fact that RINs were supposed to consist of all numbers.
    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 usually involves 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 was only on a quarterly basis, a RIN error could exist for 
several months before being discovered.
    Incorrect RINs are invalid RINs. If parties in the distribution 
system cannot track down and correct errors in a timely manner, then 
all downstream parties that traded the invalid RIN are in violation. 
Because RINs are the basic unit of compliance for the RFS program, it 
is important that parties have confidence when generating and using 
them.
    All parties in the RFS1 and the RFS2 regulated community are 
required to use RINs. Under RFS2, we foresee that regulated party 
community will substantially expand. Newer regulated parties of an 
already complex system necessitate EMTS. These parties include 
renewable fuel producers and importers, obligated parties, exporters, 
and other RIN owners; (typically marketers of renewable fuels and 
blenders). Under RFS1, all RINs were used to comply with a single 
standard. With RFS2, there are four standards. RINs must be generated 
to identify one of the fuel categories: cellulosic biofuel, cellulosic 
diesel, biomass-based diesel, advanced biofuel, and renewable fuels 
(e.g., corn ethanol). (For a more detailed discussion of RINs, see 
Section II.A of this preamble.) The different types of RINs will be 
managed in the EMTS.
2. Implementation of the EPA Moderated Transaction System
    We proposed that EMTS would be an opt-in for the calendar year 2010 
and mandatory for calendar year 2011. We received many comments 
strongly supporting EMTS implementation with the start of the RFS2 
program to ensure confidence and simplicity in an increasingly complex 
program. We also received comments that EMTS implementation with RFS2 
is necessary so industry would not have to create a new system to 
handle RFS2 RINs for 2010 and then move to EMTS for 2011 while still 
handling RFS1 RINs. Potentially, three RIN transaction systems would 
exist during transition from RFS1 to RFS2 if EMTS could not be 
implemented with the start of the RFS2 program. EPA agrees that this 
three system issue would be an undue burden to industry as it would 
require industry to create two systems within a 12 month period. EMTS 
development started with the introduction of the NPRM, and has been in 
beta testing since early November with a select group of different 
industry stakeholders. Industry feedback has been overwhelmingly strong 
for the implementation of EMTS with the start of RFS2. With this final 
rule, EPA decided that EMTS will start on the same date when RFS2 RINs 
are required to be generated. In addition, to ensure that parties will 
have enough time to incorporate RFS2 and EMTS requirements into private 
RIN tracking systems, the generation of RFS2 RINs will begin on July 1, 
2010. Therefore, all RFS regulated parties are required to use EMTS 
starting July 1, 2010.
    RIN transactions are required to be verified and certified on a 
quarterly basis. EMTS will provide summaries for parties to verify, 
report, and certify transactions to EPA through the fuels reporting 
system, DCFuels. Additional information may be required to be added to 
the EMTS provided summary. This additional certification step allows 
parties to verification that the information sent to EMTS is accurate. 
However, parties may choose to review their data by checking their EMTS 
account at anytime.
    With EMTS, RIN transactions are required to be verified and 
certified on a quarterly basis. EMTS will provide summaries for parties 
to verify, report, and certify transactions to EPA through the fuels 
reporting system, DCFuels. Additional information may be required to be 
added to the EMTS provided report. This additional certification step 
allows parties to verify that the information sent to EMTS is accurate. 
However, parties may choose to review their data by checking their EMTS 
account at any time.
3. How EMTS Will Work
    EMTS will be a closed, EPA-moderated system that provides a 
mechanism for screening RINs and a structured environment for 
conducting RIN transactions. ``Screening'' of RINs means that parties 
can have 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 received comments opposing the 3 day time window for reporting 
transactions to the EMTS. One commenter requested 7 days from the event 
for sellers to report a transaction and 7 days after that for the buyer 
to accept the transaction. In order for this to be a ``real time'' 
system, we must require that the information comes in a timely manner. 
One commenter requested 10 days from the event to send information to 
EMTS. EPA has concluded that five days, or a business week, is an 
appropriate amount of time for both parties to receive or provide 
necessary documentation in order to interact with EMTS accurately and 
timely. ``Real time'' will be defined as within five (5) business days 
of a reportable event (e.g., generation and assignment of RINs, 
transfer of RINs).
    Parties who use EMTS must first register with EPA in accordance 
with the RFS2 registration program described in Section II.C of this 
preamble. Parties will also have to create an account (i.e., register) 
via EPA's Central Data Exchange (CDX), as users will access EMTS via 
CDX. CDX is a secure and central electronic portal through which 
parties may submit compliance reports. Parties must establish an 
account with EMTS by July 1, 2010 or 60 days prior to engaging in any 
transaction involving RINs, whichever is later. Once registration 
occurs, individual accounts will be established within EMTS and the 
system will enable a party to submit transactions based on their 
registration information.
    In EMTS, the screening and assignment of RINs will be made at the 
logical point, i.e., the point when RINs

[[Page 14733]]

are generated through production or importation of renewable fuel. A 
renewable producer will electronically submit, in ``real time,'' a 
volume of renewable fuel produced or imported, as well as a number of 
the RINs generated and assigned. EMTS will automatically screen each 
batch and either reject the information or allow RINs created in the 
RIN generator's account as one of the five types of RINs.
    We received comments supporting the RFS1 approach that allows 
producers and importers to generate RINs at the renewable fuel point of 
sale. EPA realizes that this is an industry practice and this 
flexibility will still be allowed for RIN generators, but only if 
applied consistently.
    After RINs have entered the system, parties may then trade them 
based on agreements outside of EMTS. One major advantage of EMTS, over 
the RFS1 system, is that the system will simplify trading by allowing 
RINs to be traded generically. Only some specifying information will be 
needed to trade RINs, such as RIN quantity, fuel type, RIN assignment, 
RIN year, RIN price or price per gallon. The unique identification of 
the RIN will exist within EMTS, but parties engaging in RIN 
transactions will no longer have to worry about incorrectly recording 
or using 38-digit RIN numbers. The actual items of transactional 
information covered under RFS2 are very similar to those reported under 
RFS1. The RIN price is one of the new pieces of transactional 
information required to be submitted under RFS2.
    We received several adverse comments strongly opposing the 
collection of price information due to Confidential Business 
Information (CBI) concerns, other services being able to provide this 
information, marketplace delays and undue stress on the EMTS from 
disagreements in RIN price. We received one comment strongly supporting 
EPA collecting this information. EPA decided that the price information 
has great programmatic value because it will help us anticipate and 
appropriately react to market disruptions and other compliance 
challenges, assess and develop responses to potential waivers, and 
assist in setting future renewable fuel standards. In addition, EPA 
decided 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. 
Also, EPA will not require the matching of the exact RIN price to 
alleviate the burden of resubmission due to price mistakes. However, 
the price information must be accurate and rounded to the nearest cent 
(U.S. Dollar) at the time of sending the transactional information to 
EMTS.
    We received one comment requesting publication of security 
precautions taken by EPA to protect EMTS from attacks. EPA cannot 
provide security information to the public because providing such 
information may create security vulnerabilities. However, EMTS will be 
compliant with the appropriate security requirements for all federal 
agency information technology systems.
    Also 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 will offer the option for a buyer to accept or reject RINs from 
specific RIN generators or from classes of RIN generators.
4. A Sample EMTS Transaction
    This sample illustrates how two parties may trade RINs in EMTS:
    (1) Seller logs into EMTS and posts a sale of 10,000 RINs to Buyer 
at X price. For this example, assume the RINs were generated in 2010 
and were assigned to 10,000 gallons of ``Renewable fuel (D=6)''. 
Seller's RIN account for ``Renewable fuel (D=6)'' is put into a 
``pending'' status of 10,000 with the posting of the sale to Buyer. 
Buyer receives automatic notification of the pending transaction.
    (2) Buyer logs into EMTS. Buyer sees the sale transaction pending. 
Assuming it is correct, Buyer accepts it. Upon acceptance, Buyer's RIN 
account for ``Renewable fuel (D=6)'' RINs is automatically increased by 
10,000 2010 assigned RINs sold at X price.
    (3) After Seller has posted the sale and Buyer has accepted it, 
EMTS automatically notifies both Buyer and Seller that the transaction 
has been fully completed.
    Under EMTS, the seller will always have to initiate any 
transaction. The specific amount of RINs are put into a pending status 
when the seller posts the sale. The buyer must confirm the sale in 
order to have the RINs transferred to the buyer's account. Transactions 
will always be limited to available RINs. Notification will 
automatically be sent to both the buyer and the seller upon completion 
of the transaction. EPA considers any sale or transfer as complete upon 
acknowledgement by the buyer. We will also allow buyers to submit their 
acknowledgement prior to a seller initiating the transaction. However, 
these buy transactions will not initiate any RINs being put into a 
pending status from a seller's account. Instead, the buy transactions 
will be queued and checked periodically to see if a ``sell'' 
transaction was posted by the seller. If a buy is posted without a 
matching sell transaction, then the seller will be notified that a buy 
transaction is pending. Both buy and sell transactions must be matched 
within a set number of days from the submission date or they will 
expire. Transactions will expire 7 days after the submission of the 
file. Since both parties are required to submit information within 5 
days, we allow the full 5 days to expire plus 2 days in the case of 
late submissions.
    In summary, the advantage to implementing EMTS is that parties may 
engage in RIN transactions with a high degree of confidence, errors 
will be virtually eliminated, and everyone engaging in RIN transactions 
will have a simplified environment in which to work, which should 
minimize the level of resources needed for implementation.

B. Upward Delegation of RIN-Separating Responsibilities

    Since the start of the RFS 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 rule, 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 gasoline 
only. EISA mandates certain amounts of renewable fuels to be blended 
into all transportation fuels--which includes highway and 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 EPA fuels regulations) will now be 
regulated by the RFS program.

[[Page 14734]]

    Consequently, we believe it is appropriate, and thus we are 
finalizing as proposed, 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 is consistent with the 
fact that the RFS 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 will 
eliminate undue burden on small parties who would otherwise not be 
regulated by this program. This provision is solely for the case of 
blenders who blend and trade less than 125,000 total gallons of 
renewable fuel per year (i.e., a company that blends 100,000 gallons 
and trades another 100,000 gallons would not be able to use this 
provision) and is available to any blender who must separate RINs from 
a volume of renewable fuel under Sec.  80.1429(b)(2).
    We requested comment in the NPRM on this concept, the 125,000 
gallon threshold, and appropriate documentation to authorize this 
upward delegation. In general, those that commented on this provision 
support the idea of upward delegation for small blenders, though one 
commenter stated that EPA should not allow small entities to delegate 
their RIN-related responsibilities upward. Those commenters that 
support the upward delegation provision stated that it should be 
limited to small blenders only and should only be for delegating to the 
party directly upstream. A few commenters stated that they believe the 
125,000 gallon threshold is appropriate; while others commented that it 
should be higher. We believe that the 125,000 gallon limit strikes the 
correct balance between providing relief to small blenders, while still 
ensuring that non-obligated parties cannot unduly influence the RIN 
market.
    We did not receive any comments on appropriate documentation, 
however a couple commenters suggested that we retain the proposed 
annual authorization between the blender and the party directly 
upstream, as well as allowing a small blender to enter into 
arrangements with multiple suppliers on a transaction-by-transaction 
basis. Please see Chapter 5 of the Summary and Analysis of Comments 
Document for more discussion on the comments received and our responses 
to those comments.
    We are also finalizing, as stated in the preamble to the proposed 
rule, that for upstream delegation, both parties must sign a quarterly 
written statement (which must be included with the reporting party's 
reports) authorizing the upward delegation. Copies of these statements 
must be retained as records by both parties. 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. 
This statement would apply to all volumes of renewable fuel transferred 
between the two parties. Thus, the two parties would enter into a 
contract stating that the supplier has RIN-separation responsibilities 
for all transferred volumes between the two parties, and no additional 
permissions from the small blender would be needed for any volumes 
transferred. A blender may enter into such an agreement with as many 
parties as they wish.

C. Small Producer Exemption

    Under the RFS1 rule, 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. These 
producers and importers are also exempt from registration, reporting, 
recordkeeping, and attest engagement requirements. In the preamble to 
the proposed rule, we requested comment on whether or not this 10,000 
gallon threshold was appropriate. One commenter suggested that we 
retain the 10,000 gallon threshold as-is. Another commenter supported 
the concept of less burdensome requirements for small producers, but 
suggested that these entities should, at a minimum, be required to 
generate RINs for all qualifying renewables. We are maintaining this 
exemption under the RFS2 rule for parties who produce or import less 
than 10,000 gallons of renewable fuel per year.
    In addition to the permanent exemption for those producers and 
importers who produce or import less than 10,000 gallons of renewable 
fuel per year, we are also finalizing a temporary exemption for 
renewable fuel producers who produce less than 125,000 gallons of 
renewable fuel each year from new production facilities. These 
producers are not required to generate and assign RINs to batches of 
renewable fuel for a period of up to three years, beginning with the 
calendar year in which the production facility produces its first 
gallon of renewable fuel. Such producers are also exempt from 
registration, reporting, recordkeeping, and attest engagement 
requirements as long as they do not own RINs or voluntarily generate 
and assign RINs. This provision is intended to allow pilot and 
demonstration plants of new renewable fuel technologies to focus on 
developing the technology and obtaining financing during these early 
stages of their development without having to comply with the RFS2 
regulations.

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. When renewable fuel volumes are being 
produced that exceed the RFS2 standards, the rollover issue could 
undermine the ability of a limit on credit life to guarantee an ongoing 
market for renewable fuels.

[[Page 14735]]

    To implement EISA'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.
    As described in the NPRM, 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. As a result we proposed to maintain the 
regulatory requirement for a 20% rollover cap under the new RFS2 
program, and to apply this cap separately to all four RVOs under RFS2. 
However, we took comment on changing the level of the cap to some 
alternative value lower or higher than 20%.
    A lower cap could provide a greater incentive for parties with 
excess RINs to sell them rather than hold onto them, increasing the 
availability of RINs for parties that need them for compliance 
purposes. But a lower cap would also reduce flexibility for obligated 
parties attempting to minimize the costs of compliance with increasing 
annual volume requirements, particularly if there are concerns that the 
RIN market may be tighter in the future than it is currently.
    Conversely, the increasing annual volume requirements in EISA make 
it less likely that renewable fuel producers will overcomply, and as a 
result it is less likely that there will be an excess of RINs in the 
market. Under these circumstances, there is little opportunity for RINs 
to build up in the market, and the rollover cap would have less of an 
impact on the market as a whole. Thus a higher cap might be warranted. 
However, while a higher cap would create greater flexibility for some 
obligated parties, it could also create disruptions in the RIN market 
as parties with excess RINs would have a greater opportunity to hold 
onto them rather than sell them. Parties without direct access to RINs 
through the purchase and blending of renewable fuels would be placed at 
a competitive disadvantage in comparison to parties with excess RINs. 
In the extreme, removal of the cap entirely would allow obligated 
parties to roll over up to one year's worth of their obligations 
indefinitely.
    In general, commenters on the NPRM reiterated the positions that 
they raised during development of the RFS1 program. While one renewable 
fuel producer requested that the rollover cap be left at 20%, most 
producers requested that the rollover cap be reduced to 0%, such that 
compliance with the standards applicable in a given year could only be 
demonstrated using RINs generated in that year. In contrast, refiners 
requested that the rollover cap be either eliminated, such that any 
number of previous year RINs could be used for current year compliance, 
or at least raised to 40 or 50 percent. Small refiners requested that 
the cap be raised for small refiners only to accommodate the 
competitive disadvantage with respect to the RIN market that they 
believe they experience in comparison to larger refiners.
    Based on the comments received, we believe that the 20% level 
continues to provide the appropriate balance between, on the one hand, 
allowing legitimate RIN carryovers and protecting against potential 
supply shortfalls that could limit the availability of RINs, and on the 
other hand ensuring an annual demand for renewable fuels as envisioned 
by EISA. Therefore, we are continuing the 20% rollover cap for 
obligated parties for the RFS program.

E. Small Refinery and Small Refiner Flexibilities

    This section discusses flexibilities for small refineries and small 
refiners for the RFS2 rule. As explained in the discussion of our 
compliance with the Regulatory Flexibility Act below in Section XI.C 
and in the Final Regulatory Flexibility Analysis in Chapter 7 of the 
RIA, we considered the impacts of the RFS2 regulations on small 
businesses (small refiners). 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 
for this rule, 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 rulemaking 
docket. For the SBREFA process, we conducted outreach, fact-finding, 
and analysis of the potential impacts of our regulations on small 
business refiners.
1. Background--RFS1
a. Small Refinery Exemption
    CAA section 211(o)(9), 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.\35\ 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.
---------------------------------------------------------------------------

    \35\ Small refineries are also allowed to waive this exemption.
---------------------------------------------------------------------------

b. Small Refiner Exemption
    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 EPAct small refinery definition as noted above.
2. Statutory Options for Extending Relief
    There are two provisions in section 211(o)(9) that allow for an 
extension of the temporary exemption for small refineries beyond 
December 31, 2010.
    One provision 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 automatic extension of at least two years for small 
refineries that DOE determines would be subject to such 
disproportionate hardship (per section 211(o)(9)(A)(ii)). If the DOE 
study determines that such hardship exists, then section 
211(o)(9)(A)(ii) (which was retained in EISA) provides that EPA shall 
extend the exemption for a period of at least two years.
    The second provision, at section 211(o)(9)(B), authorizes EPA to 
grant an extension for a small refinery based upon disproportionate 
economic hardship, on a case-by-case basis. A small refinery may, at 
any time, petition EPA for an extension of the small refinery exemption 
on the basis of disproportionate economic hardship. EPA is to consult 
with DOE and consider the findings of the DOE small

[[Page 14736]]

refinery study in evaluating such petitions. These petitions may be 
filed at any time, and EPA has discretion to determine the length of 
any exemption that may be granted in response.
3. The DOE Study/DOE Study Results
    As discussed above, EPAct required that DOE perform a study by 
December 31, 2008 on the impact of the renewable fuel requirements on 
small refineries (section 211(o)(9)(A)(ii)(I)), and whether or not the 
requirements would impose a disproportionate economic hardship on these 
refineries. 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 regulation section 
80.1456). DOE thus determined that small refineries would not be 
subject to disproportionate economic hardship under the proposed RFS2 
program, and that the exemption should not, on the basis of the study, 
be extended for small refineries (including those small refiners who 
own refineries meeting the small refinery definition) 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 (pursuant to Section 
211(o)(9)(B)).
4. Ability To Grant Relief Beyond 211(o)(9)
    The SBREFA panel made a number of recommendations for regulatory 
relief and additional flexibility for small refineries and small 
refiners. These are described in the Final Panel Report (located in the 
rulemaking docket), and summarized below. During the development of 
this final rule, we again evaluated the various options recommended by 
the Panel and also comments on the proposed rule. We also consulted the 
small refinery study prepared by DOE.
    As described in the Final Panel Report, EPA early-on identified 
limitations on its authority to issue additional flexibility and 
exemptions to small refineries. In section 211(o)(9) Congress 
specifically addressed the issue of an extension of time for compliance 
for small refineries, temporarily exempting them from renewable fuel 
obligations through December 31, 2010. As discussed above, the statute 
also includes two specific provisions describing the basis and manner 
in which further extensions of this exemption can be provided. In the 
RFS1 rulemaking, EPA considered whether it should provide additional 
relief to the limited number of small refiners who were not covered by 
the small refinery provision, by providing them a temporary exemption 
consistent with that provided by Congress for small refineries. EPA 
exercised its discretion under section 211(o)(3) and provided such 
relief. Thus, in RFS1, EPA did not modify the relief provided by 
Congress for small refineries, but did exercise its discretion to 
provide the same relief specified by statute to a few additional 
parties.
    In RFS2 we are faced with a different issue--the extent to which 
EPA should provide additional relief to small refineries beyond the 
relief specified by statute, and whether it should provide such further 
relief to small refiners as well. There is considerable overlap between 
entities that are small refineries and those that are small refiners. 
Providing additional relief just to small refiners would, therefore, 
also extend additional relief to at least a number of small refineries. 
Congress spoke directly to the relief that EPA may provide for small 
refineries, including those small refineries operated by small 
refiners, and limited that relief to a blanket exemption through 
December 31, 2010, with additional extensions if the criteria specified 
by Congress are met. EPA believes that an additional or different 
extension, relying on a more general provision in section 211(o)(3) 
would be inconsistent with Congressional intent. Further, we do not 
believe that the statute allows us the discretion to give relief to 
small refiners only--as this would result in a subset of small 
refineries (those that also qualify as small refiners) receiving relief 
that is greater than the relief already given to all small refineries 
under EISA.
    EPA also notes that the criteria specified by statute for providing 
a further compliance extension to small refineries is a demonstration 
of ``disproportionate economic hardship.'' The statute provides that 
such hardship can be identified through the DOE study, or in individual 
petitions submitted to the Agency. However, the DOE study has concluded 
that no disproportionate economic hardship exists, at least under 
current conditions and for the foreseeable future under RFS2. 
Therefore, absent further information that may be provided through the 
petition process, there does not currently appear to be a basis under 
the statute for granting further compliance extensions to small 
refineries. If DOE revises its study and comes to a different 
conclusion, EPA can revisit this issue.
5. Congress-Requested Revised DOE Study
    In their written comments, as well as in discussions we had with 
them on the proposed rule, small refiners indicated that they did not 
believe that EPA should rely on the results of the DOE small refinery 
study to inform any decisions on small refiner provisions. Small 
refiners generally commented that they believe that the study was 
flawed and that the conclusions of the study were reached without 
adequate analysis of, or outreach with, small refineries (as the 
majority of the small refiners own refineries that meet the 
Congressional small refinery definition). One commenter stated that 
such a limited investigation into the impact on small refineries could 
not have resulted in any in-depth analysis on the economic impacts of 
the program on these entities. Another commenter stated that it 
believes that DOE should be directed to reopen and reassess the small 
refinery study be June 30, 2010, as suggested by the Senate 
Appropriations Committee.
    We are aware that there have been expressions of concern from 
Congress regarding the DOE Study. Specifically, in Senate Report 111-
45, the Senate Appropriations Committee ``directed [DOE] to reopen and 
reassess the Small Refineries Exemption Study by June 30, 2010,'' 
noting a number of factors that the Committee intended that DOE 
consider in the revised study. The Final Conference Report 111-278 to 
the Energy & Water Development Appropriations Act (H.R. 3183), 
referenced the language in the Senate Report, noting that the conferees 
``support the study requested by the Senate on RFS and expect the 
Department to undertake the requested economic review.'' At the present 
time, however, the DOE study has not been revised. If DOE prepares a 
revised study and the revised study finds that there is a 
disproportionate economic impact, we will revisit the exemption 
extension at that point in accordance with section 211(o)(9)(A)(ii).

[[Page 14737]]

6. What We're Finalizing
a. Small Refinery and Small Refiner Temporary Exemptions
    As mentioned above, the RFS1 program regulations exempt gasoline 
produced by small refineries from the renewable fuels standard through 
December 31, 2010 (at 40 CFR 80.1141), per EPAct. As EISA did not alter 
the small refinery exemption in any way, we are retaining this small 
refinery temporary exemption in the RFS2 program without change (except 
for the fact that all transportation fuel produced by small refineries 
will be exempt, as EISA also covers diesel and nonroad fuels).
    Likewise, as we extended under RFS1 the small refinery 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), we are also finalizing a continuation 
of the small refiner temporary exemption through December 31, 2010.
b. Case-by-Case Hardship for Small Refineries and Small Refiners
    As discussed in Section III.E.2, EPAct also 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 allow 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 finalizing 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). We 
are also finalizing a case-by-case hardship provision for those small 
refiners that do not operate small refineries using our discretion 
under CAA section 211(o)(3)(B). This provision will allow those small 
refiners that do not operate small refineries to apply for the same 
kind of hardship extension as a small refinery. In evaluating 
applications for this hardship provision EPA will take into 
consideration information gathered from annual reports and RIN system 
progress updates, as recommended by the SBAR Panel, as well as 
information provided by the petitioner and through consultation with 
DOE.
c. Program Review
    During the SBREFA process, the small refiner Small Entity 
Representatives (SERs) also requested that EPA perform an annual 
program review, to begin one year before small refiners are required to 
comply with the program, to provide information on RIN system progress. 
As mentioned in the preamble to the proposed rule, we were concerned 
that such a review could lead to some redundancy with the notice of the 
applicable RFS standards that EPA will publish 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, and we proposed, that an update of RIN system 
progress (e.g., RIN trading, publicly-available information on RIN 
availability, etc.) be included in this annual notice.
    Based on comments received on the proposed rule, we believe that 
such information could be helpful to industry, especially to small 
businesses to help aid the proper functioning of the RIN market, 
especially in the first years of the program. However, during the 
development of the final rule, it became evident that there could be 
instances where we would want to report out RIN system information on a 
more frequent basis than just once a year. Thus we are finalizing that 
we will periodically report out elements of RIN system progress; but 
such information will be reported via other means (e.g., the RFS Web 
site (http://www.epa.gov/otaq/renewablefuels/index.htm), EMTS homepage, 
etc.).
7. Other Flexibilities Considered for Small Refiners
    During the SBREFA process, and in their comments on the proposed 
rule, 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 costs), the desire for an annual RIN system review, 
and the difficulty in raising capital and competing for engineering 
resources to make capital improvements.
    The Panel recommended that EPA consider the issues raised by the 
small refiner 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 XI.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. Also, a 
complete discussion of comments received on the proposed rule regarding 
small refinery and small refiner flexibilities can be found in Chapter 
5 of the Summary and Analysis of Comments document.
a. Extensions of the RFS1 Temporary Exemption for Small Refiners
    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. This provided an exemption for 
small refineries (and small refiners) for the first five years of the 
RFS program. Small refiner SERs suggested that an additional temporary 
exemption for the RFS2 program would be beneficial to them in meeting 
the RFS standards as increased by Congress in EISA. The Panel 
recommended that EPA propose a delay in the effective date of the 
standards until 2014 (for a total of eight years) for small entities, 
to the extent allowed by the statute.
    During the development of both the Final Panel Report and the 
proposed rule, we evaluated various options for small refiners, 
including an additional temporary exemption for small refiners from the 
required RFS2 standards. As discussed above, we concluded that we do 
not have the statutory authority to provide such extensions through 
means other than those specified in the statute. Thus, further 
extensions will be as a result of any revised DOE study, or in response 
to a petition, pursuant to the authorities specified in section 
211(o)(9).
    We proposed to continue the temporary exemption finalized in RFS1--
through December 31, 2010. Commenters that oppose an extension of the 
temporary exemption generally stated that an extension is not 
warranted, and some commenters expressed concerns about allowing

[[Page 14738]]

provisions for small refiners. One commenter also stated that it 
believes that the small refinery exemption should not be extended and 
that the small refiner exemption should be eliminated completely. Two 
commenters supported the continuation of the exemption through December 
31, 2010 only, and one stated that it does not support an extension as 
it believes that all parties have been well aware of the passage of 
EISA and small refineries and small refiners should have been striving 
to achieve compliance by the end of 2010. Two commenters also expressed 
views that the exemption should not have been offered to small refiners 
in RFS1 as this was not provided by EPAct, and that an extension of the 
exemption should not be finalized for small refineries at all. The 
commenters further commented that an economic hardship provision was 
included in EPAct, and any exemption extension should be limited to 
such cases, and only to the specific small refinery (not small refiner) 
that has petitioned for such an extension.
    Commenters supporting an extension of the exemption commented that 
they believe that the statutes (EPAct and EISA) do not prohibit EPA 
from providing relief to regulated small entities on which the rule 
will have a significant economic impact, and that such a delay could 
lessen the burden on these entities. One commenter stated that it 
believes EPA denied or ignored much of the relief recommended by the 
Panel in the proposal. Another commenter stated that it believes EPA's 
concerns regarding the legal authority are unsustainable considering 
EPA's past exercises of discretion under the RFS1 program, and with the 
discretion afforded to EPA under section 211(o) of the CAA. Some 
commenters requested a delay until 2014 for small refiners. One 
additional commenter expressed support for an extension of the small 
refinery exemption only, and that these small refineries should be 
granted a permanent exemption.
    During the development of this final rule, we again evaluated the 
various options recommended by the Panel, the legality of offering an 
extension of the exemption to small refiners only, and also comments on 
the proposed rule. Specifically in the case of an extension of the 
exemption for small refiners, we also consulted the small refinery 
study prepared by DOE, as the statute directs us to use this as a basis 
for providing an additional two year exemption. As discussed above in 
Sections III.E.4 and 5, we do not believe that we can provide an 
extension of the exemption considering the outcome of the DOE small 
refinery study, which did not find that there was a disproportionate 
economic hardship. Further, we do not believe that the statute allows 
us the discretion to give relief to a subset of small refineries (those 
that also qualify as small refiners) that is greater than the relief 
already given to all small refineries under EPAct. However, it is 
important to recognize that the 211(o)(9) small refinery provision does 
allow for extensions beyond December 31, 2010, as discussed above in 
Section III.E.2. Thus, refiners may apply for individual hardship 
relief.
b. 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 stated in the 
NPRM that we had serious concerns about our legal authority to provide 
such a phase-in. CAA section 211(o)(3)(B) states that the renewable 
fuel obligation shall ``consist of a single applicable percentage that 
applies to all categories of persons specified'' as obligated parties. 
A phase-in approach would essentially result in different applicable 
percentages being applied to different obligated parties. Further, such 
a phase-in approach would provide more relief to small refineries 
operated by small refiners than that provided under the statutory small 
refinery provisions.
    Some commenters stated that they believe that EPA has the ability 
to consider a phase-in of the standards for small refiners. One 
commenter suggested that a temporary phase-in could help lessen the 
burden of regulation on small entities and promote compliance. Another 
commenter stated that it believes EPA's legal concerns regarding a 
phase-in are unsustainable considering EPA's past exercises of 
discretion under the RFS1 program and with the discretion afforded to 
EPA under section 211(o) of the CAA.
    After considering the comments on this issue, EPA continues to 
believe that allowing a phase-in of regulatory requirements for small 
refineries and/or small refiners would be inconsistent with the 
statute, for the reasons mentioned above. Any individual entities that 
are experiencing hardship that could justify a phase-in of the 
standards have the ability to petition EPA for individualized relief. 
Therefore we are not including a phase-in of standards for small 
refiners in today's rule.
c. RIN-Related Flexibilities
    The small refiner SERs requested that the RFS2 rule contain 
provisions for small refiners related to the RIN system, such as 
flexibilities in the RIN rollover cap percentage and allowing small 
refiners only to use RINs interchangeably. In the RFS1 rule, up to 20% 
of a previous year's RINs may be ``rolled over'' and used for 
compliance in the following year. In the preamble to the proposed rule, 
we discussed the concept of allowing for flexibilities in the rollover 
cap, such as a higher RIN rollover cap for small refiners for some 
period of time or for at least some of the four standards. As 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, we requested comment on the concept of 
increasing the RIN rollover cap percentage for small refiners and an 
appropriate level of that percentage. In response to the Panel's 
recommendation, we also sought comment on allowing small refiners to 
use the four types of RINs interchangeably.
    In their comments on the proposed rule, one small refiner commented 
that, in regards to small refiners' concerns about RIN pricing and 
availability, there is no mechanism in the rule to address the 
possibility that the RIN market will not be viable. The commenter 
further suggested that more ``durable'' RINs are needed for small 
refiners that can be carried over from year to year, to alleviate some 
of the potentially market volatility for renewable fuels. Another 
commenter suggested that RINs should be interchangeable for small 
refiners, or alternatively, some mechanism should be implemented to 
ensure that RIN prices are affordable for small refiners. Further, with 
regard to interchangeable RINs, one commenter stated that small 
refiners do not have the staff or systems to manage and account for 
four different categories of RINs and rural small refiners will suffer 
economic hardship and disadvantage because of the unavailability of 
biofuels. The commenter also requested an increase in the rollover cap 
to 50% for small refiners.
    We are not finalizing additional RIN-related flexibilities for 
small refiners in today's action. As highlighted in the NPRM, we 
continue to believe that the concept of interchangeable RINs for small 
refiners only fails to require the four different standards mandated by 
Congress (e.g., conventional biofuel

[[Page 14739]]

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. Essentially, it would circumvent the explicit direction of 
Congress in EISA to require that the four RFS2 standards be met 
separately. Further, given the findings from the DOE study that small 
refineries (and thus, most small refiners) do not currently face 
disproportionate economic hardship, and are not expected to do so as 
RFS2 is implemented, we do not believe that a basis exists to justify 
providing small refiners with a larger rollover cap than other 
regulated entities. Thus, small refiners will be held to the same RIN 
rollover cap as other obligated parties.

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

    We proposed labeling requirements for fuel dispensers that handle 
greater than 10 volume percent ethanol blends which included the 
following text: For use only in flexible-fuel vehicles, May damage non-
flexible-fuel vehicles, Federal law prohibits use in non-flexible-fuel 
vehicles. This proposal was primarily meant to help address concerns 
about the potential misfueling of non-flex-fuel vehicles with E85, in 
light of the anticipated increase in E85 sales volumes in response to 
the RFS2 program. All ethanol blends above 10 volume percent were 
included due to the increasing industry focus on ethanol blender pumps 
that are designed to dispense a variety of ethanol blends (e.g., E30, 
and E40) for use in flex-fuel vehicles.
    Commenters stated that EPA should undertake additional analysis of 
the potential impacts from misfueling and what preventative measures 
might be appropriate before finalizing labeling requirements for >E10 
blends. They also stated that EPA should coordinate any such labeling 
provisions with those already in place by the Federal Trade Commission. 
EPA is also currently evaluating a petition to allow the use of up to 
15 volume percent ethanol in non-flex fuel vehicles. One potential 
result of this evaluation might be for EPA to grant a partial waiver 
that is applicable only for a subset of the current vehicle population. 
Under such an approach, a label for E15 fuel dispensers would be needed 
that identifies what vehicles are approved to use E15.
    Based on the public comments and the fact that EPA has not 
completed its evaluation of the E15 waiver petition, we believe that it 
is appropriate to defer finalizing labeling requirements for >E10 
blends at this time. This will afford us the opportunity to complete 
our analysis of what measures might be appropriate to prevent 
misfueling with >E10 blends before this may become a concern in the 
context of the RFS2 program.

G. Biodiesel Temperature Standardization

    The volume of a batch of renewable fuel can change under extreme 
changes in temperature. The volume of a batch of renewable fuel can 
experience expansion as the temperature increases, or can experience 
contraction as temperature decreases. The Agency requires temperature 
standardization of renewable fuels at 60[deg] Fahrenheit ([deg]F) so 
renewable fuel volumes are accounted for on a uniform and consistent 
basis over the entire fuels industry. In the May 1, 2007 Renewable 
Fuels Standard (RFS) final rule the Agency required biodiesel 
temperature standardization to be completed as follows:

Vs,b = Va,b x (-0.0008008 x T + 1.0480)

Where

Vs,b = Standard Volume of biodiesel at 60 degrees F, in 
gallons;
Va,b = Actual volume of biodiesel, in gallons;
T = Actual temperature of batch, in degrees F.

    This equation was based on data from a published research paper by 
Tate et al.\36\ Members of the petroleum industry have indicated that 
the current biodiesel temperature standardization equation in the 
regulations provides different results than that commonly used by both 
the petroleum and biodiesel industry for commercial trading of 
biodiesel. These commercial values are either based on American 
Petroleum Institute (API) tables for petroleum products or on empirical 
values from industry measurements at common temperatures and pressures 
observed in bulk fuel facilities. The difference between RIN calculated 
volumes and commercial sales volumes has created confusion within the 
record keeping system of both the petroleum and biodiesel industry.
---------------------------------------------------------------------------

    \36\ Equation was derived from R.E. Tate et al. ``The Densities 
of Three Biodiesel Fuels at Temperatures up to 300 [deg]C.'', 
Department of Biological Engineering, Dalhousie University, April 
2005. ``Fuel 85 (2006) 1004-1009, Table 1 for soy methyl ester.''
---------------------------------------------------------------------------

    In the RFS2 proposed rule, the Agency proposed the temperature 
standardization of biodiesel remain unchanged from the RFS1 
requirements.\37\ The Agency received comments from Archer Daniels 
Midland Company (ADM), World Energy Alternatives, Marathon Petroleum 
Company (Marathon) and the National Biodiesel Board (NBB) to revise the 
biodiesel temperature standardization equation.
---------------------------------------------------------------------------

    \37\ 74 FR 24943, May 26, 2009.
---------------------------------------------------------------------------

    Both ADM and NBB agreed on the necessity for biodiesel temperature 
standardization at 60 [deg]F. ADM and NBB commented on several 
empirical calculations which have been developed specific to biodiesel 
temperature standardization since the 2007 RFS1 final rule. These 
include a 2004 data set developed by the Minnesota Department of 
Commerce and the Renewable Energy Group and updated in 2008; 
information embedded in the European Biodiesel Specification EN 14214; 
and information from the Alberta Research Council. The table below 
provides values from NBB for 1000 gallons of biodiesel standardized to 
a temperature at 60 [deg]F for these empirical calculations, along with 
the current EPA equation, and the American Petroleum Institute (API) 
Refined Products Table 6.

 Table III.G-1--NBB Comparison of Biodiesel Temperature Standardization
  Calculations to 60 [deg]F for 1000 gallons of Biodiesel at 90 [deg]F
------------------------------------------------------------------------
                                                                Gallons
------------------------------------------------------------------------
2007 EPA Biodiesel Formula..................................     975.28
2008 Minnesota (Hedman) data................................     986.270
API Refined Products Table 6 (biodiesel density @ 7.359)....     986.625
Alberta Research Council....................................     986.238
EN 14214 data...............................................     986.401
2004 Minnesota Renewable Energy Group data..................     986.830
------------------------------------------------------------------------

    As illustrated by the results from the above table, the values for 
the various biodiesel temperature standardization empirical 
calculations are within 1 gallon of agreement of each other for a 1000 
gallon biodiesel batch, except for the current biodiesel temperature 
standardization equation in the regulations.
    To ensure consistency in RIN generation, ADM commented EPA should 
adopt only one biodiesel temperature standardization calculation. ADM 
commented that all biodiesel temperature standardization calculations 
developed, including the API Refined Products Table 6, are in very 
close agreement with each other and the differences between them all 
are insignificant. They further commented the API Refined Products 
Table 6 has provided a uniform measurement of volume for years for the 
entire liquid fuels industry. Thus, ADM believes the API Refined 
Products Table 6 should be adopted for biodiesel to be consistent with 
the calculation of sales volumes.

[[Page 14740]]

Finally ADM comments adoption of the API Refined Products Table 6 would 
allow for easier verification within the marketplace, eliminate the 
need for calculating one volume for sales and trades and another for 
RINs, and prevents the entire distribution network from facing the 
financial burden of reprogramming existing meters that already are 
based on the API Refined Products Table 6.
    NBB commented that earlier surveys from its members indicate a 
fifty-fifty split between members using the API Refined Products Table 
6 or some variation of the current EPA biodiesel formula for biodiesel 
temperature standardization. Some NBB members indicated that the API 
Refined Products Table 6 was more commonly used by the petroleum 
industry and embedded into the meters, pumps and accounting systems of 
the petroleum industry. Companies already using the API Refined 
Products Table 6 would have a reduction in required paperwork with RIN 
generation and tracking because already existing commercial documents 
could serve that purpose and they thus could eliminate or reduce their 
current dual tracking system. Other NBB members have already embedded 
the current EPA biodiesel equation within their accounting and sales 
systems and would like to continue using that type of biodiesel 
temperature standardization approach rather than the API Refined 
Products Table 6. The NBB recommended EPA revise its current equation 
in the regulations to the 2008 Hedman biodiesel temperature 
standardization equation. Thus, NBB commented EPA should provide 
flexibility to their members by allowing the use of either the API 
Refined Products Table 6 or the use of a biodiesel temperature 
standardization equation.
    Marathon commented the regulations allow for the standardization of 
volume for other renewable fuels to be determined by an appropriate 
formula commonly accepted by the industry which may be reviewed by the 
EPA for appropriateness. They recommended that EPA extend this courtesy 
to biodiesel.
    The Agency acknowledges that the current biodiesel temperature 
standardization equation is likely not correct for biodiesel 
temperature standardization at ambient temperatures observed in the 
fuel distribution system. Based on the comments received, the Agency is 
amending the regulations to allow for two ways for biodiesel 
temperature standardization: (1) The American Petroleum Institute 
Refined Products Table 6B, as referenced in ASTM D1250-08, entitled, 
``Standard Guide for Use of the Petroleum Measurement Tables'', and (2) 
a biodiesel temperature standardization equation that utilizes the 2008 
data generated by the Minnesota Department of Commerce and the 
Renewable Energy Group. These two methods for biodiesel temperature 
standardization are within one gallon of agreement of each other for a 
1000 gallon biodiesel batch and thus in very close agreement. Both ADM 
and NBB acknowledged that the differences between these two methods are 
insignificant and the resulting corrected volumes from these two 
methods of calculation are within accuracy tolerances of any metered 
measurement. Thus, the Agency believes the allowance of both of these 
methods for biodiesel temperature standardization will increase 
flexibility while still providing for a consistent generation and 
accounting of biodiesel RINs over the entire fuel delivery system.

IV. Renewable Fuel Production and Use

    An assessment of the impacts of increased volumes of renewable fuel 
must begin with an analysis 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 an assessment of the 
potential feedstocks and renewable fuels that could 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 cases 
for analysis purposes. As new technologies, feedstocks, and fuels 
continue to develop on a daily basis, markets may appear differently 
from our projections. Although actual volumes and feedstocks may 
differ, we believe the projections made for our control cases are 
within the range of possible predictions for which the standards are 
met and allow for an assessment of the potential impacts of the 
increases in renewable fuel volumes that meet the requirements of EISA.

A. Overview of Renewable Fuel 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 reference and control cases from which subsequent 
analyses are based. The reference cases are projections of renewable 
fuel volumes without the enactment of EISA and are described in Section 
IV.A.1. The control cases are projections of the volumes and types of 
renewable fuel that might be used in the future to comply with the EISA 
volume mandates. For the NPRM we had focused on one primary control 
case (see Section IV.A.2) whereas for the final rule we have expanded 
the analysis to include two additional sensitivity cases (see Section 
IV.A.3). Based on the public comments received as well as new 
information, we have updated the primary control case volumes from the 
NPRM to reflect what we believe could be a more likely set of volumes 
to analyze. We assume in each of the cases the same ethanol-equivalence 
basis as was used in the RFS1 rulemaking to meet the standard. Volumes 
are listed in tables for this section in both straight-gallons and 
ethanol-equivalent gallons (i.e., times 1.5 for biodiesel or 1.7 for 
cellulosic diesel and renewable diesel). The volumes included in this 
section are for 2022. For intermediate years, refer to Section 1.2 of 
the RIA.
1. Reference Cases
    Our primary reference case renewable fuel volumes are based on the 
Energy Information Administration's (EIA) Annual Energy Outlook (AEO) 
2007 reference case projections.\38\ While AEO 2007 is not as up-to-
date as AEO 2008 or AEO 2009, we chose to use AEO 2007 because later 
versions of AEO already include the impact of increased renewable fuel 
volumes under EISA as well as fuel economy improvements under CAFE as 
required in EISA, whereas AEO 2007 did not.
---------------------------------------------------------------------------

    \38\ AEO 2007 was only used to derive renewable fuel volume 
projections for the primary reference case. AEO 2009 was used for 
future crude oil cost estimates and for estimating total 
transportation fuel energy use.
---------------------------------------------------------------------------

    For the final rule we have also assessed a number of the impacts 
relative to a reference case assuming the mandated renewable fuel 
volumes under RFS1 from the Energy Policy Act of 2005 (EPAct). This 
allows for a more complete assessment of the impacts of the EISA volume 
mandates, especially when combined with the impacts assessment 
conducted for the RFS1 rulemaking (though many factors have changed 
since then). Table IV.A.1-1 summarizes the 2022 renewable fuel volumes 
for the AEO 2007 and the RFS1 reference cases (listed in both straight 
volumes and ethanol-equivalent volumes).

[[Page 14741]]



                                              Table IV.A.1-1--Reference Case Renewable Fuel Volumes in 2022
                                                                    [Billion gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                  Advanced biofuel                      Non-advanced
                                                               ------------------------------------------------------      biofuel
                                                                   Cellulosic       Biomass-based    Other advanced  ------------------
                      Source/volume type                             biofuel          diesel a           biofuel                         Total renewable
                                                               ------------------------------------------------------                         fuel
                                                                   Cellulosic                                           Corn ethanol
                                                                    ethanol c     FAME biodiesel b  Imported ethanol
--------------------------------------------------------------------------------------------------------------------------------------------------------
AEO 2007 Straight Volume......................................              0.25              0.38              0.64             12.29             13.56
AEO 2007 Ethanol-Equivalent...................................              0.25              0.58              0.64             12.29             13.76
RFS 1 Straight Volume.........................................              0.00              0.30              0.00              7.05              7.35
RFS 1 Ethanol-Equivalent......................................              0.00              0.45              0.00              7.05              7.50
--------------------------------------------------------------------------------------------------------------------------------------------------------
a Biomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.
b Only fatty acid methyl ester (FAME) biodiesel volumes were considered.
c Under the RFS1 reference case, we assumed the 250-million gallon cellulosic standard set by EPAct would be met primarily by corn ethanol plants
  utilizing 90% biomass for energy, thus actual production of cellulosic biofuel is zero. AEO 2007 reference case assumes actual production of
  cellulosic biofuel and therefore assumed to be 0.25 billion gallons.

2. Primary Control Case
    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 increased volumes of renewable fuel, we 
projected a set of reasonable renewable fuel volumes based on our 
projection of fuels that could come to market.
    Although actual volumes and feedstocks will be different, we 
believe the projections made for our control cases are within the range 
of possible predictions for which the standards are met and allow for 
an assessment of the potential impacts of increased volumes of 
renewable fuel. Table IV.A.2-1 summarizes the fuel types used for the 
primary control case and their corresponding volumes for the year 2022.

                                      Table IV.A.2-1--Primary Control Case Projected Renewable Fuel Volumes in 2022
                                                                    [Billion gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Advanced biofuel                                    Non-
                                                 ------------------------------------------------------------------------------   advanced
                                                     Cellulosic biofuel     Biomass-based diesel \a\   Other advanced biofuel     biofuel       Total
                   Volume type                   -------------------------------------------------------------------------------------------  renewable
                                                                                                         Other                                   fuel
                                                   Cellulosic   Cellulosic    FAME \c\     NCRD \d\    biodiesel     Imported       Corn
                                                    ethanol     diesel \b\   biodiesel                    \e\        ethanol      ethanol
--------------------------------------------------------------------------------------------------------------------------------------------------------
Straight Volume.................................         4.92         6.52         0.85         0.15         0.82         2.24        15.00        30.50
Ethanol-Equivalent..............................         4.92        11.08         1.28         0.26         1.23         2.24        15.00        36.00
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.
\b\ Cellulosic Diesel includes at least 1.96 billion gallons (3.33 billion ethanol-equivalent gallons) from Fischer-Tropsch Biomass-to-Liquids (BTL)
  processes based on EIA's forecast and an additional 4.56 billion gallons (7.75 billion ethanol-equivalent gallons) from this or other types of
  cellulosic diesel processes.
\c\ Fatty acid methyl ester (FAME) biodiesel.
\d\ Non-Co-processed Renewable Diesel (NCRD).
\e\ Other Biodiesel is biodiesel that could be produced in addition to the amount needed to meet the biomass-based diesel standard.

    The following subsections detail our rationale for projecting the 
amount and type of fuels needed to meet EISA as shown in Table IV.A.2-
1. For cellulosic biofuel we have assumed that by 2022 on a straight-
volume basis about half would come from cellulosic ethanol and the 
other half from cellulosic diesel. On an ethanol-equivalent volume 
basis, cellulosic diesel would make up almost 70% of the 16 billion 
gallons cellulosic biofuel standard. 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 by cellulosic biofuel and 
biomass-based diesel is assumed to come mainly from imported sugarcane 
ethanol with a smaller amount from additional biodiesel sources. The 
total renewable fuel volume not required to be comprised of advanced 
biofuels is assumed to be met with corn ethanol with small amounts of 
other grain starches and waste sugars.
    The main difference between the volumes used for the NPRM and the 
volumes used for the FRM is the inclusion of cellulosic diesel for the 
FRM. The NPRM made the simplifying assumption that the cellulosic 
biofuel standard would be met entirely with cellulosic ethanol. 
However, due to growing interest and recent developments in 
hydrocarbon-based or so-called ``drop-in'' renewable fuels as well as 
butanol, and marketplace challenges for consuming high volumes of 
ethanol, we have included projections of more non-ethanol renewables in 
our primary control case for the final rule.\39\ In the future, this 
could include various forms of ``green hydrocarbons'' (i.e., cellulosic 
gasoline, diesel and jet) and higher alcohols, but

[[Page 14742]]

for analysis purposes, we have modeled it as cellulosic diesel fuel. We 
describe these fuels in greater detail in Section IV.B-D. We have also 
included some algae-derived biofuels in our FRM analyses given the 
large interest and potential for such fuels. We have continued to 
assume zero volume for renewable fuels or blendstocks such as biogas, 
jatropha, palm, imported cellulosic biofuel, and other alcohols or 
ethers in our control cases. Although we have not included these 
renewable fuels and blendstocks in our impact analyses, it is important 
to note that they can still be counted under our program if they meet 
the lifecycle thresholds and definitions for renewable biomass, and 
recent information suggests that some of them may be likely.
---------------------------------------------------------------------------

    \39\ Comments received from Advanced Biofuels Association, 
Testimony on June 9, 2009 suggesting a number of advanced biofuel 
technologies will be able to produce renewable diesel, jet fuels, 
gasoline, and gasoline component fuels (e.g. butanol, iso-octane). 
Similar comments were received from the New York State Department of 
Environmental Conservation (Docket EPA-HQ-OAR-2005-0161-2143), OPEI 
and AllSAFE (Docket EPA-HQ-OAR-2005-0161-2241), and the Low Carbon 
Synthetic Fuels Association (Docket EPA-HQ-OAR-2005-0161-2310).
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a. Cellulosic Biofuel
    As discussed in our NPRM, whether cellulosic biofuel is ethanol 
will depend on a number of factors, including production costs, the 
form of tax subsidies, credit programs, and factors influencing the 
blending of biofuel into the fuel pool. It will also depend on the 
relative demand for gasoline and diesel fuel. As a result of our 
analyses on ethanol consumption (see Section IV.D) and continual 
tracking of the industry's interest in hydrocarbon-based renewables 
(see Section IV.B), we have decided to analyze a cellulosic biofuel 
standard made up of both cellulosic ethanol and cellulosic diesel 
fuels.
    For assessing the impacts of the RFS2 standards, we used AEO 2009 
(April release) cellulosic ethanol volumes (4.92 billion gallons), as 
well as the cellulosic biomass-to-liquids (BTL) diesel volumes (1.96 
billion gallons) using Fischer-Tropsch (FT) processes. We consider BTL 
diesel from FT processes as a subset of cellulosic diesel. In order to 
reach a total of 16 billion ethanol-equivalent gallons, we assumed that 
an additional 4.56 billion gallons of cellulosic diesel could be 
produced from other cellulosic diesel processes. Refer to Section 1.2 
of the RIA for more discussion.
b. Biomass-Based Diesel
    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 could potentially contribute to the biomass-based diesel 
category, we have assumed for our analyses that the fuel produced 
through Fischer-Tropsch (F-T) or other processes and its corresponding 
feedstocks (cellulosic biomass) are already accounted for in the 
cellulosic biofuel category discussed previously in Section IV.A.2.a.
    FAME and RD processes can both utilize vegetable oils, rendered 
fats, and greases, and thus will generally compete for the same 
feedstock pool. We have based RD volumes on our forecast of industry 
plans, and expect these plants to use rendered fats as feedstock. Most 
biodiesel plants now have the capability to use vegetable or animal 
fats as feedstock, and thus our analysis assumes biodiesel will be made 
from a mix of inputs, depending on local availability, economics, and 
season. Refer to Section 1.1 of the RIA for more detail on FAME and RD 
feedstocks
    Renewable diesel production can be further classified as co-
processed or non-co-processed, depending on whether the renewable 
material is mixed with petroleum during the hydrotreating operations. 
EISA specifically forbids co-processed RD from being counted as 
biomass-based diesel, but it can still count toward the total advanced 
biofuel requirement. At this time, based on current industry plans, we 
expect most, if not all, RD will be non-co-processed (that is, non-
refinery operations).
    Perhaps the feedstock with the greatest potential for providing 
large volumes of oil for the production of biomass-based diesel is 
algae. 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 feedstocks. For 
all three control cases, we have chosen to include 100 million gallons 
of algae-based biodiesel by 2022. We believe this is reasonable given 
several announcements from the algae industry about their production 
plans.\40\ Although algae to biofuel companies can focus 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. For more detail on algae as a feedstock, refer to 
Section 1.1 of the RIA.
---------------------------------------------------------------------------

    \40\ Sapphire Energy plans for 135 MMgal by 2018 and 1 Bgal by 
2025; Petrosun plans for 30 MMgal/yr facility; Solazyme plans for 
100 MMgal by 2012/13; U.S. Biofuels plans for 4 MMgal by 2010 and 50 
MMgal by full scale. Only several companies have thus far revealed 
production plans, and more are announced each day. It is important 
to realize that future projections are highly uncertain, and we have 
taken into account the best information we could acquire at the 
time.
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    During the comment period, we received information from 
stakeholders on alternative biodiesel feedstocks such as camelina and 
pennycress, to name a few. These feedstocks are currently being 
researched due to their potential for lower agricultural inputs and 
higher oil yields than traditional vegetable oil feedstocks as well as 
their use in additional crop rotations (i.e., winter cover crops) on a 
given area of land. We acknowledge that as we learn more about the 
challenges and benefits to the use of newer feedstocks, these could be 
used in the future towards meeting the biomass-based diesel standard 
under the RFS2 program provided they meet the lifecycle thresholds and 
definitions for renewable biomass. For the purpose of our impacts 
analysis, however, we have chosen not to include these feedstocks in 
our analyses at this time.
c. Other Advanced Biofuel
    As defined in EISA, advanced biofuel includes the cellulosic 
biofuel and biomass-based diesel categories that were mentioned in 
Sections IV.A.2.a and IV.A.2.b above. However, EISA requires greater 
volumes of advanced biofuel than just the volumes required of these 
fuels. It is entirely possible that greater volumes of cellulosic 
biofuel and biomass-based diesel than required by EISA could be 
produced in the future. Our control case assumes that the cellulosic 
biofuel volumes will not exceed those required under EISA. We do 
assume, however, that additional biodiesel than that needed to meet the 
biomass-based diesel volume will be used to meet the total advanced 
biofuel volume. Despite additional volumes assumed from biodiesel, to 
fully meet the total advanced biofuel volume required under EISA, other 
types of advanced biofuel are necessary through 2022.
    We have assumed for our control case that the most likely sources 
of advanced fuel other than cellulosic biofuel and biomass-based diesel 
would be from imported sugarcane ethanol and perhaps limited amounts of 
co-processed renewable diesel. 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 
advanced biofuel standards, we assumed it would make up the difference 
not met by cellulosic biofuel, biomass-based diesel and additional 
biodiesel categories (see Table IV.A.2-1). The amount of imported 
ethanol required by 2022 is approximately 2.2 Bgal.

[[Page 14743]]

    As discussed in the NPRM, other potential advanced biofuels could 
include for example, U.S. domestically produced sugarcane ethanol, 
biobutanol, and biogas. While we have not chosen to reflect these fuels 
in our control case, they can still be counted under our program 
assuming they meet the lifecycle thresholds and other definitions under 
the program.
d. Other Renewable Fuel
    The remaining portion of total renewable fuel not met with advanced 
biofuel was assumed to come from corn-based ethanol (including small 
amounts from other grains and waste sugars). EISA effectively sets a 
limit for participation in the RFS program of 15 Bgal of corn ethanol, 
and we are assuming for our analysis that sufficient corn ethanol will 
be produced to meet the 15-Bgal limit that either meets the 20% GHG 
threshold or is grandfathered. 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 (2010-2015) in which we project that some 
fuels could compete favorably with corn ethanol (e.g., biodiesel and 
imported ethanol). Refer to Section 1.2 of the RIA for more details on 
interim years. Beginning around 2016, fuels qualifying as advanced 
biofuels likely will be devoted to meeting the increasingly stringent 
volume mandates for advanced biofuel. It is also important to note that 
more than 15 Bgal of corn ethanol could be produced and RINs generated 
for that volume under the RFS2 regulations. However, obligated parties 
would not be required to purchase more than 15 Bgal worth of non-
advanced biofuel RINs, e.g. corn ethanol RINs.
3. Additional Control Cases Considered
    Since there is significant uncertainty surrounding what fuels will 
be produced to meet the 16 billion gallon cellulosic biofuel standard, 
we have decided to investigate two other sensitivity cases for our cost 
and emission impact analyses conducted for the rule. The first case, we 
refer to as the ``low-ethanol'' control case and assume only 250 
million gallons of cellulosic ethanol (from AEO 2007 reference case). 
The rest of the 16 billion gallon cellulosic biofuel standard is made 
up of cellulosic diesel as shown in Table IV.A.3-1. The second case, we 
refer to as the ``high-ethanol'' control case and assume the entire 16 
billion gallon cellulosic biofuel standard is met with cellulosic 
ethanol, also shown in Table IV.A.3-1.

                                          Table IV.A.3-1--Control Case Projected Renewable Fuel Volumes in 2022
                                                                    [Billion gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Advanced biofuel                                    Non-
                                                 ------------------------------------------------------------------------------   advanced
                                                     Cellulosic biofuel     Biomass-based diesel \a\   Other advanced biofuel     biofuel       Total
                Case/volume type                 -------------------------------------------------------------------------------------------  renewable
                                                                                                         Other                                   fuel
                                                   Cellulosic   Cellulosic    FAME \c\     NCRD \d\    biodiesel     Imported       Corn
                                                    ethanol     diesel \b\   biodiesel                    \e\        ethanol      ethanol
--------------------------------------------------------------------------------------------------------------------------------------------------------
Low-Ethanol Straight Volume.....................         0.25         9.26         0.85         0.15         0.82         2.24        15.00        28.57
Low-Ethanol Ethanol-Equivalent..................         0.25        15.75         1.28         0.26         1.23         2.24        15.00        36.00
High-Ethanol Straight Volume....................        16.00         0.00         0.85         0.15         0.82         2.24        15.00        35.06
High-Ethanol Ethanol-Equivalent.................        16.00         0.00         1.28         0.26         1.23         2.24        15.00        36.00
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.
\b\ Cellulosic Diesel includes 1.96 billion gallons (3.33 ethanol-equivalent billion gallons) from Fischer-Tropsch Biomass-to-Liquids (BTL) processes
  and 7.30 billion gallons (12.42 ethanol-equivalent billion gallons) from other types of cellulosic diesel processes for the Low-Ethanol case and zero
  cellulosic diesel in the High-Ethanol Case.
\c\ Fatty acid methyl ester (FAME) biodiesel.
\d\ Non-Co-processed Renewable Diesel (NCRD).
\e\ Other Biodiesel is biodiesel that could be produced in addition to the amount needed to meet the biomass-based diesel standard.

    In comparison, our primary control case described in Section 
IV.A.2, could be considered a ``mid-ethanol'' control case, as the 
cellulosic ethanol and diesel volumes analyzed are in between the low-
ethanol and high-ethanol cases described in this section. We believe 
the addition of these sensitivity cases is useful in understanding the 
potential impacts of the renewable fuels standards. Refer to Section 
1.2 of the RIA for more detail on three control cases analyzed as part 
of this rule.

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 summarize the present state of the 
corn/starch ethanol industry and discuss how we expect things to change 
in the future under the RFS2 program.
a. Historic/Current Production
    The United States is currently the largest ethanol producer in the 
world. In 2008, the U.S. produced nine billion gallons of fuel ethanol 
for domestic consumption, the majority of which came from locally grown 
corn.\41\ The nation is currently on track for producing over 10 
billion gallons by the end of 2009.\42\ Although the U.S. ethanol 
industry has been in existence since the 1970s, it has rapidly expanded 
in recent years due to the phase-out of methyl tertiary butyl ether 
(MTBE), elevated crude oil prices, state mandates and tax incentives, 
the introduction of the Federal Volume Ethanol Excise Tax

[[Page 14744]]

Credit (VEETC),\43\ the implementation of the existing RFS1 
program,\44\ and the new volume requirements established under EISA. As 
shown in Figure IV.B.1-1, U.S. ethanol production has grown 
exponentially over the past decade.
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    \41\ Based on total transportation ethanol reported in EIA's 
September 2009 Monthly Energy Review (Table 10.2) less imports 
(http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
    \42\ Based on ethanol projected in EIA's October 2009 Short Term 
Energy Outlook less projected imports. Actual year-end data for 2009 
was unavailable at the time of this FRM assessment.
    \43\ 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 ethanol blender credit replaced the former fuel excise tax 
exemption, blender's credit, and pure ethanol fuel credit. However, 
the 2008 Farm Bill modified the alcohol credit so that corn ethanol 
gets a reduced credit of $0.45/gal and cellulosic biofuel gets a 
credit of $1.01/gal.
    \44\ On May 1, 2007, EPA published a final rule (72 FR 23900) 
implementing the Renewable Fuel Standard required by EPAct (also 
known as RFS1). RFS1 requires that 4.0 billion gallons of renewable 
fuel be blended into gasoline/diesel by 2006, growing to 7.5 billion 
gallons by 2012.
[GRAPHIC] [TIFF OMITTED] TR26MR10.419

    As of November 2009 there were 180 corn/starch ethanol plants 
operating in the U.S. with a combined production capacity of 
approximately 12 billion gallons per year.\46\ This does not include 
idled ethanol plants, discussed later in this subsection. The majority 
of today's ethanol production (91.5% by volume) comes from 155 plants 
relying exclusively on corn. Another 8.3% comes from 18 plants 
processing a blend of corn and/or similarly processed grains (milo, 
wheat, or barley). The remainder comes from seven small plants 
processing waste beverages or other waste sugars and starches.
---------------------------------------------------------------------------

    \45\ Based on total transportation ethanol reported in EIA's 
September 2009 Monthly Energy Review (Table 10.2) less imports 
(http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
    \46\ Our November 2009 corn/starch ethanol industry 
characterization was based on a variety of sources including plant 
lists published online by the Renewable Fuels Association and 
Ethanol Producer Magazine (updated October 22, 2009), information 
from ethanol producer Web sites including press releases, and 
follow-up correspondence with producers. 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.
---------------------------------------------------------------------------

    Of the 173 plants processing corn and/or other similarly processed 
grains, 162 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 plants using front-end 
fractionation to produce food-grade corn oil or back-end extraction to 
produce fuel-grade corn oil for the biodiesel industry. A company 
called GreenShift has corn oil extraction facilities located at five 
ethanol plants in Michigan, Indiana, New York and Wisconsin.\47\ 
Collectively, these facilities are designed to extract in excess of 7.3 
million gallons of corn oil per year. Primafuel Solutions is another 
company offering corn oil extraction technologies to make existing 
ethanol plants more sustainable. For more information on corn oil 
extraction and other advanced technologies being pursued by today's 
corn ethanol industry, refer to Section 1.4.1 of the RIA.
---------------------------------------------------------------------------

    \47\ Two plants in Michigan and one in each of the other three 
states. All company information based on GreenShift's Q2 2009 SEC 
filing available at http://www.greenshift.com/pdf/GERS_Form10Q_Q209_FINAL.pdf.
---------------------------------------------------------------------------

    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

[[Page 14745]]

plants are generally more costly to build but are larger in size on 
average.\48\ As such, 11.4% of the current grain ethanol production 
comes from the 11 previously mentioned wet mill facilities.
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    \48\ According to our November 2009 corn ethanol plant 
assessment, the average wet mill plant capacity is 125 million 
gallons per year--almost twice that of the average dry mill plant 
capacity (65 million gallons per year). For more on average plant 
sizes, refer to Section 1.5 of the RIA.
---------------------------------------------------------------------------

    The remaining seven ethanol plants process waste beverages or waste 
sugars/starches and operate differently than their grain-based 
counterparts. These small production facilities do not require milling 
and operate simpler enzymatic fermentation processes.
    Ethanol production is a relatively resource-intensive process that 
requires the use of water, electricity, and steam. Steam needed to heat 
the process is generally produced on-site or by other dedicated 
boilers.\49\ The ethanol industry relies primarily on natural gas. Of 
today's 180 ethanol production facilities, an estimated 151 burn 
natural gas \50\ (exclusively), three burn a combination of natural gas 
and biomass, one burns natural gas and coal (although natural gas is 
the primary fuel), one burns a combination of natural gas, landfill 
biogas and wood, and two burn natural gas and syrup from the process. 
We are aware of 17 plants that burn coal as their primary fuel and one 
that burns a combination of coal and biomass.\51\ Our research suggests 
that three corn ethanol plants rely on a combination of waste heat and 
natural gas and one plant does not have a boiler and relies solely on 
waste heat from a nearby power plant. Overall, our research suggests 
that 27 plants currently utilize cogeneration or combined heat and 
power (CHP) technology, although others may exist.\52\ 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.\53\
---------------------------------------------------------------------------

    \49\ Some plants pull steam directly from a nearby utility.
    \50\ Facilities were assumed to burn natural gas if the plant 
boiler fuel was unspecified or unavailable on the public domain.
    \51\ Includes corrections from NPRM based on new information 
obtained on Cargill plants and Blue Flint ethanol plant.
    \52\ CHP assessment based on information provided by EPA's 
Combined Heat and Power Partnership, literature searches and 
correspondence with ethanol producers.
    \53\ For more on CHP technology, refer to Section 1.4.1.3 of the 
RIA.
---------------------------------------------------------------------------

    During the ethanol fermentation process, large amounts of carbon 
dioxide (CO2) gas are released. In some plants the 
CO2 is vented into the atmosphere, but where local markets 
exist, it is captured, purified, and sold to the food processing 
industry for use in carbonated beverages and flash-freezing 
applications. We are currently aware of 40 fuel ethanol plants that 
recover CO2 or have facilities in place to do so. According 
to Airgas, a leading gas distributor, the U.S. ethanol industry 
currently recovers 2 to 2.5 million tons of CO2 per year 
which translates to about 5-7% of all the CO2 produced by 
the industry.\54\
---------------------------------------------------------------------------

    \54\ Based on information provided by Bruce Woerner at Airgas on 
August 14, 2009.
---------------------------------------------------------------------------

    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 180 ethanol production facilities, 163 are located in the 15 
states comprising PADD 2. For a map of the government's Petroleum 
Administration for Defense Districts or PADDs, refer to Figure IV.B.1-
2.
[GRAPHIC] [TIFF OMITTED] TR26MR10.420

    As a region, PADD 2 accounts for over 94% (or 11.3 billion gallons) 
of today's estimated ethanol production capacity, followed by PADD 3 
(2.4%), PADDs 4 and 1 (each with 1.3%) and PADD 5 (0.8%). For more 
information on today's ethanol plant locations, refer to Section 1.5.1 
of the RIA.
    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, these facilities account for about 80% of today's 
online ethanol production capacity.\55\ Furthermore, nearly 30% of the 
total domestic product comes from 40 plants owned by just three 
different companies--POET Biorefining, Archer Daniels Midland (ADM), 
and Valero Renewables. Valero entered the ethanol industry in March of 
2009 when it acquired seven ethanol plants from

[[Page 14746]]

former ethanol giant, Verasun. The oil company currently has agreements 
in place to purchase three more ethanol plants that would bring the 
company's ethanol production capacity to 1.1 billion gallons per 
year.\56\ However, ethanol plants are much smaller than petroleum 
refineries. Valero's smallest petroleum refinery in Ardmore, OK has 
about twice the throughput of all its ethanol plants combined.\57\ 
Still, as obligated parties under RFS1 and RFS2, the refining industry 
continues to show increased interest in biofuels. Suncor and Murphy Oil 
recently joined Valero as the second and third oil companies to 
purchase idled U.S. ethanol plants. Many refiners are also supporting 
the development of cellulosic biofuels and algae-based biodiesel.
---------------------------------------------------------------------------

    \55\ Company-owned plants were assumed to be all those companies 
not denoted as locally-owned based on Renewable Fuels Association 
(RFA), Ethanol Biorefinery Locations (updated October 22, 2009). For 
more on average plant sizes, refer to Section 1.5.1 of the RIA.
    \56\ Valero recently announced that it has purchase agreements 
in place to acquire the last two Verasun plants in Linden, IN and 
Bloomington, OH and the former Renew Energy plant in Jefferson 
Junction, WI.
    \57\ Based on refinery information provided at http://www.valero.com/OurBusiness/OurLocations/.
---------------------------------------------------------------------------

b. Forecasted Production Under RFS2
    As highlighted earlier, domestic ethanol production is projected to 
grow to over 10 billion gallons in 2009. And with over 12 billion 
gallons of capacity online as of November 2009, ethanol production 
should continue to grow in 2010, provided plants continue to produce at 
or above today's production levels. In addition, despite current market 
conditions (i.e., poor ethanol margins), the ethanol industry is 
expected to grow in the future under the RFS2 program. Although there 
is not a set corn ethanol requirement, EISA allows for 15 billion 
gallons of the 36-billion gallon renewable fuel standard to be met by 
conventional biofuels. We expect that corn ethanol will fulfill this 
requirement, provided it is more cost competitive than imported ethanol 
or cellulosic biofuel in the marketplace.
    In addition to the 180 aforementioned corn/starch ethanol plants 
currently online, 27 plants are presently idled.\58\ Some of these are 
smaller ethanol plants that have been idled for quite some time, 
whereas others are in a more temporary ``hot idle'' mode, ready to be 
restarted. In response to the economic downturn, a number of ethanol 
producers have idled production, halted construction projects, sold off 
plants and even filed for Chapter 11 bankruptcy protection. Some corn 
ethanol companies have exited the industry all together (e.g., Verasun) 
whereas others are using bankruptcy as a means to protect themselves 
from creditors as they restructure their finances with the goal of 
becoming sustainable.
---------------------------------------------------------------------------

    \58\ Based on our November 2009 corn/starch ethanol industry 
characterization. We are aware of at least one plant that has come 
back online since then.
---------------------------------------------------------------------------

    Crude oil prices are expected to increase in the future making corn 
ethanol more economically viable. According to EIA's AEO 2009, crude 
oil prices are projected to increase from about $80/barrel (today's 
price) to $116/barrel by 2022.\59\ As oil and gas prices rebound, we 
expect that the biofuels industry will as well. Since our April 2009 
industry assessment used for the NPRM, at least nine corn ethanol 
plants have come back online.
---------------------------------------------------------------------------

    \59\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 12).
---------------------------------------------------------------------------

    For analysis purposes, we assumed that all 27 idled corn/starch 
ethanol plants would resume operations by 2022 under the RFS2 program. 
We also assumed that a total of 11 new ethanol plants and two expansion 
projects currently under construction or in advanced stages of planning 
would come online.\60\ This includes two large dry mill expansion 
projects currently underway at existing ADM wet mill plants and two 
planned combination corn/cellulosic ethanol plants that received 
funding from DOE. While several of these projects are delayed or on 
hold at the moment, we expect that these facilities (or comparable 
replacement projects) would eventually come online to get the nation to 
approximately 15 billion gallons of corn ethanol production capacity.
---------------------------------------------------------------------------

    \60\ Sources include Renewable Fuels Association, Ethanol 
Biorefinery Locations (updated October 22, 2009) and Ethanol 
Producer Magazine, Producing, Not Producing, Under Construction, and 
Expansions lists (last modified on October 22, 2009) in addition to 
information gathered from producer Web sites and follow-up 
correspondence.
---------------------------------------------------------------------------

    Almost 100% of conventional ethanol plant growth is expected to 
come from facilities processing corn or other similarly processed 
grains. And not surprisingly, the majority of growth (approximately 70% 
by volume) is expected to originate from PADD 2. However, growth is 
expected to occur in all PADDs. With the exception of one facility,\61\ 
all new corn/grain ethanol plants are expected to utilize dry milling 
technologies and the majority of new production is expected to come 
from plants burning natural gas. However, we anticipate that two manure 
biogas plants,\62\ one biomass-fired plant, and two coal-fired ethanol 
plants will be added to the mix.\63\ Of these new and returning idled 
plants, we're aware of five facilities currently planning to use CHP 
technology, bringing the U.S. total to 32.
---------------------------------------------------------------------------

    \61\ Tate and Lyle is currently in the process of building a 115 
MGY wet mill corn ethanol plant in Fort Dodge, IA.
    \62\ One manure biogas plant that is currently idled and another 
that was under construction but is now on hold.
    \63\ The two coal fired plants are the aforementioned dry mill 
expansion projects currently underway at existing ADM sites. These 
projects commenced construction on or before December 19, 2007 and 
would therefore should likely be grandfathered under the RFS2 rule. 
For more on our grandfathering assessment, refer to Section 1.5.1.4 
of the RIA.
---------------------------------------------------------------------------

    The above predictions are based on the industry's current near-term 
production plans. However, we anticipate additional growth in advanced 
ethanol production technologies under the RFS2 program. Forecasted fuel 
prices are projected to drive corn ethanol producers to transition from 
conventional boiler fuels to biomass feedstocks. In addition, fossil 
fuel/electricity prices will likely 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 RIA.
2. Imported Ethanol
    As discussed in the proposal, 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. Between years 2000 and 2008, the volume of ethanol imported 
into the U.S. has ranged from 46-720 million gallons per year. So far 
this year, from January through November 2009, imported ethanol has 
only reached 197 million gallons.\64\ As the data show, the volume of 
imported ethanol can fluctuate greatly.
---------------------------------------------------------------------------

    \64\ Official Statistics of the U.S. Department of Commerce, 
U.S. ITC.
---------------------------------------------------------------------------

    In the past, the majority of volume has originated from countries 
that are part of the Caribbean Basin Initiative. Direct Brazilian 
imports have also made up a sizeable portion of total ethanol imported 
into the U.S. However, recently there have been relatively small 
amounts of direct imports of ethanol from Brazil.\65\ This indicates 
that current market conditions have made importing Brazilian ethanol 
directly to the U.S. uneconomical. Part of the reason for this decline 
in imports is the cessation of the duty drawback that became effective 
on October 1, 2008, but also changes in world sugar prices.\66\
---------------------------------------------------------------------------

    \65\ Approximately 19,000 gallons directly from Brazil in the 
month of June 2009 and 4 million gallons from Brazil in the month of 
November 2009, zero gallons reported from November 2008-May 2009 and 
July 2009-October 2009.
    \66\ Lundell, Drake, ``Brazilian Ethanol Export Surge to End; 
U.S. Customs Loophole Closed Oct. 1,'' Ethanol and Biodiesel News, 
Issue 45, November 4, 2008.

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

[[Page 14747]]

    It is difficult to project the potential volume of future ethanol 
imports to the U.S. based purely on historical data. Rather, it is 
necessary to assess future import potential by analyzing the major 
players for foreign ethanol production and consumption. 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.\67\ Consumption of fuel ethanol is also dominated by the 
United States and Brazil with approximately 9.6 and 4.9 billion gallons 
consumed in each country, respectively.68 69 The EU consumed 
approximately 0.9 billion gallons of fuel ethanol in 2008.\70\
---------------------------------------------------------------------------

    \67\ Renewable Fuels Association (RFA), ``2008 World Fuel 
Ethanol Production, '' http://www.ethanolrfa.org/industry/statistics/#E, March 31, 2009.
    \68\ Ibid.
    \69\ UNICA, ``Sugarcane Industry in Brazil: Ethanol Sugar, 
Bioelectricity'' Brochure, 2008.
    \70\ EurObserv'ER, ``Biofuels Barometer'' July 2009, http://www.eurobserv-er.org/pdf/baro192.pdf.
---------------------------------------------------------------------------

    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.
    Due to uncertainties in the future demand for ethanol domestically 
and internationally, uncertainties in the actual investments made in 
the Brazilian ethanol industry, as well as uncertainties in future 
sugar prices, there appears to be a wide range of Brazilian production 
and domestic consumption estimates. The most current and complete 
estimates indicate that total Brazilian ethanol exports will likely 
reach 3.8-4.2 billion gallons by 2022.71 72 73 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 about 2.2 billion 
gallons (see Table IV.A.2-1), or approximately 55% of total Brazilian 
ethanol export estimates. This is aggressive, yet within the bounds of 
reason, therefore, we have made this simplifying assumption for the 
purposes of further analysis.
---------------------------------------------------------------------------

    \71\ EPE, ``Plano Nacional de Energia 2030,'' Presentation from 
Mauricio Tolmasquim, 2007.
    \72\ UNICA, ``Sugarcane Industry in Brazil: Ethanol, Sugar, 
Bioelectricity,'' 2008.
    \73\ 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).
---------------------------------------------------------------------------

    Generally speaking, Brazilian ethanol exporters will seek routes to 
countries with the lowest costs for transportation, taxes, and tariffs. 
With respect to the U.S., the most likely route is through the 
Caribbean Basin Initiative (CBI).\74\ Brazilian ethanol entering the 
U.S. through CBI countries is not currently subject to the 54 cent/gal 
imported ethanol tariff and yet receives the 45 cent/gal ethanol 
blender credit. In addition to the U.S., other countries also have 
similar tariffs on imported ethanol. Refer to Section 1.5.2 of the RIA 
for more details. 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 2021 was 19.2 Bgal (under the 
primary control case), then approximately 1.21 Bgal of ethanol could 
enter the U.S. through CBI countries in 2022. 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. To meet our advanced biofuel standard, we assumed 1.03 Bgal of 
sugarcane ethanol would be imported directly to the U.S. in 2022.
---------------------------------------------------------------------------

    \74\ 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.
---------------------------------------------------------------------------

3. Cellulosic Biofuel
    The majority of the biofuel currently produced in the United States 
comes from plants processing first-generation feedstocks like corn, 
plant oils, sugarcane, etc. Non-edible cellulosic feedstocks have the 
potential to greatly expand biofuel production, both volumetrically and 
geographically. Research and development on cellulosic biofuel 
technologies has exploded over the last few years, and plants to 
commercialize a number of these technologies are already beginning to 
materialize. The $1.01/gallon tax credit for cellulosic biofuel that 
was introduced in the 2008 Farm Bill and recently became effective, is 
also offering much incentive to this developing industry. In addition 
to today's RFS2 program which sets aggressive goals for cellulosic 
biofuel production, the Department of Energy (DOE), Department of 
Agriculture (USDA), Department of Defense (DOD) and state agencies are 
helping to spur industry growth.
a. Current State of the Industry
    There are a growing number of biofuel producers, biotechnology 
companies, universities and research institutes, start-up companies as 
well as refiners investigating cellulosic biofuel production. The 
industry is currently pursuing a wide range of feedstocks, conversion 
technologies and fuels. There is much optimism surrounding the long-
term viability of cellulosic ethanol and other alcohols for gasoline 
blending. There is also great promise and growing interest in synthetic 
hydrocarbons like gasoline, diesel and jet fuel as ``drop in'' 
petroleum replacements. Some companies intend to start by processing 
corn or sugarcane and then transition to cellulosic feedstocks while 
others are focusing entirely on cellulosic materials. Regardless, 
cellulosic biofuel production is beginning to materialize.
    We are currently aware of over 35 small pilot- and demonstration-
level plants operating in North America. However, the main focus at 
these facilities is research and development, not commercial 
production. Most of the plants are rated at less than 250,000 gallons 
per year and that's if they were operated at capacity. Most only 
operate intermittently for the purpose of demonstrating that the 
technologies can be used to produce transportation fuels. The industry 
as a whole is still working to increase efficiency, improve yields, 
reduce costs and prove to the public, as well as investors, that 
cellulosic biofuel is both technologically and economically feasible.
    As mentioned above, a variety of feedstocks are being investigated 
for cellulosic biofuel production. There is a great deal of interest in 
urban waste (MSW and C&D debris) because it is

[[Page 14748]]

virtually free and abundant in many parts of the country, including 
large metropolitan areas where the bulk of fuel is consumed. There is 
also a lot of interest in agricultural residues (corn stover, rice and 
other cereal straws) and wood (forest thinnings, wood chips, pulp and 
paper mill waste and yard waste). However, researchers are still 
working to find viable harvesting and storage solutions. Others are 
investigating the possibility of growing dedicated energy crops for 
cellulosic biofuel production, e.g., switchgrass, energy cane, sorghum, 
poplar, miscanthus and other fast-growing trees. While these crops have 
tremendous potential, many are starting with the feedstocks that are 
available today with the mentality that once the industry has proven 
itself, it will be easier to secure growing contracts and start 
producing energy crops. For more information on cellulosic feedstock 
availability, refer to preamble Section IV.B.3.d and Section 1.1.2 of 
the RIA.
    The industry is also pursuing a number of different cellulosic 
conversion technologies and biofuels. Most of the technologies fall 
into one of two categories: biochemical or thermochemical. Biochemical 
conversion involves the use of acids and/or enzymes to hydrolyze 
cellulosic materials into fermentable sugars and lignin. Thermochemical 
conversion involves the use of heat to convert biomass into synthesis 
gas or pyrolysis oil for upgrading. A third technology pathway is 
emerging that involves the use of catalysts to depolymerize or reform 
the feedstocks into fuel. The technologies currently being considered 
are capable of producing cellulosic alcohols or hydrocarbons for the 
transportation fuel market. Many companies are also researching the 
potential of co-firing biomass to produce plant energy in addition to 
biofuels. For a more in-depth discussion on cellulosic technologies, 
refer to Section 1.4.3 of the RIA.
b. Setting the 2010 Cellulosic Biofuel Standard
    The Energy Independence and Security Act (EISA) set aggressive 
cellulosic biofuel targets beginning with 100 million gallons in 2010. 
However, EISA also supplied EPA with cellulosic biofuel waiver 
authority. For any calendar year in which the projected cellulosic 
biofuel production is less than the minimum applicable volume, EPA can 
reduce the standard based on the volume expected to be available that 
year. EPA is required to set the annual cellulosic standard by November 
30th each year and should consider the annual estimate made by EIA by 
October 31st of each year. We are setting the 2010 standard as part of 
this final rule.
    Setting the cellulosic biofuel standard for 2010 represents a 
unique challenge. As discussed above, the industry is currently 
characterized by a wide range of companies mostly focused on research, 
development, demonstration, and financing their developing 
technologies. In addition, while we are finalizing a requirement that 
producers and importers of renewable fuel provide us with production 
outlook reports detailing future supply estimates (refer to Sec.  
80.1449), we do not have the benefit of this valuable cellulosic supply 
information for setting the 2010 standard. Finally, since today's 
cellulosic biofuel production potential is relatively small, and the 
number of potential producers few (as described in more detail below), 
the overall volume for 2010 can be heavily influenced by new 
developments, either positive or negative associated with even a single 
company, which can be very difficult to predict. This is evidenced by 
the magnitude of changes in cellulosic biofuel projections and the 
potential suppliers of these fuels since the proposal.
    In the proposal, we did a preliminary assessment of the cellulosic 
biofuel industry to arrive at the conclusion that it was possible to 
uphold the 100 million gallon standard in 2010 based on anticipated 
production. At the time of our April 2009 NPRM assessment, we were 
aware of a handful of small pilot and demonstration plants that could 
help meet the 2010 standard, but the largest volume contributions were 
expected to come from Cello Energy and Range Fuels.
    Cello Energy had just started up a 20 million gallon per year (MGY) 
cellulosic diesel plant in Bay Minette, AL. EPA staff visited the 
facility twice in 2009 to confirm that the first-of-its-kind commercial 
plant was mechanically complete and poised to produce cellulosic 
biofuel. It was assumed that start-up operations would go as planned 
and that the facility would be operating at full capacity by the end of 
2009 and that three more 50 MGY cellulosic diesel plants planned for 
the Southeast could be brought online by the end of 2010.
    At the time of our assessment, we were also anticipating cellulosic 
biofuel production from Range Fuels' first commercial-scale plant in 
Soperton, GA. The company received a $76 million grant from DOE to help 
build a 40 MGY wood-based ethanol plant and they broke ground in 
November 2007. In January 2009, Range was awarded an $80 million loan 
guarantee from USDA.\75\ With the addition of this latest capital, the 
company seemed well on its way to completing construction of its first 
10 MGY phase by the end of 2009 and beginning production in 2010.
---------------------------------------------------------------------------

    \75\ For more information on federal support for biofuels, refer 
to Section 1.5.3.3 of the RIA.
---------------------------------------------------------------------------

    Since our April 2009 industry assessment there have been a number 
of changes and delays in production plans due to technological, 
contractual, financial and other reasons. Cello Energy and Range Fuels 
have delayed or reduced their production plans for 2010. Some of the 
small plants expected to come online in 2010 have pushed back 
production to the 2011-2012 timeframe, e.g., Clearfuels Technology, 
Fulcrum River Biofuels, and ZeaChem. Alltech/Ecofin and RSE Pulp & 
Chemical, two companies that were awarded DOE funding back in 2008 to 
build small-scale biorefineries appear to be permanently on hold or off 
the table. In addition, Bell Bio-Energy, a company that received DOD 
funding has since abandoned plans to produce cellulosic diesel from MSW 
at U.S. military bases.\76\
---------------------------------------------------------------------------

    \76\ Bell Bio-Energy is currently investigating other locations 
for turning MSW into diesel fuel according to an October 14, 2009 
conversation with JC Bell.
---------------------------------------------------------------------------

    At the same time, there has also been an explosion of new 
companies, new business relationships, and new advances in the 
cellulosic biofuel industry. Keeping track of all of them is a 
challenge in and of it self as the situation can change on a daily 
basis. EIA recently provided EPA with their first cellulosic biofuel 
supply estimate required under CAA section 211(o)(7)(D)(i). In a letter 
to the Administrator dated October 29, 2009, they arrived at a 5.04 
million gallon estimate for 2010 based on publicly available 
information and assumptions made with respect production capacity 
utilization.\77\ A summary of the plants they considered is shown below 
in Table IV.B.3-1.
---------------------------------------------------------------------------

    \77\ Letter from Richard Newell, EIA Administrator to Lisa 
Jackson, EPA Administrator dated October 29, 2009 (Table 2).

[[Page 14749]]



                                 Table IV.B.3-1--EIA's Projected Cellulosic Biofuel Plant Production Capacities for 2010
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                             Capacity        Expected       Production
               Online                       Company                Location               Product            (million       utilization      (million
                                                                                                             gallons)           (%)        gallons) \3\
--------------------------------------------------------------------------------------------------------------------------------------------------------
2007...............................  KL Process Design....  Upton, WY............  Ethanol..............             1.5              10            0.15
2008...............................  Verenium.............  Jennings, LA.........  Ethanol..............             1.4              10            0.14
2008...............................  Terrabon.............  Bryan, TX............  Bio-Crude............            0.93              10            0.09
2010...............................  Zeachem..............  Boardman, OR.........  Ethanol..............             1.5              10            0.15
2010...............................  Cello Energy.........  Bay Minette, AL......  Diesel...............            20.0          10 \1\            2.00
2010...............................  Range Fuels..........  Soperton, GA.........  Ethanol..............         5.0 \2\              50             2.5
                                                                                                         -----------------------------------------------
    Total..........................  .....................  .....................  .....................           30.35  ..............            5.04
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: 1. Cello Energy is assigned a 10-percent utilization factor as they have not been able to run on a continuous basis long enough to apply for a
  Synthetic Minor Operating Permit or produce significant amounts of fuel during 2009. 2. It is estimated that only half the 2010 projected capacity (10
  million gallons per year) will be a qualified fuel. 3. The production from these facilities in 2009 is not surveyed by EIA or EPA.

    In addition to receiving EIA's information and coordinating with 
them and other offices in DOE, we have initiated meetings and 
conversations with over 30 up-and-coming advanced biofuel companies to 
verify publicly available information, obtain confidential business 
information, and better assess the near-term cellulosic biofuel 
production potential for use in setting the 2010 standard. What we have 
found is that the cellulosic biofuel landscape has continued to evolve. 
Based on information obtained, not only do we project significantly 
different production volumes on a company-by-company basis, but the 
list of potential producers of cellulosic biofuel in 2010 is also 
significantly different than that identified by EIA.
    Overall, our industry assessment suggests that it is difficult to 
rely on commercial production from small pilot or demonstration-level 
plants. The primary purpose of these facilities is to prove that a 
technology works and demonstrate to investors that the process is 
capable of being scaled up to support a larger commercial plant. Small 
plants are cheaper to build to demonstrate technology than larger 
plants, but the operating costs ($/gal) are higher due to their small 
scale. As a result, it's not economical for most of these facilities to 
operate continuously. Most of these plants are regularly shut down and 
restarted as needed as part of the research and development process. 
Due to their intermittent nature, most of these plants operate at a 
fraction of their rated capacity, some less than the 10% utilization 
rate assumed by EIA. In addition, few companies plan on making their 
biofuel available for commercial sale.
    However, there are at least two cellulosic biofuel companies 
currently operating demonstration plants in the U.S. and Canada that 
could produce fuel commercially in 2010. The first is KL Energy 
Corporation, a company we considered for the NPRM with a 1.5 MGY 
cellulosic ethanol plant in Upton, WY. This plant was considered by EIA 
and is included in Table IV.B.3-1. The second is Iogen's cellulosic 
ethanol plant in Ottawa, Canada with a 0.5 MGY capacity. Iogen's 
commercial demonstration plant was referenced by EIA as a potential 
foreign source for cellulosic biofuel but was not included in their 
final table. In addition to these online demonstration plants, there 
are three additional companies not on EIA's list that are currently 
building demonstration-level cellulosic biofuel plants in North America 
that are scheduled to come online in 2010. This includes DuPont Danisco 
Cellulosic Ethanol and Fiberight, companies building demonstration 
plants in the U.S. and Enerkem, a company building a demonstration 
plant in Canada. Cello Energy's plant in Bay Minette, AL continues to 
offer additional potential for cellulosic biofuel in 2010. And finally, 
Dynamotive, a company that currently has two biomass-based pyrolysis 
oil production plants in Canada is another potential source of 
cellulosic biofuel in 2010. All seven aforementioned companies are 
discussed in greater detail below along with Range Fuels.
    KL Energy Corporation (KL Energy), through its majority-owned 
Western Biomass Energy, LLC (WBE) located in Upton, WY, is designed to 
convert wood products and wood waste products into ethanol. Since the 
end of construction in September 2007, equipment commissioning and 
process revisions continued until the October 2009 startup. The plant 
was built as a 1.5 MGY demonstration plant and was designed to both 
facilitate research and operate commercially. It is KL Energy's intent 
that WBE's future use will involve the production and sale of small but 
commercial-quality volumes of ethanol and lignin co-product. The 
company's current 2010 goal is for WBE to generate RINs under the RFS2 
program.\78\
---------------------------------------------------------------------------

    \78\ Based on information provided by Lori Litzen, Environmental 
Permit Engineer at KL Energy on December 10, 2009.
---------------------------------------------------------------------------

    Iogen is responsible for opening the first commercial demonstration 
cellulosic ethanol plant in North America. Iogen's plant located in 
Ottawa, Canada has been producing cellulosic ethanol from wheat straw 
since 2004. Like KL Energy, Iogen has slowly been ramping up production 
at its 0.5 MGY plant. According to the company's Web site, they 
produced approximately 24,000 gallons in 2004 and 34,000 gallons in 
2005. Production dropped dramatically in 2006 and 2007 but came back 
strong with 55,000 gallons in 2008. Iogen recently produced over 
150,000 gallons of ethanol from the demonstration plant in 2009. Iogen 
also recently became the first cellulosic ethanol producer to sell its 
advanced biofuel at a retail service station in Canada. Their 
cellulosic ethanol was blended to make E10 available for sale to 
consumers at an Ottawa Shell station. Iogen also recently announced 
plans to build its first commercial scale plant in Prince Albert, 
Saskatchewan in the 2011/2012 timeframe. Based on the company's 
location and operating status, Iogen certainly has the potential to 
participate in the RFS2 program. However, at this time, we are not 
expecting them to import any cellulosic ethanol into the U.S. in 
2010.\79\
---------------------------------------------------------------------------

    \79\ Based on Web site information, comments submitted in 
response to our proposal, and a follow-up phone call with Iogen 
Executive VP, Jeff Passmore on December 17, 2009.
---------------------------------------------------------------------------

    DuPont Danisco Cellulosic Ethanol, LLC (DDCE), a joint venture 
between DuPont and Danisco, is another potential source for cellulosic 
biofuel in 2010. DDCE received funding from the State of Tennessee and 
the University of Tennessee to build a small 0.25 MGY demonstration 
plant in Vonore, TN to

[[Page 14750]]

pursue switchgrass-to-ethanol production. According to DDCE, 
construction commenced in October 2008 and the plant is now 
mechanically complete and undergoing start-up operations. The facility 
is scheduled to come online by the end of January and the company hopes 
to operate at or around 50% of production capacity in 2010. According 
to the DDCE, the objective in Vonore is to validate processes and data 
for commercial scale-up, not to make profits. However, the company does 
plan to sell the cellulosic ethanol it produces.\80\
---------------------------------------------------------------------------

    \80\ Based on a December 16, 2009 telephone conversation with 
DDCE Director of Corporate Communications, Jennifer Hutchins and 
follow-up e-mail correspondence.
---------------------------------------------------------------------------

    Enerkem is another company pursuing cellulosic ethanol production. 
The Canadian-based company was recently announced as a recipient of a 
joint $50 million grant from DOE and USDA to build a 10 MGY woody 
biomass-to-ethanol plant in Pontotoc, MS.\81\ The U.S. plant is not 
scheduled to come online until 2012, but Enerkem is currently building 
a 1.3 MGY demonstration plant in Westbury, Quebec. According to the 
company, plant construction in Westbury started in October 2007 and the 
facility is currently scheduled to come online around the middle of 
2010. While it's unclear at this time whether the cellulosic ethanol 
produced will be exported to the United States, Enerkem has expressed 
interest in selling its fuel commercially.\82\
---------------------------------------------------------------------------

    \81\ Refer to December 4, 2009 DOE press release entitled, 
``Recovery Act Announcement: Secretaries Chu and Vilsack Announce 
More Than $600 Million Investment in Advanced Biorefinery 
Projects.''
    \82\ Based on an October 14, 2009 meeting with Enerkem and 
follow-up telephone conversation with VP of Government Affairs, 
Marie-Helene Labrie on December 14, 2009.
---------------------------------------------------------------------------

    Additional cellulosic biofuel could come from Fiberight, LLC 
(Fiberight) in 2010. We recently became aware of this start-up company 
and contacted them to learn more about their process and cellulosic 
biofuel production plans. According to Fiberight, they have been 
operating a pilot-scale facility in Lawrenceville, VA for three years. 
They have developed a proprietary process that not only fractionates 
MSW but biologically converts the non-recyclable portion into 
cellulosic ethanol and biochemicals. Fiberight recently purchased a 
shut down corn ethanol plant in Blairstown, IA and plans to convert it 
to become MSW-to-ethanol capable. According to the company, 
construction is currently underway and the goal is to bring the 2 MGY 
demonstration plant online by February or March, 2010. If the plant 
starts up according to plan, the company intends on making cellulosic 
ethanol commercially available in 2010 and generating RINS under the 
RFS2 program. Fiberight's long-term goal is to expand the Blairstown 
plant to a 5-8 MGY capacity and build other small commercial plants 
around the country that could convert MSW into fuel.\83\
---------------------------------------------------------------------------

    \83\ Based on a December 15, 2009 telephone conversation with 
Fiberight CEO, Craig Stuart-Paul and follow-up e-mail 
correspondence.
---------------------------------------------------------------------------

    Cello Energy, a company considered in the proposal, continues to be 
another viable source for cellulosic biofuel in 2010. Despite recent 
legal issues which have constrained the company's capital, Cello Energy 
is still pursuing cellulosic diesel production. According to the 
company, they are currently working to resolve materials handling and 
processing issues that surfaced when they attempted to scale up 
production to 20 MGY from a previously operated demonstration plant. As 
of November 2009, they were waiting for new equipment to be ordered and 
installed which they hoped would allow for operations to be restarted 
as early as February or March, 2010. Cello's other planned commercial 
facilities are currently on hold until the Bay Minette plant is 
operational.\84\
---------------------------------------------------------------------------

    \84\ Based on a November 9, 2009 telephone conversation with 
Cello Energy CEO, Jack Boykin.
---------------------------------------------------------------------------

    Another potential supplier of cellulosic biofuel is Dynamotive 
Energy Systems (Dynamotive) headquartered in Vancouver, Canada. 
Dynamotive currently has two plants in West Lorne and Guelph, Ontario 
that produce biomass-based pyrolysis oil (also known as ``BioOil'') for 
industrial applications. The BioOil production capacity between the two 
plants is estimated at around 9 MGY, but both plants are currently 
operating at a fraction of their rated capacity.\85\ However, according 
to a recent press release, Dynamotive has contracts in place to supply 
a U.S.-based client with at least nine shipments of BioOil in 2010. If 
Dynamotive's BioOil is used as heating oil or upgraded to 
transportation fuel, it could potentially count towards meeting the 
cellulosic biofuel standard in 2010.
---------------------------------------------------------------------------

    \85\ According to Dynamotive's Web site, the Guelph plant has a 
capacity to convert 200 tonnes of biomass into BioOil per day. If 
all modules are fully operational, the plant has the ability to 
process 66,000 dry tons of biomass per year with an energy output 
equivalent to 130,000 barrels of oil. The West Lorne plant has a 
capacity to convert 130 tonnes of biomass into BioOil per day which, 
if proportional to the Guelph plant, translates to an energy-
equivalent of 84,500 barrels of oil. According to a November 3, 2009 
press release, Dynamotive has contracts in place to supply a U.S.-
based client with at least nine shipments of BioOil in 2010.
---------------------------------------------------------------------------

    As for the Range Fuels plant, construction of phase one in 
Soperton, GA is about 85% complete, with start-up planned for mid-2010. 
However, there have been some changes to the scope of the project that 
will limit the amount of cellulosic biofuel that can be produced in 
2010. The initial capacity has been reduced from 10 to 4 million 
gallons per year. In addition, since they plan to start up the plant 
using a methanol catalyst they are not expected to produce qualifying 
renewable fuel in 2010. During phase two of their project, currently 
slated for mid-2012, Range plans to expand production at the Soperton 
plant and transition from a methanol to a mixed alcohol catalyst. This 
will allow for a greater alcohol production potential as well as a 
greater cellulosic biofuel production potential.\86\
---------------------------------------------------------------------------

    \86\ Based on a November 5, 2009 telephone conversation with 
Range Fuels VP of Government Affairs, Bill Schafer.
---------------------------------------------------------------------------

    Overall, our most recent industry assessment suggests that there 
could potentially be over 30 MGY of cellulosic biofuel production 
capacity online by the end of 2010.\87\ However, since most of the 
plants are still under construction today, the amount of cellulosic 
biofuel produced in 2010 will be contingent upon when and if these 
plants come online and whether the projects get delayed due to funding 
or other reasons. In addition, based on our discussions with the 
developing industry, it is clear that we cannot count on demonstration 
plants to produce at or near capacity in 2010, or in their first few 
years of operation for that matter. The amount of cellulosic biofuel 
actually realized will depend on whether the process works, the 
efficiency of the process, and how regularly the plant is run. As 
mentioned earlier, most small plants, including commercial 
demonstration plants, are not operated continuously. As such, we cannot 
base the standard on these plants running at capacity--at least until 
the industry develops further and proves that such rates are 
achievable. We currently estimate that production from first-of-its 
kind plants could be somewhere in the 25-50% range in 2010. Together, 
the implementation timelines and anticipated production levels of the 
plants described above brings the cellulosic biofuel supply estimate to 
somewhere in the 6-13 million gallon range for 2010.
---------------------------------------------------------------------------

    \87\ For more information, refer to Section 1.5.3.2 of the RIA.
---------------------------------------------------------------------------

    In addition, it is unclear how much we can rely on Canadian plants 
for

[[Page 14751]]

cellulosic biofuel in 2010. Although we currently receive some 
conventional biofuel imports from Canada and many of the aforementioned 
Canadian companies have U.S. markets in mind, the country also has its 
own renewable fuel initiatives that could keep much of the cellulosic 
biofuel produced from coming to the United States, e.g., Iogen. 
Finally, it's unclear whether all fuel produced by these facilities 
will qualify as cellulosic biofuel under the RFS2 program. Several of 
the companies are producing fuels or using feedstocks which may not in 
fact qualify as cellulosic biofuel once we receive their detailed 
registration information. Factoring in these considerations, the 
cellulosic biofuel potential from the six more likely companies 
described above could result in several different production scenarios 
in the neighborhood of the recent EIA estimate. We believe this 
estimate of 5 million gallons or 6.5 ethanol-equivalent million gallons 
represents a reasonable yet achievable level for the cellulosic biofuel 
standard in 2010 considering the degree of uncertainty involved with 
setting the standard for the first year. As mentioned earlier, we 
believe standard setting will be easier in future years once the 
industry matures, we start receiving production outlook reports and 
there is less uncertainty regarding feasibility of cellulosic biofuel 
production.
c. Current Production Outlook for 2011 and Beyond
    Since the proposal, we have also learned about a number of other 
cellulosic biofuel projects in addition to those described above. This 
includes commercial U.S. production plans by Coskata, Enerkem and 
Vercipia. However, production isn't slated to begin until 2011 or later 
and the same is true for most of the other larger plants we're aware of 
that are currently under development. Nonetheless, while cellulosic 
biofuel production in 2010 may be limited, it is remarkable how much 
progress the industry has made in such a short time, and there is a 
tremendous growth opportunity for cellulosic biofuels over the next 
several years.
    Most of the cellulosic biofuel companies we've talked to are in 
different stages of proving their technologies. Regardless of where 
they are at, many have fallen behind their original commercialization 
schedules. As with any new technology, there have been delays 
associated with scaling up capacity, i.e., bugs to work out going from 
pilot to demonstration to commercialization. However, most are saying 
it's not the technologies that are delaying commercialization, it is 
lack of available funding. Obtaining capital has been very challenging 
given the current recession and the banking sector's financial 
difficulties. This is especially true for start-up companies that do 
not have access to capital through existing investors, plant profits, 
etc. From what we understand, banks are looking for cellulosic 
companies to be able to show that their plants are easily ``scalable'' 
or expandable to commercial size. Many are only considering companies 
that have built plants to one-tenth of commercial scale and have logged 
many hours of continuous operation.
    The government is currently trying to help in this area. To date, 
the Department of Energy (DOE) and the Department of Agriculture (USDA) 
have allocated over $720 million in federal funding to help build pilot 
and demonstration-scale biorefineries employing advanced technologies 
in the United States. The largest installment from Recovery Act funding 
was recently announced on December 4, 2009 and includes funding for a 
series of larger commercial demonstration plants including cellulosic 
ethanol projects by Enerkem and INEOS New Planet BioEnergy, LLC. DOE 
has also issued grants to help fund some of the first commercial 
cellulosic biofuel plants. Current recipients include Abengoa 
Bioenergy, BlueFire Ethanol \88\ and POET Biorefining in addition to 
Range Fuels. DOE and USDA are also issuing loan guarantees to help 
support the up-and-coming cellulosic biofuels industry and funding 
research and development. Many states are also providing assistance. 
For more information on government support for biofuels, refer to 
Section 1.5.3.3 of the RIA.
---------------------------------------------------------------------------

    \88\ Although BlueFire is still working on obtaining financing 
to build its first demonstration plant, it has received two 
installments of federal funding towards its first planned 
commercial-scale plant. The 19 MGY plant planned for Fulton, MS 
(originally planned for Southern California) was awarded $40 million 
from DOE on February 28, 2008 and another $81.1 million from DOE and 
USDA on December 4, 2009.
---------------------------------------------------------------------------

    The refining industry is also helping to fund cellulosic biofuel 
R&D efforts and some of the first commercial plants. Many of the major 
oil companies have invested in advanced second-generation biofuels over 
the past 12-18 months. A few refiners (e.g., BP and Shell) have even 
entered into joint ventures to become cellulosic biofuel producers. 
General Motors and other vehicle/engine manufacturers are also 
providing financial support to help with research and development.
    A summary of some of the cellulosic biofuel companies with near-
term commercialization plans in North America is provided in Table 
IV.B.3-2. The capacities presented represent maximum annual average 
throughput based on each company's current production plans. However, 
as noted, capacity does not necessarily translate to production. Actual 
production of cellulosic biofuel will likely be well below capacity, 
especially in the early years of production. We will continue to track 
these companies and the cellulosic biofuel industry as a whole 
throughout the duration of the RFS2 program. In addition, we will 
continue to collaborate with EIA in annual standard setting. A more 
detailed discussion of the plants corresponding to these company 
estimates is provided in Section 1.5.3 of the RIA.
BILLING CODE 6560-50-P

[[Page 14752]]

[GRAPHIC] [TIFF OMITTED] TR26MR10.421

BILLING CODE 6560-50-C

d. Feedstock Availability
    A wide variety of feedstocks can be used for cellulosic biofuel 
production, including: Agricultural residues, forestry biomass, certain 
renewable portions of municipal solid waste and construction and 
demolition waste (i.e., separated food, yard and incidental, and post-
recycled paper and wood waste as discussed in Section II.B.4) and 
energy crops. These feedstocks are currently much more difficult to 
convert into biofuel than traditional corn/starch crops or at least 
require new and different processes because of the more complex 
structure of cellulosic material.
    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 
determine the most economical volume of agriculture residues, energy 
crops, and forestry resources (see Section VIII for more details on the 
FASOM) used to meet the standard. We supplemented these estimates with 
feedstock assessment estimates for the biomass portions of municipal 
solid waste and construction and demolition waste.\89\
---------------------------------------------------------------------------

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

    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

[[Page 14753]]

cellulosic biofuel by 2022. Refer to Section IV.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 incurs a fee for its disposal 
may be among the first to be used. Urban wastes are used in a variety 
of ways. Most commonly, wastes are ground into mulch, dumped into land-
fills, or incinerated. We describe two components of urban waste, 
municipal solid waste (MSW) and construction and demolition (C&D) 
debris, below.
    MSW consists of paper, glass, metals, plastics, wood, yard 
trimmings, food scraps, rubber, leather, textiles, etc. The portion of 
MSW that can qualify as renewable biomass under the program is 
discussed in Section II.B.4.d. The bulk of the biogenic portion of MSW 
that can be converted into biofuel is cellulosic material such as wood, 
yard trimmings, paper, and much of food wastes. Paper made up 
approximately 31% of the total MSW generated in 2008.\90\ 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. 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).
---------------------------------------------------------------------------

    \90\ EPA. Municipal Solid Waste Generation, Recycling, and 
Disposal in the United States: Facts and figures for 2008.
---------------------------------------------------------------------------

    We estimated that a total of 44.5 million dry tons of MSW (wood, 
yard trimmings, paper, and food waste) 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.91 92 Between 
the proposal and this final rule, we have updated the assumptions noted 
above based on newer reports. It should be noted, however, that our 
estimates of urban waste availability have not changed significantly 
between the proposal and the final rule. We assumed that approximately 
26 million dry tons (of the total 44.5 million dry tons) could be used 
to produce biofuels. However, many areas of the U.S. (e.g., much of the 
Rocky Mountains) have such sparse resources that an MSW and C&D 
cellulosic facility would not likely be justifiable. We did assume that 
in areas with other 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 2.3 ethanol-equivalent billion gallons of fuel.\93\ Note 
that some processes are likely to also process other portions of MSW 
(e.g., plastics, rubbers) into fuel, but we have only accounted for the 
portion expected to qualify as renewable fuel and produce RINs.
---------------------------------------------------------------------------

    \91\ Wiltsee, G., ``Urban Wood Waste Resource Assessment,'' 
NREL/SR-570-25918, National Renewable Energy Laboratory, November 
1998.
    \92\ Biocycle, ``The State of Garbage in America,'' Vol. 49, No. 
12, December 2008, p. 22.
    \93\ 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.\94\ 
Katrina also generated over 100 million tons of residential debris, not 
including the commercial sector. Much of this waste would likely be 
disposed of and therefore go unused. Collection of this material for 
the generation of biofuel could be a better alternative use for this 
waste. While we acknowledge this material could provide a large source 
in the short-term, natural disasters are highly variable, making it 
hard to predict amounts of material available in the future. Thus, for 
our analyses we have not included natural disaster renewable biomass in 
our estimates.
---------------------------------------------------------------------------

    \94\ 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 residues are corn stover (the stalks, leaves, 
and/or cobs) and straw from wheat, rice, barley, and oats. These U.S. 
crops and others 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.\95\ 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.
---------------------------------------------------------------------------

    \95\ 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 raise 
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 shows that under current rotation and tillage practices, 
about 30% of corn 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.\96\ The same study 
shows that if farmers convert to no-till corn management and total 
stover production does 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

[[Page 14754]]

erosion.\97\ 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 no stover is removable on conventional tilled 
lands, 35% of stover is removable on conservation tilled lands, and 50% 
is removable on no-till lands. In general, these removal guidelines are 
appropriate only for the Midwest, where the majority of corn is 
currently grown.
---------------------------------------------------------------------------

    \96\ Graham, R.L., ``Current and Potential U.S. Corn Stover 
Supplies,'' American Society of Agronomy 99:1-11, 2007.
    \97\ 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 by region due to local 
differences. Given the current understanding of sustainable removal 
rates, we believe that such assumptions are reasonably justified. Based 
on our research, we also note that calculating 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. 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, however, 
we had limited data on which to accurately apply this approach and 
therefore assumed the removal guidelines based on tillage practices.
    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 (4.9 ethanol-equivalent Bgal).\98\ 
Smaller contributions are expected to come from other crop residues 
including sugarcane bagasse (0.6 ethanol-equivalent Bgal), wheat 
residues (0.1 ethanol-equivalent Bgal), and sweet sorghum pulp (0.1 
ethanol-equivalent Bgal).\99\
---------------------------------------------------------------------------

    \98\ Assuming 92.3 gal/dry ton ethanol conversion yield for corn 
stover in 2022.
    \99\ 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 and sorghum being 
an agricultural feedstock.
---------------------------------------------------------------------------

    The U.S. also 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.\100\ Logging residues are produced in 
conventional harvest operations, forest management activities, and 
clearing operations. In 2004, these operations generated approximately 
67 million dry tons of forest residues that were left uncollected at 
harvest sites.\101\ Other feedstocks include those from other removal 
residues, thinnings from timberland, and primary mill residues.
---------------------------------------------------------------------------

    \100\ 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.
    \101\ USDA-Forest Service. ``Timber Products Output Mapmaker 
Version 1.0.'' 2004.
---------------------------------------------------------------------------

    For the NPRM, FASOM was not able to model forestry biomass as a 
potential feedstock. As a result, we relied on USDA-Forest Service (FS) 
for information on the forestry sector at the time. For the final rule, 
we were able to incorporate the forestry sector model in FASOM. 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, our modeling of 
forestry biomass excluded such material. The FASOM model estimated that 
approximately 0.1 ethanol-equivalent billion gallons would be produced 
from forestry biomass 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 for 
energy purposes. Various perennial plants have been researched as 
potential dedicated feedstocks, including switchgrass, mixed prairie 
grasses, hybrid poplar, miscanthus, energy cane, energy sorghum, and 
willow trees. Refer to Section 1.1.2.2 of the RIA for more information 
on the benefits and challenges with using dedicated energy crops.
    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 (7.9 ethanol-
equivalent Bgal).\102\ FASOM covers all cropland and pastureland in 
production in the 48 contiguous United States. For the NPRM, FASOM did 
not contain all categories of grassland and rangeland captured in 
USDA's Major Land Use data sets. For the final rule, FASOM accounts for 
all major land categories, including forestland and rangeland. All crop 
production, including dedicated energy crops, takes place on cropland. 
Land categories that can be converted to cropland production include 
cropland pasture, forest pasture, and forestland. More detail can be 
found in Chapter VIII of this preamble. Furthermore, we constrained 
FASOM to be consistent with the 2008 Farm Bill and assumed 32 million 
acres would stay in Conservation Reserve Program (CRP).\103\ 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 to meet EISA could be significant, similar 
to our FASOM modeling results for the final rule.\104\
---------------------------------------------------------------------------

    \102\ Assuming 16 Bgal cellulosic biofuel total, 2.3 Bgal from 
Urban Waste; 13.7 Bgal of cellulosic biofuel for ag residues, 
forestry biomass, and/or energy crops would be needed.
    \103\ 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.
    \104\ 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 IV.B.3-3 summarizes our internal estimate of the types of 
cellulosic feedstocks projected to be used and their corresponding 
volume contribution to 16 billion gallons cellulosic biofuel by 2022 
for the purposes of our impacts assessment. The majority of feedstock 
is projected to come from dedicated energy crops. Other feedstocks 
include agricultural residues, forestry biomass, and urban waste.

[[Page 14755]]



Table IV.B.3-3--Cellulosic Feedstocks Assumed To Meet EISA in 2022 \105\
------------------------------------------------------------------------
                                                                Volume
                                                              (ethanol-
                         Feedstock                            equivalent
                                                                Bgal)
------------------------------------------------------------------------
Agricultural Residues......................................          5.7
    Corn Stover............................................          4.9
    Sugarcane Bagasse......................................          0.6
    Wheat Residue..........................................          0.1
    Sweet Sorghum Pulp.....................................          0.1
Forestry Biomass...........................................          0.1
Urban Waste................................................          2.3
Dedicated Energy Crops (Switchgrass).......................          7.9
                                                            ------------
  Total....................................................         16.0
------------------------------------------------------------------------

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 storage 
stability) for which the engines have been designed. The definition of 
biodiesel given in applicable regulations is sufficiently broad to be 
inclusive of both fuels.\106\ 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 the RFS2 
volume requirements.\107\
---------------------------------------------------------------------------

    \105\ Volumes are represented here as ethanol-equivalent 
volumes, a mix of diesel and ethanol volumes as described in Section 
IV.A, above.
    \106\ 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 II.B.2, as published in the Federal Register Vol. 72, No. 
83, p. 23917.
    \107\ For more detailed discussion of the definition of 
coprocessing and its implications for compliance with EISA, see 
Section II.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 processes are at various stages of 
development, but due to uncertainty on production timelines, we didn't 
include these fuels in the biomass-based diesel impact assessments.
a. Historic and Projected Production
i. Biodiesel
    As of November 2009, the aggregate production capacity of biodiesel 
plants in the U.S. was estimated at 2.8 billion gallons per year across 
approximately 191 facilities.\108\ (However, at the time of this 
writing it is anticipated that capacity utilization will be 
approximately 17% for calendar year 2009.) Biodiesel plants exist in 
nearly all states, with the largest density of plants in the Midwest 
and Southeast where agricultural feedstocks are most plentiful.
---------------------------------------------------------------------------

    \108\ Capacity data taken from National Biodiesel Board as of 
November 2009.
---------------------------------------------------------------------------

    Table IV.B.4-1 gives data on U.S. biodiesel production and use for 
recent years, including net domestic use after accounting for imports 
and exports. 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 
along a path of more small, privately-owned plants in comparison to the 
ethanol industry, with median size less than 10 million gallons/
yr.\109\ These small plants, with relatively low costs other than 
feedstock, have generally been able to survive producing well below 
their nameplate capacities.
---------------------------------------------------------------------------

    \109\ Assessment of plant capital cost based on USDA production 
cost models. A publication describing USDA modeling of biodiesel 
production costs can be found in Bioresource Technology 97(2006) 
671-8.

                          Table IV.B.4-1--Summary of U.S. Biodiesel Production and Use
                                             [Million gallons] \110\
----------------------------------------------------------------------------------------------------------------
                                                                                                         Net
                                    Domestic                          Apparent                         domestic
              Year                 production     Domestic total      capacity      Net domestic        use as
                                    capacity        production      utilization     biodiesel use     percent of
                                                                     (percent)                        production
----------------------------------------------------------------------------------------------------------------
2004............................          245  28.................           11  27................           96
2005............................          395  91.................           23  91................          100
2006............................          792  250................           32  261...............          104
2007............................        1,809  490................           27  358...............           73
2008............................        2,610  776................           30  413...............           53
2009............................        2,806  475 (est.).........           17  296 (est.)........           62
----------------------------------------------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \110\ Capacity data taken from National Biodiesel Board as of 
November 2009. Production, import, and export figures taken from EIA 
Monthly Energy Review, Table 10.4 as of December 2009.
---------------------------------------------------------------------------

    During 2004-2006, demand for biodiesel grew rapidly, but the trend 
of increasing sales was quickly surpassed by construction and start-up 
of new plants Since then, periods of high commodity prices followed by 
reduced demand for transportation fuel during

[[Page 14756]]

the economic downturn have caused additional strain on the industry 
beyond the overcapacity situation. Biodiesel producers were able to 
find additional markets overseas, and a significant portion of the 2007 
and 2008 production was exported to Europe where fuel prices and 
additional tax subsidies helped offset high feedstock costs. However, 
the EU enacted a tariff to protect domestic producers early in 2009, 
after which exports dropped to a small fraction of production.\111\ We 
understand there may be some additional export markets developing 
within North America, but given the uncertainty at this time, we do not 
account for any biodiesel exports in our projections.
---------------------------------------------------------------------------

    \111\ Ibid.
---------------------------------------------------------------------------

    To perform our impacts analyses for this rule, 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 
industry capacity to be much closer to 1.67 billion gallons per year by 
2022 (based on the volume requirements to meet the standard; see 
Section IV.A.2). 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.\112\ Going forward producers will compete for feedstocks and 
markets may consolidate. During this period the number of operating 
plants is expected to shrink, with surviving plants utilizing 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 85%. Table IV.B.4-2 summarizes this 
forecast. See Section 1.5.4 of the RIA for more details.
---------------------------------------------------------------------------

    \112\ 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.

Table IV.B.4-2--Summary of Projected Biodiesel Industry Characterization
                       Used in Our Analyses \113\
------------------------------------------------------------------------
                                                          2008     2022
------------------------------------------------------------------------
Total production capacity on-line (million gal/yr)....    2,610    1,968
Number of operating plants............................      176      121
Median plant size (million gal/yr)....................        5        5
Total biodiesel production (million gal)..............      776    1,670
Average plant utilization.............................     0.30     0.85
------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \113\ 2008 capacity data taken from National Biodiesel Board; 
production figures taken from EIA Monthly Energy Review, Table 10.4 
as of October 2009.
---------------------------------------------------------------------------

    As a result of the oxygen and olefins in the feedstock being 
removed, renewable diesel has storage, stability, and shipping 
properties equivalent to petroleum diesel. This allows renewable diesel 
fuel to be shipped in existing petroleum pipelines used for 
transporting fuels, thus avoiding a significant issue with distribution 
of biodiesel. For more on fuel distribution, refer to Section IV.C.
    Considering that this industry is still in development and that 
there are no long-term projections of production volume, we base our 
volume estimate of 150 MMgal/yr primarily on recent industry project 
announcements involving proven technology. Due to the current status of 
tax incentives, we project all of this fuel will be produced at stand-
alone facilities.
b. Feedstock Availability
    Publically available industry information along with agricultural 
commodity modeling we have done for this rule (see Section VIII.A) 
suggests that the three largest sources of feedstock for biodiesel will 
be rendered animal fats, soy oil, and corn oil extracted from dry mill 
ethanol facilities. Renewable diesel plants are expected to use solely 
animal fats due to the fact that these feedstocks are cheaper than 
vegetable oils and the process can handle them without issue. Comments 
we have received from a large rendering company suggest there will be 
adequate fats and greases feedstocks to supply biofuels as well as 
other historical uses. Table IV.B.4-3 summarizes the feedstock types, 
process types, and volumes projected to be used in 2022 for biodiesel 
and renewable diesel. More details on feedstock sources and volumes are 
presented in Section 1.1.3 of the RIA.

            Table IV.B.4-3--Summary of Projected Biodiesel and Renewable Diesel Feedstock Use in 2022
                                                     [MMgal]
----------------------------------------------------------------------------------------------------------------
                                                                                       Acid-
                         Feedstock type                           Base catalyzed   pretreatment      Renewable
                                                                     biodiesel       biodiesel        diesel
----------------------------------------------------------------------------------------------------------------
Virgin vegetable oil............................................             660  ..............  ..............
Corn oil from ethanol production................................  ..............             680  ..............
Rendered animal fats and greases................................  ..............             230             150
Algae oil or other advanced source..............................             100  ..............  ..............
----------------------------------------------------------------------------------------------------------------


[[Page 14757]]

C. Biofuel Distribution

    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 
country. In contrast, most biofuel is produced in the heartland of the 
country and needs to be shipped to the coasts, flowing roughly in the 
opposite direction of petroleum-based fuels. In addition, while some 
renewable fuels such as hydrocarbons may be transparent to the 
distribution system, the physical/chemical nature of other renewable 
fuels may limit the extent to which they can be shipped/stored fungibly 
with petroleum-based fuels. The vast majority of biofuels are currently 
shipped by rail, barge and tank truck to petroleum terminals. All 
biofuels are currently blended with petroleum-based fuels prior to 
use.\114\ Most biofuel blends can be used in conventional vehicles. 
However, E85 can only be used in flex-fuel vehicles, requires specially 
constructed retail dispensing/storage equipment, and may require 
special blendstocks at terminals. These factors limit the ability of 
biofuels to utilize the existing petroleum fuel distribution 
infrastructure. Hence, the distribution of renewable fuels raises 
unique concerns and in many instances requires the addition of new 
transportation, storage, blending, and retail equipment.
---------------------------------------------------------------------------

    \114\ The prescribed blending ratio for a given biofuel is based 
on vehicle compatibility and emissions considerations. Some biofuels 
may be found to be suitable for use without the need for blending 
with petroleum-based fuel.
---------------------------------------------------------------------------

1. Biofuel Shipment to Petroleum Terminals
    Ethanol currently is 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. A 
short gasoline pipeline in Florida is currently shipping batches of 
ethanol, and other more extensive pipeline systems have feasibility 
studies underway.\115\ Thus, existing petroleum pipelines in some areas 
of the country may play an increasing role in the shipment of ethanol. 
Evaluations are also currently underway regarding the feasibility of 
constructing a new dedicated ethanol pipeline from the Midwest to the 
East coast. We expect that cellulosic distillate fuels will not have 
materials compatibility issues with the existing petroleum fuel 
distribution infrastructure. Thus, there may be more opportunity for 
cellulosic distillate fuel to be shipped by pipeline. However, the 
location of both ethanol and cellulosic distillate production 
facilities relative to the origination points for existing petroleum 
pipelines will be a limiting factor regarding the extent to which 
pipelines can be used.
---------------------------------------------------------------------------

    \115\ Shipment of ethanol in pipelines that carry distillate 
fuels as well as gasoline presents additional challenges.
---------------------------------------------------------------------------

    Our analysis of the shipment of ethanol and cellulosic distillate 
fuels to petroleum terminals is based on the projections of the 
location of biofuel production facilities and end use areas contained 
in the NPRM. We assume that the majority of ethanol and cellulosic 
distillate fuel would be produced in the Midwest, and that both fuels 
would be shipped to petroleum terminals in a similar fashion (by rail, 
barge, and tank truck). To the extent which new biofuel production 
facilities are more dispersed than projected in the NPRM, there may be 
more opportunity for both fuels to be used closer to their point of 
manufacture. This potential benefit would primarily apply to cellulosic 
ethanol and distillate production facilities given that such facilities 
have yet to be constructed, whereas most corn-ethanol production 
facilities have already been constructed in the Midwest.
    Biodiesel is currently not typically shipped by pipeline due to 
concerns that it may contaminate jet fuel that is shipped on the same 
pipeline and potential incompatibility with pipeline gaskets and seals. 
Kinder Morgan's Plantation pipeline is currently shipping B5 blends on 
segments of its system that do not handle jet fuel. The shipment of 
biodiesel by pipeline may become more widespread and might be expanded 
to systems that handle jet fuel. However, the relatively small 
production volumes from individual biodiesel plants and the widespread 
location of such production facilities will tend to limit the extent to 
which biodiesel may be shipped by pipeline.
    Due to the uncertainties regarding the extent to which pipelines 
might participate in the transportation of biofuels in the future, we 
assumed that biofuels will continue to be transported by rail, barge, 
and truck to petroleum terminals as the vast majority of biofuel 
volumes are today. To the extent that pipelines do play an increasing 
role in the distribution of ethanol, this may improve reliability in 
supply and reduce distribution costs. Apart from increased shipment by 
pipeline, biofuel distribution, and in particular ethanol distribution 
can be further optimized primarily through the expanded use of unit 
trains.\116\ We anticipate that the vast majority of ethanol and 
cellulosic distillate facilities will be sized to facilitate unit train 
service.\117\ We do not expect that biodiesel facilities will be of 
sufficient size to justify shipment by unit train. In the NPRM, we 
projected that unit train receipt facilities would be located at 
petroleum terminals and existing rail terminals. Based on industry 
input regarding the logistical hurdles in locating unit train receipt 
facilities at petroleum/existing rail terminals, we expect that such 
facilities will be constructed on dedicated property with rail access 
that is as close to petroleum terminals as practicable.\118\
---------------------------------------------------------------------------

    \116\ Unit trains are composed of 70 to 100 rail cars that are 
dedicated to shuttle back and forth from production facilities 
downstream receipt facilities near petroleum terminals.
    \117\ A facility exists in Iowa to consolidate rail cars of 
ethanol from some ethanol plants that are not large enough to 
support unit train service by themselves.
    \118\ Existing unit train receipt facilities have primarily 
followed this model.
---------------------------------------------------------------------------

    Shipment of biofuels by manifest rail to existing rail terminals 
will continue to be an important means of supplying biofuels to distant 
markets where the volume of the production facility and/or the local 
demand is not sufficient to justify shipment by unit train.\119\ 
Shipments by barge will also play an important role in those instances 
where production and demand centers have water access and in some cases 
as the final link from a unit train receipt facility to a petroleum 
terminal. Direct shipment by tank truck from production facilities to 
petroleum terminals will also continue for shipment over distances 
shorter than 200 miles.
---------------------------------------------------------------------------

    \119\ Manifest rail shipment refers to the shipment of rail cars 
of biofuels in trains that also carry other products.
---------------------------------------------------------------------------

    We project that most biofuel volumes shipped by rail will be 
delivered to petroleum terminals by tank truck.\120\ We expect that 
this will always be the case for manifest rail shipments. In the NPRM, 
we projected that trans-loading of biofuels from rail cars to tank 
trucks would be an interim measure until biofuel storage tanks were 
constructed.\121\ Based on industry input, we now expect trans-loading 
will be a long-term means of transferring manifest rail car shipments 
of biofuels received at

[[Page 14758]]

existing rail terminals to tank trucks for delivery to petroleum 
terminals. We also anticipate that trans-loading will be used at some 
unit train receipt facilities, although we expect that most of these 
facilities will install biofuel storage tanks from which tank trucks 
will be filled for delivery to petroleum terminals. Imported biofuels 
will typically be received and be further distributed by tank truck 
from petroleum terminals that already have receipt facilities for 
waterborne fuel shipments.
---------------------------------------------------------------------------

    \120\ At least one current ethanol unit train receipt facility 
has a pipeline link to a nearby terminal. To the extent that 
additional unit train receipt facilities could accomplish the final 
link to petroleum terminals by pipeline, this would significantly 
reduce the need for shipment by tank truck.
    \121\ Trans-loading refers to the direct transfer of the 
contents of a rail car to a tank truck without the intervening 
delivery into a storage tank.
---------------------------------------------------------------------------

    We anticipate that the deployment of the necessary distribution 
infrastructure to accommodate the shipment of biofuels to petroleum 
terminals is achievable.\122\ We believe that construction of the 
requisite rail cars, barges, tank trucks, tank truck and rail/barge/
truck receipt facilities is within the reach of corresponding 
construction firms.\123\ Although shipment of biofuels by rail 
represents a major fraction of all biofuel ton-miles, it is projected 
to account for approximately 0.4% of all rail freight by 2022. 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. 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 under EISA.
---------------------------------------------------------------------------

    \122\ See Section 1.6 of the RIA for additional discussion of 
the challenges in distributing biofuels from the production/import 
facility to the end user.
    \123\ Vessels that transport biodiesel will need to be heated/
insulated in cold climates to prevent gelling.
---------------------------------------------------------------------------

2. Petroleum Terminal Accommodations
    Terminals will need to install additional storage capacity to 
accommodate the volume of biofuels that we anticipate will be used in 
response to the RFS2 standards. Petroleum terminals will also need to 
install truck receipt facilities for biofuels and equipment to blend 
biofuels into petroleum-based fuels. Upgrades to barge receipt 
facilities to handle deliveries of biofuels may also be needed at 
petroleum terminals with water access. Biodiesel storage and blending 
facilities will need to be insulated/heated in cold climates to prevent 
biodiesel from gelling.\124\ 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.\125\ Overall 
demand for fuel used in motor vehicles is expected to remain relatively 
constant through 2022. Thus, much of the increased demand for biofuel 
storage could be accommodated by modifying storage tanks previously 
used for the gasoline and petroleum-based diesel fuels that would 
displaced by biofuels. 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. 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 storage of biofuels. However, 
we believe that there would be few such situations.
---------------------------------------------------------------------------

    \124\ Some terminals are avoiding the need for heated/insulated 
biodiesel facilities by storing high biodiesel blends (e.g. B50) for 
blending with petroleum-based diesel fuel.
    \125\ The Independent Fuel Terminal Operators Association 
represents terminals in the Northeast.
---------------------------------------------------------------------------

    In the NPRM, we stated the current EPA policy that the RFG and 
anti-dumping regulations currently require certified gasoline to be 
blended with denatured ethanol to produce E85. We also stated that 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. 
Commenters questioned these statements. As we are not taking any action 
in this final rule with respect to policies surrounding E85, we will 
consider these comments outside the context of this rule.
3. Potential Need for Special Blendstocks at Petroleum Terminals for 
E85
    ASTM International is considering a proposal to lower the minimum 
ethanol concentration in E85 to facilitate meeting ASTM minimum 
volatility specifications in cold climates and when only low vapor 
pressure gasoline is available at terminals.\126\ Commenters have 
stated that the current proposal to lower the minimum ethanol 
concentration to 68 volume percent may not be sufficient for this 
purpose. ASTM International may consider an additional proposal to 
further decrease the minimum ethanol concentration. Absent such an 
adjustment, a high-vapor pressure petroleum-based blendstock such as 
butane would need to be supplied to most petroleum terminals to produce 
E85 that meets minimum volatility specifications. In such a case, 
butane would need to be transported by tank truck from petroleum 
refineries to terminals and storage and blending equipment would be 
needed at petroleum terminals.\127\
---------------------------------------------------------------------------

    \126\ Minimum volatility specifications were established by ASTM 
to address safety and vehicle driveability considerations.
    \127\ See Section 1.6 of the RIA for a discussion of the 
potential distribution of butane to petroleum terminals for blending 
with E85 and Section 4.2 for the potential costs.
---------------------------------------------------------------------------

    Instead of lowering the minimum ethanol concentration of E85, some 
stakeholders are discussing establishing a new high-ethanol blend for 
use in flex-fuel vehicles. Such a fuel would have a minimum ethanol 
concentration that would be sufficient to allow minimum volatility 
specifications to be satisfied while using finished gasoline that is 
already available at petroleum terminals.\128\ E85 would continue to be 
marketed in addition to this new fuel for use in flex-fuel vehicles 
when E85 minimum volatility considerations could be satisfied.
---------------------------------------------------------------------------

    \128\ Such a new fuel might have a lower ethanol concentration 
of 60% and a maximum ethanol concentration of 85%.
---------------------------------------------------------------------------

    We believe that industry will resolve the concerns over the ability 
to meet the minimum volatility needed for high-ethanol blends used in 
flex-fuel vehicles in a manner that will not necessitate the use of 
high-vapor pressure blendstocks in their manufacture. Nevertheless, 
petroleum terminals may find it advantageous to blend butane into E85 
because of the low cost of butane relative to gasoline provided that 
the cost benefit outweighs the associated butane distribution 
costs.\129\
---------------------------------------------------------------------------

    \129\ EPA may consider reevaluating its policies regarding the 
blendstocks used in the manufacture of E85 to facilitate this 
practice.
---------------------------------------------------------------------------

4. Need for Additional E85 Retail Facilities
    The number of additional E85 retail facilities needed to consume 
the volume of ethanol used under EISA varies substantially depending on 
the control case. Under our primary mid-ethanol scenario, we estimate 
that by 2022 an additional 19,765 E85 retail facilities would be needed 
relative to the AEO reference case to enable the consumption of the 
ethanol that we project would be used in E85.\130\ Under

[[Page 14759]]

the high-ethanol scenario, we estimate that an additional 23,809 E85 
facilities would be needed and that 4,500 E85 facilities that would 
otherwise be in place would need to be upgraded to include more E85 
dispensers by 2022. Whereas under the low-ethanol volume scenario, we 
project that 11,677 additional E85 facilities would be needed by 2022.
---------------------------------------------------------------------------

    \130\ See Section 1.6 of the RIA for a discussion of the 
projected number of E85 refueling facilities that would be needed. 
There would need to be a total of 24,265 E85 retail facilities under 
the primary scenario, 4,500 of which are projected to have been 
placed in service absent the RFS2 standards under the AEO reference 
case. Our analysis assumes the installation of new dispensers and 
underground storage tank (UST) systems for E85. EPA's Office of 
Underground Storage Tanks requires that UST systems must be 
compatible with the fuel stored. Authorities who Have Jurisdiction 
(such as local fire marshals) typically require that fuel dispensers 
be listed by an organization such as Underwriters Laboratories.
---------------------------------------------------------------------------

    On average, approximately 1,520 additional E85 facilities will be 
needed each year from 2010 through 2022 under our primary scenario. 
Under the high and low ethanol scenarios, an additional 1,820 and 900 
E85 retail facilities per year respectively would be needed. Under the 
high ethanol case and to a lesser extent under the primary case, this 
represents an aggressive timeline for the addition of new E85 
facilities given that there are approximately 2,000 E85 retail 
facilities in service today. Nevertheless, we believe the addition of 
these new E85 facilities may be possible for the industries that 
manufacture and install E85 retail equipment. Underwriters Laboratories 
requires that E85 refueling dispenser systems must be certified as 
complete units.\131\ To date, no complete E85 dispenser systems have 
been certified by UL. We understand that all the fuel dispenser 
components with the exception of the hoses that connect to the 
refueling nozzle have successfully passed the necessary testing. There 
does not appear to be a technical difficulty in finding hoses that can 
pass the required testing. Therefore, we anticipate this situation will 
be resolved once the demand for new E85 facilities is demonstrated. 
Hence, we believe that the current lack of a UL certification for 
complete E85 dispenser systems will not impede the installation of the 
additional E85 facilities that we projected will be needed.
---------------------------------------------------------------------------

    \131\ See http://ulstandardsinfonet.ul.com/outscope/0087A.html.
---------------------------------------------------------------------------

    Petroleum retailers expressed concerns about their ability to bear 
the cost installing the needed E85 refueling equipment given that most 
retailers are small businesses and have limited capital resources. They 
also expressed concern regarding their ability to discount the price of 
E85 relative to E10 sufficiently to persuade flexible fuel vehicle 
owners to choose E85 given the lower energy density of ethanol. Today's 
rule does not contain a requirement for retailers to carry E85. We 
understand that retailers will only install E85 facilities if they can 
be assured of sufficient E85 throughput to recover their capital costs. 
The current projections regarding the future cost of gasoline relative 
to ethanol indicate that it may be possible to price E85 in a 
competitive fashion to E10. Thus, demand for E85 may be sufficient to 
encourage retailers to install the needed E85 refueling facilities.

D. Ethanol Consumption

1. Historic/Current Ethanol Consumption
    Ethanol and ethanol-gasoline blends have a long history as 
automotive fuels. In fact, the well-known Model-T was capable of 
running on both ethanol and gasoline.\132\ However, inexpensive crude 
oil prices kept ethanol from making a significant presence in the 
transportation sector until the end of the 20th century. Over the past 
decade, ethanol use has grown rapidly due to oxygenated fuel 
requirements, MTBE bans, tax incentives, state mandates, the first 
federal renewable fuels standard (``RFS1''), and rising crude oil 
prices. Although the cost of crude has come down since reaching record 
levels in 2008, uncertainty surrounding pricing and the environmental 
implications of fossil fuels continue to drive ethanol use.
---------------------------------------------------------------------------

    \132\ The Model T was also capable of running on kerosene.
---------------------------------------------------------------------------

    A record 9.5 billion gallons of ethanol were blended into U.S. 
gasoline in 2008 and EIA is forecasting additional growth in the years 
to come.\133\ According to their recently released Short-Term Energy 
Outlook (STEO), EIA is forecasting 0.7 million barrels of daily ethanol 
use in 2009, which equates to 10.7 billion gallons. The October 2009 
STEO projects that total ethanol usage (domestic production plus 
imports) will reach 12.1 billion gallons by 2010.\134\
---------------------------------------------------------------------------

    \133\ EIA, Monthly Energy Review, September 2009 (Table 10.2b).
    \134\ Letter from Richard Newell, EIA Administrator to Lisa 
Jackson, EPA Administrator dated October 29, 2009 (Table 1).
---------------------------------------------------------------------------

    The National Petrochemical and Refiners Association (NPRA) 
estimates that ethanol is currently blended into about 75 percent of 
all gasoline sold in the United States.\135\ The vast majority is 
blended as E10 or 10 volume percent ethanol, although a small amount is 
blended as E85 for use in flexible fuel vehicles (FFVs).
---------------------------------------------------------------------------

    \135\ Based on comments provided by NPRA (EPA-HQ-OAR-2005-0161-
2124.1).
---------------------------------------------------------------------------

    Complete saturation of the gasoline market with E10 is referred to 
as the ethanol ``blend wall.'' The height of the blend wall in any 
given year is directly related to gasoline demand. In AEO 2009, EIA 
projects that gasoline demand will peak around 2013 and then start to 
taper off due to vehicle fuel economy improvements. Based on the 
primary ethanol growth scenario we're forecasting under today's RFS2 
program, the nation is expected to hit the 14-15 billion gallon blend 
wall by around 2014 (refer ahead to Figure IV.D.2-1), although it could 
be sooner if gasoline demand is lower than expected. It could also be 
lower if projected volumes of non-ethanol renewables do not materialize 
and ethanol usage is higher than expected.
    Over the years there have been several policy attempts to increase 
FFV sales including Corporate Average Fuel Economy (CAFE) credits and 
government fleet alternative-fuel vehicle requirements. As a result, 
there are an estimated 8 million FFVs on the road today, up from just 
over 7 million in 2008. While this is not insignificant in terms of 
growth, FFVs continue to make up less than 4 percent of the total 
gasoline vehicle fleet. In addition, E85 is only currently offered at 
about 1 percent of gas stations nationwide. Ethanol consumption is 
currently limited by the number of FFVs on the road and the number of 
E85 outlets or, more specifically, the number of FFVs with access to 
E85. Still many FFV owners with access to E85 are not choosing it 
because it is currently priced almost 40 cents per gallon higher than 
conventional gasoline on an energy equivalent basis.\136\ According to 
EIA, only 12 million gallons of E85 were consumed in 2008.\137\
---------------------------------------------------------------------------

    \136\ Based on average E85 and regular unleaded gasoline prices 
reported at http://www.fuelgaugereport.com/on November 23, 2009.
    \137\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 2).
---------------------------------------------------------------------------

    To meet today's RFS2 requirements we are going to need to see 
growth in FFV and E85 infrastructure as well as changes in retail 
pricing and consumer behavior. However, the amount of change needed is 
proportional to the amount of ethanol observed under the RFS2 program. 
As explained in Section IV.A, EPA expects total ethanol demand could be 
anywhere from 17.5 to 33.2 billion gallons in 2022, depending on the 
amount of non-ethanol cellulosic biofuels that are realized. The low-
ethanol case would require only moderate changes in FFV/E85 
infrastructure and refueling whereas the high-ethanol case would 
require very dramatic changes and likely a mandate. For the final rule, 
we have chosen to focus our impact analyses on the primary mid-ethanol 
case of 22.2 billion gallons. A discussion of how this

[[Page 14760]]

volume of ethanol could be consumed in 2022 with expanded FFV/E85 
infrastructure is presented below. As expected, the infrastructure 
changes required under this FRM scenario are less extreme than those 
highlighted in the proposal based on a predominant ethanol world (34.2 
billion gallons of ethanol). However, there are additional 
technological, logistical and financial barriers that will need to be 
overcome with respect to commercialization of BTL and non-ethanol 
cellulosic biofuels. For more on cellulosic diesel technologies, 
distribution impacts, and production costs, refer to Sections 1.4, 1.6 
and 4.1 of the RIA.
2. Increased Ethanol Use Under RFS2
    Under the primary ethanol growth scenario considered as part of 
today's rule, ethanol consumption will need to be about three times 
higher than RFS1 levels, more than twice as much as today's levels, and 
9 billion gallons higher than the ethanol predicted to occur in 2022 
absent RFS2 (according to AEO 2007). To get to 22.2 billion gallons of 
ethanol use according to the potential ramp-up described in Section 1.2 
of the RIA, the nation is predicted to hit the blend wall in 2014 as 
shown below in Figure IV.D.2-1.
[GRAPHIC] [TIFF OMITTED] TR26MR10.422

    As shown above, we are anticipating almost 14 billion gallons of 
non-ethanol advanced biofuels under today's RFS2 program. But overall, 
ethanol is expected to continue to be the nation's primary biofuel with 
over 22 billion gallons in 2022. To get beyond the blend wall and 
consume more than 14-15 billion gallons of ethanol, we are going to 
need to see increases in the number FFVs on the road, the number of E85 
retailers, and the FFV E85 refueling frequency.
    It is possible that conventional gasoline (E0) could continue to 
co-exist with E10 and E85 for quite some time. However, for analysis 
purposes, we have assumed that E10 would replace E0 as expeditiously as 
possible and that all subsequent ethanol growth would come from E85. 
Furthermore, we assumed that no ethanol consumption would come from the 
mid-level ethanol blends (e.g., E15) under our primary control case 
since they are not currently approved for use in non-FFVs. However, as 
a sensitivity analysis, we have examined the impacts that E15 would 
have on ethanol consumption (refer to Section IV.D.3).
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 provided by EIA in the AEO 2009 final release.\138\ AEO 
2009 takes the fuel economy improvements set by EISA into consideration 
and also assumes a slight dieselization of the light-duty vehicle 
fleet.\139\ It also takes the recession's impacts on driving patterns 
into consideration. The result is a 25% reduction in the projected 2022 
gasoline

[[Page 14761]]

energy demand from AEO 2007 (a pre-EISA world) to AEO 2009.\140\ EIA 
essentially has total gasoline energy demand (petroleum-based gasoline 
plus ethanol) flattening out, and even slightly decreasing, as we move 
into the future.
---------------------------------------------------------------------------

    \138\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 2).
    \139\ The gasoline energy demand forecast provided in AEO 2009--
ARRA Update is reasonably consistent with the recently Proposed 
Rulemaking To Establish Light-Duty Vehicle Greenhouse Gas Emission 
Standards and Corporate Average Fuel Economy Standards (referred to 
hereafter as the ``Light-Duty Vehicle GHG Rule.'' For more 
information on the Light-Duty Vehicle GHG Rule, refer to 74 FR 49454 
(September 28, 2009).
    \140\ EIA, Annual Energy Outlooks 2007 & 2009--ARRA Update 
(Table 2).
---------------------------------------------------------------------------

b. Projected Growth in Flexible Fuel Vehicles
    Over one million FFVs were sold in both 2008 and 2009 according to 
EPA certification data. Despite the recession and current state of the 
auto industry, 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 automakers 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.
    To measure the impacts of increased volumes of renewable fuel, we 
considered three different FFV production scenarios that might 
correspond to the three biofuel control cases analyzed for the final 
rule. For all three cases, we assumed that total light-duty vehicle 
sales would follow AEO 2009 trends. The latest EIA report suggests 
lower than average sales in 2008-2013 (less than 16 million vehicles 
per year) before rebounding and growing to over 17 million vehicles by 
2019.\141\ These vehicle projections are consistent with EPA's recently 
proposed Light-Duty Vehicle GHG Rule.\142\
---------------------------------------------------------------------------

    \141\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 47).
    \142\ Rulemaking to Establish Light-Duty Vehicle GHG Emission 
Standards and Corporate Average Fuel Economy Standards, 74 FR 49454 
(September 28, 2009).
---------------------------------------------------------------------------

    Although we assumed total vehicle and car/truck sales would be the 
same in all three cases, we assumed varying levels of FFV production. 
For our low-ethanol control case, we assumed steady business-as-usual 
FFV growth according to AEO 2009 predictions.\143\ For our primary mid-
ethanol control case, we assumed increased FFV sales under the 
presumption that GM, Ford and Chrysler (referred to hereafter as the 
``Detroit 3'') would follow through with their commitment to produce 
50% FFVs by 2012. Despite the current state of the economy and the 
hardships facing the auto industry (GM and Chrysler filed for 
bankruptcy earlier this year), the Detroit 3 appear to still be moving 
forward with their voluntary FFV commitment.\144\ Under our primary 
control case, we assumed that non-domestic FFVs sales would track 
around 2%, consistent with today's production/plans.\145\ Finally, for 
our high-ethanol control case, we assumed a theoretical 80% FFV mandate 
based on the Open Fuel Standard Act of 2009 that was reintroduced in 
Congress on March 12, 2009.\146\ Given today's reduced vehicle sales 
and gasoline demand, we believe a mandate would be the only viable 
means for consuming 32.2 billion gallons of ethanol in 2022.
---------------------------------------------------------------------------

    \143\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 47).
    \144\ Ethanol Producer Magazine, ``Automakers Maintain FFV 
Targets in Bailout Plans.'' February 2009. This is consistent with 
information provided in GM and Chrysler's restructuring plans 
submitted to the U.S. Department of Treasury on February 17, 2009.
    \145\ Based on 2008 FFV certification data and 2009 projections 
based on the National Ethanol Vehicle Coalition, 2009 FFV Purchasing 
Guide.
    \146\ A copy of H.R. 1476 can be found at: http://www.opencongress.org/bill/111-h1476/text.
---------------------------------------------------------------------------

    Under our primary mid-ethanol control case, total FFV sales are 
estimated at just over 4 million vehicles per year in 2017 and beyond. 
This is less aggressive than the assumptions made in the NPRM. At that 
time, we were expecting more cellulosic ethanol which could justify 
higher FFV production assumptions. We assumed that not only would the 
Detroit 3 fulfill their 50% by 2012 FFV production commitment, non-
domestic automakers might follow suit and produce 25% FFV in 2017 and 
beyond. We also assumed that annual light-duty vehicle sales would 
continue around the historical 16 million vehicle mark resulting in 6 
million FFVs in 2017 and beyond.
    Based on our revised vehicle/FFV production assumptions coupled 
with vehicle survival rates, VMT, and fuel economy estimates applied in 
the recently proposed Light-Duty Vehicle GHG Rule, the maximum 
percentage of fuel (gasoline/ethanol mix) that could feasibly be 
consumed by FFVs in 2022 would be about 20% (down from 30% in the 
NPRM). For more information on our FFV production assumptions and fuel 
fraction calculations, refer to Section 1.7.2 of the RIA.
c. Projected Growth in E85 Access
    According to the National Ethanol Vehicle Coalition (NEVC), there 
are currently 2,100 gas stations offering E85 in 44 states plus the 
District of Columbia.\147\ While this represents significant industry 
growth, it still only translates to 1.3% of U.S. retail stations 
nationwide carrying the fuel.\148\ 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.\149\ Accordingly, just over 5% of the nation currently has 
reasonable access to E85, up from 4% in 2008 (based on a mid-year NEVC 
pump estimate).\150\
---------------------------------------------------------------------------

    \147\ NEVC Web site, accessed on November 23, 2009.
    \148\ Based on National Petroleum News gasoline station estimate 
of 161,768 in 2008.
    \149\ For a more detailed discussion on how we derived our one-
in-four reasonable access assumption, refer to Section 1.6 of the 
RIA. 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 RIA.
    \150\ Computed as percent of stations with E85 (2,101/161,768 as 
of November 2009 or 1,733/161,768 as of August 2008) 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, 10 Midwest states have adopted a progressive 
Energy Security and Climate Stewardship Platform.\151\ 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, the 
American Recovery and Reinvestment Act of 2009 (ARRA or Recovery Act) 
recently increased 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.\152\
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    \151\ The following states have adopted the plan: Illinois, 
Indiana, Iowa, Kansas, Michigan, Minnesota, Missouri, Ohio, South 
Dakota and Wisconsin. For more information, visit: http://www.midwesterngovernors.org/resolutions/Platform.pdf.
    \152\ http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=111_cong_bills&docid=f:h1enr.pdf.
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    Given the growing number of subsidies, it is clear that E85 
infrastructure will continue to expand in the future. However, like 
FFVs, we expect that E85 station growth will be somewhat proportional 
to the amount of ethanol realized under the RFS2 program. As such, we 
analyzed three different E85 growth scenarios for the final rule that 
could correspond to the three different RFS2 control cases. As an upper 
bound for our high-ethanol control case, we maintained the 70% access 
assumption we applied for the NPRM. This is roughly equivalent to all 
urban areas in the United States offering reasonable (one-in-four-
station) access

[[Page 14762]]

to E85.\153\ For our other control cases we assumed access to E85 would 
be lower with the logic that retail stations (the majority of which are 
independently owned and operated and net around $30,000 per year) would 
not invest in more E85 infrastructure than what was necessary to meet 
the RFS2 requirements. For our primary mid-ethanol control case we 
assumed reasonable access would grow from 4% in 2008 to 60% in 2022 and 
for our low-ethanol control case we assumed that access would only grow 
to 40% by 2022. As discussed in Section IV.C, we believe these E85 
growth scenarios are possible based on our assessment of distribution 
infrastructure capabilities.
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    \153\ 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.
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d. Required Increase in E85 Refueling Rates
    As mentioned earlier, there were just over 7 million FFVs on the 
road in 2008. If all FFVs refueled on E85 100% of the time, this would 
translate to about 8.3 billion gallons of E85 use.\154\ However, E85 
usage was only around 12 million gallons in 2008.\155\ This means that, 
on average, FFV owners were only tapping into about 0.15% 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 4% E85 refueling 
frequency for those FFVs that had reasonable access to the fuel.
---------------------------------------------------------------------------

    \154\ Based on average vehicle miles traveled (VMT) and in-use 
fuel economy (MPG) for FFVs in the fleet in 2008. For more 
information on FFV E85 fuel consumption calculations, refer to 
Section 1.7.4 of the RIA.
    \155\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 17).
---------------------------------------------------------------------------

    There are several reasons behind 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.\156\ 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 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).\157\ 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 (discussed in more 
detail in the subsection that follows).
---------------------------------------------------------------------------

    \156\ 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.
    \157\ Based on our assumption that denatured ethanol has an 
average lower heating value of 77,012 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 2009 assumption, E85 was 
assumed to contain 74 vol% ethanol and 26 vol% gasoline on average.
---------------------------------------------------------------------------

    To comply with the RFS2 program and consume 22.2 billion gallons of 
ethanol by 2022 (under our primary ethanol control case), 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 would need to fill up on it as often as 58% of the time, a 
significant increase from today's estimated 4% 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 an online fuel price survey, E85 is currently priced 
almost 40 cents per gallon or about 15% lower than regular grade 
conventional gasoline.\158\ But this is still about 30 cents per gallon 
higher than conventional gasoline on an energy-equivalent basis. 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. Overall, we estimate 
that E85 would need to be priced about 25% lower than E10 at retail in 
2022 in order for it to make sense to consumers.
---------------------------------------------------------------------------

    \158\ Based on average E85 and regular unleaded gasoline prices 
reported at http://www.fuelgaugereport.com/ on November 23, 2009.
---------------------------------------------------------------------------

    However, ultimately it comes down to what refiners are willing to 
pay for ethanol blended as E85. The more ethanol you try to blend as 
E85, the more devalued ethanol becomes as a gasoline blendstock. 
Changes to state and Federal excise tax structures could help promote 
ethanol blending as E85. Similarly, high crude prices make E85 look 
more attractive. According to EIA's AEO 2009, crude oil prices are 
expected to increase from about $80 per barrel (today's price) to $116/
barrel by 2022.\159\ Based on our retail cost calculations, ethanol 
would have to be priced around $2/gallon or less in order to be 
attractive to refiners for E85 blending in 2022. According to the DTN 
Ethanol Center, the current rack price for ethanol is around $2.20/
gallon.\160\ However, as explained in Section 4.4 of the RIA, we 
project that the average ethanol delivered price will come down in the 
future under the RFS2 program. Therefore, while gasoline refiners and 
markets will always have a greater profit margin selling ethanol in 
low-level blends to consumers based on volume, they should be able to 
maintain a profit selling it as E85 based on energy content in the 
future.
---------------------------------------------------------------------------

    \159\ EIA, Annual Energy Outlook 2009--ARRA Update (Table 12).
    \160\ http://www.dtnethanolcenter.com/index.cfm?show=10&mid=32.
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    Once the nation gets past the blend wall, more ethanol will need to 
be blended as E85 and less as E10. FFV owners who were formerly 
refueling on gasoline will need to start filling up on E85. Under our 
primary control case, we expect that 12.9 billion gallons of ethanol 
would be blended as E10 and 9.3 billion gallons would be blended as E85 
to reach the 22.2 billion gallons in 2022. For more on our ethanol 
consumption feasibility and retail cost calculations, including 
discussion of the other two control cases, refer to Section 1.7 of the 
RIA.
3. Consideration of >10% Ethanol 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 ethanol by volume.\161\ On 
April

[[Page 14763]]

21, 2009, EPA issued a Federal Register notice announcing receipt of 
the Growth Energy waiver application and soliciting comment on all 
aspects of it.\162\ On May 20, 2009, EPA issued an additional Federal 
Register notice extending the public comment period by an additional 60 
days.\163\ The comment period ended on July 20, 2009, and EPA is now 
evaluating the waiver application and considering the comments which 
were submitted.
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    \161\ http://www.growthenergy.org/2009/e15/Waiver%20Cover%20Letter.pdf. Additional supporting documents are 
available on the Growth Energy Web site.
    \162\ Refer to 74 FR 18228 (April 21, 2009).
    \163\ Refer to 74 FR 23704 (May 20, 2009).
---------------------------------------------------------------------------

    In a letter dated November 30, 2009, EPA notified the applicant 
that, because crucial vehicle durability information being developed by 
the Department of Energy would not be available until mid-2010, EPA 
would be delaying its decision on the application until a sufficient 
amount of this information could be included in its analysis so that 
the most scientifically supportable decision could be made.\164\ As the 
current Growth Energy waiver application is still under review, EPA 
believes it is appropriate to address aspects of the mid-level blend 
waiver in its decision announcement on the waiver application as 
opposed to dealing with the comments and evaluation of the potential 
waiver in the preamble of today's final rule.
---------------------------------------------------------------------------

    \164\ http://www.epa.gov/OMS/regs/fuels/additive/lettertogrowthenergy11-30-09.pdf.
---------------------------------------------------------------------------

    Although EPA has yet to make a waiver decision, since its approval 
could have a significant impact on our analyses that are based on the 
use of E85, as a sensitivity analysis, we have evaluated the impacts 
that E15 could have on ethanol consumption feasibility. More 
specifically, we have assessed the impacts of a partial waiver for 
newer technology vehicles consistent with the direction of EPA's 
November 30, 2009 letter. We assumed that E10 would need to continue to 
co-exist for legacy and non-road equipment based on consumer demand 
regardless of any waiver decision. For analysis purposes, we assumed 
E10 would be marketed as premium-grade gasoline (the universal fuel), 
E15 would be marketed as regular-grade gasoline (to maximize ethanol 
throughput) and, like today, midgrade would be blended from the two 
fuels to make a 12.5 vol% blend (E12.5). In addition, we assumed that 
some E15-capable vehicles would continue to choose E10 or E12.5 based 
on our knowledge of today's premium and midgrade sales.\165\
---------------------------------------------------------------------------

    \165\ According to EIA's 2008 Petroleum Annual Outlook (Table 
45), midgrade and premium comprise 13.5% of total gasoline sales.
---------------------------------------------------------------------------

    In the event of a partial waiver, it is unclear how long it would 
take for E15 to be fully deployed or whether it would ever be available 
nationwide. For analysis purposes, we assumed that E15 would be fully 
phased in and available at all retail stations nationwide by the time 
the nation hit the blend wall, or around 2014 for our primary control 
case shown in Figure IV.D.3-1.
[GRAPHIC] [TIFF OMITTED] TR26MR10.423

    As modeled, a partial waiver for E15 could increase the ethanol 
consumption potential from conventional vehicles to about 19 billion 
gallons. Under our primary control case (shown in Figure IV.D.3-1), E15 
could postpone the blend wall by up to five years, or to 2019. Although 
E15 would fall short of meeting the RFS2 requirements under this 
scenario, it could provide interim relief while the county ramps up 
non-ethanol cellulosic biofuel production and expands E85/FFV 
infrastructure. Under our high-ethanol control case, a partial waiver 
for E15 could eliminate

[[Page 14764]]

the need for FFV or E85 infrastructure mandates. Under our low-ethanol 
control case, E15 could eliminate the need for additional FFV/E85 
infrastructure all together. For more information, refer to Section 
1.7.6 of the RIA.

V. Lifecycle Analysis of Greenhouse Gas Emissions

A. Introduction

    As recognized earlier in this preamble, a significant aspect of the 
RFS2 program is the requirement that a fuel meet a specific lifecycle 
greenhouse gas (GHG) emissions threshold for compliance for each of 
four types of renewable fuels. This section describes the methodology 
used by EPA to determine the lifecycle GHG emissions of biofuels, and 
the petroleum-based transportation fuels that they replace. EPA 
recognizes that this aspect of the RFS2 regulatory program has received 
particular attention and comment throughout the public comment period. 
Therefore, this section also will describe the enhancements made to our 
approach in conducting the lifecycle analysis for the final rule. This 
section will highlight areas where we have incorporated new scientific 
data that has become available since the proposal as well as the 
approach the Agency has taken to recognize and quantify, where 
appropriate, the uncertainty inherent in this analysis.
1. Open and Science-Based Approach to EPA's Analysis
    Throughout the development of EPA's lifecycle analysis, the Agency 
has employed a collaborative, transparent, and science-based approach. 
EPA's lifecycle methodology, as developed for the RFS2 proposal, 
required breaking new scientific ground and using analytical tools in 
new ways. The work was generally recognized as state of the art and an 
advance on lifecycle thinking, specifically regarding the indirect 
impacts of biofuels.
    However, the complexity and uncertainty inherent in this work made 
it extremely important that we seek the advice and input of a broad 
group of stakeholders. In order to maximize stakeholder outreach 
opportunities, the comment period for the proposed rule was extended to 
120 days. In addition to this formal comment period, EPA made multiple 
efforts to solicit public and expert feedback on our approach. 
Beginning early in the NPRM process and continuing throughout the 
development of this final rule, EPA held hundreds of meetings with 
stakeholders, including government, academia, industry, and non-profit 
organizations, to gather expert technical input. Our work was also 
informed heavily by consultation with other federal agencies. For 
example, we have relied on the expert advice of USDA and DOE, as well 
as incorporating the most recent inputs and models provided by these 
Agencies. Dialogue with the State of California and the European Union 
on their parallel, on-going efforts in GHG lifecycle analysis also 
helped inform EPA's methodology. As described below, formal technical 
exchanges and an independent, formal peer review of the methodology 
were also significant components of the Agency's outreach. A key result 
of our outreach effort has been awareness of new studies and data that 
have been incorporated into our final rule analysis.
    Technology Exchanges: Immediately following publication of the 
proposed rule, EPA held a two-day public workshop focused specifically 
on lifecycle analysis to assure full understanding of the analyses 
conducted, the issues addressed, and the options discussed. The 
workshop featured EPA presentations on each component of the 
methodology as well as presentations and discussions by stakeholders 
from the renewable fuel community, federal agencies, universities, and 
environmental groups. The Agency also took advantage of opportunities 
to meet in the field with key, affected stakeholders. For example, the 
Agency was able to twice participate in meetings and tours in Iowa 
hosted by the local renewable fuel and agricultural community. As 
described in this section, one of the many outcomes of these meetings 
was an improved understanding of agricultural and biofuel production 
practices.
    As indicated in the proposal, our lifecycle results were 
particularly impacted by assumptions about land use patterns and 
emissions in Brazil. During the public comment process we were able to 
update and refine these assumptions, including the incorporation of 
new, improved sources of data based on Brazil-specific data and 
programs. In addition, the Agency received more recent trends on 
Brazilian crop productivity, areas of crop expansion, and regional 
differences in costs of crop production and land availability. Lastly, 
we received new information on efforts to curb deforestation allowing 
the Agency to better predict this impact through 2022.
    Peer Review: To ensure the Agency made its decisions for this final 
rule on the best science available, EPA conducted a formal, independent 
peer review of key components of the analysis. The reviews were 
conducted following the Office of Management and Budget's peer review 
guidance that ensures consistent, independent government-wide 
implementation of peer review, and according to EPA's longstanding and 
rigorous peer review policies. In accordance with these guidelines, EPA 
used independent, third-party contractors to select highly qualified 
peer reviewers. The reviewers selected are leading experts in their 
respective fields, including lifecycle assessment, economic modeling, 
remote sensing imagery, biofuel technologies, soil science, 
agricultural economics, and climate science. They were asked to 
evaluate four key components of EPA's methodology: (1) Land use 
modeling, specifically the use of satellite data and EPA's proposed 
land conversion GHG emission factors; (2) methods to account for the 
variable timing of GHG emissions; (3) GHG emissions from foreign crop 
production (both the modeling and data used); and (4) how the models 
EPA relied upon are used together to provide overall lifecycle 
estimates.
    The advice and information received through this peer review are 
reflected throughout this section. EPA's use of higher resolution 
satellite data is one example of a direct outcome of the peer review, 
as is the Agency's decision to retain its reliance upon this data. The 
reviewers also provided recommendations that have helped to inform the 
larger methodological decisions presented in this final rule. For 
example, the reviewers in general supported the importance of assessing 
indirect land use change and determined that EPA used the best 
available tools and approaches for this work. However, the review also 
recognized that no existing model comprehensively simulates the direct 
and indirect effects of biofuel production both domestically and 
internationally, and therefore model development is still evolving. The 
uncertainty associated with estimating indirect impacts and the 
difficulty in developing precise results also were reflected in the 
comments. In the long term, this peer review will help focus EPA's 
ongoing lifecycle analysis work as well as our future interactions with 
the National Academy of Science and other experts.
    Altogether, the many and extensive public comments we received to 
the rule docket, the numerous meetings, workshops and technical 
exchanges, and the scientific peer review have all been instrumental to 
EPA's ability to advance our analysis between proposal and final and to 
develop the

[[Page 14765]]

methodological and regulatory approach described in this section.
2. Addressing Uncertainty
    The peer review, the public comments we have received, and the 
analysis conducted for the proposal and updated here for the final 
rule, indicate that it is important to take into account indirect 
emissions when looking at lifecycle emissions from biofuels. It is 
clear that, especially when considering commodity feedstocks, including 
the market interactions of biofuel demand on feedstock and agricultural 
markets is a more accurate representation of the impacts of an increase 
in biofuels production on GHG emissions than if these market 
interactions are not considered.
    However, it is also clear that there are significant uncertainties 
associated with these estimates, particularly with regard to indirect 
land use change and the use of economic models to project future market 
interactions. Reviewers highlighted the uncertainty associated with our 
lifecycle GHG analysis and pointed to the inherent uncertainty of the 
economic modeling.
    In the proposal, we asked for comment on whether and how to conduct 
an uncertainty analysis to help quantify the magnitude of this 
uncertainty and its relative impact on the resulting lifecycle 
emissions estimates. The results of the peer review, and the feedback 
we have received from the comment process, supported the value of 
conducting such an analysis. Therefore, working closely with other 
government agencies as well as incorporating feedback from experts who 
commented on the rule, we have quantified the uncertainty associated 
specifically with the international indirect land use change emissions 
associated with increased biofuel production.
    Although there is uncertainty in all portions of the lifecycle 
modeling, we focused our uncertainty analysis on the factors that are 
the most uncertain and have the biggest impact on the results. 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). 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.
    Therefore, we focused our efforts on the international indirect 
land use change emissions and worked to manage the uncertainty around 
those impacts in three ways: (1) Getting the best information possible 
and updating our analysis to narrow the uncertainty, (2) performing 
sensitivity analysis around key factors to test the impact on the 
results, and (3) establishing reasonable ranges of uncertainty and 
using probability distributions within these ranges in threshold 
assessment. The following sections outline how we have incorporated 
these three approaches into our analysis.
    EPA recognizes that as the state of scientific knowledge continues 
to evolve in this area, the lifecycle GHG assessments for a variety of 
fuel pathways will continue to change. Therefore, while EPA is using 
its current lifecycle assessments to inform the regulatory 
determinations for fuel pathways in this final rule, as required by the 
statute, the Agency is also committing to further reassess these 
determinations and lifecycle estimates. As part of this ongoing effort, 
we will ask for the expert advice of the National Academy of Sciences, 
as well as other experts, and incorporate their advice and any updated 
information we receive into a new assessment of the lifecycle GHG 
emissions performance of the biofuels being evaluated in this final 
rule. EPA will request that the National Academy of Sciences over the 
next two years evaluate the approach taken in this rule, the underlying 
science of lifecycle assessment, and in particular indirect land use 
change, and make recommendations for subsequent rulemakings on this 
subject. This new assessment could result in new determinations of 
threshold compliance compared to those included in this rule that would 
apply to future production (from plants that are constructed after each 
subsequent rule).

B. Methodology

    The regulatory purpose of this analysis is to determine which 
biofuels (both domestic and imported) qualify for the four different 
GHG reduction thresholds and renewable fuel categories established in 
EISA (see Section I.A). This threshold assessment compares the 
lifecycle emissions of a particular biofuel against the lifecycle 
emissions of the petroleum-based fuel it is replacing (e.g., ethanol 
replacing gasoline or biodiesel replacing diesel). This section 
discusses the Agency's approach both for assessing the lifecycle GHG 
emissions from biofuels as well as for the petroleum-based fuels 
replaced by the biofuels.
    As described in detail below, EPA has received a number of comments 
on the different pieces of this analysis and has thoroughly considered 
those comments as well as feedback from our peer review process. In 
each section below we will discuss comments received and how they 
impacted our analysis.
1. Scope of Analysis
    As stated in the proposal, the definition of lifecycle GHG 
emissions established by Congress in EISA is critical to establishing 
the scope of our analysis. 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.\166\
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    \166\ Clean Air Act Section 211(o)(1).

    This definition forms the basis of defining the goal and scope of 
our lifecycle GHG analysis and in determining to what extent changes 
should be made to the analytical approach outlined in our proposed 
rulemaking.
a. Inclusion of Indirect Land Use Change
    EPA notes that it received significant comment on including 
international indirect emissions in its lifecycle calculations. Most of 
the comments suggested that the science of international indirect land 
use change was too new, or that the uncertainty involved was too great, 
to be included in a regulatory analysis. EPA continues to believe 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 significant 
indirect impacts that occur not just within the United States, but also 
those that occur in other countries.
    Some commenters strongly supported EPA's proposal to include 
significant GHG emissions that occur overseas and

[[Page 14766]]

are related to the lifecycle of renewable fuels or baseline fuels used 
in the United States. These commenters agreed that the text of the 
statute supports EPA's proposed approach, and that the alternative of 
ignoring such emissions would result in grossly inaccurate assessments, 
and would be inconsistent with the international nature of GHG 
pollution and the fact that overseas emissions have domestic impacts.
    Other commenters argued that the presumption against 
extraterritorial application of domestic laws carries with it the 
presumption that Congress is concerned with domestic effects and 
domestic impacts only. They assert further that Congress intended to 
benefit domestic agriculture through EISA enactment, and that the 
statute's ambiguous terms should not be interpreted in a manner that 
could harm domestic agriculture in general or, for one commenter, the 
biodiesel industry in particular. Although considering international 
emissions in its analyses could result in different implications under 
the statute for various fuels and fuel pathways as compared to ignoring 
these emissions, EPA believes that this is precisely the outcome that 
Congress intended. Implementation of EISA will undoubtedly benefit the 
domestic agricultural sector as a whole, with some components 
benefiting more than others depending in part on the lifecycle GHG 
emissions associated with the products to be made from individual 
feedstocks. If Congress had sought to promote all biofuel production 
without regard to GHG emissions related to the full lifecycle of those 
fuels, it would not have specified GHG reduction thresholds for each 
category of renewable fuel for which volume targets are specified in 
the Act.
    It is also important to note that including international indirect 
emissions in EPA's lifecycle analysis does not exercise regulatory 
authority over activities that occur solely outside the U.S., nor does 
it raise questions of extra-territorial jurisdiction. EPA's regulatory 
action involves an assessment 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 EISA for the 
use of designated volumes of renewable fuel, cellulosic biofuel, 
biomass-based diesel, and advanced biofuel. 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.
    A number of commenters pointed to the text and structure of the 
definition of ``lifecycle greenhouse gas emissions'' to argue that EPA 
either is not authorized to consider GHG emissions related to 
international land use change, or that it is not required to do so. One 
commenter suggested that the reference in the definition of ``lifecycle 
greenhouse gas emissions'' to ``all stages'' of the lifecycle ``from'' 
feedstock generation ``through'' use of the fuel by the ultimate 
consumer does not include indirect emissions that result from decisions 
to place more land in acreage overseas for such non-fuel purposes as 
cattle feed. Another commenter stated that EPA's approach does not give 
any meaning to the terms ``significant'' and ``fuel lifecycle'' in the 
definition, but instead focuses on the words such as ``full'' to arrive 
at an expansive meaning. This commenter also noted the lack of any 
specific reference to international considerations in Section 211(o), 
as opposed to other provisions in the CAA, such as Section 115.
    EPA believes that a complete analysis of the aggregate GHG 
emissions related to the full lifecycle of renewable fuels includes the 
significant indirect emissions from international land use change that 
are predicted to result from increased domestic use of agricultural 
feedstocks to produce renewable fuel. The statute specifically directs 
EPA to include in its analyses significant indirect emissions such as 
significant emissions from land use changes. EPA has not ignored either 
the terms ``significant'' or ``life cycle.'' It is clear from EPA's 
assessments that the modeled indirect emissions from land use changes 
are ``significant'' in terms of their relationship to total GHG 
emissions for given fuel pathways. Therefore, they are appropriately 
considered in the total GHG emissions profile for the fuels in 
question. EPA has not ignored the term ``life cycle.'' The entire 
approach used by EPA is directed to fully analyzing emissions related 
to the complete lifecycle of renewable and baseline fuels.
    Although the definition of lifecycle greenhouse gas emissions in 
Section 211(o) does not specifically mention international emissions, 
it would be inconsistent with the intent of this section of the amended 
Act to exclude them. A large variety of activities outside the U.S. 
play a major part in the full fuel lifecycle of both baseline (gasoline 
and diesel fuel used as transportation fuel in 2005) and renewable 
fuels. For example, several stages of the lifecycle process for 
gasoline and diesel can occur overseas, including extraction and 
delivery of imported crude oil, and for imported gasoline and diesel 
products, emissions associated with refining and distribution of the 
finished product to the U.S. For imported renewable fuel, all of the 
emissions associated with feedstock production and distribution, fuel 
processing, and delivery of the finished renewable fuel to the U.S. 
occur overseas. The definition of lifecycle GHG 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 result 
in a lifecycle analysis that bears no apparent relationship to the 
purpose of this provision. The purpose of the thresholds in EISA is to 
require the use of renewable fuels that achieve reductions in GHG 
emissions compared to the baseline. Ignoring international emissions, a 
large part of the GHG emission associated with the different fuels, 
would result in a GHG analysis that bears no relationship to the real 
world emissions impact of transportation fuels. The baseline would be 
significantly understated, given the large amount of imported crude and 
imported finished gasoline and diesel used in 2005. Likewise, the 
emissions estimates for imported renewable fuel would be grossly 
reduced in comparison to the aggregate emissions estimates for fuels 
made domestically with domestically-grown feedstocks, simply because 
the impacts of domestically produced fuels occurred within the U.S. EPA 
does not believe that Congress intended such a result.
    Excluding international impacts means 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 where the 
emissions occur. If the purpose of thresholds is to achieve some 
reduction in GHG emissions in order to help address climate change, 
then ignoring emissions outside our borders interferes with the ability 
to achieve this objective. Such an approach would essentially undermine 
the purpose of the provision, and would be an arbitrary interpretation 
of the broadly phrased text used by Congress.
    One commenter stated that matters that could appropriately be 
considered part of a food lifecycle (new land clearing for overseas 
grain production as a result of decreased U.S. grain exports)

[[Page 14767]]

should not be considered part of a renewable fuel lifecycle. However, 
the suggested approach would mean that EPA would fail to account for 
the significant indirect emissions that relate to renewable fuel 
production. EPA believes this would be counter to Congressional intent. 
Although a life cycle analysis of foreign food production may also take 
into account a given land use change, that does not mean that the same 
land use change should not be considered in evaluating its ultimate 
cause, which may be renewable fuel production in the United States.
    Some comments asserted that significant GHG gas emissions from 
international land use change should not be considered if the only 
available models for doing so are not generally accepted or valid 
considering economics or science, or where the approach is new and 
untested, or where the data are faulty and EPA models unrealistic 
scenarios. As described in this rulemaking, EPA has used the best 
available models and substantially modified key inputs to those models 
to reflect comments by peer reviewers, the public, and emerging 
science. EPA has also modeled additional scenarios from those described 
in the NPRM. EPA recognizes that uncertainty exists with respect to the 
results, and has attempted to quantify the range of uncertainty. While 
EPA agrees that application of the models it has used in the context of 
assessing GHG emissions represents changes from previous biofuel 
lifecycle modeling, EPA disagrees that it has used faulty data, modeled 
unrealistic scenarios, or that its approach is otherwise scientifically 
indefensible. Although the results of modeling GHG emissions associated 
with international land use change are uncertain, EPA has attempted to 
quantify that uncertainty and is now in a better position to consider 
the uncertainty inherent in its approach.
    One commenter asserted that by considering international land use 
changes, EPA is seeking to penalize domestic renewable fuel producers 
for impacts over which they have no control. In response, EPA disagrees 
that it is seeking to penalize anyone at all. EPA is simply attempting 
to account for all GHG emissions related to the full fuel lifecycle. 
Domestic renewable fuel producers may have no direct control over land 
use changes that occur overseas as a result of renewable fuel 
production and use here, but their choice of feedstock can and does 
influence oversees activities, and EPA believes it is appropriate to 
consider the GHG emissions from those activities in its analyses.
    Some commenters noted that a finding of causation is built into the 
definitions of ``indirect effects'' in the Endangered Species Act and 
the National Environmental Policy Act, and that EPA should interpret 
the reference to ``indirect emissions' in EISA as requiring similar 
findings of causation. Specifically, they argue that for EPA to count 
GHG emissions from international land use change in its assessments, 
EPA must find that renewable fuel production ``caused'' the land use 
change. In response, without addressing the commenter's claims 
regarding the requirements of NEPA or the ESA, EPA notes that Congress 
has specified in Section 211(o) the required causal link between a fuel 
and indirect emissions. The indirect emissions must be ``related to'' 
the full fuel lifecycle. EPA believes that it has demonstrated this 
link through its modeling efforts. Specifically, the models predict 
that increased demand for feedstocks to produce renewable fuel that 
satisfies EISA mandates will likely result in international land use 
change. Such change is, then, ``related to'' the full fuel lifecycle of 
these fuels. EPA does not believe that the statute requires EPA to wait 
until these effects occur to establish the required linkage, but 
instead believes that it is authorized to use predictive models to 
demonstrate likely results.
    The term ``related to'' is generally interpreted broadly 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. EPA has used a suite of global 
models to project a variety of agricultural impacts of the RFS program, 
including changes in the types of crops and number of acres planted 
world-wide. These shifts in the agricultural market are a direct 
consequence of the increased demand for biofuels in the U.S. This 
increased demand diverts biofuel feedstocks from other competing uses, 
and also increases the price of the feedstock, thus spurring additional 
international production. Our analysis uses country-specific 
information to determine the amount, location, and type of land use 
change that would occur to meet these changes in production patterns. 
The linkages of these changes to increased U.S. biofuel demand in our 
analysis are generally close, and are not extended or overly complex.
    Overall, EPA is confident that it is appropriate to consider 
indirect emissions, including those from both domestic and 
international land use changes, as ``related to'' the full fuel 
lifecycle, based on the results of our modeling. These results form a 
reasonable technical basis for the linkage between the full fuel 
lifecycle of transportation fuels and indirect emissions, as well as 
for the determination that these emissions are significant. EPA 
believes that while uncertainty in the resulting aggregate GHG 
estimates should be taken into consideration, it would be inappropriate 
to exclude indirect emissions estimates from this analysis. The use of 
reasonable estimates of these kinds of indirect emissions allows EPA to 
conduct 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.
    EPA understands that including international indirect land use 
change is a key decision and that there is significant uncertainty 
associated with it. That is why we have taken an approach that 
quantifies that uncertainty and presents the weight of currently 
available evidence in making our threshold determinations.
b. Models Used
    As described in the proposal, to estimate lifecycle indirect 
impacts of biofuel production requires the use of economic modeling to 
determine the market impacts of using agricultural commodity feedstocks 
for biofuels. The use of economic models and the uncertainty of those 
models to accurately predict future agricultural sector scenarios was 
one of the main comments we received on our analysis. While the 
comments and specifically the peer review supported our need to use 
economic models to incorporate and measure indirect impacts of biofuel 
production, they also highlighted the uncertainty with that modeling 
approach, especially in projecting out to the future.
    However, it is important to note that while there are many factors 
that impact the uncertainty in predicting total land used for crop 
production, making accurate predictions of many of these factors are 
not relevant to our analysis. For example different assumptions about 
economic growth rates, weather, and exchange rates will all impact 
future agricultural projections including amount of land use for crops. 
However, we are interested only in the difference between two biofuel 
scenarios holding all other changes constant. So the absolute values 
and projections for crops and other variables in the model

[[Page 14768]]

projections are not as important as the difference the model is 
projecting due to an increase in biofuels production. This limits the 
uncertainty of using the economic models for our analysis.
    Furthermore, one of the key uncertainties associated with our 
agricultural sector economic modeling that has the biggest impact on 
land use change results is the assumptions around crop yields. As 
discussed in Section V.A.2, we are conducting sensitivity analysis 
around different yield assumptions in our analysis.
    Therefore, because of the fact that we are only using the economic 
models to determine the difference between two projected scenarios and 
the fact that we are conducting sensitivity analysis around the yield 
assumptions we feel it is appropriate and acceptable to use economic 
models in our analysis of determining GHG thresholds in our final rule 
analysis.
    As was the case in the proposed analysis, 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, EPA uses the Forestry and Agricultural Sector Optimization 
Model (FASOM), developed by Texas A&M University and others. To 
estimate the impacts of biofuels feedstock production on international 
agricultural and livestock production, we used the integrated Food and 
Agricultural Policy and Research Institute international models, as 
maintained by the Center for Agricultural and Rural Development (FAPRI-
CARD) at Iowa State University.
    One of the main comments we received on our choice of models was 
the issue of transparency. Several comments were concerned that the 
results of EPA's modeling efforts can not be duplicated outside the 
experts who developed the models and conducted the analysis used by EPA 
in the proposal. Upon the release of the proposal, EPA requested 
comment on the use of these various models. EPA conducted a number of 
measures to gather comments, including the public comment period upon 
release of the NPRM analysis, holding a public workshop on the 
lifecycle methodology, and conducting a peer review of the lifecycle 
methodology. Specifically, one of the major tasks of the peer review of 
EPA's lifecycle GHG methodology was to review and comment on the use of 
the various models and their linkages. The response we received through 
the peer review is supportive of our use of the FASOM and FAPRI-CARD 
models, affirming that they are the strong and appropriate tools for 
the task of estimating land use changes stemming from agricultural 
economic impacts due to changes in biofuel policy.
    In addition, in an effort to garner as useful comments as possible 
and to be as transparent as possible about the modeling process, EPA 
supplied in the docket technical documents for the FASOM and FAPRI-CARD 
models, the output received by EPA from each model, and the models 
themselves such that the public and commenters could learn and examine 
how each model operates.
    Building upon the support for the use of the FASOM and FAPRI-CARD 
models, a number of important enhancements were made to both models in 
response to comments received through the public comment system and 
through the peer review, and in consultation with various experts on 
domestic and international agronomics. These enhancements include 
updated substitution rates of corn and soybean meal for distillers 
grains (DG) based on recent scientific research by Argonne National 
Laboratory, the addition of a corn oil from the dry mill ethanol 
extraction process as a source of biodiesel, the full incorporation of 
FASOM's forestry model that dynamically interacts with the agriculture 
sector model in the U.S., as well as the addition of a Brazil regional 
model to the FAPRI-CARD modeling system. All of these enhancements are 
discussed in more detail below and in the RIA (Chapter 2 and 5). In 
addition to the model enhancements we also conducted a sensitivity 
analysis on yields as part of our final rule analysis. These updates to 
our modeling and the sensitivity analysis was done in response to 
public comments specifically asking for this to add transparency to the 
modeling and modeling results.
    We also received comments on the combined use of FASOM and FAPRI-
CARD. Several comments and peer reviewers questioned the benefit of 
using two agricultural sector models. Specifically reviewers pointed to 
some of the inconsistencies in the FASOM and FAPRI-CARD domestic 
results. For the final rule analysis we worked to reconcile the two 
model results. We apply the same set of scenarios and key input 
assumptions in both models. For example, both models were updated to 
apply consistent treatment of DGs in domestic livestock feed 
replacement and consistent assumptions regarding DG export.
    Some reviewers questioned the benefits of using FASOM and suggested 
we rely entirely on the FAPRI-CARD model for the analysis. However, we 
continue to believe there are benefits to the use of FASOM. 
Specifically, the fact that FASOM has domestic land use change 
interactions between crop, pasture, and forest integrated into the 
modeling is an advantage over using the domestic FAPRI-CARD model that 
only tracks cropland.
c. Scenarios Modeled
    As was done for the proposal, 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 volume scenarios in our economic models. 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 sectors of the economy in response to a given volume change in 
the amount of biofuel produced.
    Volume Scenarios: The two future scenarios considered included 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 scenario assumed a higher 
volume of renewable fuels as mandated by EISA for 2022.
    We project our analysis and economic modeling through the life of 
the program. We then consider the impacts of an increase of biofuels on 
the agricultural sector in 2022 as the basis for our threshold 
analysis. This was an area that we received numerous comments on 
highlighting that this approach adds uncertainty to our results because 
we are projecting uncertain technology and other changes out into the 
future. One of the recommendations was to base the lifecycle GHG 
assessments on a near term time frame and update the analysis every few 
years to capture actual technology changes.
    We continue to focus our final rule analyses on 2022 results for 
two main 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

[[Page 14769]]

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. This also allows for the complete implementation of 
technology changes and updates that were made to improve or modeling 
efforts. For example, the inclusion of price induced yield increases 
and the efficiency gains of DGs replacement are phased in over time. 
Furthermore, these changes are in part driven by the changes in earlier 
years of increased biofuel use.
    Crop Yield Scenarios: EPA received numerous comments to the effect 
that we should consider a case in our economic models with higher 
yields that what were projected for the proposed rule analysis. There 
are many factors that go into the economic modeling but the yield 
assumptions for different crops has one of the biggest impacts on land 
use and land use change. Therefore, for this analysis we ran a base 
yield case and a high yield case. This will provide two distinct model 
results for key parameters like total amount of land converted by crop 
by country.
    EPA's base yield projections are derived from extrapolating through 
2022 long-term historical U.S. corn yields from 1985 to 2009. This 
estimate, 183 bushels/acre for corn and 48 bushels/acre for soybeans, 
is consistent with USDA's method of projecting future crop yields. 
During the public comment process we learned that numerous technical 
advancements-- including better farm practices, seed hybridization and 
genetic modification--have led to more rapid gains in yields since 
1995. In addition, commenters, including many leading seed companies, 
provided data supporting more rapid improvements in future yields. For 
example, commenters pointed to recent advancements in seed development 
(including genetic modification) and the general accumulation of 
knowledge of how to develop and bring to market seed varieties--factors 
that would allow for a greater rate of development of seed varieties 
requiring fewer inputs such as fertilizer and pest management 
applications. This new information would suggest that the base yield 
may be a conservative estimate of future yields in the U.S. Therefore, 
in coordination with USDA experts, EPA has developed for this final 
rule a high yield case scenario of 230 bushels/acre for corn and 60 
bushels/acre for soybeans. These figures represent the 99% upper bound 
confidence limit of variability in historical U.S. yields. This high 
yield case represents a feasible high yield scenario for the purpose of 
a sensitivity test of the impact on the results of higher yields.
    Feedback we received indicated that corn and soybean yields respond 
in tandem and that a high yield corn case would also imply a higher 
yield for soybeans as well. The high yield case is therefore based on 
higher yield corn and soybeans in the U.S. as well as in the major corn 
and soybean producing countries around the world. For international 
yields, it is reasonable to assume the same percent increases from the 
baseline yield assumptions could occur as we are estimating for the 
U.S. Thus in the case of corn, 230 bushels per acre is approximately 
25% higher than the U.S. baseline yield of 183 bushels per acre in 
2022. This same 25% increase in yield can be expected for the top corn 
producers in the rest of the world by 2022, as justified improvements 
in seed varieties and, perhaps even more so than in the case of the 
U.S., improvements in farming practices which can take more full 
advantage of the seed varieties' potential. For example, seeds can be 
more readily developed to perform well in the particular regions of 
these countries and can be coupled with much improved farming practices 
as farmers move away from historical practices such as saving seeds 
from their crop for use the next year and better understand the 
economic advantages of modern farming practices. So the high yield 
scenarios would not have the same absolute yield values in other 
countries as the U.S. but would have the same percent increase.
    While we modeled a high yield scenario for this analysis we 
continue to rely primarily on the base yield estimates in our 
assessments of different biofuel lifecycle GHG emissions recognizing 
that the base yields could be conservative. The reasons outlined above 
could lead to higher rates of yield growth in the future, however, 
there are mitigating factors that could limit this yield growth or 
potentially cause reductions in yield growth rates. For example, the 
water requirements for both increased corn farming and ethanol 
production could lead to future water constraints that may in some 
regions limit yield growth potential. Furthermore, one of the long term 
impacts of potential global climate change could be a reduction in 
agricultural output of different impacted regions around the world, 
including the U.S. This could also serve to reduce yield growth. As 
with many aspects of this lifecycle modeling, as the science and data 
evolves on crop yields, the Agency will update its factors accordingly.
2. Biofuel Modeling Framework & Methodology for Lifecycle Analysis 
Components
    As discussed above, to account for the direct and indirect 
emissions of biofuel production required the use of agricultural sector 
economic models. The results of these models were combined with other 
data sources to generate lifecycle GHG emissions for the different 
fuels. The basic modeling framework involved the following steps and 
modeling tools.
    To estimate the changes in the domestic agricultural sector we used 
FASOM, developed by Texas A&M University and others. FASOM is a partial 
equilibrium economic model of the U.S. forest and agricultural sectors 
that tracks over 2,000 production possibilities for field crops, 
livestock, and biofuels for private lands in the contiguous United 
States. Because FASOM captures the impacts of all crop production, not 
just biofuel feedstock, we are able to use it to determine secondary 
agricultural sector impacts, such as crop shifting and reduced demand 
due to higher prices.
    The output of the FASOM analysis includes changes in total domestic 
agricultural sector fertilizer and energy use. These are calculated 
based on the inputs required for all the different crops modeled and 
changes in the amounts of the different crops produced due to increased 
biofuel production. FASOM output also includes changes in the number 
and type of livestock produced. These changes are due to the changes in 
animal feed prices and make-up due to the increase in biofuel 
production. The FASOM output changes in fertilizer, energy use, and 
livestock are combined with GHG emission factors from those sources to 
generate biofuel lifecycle impacts. The GHG emission factors for fuel 
and fertilizer production come from the Greenhouse gases, Regulated 
Emissions, and Energy use in Transportation (GREET) spreadsheet 
analysis tool developed by Argonne National Laboratories, and livestock 
GHG emission factors are from IPCC guidance.
    To estimate the domestic impacts of N2O emissions from 
fertilizer application, we used the DAYCENT

[[Page 14770]]

model developed by Colorado State University. 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, and NOX). DAYCENT model 
results for N2O emissions from different crop and land use 
changes were combined with FASOM output to generate overall domestic 
N2O emissions.
    FASOM output also provides changes in total land use required for 
agriculture and land use shifting between crops, and interactions with 
pasture, and forestry. This output is combined with emission factors 
from land use change to generate domestic land use change GHG emissions 
from increased biofuel production.
    To estimate the impacts of biofuels feedstock production on 
international agricultural and livestock production, we used the 
integrated FAPRI-CARD international models, developed by Iowa State 
University. These worldwide agricultural sector economic models capture 
the biological, technical, and economic relationships among key 
variables within a particular commodity and across commodities.
    The output of the FAPRI-CARD model included changes in crop acres 
and livestock production by type by country globally. Unlike FASOM, the 
FAPRI-CARD output did not include changes in fertilizer or energy use 
or have land type interactions built in. These were developed outside 
the FAPRI-CARD model and combined with the FAPRI-CARD output to 
generate GHG emission impacts.
    Crop input data by crop and country was developed and combined with 
the FAPRI-CARD output crop acreage change data to generate overall 
changes in fertilizer and energy use. These fertilizer and energy 
changes along with the FAPRI-CARD output livestock changes were then 
converted to GHG emissions based on the same basic approach used for 
domestic sources, which involves combining with emission factors from 
GREET and IPCC.
    International land use change emissions were determined based on 
combining FAPRI-CARD output of crop acreage change with satellite data 
to determine types of land impacted by the projected crop changes and 
then applying emission factors of different land use conversions to 
generate GHG impacts.
    Additional modeling and data sources used to determine the GHG 
emissions of other stages in the biofuel lifecycle include studies and 
data on the distance and modes of transport needed to ship feedstock 
from the field to the biofuel processing facility and the finished 
biofuel from the facility to end use. These distances and modes are 
used to develop amount and type of energy used for transport which is 
combined with GREET factors to generate GHG emissions. We also 
calculate energy use needed in the biofuel processing facility from 
industry sources, reports, and process modeling. This energy use is 
combined with emissions factors from GREET to develop GHG impacts of 
the biofuel production process
    The following sections outline how the modeling tools and 
methodology discussed above were used in conducting the analysis for 
the different lifecycle stages of biofuel production, including changes 
made since the proposal. Lifecycle stages discussed include feedstock 
production, land use change, feedstock and fuel transport, biofuel 
production, and vehicle end use. The modeling of the petroleum fuels 
baseline is discussed in Section V.B.3.
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).
i. Domestic Agricultural Sector Impacts
    Agricultural Sector Inputs: The proposal analysis calculated GHG 
emissions from domestic agriculture fertilizer and energy use and 
production change by applying rates of energy and fertilizer use by 
crop by region to the FASOM acreage data and then multiplying by 
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.
    In general commenters supported this approach as it captures all 
indirect impacts of agricultural sector emissions and not just those 
associated with the specific biofuel crop in question. However, we did 
receive comments as part of our Model Linkages Peer Review that the 
input data for some crops may be overestimating GHG emissions. 
Specifically, the commenter highlighted that N2O emissions 
from domestic hay production seemed to be over estimated. As part of 
the final rule analysis EPA confirmed that input data was being used 
correctly, however, the hay N2O emissions in the proposal 
may have been overestimated based on the approach used in the proposal 
to generate N2O emissions from nitrogen fixing crops. This 
has been updated for the final rule analysis as discussed in the next 
section which resulted in lower emissions from nitrogen fixing crops.
    Other comments indicated that we should be using the most up to 
date data for our calculations of GHG emissions. Since the proposal 
there has been a new release of the GREET model (Version 1.8C). EPA 
reviewed the new version and concluded that this was an improvement 
over the previous GREET release that was used in the proposal analysis 
(Version 1.8B). Therefore, EPA updated the GHG emission factors for 
fertilizer production used in our analysis to the values from the new 
GREET version. This had the result of slightly increasing the GHG 
emissions associated with fertilizer production and thus slightly 
increasing the GHG emission impacts of domestic agriculture.
    As was the case in the proposal, we held the rates of domestic 
fertilizer application constant over time. This is true for both of our 
yield scenarios considered as well as for price induced yield 
increases. This constant rate of application is justified based on USDA 
data indicating that crops are becoming more efficient in their uptake 
of fertilizer such that higher yields can be achieved based on the same 
per acre fertilizer application rates.
    N2O Emissions: The proposal analysis calculated N2O 
emissions from domestic 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. The proposal analysis 
N2O factors were based on existing DAYCENT modeling that was 
developed using the 1996 IPCC guidance for calculating N2O 
emissions from fertilizer applications and nitrogen fixing crops. We 
identified in the proposal that this was an area we would be updating 
for the final rule based on new analysis from Colorado State University 
using the DAYCENT model. This update was not available at time of 
proposal.
    We received a number of comments on our proposal results indicating 
that the N2O emissions were overestimated from soybean and 
other legume production (e.g., nitrogen fixing hay) in our analysis. 
The main issue is that because the N2O emission factors used 
in the proposal were based on the 1996

[[Page 14771]]

IPCC guidance for N2O accounting they were overestimating 
N2O emissions from nitrogen fixing crops. As an update in 
2006, IPCC guidance was changed such that biological nitrogen fixation 
was removed as a direct source of N2O because of the lack of 
evidence of significant emissions arising from the fixation process 
itself. IPCC concluded that the N2O emissions induced by the 
growth of legume crops/forages may be estimated solely as a function of 
the above-ground and below-ground nitrogen inputs from crop/forage 
residue. This change effectively reduces the N2O emissions 
from nitrogen fixing crops like soybeans and nitrogen fixing hay from 
the 1996 to 2006 IPCC guidance.
    Therefore, as part of the update to new N2O emission 
factors from DAYCENT used for our final rule analysis we have updated 
to the 2006 IPCC guidance which reduces the N2O emissions 
from soybean production. This has the effect of reducing lifecycle GHG 
emissions for soybean biodiesel production. When we model corn 
expansion as would result from increased production of corn-based 
ethanol, one of the impacts is that the increase in corn acres 
displaces some acres otherwise planted to soy beans. Since the GHG 
emissions impact of this change in land use considers the 
N2O emissions benefit from the displaced soy, the result of 
this lower soy bean N2O assessment means that the benefits 
for soy displacement are less, directionally increasing the net GHG 
emissions for corn expansion.
    We also received comments on our approach that we should use IPCC 
factors directly as opposed to relying on DAYCENT modeling. The 
difference is that IPCC provides default factors by crop by country, 
while DAYCENT models N2O emissions by crop but also by 
region within the US, accounting for different soil types and weather 
factors. For the final rule we still rely on the DAYCENT modeling 
results as we believe them to be more accurate. For example, the 
National Greenhouse Gas Inventory as reported annually by the US to the 
Framework Convention on Climate Change uses the DAYCENT model to 
determine N2O emissions from domestic fertilizer use as 
opposed to using default IPCC factors as the DAYCENT modeling is 
recognized to be a more accurate approach.
    Livestock Emissions: GHG emissions from livestock have two main 
sources: enteric fermentation and manure management. For the proposal, 
enteric fermentation methane emissions were determined by applying IPCC 
default factors for different livestock types to herd values as 
calculated by FASOM to get GHG emissions. Comments we received on this 
approach were that the default IPCC factors do not account for the 
beneficial use of distiller grains (DGs) as animal feed. Use of DGs has 
been shown to decrease methane produced from enteric fermentation if 
replacing corn as animal feed. This is due to the fact that the DGs are 
a more efficient feed source. Consistent with our assumptions regarding 
the efficiency of DGs as an animal feed in our agricultural sector 
modeling, we have also included the enteric fermentation methane 
reductions of DGs use in our final rule analysis. The reduction amount 
was based on default factors in GREET that calculated this reduction 
based on the same Argonne report used to determine DGs feed replacement 
efficiency discussed in Section V.B.2.b.i. This resulted in a reduction 
in the lifecycle GHG emissions for corn ethanol compared to the 
proposal assumptions. More detail on the enteric fermentation methane 
reductions of DGs use can be found in Chapter 2 of the RIA.
    The proposal analysis also included the methane and N2O 
emissions of livestock manure management based on IPCC default factors 
for emissions from the different types of livestock and management 
methods combined with FASOM results for livestock changes. We received 
comments that this was a good approach as it quantifies the indirect 
impacts of emissions associated with biofuel production. The same 
approach was used for the final rule analysis.
    Methane from Rice: For the proposal, methane emissions from rice 
production were calculated by taking the FASOM output predicted changes 
in rice acres, resulting from the increase in biofuel production, and 
multiplying by default methane emission factors from IPCC to generate 
GHG impacts. We received comments that this was a good approach as it 
quantifies the indirect impacts of emissions associated with biofuel 
production. The same approach was used for the final rule analysis.
ii. International Agricultural Sector Impacts
    Agricultural Sector Inputs: For the proposal we determined 
international fertilizer and energy use emissions based on applying 
input data collected by the Food and Agriculture Organization (FAO) of 
the United Nations and the International Energy Agency (IEA) to the 
FAPRI-CARD crop output data and then applied GREET defaults for 
converting those inputs to GHG emissions.
    As part of our public comment and peer review process we had this 
component of our analysis specifically peer reviewed. The main comment 
we received was to update our input data with newer data sources. 
Therefore, for the final rule analysis we updated fertilizer and 
pesticide consumption projections from the incorporation of updates 
made by the FAO to its Fertistat and FAOStat datasets, as well as the 
incorporation of more up-to-date fertilizer consumption statistics 
provided by a recent International Fertilizer Institute (IFA) report. 
This update had varying impacts on the amount of fertilizer used on 
different crops in different countries but in general increased the 
amount of fertilizer assumed and thus international agriculture 
lifecycle GHG emissions from fertilizer use for all biofuels.
    Another comment from the peer review was that we should include 
lime use for some of the key crops modeled in our analysis. Lime use 
was not included in the proposal because of lack of international data 
on lime use by crop. Excluding lime used is an underestimate of 
international agriculture GHG emissions. For our final rule analysis we 
included lime use for sugarcane production in Brazil based on 
information received from Brazilian agricultural experts provided as 
part of the comment process. This led to an increase in GHG emissions 
from sugarcane farming. We did not include lime use for other crops in 
the final rule analysis because of lack of other data sources for other 
crops.
    Other comments we received on our approach were that we were 
potentially underestimating GHG emissions from international 
agriculture energy use. Our proposal based international agriculture 
energy use on factors from the International Energy Agency (IEA) that 
included all energy use for agriculture that we divided by all 
agricultural sector land by country to get a GHG emission per acre for 
each country considered. The comment raised the issue that by using all 
agricultural land this includes pasture land that would not have the 
same energy input as crop production. Effectively, higher energy use 
from crop production was getting averaged with lower energy use for 
pasture and then this lower number was applied only to crop production. 
We specifically asked as part of our peer review for guidance and 
comment on our international agriculture energy use calculation. We did 
not receive significant comments or data to suggest that we change our 
approach and reviewers generally

[[Page 14772]]

agreed we were using the best data available. Furthermore, the energy 
use values represent all agriculture including forestry and fishing 
which could in some countries be overestimating energy use for crop 
production. So for our final rule analysis we used the same approach as 
for the proposal to calculate international agriculture energy use GHG 
emissions.
    We also received comments on the applicability of applying GREET 
defaults for fuel and fertilizer production to international fuel and 
fertilizer use to generate GHG emissions. The comments noted that GREET 
factors are developed for domestic US conditions and would not 
necessarily apply internationally. Specifically on the issue of 
nitrogen fertilizer production, the comments indicated that nitrogen 
fertilizer production internationally could rely on coal as a fuel 
source as opposed to natural gas used in the US, which would cause 
international GHG emissions associated with fertilizer production and 
hence biofuel production to be underestimated in our analysis. This was 
also an area we asked peer reviewers for comment and guidance. The peer 
review response generally supported our approach and did not offer 
suggestions for other data sources. So for our final rule analysis we 
used the same approach as for the proposal and applied GREET defaults 
to calculate international fertilizer production GHG emissions.
    As was the case in the proposal and for domestic agriculture, we 
held the rates of international fertilizer application constant over 
time. This is true for both of our yield scenarios considered as well 
as for price induced yield increases. This was an area that was 
specifically addressed in our peer review of International Agricultural 
Greenhouse Gas Emissions and Factors. The reviewers supported the 
approach we have taken, for example indicating that generally crop 
production as a unit of fertilizer application has increased over time, 
therefore, crop yields have increased with the same or lower fertilizer 
applications.
    N2O Emissions: For the proposal we included 
N2O emissions from fertilizer application by applying IPCC 
default factors for different crops in different countries. We use IPCC 
default factors because we do not have the same level of regional 
factors like we do in the US from the DAYCENT model. The IPCC guidance 
has emission factors for four sources of N2O emissions from 
crops, Direct N2O Emissions from Synthetic Fertilizer 
Application, Indirect N2O Emissions from Synthetic 
Fertilizer Application, Direct Emissions from Crop Residues, and 
Indirect Emissions from Crop Residues. The proposal did not include 
N2O emissions from the Direct and Indirect Emissions from 
Crop Residues for cotton, palm oil, rapeseed, sugar beet, sugarcane, or 
sunflower. These were not included for these crops because default 
crop-specific IPCC factors used in the calculation were not available.
    Comments from our peer review process suggested that we include 
proxy emissions from these crops based on similar crop types that do 
have default factors. Therefore, for our final rule analysis we have 
included crop residue N2O emissions from sugarcane 
production based on perennial grass as a proxy. Perennial grass is 
chosen as a proxy based on input from N2O modeling experts. 
This change results in an increase in N2O emissions from 
sugarcane and therefore sugarcane ethanol production compared to the 
proposal.
    Livestock Emissions: Similar to domestic livestock impacts, enteric 
fermentation and manure management GHG emissions were included in our 
proposal analysis. The proposal calculated international livestock GHG 
impacts based on activity data provided by the FAPRI-CARD model (e.g., 
number and type of livestock by country) multiplied by IPCC default 
factors for GHG emissions.
    Based on the peer review of the methodology used for the proposal 
it was determined that the calculations for manure management did not 
include emissions from soil application. These emissions were included 
for our final rule analysis but do not cause a significant change in 
the livestock GHG emission results.
    Rice Emissions: To estimate rice emission impacts internationally, 
the proposal used the FAPRI-CARD model to predict changes in 
international rice production as a result of the increase in biofuels 
demand in the U.S. We then applied IPCC default factors by country to 
these predicted changes in rice acres to generate GHG emissions. We 
received comments that this was a good approach as it quantifies the 
indirect impacts of emissions associated with biofuel production. The 
same approach was used for the final rule analysis.
b. Land Use Change
    The following sections discuss our final rulemaking assessment of 
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. There are four main methodology questions addressed 
both domestically and internationally:
     Amount of Land Converted and Where.
     Type of Land Converted.
     GHG Emissions Associated with Conversion.
     Timeframe of Emission Analysis.
    Each of those methodology components are discussed as are the 
comments we received as part of the comment and peer review process. We 
also outline in addition to our main FASOM and FAPRI-CARD approach a 
general equilibrium modeling approaches and its results.
i. Amount of Land Area Converted and Where
    Based on a number of modeling changes made to the FASOM and FAPRI-
CARD models since the NPRM, the amount of land use change resulting 
from an increase in biofuel demand in the U.S. is significantly lower 
in this FRM analysis for most renewable fuels. Many of the changes made 
were a direct result of comments received through the notice-and-
comment period, comments received from the peer-reviewers, or as a 
result of incorporating new science that has become available since the 
analysis was conducted in the proposal. Some of the key changes that 
had the largest impact on the land use change estimates are included in 
this section. For additional information, see Chapter 2 of the RIA.
    As discussed in the NPRM, one of the key factors in determining the 
amount of new land needed to meet an increase in biofuel demand is the 
treatment of co-products of ethanol and biodiesel production. We 
received many comments on this topic, particularly on the amount of 
corn and soybean meal a pound of DGS, the byproduct of dry mill grain 
ethanol production, can replace in animal feed. For the final rule, we 
predict that distiller grains will be absorbed by livestock more 
efficiently over time. We updated the displacement rate assumptions in 
the FASOM and FAPRI-CARD models based on comments we received and on 
the recent research conducted by Argonne National Laboratory and 
others.\167\ According to this research, one pound of DGS replaces more 
than a pound of corn and/or soybean meal in beef and dairy rations, in 
part because cattle fed DGS show faster weight gain and increased milk 
production compared to those fed a traditional diet. While this

[[Page 14773]]

study represents a significant increase over current DGS replacement 
rates, we believe it is reasonable to assume that improvements will be 
made in the use and efficiency of DGS over time as the DGS market 
matures, the quality and consistency of DGS improves, and as livestock 
producers learn to optimize DGS feed rations. As a result of this 
modification, less land is needed to replace the amount of corn 
diverted to ethanol production. Additional details on the DGS 
assumptions are included in Chapters 2 and 5 of the RIA.
---------------------------------------------------------------------------

    \167\ Salil, A., M. Wu, and M. Wang. 2008. ``Update of 
Distillers Grains Replacement Ratios for Corn Ethanol Life-Cycle 
Analysis.'' Available at http://www.transportation.anl.gov/pdfs/AF/527.pdf.
---------------------------------------------------------------------------

    A second factor that can have a significant impact on the amount of 
land that may be converted as a result of increasing biofuel demand are 
changes in crop yields over time. As discussed in the NPRM, our 
proposal based domestic yields on USDA projections for both the 
reference case and the control case. As discussed in Section V.B.1.c, 
for this FRM we have also included scenarios that use higher yield 
projections in both the reference case and the control case. However, 
in the NPRM we also requested comment on whether the higher prices 
caused by an increased in demand for biofuels would increase future 
yield projections in the policy case beyond the yield trends in the 
reference case (sometimes referred to as ``price induced yields''), or 
whether these price induced yields would be offset by the reduction in 
yields associated with expanding production onto new marginal acres 
(sometimes referred to as extensification). Based on the comments we 
received, along with additional historical trend analysis conducted by 
FAPRI-CARD, the international agricultural modeling framework now 
incorporates a price induced yield component.\168\ The new yield 
adjustments are partially offset by the extensification factor, 
however, the combined impact is that fewer new acres are needed for 
agricultural production to meet world agricultural demands.
---------------------------------------------------------------------------

    \168\ Technical Report: An Analysis of EPA Renewable Fuel 
Scenarios with the FAPRI-CARD International Models, CARD Staff, 
January, 2010.
---------------------------------------------------------------------------

    One additional change we made to the yield assumptions was to 
update the FASOM model with new analysis by Pacific Northwest National 
Laboratories (PNNL) on switchgrass yields.\169\ We included this new 
data for two reasons. First, we received several comments that our 
assumptions on switchgrass yields were too low, based on more recent 
field work. In addition, for out NPRM analysis, we did not have data 
for switchgrass yields in certain regions of the US. Therefore, the 
PNNL data helped to fill a pre-existing data gap. As a result of these 
updates, less land is needed per gallon of switchgrass ethanol 
produced. Additional details on switchgrass yields and other 
agricultural sector modeling assumptions are included in RIA Chapter 5.
---------------------------------------------------------------------------

    \169\ Thomson, A.M., R.C. Izarrualde, T.O. West, D.J. Parrish, 
D.D. Tyler, and J.R. Williams. 2009. Simulating Potential 
Switchgrass Production in the United States. PNNL-19072. College 
Park, MD: Pacific Northwest National Laboratory.
---------------------------------------------------------------------------

    One of the major changes made to the FAPRI-CARD model between the 
NPRM and FRM includes the more detailed representation of Brazil 
through a new integrated module. The Brazil module was developed by 
Iowa State with input from Brazilian agricultural sector experts and we 
believe it is an improvement over the approach used in the proposal. In 
the NPRM, we requested additional data for countries outside the U.S. 
We received comments encouraging us to use regional and country 
specific data where it was available. We also received comments 
encouraging us to take into account the available supply of abandoned 
pastureland in Brazil as a potential source of new crop land. The new 
Brazil module addresses these comments. Since the Brazil module 
contains data specific to six regions, this additional level of details 
allows FAPRI-CARD to more accurately capture real-world responses to 
higher agricultural prices. For example, double cropping (the practice 
of planting a winter crop of corn or wheat on existing crop acres) is a 
common practice in Brazil. Increased double cropping is feasible in 
response to higher agricultural prices, which increases total 
production without increasing land use conversion. The new Brazil 
module also explicitly accounts for changes in pasture acres, therefore 
accounting for the competition between crop and pasture acres. 
Furthermore, the Brazil module explicitly models livestock 
intensification, the practice of increasing the number of heads of 
cattle per acre of land in response to higher commodity prices or 
increased demand for land.
    In addition to modifying how pasture acres are treated in Brazil, 
we also improved the methodology for calculating pasture acreage 
changes in other countries. We received several comments through the 
public comment period and peer reviewers supporting a better analysis 
of the interaction between crops, pasture, and livestock. In the NPRM, 
although we accounted for GHG emissions from livestock production 
(e.g., manure management), we did not explicitly account for GHG 
emissions from changes in pasture demand. In response to comments 
received, our new methodology accounts for changes in pasture area 
resulting from livestock fluctuations and therefore captures the link 
between livestock and land used for grazing. Based on regional pasture 
stocking rates (livestock per acre), we now calculate the amount of 
land used for livestock grazing. The regional stocking rates were 
determined with data on livestock populations from the UN Food and 
Agricultural Organization (FAO) and data on pasture area measured with 
agricultural inventory and satellite-derived land cover data. As a 
result of this change, in countries where livestock numbers decrease, 
less land is needed for pasture. Therefore, unneeded pasture acres are 
available for crop land or allowed to revert to their natural state. In 
countries where livestock numbers increase, more land is needed for 
pasture, which can be added on abandoned cropland or unused grassland, 
or it can result in deforestation. We believe this new methodology 
provides a more realistic assessment of land use changes, especially in 
regions where livestock populations are changing significantly. For 
additional information on the pasture replacement methodology, see RIA 
Chapter 2.
    Although the total amount of land use conversion is lower in the 
FRM analysis compared to the NPRM analysis, the regional distribution 
of this land use change has shifted. Due to the many changes made in 
response to comments associated with agriculture and livestock markets, 
Brazil is now much more responsive to changes in world biofuel and 
agricultural product demand. As a result, a larger portion of the 
projected land use change occurs in Brazil compared to the NPRM 
analysis. Additional details on the geographical location of land use 
change are included in Chapter 2 of the RIA.
ii. Type of Land Converted
    Based on a number of improvements in our analysis, the types of 
land affected by biofuel-induced tend to be less carbon intensive 
compared to the NPRM. Therefore, the net effect of our revisions to 
this part of our analysis significantly reduced land use change GHG 
emissions. The updated FAPRI-CARD Brazil model, discussed in the 
previous section, showed more pasture expansion in the Amazon which 
increased land use change emissions. However, the most important 
revisions to this part of our international analysis, in terms of their 
net effect on GHG emissions, were improvements that we made in our 
modeling of the

[[Page 14774]]

interactions between livestock, pasture, crops and unused, or 
underutilized, grasslands globally. In the NPRM we made the broad 
assumption that international crop expansion would necessarily displace 
pasture, which would require an equivalent amount of pasture to expand 
into forests and shrublands. In the FRM analysis as discussed in the 
previous section, we have linked international changes in livestock 
production with changes in pasture area to allow for pasture 
abandonment in regions where livestock production decreases as a result 
of biofuel production. We also incorporated the ability of pasture to 
expand onto unused, or underutilized, grasslands and savannas which on 
a global basis reduced the amount of forest conversion compared to the 
proposal. These revisions, as well as a quantitative uncertainty 
assessment, are discussed in this section.
    In the same way that the amount and location of land use change is 
important, the type of land converted is also a critical determinant of 
the magnitude of the GHG emissions impacts associated with biofuel 
production. For example, the conversion of rainforest to agriculture 
results in a much larger GHG release than conversion of grassland. In 
the proposed rule analysis we used two approaches, based on the best 
available information to us at the time, to evaluate the types of land 
that would be affected domestically and internationally. Domestically, 
we used the FASOM model, which simulates rental rates for different 
types of land (e.g., forest, pasture, crop) and chooses the land uses 
that would produce the highest net returns. Internationally, we used 
the FAPRI-CARD/Winrock analysis whereby historical land conversion 
trends, as evaluated with satellite imagery, are used to determine what 
types of land are affected by agricultural land use changes in each 
country or sub-region.
    In the proposed rule we also explained several other options to 
determine what types of land will be affected by biofuel-induced land 
use changes, such as the use of general equilibrium models. EPA 
specifically sought expert peer review input and public comment on our 
approach and all of the analytical options for this part of the 
lifecycle assessment. The expert peer reviewers agreed that EPA's 
approach was scientifically justifiable, but they highlighted 
problematic areas and suggested important revisions to improve our 
analysis. The public comments received on this issue expressed a wide 
range of views regarding EPA's approach. In general, the commenters 
that objected to our analytical approach raised similar concerns as the 
peer reviewers, such as the need for more data validation and 
uncertainty assessment. As discussed below, we made significant 
improvements to our analysis based on the recommendations and comments 
we received. Based on the peer reviewers agreement that our general 
approach is scientifically justifiable, and in light of the significant 
improvements made, we think that our approach represents the best 
available analysis of the types of land affected by biofuel-induced 
land use changes. We did consider a range of other analytical options, 
but based on all of the information considered and the requirements for 
this analysis, we did not find any alternative approaches that are 
superior at this time. As part of periodic updates to the lifecycle 
analysis, we will continue to consider ways to improve this part of our 
analysis, as well as the merits of alternate approaches.
    Domestic: In response to comments received, we made two major 
improvements to the FASOM model for the final rulemaking. As discussed 
in the NPRM and supported by comments, we were able to include the 
forestry sector into the FASOM analysis. Only the agricultural sector 
of FASOM was analyzed for the NPRM, due to the fact that the forestry 
sector component was undergoing model modifications. For this FRM 
analysis, we were able to use the fully integrated forestry and 
agricultural sector model, thereby capturing the interaction between 
agricultural land and forests in the U.S. In addition, the inclusion of 
the forestry model allows us to explicitly model the land use change 
impacts of the competing demand for cellulosic ethanol from 
agricultural sources with cellulosic ethanol from logging and mill 
residues. As a result of this modification, the FRM analysis includes 
some land use conversion from forests into agriculture in the U.S. as a 
result of the increased demand for renewable fuels.
    The second major modification we made in response to comments was 
the disaggregation of different types of land included in FASOM. In the 
proposed rulemaking, the FASOM model included three major categories of 
land: cropland, pasture, and acres enrolled in the Conservation Reserve 
Program (CRP). Although this categorization allowed for a detailed 
regional analysis of land used to grow crops, acres used for livestock 
production were not fully captured. We received comments requesting a 
more detailed breakdown of land types in order to capture the 
interaction between livestock, pasture, and cropland. Therefore, the 
FASOM model now includes rangeland, pasture and forest land that can be 
used for grazing. Since we also received comments that we should take 
into account the potential for idle land to be used for other purposes 
such as the production of cellulosic ethanol, FASOM now accounts for 
the amount of land within each category that is either idle or used for 
production.
    These two major modifications to the FASOM model now allow us to 
explicitly track land transfers between various land categories in the 
U.S. As a result, we can more accurately capture the GHG impacts of 
different types of land use changes domestically. More detail and 
results of the FASOM model can be found in Section V.B.1.b of the 
preamble.
    International: The proposed rule included a detailed description of 
the FAPRI-CARD/Winrock approach used to determine the type of land 
affected internationally. This approach uses satellite data depicting 
recent land conversion trends in conjunction with economic projections 
from the FAPRI-CARD model (an economic model of global agricultural 
markets) to determine the type of land converted internationally. In 
the proposed rule we described areas of uncertainty in this approach, 
illustrated the uncertainty with sensitivity analyses, and discussed 
other potential approaches for this analysis. To encourage expert and 
stakeholder feedback, EPA specifically invited comment on this issue, 
held public hearings and workshops, and sponsored an independent peer-
review, all of which specifically highlighted this part of our analysis 
for feedback. While there were a wide range of views expressed in these 
forums, the feedback received by the Agency generally supported the 
FAPRI-CARD/Winrock approach as appropriate for this analysis. For 
example, all five experts that peer reviewed EPA's use of satellite 
imagery agreed that it is scientifically justifiable to use historic 
remote sensing data in conjunction with agricultural sector models to 
evaluate and project land use change emissions associated with biofuel 
production. Additionally, the peer reviewers and public commenters 
highlighted problematic areas and suggested revisions to improve our 
analysis. Below, we describe the key revisions that were implemented 
which have significantly improved our analysis based on the feedback 
received.
    FAPRI-CARD/Satellite Data Approach: As described above in

[[Page 14775]]

Section V.B.1.b, the FAPRI-CARD model was used to determine the amount 
of land use change in each country/region in response to increased 
biofuel production. Because the FAPRI-CARD model does not provide 
information about what type of land is converted to crop production or 
pasture, we worked with Winrock International to evaluate the types of 
land that would be affected internationally. Winrock is a global 
nonprofit organization with years of experience in the development and 
application of the IPCC agricultural forestry and other land use 
(AFOLU) guidance. For the proposed rule, we used satellite data from 
2001-2004 to provide a breakdown of the types of land converted to crop 
production. A key strength of this approach is that satellite 
information is based on empirical observations which can be verified 
and statistically tested for accuracy. Furthermore, it is reasonable to 
assume that recent land use change decisions have been driven largely 
by economics, and, as such, recent patterns will continue in the 
future, absent major economic or land use regime shifts caused, for 
example, by changes in government policies.
    As discussed above, all five of the expert peer reviewers that 
reviewed our use of satellite imagery for this analysis agreed that our 
general approach was scientifically justifiable. However, all of the 
peer reviewers qualified that statement by describing relevant 
uncertainties and highlighting revisions that would improve our 
analysis. Some of the public commenters supported EPA's use of 
satellite imagery, while other expressed concern. In general, both sets 
of public commenters--those in favor and opposed--outlined the same 
criticisms and suggestions as the expert peer reviewers. Among the many 
valuable suggestions for satellite data analysis provided in the expert 
peer reviews and public comments, several major recommendations 
emerged: EPA should use the most recent satellite data set that covers 
a period of at least 5 years; EPA should use higher resolution 
satellite imagery; EPA's analysis should consider a wider range of land 
categories; EPA should improve it's analysis of the interaction between 
cropland, pasture and unused or underutilized land; and EPA's analysis 
should include thorough data validation and a full assessment of 
uncertainty. Below, we describe these and other recommendations and how 
we addressed each of them to improve our analysis. Based on the peer 
reviewers agreement that our general approach is scientifically 
justifiable, and in light of the significant improvements made, we 
think that our approach represents the best available analysis of the 
types of land affected internationally.
    One of the fundamental improvements in this analysis since the 
proposed rule is that it now provides global coverage. The analysis for 
the proposed rule included satellite imagery for 6 land categories in 
314 regions across 35 of the most important countries, with a weighted 
average applied to the rest of the world. We have since completed a 
global satellite data analysis including 9 land categories in over 750 
distinct regions across 160 countries. This was an analytical 
improvement that we committed to do in the proposed rule. As described 
below, the other major analytical enhancements were conducted in 
response to the many technical recommendations that we received as part 
of the peer review and public comment process.
    All of the expert peer reviewers agreed that the version 4 MODIS 
data set used in the proposed rule, which covers 2001-2004 with one 
square-kilometer (1km) spatial resolution, was appropriate for our 
analysis given the goals of the study at the time. However, almost all 
of the reviewers strongly recommended using a data set covering a 
longer time period. The reviewers argued that the 3-year time period 
from 2001-2004 was too short to capture the often gradual, or 
sequential, cropland expansion that has been observed in the tropics. 
The short time period may also show unusual or temporary trends in land 
use caused by short-term policy changes or market influences. The 
reviewers suggested that remote sensing observations covering 5-10 
years would be adequate to address these problems. The reviewers also 
recommended that remote sensing observations should be as recent as 
possible in order to capture current land use change drivers and 
patterns (e.g., political systems, infrastructure, and protected 
areas). To use the best available data and respond to the peer 
reviewers' recommendations, the analysis was updated to include the 
most recent MODIS data set, version 5, which covers the time period 
2001-2007. MODIS land cover products are not available for years prior 
to 2001, so it is not currently possible to analyze a time period 
longer than six years (i.e., 2001-2007) with a single, or consistent, 
data set. Thus, consistent with the peer review recommendations, we are 
now using the most recent global data set which covers at least 5 
years. There are other advantages to using the version 5 MODIS data, 
such as improved spatial resolution, and robust data validation, which 
are discussed below.
    There was strong agreement among the peer reviewers that higher 
resolution satellite imagery would be an important improvement over the 
1-km resolution data used in the proposed rule analysis. Higher spatial 
resolution is especially useful in categorizing highly fragmented 
landscapes. One of the reviewers hypothesized that land use change 
driven by biofuel production would likely involve large parcels of 
land, and thus 1-km resolution may be sufficient. However, all of the 
reviewers agreed that higher resolution data would be preferable. A 
number of the peer reviewers specifically said that the version 5 MODIS 
data set, with 500 meter resolution, would be adequate. With four-times 
higher spatial resolution than version 4, the peer reviewers 
anticipated that the 500m imagery would classify less area of ``mixed 
class'' land, thus providing a more detailed representation of the land 
in that category. Consistent with the peer reviewer's recommendations 
and with our goal to use the best available information, our analysis 
was updated with the higher resolution version 5 MODIS data.
    Related to the issue of spatial resolution, the peer review experts 
were asked whether they would recommend augmenting our global analysis 
with even higher resolution data for specific regions where there is a 
high degree of agricultural land use change. All of the peer reviews 
agreed that this type of analysis would be worthwhile. In response to 
this recommendation, we analyzed select geographic regions (e.g., 
Brazil, India) with the higher resolution 30m Landsat data set covering 
2000-2005. The Landsat data set does not currently provide global 
coverage, thus it was not an option for use in the full analysis; 
instead, it was used as a way to check/validate the appropriateness of 
the version 5 MODIS imagery. In general, the higher resolution data 
showed similar land use change patterns as the MODIS data. The results 
of this analysis are discussed further in Chapter 2 of the RIA.
    Another issue that we invited comments on was the re-classification 
of the MODIS data from 17 land cover categories into 6 aggregated 
categories (e.g., open and closed shrubland were both re-classified as 
shrubland). The category aggregation was intended to remove unnecessary 
complexity from the analysis. All five expert reviewers agreed that the 
methodology used to re-classify land cover categories using 
International Geosphere-Biosphere Programme (IGBP) land definitions was

[[Page 14776]]

sound; however, the reviewers recommended inclusion of more than 6 
aggregated land categories. The reviewers specifically recommended the 
addition cropland/natural vegetation mosaic, permanent wetlands, and 
barren or sparsely vegetated land, all of which are now included in our 
analysis. Consistent with these recommendations, there are 9 aggregate 
land categories in our revised analysis: barren, cropland, excluded 
(e.g., urban, ice, water bodies), forest, grassland, mixed (i.e., 
cropland/natural vegetation mosaic), savanna, shrubland and wetland. 
These land cover categories capture all significant types of land 
affected by agricultural land use changes. As described below in 
Section V.B.2.b.iii, we also estimated carbon sequestrations for all of 
these land categories. The impact of adding these land categories to 
our analysis is discussed further in RIA Chapter 2.
    Another important addition to our analysis was consideration of the 
types of land affected by changes in pasture area, and the interaction 
of pasture land with cropland. In the proposed rule, we made a broad 
assumption that the total land area used for pasture would stay the 
same in each country or region. Thus, in the proposed rule, we assumed 
that any crop expansion onto pasture would necessarily require an equal 
amount of pasture to be replaced on forest or shrubland. We received a 
large number of comments questioning these assumptions, and the expert 
peer reviewers encouraged us to develop a better representation of the 
interactions between cropland and pasture land. As described above in 
Section V.B.2.6.i, the results from the FAPRI-CARD model are now used 
to determine pasture area changes in each country or region. In regions 
where we project that pasture and crop area both increase, the land 
types affected by pasture expansion are determined using the same 
analysis used for crop expansion. This new approach accounts for the 
ability of pasture to expand on to previously unused, or underutilized, 
grasslands and savanna. In regions where we project that crop and 
pasture area will change in opposite directions (e.g., crop area 
increases and pasture decreases) we assume that crops will expand onto 
abandoned pasture, and vice versa. Our analysis also now accounts for 
carbon sequestration resulting from crop or pasture abandonment. We 
used our satellite analysis, which shows the dominant ecosystems and 
land cover types in each region, to determine which types of ecosystems 
would grow back on abandoned agricultural lands in each region. More 
information about our analysis of pasture and abandoned agricultural 
land are provided in RIA Chapter 2.
    A sub-set of the expert peer reviewers recommended combining the 
historic satellite imagery with other information on land use change 
drivers (e.g., transportation infrastructure, poverty rates, 
opportunity costs) as an additional means to estimate the types of land 
affected. Consideration of these types of information could potentially 
address two conceptual issues with the use of satellite imagery in this 
analysis: First, biofuel-induced land use change could affect different 
types of land than the generic agricultural expansion captured by the 
historic data; and second, future land use change patterns may differ 
from historic patterns. Our concerns with the first issue are allayed 
to some degree by one of the peer reviewers who observed, ``While it is 
theoretically possible that the changes in land use resulting from 
biofuel production occur in ecosystems or regions that would not be the 
ones affected by other drivers, this doesn't appear very likely.'' 
\170\ Furthermore, the economic drivers of land use change are to a 
large degree captured by the economic models that are used in our 
analysis. For example, the FAPRI-CARD model considers economic drivers 
in its projections of where and how much crop production will change as 
a result of specifically biofuel-induced changes. The second issue is 
also addressed to some degree by the FAPRI-CARD model which includes 
baseline forecasts of future international agricultural, economic and 
demographic conditions. Furthermore, as discussed above, we used the 
most recently available satellite data sets in order to capture the 
most current land use change drivers. Thus, while we think that these 
issues are currently addressed to a scientifically justifiable degree 
for the purposes of this analysis, we recognize that these are areas 
for future investigation, and we have tried to capture the uncertainty 
from these factors in uncertainty and sensitivity analyses as described 
below.
---------------------------------------------------------------------------

    \170\ Peer Review Report, Emissions from Land Use Change due to 
Increased Biofuel Production: Satellite Imagery and Emissions Factor 
Analysis, July 31, 2009, p. 2.
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    While EPA has made significant improvements to the methodology in 
response to peer review comments, the use of satellite data for 
forecasting land use changes is a key area of uncertainty in the 
analysis. To facilitate substantive comments on the impact of 
uncertainty in international land use changes, and how to address the 
uncertainty, the proposed rule highlighted areas of uncertainty and 
included multiple sensitivity analyses. For example, we presented a 
range of lifecycle results assuming at the high-end that all land 
conversion caused deforestation and at the low-end that biofuels would 
cause no deforestation. Further, EPA sought input on this issue in 
public hearings and workshops, and expert feedback through the 
independent peer review. The feedback we received, both from experts 
and the public, overwhelmingly supported a more systematic analysis of 
the uncertainty in using satellite data to project biofuel-induced land 
use change patterns. Additionally, commenters recommended more data 
validation, especially regarding the satellite imagery. To respond to 
these comments, we incorporated satellite imagery validation and 
conducted a Monte Carlo analysis of the MODIS satellite data using 
assessments provided by NASA to quantitatively evaluate the uncertainty 
in our application of satellite imagery.
    One benefit of using the MODIS data set is that it is routinely and 
extensively validated by NASA's MODIS land validation team. NASA uses 
several validation techniques for quality assurance and to develop 
uncertainty information for its products. NASA's primary validation 
technique includes comparing the satellite classifications to data 
collected through field and aircraft surveys, and other satellite data 
sensors. The accuracy of the version 5 MODIS land cover product was 
assessed over a significant set of international locations, including 
roughly 1,900 sample site clusters covering close to 150 million square 
kilometers. The results of these validation efforts are summarized in a 
``confusion matrix'' which compares the satellite's land 
classifications with the actual land types observed on the ground. We 
used this information to assess the accuracy and systematic biases in 
the published MODIS data. In general, the validation process found that 
MODIS version 5 was quite accurate at distinguishing forest from 
cropland or grassland. However, the satellite was more likely; for 
example, to confuse savanna and shrubland because these land types can 
look quite similar from space.
    Using the data validation information from NASA about which types 
of land MODIS tends to confuse which each other, our Monte Carlo 
analysis was able to account for systematic misclassifications in the 
MODIS data set. Therefore, part of the Monte Carlo analysis can be 
viewed as a way to correct and reduce the inaccuracies in the MODIS 
data. After this correction is performed, the uncertainty in the 
satellite data is no longer solely a

[[Page 14777]]

function of the accuracy of the satellite. Instead, the sizes of the 
standard errors for each classification are also a function of the 
sample sizes in the data validation exercise. For example, if NASA 
validated every pixel on Earth, the corrected data set would be 100% 
accurate, even if the original satellite data were only 50% accurate. 
Similarly, although NASA reports that the overall accuracy of the MODIS 
version 5 land cover data set is approximately 75%, the standard errors 
after the Monte Carlo procedure are less than 5% for each aggregate 
land category. These standard errors were used to quantify the 
uncertainty added by the satellite data used in our analysis. This 
procedure and the results are described in more detail in Chapter 2 of 
the RIA.
    It should be noted that our assessment of satellite data 
uncertainty did not try to fully quantify the uncertainty of using 
historical data to make future projections about the types of land that 
would be affected internationally. As noted above, we think it is 
reasonable to assume that in general, recent land use change patterns 
will continue in the future absent major economic or land use regime 
shifts caused, for example, by changes in government policies. Thus, 
our uncertainty assessment provides a reasonable estimate of the 
variability in land use change patterns absent any fundamental shifts 
in the factors that affect land use patterns. However, our uncertainty 
assessment does not attempt to fully quantify the probability of major 
shifts in land use regimes, such as the implementation of effective 
international policies to curb deforestation.
    Some of the peer reviewers recommended a satellite imagery analysis 
approach known as change detection, instead of the ``differencing'' 
approach used in the Winrock analysis. However, there was disagreement 
among the peer reviewers on this point, with one peer reviewer saying 
that thematic differencing between land cover maps generated for two 
specific dates, as conducted in this study, provides the best approach 
for detecting and analyzing land use pattern changes globally. In 
general terms, the differencing method employed by Winrock compared 
global land cover maps from 2001 and 2007 to evaluate the pattern of 
land use change during this period. Thus, the differencing method shows 
all of the land that changed categories, as well as all of the land 
that stayed the same over this period. For change detection, instead of 
using comprehensive land cover maps, the data set only shows land 
categories that changed. One advantage of change detection is that it 
is better suited to capture the sequential nature of land use changes, 
e.g., a forest could be converted to savanna, then grassland and then 
cropland. The differencing method that we employed lends itself more 
readily to comprehensive global analysis, data validation, and 
uncertainty assessment. Given the timeframe and priorities for our 
analysis, we think that the differencing method provides the best 
approach available at this time. However, we will continue to consider 
alternative analytical techniques, such as change detection, for use as 
part of periodic updates to this analysis.
    Some of the peer reviewers recommended additional alternative 
technical approaches for satellite data and land use change analysis. 
For example, some of the reviewers recommended the use of satellite 
imagery to identify specific crop-types and rotations, and one reviewer 
suggested that EPA develop a new interactive spatial model. The Summary 
and Analysis of Comments document includes discussion of these and 
other technical comments and recommendations that are not covered here.
iii. GHG Emissions Associated With Conversion
(1) Domestic Emissions
    GHG emissions impacts due to domestic land use change are based on 
GHG emissions the FASOM model generates in association with land type 
conversions projected in the model. In the proposed rule analysis, 
estimates of land use change emissions were limited to conversion 
between different types of agricultural land (e.g., cropland, fallow 
cropland, pasture). The analysis did not allow for the addition of new 
domestic agricultural land.
    In response to feedback EPA received during the public comment 
period and based on commitments EPA made in the NPRM, several changes 
and additions have augmented the analysis of domestic land use change 
GHG emissions since the proposed rule analysis. The addition of the 
forest land types and the interaction between cropland, pastureland, 
forestland, and developed land to the FASOM model provides a more 
complete emissions profile due to domestic land use change (see Section 
V.B.4.b.ii). We have updated soil carbon accounting based on new 
available data. Lastly, the methodology now captures GHG emission 
streams over time associated with discrete land use changes.
    For agricultural soils, FASOM models GHG emissions associated with 
changes in crop production acreage and with changes in crop type 
produced. FASOM generates soil carbon factors for cropland and pasture 
according to IPCC Agriculture, Forestry, and Other Land Use (AFOLU) 
Guidelines. In the proposed rule, we committed to updating FASOM soil 
carbon accounting for agriculture. Per our commitment, we have updated 
FASOM soil carbon accounting for cropland and pasture using the latest 
DAYCENT modeling from Colorado State University.
    In the proposed rule, EPA committed to incorporate the forestry 
sector and the GHG emission impacts due to the land use interactions 
between the domestic agricultural and forestry sectors into the FASOM 
analysis. We received comment supporting the incorporation of the 
forestry sector. By including the forestry sector in the FASOM domestic 
model (see Section V.B.4.b.ii), we have incorporated GHG emission 
impacts associated with change in forest above-ground and below-ground 
biomass, forest soil carbon stocks, forest management practices (e.g. 
timber harvest cycles), and forest products and product emission 
streams over time. Forest carbon accounting in FASOM is based on the 
FORCARB developed by the U.S. Forest Service and on data derived 
largely from the U.S. Forest Service RPA modeling system.
    With the changes to FASOM discussed above, we also updated the 
final calculation method of domestic land use change GHG emissions to 
account for FASOM's cumulative assessment of GHG emissions and the 
continuous (rather than discrete) nature of soil carbon and forest 
product emissions. For each category of agricultural and forestry land 
use emissions, we calculated the mean cumulative emissions from the 
initial year of FASOM modeling (2000) to 2022. Changes in agricultural 
and forest soil carbon and forest products have a stream of GHG 
emissions associated with them in addition to the initial pulse 
associate with a discrete instance or year of land use change. For each 
of these categories FASOM calculates the emissions over time associated 
with the mean land use change over a year. We included in total 
domestic land use change emissions the annualized emission streams 
associated with all agricultural soil, forest soil, and forest product 
changes included in the mean cumulative emissions (2000-2022) for 30 
years after 2022.

[[Page 14778]]

(2) International Emissions
    Based on input from the expert peer review and public comments, we 
incorporated new data sources and made other methodological 
improvements in our estimates of GHG emissions from international land 
conversions. Some of these modifications increased land use change GHG 
emissions compared to the NPRM, such as the consideration of carbon 
releases from drained peat soils. Other modifications, such as more 
conservative foregone sequestration estimates, tended to decrease land 
use change GHG emissions. For example, our estimates of emissions per 
acre of deforestation in Brazil tended to increase because of improved 
data on forest biomass carbon stocks in that region. However, for 
example, our deforestation estimates in China decreased, in part 
because of new data on foregone forest sequestration. The net effect of 
the revisions varied depending on the location and types of land use 
changes in each biofuel scenario. The major changes to this part of our 
analysis, including a quantitative uncertainty assessment, are 
discussed in this section.
    To determine the GHG emissions impacts of international land use 
changes, we followed the 2006 IPCC Agriculture, Forestry, and Other 
Land Use (AFOLU) Guidelines.\171\ We worked with Winrock, which has 
years of experience developing and implementing the IPCC guidelines, to 
estimate land conversion emissions factors, including changes in 
biomass carbon stocks, soil carbon stocks, non-CO2 emissions 
from clearing with fire and foregone forest sequestration (i.e., lost 
future growth in vegetation and soil carbon). In addition to seeking 
comment on our analysis in the proposed rule, EPA organized public 
hearings and workshops, and an expert peer review specifically 
eliciting feedback on this part of the lifecycle analysis. All of the 
expert peer reviewers generally felt that our analysis followed IPCC 
guidelines and was scientifically justifiable; however, they did make 
several suggestions of new data sources and recommended areas that 
could benefit from additional clarification. Based on the detailed 
comments we received, we worked with Winrock to make a number of 
important revisions, which have significantly improved this part of our 
analysis.
---------------------------------------------------------------------------

    \171\ 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.
---------------------------------------------------------------------------

    The proposed rule analysis included land conversion emissions 
factors for 5 land categories in 314 regions across 35 of the most 
important countries, with a weighted average applied to the rest of the 
world. We augmented this analysis to provide global coverage, including 
emissions factors for 10 land categories in over 750 regions across 160 
countries. Other significant improvements included incorporation of new 
data sources, emissions factors for peat soil drainage, sequestration 
factors for abandoned agricultural land, and a full uncertainty 
assessment considering every data input.
    Another significant improvement in our analysis was incorporation 
of higher resolution soil carbon data. One of the expert peer reviewers 
commented that the weakest part of EPA's international emissions factor 
analysis for the proposed rule was the global soil carbon map that was 
used because of its coarse resolution. To address this comment, we 
incorporated the new Harmonized World Soil Database, released in March 
2009. This dataset provides one square kilometer spatial resolution, 
which is a major improvement compared to the proposed rule analysis. 
This dataset also includes an updated soil map of China that the peer 
reviewers recommended. Using this updated soil carbon data, the change 
in soil carbon following conversion of natural land to annual crop 
production was estimated following the 2006 IPCC guidelines. When land 
is plowed in preparation for crop production the soil loses carbon over 
time until a new equilibrium is established. To calculate soil carbon 
emissions the IPCC approach considers both tillage practices and 
agricultural inputs. Some of the peer reviewers expressed concern with 
our annual soil carbon change estimates, which assumed a constant rate 
of change over 20 years. However, for analytical timeframes greater 
than 20 years, such as used in our lifecycle analysis, the peer 
reviewers agreed that the our approach was scientifically justifiable. 
More information about soil carbon stock estimates is available in 
Chapter 2 of the RIA.
    The expert peer reviewers generally agreed that EPA's estimate of 
forest carbon stocks followed IPCC guidelines and used the best 
available data. They did, however, recommend that the analysis could be 
updated with improved forest biomass maps as they become available. 
Consistent with these suggestions, we incorporated improved forest 
biomass maps for regions where they were available. More information 
about the specific data sources used is available in RIA Chapter 2.
    In addition to estimating forest carbon stocks for each region, 
EPA's analysis also includes estimates of annual forest carbon uptake. 
When a forest is cleared the future carbon uptake from the forest is 
lost; this is known as foregone forest sequestration. In the proposed 
rule, to estimate annual forgone forest sequestration, we used IPCC 
default data for the growth rates of forests greater than 20 years old. 
The expert peer reviewers noted that these estimates could be refined 
with more detailed information from the scientific literature. Many of 
the public commenters were also concerned that EPA's approach 
overestimated foregone sequestration because it did not adequately 
account for natural disturbances, such as fires and disease. To address 
these comments, our analysis has been updated with peer reviewed 
studies of long-term growth rates for both tropical and temperate 
forests. These estimates are based on long-term records (i.e., 
monitoring stations in old-growth forests for the tropics and multi-
decadal inventory comparisons for the temperate regions) and reflect 
all losses/gains over time. These studies show that the old-growth 
forests in the tropics that many once assumed to be in ``steady state'' 
(i.e., carbon gains equal losses) are in fact still gaining carbon. In 
summary, our analysis now includes more conservative foregone forest 
sequestration estimates that account for natural gains and losses over 
time. More information about these estimates is provided in RIA Chapter 
2.
    Another consideration when estimating GHG emissions resulting from 
deforestation is that some of the wood from the cleared forest can be 
harvested and used in wooden products, such as a table, that retain 
biogenic carbon for a long period of time. Some commenters argued that 
consideration of the use of harvested wood in products would decrease 
land use change emissions and reduce the impacts of biofuel production. 
As part of analysis for the proposed rule, we investigated the share of 
cleared forest biomass that is typically used in harvested wood 
products (HWP). However, we did not account for this factor in the 
proposed rule after it was determined that HWP would have a very small 
impact on the magnitude of land use change emissions. A number of 
commenters expressed concern that we did not account for HWP, and they 
argued that HWP would be more significant than we had determined. 
However, in response to specific questions on this topic, all of the 
expert

[[Page 14779]]

peer reviewers agreed that EPA had properly accounted for HWP and other 
factors (e.g., land filling) that could prevent or delay emissions from 
land clearing. One of the peer reviewers noted that forests converted 
to croplands are generally driven by interests unrelated to timber, and 
thus the trees are simply burned and exceptions are probably of minor 
importance. To study this issue further, we looked at FAO timber volume 
estimates for 111 developing countries, and published literature on the 
share of harvested timber used in wood products and the oxidation 
period for wood products, such as wood-based panels and other 
industrial roundwood. Consistent with the peer reviewers' statements, 
our analysis concluded that even in countries with high rates of 
harvested timber utilization, such as Indonesia, a very small share of 
harvested forest biomass would be sequestered in HWP for longer than 30 
years. The details of our HWP analysis are discussed further in RIA 
Chapter 2. This is an area for further work, but based on our analysis, 
and the feedback from expert commenters, we do not expect that 
consideration of HWP would have a significant impact on the magnitude 
of GHG emissions from international deforestation in our analysis. 
Furthermore, the range of outcomes from consideration of HWP is 
indirectly captured in our assessment of forest carbon stock 
uncertainty, which is described below.
    The land conversion emissions estimates used in our analysis 
consider the carbon stored in crop biomass. In the proposed rule, we 
used the IPCC default biomass sequestration factor of 5 metric tons of 
carbon per hectare for annual crops, and applied this value to all 
crops globally. The final rule analysis now distinguishes between 
annual and perennial crops, with separate sequestration estimates for 
sugarcane and oil palm determined from the scientific literature. The 
peer reviewers suggested approaches to refine our biomass carbon 
estimates for different types of annual crops, e.g., for corn versus 
soybeans. However, we determined that adding crop-specific biomass 
sequestration estimates would have a very small impact on our results, 
because in general annual cropland carbon stocks range only from 3 to 7 
tons per hectare and the average would likely be very close to the IPCC 
default factor currently applied. This is an area for future work, but 
we are confident that it would have very small impact. Furthermore, the 
range of potential outcomes is captured in the uncertainty analysis 
described below.
    Other issues that were covered in the expert peer review and public 
comments included EPA's carbon stock estimates for grasslands, savanna, 
shrublands and wetlands, and our assumptions about which regions use 
fire to clear land prior to agricultural expansion. There is less data 
available for these parameters relative to some of the other issues 
discussed above, e.g., forest carbon stocks. Therefore, we worked to 
use expert judgment to derive global estimates for these parameters. In 
general, the peer reviewers thought that EPA's approach to these issues 
was reasonable and scientifically justifiable. Some of the peer 
reviewers recommended more resource-intensive techniques to refine some 
of our estimates. For example, regarding the issue of clearing with 
fire, one of the peer reviewers suggested that we could review fire 
events in the historical satellite data to estimate where fire is most 
commonly used. We carefully considered these suggestions, but did not 
make significant revisions to our analysis of these issues. Our review 
concluded that given the timeframe and goals of our analysis, the 
approach used in the proposed rule was most appropriate. We recognize 
that these are areas for future work, and we will consider new data as 
part of periodic updates. Furthermore, our uncertainty analysis, 
described below, considered the fact that these are areas where less 
data is available.
    Other improvements in our analysis included the addition of 
emissions from peat soil drainage in Indonesia and Malaysia, and 
sequestration factors for abandoned agricultural land. Consistent with 
the expert peer reviewers' recommendations, we considered a number of 
recent studies to estimate average carbon emissions when peat soils are 
drained in Indonesia and Malaysia (the countries where peat soil is 
sometimes drained in preparation for new agricultural production). To 
estimate annual sequestration on abandoned agricultural land we used 
our foregone sequestration estimates and other data from IPCC. More 
information about these estimates is available in RIA Chapter 2.
    As discussed in Section V.A.2, the uncertainty of land use change 
emissions is an important consideration in EPA's threshold 
determinations as part of this rulemaking. We conducted a full 
assessment of the uncertainty in international land use change 
emissions factors consistent with 2006 IPCC guidance.\172\ This 
analysis considers the uncertainty in the every parameter used in our 
emissions factor estimates. Standard deviations for each parameter were 
estimated based on the quality and quantity of the underlying data. For 
example, in our analysis the standard errors (as a percent of the mean) 
tend to be smallest for forest carbon stocks in Brazil, because a large 
amount of high quality/resolution data was considered to estimate that 
parameter. Standard errors are largest for parameters that were 
estimated by scaling other data, or applying IPCC defaults, e.g., 
savanna carbon stocks in Yemen. More detail about our estimate of 
parameter uncertainty is available in RIA Chapter 2.
---------------------------------------------------------------------------

    \172\ 2006 IPCC Guidelines for National Greenhouse Gas 
Inventories, Volume 1: General Guidance and Reporting, Chapter 3: 
Uncertainties, available at http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol1.html.
---------------------------------------------------------------------------

    Following IPCC guidance, the uncertainties in the individual 
parameters of an emission factor can be combined using either error 
propagation methods (IPCC Tier 1) or Monte Carlo simulation (IPCC Tier 
2). We used the Tier 2 Monte Carlo simulation method for this analysis. 
Monte Carlo is a method for analyzing uncertainty propagation by 
randomly sampling from the probability distributions of model 
parameters, calculating the results of the model from each sample, and 
characterizing the probability of the outcomes. An important 
consideration for Monte Carlo analysis is the treatment of correlation, 
or dependencies, among parameter errors. Strong positive correlation 
among parameter errors will result in greater overall uncertainty. As a 
simplified example, if the errors in our forest carbon stock estimates 
are positively correlated, then if we are overestimating forest carbon 
in one region we are likely overestimating forest carbon in every 
region. We worked with Winrock to estimate the degree of correlation 
among variables--both the correlation of one variable across space as 
well as the correlation of one variable to any others used in the 
analysis. This was done by considering dependencies in the underlying 
data used to estimate each parameter. For example, our forest carbon 
stock estimates are correlated across Russia because they were derived 
from one biomass map covering Russia. However, forest carbon stocks in 
Russia are not correlated with China, because they were derived from 
separate biomass maps. This partial correlation approach tended to 
reduce the overall uncertainty

[[Page 14780]]

associated with GHG emissions factor data.
    The information about the uncertainty in each parameter and the 
degree of correlation across parameters was utilized in Monte Carlo 
analysis to determine the overall uncertainty in our emissions factor 
estimates. We used the Monte Carlo simulation to combine the emissions 
factor and satellite data uncertainty for every biofuel scenario 
analyzed. Uncertainty ranges varied across scenarios depending on the 
types and locations of land use changes. For example, based on the 
sources of uncertainty analyzed, the 95% confidence range for land use 
change emissions (as a percent of the mean) was -27% to +32% for base 
yield corn ethanol in 2022, and -56% to +76% for base yield soy 
biodiesel in 2022.\173\ More details about this uncertainty analysis 
are provided in RIA Chapter 2.
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    \173\ The 95% confidence range indicates there is no more than a 
5% chance the actual value is likely to be outside this range.
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iv. Timeframe of Emission Analysis
    Based on input from the expert peer review and public comments, EPA 
has chosen to analyze lifecycle GHG emissions using a 30 year time 
period, over which emissions are not discounted, i.e., a zero discount 
rate is applied to future emissions. The input we received and the 
reasons for our use of this approach are described in this section.
    As required by EISA, EPA must determine whether biofuels reduce GHG 
emissions by the required percentage relative to the 2005 petroleum 
baseline. In the proposal the Agency discussed a number of accounting 
methods for capturing the full stream of GHG emissions and benefits 
over time. When accounting for the time profile of lifecycle GHG 
emissions, two important assumptions to consider are: (1) The time 
period considered and (2) the discount rate (which could be zero) 
applied to future emissions streams. At the time of proposal, EPA 
requested public comment on the choice of time frames and discounting 
approaches for purposes of estimating lifecycle GHG emissions. Also, as 
part of the peer review process, EPA requested comment from expert peer 
reviewers on the choice of the appropriate time frames and discount 
rates for the RFS2 analysis. Below is a summary of the comments we 
received on these issues and how we address them in our analytical 
approach.
    Time Period for Analysis: In the proposed rule, EPA highlighted two 
time periods, 30 years and 100 years, for consideration in our 
lifecycle analysis. The Agency discussed the relative advantages of 
these, and other, time periods. In addition, the Agency sought comment 
on whether it is appropriate to split the time period for GHG emissions 
assessment based upon how long the biofuel would be produced (i.e., the 
``project'' period) and the time period for which there would likely be 
GHG emissions changes (i.e., the ``impact'' period). To encourage 
expert and public comments on these issues, EPA held public hearings 
and workshops and sponsored an expert peer review specifically focused 
on this topic. The expert input and comments that we received included 
many valuable points which guided our decisions about which time frame 
should be the focus of our analysis. Below we summarize some of the key 
arguments made by the peer reviewers and commenters, and how these 
arguments factored into our choice of analytical approach.
    The expert peer reviewers discussed a number of justifiable time 
periods ranging from 13 to 100 years for assessing lifecycle GHG 
emissions. A subset of the reviewers said that EPA's analysis should be 
restricted to 2010-2022 based on the years specified in EISA, because 
these reviewers argued that EPA should not assume that biofuel 
production will continue beyond 2022 at the RFS2 levels. The reviewers 
said that longer time frames, such as 100 years, were only appropriate 
if the Agency used positive discount rates to value future emissions. 
Almost all of the peer reviewers said that a time frame of 20 to 30 
years would be a reasonable timeframe for assessing lifecycle GHG 
emissions. They gave several reasons for why a short time period is 
appropriate: This time frame is the average life of a typical biofuel 
production facility; future emissions are less certain and more 
difficult to value, so the analysis should be confined insofar as 
possible to the foreseeable future; and a near-term time horizon is 
consistent with the latest climate science that indicates that 
relatively deep reductions of heat-trapping gasses are needed to avoid 
catastrophic changes due to a warming climate. The peer reviewers 
suggested that while there is no unassailable basis for choosing a 
precise timeframe the expected average lifetime of a biofuel production 
facility is the ``most sensible anchor'' for the choice of a timeframe.
    There was support in the public comments for both the 30 year and 
100 year time frames. A number of public commenters supported the use 
of a 30 year time period, or less, and made arguments similar to those 
of the expert peer reviewers. They argued that shorter time periods 
give more weight to the known, more immediate, effects of biofuel 
production and that use of longer time periods gives more weight to 
activities that are much more uncertain, and that the 100 year 
timeframe is inappropriate because it is much longer than the life of 
individual biofuel plants.
    On the issue of whether to split the time period for GHG emissions 
analysis into the ``project and ``impact'' periods, there was little 
support for the use of a split time frame for evaluating lifecycle GHG 
emissions by the peer reviewers or in the public comments. The peer 
reviewers thought that it would be difficult to find a scientific basis 
for determining the length of the two different time horizons. Also, 
splitting the time horizon would necessitate consideration of the land 
use changes following the end of the project time horizon such as land 
reversion. However, the majority of expert peer reviewers did not think 
it was appropriate to attribute potential land reversions, following 
the project time frame, to a biofuel's lifecycle.
    Based upon the comments discussed above, EPA has decided to use a 
30 year frame for assessing the lifecycle GHG emissions. There are 
several reasons why the 30 year time frame was chosen. The full life of 
a typical biofuel plant seems reasonable as a basis for the timeframe 
for assessing the GHG emissions impacts of a biofuel, because it 
provides a guideline for how long we can expect biofuels to be produced 
from a particular entity using a specific processing technology. Also, 
the 30 year time frame focuses on GHG emissions impacts that are more 
near term and, hence, more certain. We also determined that longer time 
periods were less appropriate because the peer reviewers recommended 
that they should only be used in conjunction with positive discount 
rates; but, for the reasons discussed below, we are using a zero 
discount rate in our analysis. In addition, the 30 year time frame is 
consistent with responses of the peer reviewers that EPA should not 
split the time periods for analysis, or include potential land 
reversions following the project time period in the biofuel lifecycle.
    Discounting: In the RFS2 Proposal, EPA highlighted two principal 
options for discounting the lifecycle GHG emission streams from 
biofuels over time. The first involved the use of a 2% discount rate 
using the 100 year time horizon for assessing lifecycle GHG emissions 
streams. The second option involved using a 30 year time horizon for 
examining lifecycle GHG emissions

[[Page 14781]]

impacts. In the 30 year case, each GHG emission is treated equally 
through time, which implicitly assumes a zero discount rate to GHG 
lifecycle emissions streams. The issue of whether to discount lifecycle 
GHG emissions was raised as a topic that EPA sought comment on in both 
the peer review process and in public comments.
    EPA received numerous comments on the issue of whether the Agency 
should be discounting lifecycle GHG emissions through time. While many 
of peer reviewers thought that current GHG emissions reductions should 
be more strongly weighted than future reductions, the peer reviewers 
were in general agreement that a discount rate should only be applied 
to a monetary unit, rather than a physical unit, such as GHG emissions. 
Public commenters suggested that discounting is an essential part of 
long term cost benefit analysis but it is not necessary in the context 
of the physical aggregation of lifecycle GHG emissions called for in 
the EISA. Further, public commenters expressed concerns that any 
discount rate chosen by the Agency would be based upon relatively 
arbitrary criteria.
    After considering the comments on discounting from the peer review 
and the public, EPA has decided not to discount (i.e., use a 0% 
discount rate) GHG emissions due to the many issues associated with 
applying an economic concept to a physical parameter. First, it is 
unclear whether EISA intended lifecycle GHG emissions to be converted 
into a metric whose underpinnings rest on principals of economic 
valuation. A more literal interpretation of EISA is that EPA should 
consider only physical GHG emissions. Second, even if the principle of 
tying GHG emissions to economic valuation approaches were to be 
accepted, there would still be the problem that there is a lack of 
consensus in the scientific community about the best way to translate 
GHG emissions into a proxy for economic damages. Also, there is a lack 
of consensus as to the appropriate discount rate to apply to GHG 
lifecycle emissions streams through time. Finally, since EPA has 
decided to base threshold assessments of lifecycle GHG emissions on a 
30 year time frame, the issue of whether to discount GHG emissions is 
not as significant as if the EPA had chosen the 100 year time frame to 
assess GHG emissions impacts. More discussion of discount rates and 
their impact on the lifecycle results can be found in Chapter 2 of the 
RIA.
v. GTAP and Other Models
    Although we have used the partial equilibrium (PE) models FASOM and 
FAPRI-CARD as the primary tools for evaluating whether individual 
biofuels meet the GHG thresholds, as part of the peer review process, 
we explicitly requested input on whether general equilibrium (GE) 
models should be used. None of the comments recommended using a GE 
model as the sole tool for estimating GHG emissions, given the limited 
details on the agricultural sector contained in most GE models. The 
peer reviewers generally supported the use of the FASOM and FAPRI-CARD 
models for our GHG analysis given the need for additional detail 
offered in the PE models, however several comments suggested 
incorporating GE models into the analysis.
    Given these recommendations, we opted to use the GTAP model to 
inform the range of potential GHG emissions associated with land use 
change resulting from an increase in renewable fuels. As discussed in 
the NPRM, there are several advantages to using GTAP. As a general 
equilibrium model, GTAP captures the interaction between different 
markets (e.g., agriculture and energy) in different regions. It is 
distinctive in estimating the complex international land use change 
through trade linkages. In addition, GTAP explicitly models land-use 
conversion decisions, as well as land management intensification. 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 types of land cover within each Agro-Ecological Zone.
    Like the peer reviewers, we felt that some of the drawbacks of the 
GTAP model prevent us from using GTAP as the sole model for estimating 
GHG emissions from biofuels. As discussed in the NPRM, GTAP does not 
utilize unmanaged cropland, nor is it able to capture the long-run 
baseline issues (e.g., the state of the economy in 2022). For our 
analysis, the GTAP model was most valuable for providing another 
estimate of the quantity and type of land conversion resulting from an 
increase in corn ethanol and biodiesel given the competition for land 
and other inputs from other sectors of the economy. These results were 
therefore considered as part of the weight of evidence when determining 
whether corn ethanol or biodiesel met the GHG thresholds.
    The quantity of total acres converted to crop land projected by 
FAPRI-CARD were within the range of values projected by GTAP when 
normalized on a per BTU basis, although there were differences in the 
regional distribution of these changes. The land use changes projected 
by GTAP were smaller than land use changes predicted by FAPRI-CARD, 
which is primarily due to several important differences in the modeling 
frameworks. First, the GTAP model incorporates a more optimistic view 
of intensification options by which higher prices induced by renewable 
fuels results in higher yields, not just for corn, but also for other 
displaced crops. Second, the demands for other uses of land are 
explicitly captured in GTAP. Therefore, when land is withdrawn from 
these uses, the prices of these products rise and provide a certain 
amount of ``push-back'' on the conversion of land to crops from pasture 
or forest. Third, none of the peer-reviewed versions of GTAP currently 
contain unmanaged cropland, thereby omitting additional sources of 
land. Finally, the GTAP model also predicted larger increases in forest 
conversion than the FAPRI-CARD/Winrock analysis, in part because the 
GTAP model includes only three types of land (i.e., crops, pasture, 
forest). As discussed in the FAPRI-CARD/Winrock section, there are many 
other categories of land which may be converted to pasture and crop 
land.
    As with all economic models, GTAP results are sensitive to certain 
key parameter values. One advantage of this framework is that it offers 
a readily usable approach to Systematic Sensitivity Analysis (SSA) 
using efficient sampling techniques. We have exploited this tool in 
order to develop a set of 95% confidence intervals around the projected 
land use changes. Several key parameters were identified that have a 
significant impact on the land use change projections, including the 
yield elasticity (i.e., the change in yield that results from a change 
in that commodity's price), the elasticity of transformation of land 
supply (i.e., the measure of how easily land can be converted between 
forest, pasture, and crop land), and the elasticity of transformation 
of crop land (i.e., the measure of how easily land can be converted 
between crops). Although the confidence intervals are relatively large, 
in most cases the ranges do not bracket zero. Therefore, we conclude 
that the impacts of the corn ethanol and soybean biodiesel mandates on 
land use change are statistically significant. These confidence 
intervals also bracket the FAPRI-CARD results. Additional

[[Page 14782]]

information on the GTAP results is discussed in RIA Chapter 2.
c. Feedstock Transport
    To estimate the GHG impacts of transporting corn from the field to 
an ethanol production facility and transporting the co-product DDGS 
from the ethanol facility to the point of use, we used the method 
described in the proposed rule. We also did not change our estimates 
for the transport of cellulosic biofuel feedstock and biomass-based 
diesel feedstock.
    For sugarcane transport, we received the comment that the GREET 
defaults used to estimate the energy consumption and associated GHG 
emissions do not all reflect current industry practices. To address 
this concern, we reviewed the current literature on sugarcane transport 
and updated our assumptions on the distance sugarcane travels by truck 
from the field to ethanol production facilities as well as the payload 
and fuel economy of those trucks. We incorporated these revised inputs 
into an updated version of the GREET model (Version 1.8c) in order to 
estimate the GHG impacts of sugarcane transport. More details on these 
updates can be found in Chapter 2 of the RIA.
    In the proposal, we discussed updating our analysis to incorporate 
the results of a recent study detailing biofuel production locations 
and modes of transport. This study, conducted by Oak Ridge National 
Laboratory, modeled the transportation of ethanol from production or 
import facilities to petroleum blending terminals. Since the study did 
not explicitly address the transport of biofuel feedstocks, we did not 
implement the results for this part of the analysis. However, we did 
incorporate the results into our assessment of the GHG impacts of fuel 
transportation. We will continue to examine whether our feedstock 
transport estimates could be significantly improved by implementing 
more detailed information on the location of biofuel production 
facilities.
    We also discussed updating the transportation modes and distances 
assumed for corn and DDGS to account for the secondary or indirect 
transportation impacts. For example, decreases in exports will reduce 
overall domestic agricultural commodity transport and emissions but 
will increase transportation of commodities internationally. We did not 
implement these secondary transportation impacts in this final rule. 
While we do not anticipate that such impacts would significantly change 
the lifecycle analysis, we plan to continue to look at this issue and 
consider incorporating them in the future.
d. Biofuel Processing
    For the proposal the GHG emissions from renewable fuel production 
were calculated by multiplying the Btus of the different types of 
energy inputs at biofuel process plants by emissions factors for 
combustion of those fuel sources. The Btu of energy input was 
determined based on analysis of the industry and specific work done as 
part of the NPRM. The emission factors for the different fuel types are 
from GREET and were based on assumed carbon contents of the different 
process fuels. The emissions from producing electricity in the U.S. 
were also taken from GREET and represent average U.S. grid electricity 
production emissions.
    We received comments on our approach and updated the analysis of 
GHG emissions from biofuel process for the final rule specifically 
regarding process energy use and the treatment of co-products.
    Process Energy Use: For the final rule we updated each of our 
biofuel pathways to include the latest data available on process energy 
use. For the proposal, one of the key sources of information on energy 
use for corn ethanol production was a study from the University of 
Illinois at Chicago Energy Resource Center. Between proposal and final 
rule, the study was updated, therefore, we incorporated the results of 
the updated study in our corn ethanol pathways process energy use for 
the final rule. We also updated corn ethanol production energy use for 
different technologies in the final rule based on feedback from 
industry technology providers as part of the public comment period. The 
main difference between proposal and final corn ethanol energy use 
values was a slight increase in energy use for the corn ethanol 
fractionation process, based on feedback from industry technology 
providers.
    For the proposal we based biodiesel processing energy on a process 
model developed by USDA-ARS to simulate biodiesel production from the 
Fatty Acid Methyl Ester (FAME) transesterification process. We received 
a number of comments from stakeholders that the energy balance for 
biodiesel production was overestimating energy use and should be 
updated. During the comment period USDA updated their energy balance 
for biodiesel production to incorporate a different biodiesel 
dehydration process based on a system which has resulted in a decrease 
in energy requirements. This change was reflected in the energy use 
values for biodiesel assumed in our final rule analysis which resulted 
in reduced GHG impacts from the biodiesel production process.
    In addition, for the final rule we have included an analysis of 
algae oil production for biodiesel based on ASPEN process modeling from 
NREL.\174\ The analysis is for two major cultivation pathways (open 
pond and photobioreactors) for a facility that can be feasibly 
commercialized in the future, represented by a ``2022'' target 
production. We coupled the algae oil production process (which includes 
cultivation, harvesting, and extraction) with the biodiesel production 
energy use from virgin oils energy use model under the assumption that 
algae oil is similar enough to that of virgin oil.
---------------------------------------------------------------------------

    \174\ Davis, Ryan. November 2009. Techno-economic analysis of 
microalgae-derived biofuel production. National Renewable Energy 
Laboratory (NREL)
---------------------------------------------------------------------------

    For the cellulosic biofuel pathways, we updated our final rule 
energy consumption assumptions on process modeling also completed by 
NREL. For the NPRM, NREL estimated energy use for the biochemical 
enzymatic process to ethanol route in the near future (2010) and future 
(2015 and 2022).175 176 177 As there are multiple processing 
pathways for cellulosic biofuel, we have expanded the analysis for the 
FRM to also include thermochemical processes (Mixed-Alcohols route and 
Fischer-Tropsch to diesel route) for plants which assume woody biomass 
as its feedstock.
---------------------------------------------------------------------------

    \175\ Tao, Ling and Aden, Andy. November 2008. Techno-economic 
Modeling to Support the EPA Notice of Proposed Rulemaking (NOPR). 
National Renewable Energy Laboratory (NREL).
    \176\ Aden, Andy. September 2009. Mixed Alcohols from Woody 
Biomass--2010, 2015, 2022. National Renewable Energy Laboratory 
(NREL).
    \177\ Davis, Ryan. August 2009. Techno-economic analysis of 
current technology for Fischer-Tropsch fuels. National Renewable 
Energy Laboratory (NREL).
---------------------------------------------------------------------------

    Under the imported sugarcane ethanol cases we updated process 
energy use assumptions to reflect anticipated increases in electricity 
production for 2022 based on recent literature and comments to the 
proposal. One major change was assuming the potential use of trash 
(tops and leaves of sugarcane) collection in future facilities to 
generate additional electricity. The NPRM had only assumed the use of 
bagasse for electricity generation. Based on comments received, we are 
also assuming marginal electricity production (i.e., natural gas) 
instead of average electricity mix in Brazil which is mainly 
hydroelectricity. This approach assumes surplus electricity will likely 
displace electricity which is normally dispatched last, in this case

[[Page 14783]]

typically natural gas based electricity. The result of this change is a 
greater credit for displacing marginal grid electricity and thus a 
lower GHG emissions profile for imported sugarcane ethanol than that 
assumed in the NPRM. We also received public comment that there are 
differences in the types of process fuel e.g. used in the dehydration 
process for ethanol. While using heavier fuels such as diesel or bunker 
fuel tends to increase the imported sugarcane ethanol emissions 
profile, the overall impact was small enough that lifecycle results did 
not change dramatically.
    Co-Products: In response to comments received, we included corn oil 
fractionation and extraction as a potential source of renewable fuels 
for this final rulemaking. Based on research of various corn ethanol 
plant technologies, corn oil as a co-product from dry mill corn ethanol 
plants can be used as an additional biodiesel feedstock source (see 
Section VII.A.2 for additional information). Dry mill corn ethanol 
plants have two different technological methods to withdraw corn oil 
during the ethanol production process. The fractionation process 
withdraws corn oil before the production of the DGS co-product. The 
resulting product is food-grade corn oil. The extraction process 
withdraws corn oil after the production of the DGS co-product, 
resulting in corn oil that is only suitable for use as a biodiesel 
feedstock.
    Based on cost projections outlined in Section VII.A, it is 
estimated that by 2022, 70% of dry mill ethanol plants will conduct 
extraction, 20% will conduct fractionation, and that 10% will choose to 
do neither. These parameters have been incorporated into the FASOM and 
FAPRI-CARD models for the final rulemaking analysis, allowing for corn 
oil from extraction as a major biodiesel feedstock.
    Glycerin is a co-product of biodiesel production. Our proposal 
analysis did not assume any credit for this glycerin product. The 
assumption for the proposal was that by 2022 the market for glycerin 
would be saturated due to the large increase in biodiesel production in 
both the US and abroad and the glycerin would therefore be a waste 
product. We received a number of comments that we should be factoring 
in a co-product credit for glycerin as there would be some valuable use 
for this product in the market. Based on these comments we have 
included for the final rule analysis that glycerin would displace 
residual oil as a fuel source on an energy equivalent basis. This is 
based on the assumption that the glycerin market would still be 
saturated in 2022 and that glycerin produced from biodiesel would not 
displace any additional petroleum glycerin production. However, the 
biodiesel glycerin would not be a waste and a low value use would be to 
use the glycerin as a fuel source. The fuel source assumed to be 
replaced by the glycerin is residual oil. This inclusion of a co-
product credit for glycerin reduces the overall GHG impact of biodiesel 
compared to the proposal analysis.
e. Fuel Transportation
    For the proposed rule, we estimated the GHG impacts associated with 
the transportation and distribution of domestic and imported ethanol 
and biomass-based diesel using GREET defaults. We have upgraded to the 
most recent version of GREET (Version 1.8c) for our transportation 
analysis in the final rule.\178\ We made several other updates to the 
method we utilized in the proposed rule. These updates are described 
here and in more detail in Chapter 2 of the RIA.
---------------------------------------------------------------------------

    \178\ The method used to estimate the GHG impacts associated 
with biodiesel transportation has not been changed since the 
proposal. This method utilized an earlier version of the GREET 
model.
---------------------------------------------------------------------------

    In the proposal, we noted our intention to incorporate the results 
of a recent study by Oak Ridge National Laboratory (ORNL) into our 
transportation analysis for the final rule. The ORNL study models the 
transportation of ethanol from refineries or import facilities to the 
petroleum blending terminals by domestic truck, marine, and rail 
distribution systems. We used ORNL's transportation projections for 
2022 under the EISA policy scenario to update our estimates of the GHG 
impacts associated with the transportation of corn, cellulosic, and 
sugarcane ethanol. Since the study did not address the distribution of 
ethanol from petroleum blending terminals to refueling stations, we 
continued to use GREET defaults to estimate these impacts.
    The ORNL study also did not address the transportation of imported 
ethanol within its country of origin or en route to the import facility 
in the United States. As in the proposal, we used GREET defaults to 
estimate the impacts associated with the transportation of sugarcane 
ethanol within Brazil. We updated the GREET default for the average 
distance sugarcane ethanol travels by ocean tanker using recent 
shipping data from EIA in order to account for both direct Brazilian 
exports and the shipment of ethanol from countries in the Caribbean 
Basin Initiative. We received several comments on the back-haul 
emissions associated with ocean transport. For the final rule, we 
assumed that these emissions were negligible.
f. Vehicle Tailpipe Emissions
    We updated the CO2 emissions factors for ethanol and 
biodiesel to be consistent with those used in the October 30, 2009 
final rulemaking for the Mandatory GHG Reporting Rule. These changes 
caused the tailpipe GHG emission factors to increase by 0.8% for 
ethanol and to decrease by 1.5% for biodiesel. Specific tailpipe 
combustion values used in this final rule can be found in Chapter 2 of 
the RIA. Estimates for CH4 and N2O were made 
using outputs from EPA's MOVES model.
3. Petroleum Baseline
    For the proposed rule, we conducted an analysis to determine the 
lifecycle greenhouse gas emissions for the petroleum baseline against 
which renewable fuels were to be compared. We utilized the GREET model 
(Version 1.8b), which uses an energy efficiency metric to calculate GHG 
emissions associated with the production of petroleum-based fuels. We 
received numerous comments regarding this approach.
    Petroleum baseline calculation from proposed rule: The GREET model 
relies on using average values as inputs to estimate aggregate 
emissions, rather than using site-specific values. Commenters noted a 
number of GREET input values that they believed to be incorrect. These 
included: energy efficiency values for crude oil extraction; methane 
emission factors for oil production and flaring; transportation 
distances for crude oil and petroleum products; and the oil tanker 
cargo payload value. Commenters also noted that GREET does not account 
for the energy consumption associated with crude oil transport in the 
country of extraction.
    In addition, commenters stated that the crude oil import slate 
assumed in the proposed rule was inconsistent with EIA crude oil 
production and import data for 2005. Commenters also noted that the 
gasoline and diesel mix that we used for the proposal did not match 
with EIA prime supplier sales volume data. One specific comment focused 
on the definition of low-sulfur diesel in GREET, where it is defined as 
being 11 ppm sulfur content, which is inconsistent with EPA's 
definition. As a result, in the proposed rule, all transportation 
diesel produced in 2005 was assumed to be ultra-low sulfur diesel.

[[Page 14784]]

    We largely agree with the above comments. An updated version of the 
GREET model (Version 1.8c) is available, and it may address some of the 
issues raised by commenters. We considered using this new version of 
GREET with updated input values from publically available sources to 
determine the petroleum baseline for the final rule. However, we have 
decided that using the 2005 petroleum baseline model developed by the 
National Energy Technology Laboratory (NETL) \179\ would address the 
commenters' concerns, and result in a more accurate and comprehensive 
assessment of the petroleum baseline than we could obtain using the 
GREET model.
---------------------------------------------------------------------------

    \179\ Department of Energy: National Energy Technology 
Laboratory. 2009. NETL: Petroleum-Based Fuels Life Cycle Greenhouse 
Gas Analysis--2005 Baseline Model.
---------------------------------------------------------------------------

    Use of NETL study for final rule petroleum baseline calculation: In 
the proposed rule, we requested comment on using the NETL study for our 
2005 petroleum baseline for the final rulemaking. We only received one 
comment, which agreed that the NETL values were generally more accurate 
and better documented than the values in GREET. However, the commenter 
also stated that NETL's use of 2002 crude oil extraction data would 
underestimate extraction emissions for 2005, and that it would be 
inconsistent to use the GREET model for determining GHG emissions from 
biofuels, but not for petroleum.
    We do not agree with the commenters' criticism of the NETL model. 
We have not seen data that indicates that the GHG emissions associated 
with crude oil extraction would be appreciably different in 2005 than 
2002. EPA also believes that it is important to use the best available 
tools to estimate a petroleum baseline that can be compared to 
renewable fuels. The fact that some GREET emission factors are used in 
the calculation of biofuel lifecycle GHG impacts is not a reason to use 
the GREET model for the petroleum baseline analysis over what we feel 
to be a better tool for the baseline calculation needed.
    NETL states that the goal of their study is to ``determine the life 
cycle greenhouse gas emissions for liquid fuels (conventional gasoline, 
conventional diesel, and kerosene-based jet fuel) production from 
petroleum as consumed in the U.S. in 2005 to allow comparisons with 
alternative transportation fuel options on the same basis (i.e., life 
cycle modeling assumptions, boundaries, and allocation procedures).'' 
Unlike GREET, the NETL study utilized site-specific data, such as 
country-specific crude oil extraction profiles and port-to-port travel 
distances for imported crude oil and petroleum products. The NETL model 
also accounts for NGLs and unfinished oils as refinery inputs, which is 
not available in GREET.
    Thus, we believe that use of the NETL model addresses the 
commenters' concerns with the GREET inputs used in the proposed rule. 
We have also verified that the NETL model uses a crude oil input mix 
and gasoline and diesel product slate consistent with EIA data for 
2005.
    For the final rule, we have also updated the CO2 
emissions factors to be consistent with other EPA rulemakings. EPA 
recently revised the CO2 emission factors for gasoline and 
diesel and used them in the September 28, 2009 proposed rule to 
establish GHG standards for light-duty vehicles. These new factors are 
slightly lower than those used in the RFS2 proposal and result in a 
decrease in tailpipe GHG emissions of 0.4% for gasoline of 0.6% and for 
diesel.
    Overall, with the switch to NETL and the updated tailpipe values, 
the final petroleum baseline value calculated for the final rule 
analysis does not differ significantly from what we calculated in the 
proposed rule.
    Inclusion of estimate for land use change: Numerous commenters 
raised the issue of land use change with regard to oil production, both 
on a direct and indirect basis. The proposed rule analysis for baseline 
petroleum emissions did not consider any land use change emissions 
associated with crude oil extraction. For the final rule, we do not 
consider land use emissions associated with road or other 
infrastructure construction for petroleum extraction, transport, 
refining, or upgrading, as the land use change associated with roads 
constructed for crop and livestock production was also not included. 
Furthermore, land use associated with natural gas extracted for use in 
oil sands extraction or upgrading was also not considered, as the land 
use change from natural gas extracted for biofuels production was not 
considered.
    However, for the final rule we did consider the inclusion of land 
use emissions associated with oil extraction. Using estimates for land-
use change from conventional oil production and oil sands in 
conjunction with our data for the carbon intensity of land being 
developed, we were able to determine GHG emissions associated with land 
use change for oil production. Our analysis showed that the value was 
negligible compared to the full petroleum lifecycle. More detail on 
this analysis can be found in Chapter 2 of the RIA.
    Consideration of marginal impacts: We received several comments 
stating that we did not use consistent system boundaries in our 
comparisons of biofuels and petroleum-based fuels, in particular by 
using a marginal assessment of GHG emissions related to biofuel, but 
not doing so for baseline petroleum fuels. According to commenters, by 
not assessing the marginal impacts of petroleum production, we 
overestimated the GHG impacts of an increase in biofuel use in the 
proposed rule. Commenters argued that a consistent modeling approach 
would involve a marginal analysis for both biofuels and the petroleum 
baseline.
    The reason the system boundaries used for threshold assessment in 
the proposed rule and the final rule did not include a marginal 
analysis of petroleum production was due to the definition of 
``baseline lifecycle greenhouse gas emissions'' in Section 211(o)(1)(C) 
of the CAA. The definitions of the different renewable fuel categories 
specify that the lifecycle threshold analysis be compared to baseline 
lifecycle greenhouse gas emissions, which are defined as:

    The term `baseline lifecycle greenhouse gas emissions' means the 
average lifecycle greenhouse gas emissions, as determined by the 
Administrator, after notice and opportunity for comment, for 
gasoline or diesel (whichever is being replaced by the renewable 
fuel) sold or distributed as transportation fuel in 2005.

    Therefore, the petroleum production component of the system 
boundaries is specifically mandated by EISA to be based on the 2005 
average for crude oil used to make gasoline or diesel sold or 
distributed as transportation fuel, and not the marginal crude oil that 
will be displaced by renewable fuel. Furthermore, as the EISA language 
specifies that the baseline emissions are to be only ``average'' 
lifecycle emissions for this single specified year and volume, it does 
not allow for a comparison of alternative scenarios. Indirect effects 
can only be determined using such an analysis; therefore there are no 
indirect emissions to include in the baseline lifecycle greenhouse gas 
emissions.
    On the other hand, assessing the lifecycle GHG emissions of 
renewable fuel is not tied by statute to the 2005 baseline and could 
therefore be based on a marginal analysis of anticipated changes in 
transportation fuel as would result from meeting the EISA mandates.

[[Page 14785]]

    Thus, Congress did not, as many commenters suggested, intend to 
accomplish simply a reduction in GHG emissions as compared to the 
situation that would exist in the future without enactment of EISA, as 
would be the case if Congress had specified that EPA use a marginal 
analysis in assessing the GHG emissions related to conventional 
baseline fuels that the EISA-mandated biofuels would replace. Rather, 
the statute specifies a logical approach for reducing the GHG emissions 
of transportation fuel as compared to those emissions that occurred in 
2005. Therefore, EPA has retained in today's final rule the basic 
analytical approach (marginal analysis for biofuels and 2005 average 
for baseline fuels) used in the proposed rule.

C. Threshold Determination and Assignment of Pathways

    As required by EISA, EPA is making a determination of lifecycle GHG 
emission threshold compliance for the range of pathways likely to 
produce significant volumes of biofuel for use in the U.S. by 2022. 
These threshold assessments only pertain to biofuels which are not 
produced in production facilities that are grandfathered 
(grandfathering of production facilities is discussed at the end of 
Section V.C).
    As described in Section I.A.3, because of the inherent uncertainty 
and the state of the evolving science on this issue, EPA is basing its 
GHG threshold compliance determinations for this rule on an approach 
that considers the weight of evidence currently available. For fuel 
pathways with a significant land use impact, the evidence considered 
includes the best estimate as well as the range of possible lifecycle 
greenhouse gas emission results based on formal uncertainty and 
sensitivity analyses conducted by the Agency. In making the threshold 
determinations for this rule, EPA weighed all of the evidence available 
to it, while placing the greatest weight on the best estimate value for 
the base yield scenario. In those cases where the best estimate for the 
potentially conservative base yield scenario exceeds the reduction 
threshold, EPA judges that there is a good basis to be confident that 
the threshold will be achieved and is determining that the bio-fuel 
pathway complies with the applicable threshold. To the extent the 
midpoint of the scenarios analyzed lies further above a threshold for a 
particular biofuel pathway, we have increasingly greater confidence 
that the biofuel exceeds the threshold.
    EPA recognizes that the state of scientific knowledge in this area 
is continuing to evolve, and that as the science evolves, the lifecycle 
greenhouse gas assessments for a variety of fuel pathways will continue 
to change. Therefore, while EPA is making regulatory determinations for 
fuel pathways as required by the statute in this final rule based on 
its current assessment, EPA is at the same time committing to further 
reassess these determinations and the lifecycle estimates. As part of 
the ongoing effort, we will ask for the expert advice of the National 
Academy of Sciences as well as other experts and then reflect this 
advice and any updated information in a new assessment of the lifecycle 
GHG emission performance of the biofuels being evaluated today. EPA 
will request that the National Academy of Sciences evaluate the 
approach taken in this rule, and the underlying science of lifecycle 
assessment and in particular indirect land use change, and make 
recommendations for subsequent rulemakings on this subject. This new 
assessment could in some cases result in new determinations of 
threshold compliance compared to those included in this rule which 
would apply to future production from plants that are constructed after 
each subsequent rule.
    Nonetheless, EPA is required by EISA to make threshold 
determinations at this time as to what fuels qualify for each of the 
four different fuel categories and lifecycle GHG thresholds. In the 
previous sections, we have described the analytical basis EPA is using 
for its lifecycle GHG assessment. These analyses represent the most up 
to date information currently available on the GHG emissions associated 
with each element of the full lifecycle assessment. Notably these 
analyses include an assessment of uncertainty for key parameters of the 
pathways evaluated. The best estimates and ranges of results for the 
different pathways can be used to help assess whether a particular 
pathway should be considered as attaining the 20%, 50% or 60% 
thresholds, as applicable. The graphs included in the discussion below 
provide representative depictions of the results of our analysis 
(including the uncertainty in the modeling) for typical pathways for 
corn ethanol, biodiesel produced from soy oil and from waste oils, fats 
and greases, sugarcane ethanol and cellulosic biofuel from switchgrass. 
We have also conducted lifecycle modeling assessments for cellulosic 
biofuel pathways using other feedstock sources, for biobutanol and for 
two specific pathways for emerging biofuels that would use oil from 
algae as their feedstock. Additional GHG performance assessment results 
for other feedstock/fuel/technology combinations are also described 
below as well as in the RIA Chapter 2.
    Below we consider the analytical results of scenarios and fuel 
pathways modeled by EPA as well as additional appropriate information 
to determine the threshold compliance for an array of biofuels likely 
to be produced in 2022.
    Ethanol from corn starch: While EPA analyzed the lifecycle GHG 
performance of a variety of ethanol from corn starch pathways (complete 
results can be found in the RIA), for purposes of this threshold 
determination we have focused the discussion on the impacts of those 
plant designs that are most likely to be built in the future. We have 
focused this discussion on new plant designs because production from 
existing plants is grandfathered for purposes of compliance with the 
20% lifecycle GHG threshold. Only new plants and expanded capacity at 
existing plants need to comply with a 20% lifecycle GHG emissions 
threshold to comply with the total renewable fuel mandate under the 
RFS2.
    While we focus our lifecycle GHG threshold analysis on the new 
plant designs most likely to be built through 2022, we also note that 
some existing plant designs, although subject to the grandfathering 
provisions, would not qualify if having to meet the 20% performance 
threshold. For example, existing designs of ethanol plants using coal 
as their process heat source would not qualify.
    As discussed in Section IV, EPA anticipates that by 2022 any new 
dry mill plants producing ethanol from corn starch will be equipped 
with more energy efficient technology and/or enhanced co-product 
production than today's average plant. These predictions are largely 
based on economic considerations. To compete economically, future 
ethanol plants will need to employ energy saving technologies and other 
value added technologies that have the effect of also reducing their 
GHG footprint. For example, while only in limited use today, we predict 
approximately 90% of all plants will be producing corn oil as a by-
product either through a fractionation or extraction process; it is 
likely most if not all new plants will elect to include such 
technology. We also predict that all will use natural gas, biomass or 
biogas as the process energy

[[Page 14786]]

source.180 181 We also expect that, to lower their operating 
costs, most facilities will sell a portion of their co-product DGS 
prior to drying thus reducing energy consumption and improving the 
efficiency and lifecycle GHG performance of the plant. The current 
national average plant sells approximately 37% of the DGS co-product 
prior to drying.
---------------------------------------------------------------------------

    \180\ Dry mill corn ethanol plants using coal as a process 
energy source would not qualify as exceeding the 20% reduction 
threshold as modeled. We do not expect plants relying on coal for 
process energy to be built through 2022. However, if they were 
built, they would need to use technology improvements such as carbon 
capture and storage (CCS) technology. We did not model what the 
performance would be if these plants also installed CCS technology.
    \181\ We do not believe new wet mill corn ethanol plants will be 
built through 2022 since this design is much more complicated and 
expensive than a dry mill plant. Especially since dry mill plants 
equipped with corn oil fractionation will produce additional 
supplies of food grade corn oil (one of the products and therefore 
reasons to construct a wet mill plant), we see no near term 
incentive for additional wet mill ethanol production capacity. 
However, we have modeled the lifecycle GHG impact of ethanol 
produced at a wet mill plant when relying on biomass as the process 
energy source and have determined it would meet the 20% GHG 
threshold. Therefore, this type of facility is also included in 
Table V.C-6.
---------------------------------------------------------------------------

    In analyzing the corn ethanol plant designs we expect could be 
built through 2022 using natural gas or biomass for process energy and 
employing advanced technology, in all cases, the midpoint and therefore 
the majority of the scenarios analyzed are above the 20% threshold. 
This indicates that, based on the current modeling approaches and sets 
of assumptions, we are over 50% confident the actual GHG performance of 
the ethanol from new corn ethanol plants will exceed the threshold of 
20% improvement in lifecycle GHG emissions performance compared to the 
gasoline it is replacing.
    We are determining at this time that the corn ethanol produced at 
such new plants (and existing plants with expanded capacity employing 
the same technology) will exceed the 20% GHG performance threshold. A 
complete listing of complying facilities using advanced technologies 
and operating procedures is included in Table V.C-6.
    Figure V.C-1 shows the percent change in the lifecycle GHG 
emissions compared to the petroleum gasoline baseline in 2022 for a 
corn ethanol dry mill plant using natural gas for its process energy 
source, drying the national average of 63% of the DGS it produces and 
employing corn oil fractionation technology. Lifecycle GHG emissions 
equivalent to the gasoline baseline are represented on the graph by the 
zero on the X-axis. The 20% reduction threshold is represented by the 
dashed line at -20 on the graph. The results for this corn ethanol 
scenario are that the midpoint of the range of results is a 21% 
reduction in GHG emissions compared to the gasoline 2005 baseline. The 
95% confidence interval around that midpoint ranges from a 7% reduction 
to a 32% reduction compared to the gasoline baseline.

[[Page 14787]]

[GRAPHIC] [TIFF OMITTED] TR26MR10.424

    Table V.C-1 below includes lifecycle GHG emissions broken down by 
several stages of the lifecycle impacts for a natural gas dry mill corn 
ethanol facility as compared to the 2005 baseline average for gasoline. 
This table (and similar tables which follow in the discussion for other 
biofuels) is included to transparently demonstrate the contribution of 
each stage and their relative significance. Lifecycle emissions are 
normalized per energy unit of fuel produced and presented in kilograms 
of carbon-dioxide equivalent GHG emissions per million British Thermal 
Units of renewable fuel produced (kg CO2e/mmBTU). The 
domestic and international agriculture rows include emissions from 
changes in agricultural production (e.g., fertilizer and energy use, 
rice methane) and livestock production. The fuel production row 
includes emissions from the fuel production or refining facility, 
primarily from energy consumption. For renewable fuels, tailpipe 
emissions only include non-CO2 gases, because the carbon 
emitted as a result of fuel combustion is offset by the uptake of 
biogenic carbon during feedstock production. Note, that while the table 
separates the emissions into different categories, the results are 
based on integrated modeling; therefore, one component can not be 
removed without impacting the other results. For example, domestic land 
use and agricultural sector emissions depend on the international 
assumptions. If a case without international impacts were modeled, the 
domestic results would likely be significantly different.
    The table includes our mean estimate of international land use 
change emissions as well as the 95% confidence range from our 
uncertainty assessment, which accounts for uncertainty in the types of 
land use changes and the magnitude of resulting GHG emissions. The last 
row includes mean, low and high total lifecycle GHG emissions based on 
the 95% confidence range for land use change emissions. For the 
petroleum baseline, the fuel production stage includes emissions from 
extraction, transport, refining and distribution of petroleum 
transportation fuel. Petroleum tailpipe emissions include 
CO2 and non-CO2 gases emitted from fuel 
combustion.

[[Page 14788]]



       Table V.C-1--Lifecycle GHG Emissions for Corn Ethanol, 2022
                             [kg CO2e/mmBTU]
------------------------------------------------------------------------
                                                                 2005
             Fuel type                       Ethanol           Gasoline
                                                               baseline
------------------------------------------------------------------------
Fuel Production Technology.........  Natural Gas Fired Dry   ...........
                                      Mill.
Net Domestic Agriculture (w/o land   4.....................  ...........
 use change).
Net International Agriculture (w/o   12....................  ...........
 land use change).
Domestic Land Use Change...........  -2....................  ...........
International Land Use Change, Mean  32 (21/46)............  ...........
 (Low/High).
Fuel Production....................  28....................           19
Fuel and Feedstock Transport.......  4.....................  ...........
Tailpipe Emissions.................  1.....................           79
                                    ------------------------------------
Total Emissions, Mean (Low/High)...  79 (54/97)............           98
------------------------------------------------------------------------

    While we are projecting technology enhancements which would allow 
corn ethanol plants to exceed the threshold, plant designs which do not 
include such advanced technology would not comply. For example, a basic 
plant which is not equipped with combinations of advanced technologies 
such as corn oil fractionation or dries more than 50% of its DGS is 
predicted to not comply. While we do not expect such a basic, low 
technology plant to be built nor existing plants to expand their 
production without also installing such advanced technology, if this 
were to occur, ethanol produced at such facilities would not comply 
with the 20% threshold.
    Biodiesel from soybean oil: We analyzed the lifecycle GHG emission 
impacts of producing biodiesel using soy oil as a feedstock for 
compliance with a lifecycle GHG performance threshold of 50%. The 
modeling framework for this analysis was much the same as used for the 
proposal. However, as noted above, based on comments, updated 
information and enhanced models, the results are significantly updated.
    As in the case of ethanol produced from corn starch, EPA has relied 
on a weight of evidence in developing its threshold assessment for 
biodiesel produced from soybean oil. In analyzing the base yield case, 
the midpoint and therefore the majority of the scenarios analyzed 
exceed the threshold. This indicates that based on currently available 
information and our current analysis over the range of scenarios 
considered, the actual performance of soy oil-based biodiesel likely 
exceeds the applicable 50% threshold.
    The scenarios analyzed also indicate, based on current data, we are 
at least 95% confident biodiesel produced from soy oil will have GHG 
impacts which are better than the 2005 baseline diesel fuel. From a GHG 
impact perspective, we therefore conclude that even in the less likely 
event the actual performance of biodiesel from soy oil does not exceed 
the 50% threshold, GHG emission performance of transportation fuel 
would still improve if this biodiesel replaced diesel fuel.
    We are further confident that biodiesel exceeds the 50% threshold 
since our assessment of biodiesel GHG performance does not include any 
prediction of significant improvements in plant technology or 
unanticipated energy saving improvements that would further improve GHG 
performance. Additionally, our assumption that the co-product of 
glycerin would only have GHG value as replacement for residual heating 
oil could be conservative. While we have not analyzed the range of 
potential uses of glycerin, potential uses of glycerin including as a 
feedstock to the chemical industry could be higher in GHG benefit than 
its assumed use as a heating fuel.
    Considering all of the above current information and analyses, EPA 
concludes that biodiesel made from soy oil will exceed its lifecycle 
GHG threshold. Further, we see no benefit in lowering the threshold to 
as low as 40% as allowed under EISA as this will neither benefit 
available supply nor GHG performance of the fuel. Therefore, the 
threshold for this rule will be maintained at 50%.
    Figure V.C-2 shows the percent change in the typical 2022 soybean 
biodiesel lifecycle GHG emissions compared to the petroleum diesel fuel 
2005 baseline. Lifecycle GHG emissions equivalent to the diesel fuel 
baseline are represented on the graph by the zero on the X-axis. The 
50% reduction threshold is represented by the dashed line at -50 on the 
graph. The results for soybean biodiesel are that the midpoint of the 
range of results is a 57% reduction in GHG emissions compared to the 
diesel fuel baseline. The 95% confidence interval around that midpoint 
results in range of a 22% reduction to an 85% reduction compared to the 
diesel fuel 2005 baseline.

[[Page 14789]]

[GRAPHIC] [TIFF OMITTED] TR26MR10.425

    Biodiesel from waste oils, fats and greases: The lifecycle 
assessment of GHG performance for biodiesel produced from waste oils, 
fats and greases is much simpler than comparable assessments for 
biofuels made from crops. In the case of biodiesel made from waste 
material, there is no land use impact so the agricultural assessments 
required for crop-based biofuels are unnecessary. Without the 
uncertainty concerns due to land use impacts, there was no need to 
conduct an uncertainty analysis for biodiesel from waste oils, fats and 
greases. The assessment methodology for biofuel from waste oils fats 
and greases is much the same as that analyzed for the proposal. As was 
the case for the proposal, the assessment of each element in the 
lifecycle process is straight forward and includes collecting and 
transporting the feedstock, transforming it into a biofuel and 
distributing and using the fuel. Based on the lifecycle assessment for 
this final rule, we are estimating biofuel from waste oils, fats and 
greases result in an 86% reduction in GHG emissions compared to the 
2005 baseline for petroleum diesel. As was the case for the assessment 
included in the proposal, biofuel from these feedstock sources easily 
exceeds the applicable threshold of 50%.
    Table V.C-2 below breaks down by stage the lifecycle GHG emissions 
for soy-based biodiesel, biodiesel from waste grease feedstocks and the 
2005 diesel baseline. The average 2022 biodiesel production process 
reflected in this table assumes that natural gas is used for process 
energy and accounts for co-product glycerin displacing residual oil. 
This table demonstrates the contribution of each stage and their 
relative significance.

                            Table V.C-2--Lifecycle GHG Emissions for Biodiesel, 2022
                                                 [kg CO2e/mmBTU]
----------------------------------------------------------------------------------------------------------------
                                                                     Soy-based     Waste grease     2005 Diesel
                            Fuel type                                biodiesel       biodiesel       baseline
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change)..................             -10               0  ..............
Net International Agriculture (w/o land use change).............               1               0  ..............
Domestic Land Use Change........................................              -9               0  ..............
International Land Use Change,..................................      43 (15/76)               0  ..............
Mean (Low/High).................................................

[[Page 14790]]

 
Fuel Production.................................................              13              10              18
Fuel and Feedstock Transport....................................               3               3  ..............
Tailpipe Emissions..............................................               1               1              79
                                                                 -----------------------------------------------
Total Emissions, Mean...........................................      42 (14/76)              14              97
(Low/High)......................................................
----------------------------------------------------------------------------------------------------------------

    Biodiesel from algae oil: We analyzed the lifecycle GHG emission 
impacts of producing biodiesel from algae oil as a feedstock for 
compliance with a lifecycle performance threshold of 50%. Our analyses 
were based on technoeconomic modeling completed by NREL, as previously 
discussed. The NREL modeling included algae cultivation, harvesting, 
extraction, and recovery of algae oil. Algae oil is further assumed to 
use the same oil to biodiesel production technology as soy oil, which 
was updated based on enhanced models. As algae are expected to be grown 
on relatively small amounts of non-arable lands, it is expected that 
the land use impact will be negligible. Based on our current lifecycle 
assessment of algae oil for the final rule, we are determining that 
biodiesel from algae oil will comply with the lifecycle performance 
advanced biofuel threshold of 50%.
    Ethanol from sugarcane: As is the case for other crop-based 
biofuels, EPA considered the weight of evidence currently available 
information in assessing the lifecycle GHG performance of this fuel. As 
noted in Section I.A.3, this lifecycle GHG assessment includes 
significant updates from the analysis performed for the proposal. We 
have added pathways for sugarcane ethanol such that we now distinguish 
sugarcane ethanol produced assuming most crop residue (leaves and 
stalks) are collected and therefore available for burning as process 
energy, or sugarcane produced without the extra crop residue being 
collected nor burned as process energy. We also analyzed pathways 
assuming the ethanol is distilled in Brazil or alternatively being 
distilled in the Caribbean. We did not analyze a ``high yield'' case 
for sugarcane as we did for corn and soy since we had no information 
available suggesting there could be an appreciable range in expected 
sugarcane yields.
    Based on the currently available information, the midpoint and thus 
the majority of the scenarios analyzed exceed the 50% threshold 
applicable to advanced biofuels. This indicates that based on currently 
available information and our current analysis, it is more than 50% 
likely that the actual performance of ethanol produced from sugarcane 
exceeds the applicable 50% threshold.
    The analyses also indicate, based on current data, ethanol produced 
from sugarcane will clearly have GHG impacts which are better than the 
2005 baseline gasoline. From a GHG impact perspective, we therefore 
conclude that even in the less likely event the actual performance of 
sugarcane does not exceed the 50% threshold, GHG emission performance 
of ethanol from sugarcane would be better than gasoline.
    We also considered what would happen if we determine that ethanol 
from sugarcane does not comply with a 50% threshold due to the 
relatively low risk that this biofuel will actually be below that 
threshold. Based on our current analysis of available pathways for 
producing advanced biofuel, we believe that it will be necessary to 
include over 2 billion gallons of sugarcane ethanol in order to meet 
the advanced biofuel volumes anticipated by EISA. If sugarcane ethanol 
was not an eligible source of advanced biofuel and other unanticipated 
sources did not become available, the standard for advanced biofuel 
would have to be lower to the extent necessary to compensate for the 
lack of eligible sugarcane ethanol. The lower amount of advanced 
biofuel would then most likely be replaced with petroleum-based 
gasoline. The replacement fuel would have a worse GHG performance than 
the sugarcane ethanol. Therefore, GHG performance of the transportation 
fuel pool would suffer.
    Considering the above, EPA has concluded that, based on currently 
available information and our analysis, ethanol from sugarcane 
qualifies as an advanced biofuel.
    Figure V.C-3 shows the percent change in the average 2022 sugarcane 
ethanol lifecycle GHG emissions compared to the petroleum gasoline 2005 
baseline. These results assume the ethanol is produced and dehydrated 
in Brazil prior to being imported into the U.S. Lifecycle GHG emissions 
equivalent to the gasoline baseline are represented on the graph by the 
zero on the X-axis. The 50% reduction threshold is represented by the 
dashed line at -50 on the graph. The results for this sugarcane ethanol 
scenario are that the midpoint of the range of results is a 61% 
reduction in GHG emissions compared to the gasoline baseline. The 95% 
confidence interval around that midpoint results in a range of a 52% to 
71% reduction compared to the gasoline 2005 baseline.

[[Page 14791]]

[GRAPHIC] [TIFF OMITTED] TR26MR10.426

    Table V.C-3 below presents results for sugarcane ethanol production 
and use by lifecycle stage. This table demonstrates the contribution of 
each stage and their relative significance. The fuel production 
emissions include displacement of marginal Brazilian electricity 
because electricity is generated with the sugarcane bagasse co-product. 
As in similar previous tables, domestic emissions include all emissions 
sources in the United States, with all other emissions--including 
emissions from Brazil--presented in the international categories.

    Table V.C-3--Lifecycle GHG Emissions for Sugarcane Ethanol, 2022
                             [kg CO2e/mmBTU]
------------------------------------------------------------------------
                                            Sugarcane     2005 Gasoline
               Fuel type                     ethanol         baseline
------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use                0                0
 change)...............................
Net International Agriculture (w/o land              38                0
 use change)...........................
Domestic Land Use Change...............               1                0
International Land Use Change, Mean           4 (-5/12)                0
 (Low/High)............................
Fuel Production........................             -11               19
Fuel and Feedstock Transport...........               5                0
Tailpipe Emissions.....................               1               79
                                        --------------------------------
    Total Emissions, Mean (Low/High)...      38 (29/46)               98
------------------------------------------------------------------------

    Cellulosic Biofuels: In the proposal, we analyzed biochemical 
cellulosic ethanol pathways from both switchgrass and corn stover, and 
on that basis proposed that such cellulosic biofuels met the required 
60% lifecycle threshold by a considerable margin. As described in 
Section V.B, we have considerably updated our lifecycle analysis, and 
have analyzed additional cellulosic biofuel pathways (i.e., 
thermochemical cellulosic ethanol and a

[[Page 14792]]

BTL diesel pathway). We analyzed the GHG impacts of each element of the 
lifecycle for producing and using biofuels from cellulosic biomass, and 
as for other fuel pathways, considered the range of possible outcomes.
    Figure V.C-4 shows the percent change in the average lifecycle GHG 
emissions in 2022 for ethanol produced from switchgrass using the 
biochemical process compared to the petroleum gasoline 2005 baseline. 
Lifecycle GHG emissions equivalent to the gasoline baseline are 
represented on the graph by the zero on the X-axis. The 60% reduction 
threshold is represented by the dashed line at -60 on the graph. The 
results for this switchgrass ethanol scenario are that the midpoint of 
the range of results is a 110% reduction in GHG emissions compared to 
the gasoline baseline. The 95% confidence interval around that midpoint 
ranges from 102% reduction to a 117% reduction compared to the gasoline 
baseline.
[GRAPHIC] [TIFF OMITTED] TR26MR10.427

    Table V.C-4 below shows lifecycle GHG emissions for cellulosic 
ethanol produced from switchgrass (as depicted in Figure V.C-4, above) 
and also corn residue by lifecycle stage, comparing these to the 2005 
baseline gasoline. This table is included to demonstrate the 
contribution of each stage and their relative significance. Results are 
presented for the biochemical production technology depicted in Figure 
V.C-4 above and also for thermochemical production technologies. The 
fuel production emissions for the biochemical pathway include credit 
for excess electricity generation at the fuel production facility.

                                            Table V.C-4--Lifecycle GHG Emissions for Cellulosic Ethanol, 2022
                                                                     [kg CO2e/mmBTU]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                        Fuel type                                   Switchgrass ethanol                      Corn residue
--------------------------------------------------------------------------------------------------------------------------------------   2005 Gasoline
                Fuel production technology                    Bio-chemical     Thermo-chemical      Bio-chemical     Thermo-chemical        baseline
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change)...........                  6                  6                 11                 11                  0

[[Page 14793]]

 
Net International Agriculture (w/o land use change)......                  0                  0                  0                  0                  0
Domestic Land Use Change.................................                 -2                 -3                -11                -11                  0
International Land Use Change, Mean (Low/High)...........          15 (9/23)         16 1(9/24)                  0                  0                  0
Fuel Production..........................................                -33                  4                -33                  4                 19
Fuel and Feedstock Transport.............................                  3                  3                  2                  2                  0
Tailpipe Emissions.......................................                  1                  1                  1                  1                 79
                                                          ----------------------------------------------------------------------------------------------
    Total Emissions, Mean (Low/High).....................       -10 (-17/-2)         27 (20/35)                -29                  7                 98
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Table V.C-5 below presents lifecycle GHG emissions for cellulosic 
diesel produced with a Fischer-Tropsch process by lifecycle stage.

                        Table V.C-5--Lifecycle GHG Emissions for Cellulosic Diesel, 2022
                                                 [kg CO2e/mmBTU]
----------------------------------------------------------------------------------------------------------------
                     Fuel type                          Switchgrass     Corn residue diesel
----------------------------------------------------       diesel      ---------------------     2005 Diesel
                                                    -------------------                            baseline
             Fuel production technology                  F-T diesel          F-T diesel
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land use change).....                  6                   11                    0
Net International Agriculture (w/o land use change)                  0                    0                    0
Domestic Land Use Change...........................                 -3                  -11                    0
International Land Use Change, Mean (Low/High).....          16 (9/24)                    0                    0
Fuel Production....................................                  5                    5                   18
Fuel and Feedstock Transport.......................                  3                    2                    0
Tailpipe Emissions.................................                  1                    1                   79
                                                    ------------------------------------------------------------
    Total Emissions, Mean (Low/High)...............         29 (22/37)                    9                   97
----------------------------------------------------------------------------------------------------------------

    Based on the currently available information, we conclude that all 
modeled cellulosic biofuel pathways are expected to exceed the 60% 
threshold applicable to cellulosic biofuels.
    Assessments of similar feedstock sources: In the proposal, we 
indicated that although we did not specifically analyze all potential 
feedstock sources, some feedstock sources are similar enough to those 
modeled that we believe the modeled results could be extended to these 
similar feedstock types. Comments received supported this approach and 
the specific recommendations for similar feedstock designations as 
proposed.
    For this final rule, consistent with what was proposed, we are 
relying on modeling results and only expanding to additional pathways 
where we have good information these additional pathways will have 
lifecycle GHG results which either will not impact our overall 
assessment of the performance of that fuel pathway or would have at 
least as good as the modeled pathways. The agricultural sector modeling 
used for our lifecycle analysis does not predict any soybean biodiesel 
or corn ethanol will be imported into the U.S., or any imported 
sugarcane ethanol from production in countries other than Brazil. 
However, these rules do not prohibit the use in the U.S. of these fuels 
produced in countries not modeled if they are also expected to comply 
with the eligibility requirements including meeting the thresholds for 
GHG performance. Although the GHG emissions of producing these fuels 
from feedstock grown or biofuel produced in other countries has not 
been specifically modeled, we do not anticipate their use would impact 
our conclusions regarding these feedstock pathways. The emissions of 
producing these fuels in other countries could be slightly higher or 
lower than what was modeled depending on a number of factors. Our 
analyses indicate that crop yields for the crops in other countries 
where these fuels are also most likely to be produced are similar or 
lower than U.S. values indicating the same or slightly higher GHG 
impacts. Agricultural sector inputs for the crops in these other 
countries are roughly the same or lower than the U.S. pointing toward 
the same or slightly lower GHG impacts. If crop production were to 
expand due to biofuels in the countries where the models predict these 
biofuels might additionally be produced, this would tend to lower our 
assessment of international indirect impacts but could increase our 
assessment of the domestic (i.e., the country of origin) land use 
impacts. EPA believes, because of these offsetting factors along with 
the small amounts of fuel potentially coming from other countries, that 
incorporating fuels produced in other countries will not impact our 
threshold analysis. Therefore, fuels of the same fuel type, produced 
from the same feedstock using the same fuel production technology as 
modeled fuel pathways will be assessed the same GHG performance 
decisions regardless of country of origin.
    We are also able to conclude that some feedstock types not 
specifically modeled should be covered as we have good reason to 
believe their performance would be better than the feedstock pathways 
modeled. Thus for example, we can conclude that, as in the case of corn 
stover which we have modeled as a feedstock source, cellulosic biofuel 
produced from other agricultural waste will also have no land use 
impact and would be expected to

[[Page 14794]]

have lifecycle GHG emission impacts similar enough to the modeled corn 
stover feedstock pathway such that they would also comply. Similarly, 
we have information on miscanthus indicating that this perennial will 
yield more feedstock per acre than the modeled switchgrass feedstock 
without additional GHG inputs such as fertilizer. Therefore we are 
concluding that since cellulosic biofuel from switchgrass complies with 
the cellulosic threshold of 60% reduction, fuel produced using 
miscanthus and other perennial grasses will also surely comply.
    We are also determined that biofuel from separated yard and food 
wastes (which may contain incidental and post-recycled paper and wood 
wastes) satisfy biofuel thresholds. Separated food waste is largely 
starch-based and thus qualifies for the advanced biofuel standard of 
50% reduction. If the biofuel producer can demonstrate that it is able 
to quantify the cellulosic portion of food wastes, fuel made from the 
cellulosic portion can qualify as cellulosic biofuel. Since we have 
determined that yard wastes are largely cellulosic, biofuel from yard 
waste will qualify as cellulosic biofuel. The use of separated yard and 
food wastes for biofuel production including the requirements for 
demonstrating what portion of food waste is cellulosic feedstock is 
discussed further in Section II.B.4.d. EPA believes that renewable fuel 
produced from feedstocks consisting of wastes that would normally be 
discarded or put to a secondary use, and which have not been 
intentionally rendered unfit for productive use, should be assumed to 
have little or no land use emissions of GHGs. The use of wastes that 
would normally be discarded does not increase the demand for land. For 
example, the use in biofuel production of food waste from a food 
processing facility that would normally be placed in a landfill will 
not increase the demand for land to grow the crops that were purchased 
by the food processing facility. Similarly, wastes that would not 
normally be discarded because there are alternative secondary uses for 
them (for example contaminated vegetable oil might be burned in a 
boiler) are not produced for the purpose of such secondary use and the 
use of these feedstocks also does not increase demand for land. Since 
these waste-derived feedstocks have little or no land use impact, the 
lifecycle GHG emissions associated with their use for biofuel 
production are largely the result of the energy required to collect and 
process the feedstock prior to conversion, and the energy required to 
convert that feedstock into a biofuel. This has led us to conclude it 
is reasonable to include a restricted set of additional feedstocks in 
pathways complying with the applicable threshold.
    The look-up table identifies a number of individual fuel 
``pathways'' that allow for the use of waste feedstocks. These 
feedstocks include (1) waste ethanol from beverage production, (2) 
waste starches from food production and agricultural residues, (3) 
waste oils/fats/greases, (4) waste sugar from food and beverage 
production, and (5) food and beverage production wastes. For the 
purpose of this rule only, EPA will consider these feedstocks to be 
``wastes'' if they are used as feedstock to produce fuel, but would 
otherwise normally be discarded or used for another secondary purpose 
because they are no longer suitable for their original intended use. 
They may be unsuitable for their original intended use either because 
they are themselves waste from that original use (e.g., table scraps) 
or because of contamination, spoilage or other unintentional acts. EPA 
will not consider any material that has been intentionally rendered 
unsuitable for its original use to be a ``waste.''
    As discussed in more detail in Section II.B.4.d, EPA has also 
determined that the biogenic portion of post recycled MSW is eligible 
to produce renewable fuel and will largely be made up of cellulosic 
material. Therefore biofuel made from this waste-derived material will 
qualify as cellulosic biofuel.
    EPA has also considered biofuels produced from annual cover crops 
such as cover crops grown in the winter. These annual cover crops are 
normally planted as a rotation between primary planted crops or between 
trees and vines in orchards and vineyards, typically to protect soil 
from erosion, improve the soil between periods of regular crops, or for 
other conservation purposes. For annual cover crops grown on the same 
land as the primary crops, we have determined that there is little or 
no land use impact such that the GHG emissions associated with them 
would largely result due to inputs required to grow the crop, 
harvesting and transporting to the biofuel production facility, turning 
that feedstock into a biofuel and transporting it to its end use. As 
such, the biofuel from cellulosic biomass from annual cover crops are, 
for example, determined to meet requirements of cellulosic biofuel, oil 
from annual cover crops are determined to meet the requirements of 
renewable diesel and starches from annual cover crops are determined to 
meet the requirements of advanced biofuel.
    While we have not been able to model all possible feedstocks that 
can and are being used for renewable fuel production, there are a 
variety of feedstocks that should have similar enough characteristics 
to those already modeled to allow them to be grouped in with already 
modeled fuel pathways. In particular, as discussed below, there are 
five categories of biofuel feedstock sources for which we are 
confident, by virtue of their lack of any land-use change impact, in 
qualifying them for particular renewable fuel standards (D-codes) on 
the basis of our existing modeling.
    1. All crop residues which provide starch or cellulosic feedstock. 
By virtue of the fact that they do not cause any land-use change 
impacts, they should all have similar lifecycle GHG impacts. Thus, 
modeling conducted for corn stover is being extended to other crop 
residues such as wheat straw, rice straw, and citrus residue. These 
residues are what remains after a primary crop is harvested, and can be 
similarly collected, transported and used in biofuel production.
    2. Slash, forest thinnings, and forest residue providing cellulosic 
feedstock. As excess material, these represent another form of residue 
which should also result in no land-use change GHG impacts. Their GHG 
emission impacts would only be associated with collection, transport, 
and processing into biofuel. Consequently, modeling conducted for corn 
stover is also being extended to these residues.
    3. Annual cover crops planted on existing crop land such as winter 
cover crops and providing cellulosic material, starch or oil for 
biofuel production. While different from crop residues, these secondary 
crops also have no land use impact since they are planted on land 
otherwise used for primary crop production. GHG emissions would only be 
associated with growing, harvesting and transporting the secondary crop 
and then processing into biofuel. In the case of secondary crops that 
might be used for cellulosic biofuel production, they would also have 
no land-use change impact, and consequently modeling conducted for corn 
stover is also being extended to these crops. In the case of secondary 
crops used for oil production, they would then have no land-use change 
similar to waste fats, oils and greases. Consequently, modeling 
conducted for biodiesel and renewable diesel from these waste oils is 
also being extended to these annual cover crops.
    4. Separated food and yard wastes, including food and beverage 
wastes

[[Page 14795]]

from food production and processing are another category of waste 
product that would not have any land-use change impact. These waste 
products can be used as feedstock for advanced biofuel production or 
cellulosic biofuel production. Waste oils have already been modeled as 
complying with the biomass-based diesel standard. Applying our 
sugarcane results without the land-use change component to waste sugars 
clearly demonstrates compliance with the advanced biofuel threshold. 
Applying our corn results without the land-use component to waste 
starches clearly demonstrates compliance with the renewable fuel 
standard
    5. Perennial grasses including switchgrass and miscanthus. We 
modeled switchgrass and miscanthus has higher yield per acre without 
any significant (or perhaps less) inputs such as fertilizer per acre. 
We believe other perennial grasses likely to compete as feedstock 
sources will have similar land use and agricultural inputs are 
therefore confident the results from switchgrass can be extended to 
miscanthus and other perennial grasses. However, we note that the 
energy crop industry is just starting to develop and therefore as 
favored perennial grasses start to emerge, additional analyses may be 
warranted.
    Applicable D-Codes for Fuel Pathways: Based on the above, corn 
ethanol facilities using natural gas or biomass as the process energy 
source will meet the applicable 20% GHG performance threshold if it 
either also uses at least two of the technologies Table V.C-6 or one of 
the technologies in Table V.C-6 but marketing at least 35% of its DGS 
as wet. Alternatively, a facility using none of the advanced 
technologies listed in Table V.C-6 will qualify as producing ethanol 
meeting the 20% performance threshold if it sells at least 50% of its 
DGS prior to drying.

               Table V.C-6--Modeled Advanced Technologies
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
Corn oil fractionation
Corn oil extraction
Membrane separation
Raw starch hydrolysis
Combined heat and power
------------------------------------------------------------------------

    Following the criteria for D-Codes defined in Section II.A-1, the 
following renewable fuel pathways have been found to comply with the 
applicable lifecycle GHG thresholds and are therefore eligible for the 
D-Codes specified in Table V.C-7.

                                        Table V.C-7--D-Code Designations
----------------------------------------------------------------------------------------------------------------
                                                             Production process
             Fuel type                    Feedstock             requirements                  D-Code
----------------------------------------------------------------------------------------------------------------
Ethanol...........................  Corn starch..........  All of the following:  6 (renewable fuel)
                                                           Drymill process,
                                                            using natural gas,
                                                            biomass or biogas
                                                            for process energy
                                                            and at least two
                                                            advanced
                                                            technologies from
                                                            Table V.C-6).
Ethanol...........................  Corn starch..........  All of the following:  6 (renewable fuel)
                                                           Dry mill process,
                                                            using natural gas,
                                                            biomass or biogas
                                                            for process energy
                                                            and one of the
                                                            advanced
                                                            technologies from
                                                            Table V.C-6 plus
                                                            drying no more than
                                                            65% of the DGS it
                                                            markets annually.
Ethanol...........................  Corn starch..........  All of the following:  6 (renewable fuel)
                                                           Dry mill process,
                                                            using natural gas,
                                                            biomass or biogas
                                                            for process energy
                                                            and drying no more
                                                            than 50% of the DGS
                                                            it markets annually.
Ethanol...........................  Corn starch..........  Wet mill process       6 (renewable fuel)
                                                            using biomass or
                                                            biogas for process
                                                            energy.
Ethanol...........................  Starches from          Fermentation using     6 (renewable fuel)
                                     agricultural           natural gas, biomass
                                     residues; starches     or biogas for
                                     from annual cover      process energy.
                                     crops.
Biodiesel, and renewable diesel...  Soy bean oil;          One of the following:  4 (biomass-based diesel)
                                    Oil from annual cover  Trans-Esterification.
                                     crops.
                                    Algal oil............  Hydrotreating........
                                    Biogenic waste oils/   Excluding processes
                                     fats/greases;          that coprocess
                                                            renewable biomass
                                                            and petroleum.
                                    Non-food grade corn
                                     oil.
Biodiesel, and renewable diesel...  Soy bean oil;          One of the following:  5 (Advanced)
                                    Oil from annual cover  Trans-Esterification.
                                     crops.
                                    Algal oil............  Hydrotreating........
                                    Biogenic waste oils/   Includes only
                                     fats/greases;          processes that
                                                            coprocess renewable
                                                            biomass and
                                                            petroleum.
                                    Non-food grade corn
                                     oil.
Ethanol...........................  Sugarcane............  Fermentation (Any)...  5 (Advanced)
Ethanol...........................  Cellulosic Biomass     Any..................  3 (Cellulosic Biofuel)
                                     from agricultural
                                     residues, slash,
                                     forest thinnings,
                                     forest product
                                     residues, annual
                                     cover crops,
                                     switchgrass and
                                     miscanthus;
                                     cellulosic
                                     components of
                                     separated yard
                                     wastes; cellulosic
                                     components of
                                     separated food
                                     wastes; and
                                     cellulosic
                                     components of
                                     separated MSW.

[[Page 14796]]

 
Cellulosic Diesel, Jet Fuel and     Cellulosic Biomass     Any..................  7 (Cellulosic Biofuel or
 Heating Oil.                        from agricultural                             Biomass-Based Diesel)
                                     residues, slash,
                                     forest thinnings,
                                     forest product
                                     residues, annual
                                     cover crops,
                                     switchgrass and
                                     miscanthus;
                                     cellulosic
                                     components of
                                     separated yard
                                     wastes, cellulosic
                                     components of
                                     separated food
                                     wastes, and
                                     cellulosic
                                     components of
                                     separated MSW.
 Butanol..........................  Corn starch..........  Fermentation; dry       6 (renewable fuel)
                                                            mill using natural
                                                            gas, biomass or
                                                            biogas for process
                                                            energy.
Cellulosic Naphtha................  Cellulosic Biomass     Fischer-Tropsch        3 (Cellulosic Biofuel)
                                     from agricultural      process.
                                     residues, slash,
                                     forest thinnings,
                                     forest product
                                     residues, annual
                                     cover crops,
                                     switchgrass and
                                     miscanthus;
                                     cellulosic
                                     components of
                                     separated yard
                                     wastes, cellulosic
                                     components of
                                     separated food
                                     wastes, and
                                     cellulosic
                                     components of
                                     separated MSW.
Ethanol, renewable diesel, jet      The non-cellulosic     Any..................  5 (Advanced)
 fuel, heating oil, and naphtha.     portions of
                                     separated food
                                     wastes.
Biogas............................  Landfills, sewage and  Any..................  5 (Advanced)
                                     waste treatment
                                     plants, manure
                                     digesters.
----------------------------------------------------------------------------------------------------------------

    Pathways for which we have not made a threshold compliance 
decision: The pathways identified in the Table V.C-6 represent those 
pathways we have analyzed and determined meet the applicable thresholds 
as establish by EISA. We did not analyze all pathways that might be 
feasible through 2022. In some cases, we did not have sufficient time 
to complete the necessary lifecycle GHG impact assessment for this 
final rule. In addition to the pathways identified in Table V.C-6, EPA 
anticipates modeling grain sorghum ethanol, woody pulp ethanol, and 
palm oil biodiesel after this final rule and including the 
determinations in a rulemaking within 6 months. Based on current and 
projected commercial trends and the status of current analysis at EPA, 
biofuels from these three pathways are either currently being produced 
or are planned production in the near-term. Our analyses project that 
they will be used in meeting the RFS2 volume standard in the near-term. 
During the course of the NPRM comment period, EPA received detailed 
information on these pathways and is currently in the process of 
analyzing these pathways. We have received comments on several 
additional feedstock/fuel pathways, including rapeseed/canola, 
camelina, sweet sorghum, wheat, and mustard seed, and we welcome 
parties to utilize the petition process described below to request EPA 
to examine additional pathways.
    In other cases, we have not modeled the lifecycle GHG performance 
of pathways because we did not have sufficient information. For those 
fuel pathways that are different than those pathways EPA has listed in 
today's regulations, EPA is establishing a petition process whereby a 
party can petition the Agency to consider new pathways for GHG 
reduction threshold compliance. The petition process is meant for 
parties with serious intention to moved forward with production via the 
petitioned fuel pathway and who have moved sufficiently forward in the 
business process to show feasibility of the fuel pathway's 
implementation. The Agency will not consider frivolous petitions with 
insufficient information and clarity for Agency analysis. In addition, 
if the petition addresses a fuel pathway that already complies for one 
or more types of renewable fuels under RFS (e.g., renewable fuel or 
advanced biofuel), the pathway must have the potential to result in the 
pathway qualifying for a new renewable fuel category for which it was 
not previously qualified. Thus, for example, the Agency will not 
undertake any additional review for a party wishing to get a modified 
LCA value for a previously approved fuel pathway if the desired new 
value would not change the overall pathway classification. EPA will 
process these petitions as expeditiously as possible, taking into 
consideration that some fuel pathways are closer to the commercial 
production stage than others. In all events, parties are expected to 
begin this process with ample lead time as compared to their commercial 
start dates.
    In addition to the technical information described below and listed 
in today's regulations (see Sec.  80.1416), a petition must include all 
information required in the registration process except the engineering 
review. The petition should demonstrate technical and commercial 
feasibility. For example, a petition could include copies of 
applications for air or construction permits, copies of blue prints of 
the facility, or photographs of the facility or pilot plant. The 
petition must include information necessary to allow EPA to effectively 
determine the lifecycle green house gas emissions of the fuel. The 
petitioner must describe the alternative production facility technology 
applied and supply data establishing the energy savings that will 
result from the use of the alternative technology. The information 
required would include, at a minimum, a mass and energy balance for the 
proposed fuel production process. This would include for example, mass 
inputs of raw material feedstocks and consumables, mass outputs of fuel 
product produced as well as co-products and waste materials production. 
Energy inputs information should include fuels used by type, including 
purchased electricity. If steam or hot water is purchased, the source 
and fuel required for its generation would also be reported.

[[Page 14797]]

Energy output information should include energy content of the fuel 
product produced (with heating value specified) as well as energy 
content of any co-products. The petitioner should also report the 
extent to which excess electricity is generated and distributed outside 
the production facility. Information on co-products should include the 
expected use of the co-products and their market value. All information 
should be provided in a format such that it can be normalized on a fuel 
output basis (for example, tons feedstock per gallon of fuel produced). 
Other process descriptions necessary to understand the fuel production 
process should be included (e.g., process modeling flowcharts). Any 
other relevant information, including that pertaining to energy saving 
technologies or other process improvements that document significant 
differences between the fuel production processes outlined in this rule 
and that used by the renewable fuel producer, should also be submitted 
with the petition.
    For fuel pathways that utilize feedstocks that have not yet been 
modeled for this rulemaking, the petition must also submit information 
on the feedstock. Information would include, at a minimum, the 
feedstock type and feedstock production source and data on the market 
value of the feedstock and current uses of the feedstock, if any. The 
petition should also include chemical input requirements (e.g., 
fertilizer, pesticides, etc.) and energy use in feedstock production 
listed by type of energy. Yield information would also be required for 
both the current yields of the feedstock as well as anticipated changes 
in feedstock yields over time.
    EPA will use the data supplied in the petition and other data and 
information available to the Agency to technically evaluate whether the 
information is sufficient for EPA to make a determination of the RFS 
standards for which the fuel pathway may qualify. If EPA determines 
that the petition is insufficient for determination, the petitioner 
will be so notified. If EPA determines it has been provided sufficient 
data from the petitioner to evaluate the fuel pathway, we will then 
proceed with any analyses required to make a technical determination of 
compliance.
    EPA anticipates that for some petitioned fuel pathways with unique 
modifications or enhancements to production technologies of pathways 
otherwise modeled for the regulations listed today, EPA may be able to 
evaluate the pathway as a reasonably straight-forward extension of our 
current assessments. We expect such a determination would be pathway 
specific, and would be based on a technical analysis that compared the 
applicant fuel pathway to the fuel to pathway(s) that had already been 
analyzed. In these cases, EPA would be able to make a determination 
without proceeding through a full rulemaking process. For example, 
petitions may submit unique biofuel production facility configurations, 
operations, or co-product pathways that could result in greater 
efficiencies than the pathways modeled for this rulemaking, but 
otherwise do not differ greatly from the modeled fuel pathways. In such 
cases, we would expect to make a decision for that specific pathway 
without conducting a full rulemaking process. We would expect to 
evaluate whether the pathway is consistent with the definitions of 
renewable fuel types in the regulations, generally without going 
through rulemaking, and issue an approval or disapproval that applies 
to the petitioner. We anticipate that we will subsequently propose to 
add the pathway to the regulations.
    If EPA determines that a petitioned fuel pathway requires 
significant new analysis and/or modeling, EPA will need to give notice 
and seek public comment. For example, we anticipate that pathways with 
feedstocks or fuel types not yet modeled by EPA will require additional 
modeling and public comment before a determination of compliance can be 
made. In these cases, the determination would be incorporated into the 
annual rulemaking process established in today's regulations.
    When EPA makes a technical determination is made that a petitioned 
fuel pathway qualifies for a RFS volume standard, a D-code will be 
assigned to the fuel pathway. We anticipate that renewable fuel 
producers and importers will be able to generate RINs for the 
additional pathway after the next available update of the EPA Moderated 
Transaction System (EMTS) that follows a determination. EPA expects to 
update the EMTS quarterly, as long as necessary. Renewable fuel 
producers will be able to register the fuel pathway through the EPA 
Fuels Programs Registration System two weeks after the date of 
determination, but as described above, will not be able to generate 
RINs until the quarterly EMTS update.
    In the proposal, we suggested a system of temporary D-codes for 
biofuel pathways we had not analyzed. This was proposed as a means of 
assuring no undue hardship for biofuel producers using feedstock 
sources or processing technologies not analyzed by EPA. As proposed, 
these producers could market their fuel on the basis of temporarily 
assigned D-codes. While the objective was sound, EPA now believes it is 
best to properly assure compliance with thresholds on the basis of 
completed lifecycle GHG assessments. As noted above, the Agency commits 
to expedited assessment and rulemaking for those pathways most likely 
to generate biofuel in the immediate future, including ethanol produced 
from grain sorghum, ethanol, woody pulp ethanol, and palm oil 
biodiesel. We also plan to continue to model additional pathways we 
expect will be commercially available in the U.S. as soon as sufficient 
information is available to complete a quality lifecycle assessment. 
For these reasons, EPA is not finalizing a provision for assigning 
temporary D-codes.

D. Total GHG Reductions

    Similar to the analysis done in our proposal, our analysis of the 
overall GHG emission impacts of increased volumes of renewable fuel was 
performed in parallel with the lifecycle analysis performed to develop 
the individual fuel thresholds described in previous sections. The same 
sources of emissions apply such that this analysis includes the effects 
of three main areas: (a) Emissions related to the production of 
biofuels, including the growing of feedstock (corn, soybeans, etc.) 
with associated domestic and international land use change impacts, 
transport of feedstock to fuel production plants, fuel production, and 
distribution of finished fuel; (b) emissions related to the extraction, 
production and distribution of petroleum gasoline and diesel fuel that 
is replaced by use of biofuels; and (c) difference in tailpipe 
combustion of the renewable and petroleum based fuels.
    The main difference between the results of the proposal analysis 
and the final rule analysis are higher domestic land use change 
emissions in the final rule analysis. As was the case in the proposal, 
simply adding up the individual lifecycle results determined in Section 
V.C. multiplied by their respective volumes would yield a different 
assessment of the overall impacts. The two analyses are separate in 
that the overall impacts capture interactions between the different 
fuels that can not be broken out into per fuels impacts, while the 
threshold values represent impacts of specific fuels but do not account 
for all the interactions.
    While individual fuel analysis generally had small domestic land 
use change emission impacts, the overall impacts had larger domestic 
land use change emissions. The primary reason

[[Page 14798]]

for the difference in domestic land use change between the individual 
fuel scenarios and the combined fuel scenarios is that when looking at 
individual fuels there is some interaction between different crops 
(e.g., corn replacing soybeans), but with combined volume scenario when 
all mandates need to be met there is less opportunity for crop 
replacement (e.g., both corn and soybean acres needed) and therefore 
more land is required.
    As discussed in previous sections on lifecycle GHG thresholds there 
is an initial one time release from land conversion and smaller ongoing 
releases, but there are also ongoing benefits of using renewable fuels 
over time replacing petroleum fuel use. Based on the volume scenario 
considered, the one time land use change impacts result in 313 million 
metric tons of CO2-eq. emissions increase. There are, 
however, based on the biofuel use replacing petroleum fuels, GHG 
reductions in each year. Totaling the emissions impacts over 30 years 
but assuming a 0% discount rate over this 30 year period would result 
in an estimated total NPV reduction in GHG emissions of 4.15 billion 
tons over 30 years.
    This total NPV reduction can be converted into annual average GHG 
reductions, which can be used for the calculations of the monetized GHG 
benefits as shown in Section VIII.C.3. This annualized value is based 
on converting the lump sum present values described above into their 
annualized equivalents. A comparable value assuming 30 years of GHG 
emissions changes, but not applying a discount rate to those emissions 
results in an estimated annualized average emission reduction of 
approximately 138 million metrics tons of CO2-eq. emissions.
    We also considered the uncertainty in the international land use 
change emission estimates for the overall impacts. Based on the range 
of results for the international land use change emissions the overall 
annualized average emission reductions of increased volumes of 
renewable fuel could range from -136 to -140 million metrics tons of 
CO2-eq. emissions.

E. Effects of GHG Emission Reductions and Changes in Global Temperature 
and Sea Level

    The reductions in CO2 and other GHGs associated with 
increased volumes of renewable fuel will affect climate change 
projections. GHGs mix well in the atmosphere and have long atmospheric 
lifetimes, so changes in GHG emissions will affect future climate for 
decades to centuries. Two common indicators of climate change are 
global mean surface temperature and global mean sea level rise. This 
section estimates the response in global mean surface temperature and 
global mean sea level rise projections to the estimated net global GHG 
emissions reductions associated with increased volumes of renewable 
fuel.
    EPA estimated changes in projected global mean surface temperatures 
to 2050 using the MiniCAM (Mini Climate Assessment Model) integrated 
assessment model \182\ coupled with the MAGICC (Model for the 
Assessment of Greenhouse-Gas Induced Climate Change) simple climate 
model.\183\ MiniCAM was used to create the globally and temporally 
consistent set of climate relevant variables required for running 
MAGICC. MAGICC was then used to estimate the change in the global mean 
surface temperature over time. Given the magnitude of the estimated 
emissions reductions associated with the increased volumes of renewable 
fuel, a simple climate model such as MAGICC is reasonable for 
estimating the climate response.
---------------------------------------------------------------------------

    \182\ MiniCAM is a long-term, global integrated assessment model 
of energy, economy, agriculture and land use, that considers the 
sources of emissions of a suite of greenhouse gases (GHGs), emitted 
in 14 globally disaggregated global regions (i.e., U.S., Western 
Europe, China), the fate of emissions to the atmosphere, and the 
consequences of changing concentrations of greenhouse related gases 
for climate change. MiniCAM begins with a representation of 
demographic and economic developments in each region and combines 
these with assumptions about technology development to describe an 
internally consistent representation of energy, agriculture, land-
use, and economic developments that in turn shape global emissions. 
Brenkert A, S. Smith, S. Kim, and H. Pitcher, 2003: Model 
Documentation for the MiniCAM. PNNL-14337, Pacific Northwest 
National Laboratory, Richland, Washington. For a recent report and 
detailed description and discussion of MiniCAM, see Clarke, L., J. 
Edmonds, H. Jacoby, H. Pitcher, J. Reilly, R. Richels, 2007. 
Scenarios of Greenhouse Gas Emissions and Atmospheric 
Concentrations. Sub-report 2.1A of Synthesis and Assessment Product 
2.1 by the U.S. Climate Change Science Program and the Subcommittee 
on Global Change Research. Department of Energy, Office of 
Biological & Environmental Research, Washington, DC., USA, 154 pp.
    \183\ MAGICC consists of a suite of coupled gas-cycle, climate 
and ice-melt models integrated into a single framework. The 
framework allows the user to determine changes in GHG 
concentrations, global-mean surface air temperature and sea-level 
resulting from anthropogenic emissions of carbon dioxide 
(CO2), methane (CH4), nitrous oxide (N2O), reactive gases 
(e.g., CO, NOX, VOCs), the halocarbons (e.g. HCFCs, HFCs, 
PFCs) and sulfur dioxide (SO2). MAGICC emulates the global-mean 
temperature responses of more sophisticated coupled Atmosphere/Ocean 
General Circulation Models (AOGCMs) with high accuracy. Wigley, 
T.M.L. and Raper, S.C.B. 1992. Implications for Climate and Sea-
Level of Revised IPCC Emissions Scenarios Nature 357, 293-300. 
Raper, S.C.B., Wigley T.M.L. and Warrick R.A. 1996. In Sea-Level 
Rise and Coastal Subsidence: Causes, Consequences and Strategies 
J.D. Milliman, B.U. Haq, Eds., Kluwer Academic Publishers, 
Dordrecht, The Netherlands, pp. 11-45. Wigley, T.M.L. and Raper, 
S.C.B. 2002. Reasons for larger warming projections in the IPCC 
Third Assessment Report J. Climate 15, 2945-2952.
---------------------------------------------------------------------------

    EPA applied the estimated annual GHG emissions changes for the 
final rule to a MiniCAM baseline emissions scenario.\184\ Specifically, 
the CO2, N2O, and CH4 annual emission 
changes from 2022-2052 from Section V.D were applied as net reductions 
to this baseline scenario for each GHG.
---------------------------------------------------------------------------

    \184\ The reference scenario is the MiniCAM reference (no 
climate policy) scenario used as the basis for the Representative 
Concentration Pathway RCP4.5 using historical emissions until 2005. 
This scenario is used because it contains a comprehensive suite of 
greenhouse and pollutant gas emissions including carbonaceous 
aerosols. The four RCP scenarios will be used as common inputs into 
a variety of Earth System Models for inter-model comparisons leading 
to the IPCC AR5 (Moss et al. 2008). The MiniCAM RCP4.5 is based on 
the scenarios presented in Clarke et al. (2007) with non-
CO2 and pollutant gas emissions implemented as described 
in Smith and Wigley (2006). Base-year information has been updated 
to the latest available data for the RCP process.
---------------------------------------------------------------------------

    Table V.E-1 provides our estimated reductions in projected global 
mean surface temperatures and mean sea level rise associated with the 
reductions in GHG emissions due to the increase in renewable fuels in 
2022. To capture some of the uncertainty in the climate system, we 
estimated the changes in projected temperatures and sea level across 
the most current Intergovernmental Panel on Climate Change (IPCC) range 
of climate sensitivities, 1.5 [deg]C to 6.0 [deg]C.\185\ To illustrate 
the time profile of the estimated reductions in projected global mean 
surface temperatures and mean sea level rise, we have also provided 
Figures V.E-1 and V.E-2.
---------------------------------------------------------------------------

    \185\ In IPCC reports, equilibrium climate sensitivity refers to 
the equilibrium change in the annual mean global surface temperature 
following a doubling of the atmospheric equivalent carbon dioxide 
concentration. The IPCC states that climate sensitivity is 
``likely'' to be in the range of 2 [deg]C to 4.5 [deg]C and 
described 3 [deg]C as a ``best estimate.'' The IPCC goes on to note 
that climate sensitivity is ``very unlikely'' to be less than 1.5 
[deg]C and ``values substantially higher than 4.5 [deg]C cannot be 
excluded.'' IPCC WGI, 2007, Climate Change 2007--The Physical 
Science Basis, Contribution of Working Group I to the Fourth 
Assessment Report of the IPCC, http://www.ipcc.ch/.

[[Page 14799]]



  Table V.E-1--Estimated Reductions in Projected Global Mean Surface Temperature and Global Mean Sea Level Rise
                                           From Baseline in 2020-2050
----------------------------------------------------------------------------------------------------------------
                                               Climate sensitivity
-----------------------------------------------------------------------------------------------------------------
                                                   1.5         2         2.5         3         4.5         6
----------------------------------------------------------------------------------------------------------------
Year                                              Change in global mean surface temperatures (degrees Celsius)
----------------------------------------------------------------------------------------------------------------
2020..........................................      0.000      0.000      0.000      0.000      0.000      0.000
2025..........................................      0.000      0.000      0.000      0.000      0.000      0.000
2030..........................................      0.000      0.000      0.000      0.000      0.000      0.000
2035..........................................     -0.001     -0.001     -0.001     -0.001     -0.001     -0.001
2040..........................................     -0.001     -0.001     -0.001     -0.001     -0.001     -0.001
2045..........................................     -0.001     -0.001     -0.001     -0.001     -0.002     -0.002
2050..........................................     -0.001     -0.001     -0.002     -0.002     -0.002     -0.002
----------------------------------------------------------------------------------------------------------------
Year                                                   Change in global mean sea level rise (centimeters)
----------------------------------------------------------------------------------------------------------------
2020..........................................      0.000      0.000      0.000      0.000      0.000      0.000
2025..........................................      0.000      0.000      0.000      0.000      0.000      0.000
2030..........................................     -0.001     -0.001     -0.001     -0.001     -0.001     -0.001
2035..........................................     -0.002     -0.002     -0.002     -0.003     -0.003     -0.003
2040..........................................     -0.003     -0.004     -0.004     -0.005     -0.005     -0.006
2045..........................................     -0.005     -0.006     -0.006     -0.007     -0.008     -0.009
2050..........................................     -0.006     -0.008     -0.009     -0.009     -0.011     -0.012
----------------------------------------------------------------------------------------------------------------

    The results in Table V.E-1 and Figures V.E-1 and V.E-2 show small 
reductions in the global mean surface temperature and sea level rise 
projections across all climate sensitivities. Overall, the reductions 
are small relative to the IPCC's ``best estimate'' temperature 
increases by 2100 of 1.8 [deg]C to 4.0 [deg]C.\186\ Although IPCC does 
not issue ``best estimate'' sea level rise projections, the model-based 
range across SRES scenarios is 18 to 59 cm by 2099.\187\ While the 
distribution of potential temperatures in any particular year is 
shifting down, the shift is not uniform. The magnitude of the decrease 
is larger for higher climate sensitivities. The same pattern appears in 
the reductions in the sea level rise projections. Thus, we can conclude 
that the impact of increased volumes of renewable fuel is to lower the 
risk of climate change, as the probabilities of temperature increase 
and sea level rise are reduced.
---------------------------------------------------------------------------

    \186\ IPCC WGI, 2007.
    \187\ ``Because understanding of some important effects driving 
sea level rise is too limited, this report does not assess the 
likelihood, nor provide a best estimate or an upper bound for sea 
level rise.'' IPCC Synthesis Report, p. 45.
---------------------------------------------------------------------------

VI. How Would the Proposal Impact Criteria and Toxic Pollutant 
Emissions and Their Associated Effects?

    This section presents our assessment of the changes in emissions 
and air quality resulting from the increased renewable fuel volumes 
needed to meet the RFS2 standards. Increases in emissions of 
hydrocarbons, nitrogen oxides, particulate matter, and other pollutants 
are projected to lead to increases in population-weighted annual 
average ambient PM and ozone concentrations. The air quality impacts, 
however, are highly variable from region to region. Ambient 
PM2.5 is likely to increase in areas associated with biofuel 
production and transport and decrease in other areas; for ozone, many 
areas of the country will experience increases and a few areas will see 
decreases. Ethanol concentrations will increase substantially; for the 
other modeled air toxics there are some localized impacts, but 
relatively little impact on national average concentrations.

A. Overview of Emissions Impacts

    Today's action will affect the emissions of ``criteria'' pollutants 
(those pollutants for which EPA has established a National Ambient Air 
Quality Standard has been established), criteria pollutant 
precursors,\188\ and air toxics, which may affect overall air quality 
and health. Emissions are affected by the processes required to produce 
and distribute large volumes of biofuels required by today's action and 
the direct effects of these fuels on vehicle and equipment emissions. 
As detailed in Chapter 3 of the Regulatory Impact Analysis (RIA), we 
have estimated emissions impacts of production and distribution-related 
emissions using the life cycle analysis methodology described in 
Section V with emission factors for criteria and toxic emissions for 
each stage of the life cycle, including agriculture, feedstock 
transportation, and the production and distribution of biofuel; 
included in this analysis are the impacts of reduced gasoline and 
diesel refining as these fuels are displaced by biofuels. Emission 
impacts of tailpipe and evaporative emissions for on and off road 
sources have been estimated by incorporating ``per vehicle'' fuel 
effects from recent research into mobile source emission inventory 
estimation methods.
---------------------------------------------------------------------------

    \188\ NOX and VOC are precursors to the criteria 
pollutant ozone; we group them with criteria pollutants in this 
chapter for ease of discussion.
---------------------------------------------------------------------------

    In the proposal we analyzed a single renewable fuel volume 
scenario, largely dependent on ethanol, relative to three different 
reference cases, including the RFS1 base case. For today's rule we are 
presenting emission impacts for three fuel volume scenarios relative to 
two reference cases (RFS1 mandate and AEO) to show a range of the 
possible effects of biofuels depending on the relative quantities of 
various biofuels that may be used to meet the overall renewable fuel 
requirements. We have also updated our modeling for the RFS1 mandate 
reference case to better reflect the emissions for this case. Table 
VI.A-1 shows the fuel volumes for the two reference cases and all three 
control scenarios. Further discussion of these fuel volumes and the 
subcategories within each are available in Section IV.A. The emission 
impacts of the primary control scenario (22.2 Bgal of ethanol) are 
presented here relative to both reference cases. The corresponding 
results for all three control cases are available in Chapter 3 of the 
Regulatory Impact Analysis for this rule.

[[Page 14800]]



                                    Table VI.A-1--Renewable Fuel Volumes for Each Reference Case and Control Scenario
                                                                   [Bgal/year in 2022]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Ethanol
                       Scenario                        --------------------------------------------------------   Biodiesel     Renewable    Cellulosic
                                                            Corn       Cellulosic     Imported        Total                      diesel        diesel
--------------------------------------------------------------------------------------------------------------------------------------------------------
RFS1 Ref..............................................        7.046           0.0           0.0         7.046         0.303           0.0           0.0
AEO Ref...............................................        12.29          0.25          0.64         13.18          0.38           0.0           0.0
Low Ethanol...........................................         15.0          0.25          2.24         17.49          1.67          0.15          9.26
Mid Ethanol (Primary).................................         15.0          4.92          2.24         22.16          1.67          0.15          6.52
High Ethanol..........................................         15.0          16.0          2.24         33.24          1.67          0.15           0.0
--------------------------------------------------------------------------------------------------------------------------------------------------------

    There have been a number of other enhancements and corrections to 
the non-GHG emission inventory estimates since the NPRM, some of which 
were included in the air quality modeling inventories, while others 
occurred later than that. The major changes are mentioned here, and all 
the significant changes are explained in detail in Chapter 3 of the 
RIA.
    One significant change relates to the ``downstream'' vehicle and 
equipment emission impacts of using the increased proportions of 
renewable fuels. In the proposal we provided two different analyses 
based on two different assumptions regarding the effects of E10 and E85 
versus E0 on exhaust emissions from cars and trucks. Those were 
referred to as ``less sensitive'' and ``more sensitive'' cases. Based 
on analysis of recent emissions test data conducted since publication 
of the NPRM, we are modeling a single case. As detailed in Section 
VI.C, the case modeled for the final rule is a hybrid approach, 
applying ``more sensitive'' impacts for E10 and pre-Tier 2 light duty 
vehicles, and applying the ``less sensitive'' E10 effects for Tier 2 
light duty cars and trucks, which means no impact for NOX or 
non-methane hydrocarbons (NMHC). We have also updated our estimates of 
evaporative permeation impacts of E10 based on recent studies. Finally, 
for the final rule inventories we are only claiming emission effects 
with use of E85 in flex-fueled vehicles relative to E0 for two 
pollutants: ethanol and acetaldehyde, for which data suggests the 
effects are more certain. For the ``more sensitive case'' presented in 
the NPRM, and used in the air quality modeling, we had estimated 
changes to additional pollutants (including significant PM reductions) 
based on some very limited data. Until such time as additional data is 
collected to enhance this analysis it is premature to use such 
assumptions.
    For ``upstream'' emissions associated with fuel production and 
distribution, the largest change that was included in the air quality 
modeling was the improved estimate of VOC and ethanol vapor emissions 
during ethanol transport, made possible by a detailed analysis of costs 
and transport modes conducted by Oak Ridge National Laboratory 
(ORNL).\189\ This change alone more than doubled the predicted overall 
increase in ethanol emissions from the increased use of renewable 
fuels, increasing the VOC enough to change the overall VOC impact from 
a decrease to a substantial increase.
---------------------------------------------------------------------------

    \189\ ``Analysis of Fuel Ethanol Transportation Activity and 
Potential Distribution Constraints,'' Oak Ridge National Laboratory, 
U.S. Department of Energy, March 2009.
---------------------------------------------------------------------------

    Significant updates have also been made to emissions from 
cellulosic biofuel plants, in part to reflect the assumed shift in 
volumes from cellulosic ethanol to diesel between the proposed and 
final rules. For cellulosic ethanol plants, after the air quality 
modeling was done we discovered that the calculation of emissions from 
these plants had been overestimated due to failing to account for the 
portion of biomass that is not used for process energy. This change 
decreases the estimated NOX and CO impacts, and shifts the 
PM impact of these plants from an increase to a small decrease. 
However, these changes are counterbalanced by varying degrees by 
shifting some of the cellulosic volume from ethanol to diesel, which 
requires nearly twice the biomass as needed by ethanol to produce one 
gallon. While the net effect of the changes in cellulosic plant 
emissions is a decrease in NOX and CO emission impacts 
relative to the proposal, the shift to cellulosic diesel under the 
primary scenario results in a larger increase in ``upstream'' PM 
emissions than reported in the NPRM or used in the air quality 
analysis.
    Updates to agricultural modeling assumptions made between proposal 
and final had a significant impact on ammonia (NH3) emissions. Final 
modeling reflects an increase in fertilizer use with the primary 
control case, which results in a 1.2 percent increase in NH3 emissions, 
a change from the 0.5 percent decrease projected for the proposal and 
negligible impact used in the air quality analyses.
    Analysis of criteria and toxic emission impacts was performed for 
calendar year 2022, since this year reflects the full implementation of 
today's rule. Our 2022 projections account for projected growth in 
vehicle travel and the effects of applicable emission and fuel economy 
standards, including Tier 2 and Mobile Source Air Toxics (MSAT) rules 
for cars and light trucks and recently finalized controls on spark-
ignited off-road engines.
    The analysis presented here provides estimates of the change in 
national emission totals that would result from the increased use of 
renewable fuels to meet the statutory requirements of EISA. These 
totals may not be a good indication of local or regional air quality 
and health impacts. These results are aggregated across highly 
localized sources, such as emissions from ethanol plants and 
evaporative emissions from cars, and reflect offsets such as decreased 
emissions from gasoline refineries. The location and composition of 
emissions from these disparate sources may strongly influence the air 
quality and health impacts of the increased use of renewable fuels, so 
full-scale photochemical air quality modeling was also performed to 
accurately assess this. These localized impacts are discussed in 
Section VI.D.
    Our projected emission impacts for the primary renewable fuel 
scenario relative to the two reference cases are shown in Table VI.A-2 
for 2022. This shows the expected emission changes for the U.S. in that 
year, and the percent contribution of this impact relative to the total 
U.S. inventory. Overall we project that increases in the use of 
renewable fuels will result in significant increases in ethanol and 
acetaldehyde emissions--increasing the total U.S. inventories of these 
pollutants by 16-18 percent in 2022 relative to the RFS1 mandate case. 
We project more modest increases in NOX, HC, PM, 
formaldehyde, 1,3-butadiene, acrolein, and ammonia (NH3) relative to 
the RFS1 mandate case. We project a 5 percent

[[Page 14801]]

decrease in CO (due to impacts of ethanol on exhaust emissions from 
vehicles and nonroad equipment), and a 2.4 percent decrease in benzene 
(due to displacement of gasoline with ethanol in the fuel pool). 
Impacts on SO2 and naphthalene are much smaller. Relative to 
the AEO reference case the results are similar directionally, but 
smaller in magnitude due to the less drastic differences in fuel 
volumes.

 Table VI.A-2--Total Combined Upstream and Downstream Emission Impacts in 2022 for Primary Scenario Relative to
                                               Each Reference Case
----------------------------------------------------------------------------------------------------------------
                                                           RFS1 Mandate                         AEO
                                                 ---------------------------------------------------------------
                    Pollutant                      Annual short     % of total     Annual short     % of Total
                                                       tons       U.S. inventory       tons       U.S. inventory
----------------------------------------------------------------------------------------------------------------
NOX.............................................         247,604            1.95         184,820            1.45
HC..............................................         100,762            0.87          24,523            0.21
PM10............................................          69,013            1.92          63,323            1.76
PM2.5...........................................          15,549            0.46          14,393            0.42
CO..............................................      -2,869,842           -5.30        -376,419           -0.69
Benzene.........................................          -4,264           -2.41          -1,004           -0.57
Ethanol.........................................         100,123           18.20          54,137            9.84
1,3-Butadiene...................................             224            1.70              59            0.45
Acetaldehyde....................................           5,848           15.80           3,108            8.40
Formaldehyde....................................             355            0.48             130            0.17
Naphthalene.....................................              -1           -0.01              -4           -0.03
Acrolein........................................              22            0.38              21            0.35
SO2.............................................           3,286            0.04           5,065            0.06
NH3.............................................          48,711            1.15          48,711            1.15
----------------------------------------------------------------------------------------------------------------

    The breakdown of these results by the fuel production/distribution 
(``well-to-pump'' emissions) and vehicle and equipment (``pump-to-
wheel'') emissions is discussed in the following sections.

B. Fuel Production & Distribution Impacts of the Proposed Program

    Fuel production and distribution emission impacts of the increased 
use of renewable fuels were estimated in conjunction with the 
development of life cycle GHG emission impacts and the GHG emission 
inventories discussed in Section V. These emissions are calculated 
according to the breakdowns of agriculture, feedstock transport, fuel 
production, and fuel distribution; the basic calculation is a function 
of fuel volumes in the analysis year and the emission factors 
associated with each process or subprocess. Additionally, the emission 
impact of displaced petroleum is estimated, using the same domestic/
import shares discussed in Section V above.
    In general the basis for this life cycle evaluation was the 
analysis conducted as part of the Renewable Fuel Standard (RFS1) 
rulemaking, but enhanced significantly. While our approach for the RFS1 
was to rely heavily on the ``Greenhouse Gases, Regulated Emissions, and 
Energy Use in Transportation'' (GREET) model, developed by the 
Department of Energy's Argonne National Laboratory (ANL), we are now 
able to take advantage of additional information and models to 
significantly strengthen and expand our analysis for this rule. In 
particular, the modeling of the agriculture sector was greatly expanded 
beyond the RFS1 analysis, employing economic and agriculture models to 
consider factors such as land-use impact, agricultural burning, 
fertilizer, pesticide use, livestock, crop allocation, and crop 
exports.
    Other updates and enhancements to the GREET model assumptions 
include updated feedstock energy requirements and estimates of excess 
electricity available for sale from new cellulosic ethanol plants, 
based on modeling by the National Renewable Energy Laboratory (NREL). 
Per-gallon emission factors for new corn ethanol plants were updated 
based on EPA analysis of energy efficiency technologies currently 
available (such as combined heat and power) and their expected market 
penetrations. There are no new standards planned at this time that 
would offer any additional control of emissions from corn or cellulosic 
ethanol plants. EPA also updated the fuel and feedstock transport 
emission factors to account for recent EPA emission standards and 
modeling, such as the locomotive and commercial marine standards 
finalized in 2008, and revised heavy-duty truck emission rates 
contained in EPA's draft MOVES2009 model. EPA also modified the ethanol 
transport distances based on a detailed analysis of costs versus 
transport mode conducted by Oak Ridge National Laboratory. In addition, 
GREET does not include air toxics or ethanol. Thus emission factors for 
ethanol and the following air toxics were added: benzene, 1,3-
butadiene, formaldehyde, acetaldehyde, acrolein and naphthalene.
    Results of these calculations relative to each reference case in 
2022 are shown in Table VI.B-1 for the criteria pollutants, ammonia, 
ethanol and individual air toxic pollutants. Due to the complex 
interactions involved in projections in the agricultural modeling, we 
did not attempt to adjust the agricultural inputs of the AEO reference 
case for the RFS1 mandate reference case. So the fertilizer and 
pesticide quantities, livestock counts, and total agricultural acres 
were the same for both reference cases. The agricultural modeling that 
had been done for the RFS1 rule itself was much simpler and 
inconsistent with the new modeling, so it would be inappropriate to use 
those estimates.
    The fuel production and distribution impacts of the increased use 
of renewable fuels on VOC are mainly due to increases in emissions 
connected with biofuel production, countered by decreases in emissions 
associated with gasoline production and distribution as ethanol 
displaces some of the gasoline. Increases in PM2.5, 
SOX and especially NOX are driven by stationary 
combustion emissions from the substantial increase in corn and 
cellulosic ethanol production. Biofuel plants (corn and cellulosic) 
tend to have greater combustion emissions relative to petroleum 
refineries on a per-BTU of fuel produced basis. Increases in 
SOX emissions are also due to increases in agricultural 
chemical production and transport, while substantial PM

[[Page 14802]]

increases are also associated with fugitive dust from agricultural 
operations. Ammonia emissions are expected to increase substantially 
due to increased ammonia from fertilizer use.
    Ethanol vapor and most air toxic emissions associated with fuel 
production and distribution are projected to increase. Relative to the 
US total reference case emissions with RFS1 mandate ethanol volumes, 
increases of 4-13 percent for acetaldehyde and ethanol vapor are 
especially significant because they are driven directly by the 
increased ethanol production and distribution. Formaldehyde and 
acrolein increases are smaller, on the order of 0.4-1 percent. There 
are also very small decreases in benzene, 1,3-butadiene and naphthalene 
relative to the US total emissions.

 Table VI.B-1--``Upstream'' Fuel Production and Distribution Impacts of the Primary Scenario in 2022 Relative to
                                               Each Reference Case
----------------------------------------------------------------------------------------------------------------
                                                           RFS1 mandate                         AEO
                                                 ---------------------------------------------------------------
                    Pollutant                      Annual short     % of Total     Annual short     % of Total
                                                       tons       U.S. inventory       tons       U.S. inventory
----------------------------------------------------------------------------------------------------------------
NOX.............................................         169,665            1.34         164,170            1.29
HC..............................................          77,014            0.67          19,737            0.17
PM10............................................          69,583            1.94          63,892            1.78
PM2.5...........................................          15,864            0.47          14,707            0.43
CO..............................................         135,658            0.25         130,172            0.24
Benzene.........................................            -231           -0.13            -236           -0.13
Ethanol.........................................          69,445           12.63          35,865            6.52
1,3-Butadiene...................................              -1           -0.01               0            0.00
Acetaldehyde....................................           1,617            4.37             933            2.52
Formaldehyde....................................             293            0.39             187            0.25
Naphthalene.....................................              -8           -0.06              -6           -0.04
Acrolein........................................              67            1.13              37            0.63
SO2.............................................           3,266            0.04           5,044            0.06
NH3.............................................          48,711            1.15          48,711            1.15
----------------------------------------------------------------------------------------------------------------

C. Vehicle and Equipment Emission Impacts of Fuel Program

    The effects of the increased use of renewable fuels on vehicle and 
equipment emissions are a direct function of the effects of these fuels 
on exhaust and evaporative emissions from vehicles and off-road 
equipment, and evaporation of fuel from portable containers. To assess 
these impacts we conducted separate analyses to quantify the emission 
impacts of additional E10 due to the increased use of renewable fuels 
on gasoline vehicles, nonroad spark-ignited engines and portable fuel 
containers; E85 on cars and light trucks; biodiesel on diesel vehicles; 
and increased refueling events due to lower energy density of 
biofuels.\190\
---------------------------------------------------------------------------

    \190\ The impact of renewable diesel was not estimated for this 
analysis; we expect little overall impact on criteria and toxic 
emissions due to the relatively small volume change, and because 
emission effects relative to conventional diesel are presumed to be 
negligible.
---------------------------------------------------------------------------

    In the proposal we provided two different analyses based on two 
different assumptions regarding the effects of E10 and E85 on exhaust 
emissions from cars and trucks. Those were referred to as ``less 
sensitive'' and ``more sensitive'' cases. Based on analysis of recent 
studies, today's analysis is based on a hybrid of these two scenarios. 
As detailed in the RIA, EPA and other parties have been gathering 
additional data on the emission impacts of ethanol fuels on later model 
vehicles. Data available in time for this analysis supports the 
hypothesis of the ``less sensitive'' case that newer technology Tier 2 
vehicles are generally able to control for changes to emissions 
associated with low level ethanol blends; for this analysis we 
therefore are not attributing any NOX or VOC impact to the 
use of E10 on these vehicles. The data does show sensitivity for older 
technology (pre-Tier 2) vehicles, so this analysis does attribute an 
increase in NOX and decrease in NMHC to the use of E10 in 
these vehicles. This analysis does not include any emission impacts 
with use of E85 in flex-fueled vehicles, except for increases in 
ethanol and acetaldehyde, as the limited data currently available is 
insufficient to quantify the impact with any degree of certainty. 
Overall the sensitivity of exhaust emissions to ethanol assumed for the 
final rule analysis is closer to the ``less sensitive'' case presented 
in the proposal; and is generally less sensitive than the case used for 
the air quality modeling, as discussed in Section VI.D.
    We have also updated our estimates of E10 effects on permeation 
emissions from light-duty vehicles based on testing recently completed 
by the Coordinating Research Council (CRC), showing that the relative 
increase in VOC emissions is higher for newer technology vehicles. 
Nonroad spark ignition (SI) emission impacts of E10 were based on EPA's 
NONROAD model and show trends similar to light duty vehicles. Biodiesel 
effects for this analysis were unchanged from the proposal, and are 
based on an analysis of recent biodiesel testing, detailed in the RIA, 
showing a 2 percent increase in NOX with a 20 percent 
biodiesel blend, a 16 percent decrease in PM, and a 14 percent decrease 
in HC. These results essentially confirm the results of an earlier EPA 
analysis. This analysis does not attribute any downstream emission 
impact from the use of renewable diesel or cellulosic-based diesel 
relative to conventional diesel due to their chemical similarity to 
diesel fuel and limited test data.
    Summarized vehicle and equipment emission impacts in 2022, updated 
as noted above, are shown in Table VI.C-1 relative to each reference 
case. The totals shown below reflect the net impacts from all mobile 
sources, including car and truck evaporative emissions, off road 
emissions, and portable fuel containers. Additional breakdowns by 
mobile source category can be found in Chapter 3 of the RIA.
    Carbon monoxide, PM, benzene, and acrolein are projected to 
decrease in 2022 as a result of the increased use of renewable fuels, 
while NOX, HC and the other air toxics, especially ethanol 
and acetaldehyde, are projected to increase due to the impacts of E10.

[[Page 14803]]



 Table VI.C-1--``Downstream'' Vehicle and Equipment Emission Impacts of the Primary Scenario in 2022 Relative to
                                               Each Reference Case
----------------------------------------------------------------------------------------------------------------
                                                           RFS1 Mandate                         AEO
                                                 ---------------------------------------------------------------
                    Pollutant                      Annual short     % of Total     Annual short     % of Total
                                                       tons       U.S. inventory       tons       U.S. inventory
----------------------------------------------------------------------------------------------------------------
NOX.............................................          77,939            0.61          20,650            0.16
HC..............................................          23,748            0.21           4,786            0.04
PM10............................................            -569           -0.02            -569           -0.02
PM2.5...........................................            -315           -0.01            -315           -0.01
CO..............................................      -3,005,500           -5.55        -506,591           -0.94
Benzene.........................................          -4,033           -2.28            -768           -0.43
Ethanol.........................................          30,678            5.58          18,272            3.32
1,3-Butadiene...................................             225            1.71              59            0.45
Acetaldehyde....................................           4,231           11.43           2,175            5.88
Formaldehyde....................................              62            0.08             -57           -0.08
Naphthalene.....................................               7            0.05               2            0.01
Acrolein........................................             -44           -0.75             -16           -0.28
SO2.............................................              21            0.00              21            0.00
NH3.............................................               0            0.00               0            0.00
----------------------------------------------------------------------------------------------------------------

D. Air Quality Impacts

    Air quality modeling was performed to assess the projected impact 
of the renewable fuel volumes required by RFS2 on emissions of criteria 
and air toxic pollutants. Our air quality modeling reflects the impact 
of increased renewable fuel use required by RFS2 compared with two 
different reference cases that include the use of renewable fuels: A 
2022 reference case projection based on the RFS1-mandated volume of 7.1 
billion gallons of renewable fuels, and a 2022 reference case 
projection based on the AEO 2007 volume of roughly 13.6 billion gallons 
of renewable fuels. Thus, the results represent the impact of an 
incremental increase in ethanol and other renewable fuels. We note that 
the air quality modeling results presented in this final rule do not 
constitute the ``anti-backsliding'' analysis required by Clean Air Act 
section 211(v). EPA will be analyzing air quality impacts of increased 
renewable fuel use through that study and will promulgate appropriate 
mitigation measures under section 211(v), separate from this final 
action.
    It is critical to note that a key limitation of the analysis is 
that it employed interim emission inventories, which were somewhat 
enhanced compared to what was described in the proposal, but due to the 
timing of the analysis did not include some of the later enhancements 
and corrections of the final emission inventories presented in this FRM 
(see Section VI.A through VI.C of this preamble). Most significantly, 
our modeling of the air quality impacts of the renewable fuel volumes 
required by RFS2 relied upon interim inventories that assumed that 
ethanol will make up 34 of the 36 billion gallon renewable fuel 
mandate, that approximately 20 billion gallons of this ethanol will be 
in the form of E85, and that the use of E85 results in fewer emissions 
of direct PM2.5 from vehicles. The emission impacts and air 
quality results would be different if, instead of E85, more non-ethanol 
biofuels are used or mid-level ethanol blends are approved.
    In fact, as explained in Section IV, our more recent analyses 
indicate that ethanol and E85 volumes are likely to be significantly 
lower than what we assumed in the interim inventories. Furthermore, the 
final emission inventories do not include vehicle-related PM reductions 
associated with E85 use, as discussed in Section VI.A and VI.C of this 
preamble. There are additional, important limitations and uncertainties 
associated with the interim inventories that must be kept in mind when 
considering the results:
     Error in PM2.5 emissions from locomotive engines
    After the air quality modeling was completed, we discovered an 
error in the way that PM2.5 emissions from locomotive 
engines were allocated to counties in the inventory. Although there was 
very little impact on national-level PM2.5 emissions, 
PM2.5 emission changes were too high in some counties and 
too low in others, by varying degrees. As a result, we do not present 
the modeling results for specific localized PM2.5 impacts. 
However, we have concluded that PM2.5 modeling results are 
still informative for national-level benefits assessment, as discussed 
at more length in Section VIII.D of this preamble and the RIA.
     Sensitivity of light-duty vehicle exhaust emissions to 
ethanol blends
    As discussed above in Sections VI.A and VI.C of this preamble, the 
interim emission inventories used for the air quality modeling analysis 
are the ``more sensitive'' case described in the proposal. As a result, 
the interim inventories used for air quality modeling assume that 
vehicles operating on E10 have higher NOX emissions and 
lower VOC, CO and PM exhaust emissions compared to the FRM inventories.
     Cellulosic plant emissions
    The interim emission inventories used in air quality modeling 
generally assumed higher emissions from cellulosic plants than the FRM 
inventories, which used revised estimates based on updates to the 
fraction of biomass burned at these plants. However, as noted in 
Section VI.A, the shift of some cellulosic volume from ethanol to 
diesel results in higher PM emissions from cellulosic plants in the 
final rule inventories than used in the air quality modeling 
inventories.
     Ethanol volume
    As mentioned above, the interim emission inventories used in our 
air quality modeling reflect the use of ethanol in about 34 of the 
mandated 36 billion gallons and do not include any cellulosic diesel. 
As shown in Table VI.A-1, the FRM inventories assume 22 billion gallons 
of ethanol in the primary case and 6.5 billion gallons of cellulosic 
diesel. The inventories used for air quality modeling assume ethanol 
volumes are more consistent with the FRM's high-ethanol case inventory, 
which reflects the use of 33 billion gallons of ethanol and no 
cellulosic diesel.
     Renewable fuel transport emissions

[[Page 14804]]

    As discussed in Section 3.3, the estimates of renewable fuel 
transport volumes and distances differ between the air quality modeling 
and final rule inventories.
    In this section, we present information on current modeled levels 
of pollution as well as projections for 2022, with respect to ambient 
PM2.5, ozone, selected air toxics, and nitrogen and sulfur 
deposition. The air quality modeling results indicate that ambient 
PM2.5 is likely to increase in areas associated with biofuel 
production and transport and decrease in other areas. The results of 
the air quality modeling also indicate that many areas of the country 
will experience increases in ambient ozone and a few areas will see 
decreases in ambient ozone as a result of the renewable fuel volumes 
required by RFS2. The modeling also shows that ethanol concentrations 
increase substantially with increases in renewable fuel volumes. For 
the other modeled air toxics, there are some localized impacts, but 
relatively little impact on national average concentrations. Our air 
quality modeling does not show substantial overall nationwide impacts 
on the annual total sulfur and nitrogen deposition occurring across the 
U.S. However, the air quality modeling results indicate that the entire 
Eastern half of the U.S. along with the Pacific Northwest would see 
increases in nitrogen deposition as a result of increased renewable 
fuel use. The results of the modeling also show that sulfur deposition 
will increase in the Midwest and in some rural areas of the west 
associated with biofuel production. The results are discussed in more 
detail below and in Section 3.4 of the RIA.
    We used the Community Multi-scale Air Quality (CMAQ) photochemical 
model, version 4.7, for our analysis. This version of CMAQ includes a 
number of improvements to previous versions of the model that are 
important in assessing impacts of the increased use of renewable fuels, 
including additional pathways for formation of soluble organic aerosols 
(SOA). These improvements are discussed in Section 3.4 of the RIA.
    In addition to the limitations of the analysis that result from the 
use of interim emission inventories rather than the FRM inventories, 
there are uncertainties in the air quality analysis that should be 
noted. First, there are uncertainties inherent in the modeling process. 
Pollutants such as ozone, PM, acetaldehyde, formaldehyde, acrolein, and 
1,3-butadiene can be formed secondarily through atmospheric chemical 
processes. These processes can be very complex, and there are 
uncertainties in emissions of precursor compounds and reaction 
pathways. In addition, simplifications of chemistry must be made in 
order to handle reactions of thousands of chemicals in the atmosphere. 
Another source of uncertainty involves the hydrocarbon speciation 
profiles, which are applied to the VOC inventories to break VOC down 
into individual constituent compounds which react in the atmosphere. 
Given the complexity of the atmospheric chemistry, the hydrocarbon 
speciation has an important influence on the air quality modeling 
results. Speciation profiles for a number of key sources are based on 
data with significant limitations. Finally, there are uncertainties in 
the surrogates used to allocate emissions spatially and temporally; 
this is particularly significant in projecting the location of new 
ethanol plants, especially future cellulosic biofuel plants. These 
plants can have large impacts on local emissions. A more detailed 
discussion of these and additional uncertainties and limitations 
associated with our air quality modeling is presented in Section 3.4 of 
the RIA.
1. Particulate Matter
a. Current Levels
    PM2.5 concentrations exceeding the level of the 
PM2.5 NAAQS occur in many parts of the country. In 2005, EPA 
designated 39 nonattainment areas for the 1997 PM2.5 NAAQS 
(70 FR 943, January 5, 2005). These areas are composed of 208 full or 
partial counties with a total population exceeding 88 million. The 1997 
PM2.5 NAAQS was recently revised and the 2006 24-hour 
PM2.5 NAAQS became effective on December 18, 2006. On 
October 8, 2009, the EPA issued final nonattainment area designations 
for the 2006 24-hour PM2.5 NAAQS (74 FR 58688, November 13, 
2009). These designations include 31 areas composed of 120 full or 
partial counties with a population of over 70 million. In total, there 
are 54 PM2.5 nonattainment areas composed of 245 counties 
with a population of 101 million people.
b. Projected Levels Without RFS2 Volumes
    States with PM2.5 nonattainment areas are required to 
take action to bring those areas into compliance in the future. Areas 
designated as not attaining the 1997 PM2.5 NAAQS will need 
to attain the 1997 standards in the 2010 to 2015 time frame, and then 
maintain them thereafter. The 2006 24-hour PM2.5 
nonattainment areas will be required to attain the 2006 24-hour 
PM2.5 NAAQS in the 2014 to 2019 time frame and then be 
required to maintain the 2006 24-hour PM2.5 NAAQS 
thereafter.
    EPA has already adopted many emission control programs that are 
expected to reduce ambient PM2.5 levels and which will 
assist in reducing the number of areas that fail to achieve the 
PM2.5 NAAQS. Even so, recent air quality modeling for the 
``Control of Emissions from New Marine Compression-Ignition Engines at 
or Above 30 Liters per Cylinder'' rule projects that in 2020, at least 
10 counties with a population of almost 25 million may not attain the 
1997 annual PM2.5 standard of 15 [micro]g/m\3\ and 47 
counties with a population of over 53 million may not attain the 2006 
24-hour PM2.5 standard of 35 [micro]g/m\3\.\191\ These 
numbers do not account for those areas that are close to (e.g., within 
10 percent of) the PM2.5 standards. These areas, although 
not violating the standards, will also benefit from any reductions in 
PM2.5 ensuring long-term maintenance of the PM2.5 
NAAQS.
---------------------------------------------------------------------------

    \191\ US EPA (2009). Final Rule ``Control of Emissions from New 
Marine Compression-Ignition Engines at or Above 30 Liters per 
Cylinder''. (This rule was signed on December 18, 2009 but has not 
yet been published in the Federal Register. The signed version of 
the rule is available at http://epa.gov/otaq/oceanvessels.htm).
---------------------------------------------------------------------------

c. Projected Levels With RFS2 Volumes
    We are not able to present air quality modeling results which 
detail changes in PM2.5 design values for specific local 
areas due to the error in the locomotive inventory mentioned in the 
introduction to this section. However, we do know that ambient 
PM2.5 increases in some areas of the country and decreases 
in other areas of the country. Ambient PM2.5 is likely to 
increase as a result of emissions at biofuel production plants and from 
biofuel transport, both of which are more prevalent in the Midwest. PM 
concentrations are likely to decrease in some areas due to reductions 
in SOA formation and reduced emissions from gasoline refineries. In 
addition, decreases in ambient PM are predicted because our modeling 
inventory assumed that E85 usage reduces PM tailpipe emissions. The 
decreases in ambient PM from reductions in SOA and tailpipe emissions 
are likely to occur where there is a higher density of vehicles, such 
as the Northeast. See Section VIII.D for a discussion of the changes in 
national average population-weighted PM2.5 concentrations.

[[Page 14805]]

2. Ozone
a. Current Levels
    8-hour ozone concentrations exceeding the level of the ozone NAAQS 
occur in many parts of the country. In 2008, the U.S. EPA amended the 
ozone NAAQS (73 FR 16436, March 27, 2008). The final 2008 ozone NAAQS 
rule set forth revisions to the previous 1997 NAAQS for ozone to 
provide increased protection of public health and welfare. As of 
January 6, 2010 there are 51 areas designated as nonattainment for the 
1997 8-hour ozone NAAQS, comprising 266 full or partial counties with a 
total population of over 122 million people. These numbers do not 
include the people living in areas where there is a future risk of 
failing to maintain or attain the 1997 8-hour ozone NAAQS. The numbers 
above likely underestimate the number of counties that are not meeting 
the ozone NAAQS because the nonattainment areas associated with the 
more stringent 2008 8-hour ozone NAAQS have not yet been 
designated.\192\ Table VI.D-1 provides an estimate, based on 2005-07 
air quality data, of the counties with design values greater than the 
2008 8-hour ozone NAAQS of 0.075 ppm.
---------------------------------------------------------------------------

    \192\ EPA recently proposed to reconsider the 2008 NAAQS. 
Because of the uncertainty the reconsideration proposal creates 
regarding the continued applicability of the 2008 ozone NAAQS, EPA 
has used its authority to extend by 1 year the deadline for 
promulgating designations for those NAAQS. The new deadline is March 
2011. EPA intends to complete the reconsideration by August 31, 
2010.

  Table VI.D-1--Counties With Design Values Greater Than the 2008 Ozone
                NAAQS Based on 2005-2007 Air Quality Data
------------------------------------------------------------------------
                                             Number of
                                             counties      Population a
------------------------------------------------------------------------
1997 Ozone Standard: Counties within the             266    122,343, 799
 51 areas currently designated as
 nonattainment (as of 1/6/10)...........
2008 Ozone Standard: Additional counties             227      41,285,262
 that would not meet the 2008 NAAQS b...
                                         -------------------------------
    Total...............................             493     163,629,061
------------------------------------------------------------------------
Notes:
a Population numbers are from 2000 census data.
b Area designations for the 2008 ozone NAAQS have not yet been made.
  Nonattainment for the 2008 Ozone NAAQS would be based on three years
  of air quality data from later years. Also, the county numbers in this
  row include only the counties with monitors violating the 2008 Ozone
  NAAQS. The numbers in this table may be an underestimate of the number
  of counties and populations that will eventually be included in areas
  with multiple counties designated nonattainment.

b. Projected Levels Without RFS2 Volumes
    States with 8-hour ozone nonattainment areas are required to take 
action to bring those areas into compliance in the future. Based on the 
final rule designating and classifying 8-hour ozone nonattainment areas 
for the 1997 standard (69 FR 23951, April 30, 2004), most 8-hour ozone 
nonattainment areas will be required to attain the ozone NAAQS in the 
2007 to 2013 time frame and then maintain the NAAQS thereafter. EPA has 
recently proposed to reconsider the 2008 ozone NAAQS. If EPA 
promulgates different ozone NAAQS in 2010 as a result of the 
reconsideration, they would fully replace the 2008 ozone NAAQS and 
there would no longer be a requirement to designate areas for the 2008 
NAAQS. EPA would designate nonattainment areas for a potential new 2010 
primary ozone NAAQS based on the reconsideration of the 2008 ozone 
NAAQS in 2011. The attainment dates for areas designated nonattainment 
for a potential new 2010 primary ozone NAAQS are likely to be in the 
2014 to 2031 timeframe, depending on the severity of the problem.
    EPA has already adopted many emission control programs that are 
expected to reduce ambient ozone levels and assist in reducing the 
number of areas that fail to achieve the ozone NAAQS. Even so, our air 
quality modeling projects that in 2022, with all current controls but 
excluding the impacts of the renewable fuel volumes required by RFS2, 
up to 7 counties with a population of over 22 million may not attain 
the 2008 ozone standard of 0.075 ppm (75 ppb). These numbers do not 
account for those areas that are close to (e.g., within 10 percent of) 
the 2008 ozone standard. These areas, although not violating the 
standards, will also benefit from any reductions in ozone ensuring 
long-term maintenance of the ozone NAAQS.
c. Projected Levels With RFS2 Volumes
    Our modeling indicates that the required renewable fuel volumes 
will cause increases in ozone design value concentrations in many areas 
of the country and decreases in ozone design value concentrations in a 
few areas. Air quality modeling of the expected impacts of the 
renewable fuel volumes required by RFS2 shows that in 2022, most 
counties with modeled data, especially those in the southeast U.S., 
will see increases in their ozone design values. These adverse impacts 
are likely due to increased upstream emissions of NOX in 
many areas that are NOX-limited (acting as a precursor to 
ozone formation). The majority of these design value increases are less 
than 0.5 ppb. The maximum projected increase in an 8-hour ozone design 
value is in Morgan County, Alabama, 1.56 ppb and 1.27 ppb when compared 
with the RFS1 mandate and AEO 2007 reference cases respectively. As 
mentioned above there are some areas which see decreases in their ozone 
design values. This is likely due to VOC emission reductions at the 
tailpipe in urban areas that are VOC-limited (reducing VOC's role as a 
precursor to ozone formation). The maximum decrease projected in an 8-
hour ozone design value is in Riverside, CA, 0.66 ppb and 0.6 ppb when 
compared with the RFS1 mandate and AEO 2007 reference cases 
respectively. On a population-weighted basis, the average modeled 
future-year 8-hour ozone design values are projected to increase by 
0.28 ppb in 2022 when compared with the RFS1 mandate reference case and 
increase by 0.16 ppb when compared with the AEO 2007 reference case. On 
a population-weighted basis the design values for those counties that 
are projected to be above the 2008 ozone standard in 2022 will see 
decreases of 0.14 ppb when compared with the RFS1 mandate reference 
case and 0.15 ppb when compared with the AEO 2007 reference case.

[[Page 14806]]

3. Air Toxics
a. Current Levels
    The majority of Americans continue to be exposed to ambient 
concentrations of air toxics at levels which have the potential to 
cause adverse health effects.\193\ The levels of air toxics to which 
people are exposed vary depending on where people live and work and the 
kinds of activities in which they engage, as discussed in detail in 
U.S. EPA's recent Mobile Source Air Toxics Rule.\194\ According to the 
National Air Toxic Assessment (NATA) for 2002,\195\ mobile sources were 
responsible for 47 percent of outdoor toxic emissions, over 50 percent 
of the cancer risk, and over 80 percent of the noncancer hazard. 
Benzene is the largest contributor to cancer risk of all 124 pollutants 
quantitatively assessed in the 2002 NATA and mobile sources were 
responsible for 59 percent of benzene emissions in 2002. Over the 
years, EPA has implemented a number of mobile source and fuel controls 
resulting in VOC reductions, which also reduce benzene and other air 
toxic emissions.
---------------------------------------------------------------------------

    \193\ U. S. EPA. (2009) 2002 National-Scale Air Toxics 
Assessment. http://www.epa.gov/ttn/atw/nata2002/.
    \194\ U.S. Environmental Protection Agency (2007). Control of 
Hazardous Air Pollutants from Mobile Sources; Final Rule. 72 FR 
8434, February 26, 2007.
    \195\ U.S. EPA. (2009) 2002 National-Scale Air Toxics 
Assessment. http://www.epa.gov/ttn/atw/nata2002/.
---------------------------------------------------------------------------

b. Projected Levels
    Our modeling indicates that, while there are some localized 
impacts, the renewable fuel volumes required by RFS2 have relatively 
little impact on national average ambient concentrations of the modeled 
air toxics. An exception is increased ambient concentrations of 
ethanol. For more information on the air toxics modeling results, see 
Section 3.4 of the RIA for annual average results and Appendix 3A of 
the RIA for seasonal average results. Our discussion of the air quality 
modeling results focuses primarily on impacts of the renewable fuel 
volumes required by RFS2 in reference to the RFS1 mandate for 2022. 
Except where specifically discussed below, air quality modeling results 
of increased renewable fuel use with RFS2 as compared to the AEO 2007 
reference case are presented in Appendix 3A of this RIA.
i. Acetaldehyde
    Our air quality modeling does not show substantial overall 
nationwide impacts on ambient concentrations of acetaldehyde as a 
result of the renewable fuel volumes required by this rule, although 
there is considerable uncertainty associated with the results. Annual 
percent changes in ambient concentrations of acetaldehyde are less than 
1% for most of the country, and annual absolute changes in ambient 
concentrations of acetaldehyde are generally less than 0.1 [mu]g/
m3. Some urban areas show decreases in ambient acetaldehyde 
concentrations ranging from 1 to 10%, and some rural areas associated 
with new ethanol plants show increases in ambient acetaldehyde 
concentrations ranging from 1 to 10% with RFS2 volumes. This increase 
is due to an increase in emissions of primary acetaldehyde and 
precursor emissions from ethanol plants. A key reason for the decrease 
in urban areas is reductions in certain acetaldehyde precursors, 
primarily alkenes (olefins). Most ambient acetaldehyde is formed from 
secondary photochemical reactions of numerous precursor compounds, and 
many photochemical mechanisms are responsible for this process.
    The uncertainty associated with these results is described in more 
detail in Section 3.4 of the RIA. For example, some of the modeled 
decreases would likely become increases using data recently collected 
by EPA's Office of Research and Development on the composition of 
hydrocarbon emissions from gasoline storage, gasoline distribution, and 
gas cans. Furthermore, as noted in the introduction to Section VI.D, 
the inventories used for air quality modeling may overestimate 
NOX, because they assumed that use of E10 would lead to 
increases in NOX emissions for later model year vehicles. 
The emission inventories for the final rule no longer make this 
assumption, based on recent EPA testing results.\196\ Because increases 
in NOX may result in more acetyl peroxy radical forming PAN 
rather than acetaldehyde, our air quality modeling results may 
underestimate the ambient concentrations of acetaldehyde.
---------------------------------------------------------------------------

    \196\ ``Summary of recent findings for fuel effects of a 10% 
ethanol blend on light duty exhaust emissions'', Memo from Aron 
Butler to Docket EPA-HQ-OAR-2005-0161.
---------------------------------------------------------------------------

    Some previous U.S. monitoring studies have suggested an 
insignificant or small impact of increased use of ethanol in fuel on 
ambient acetaldehyde, as discussed in more detail in Section 3.4 of the 
RIA. These studies suggest that increases in direct emissions of 
acetaldehyde are offset by decreases in the secondary formation of 
acetaldehyde. Other past studies have shown increases in ambient 
acetaldehyde with increased use of ethanol in fuel, although factors 
such as differences in vehicle fleet, lack of RVP control, and 
exclusion of upstream impacts may limit the ability of these studies to 
inform expected impacts on ambient air quality Given the conflicting 
results among past studies and the limitations of our analysis, 
considerable additional work is needed to address the impacts of the 
renewable fuel volumes required by this rule on ambient concentrations 
of acetaldehyde.
ii. Formaldehyde
    Our air quality modeling results do not show substantial impacts on 
ambient concentrations of formaldehyde from the renewable fuel volumes 
required by this rule. Most of the U.S. experiences a 1% or less change 
in ambient formaldehyde concentrations. Decreases in ambient 
formaldehyde concentrations range between 1 and 5% in a few urban 
areas. Increases range between 1 and 2.5% in some rural areas 
associated with new ethanol plants; this result is due to increases in 
emissions of primary formaldehyde and formaldehyde precursors from the 
new ethanol plants. Absolute changes in ambient concentrations of 
formaldehyde are generally less than 0.1 [mu]g/m3.
iii. Ethanol
    Our modeling projects that the renewable fuel volumes required by 
this rule will lead to significant nationwide increases in ambient 
ethanol concentrations. Increases ranging between 10 to 50% are seen 
across most of the country. The largest increases (more than 100%) 
occur in urban areas with high amounts of on-road emissions and in 
rural areas associated with new ethanol plants. Absolute increases in 
ambient ethanol concentrations are above 1.0 ppb in some urban areas. 
Analysis of a modeling error that impacted ethanol emissions suggests 
that this error resulted in overestimates of ethanol impacts by more 
than 10% across much of the country. For a detailed discussion of this 
error, please refer to the emissions modeling TSD, found in the docket 
for this rule (EPA-HQ-OAR-2005-0161).
iv. Benzene
    Our modeling projects that the renewable fuel volumes required by 
this rule will lead to small nationwide decreases in ambient benzene 
concentrations. Decreases in ambient benzene concentrations range 
between 1 and 10% across most of the country and can be higher in a few 
urban areas. Absolute changes in ambient concentrations of benzene show 
reductions up to 0.2 [mu]g/m3.

[[Page 14807]]

v. 1,3-Butadiene
    The results of our air quality modeling show small increases and 
decreases in ambient concentrations of 1,3-butadiene in parts of the 
U.S. as a result of increases in renewable fuel volumes required by 
RFS2. Generally, decreases occur in some southern areas of the country 
and increases occur in some northern areas and areas with high 
altitudes. Percent changes in 1,3-butadiene concentrations are over 50% 
in several areas; but the changes in absolute concentrations of ambient 
1,3-butadiene are generally less than 0.005 [mu]g/m \3\. Annual 
increases in ambient concentrations of 1,3-butadiene are driven by 
wintertime changes. These increases appear in rural areas with cold 
winters and low ambient levels but high contributions of emissions from 
snowmobiles, and a major reason for this modeled increase may be 
deficiencies in available emissions test data used to estimate 
snowmobile 1,3-butadiene emission inventories.
vi. Acrolein
    Our air quality modeling shows small regional increases and 
decreases in ambient concentrations of acrolein as a result of 
increases in renewable fuel volumes required by this rule. Decreases in 
acrolein concentrations occur in some eastern and southern parts of the 
U.S. and increases occur in some northern areas and areas associated 
with new ethanol plants. Changes in absolute ambient concentrations of 
acrolein are between  0.001 [micro]g/m[sup3] with the 
exception of the increases associated with new ethanol plants. These 
increases can be up to and above 0.005 [micro]g/m[sup3] with percent 
changes above 50% and are due to increases in emissions of acrolein 
from the new plants. Ambient acrolein increases in northern regions are 
driven by wintertime changes, and occur in the same areas of the 
country that have wintertime increases in ambient 1,3-butadiene. 1,3-
butadiene is a precursor to acrolein, and these increases are likely 
associated with the same emission inventory issues in areas of high 
snowmobile usage seen for 1,3-butadiene, as described above.
vii. Population Metrics
    To assess the impact of projected changes in ambient air toxics as 
a result of increases in renewable fuel volumes required by this rule, 
we developed population metrics that show the population experiencing 
increases and decreases in annual ambient concentrations of the modeled 
air toxics. Table VI.D-2 below illustrates the percentage of the 
population impacted by changes of various magnitudes in annual ambient 
concentrations with the renewable fuel volumes required by RFS2, as 
compared to the RFS1 mandate reference case.

    Table VI.D-2--Percent of Total Population Impacted by Changes in Annual Ambient Concentrations of Toxic Pollutants: RFS2 Compare to RFS1 Mandate
--------------------------------------------------------------------------------------------------------------------------------------------------------
      Percent change in annual ambient          Acetaldehyde        Acrolein           Benzene        1,3-Butadiene        Ethanol        Formaldehyde
                concentration                     (percent)         (percent)         (percent)         (percent)         (percent)         (percent)
--------------------------------------------------------------------------------------------------------------------------------------------------------
<=-100......................................  ................  ................  ................  ................  ................  ................
>-100 to <=-50..............................  ................  ................  ................  ................  ................  ................
>-50 to <=-10...............................              0.76  ................              1.18              1.38  ................  ................
>-10 to <=-5................................              8.17              0.18             12.92             28.11  ................  ................
>-5 to <=-2.5...............................             13.29             13.66             48.76             31.98  ................              4.11
>-2.5 to <=-1...............................             25.26             40.13             23.60             12.87  ................             19.30
>-1 to <1...................................             52.24             36.03             13.55             19.37  ................             76.08
>=1 to <2.5.................................              0.24              3.44  ................              1.53  ................              0.48
>=2.5 to <5.................................              0.04              2.93  ................              1.13              0.22              0.01
>=5 to <10..................................              0.02              2.00  ................              1.13              1.23  ................
>=10 to <50.................................  ................              1.51  ................              2.15             63.29  ................
>=50 to <100................................  ................              0.08  ................              0.28             34.49  ................
>=100.......................................  ................              0.05  ................              0.06              0.77  ................
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Table VI.D-3 shows changes in the population-weighted average 
ambient concentrations of air toxics that are projected to occur in 
2022 with increased renewable fuel use as required by this rule.

 Table VI.D-3--Population-Weighted Average Ambient Concentrations of Air Toxics in 2022 With RFS2 Renewable Fuel
                                                  Requirements
----------------------------------------------------------------------------------------------------------------
                                      Population-weighted concentration      Population-weighted concentration
                                       (Annual average in [mu]g/m \3\)        (Annual average in [mu]g/m \3\)
                                   -----------------------------------------------------------------------------
                                     RFS2 v. RFS1 mandate reference case      RFS2 v. AEO 2007 reference case
                                   -----------------------------------------------------------------------------
                                                     RFS1     Diff. RFS2-                            Diff. RFS2-
                                        RFS2       mandate        RFS1         RFS2       AEO 2007       AEO
----------------------------------------------------------------------------------------------------------------
Acetaldehyde......................        1.590        1.618       -0.028        1.590        1.613       -0.023
Acrolein..........................        0.017        0.018       -0.001        0.017        0.017      -0.0001
Benzene...........................        0.520        0.535       -0.015        0.520        0.527       -0.007
1,3-Butadiene.....................        0.022        0.023       -0.001        0.022        0.230       -0.208
Ethanol...........................        1.521        1.039        0.482        1.521        1.112        0.409
Formaldehyde......................        1.549        1.558       -0.009        1.549        0.004       -0.006
----------------------------------------------------------------------------------------------------------------


[[Page 14808]]

4. Nitrogen and Sulfur Deposition
a. Current Levels
    Over the past two decades, the EPA has undertaken numerous efforts 
to reduce nitrogen and sulfur deposition across the U.S. Analyses of 
long-term monitoring data for the U.S. show that deposition of both 
nitrogen and sulfur compounds has decreased over the last 17 years 
although many areas continue to be negatively impacted by deposition. 
Deposition of inorganic nitrogen and sulfur species routinely measured 
in the U.S. between 2004 and 2006 were as high as 9.6 kilograms of 
nitrogen per hectare per year (kg N/ha/yr) and 21.3 kilograms of sulfur 
per hectare per year (kg S/ha/yr). The data show that reductions were 
more substantial for sulfur compounds than for nitrogen compounds. 
These numbers are generated by the U.S. national monitoring network and 
they likely underestimate nitrogen deposition because neither ammonia 
nor organic nitrogen is measured. In the eastern U.S., where data are 
most abundant, total sulfur deposition decreased by about 36% between 
1990 and 2005, while total nitrogen deposition decreased by 19% over 
the same time frame.\197\
---------------------------------------------------------------------------

    \197\ U.S. EPA. U.S. EPA's 2008 Report on the Environment (Final 
Report). U.S. Environmental Protection Agency, Washington, DC, EPA/
600/R-07/045F (NTIS PB2008-112484).
---------------------------------------------------------------------------

b. Projected Levels
    Our air quality modeling does not show substantial overall 
nationwide impacts on the annual total sulfur and nitrogen deposition 
occurring across the U.S. as a result of increased renewable fuel 
volumes required by this rule. For sulfur deposition, when compared to 
the RFS1 mandate reference case, the RFS2 renewable fuel volumes will 
result in annual percent increases in the Midwest ranging from 1% to 
more than 4%. Some rural areas in the west, likely associated with new 
ethanol plants, will also have increases in sulfur deposition ranging 
from 1% to more than 4% as a result of the RFS2 renewable fuel volumes. 
When compared to the AEO 2007 reference case, the changes are more 
limited. The Midwest will still have sulfur deposition increases 
ranging from 1% to more than 4%, but the size of the area with these 
changes will be smaller. The Pacific Northwest has minimal areas with 
increases in sulfur deposition when compared to the AEO 2007 reference 
case. When compared to both the RFS1 mandate and AEO 2007 reference 
cases, areas along the Gulf Coast in Louisiana and Texas will 
experience decreases in sulfur deposition of 2% to more than 4%. The 
remainder of the country will see only minimal changes in sulfur 
deposition, ranging from decreases of less than 1% to increases of less 
than 1%. For a map of 2022 sulfur deposition impacts and additional 
information on these impacts, see Section 3.4.2.2 of the RIA.
    Overall, nitrogen deposition impacts in 2022 resulting from the 
renewable fuel volumes required by RFS2 are more widespread than the 
sulfur deposition impacts. When compared to the RFS1 mandate 2007 
reference case, nearly the entire eastern half of the United States 
will see nitrogen deposition increases ranging from 0.5% to more than 
2%. The largest increases will occur in the states of Illinois, 
Michigan, Indiana, Wisconsin, and Missouri, with large portions of each 
of these states seeing nitrogen deposition increases of more than 2%. 
The Pacific Northwest will also experience increases in nitrogen of 
0.5% to more than 2%. When compared to the AEO 2007 reference case, the 
changes in nitrogen deposition are more limited. The eastern half of 
the United States will still see nitrogen deposition increases ranging 
from 0.5% to more than 2%; however, the size of the area with these 
changes will be smaller. Increases of more than 2% will primarily occur 
only in Illinois, Indiana, Michigan, and Missouri. Fewer areas in the 
Pacific Northwest will have increases in nitrogen deposition when 
compared to the AEO 2007 reference case. In both the RFS1 mandate and 
AEO 2007 reference cases, the Mountain West and Southwest will see only 
minimal changes in nitrogen deposition, ranging from decreases of less 
than 0.5% to increases of less than 0.5%. A few areas in Minnesota and 
western Kansas would experience reductions of nitrogen up to 2%. See 
Section 3.4.2.2 of the RIA for a map and additional information on 
nitrogen deposition impacts.

E. Health Effects of Criteria and Air Toxics Pollutants

1. Particulate Matter
a. Background
    Particulate matter is a generic term for a broad class of 
chemically and physically diverse substances. It can be principally 
characterized as discrete particles that exist in the condensed (liquid 
or solid) phase spanning several orders of magnitude in size. Since 
1987, EPA has delineated that subset of inhalable particles small 
enough to penetrate to the thoracic region (including the 
tracheobronchial and alveolar regions) of the respiratory tract 
(referred to as thoracic particles). Current NAAQS use PM2.5 
as the indicator for fine particles (with PM2.5 referring to 
particles with a nominal mean aerodynamic diameter less than or equal 
to 2.5 [mu]m), and use PM10 as the indicator for purposes of 
regulating the coarse fraction of PM10 (referred to as 
thoracic coarse particles or coarse-fraction particles; generally 
including particles with a nominal mean aerodynamic diameter greater 
than 2.5 [mu]m and less than or equal to 10 [mu]m, or 
PM10-2.5). Ultrafine particles are a subset of fine 
particles, generally less than 100 nanometers (0.1 [mu]m) in 
aerodynamic diameter.
    Fine particles are produced primarily by combustion processes and 
by transformations of gaseous emissions (e.g., SOX, 
NOX and VOC) in the atmosphere. The chemical and physical 
properties of PM2.5 may vary greatly with time, region, 
meteorology, and source category. Thus, PM2.5 may include a 
complex mixture of different pollutants including sulfates, nitrates, 
organic compounds, elemental carbon and metal compounds. These 
particles can remain in the atmosphere for days to weeks and travel 
hundreds to thousands of kilometers.
b. Health Effects of PM
    Scientific studies show ambient PM is associated with a series of 
adverse health effects. These health effects are discussed in detail in 
EPA's 2004 Particulate Matter Air Quality Criteria Document (PM AQCD) 
and the 2005 PM Staff Paper.198 199 200 Further discussion 
of health effects associated with PM can also be found in the RIA for 
this rule.
---------------------------------------------------------------------------

    \198\ U.S. EPA (2004). Air Quality Criteria for Particulate 
Matter. Volume I EPA600/P-99/002aF and Volume II EPA600/P-99/002bF. 
Retrieved on March 19, 2009 from Docket EPA-HQ-OAR-2003-0190 at 
http://www.regulations.gov/.
    \199\ U.S. EPA. (2005). Review of the National Ambient Air 
Quality Standard for Particulate Matter: Policy Assessment of 
Scientific and Technical Information, OAQPS Staff Paper. EPA-452/R-
05-005a. Retrieved March 19, 2009 from http://www.epa.gov/ttn/naaqs/standards/pm/data/pmstaffpaper_20051221.pdf.
    \200\ The PM NAAQS is currently under review and the EPA is 
considering all available science on PM health effects, including 
information which has been published since 2004, in the development 
of the upcoming PM Integrated Science Assessment Document (ISA). A 
second draft of the PM ISA was completed in July 2009 and was 
submitted for review by the Clean Air Scientific Advisory Committee 
(CASAC) of EPA's Science Advisory Board. Comments from the general 
public have also been requested. For more information, see http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=210586.
---------------------------------------------------------------------------

    Health effects associated with short-term exposures (hours to days) 
to ambient PM include premature mortality, aggravation of 
cardiovascular and lung disease (as indicated by

[[Page 14809]]

increased hospital admissions and emergency department visits), 
increased respiratory symptoms including cough and difficulty 
breathing, decrements in lung function, altered heart rate rhythm, and 
other more subtle changes in blood markers related to cardiovascular 
health.\201\ Long-term exposure to PM2.5 and sulfates has 
also been associated with mortality from cardiopulmonary disease and 
lung cancer, and effects on the respiratory system such as reduced lung 
function growth or development of respiratory disease. A new analysis 
shows an association between long-term PM2.5 exposure and a 
subclinical measure of atherosclerosis.202 203
---------------------------------------------------------------------------

    \201\ U.S. EPA. (2006). National Ambient Air Quality Standards 
for Particulate Matte. 71 FR 61144, October 17, 2006.
    \202\ K[uuml]nzli, N., Jerrett, M., Mack, W.J., et al. (2004). 
Ambient air pollution and atherosclerosis in Los Angeles. Environ 
Health Perspect.,113, 201-206.
    \203\ This study is included in the 2006 Provisional Assessment 
of Recent Studies on Health Effects of Particulate Matter Exposure. 
The provisional assessment did not and could not (given a very short 
timeframe) undergo the extensive critical review by CASAC and the 
public, as did the PM AQCD. The provisional assessment found that 
the ``new'' studies expand the scientific information and provide 
important insights on the relationship between PM exposure and 
health effects of PM. The provisional assessment also found that 
``new'' studies generally strengthen the evidence that acute and 
chronic exposure to fine particles and acute exposure to thoracic 
coarse particles are associated with health effects. Further, the 
provisional science assessment found that the results reported in 
the studies did not dramatically diverge from previous findings, and 
taken in context with the findings of the AQCD, the new information 
and findings did not materially change any of the broad scientific 
conclusions regarding the health effects of PM exposure made in the 
AQCD. However, it is important to note that this assessment was 
limited to screening, surveying, and preparing a provisional 
assessment of these studies. For reasons outlined in Section I.C of 
the preamble for the final PM NAAQS rulemaking in 2006 (see 71 FR 
61148-49, October 17, 2006), EPA based its NAAQS decision on the 
science presented in the 2004 AQCD.
---------------------------------------------------------------------------

    Studies examining populations exposed over the long term (one or 
more years) to different levels of air pollution, including the Harvard 
Six Cities Study and the American Cancer Society Study, show 
associations between long-term exposure to ambient PM2.5 and 
both all cause and cardiopulmonary premature 
mortality.204 205 206 In addition, an extension of the 
American Cancer Society Study shows an association between 
PM2.5 and sulfate concentrations and lung cancer 
mortality.\207\
---------------------------------------------------------------------------

    \204\ Dockery, D.W., Pope, C.A. III, Xu, X, et al. (1993). An 
association between air pollution and mortality in six U.S. cities. 
N Engl J Med, 329, 1753-1759. Retrieved on March 19, 2009 from 
http://content.nejm.org/cgi/content/full/329/24/1753.
    \205\ Pope, C.A., III, Thun, M.J., Namboodiri, M.M., Dockery, 
D.W., Evans, J.S., Speizer, F.E., and Heath, C.W., Jr. (1995). 
Particulate air pollution as a predictor of mortality in a 
prospective study of U.S. adults. Am. J. Respir. Crit. Care Med, 
151, 669-674.
    \206\ Krewski, D., Burnett, R.T., Goldberg, M.S., et al. (2000). 
Reanalysis of the Harvard Six Cities study and the American Cancer 
Society study of particulate air pollution and mortality. A special 
report of the Institute's Particle Epidemiology Reanalysis Project. 
Cambridge, MA: Health Effects Institute. Retrieved on March 19, 2009 
from http://es.epa.gov/ncer/science/pm/hei/Rean-ExecSumm.pdf.
    \207\ Pope, C. A., III, Burnett, R.T., Thun, M. J., Calle, E.E., 
Krewski, D., Ito, K., Thurston, G.D., (2002). Lung cancer, 
cardiopulmonary mortality, and long-term exposure to fine 
particulate air pollution. J. Am. Med. Assoc., 287, 1132-1141.
---------------------------------------------------------------------------

2. Ozone
a. Background
    Ground-level ozone pollution is typically formed by the reaction of 
VOC and NOX in the lower atmosphere in the presence of heat 
and sunlight. These pollutants, often referred to as ozone precursors, 
are emitted by many types of pollution sources, such as highway and 
nonroad motor vehicles and engines, power plants, chemical plants, 
refineries, makers of consumer and commercial products, industrial 
facilities, and smaller area sources.
    The science of ozone formation, transport, and accumulation is 
complex.\208\ Ground-level ozone is produced and destroyed in a 
cyclical set of chemical reactions, many of which are sensitive to 
temperature and sunlight. When ambient temperatures and sunlight levels 
remain high for several days and the air is relatively stagnant, ozone 
and its precursors can build up and result in more ozone than typically 
occurs on a single high-temperature day. Ozone can be transported 
hundreds of miles downwind from precursor emissions, resulting in 
elevated ozone levels even in areas with low local VOC or 
NOX emissions.
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    \208\ U.S. EPA. (2006). Air Quality Criteria for Ozone and 
Related Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. 
Washington, DC: U.S. EPA. Retrieved on March 19, 2009 from Docket 
EPA-HQ-OAR-2003-0190 at http://www.regulations.gov/.
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b. Health Effects of Ozone
    The health and welfare effects of ozone are well documented and are 
assessed in EPA's 2006 Air Quality Criteria Document (ozone AQCD) and 
2007 Staff Paper.209 210 Ozone can irritate the respiratory 
system, causing coughing, throat irritation, and/or uncomfortable 
sensation in the chest. Ozone can reduce lung function and make it more 
difficult to breathe deeply; breathing may also become more rapid and 
shallow than normal, thereby limiting a person's activity. Ozone can 
also aggravate asthma, leading to more asthma attacks that require 
medical attention and/or the use of additional medication. In addition, 
there is suggestive evidence of a contribution of ozone to 
cardiovascular-related morbidity and highly suggestive evidence that 
short-term ozone exposure directly or indirectly contributes to non-
accidental and cardiopulmonary-related mortality, but additional 
research is needed to clarify the underlying mechanisms causing these 
effects. In a recent report on the estimation of ozone-related 
premature mortality published by the National Research Council (NRC), a 
panel of experts and reviewers concluded that short-term exposure to 
ambient ozone is likely to contribute to premature deaths and that 
ozone-related mortality should be included in estimates of the health 
benefits of reducing ozone exposure.\211\ Animal toxicological evidence 
indicates that with repeated exposure, ozone can inflame and damage the 
lining of the lungs, which may lead to permanent changes in lung tissue 
and irreversible reductions in lung function. People who are more 
susceptible to effects associated with exposure to ozone can include 
children, the elderly, and individuals with respiratory disease such as 
asthma. Those with greater exposures to ozone, for instance due to time 
spent outdoors (e.g., children and outdoor workers), are of particular 
concern.
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    \209\ U.S. EPA. (2006). Air Quality Criteria for Ozone and 
Related Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. 
Washington, DC: U.S. EPA. Retrieved on March 19, 2009 from Docket 
EPA-HQ-OAR-2003-0190 at http://www.regulations.gov/.
    \210\ U.S. EPA. (2007). Review of the National Ambient Air 
Quality Standards for Ozone: Policy Assessment of Scientific and 
Technical Information, OAQPS Staff Paper. EPA-452/R-07-003. 
Washington, DC, U.S. EPA. Retrieved on March 19, 2009 from Docket 
EPA-HQ-OAR-2003-0190 at http://www.regulations.gov/.
    \211\ National Research Council (NRC), 2008. Estimating 
Mortality Risk Reduction and Economic Benefits from Controlling 
Ozone Air Pollution. The National Academies Press: Washington, DC.
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    The 2006 ozone AQCD also examined relevant new scientific 
information that has emerged in the past decade, including the impact 
of ozone exposure on such health effects as changes in lung structure 
and biochemistry, inflammation of the lungs, exacerbation and causation 
of asthma, respiratory illness-related school absence, hospital 
admissions and premature mortality. Animal toxicological studies have 
suggested potential interactions between ozone and PM with increased 
responses observed to mixtures of the two pollutants compared to either 
ozone or PM alone. The respiratory morbidity observed in animal studies 
along with

[[Page 14810]]

the evidence from epidemiologic studies supports a causal relationship 
between acute ambient ozone exposures and increased respiratory-related 
emergency room visits and hospitalizations in the warm season. In 
addition, there is suggestive evidence of a contribution of ozone to 
cardiovascular-related morbidity and non-accidental and cardiopulmonary 
mortality.
3. NOX and SOX
a. Background
    Nitrogen dioxide (NO2) is a member of the NOX 
family of gases. Most NO2 is formed in the air through the 
oxidation of nitric oxide (NO) emitted when fuel is burned at a high 
temperature. SO2, a member of the sulfur oxide 
(SOX) family of gases, is formed from burning fuels 
containing sulfur (e.g., coal or oil derived), extracting gasoline from 
oil, or extracting metals from ore.
    SO2 and NO2 can dissolve in water 
vapor and further oxidize to form sulfuric and nitric acid which react 
with ammonia to form sulfates and nitrates, both of which are important 
components of ambient PM. The health effects of ambient PM are 
discussed in Section VI.D.1 of this preamble. NOX along with 
non-methane hydrocarbon (NMHC) are the two major precursors of ozone. 
The health effects of ozone are covered in Section VI.D.2.
b. Health Effects of NOX
    Information on the health effects of NO2 can be found in 
the U.S. Environmental Protection Agency Integrated Science Assessment 
(ISA) for Nitrogen Oxides.\212\ The U.S. EPA has concluded that the 
findings of epidemiologic, controlled human exposure, and animal 
toxicological studies provide evidence that is sufficient to infer a 
likely causal relationship between respiratory effects and short-term 
NO2 exposure. The ISA concludes that the strongest evidence 
for such a relationship comes from epidemiologic studies of respiratory 
effects including symptoms, emergency department visits, and hospital 
admissions. The ISA also draws two broad conclusions regarding airway 
responsiveness following NO2 exposure. First, the ISA 
concludes that NO2 exposure may enhance the sensitivity to 
allergen-induced decrements in lung function and increase the allergen-
induced airway inflammatory response following 30-minute exposures of 
asthmatics to NO2 concentrations as low as 0.26 ppm. In 
addition, small but significant increases in non-specific airway 
hyperresponsiveness were reported following 1-hour exposures of 
asthmatics to 0.1 ppm NO2. Second, exposure to 
NO2 has been found to enhance the inherent responsiveness of 
the airway to subsequent nonspecific challenges in controlled human 
exposure studies of asthmatic subjects. Enhanced airway responsiveness 
could have important clinical implications for asthmatics since 
transient increases in airway responsiveness following NO2 
exposure have the potential to increase symptoms and worsen asthma 
control. Together, the epidemiologic and experimental data sets form a 
plausible, consistent, and coherent description of a relationship 
between NO2 exposures and an array of adverse health effects 
that range from the onset of respiratory symptoms to hospital 
admission.
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    \212\ U.S. EPA (2008). Integrated Science Assessment for Oxides 
of Nitrogen--Health Criteria (Final Report). EPA/600/R-08/071. 
Washington, DC,: U.S.EPA. Retrieved on March 19, 2009 from http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645.
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    Although the weight of evidence supporting a causal relationship is 
somewhat less certain than that associated with respiratory morbidity, 
NO2 has also been linked to other health endpoints. These 
include all-cause (nonaccidental) mortality, hospital admissions or 
emergency department visits for cardiovascular disease, and decrements 
in lung function growth associated with chronic exposure.
c. Health Effects of SOX
    Information on the health effects of SO2 can be found in 
the U.S. Environmental Protection Agency Integrated Science Assessment 
for Sulfur Oxides.\213\ SO2 has long been known to cause 
adverse respiratory health effects, particularly among individuals with 
asthma. Other potentially sensitive groups include children and the 
elderly. During periods of elevated ventilation, asthmatics may 
experience symptomatic bronchoconstriction within minutes of exposure. 
Following an extensive evaluation of health evidence from epidemiologic 
and laboratory studies, the EPA has concluded that there is a causal 
relationship between respiratory health effects and short-term exposure 
to SO2. Separately, based on an evaluation of the 
epidemiologic evidence of associations between short-term exposure to 
SO2 and mortality, the EPA has concluded that the overall 
evidence is suggestive of a causal relationship between short-term 
exposure to SO2 and mortality.
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    \213\ U.S. EPA. (2008). Integrated Science Assessment (ISA) for 
Sulfur Oxides--Health Criteria (Final Report). EPA/600/R-08/047F. 
Washington, DC: U.S. Environmental Protection Agency. Retrieved on 
March 18, 2009 from http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=198843.
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4. Carbon Monoxide
    Carbon monoxide (CO) forms as a result of incomplete fuel 
combustion. CO enters the bloodstream through the lungs, forming 
carboxyhemoglobin and reducing the delivery of oxygen to the body's 
organs and tissues. The health threat from exposures to lower levels of 
CO is most serious for those who suffer from cardiovascular disease, 
particularly those with angina or peripheral vascular disease. 
Epidemiological studies have suggested that exposure to ambient levels 
of CO is associated with increased risk of hospital admissions for 
cardiovascular causes, fetal effects, and possibly premature 
cardiovascular mortality. Healthy individuals also are affected, but 
only when they are exposed to higher CO levels. Exposure of healthy 
individuals to elevated CO levels is associated with impairment of 
visual perception, work capacity, manual dexterity, learning ability 
and performance of complex tasks. Carbon monoxide also contributes to 
ozone nonattainment since carbon monoxide reacts photochemically in the 
atmosphere to form ozone.\214\ Additional information on CO related 
health effects can be found in the Carbon Monoxide Air Quality Criteria 
Document (CO AQCD).215 216
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    \214\ U.S. EPA (2000). Air Quality Criteria for Carbon Monoxide, 
EPA/600/P-99/001F. This document is available in Docket EPA-HQ-OAR-
2004-0008.
    \215\ U.S. EPA (2000). Air Quality Criteria for Carbon Monoxide, 
EPA/600/P-99/001F. This document is available in Docket EPA-HQ-OAR-
2004-0008.
    \216\ The CO NAAQS is currently under review and the EPA is 
considering all available science on CO health effects, including 
information which has been published since 2000, in the development 
of the upcoming CO Integrated Science Assessment Document (ISA). A 
second draft of the CO ISA was completed in September 2009 and was 
submitted for review by the Clean Air Scientific Advisory Committee 
(CASAC) of EPA's Science Advisory Board. For more information, see 
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=213229.
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5. Air Toxics
    The population experiences an elevated risk of cancer and noncancer 
health effects from exposure to the class of pollutants known 
collectively as ``air toxics.''\217\ Fuel combustion contributes to 
ambient levels of air toxics that can include, but are not limited to, 
acetaldehyde, acrolein, benzene, 1,3-butadiene, formaldehyde, ethanol, 
naphthalene and peroxyacetyl nitrate

[[Page 14811]]

(PAN). Acrolein, benzene, 1,3-butadiene, formaldehyde and naphthalene 
have significant contributions from mobile sources and were identified 
as national or regional risk drivers in the 2002 National-scale Air 
Toxics Assessment (NATA).\218\ PAN, which is formed from precursor 
compounds by atmospheric processes, is not assessed in NATA. Emissions 
and ambient concentrations of compounds are discussed in Chapter 3 of 
the RIA and Section VI.D.3 of this preamble.
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    \217\ U. S. EPA. 2002 National-Scale Air Toxics Assessment. 
http://www.epa.gov/ttn/atw/nata2002/risksum.html.
    \218\ U.S. EPA .2009. National-Scale Air Toxics Assessment for 
2002. http://www.epa.gov/ttn/atw/nata2002.
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a. Acetaldehyde
    Acetaldehyde is classified in EPA's IRIS database as a probable 
human carcinogen, based on nasal tumors in rats, and is considered 
toxic by the inhalation, oral, and intravenous routes.\219\ 
Acetaldehyde is reasonably anticipated to be a human carcinogen by the 
U.S. DHHS in the 11th Report on Carcinogens and is classified as 
possibly carcinogenic to humans (Group 2B) by the 
IARC.220 221 EPA is currently conducting a reassessment of 
cancer risk from inhalation exposure to acetaldehyde.
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    \219\ U.S. EPA. 1991. Integrated Risk Information System File of 
Acetaldehyde. Research and Development, National Center for 
Environmental Assessment, Washington, DC. This material is available 
electronically at http://www.epa.gov/iris/subst/0290.htm.
    \220\ U.S. Department of Health and Human Services National 
Toxicology Program 11th Report on Carcinogens available at: 
ntp.niehs.nih.gov/index.cfm?objectid=32BA9724-F1F6-975E-7FCE50709CB4C932.
    \221\ International Agency for Research on Cancer (IARC). 1999. 
Re-evaluation of some organic chemicals, hydrazine, and hydrogen 
peroxide. IARC Monographs on the Evaluation of Carcinogenic Risk of 
Chemical to Humans, Vol 71. Lyon, France.
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    The primary noncancer effects of exposure to acetaldehyde vapors 
include irritation of the eyes, skin, and respiratory tract.\222\ In 
short-term (4 week) rat studies, degeneration of olfactory epithelium 
was observed at various concentration levels of acetaldehyde 
exposure.223 224 Data from these studies were used by EPA to 
develop an inhalation reference concentration. Some asthmatics have 
been shown to be a sensitive subpopulation to decrements in functional 
expiratory volume (FEV1 test) and bronchoconstriction upon acetaldehyde 
inhalation.\225\ The agency is currently conducting a reassessment of 
the health hazards from inhalation exposure to acetaldehyde.
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    \222\ U.S. EPA. 1991. Integrated Risk Information System File of 
Acetaldehyde. This material is available electronically at http://www.epa.gov/iris/subst/0290.htm.
    \223\ Appleman, L. M., R. A. Woutersen, V. J. Feron, R. N. 
Hooftman, and W. R. F. Notten. 1986. Effects of the variable versus 
fixed exposure levels on the toxicity of acetaldehyde in rats. J. 
Appl. Toxicol. 6: 331-336.
    \224\ Appleman, L.M., R.A. Woutersen, and V.J. Feron. 1982. 
Inhalation toxicity of acetaldehyde in rats. I. Acute and subacute 
studies. Toxicology. 23: 293-297.
    \225\ Myou, S.; Fujimura, M.; Nishi K.; Ohka, T.; and Matsuda, 
T. 1993. Aerosolized acetaldehyde induces histamine-mediated 
bronchoconstriction in asthmatics. Am. Rev. Respir.Dis.148(4 Pt 1): 
940-3.
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b. Acrolein
    Acrolein is extremely acrid and irritating to humans when inhaled, 
with acute exposure resulting in upper respiratory tract irritation, 
mucus hypersecretion and congestion. The intense irritancy of this 
carbonyl has been demonstrated during controlled tests in human 
subjects, who suffer intolerable eye and nasal mucosal sensory 
reactions within minutes of exposure.\226\ These data and additional 
studies regarding acute effects of human exposure to acrolein are 
summarized in EPA's 2003 IRIS Human Health Assessment for 
acrolein.\227\ Evidence available from studies in humans indicate that 
levels as low as 0.09 ppm (0.21 mg/m\3\) for five minutes may elicit 
subjective complaints of eye irritation with increasing concentrations 
leading to more extensive eye, nose and respiratory symptoms.\228\ 
Lesions to the lungs and upper respiratory tract of rats, rabbits, and 
hamsters have been observed after subchronic exposure to acrolein.\229\ 
Acute exposure effects in animal studies report bronchial hyper-
responsiveness.\230\ In a recent study, the acute respiratory irritant 
effects of exposure to 1.1 ppm acrolein were more pronounced in mice 
with allergic airway disease by comparison to non-diseased mice which 
also showed decreases in respiratory rate.\231\ Based on animal data, 
individuals with compromised respiratory function (e.g., emphysema, 
asthma) are expected to be at increased risk of developing adverse 
responses to strong respiratory irritants such as acrolein.
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    \226\ Sim VM, Pattle RE. Effect of possible smog irritants on 
human subjects JAMA165: 1980-2010, 1957.
    \227\ U.S. EPA (U.S. Environmental Protection Agency). (2003) 
Toxicological review of acrolein in support of summary information 
on Integrated Risk Information System (IRIS) National Center for 
Environmental Assessment, Washington, DC. EPA/635/R-03/003. 
Available online at: http://www.epa.gov/ncea/iris.
    \228\ Weber-Tschopp, A; Fischer, T; Gierer, R; et al. (1977) 
Experimentelle reizwirkungen von Acrolein auf den Menschen. Int Arch 
Occup Environ Hlth 40(2):117-130. In German
    \229\ Integrated Risk Information System File of Acrolein. 
Office of Research and Development, National Center for 
Environmental Assessment, Washington, DC. This material is available 
at http://www.epa.gov/iris/subst/0364.htm.
    \230\ U.S. EPA (U.S. Environmental Protection Agency). (2003) 
Toxicological review of acrolein in support of summary information 
on Integrated Risk Information System (IRIS) National Center for 
Environmental Assessment, Washington, DC. EPA/635/R-03/003. 
Available online at: http://www.epa.gov/ncea/iris.
    \231\ Morris JB, Symanowicz PT, Olsen JE, et al. 2003. Immediate 
sensory nerve-mediated respiratory responses to irritants in healthy 
and allergic airway-diseased mice. J Appl Physiol 94(4):1563-1571.
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    EPA determined in 2003 that the human carcinogenic potential of 
acrolein could not be determined because the available data were 
inadequate. No information was available on the carcinogenic effects of 
acrolein in humans and the animal data provided inadequate evidence of 
carcinogenicity.\232\ The IARC determined in 1995 that acrolein was not 
classifiable as to its carcinogenicity in humans.\233\
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    \232\ U.S. EPA. 2003. Integrated Risk Information System File of 
Acrolein. Research and Development, National Center for 
Environmental Assessment, Washington, DC. This material is available 
at http://www.epa.gov/iris/subst/0364.htm.
    \233\ International Agency for Research on Cancer (IARC). 1995. 
Monographs on the evaluation of carcinogenic risk of chemicals to 
humans, Volume 63, Dry cleaning, some chlorinated solvents and other 
industrial chemicals , World Health Organization, Lyon, France.
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c. Benzene
    The EPA's IRIS database lists benzene as a known human carcinogen 
(causing leukemia) by all routes of exposure, and concludes that 
exposure is associated with additional health effects, including 
genetic changes in both humans and animals and increased proliferation 
of bone marrow cells in mice.234 235 236 EPA states in its 
IRIS database that data indicate a causal relationship between benzene 
exposure and acute lymphocytic leukemia and suggest a relationship 
between benzene exposure and chronic non-lymphocytic leukemia and 
chronic lymphocytic leukemia. The International Agency for Research on 
Carcinogens (IARC) has determined that benzene is a human carcinogen 
and the U.S. Department of Health and Human Services (DHHS) has 
characterized

[[Page 14812]]

benzene as a known human carcinogen.237 238
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    \234\ U.S. EPA. 2000. Integrated Risk Information System File 
for Benzene. This material is available electronically at http://www.epa.gov/iris/subst/0276.htm.
    \235\ International Agency for Research on Cancer (IARC). 1982. 
Monographs on the evaluation of carcinogenic risk of chemicals to 
humans, Volume 29, Some industrial chemicals and dyestuffs, World 
Health Organization, Lyon, France, p. 345-389.
    \236\ Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; Henry, 
V.A. 1992. Synergistic action of the benzene metabolite hydroquinone 
on myelopoietic stimulating activity of granulocyte/macrophage 
colony-stimulating factor in vitro, Proc. Natl. Acad. Sci. 89:3691-
3695.
    \237\ International Agency for Research on Cancer (IARC). 1987. 
Monographs on the evaluation of carcinogenic risk of chemicals to 
humans, Volume 29, Supplement 7, Some industrial chemicals and 
dyestuffs, World Health Organization, Lyon, France.
    \238\ U.S. Department of Health and Human Services National 
Toxicology Program 11th Report on Carcinogens available at: http://ntp.niehs.nih.gov/go/16183.
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    A number of adverse noncancer health effects including blood 
disorders, such as preleukemia and aplastic anemia, have also been 
associated with long-term exposure to benzene.239 240 The 
most sensitive noncancer effect observed in humans, based on current 
data, is the depression of the absolute lymphocyte count in 
blood.241 242 In addition, recent work, including studies 
sponsored by the Health Effects Institute (HEI), provides evidence that 
biochemical responses are occurring at lower levels of benzene exposure 
than previously known.243 244 245 246 EPA's IRIS program has 
not yet evaluated these new data.
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    \239\ Aksoy, M. (1989). Hematotoxicity and carcinogenicity of 
benzene. Environ. Health Perspect. 82: 193-197.
    \240\ Goldstein, B.D. (1988). Benzene toxicity. Occupational 
medicine. State of the Art Reviews. 3: 541-554.
    \241\ Rothman, N., G.L. Li, M. Dosemeci, W.E. Bechtold, G.E. 
Marti, Y.Z. Wang, M. Linet, L.Q. Xi, W. Lu, M.T. Smith, N. Titenko-
Holland, L.P. Zhang, W. Blot, S.N. Yin, and R.B. Hayes (1996) 
Hematotoxicity among Chinese workers heavily exposed to benzene. Am. 
J. Ind. Med. 29